2020

United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 40-F

☐ Registration Statement pursuant to section 12 of the Securities Exchange Act of 1934

☒ Annual report pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2020

Commission File Number: 001-04307

Husky Energy Inc.

(Exact name of Registrant as specified in its charter)

Alberta, Canada	1311	Not Applicable
(Province or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number (if applicable))	(I.R.S. Employer Identification Number (if applicable))

707-8^th Avenue S.W. Calgary, Alberta, Canada T2P 1H5

(403) 298-6111

(Address and telephone number of Registrant’s principal executive office)

CT Corporation System, 111 Eighth Avenue, New York, New York 10011

(877) 467-3525

(Name, address (including zip code) and telephone number (including area code)

of agent for service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Title of Class: None

Securities registered or to be registered pursuant to Section 12(g) of the Act:

Title of Class: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

Title of Class: Common Shares

For annual reports, indicate by check mark the information filed with this Form:

☒  Annual information form ☒  Audited annual financial statements

Number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period

covered by the annual report:

1,005,121,738 Common Shares outstanding as of December 31, 2020

10,435,932 Cumulative Redeemable Preferred Shares, Series 1 outstanding as of December 31, 2020

1,564,068 Cumulative Redeemable Preferred Shares, Series 2 outstanding as of December 31, 2020

10,000,000 Cumulative Redeemable Preferred Shares, Series 3 outstanding as of December 31, 2020

8,000,000 Cumulative Redeemable Preferred Shares, Series 5 outstanding as of December 31, 2020

6,000,000 Cumulative Redeemable Preferred Shares, Series 7 outstanding as of December 31, 2020

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.

☒  Yes            ☐  No

Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (s.232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files).

☒  Yes            ☐  No

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 12b-2 of the Exchange Act.

Emerging growth company  ☐

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards^† provided pursuant to Section 13(a) of the Exchange Act.  ☐

† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S. C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.  ☒

Principal Documents

The following documents have been filed as part of this Annual Report on Form 40-F:

A. Annual Information Form

The Annual Information Form (“AIF”) of Husky Energy Inc. (“Husky” or the “Company”) for the year ended December 31, 2020 is included as Document A of this Annual Report on Form 40-F.

B. Audited Annual Financial Statements

Husky’s audited consolidated financial statements for the years ended December 31, 2020 and December 31, 2019, including the auditors’ report with respect thereto, are included as Document B of this Annual Report on Form 40-F.

C. Management’s Discussion and Analysis

Husky’s Management’s Discussion and Analysis for the year ended December 31, 2020 is included as Document C of this Annual Report on Form 40-F.

Certifications

See Exhibits 31.1 and 32.1, which are included as Exhibits to this Annual Report on Form 40-F.

Supplemental Reserves Information

See Exhibit 99.1 for the Supplemental Reserves Information, which is included as an Exhibit to this Annual Report on Form 40-F.

Disclosure Controls and Procedures

See the section “Disclosure Controls and Procedures” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2020, which is included as Document C of this Annual Report on Form 40-F.

Management’s Annual Report on Internal Control Over Financial Reporting

See the section “Disclosure Controls and Procedures” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2020, which is included as Document C of this Annual Report on Form 40-F.

Attestation Report of the Independent Registered Public Accounting Firm

See the “Report of Independent Registered Public Accounting Firm” that accompanies Husky’s audited consolidated financial statements for the years ended December 31, 2020 and 2019, which are included as Document B of this Annual Report on Form 40-F.

Changes in Internal Control Over Financial Reporting

See the section “Disclosure Controls and Procedures” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2020, which is included as Document C of this Annual Report on Form 40-F.

Notice Pursuant to Regulation BTR

Not Applicable.

Audit Committee Financial Expert

Not applicable.

Code of Business Conduct and Ethics

Husky’s code of ethics is disclosed in its Code of Business Conduct, which is applicable to its principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions and to all of its other employees, and is posted on its website at www.huskyenergy.com. On July 29, 2020, Husky amended its Code of Business Conduct effective as of July 29, 2020, and a copy of this new amended Code of Business Conduct is included as Exhibit 99.2 to this Annual Report on Form 40-F for the fiscal year ended December 31, 2020.

A copy of such amended Code of Business Conduct was posted on Husky’s website (together with a disclosure of the nature of the amendments) promptly after the amendments became effective.

The following is a general summary of the nature of the amendments:

i. The section on political donations was updated to prohibit all political donations made by or on behalf of Husky. Husky previously allowed limited political contributions to be made on its behalf pursuant to rules and processes set out in Husky’s Community Investment Policy. The Community Investment Policy has been revised to remove all references to political contributions and it was recommended that political contributions were more appropriately addressed in the Code. Following a review of corporate governance best practices, it was recommended that all political contributions be prohibited.

ii. A number of minor revisions were made for consistent formatting and definitions and to align with, and reflect changes to, other corporate policies.

A copy of the amended Code of Business Conduct is available to any person without charge, upon request made in writing to Husky’s principal executive office, Attention: Senior Vice President, General Counsel & Secretary.

In the fiscal year ended December 31, 2020, Husky did not grant a waiver, including an implicit waiver, from a provision of its code of ethics to any of its principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions that relates to one or more of the items set forth in paragraph (9)(b) of General Instruction B to Form 40-F. In the event that, during Husky’s ensuing fiscal year, Husky:

i. amends any provision of its Code of Business Conduct that applies to its principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions that relates to any element of the code of ethics definition enumerated in paragraph (9)(b) of General Instruction B to Form 40-F; or

ii. grants a waiver, including an implicit waiver, from a provision of its Code of Business Conduct to any of its principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions that relates to one or more of the items set forth in paragraph (9)(b) of General Instruction B to Form 40-F;

Husky will promptly disclose such occurrences on its website following the date that such amendment or waiver is granted and will specifically describe the nature of any amendment or waiver, and in the case of a waiver, name the person to whom the waiver was granted and the date of the waiver, in each case as further described in paragraph (9) of General Instruction B to Form 40-F.

Principal Accountant Fees and Services

See the section “External Auditor Service Fees” in Husky’s AIF for the year ended December 31, 2020, which is included as Document A of this Annual Report on Form 40-F.

Off-Balance Sheet Arrangements

See the section “Contractual Obligations, Commitments and Off-Balance Sheet Arrangements” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2020, which is included as Document C of this Annual Report on Form 40-F.

Tabular Disclosure of Contractual Obligations

See the section “Contractual Obligations, Commitments and Off-Balance Sheet Arrangements” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2020, which is included as Document C of this Annual Report on Form 40-F.

Interactive Data File

See Exhibit 101 to this Annual Report on Form 40-F for the year ended December 31, 2020.

Mine Safety Disclosure

Not applicable.

Undertaking and Consent to Service of Process

Undertaking

Husky undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

Consent to Service of Process

A Form F-X signed by Husky and its agent for service of process has been filed with the Commission together with Form F-10 (File No. 333-236603) in connection with its securities registered on such form.

Any change to the name or address of the agent for service of process of Husky shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of Husky.

Signatures

Pursuant to the requirements of the Exchange Act, Husky Energy Inc. certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this Annual Report to be signed on its behalf by the undersigned, thereto duly authorized.

Dated this 9th day of February, 2021

	Husky Energy Inc.
By:	/s/ Jeffrey R. Hart
	Name: Jeffrey R. Hart
	Title: Acting Chief Executive Officer & Chief Financial Officer
By:	/s/ James D. Girgulis
	Name: James D. Girgulis
	Title: Senior Vice President, General Counsel & Secretary

Document A

Form 40-F

Annual Information Form

For the Year Ended December 31, 2020

ANNUAL INFORMATION FORM

FOR THE YEAR ENDED DECEMBER 31, 2020

Feb. 8, 2021

TABLE OF CONTENTS
NOTE TO READER	1
ABBREVIATIONS AND GLOSSARY OF TERMS	1
EXCHANGE RATE INFORMATION	9
CORPORATE STRUCTURE	9
GENERAL DEVELOPMENT OF HUSKY	10
DESCRIPTION OF HUSKY’S BUSINESS	13
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	26
ENVIRONMENTAL, SOCIAL AND GOVERNANCE CONSIDERATIONS	52
RISK FACTORS	66
HUSKY EMPLOYEES	77
DIVIDENDS	77
DESCRIPTION OF CAPITAL STRUCTURE	80
MARKET FOR SECURITIES	85
DIRECTORS AND OFFICERS	88
AUDIT COMMITTEE	94
PRINCIPAL HOLDERS OF VOTING SECURITIES	94
EXECUTIVE COMPENSATION	94
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS	119
LEGAL PROCEEDINGS	119
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	120
INTERESTS OF EXPERTS	120
ADDITIONAL INFORMATION	120
READER ADVISORIES	121
APPENDIX A - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES AUDITOR	126
APPENDIX B - REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE	128
APPENDIX C - INDEPENDENT QUALIFIED RESERVES AUDITOR AUDIT OPINION	129

NOTE TO READER

Unless otherwise indicated, in this Annual Information Form (“AIF”), the terms “Husky” and the “Company” mean Husky Energy Inc. and its subsidiaries and partnership interests on a consolidated basis, including information with respect to predecessor corporations.

Unless otherwise indicated, the information contained in this AIF is presented as at or for the year ended December 31, 2020, and all financial information included and incorporated by reference in this AIF is determined using International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board.

Except where otherwise indicated, all dollar amounts stated in this AIF are in Canadian dollars.

This AIF is for the year ended December 31, 2020, and is in respect of Husky and its consolidated entities and considers the completion of the Cenovus Transaction (as defined below).

See also “Reader Advisories” on page 99 of this AIF.

ABBREVIATIONS AND GLOSSARY OF TERMS

When used in this AIF, the following terms have the meanings indicated:

Units of Measure
bbl	barrel
bbls/day	barrels per calendar day
bcf	billion cubic feet
boe	barrels of oil equivalent
boe/day	barrels of oil equivalent per calendar day
GJ	gigajoule
long ton/day	imperial measurement of a metric tonne per calendar day
mbbls	thousand barrels
mbbls/day	thousand barrels per calendar day
mboe	thousand barrels of oil equivalent
mboe/day	thousand barrels of oil equivalent per calendar day
mcf	thousand cubic feet
mcf/day	thousand cubic feet per calendar day
MJ	megajoule
mmbbls	million barrels
mmboe	million barrels of oil equivalent
mmbtu	million British thermal units
mmcf	million cubic feet
mmcf/day	million cubic feet per calendar day

abandonment and reclamation costs

All costs associated with the process of restoring the Company’s properties that have been disturbed by oil and gas activities to a standard imposed by applicable government or regulatory authorities, including costs associated with the retirement of upstream and downstream assets which consist primarily of plugging and abandoning wells, abandoning surface and subsea plant, equipment and facilities, and restoring land.

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ABCA

Business Corporations Act (Alberta).

API gravity

Measure of oil density or specific gravity used in the petroleum industry. The API scale expresses density such that the greater the density of the petroleum, the lower the degree of API gravity.

Asphalt Refinery

The asphalt refinery owned by the Company and located in Lloydminster, Alberta.

Audit Committee

The Audit Committee of the Board.

barrel

A unit of volume equal to 42 U.S. gallons.

bitumen

A naturally occurring solid or semi-solid hydrocarbon, consisting mainly of heavier hydrocarbons with a viscosity greater than 10,000 millipascal-seconds or 10,000 centipoise measured at the hydrocarbon’s original temperature in the reservoir and at atmospheric pressure on a gas-free basis, and that is not primarily recoverable at economic rates through a well without the implementation of enhanced recovery methods.

Board

The Board of Directors of the Company.

Board Committees

Collectively, the Audit Committee, the Compensation Committee, the Corporate Governance Committee and the HS&E Committee.

BP-Husky Toledo Refinery

The crude oil refinery owned 50% by the Company and 50% by BP Corporation North America Inc. and located in Toledo, Ohio.

Cenovus

Cenovus Energy Inc.

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CHOPS

Cold heavy oil production with sand.

C-NLOPB

Canada-Newfoundland Offshore Petroleum Board

CNOOC

CNOOC Limited

CO₂

Carbon dioxide.

CO₂e

Carbon dioxide equivalent.

Compensation Committee

The Compensation Committee of the Board.

conventional natural gas

Natural gas that has been generated elsewhere and has migrated as a result of hydrodynamic forces and is trapped in discrete accumulations by seals that may be formed by localized structural, depositional or erosional geological features.

Corporate Governance Committee

The Corporate Governance Committee of the Board.

DBRS

Dominion Bond Rating Services Limited

development well

A well drilled within the proved area of an oil and gas reservoir to the depth of a stratigraphic horizon known to be productive.

diluent

A lighter gravity liquid hydrocarbon, usually condensate or synthetic crude oil, added to heavy oil and bitumen to facilitate the transmissibility of the oil through a pipeline.

DSU

A deferred share unit issued under the Company’s Share Accumulation Plan for Directors.

enhanced oil recovery or EOR

The increased recovery from a crude oil pool achieved by artificial means or by the application of energy extrinsic to the pool. An artificial means or application includes pressuring, cycling, pressure maintenance or injection to the pool of a substance or form of energy but does not include the injection in a well of a substance or form of energy for the sole purpose of aiding in the lifting of fluids in the well, or stimulation of the reservoir at or near the well by mechanical, chemical, thermal or explosive means.

exploration licence or EL

A licence with respect to the Canadian offshore or the Northwest Territories conferring the right to explore for, and the exclusive right to drill and test for, hydrocarbons and petroleum, the exclusive right to develop the applicable area in order to produce petroleum and, subject to satisfying the requirements for issuance of a production licence and compliance with the terms of the licence and other provisions of the relevant legislation, the exclusive right to obtain a production licence.

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exploration well

A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas. Generally, an exploration well is any well that is not a development well, a service well, an extension well, which is a well drilled to extend the limits of a known reservoir, or a stratigraphic test well as those terms are defined herein.

feedstock

Raw materials which are processed into petroleum products.

field

An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both.

FPSO

Floating production, storage and offloading vessel.

GAAP

Generally accepted accounting principles, consistently applied.

GHG

Greenhouse gas.

gross/net acres and gross/net wells

Gross refers to the total number of acres or wells, as the context requires, in which a working interest is owned. Net refers to the sum of the fractional working interests owned by a company.

gross reserves and gross production

A company’s working interest share of reserves or production, as the context requires, before deduction of royalties.

GSA

Gas sales agreement.

heavy crude oil

Crude oil with a relative density greater than 10 degrees API gravity and less than or equal to 22.3 degrees API gravity.

high-TAN

A measure of acidity. Crude oils with a high content of naphthenic acids are referred to as high total acid number (“TAN”) crude oils or high acid crude oil. The TAN value is defined as the milligrams of Potassium Hydroxide required to neutralize the acidic group of one gram of the oil sample. Crude oils in the industry with a TAN value greater than one are referred to as high-TAN crudes.

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HMLP

Husky Midstream Limited Partnership.

HS&E

Health, safety and environment.

HS&E Committee

The Health, Safety and Environment Committee of the Board.

light crude oil

Crude oil with a relative density greater than 31.1 degrees API gravity.

Lima Refinery

The crude oil refinery owned by the Company and located in Lima, Ohio.

liquefied petroleum gas

Liquefied propanes and butanes, separately or in mixtures.

medium crude oil

Crude oil with a relative density greater than 22.3 degrees API gravity and less than or equal to 31.1 degrees API gravity.

natural gas

A naturally occurring hydrocarbon gas and other gases.

natural gas liquids or NGL

Those hydrocarbon components recovered from raw natural gas as liquids by processing through extraction plants, or recovered from field separators, scrubbers or other gathering facilities. These liquids include the hydrocarbon components ethane, propane and butane and condensates and combinations thereof.

net revenue

Gross revenue less royalties.

NL

Newfoundland and Labrador.

oil sands

Sands and other rock materials that contain bitumen and all other mineral substances in association therewith.

OPEC

Organization of the Petroleum Exporting Countries.

operating netback

Gross revenue less production, operating and transportation costs and royalties on a per unit basis.

petroleum coke

A carbonaceous solid delivered from oil refinery coker units or other cracking processes.

production licence

Confers, with respect to the portions of the offshore area to which the licence applies, the right to explore for, and the exclusive right to drill and test for, petroleum, the exclusive right to develop those portions of the offshore area in order to produce petroleum, the exclusive right to produce petroleum from those portions of the offshore area and title to the petroleum produced.

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production sharing contract or PSC

A contract for the development of resources under which the contractor’s costs (investment) are recoverable each year out of the production but with a maximum amount of production that can be applied to the cost recovery in any year.

Scope 1 emissions

Direct emissions from sources that are owned or controlled by the Company, as prescribed by the U.S. Environmental Protection Agency.

Scope 2 emissions

Indirect emissions from sources that are owned or controlled by the Company, as prescribed by the U.S. Environmental Protection Agency.

SEC

United States Securities and Exchange Commission.

SEDAR

System for Electronic Document Analysis and Retrieval.

secondary recovery

Oil or gas recovered by injecting water or gas into the reservoir to force additional oil or gas to the producing wells. Usually, but not necessarily, this is done after the primary recovery phase has passed.

seismic survey

A method by which the physical attributes in the outer rock shell of the earth are determined by measuring, with a seismograph, the rate of transmission of shock waves through the various rock formations.

service well

A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, saltwater disposal, water supply for injection, observation or injection for in-situ combustion.

Significant Discovery Declaration

A discovery indicated by the first well on a geological feature that demonstrates by flow testing the existence of hydrocarbons in that feature and, having regard to geological and engineering factors, suggests the existence of an accumulation of hydrocarbons that has potential for sustained production.

Significant Discovery Licence

The document of “title” by which an interest owner can continue to hold rights to a discovery area while the extent of that discovery is determined and, if it has potential to be brought into commercial production in the future, until commercial development becomes viable. A significant discovery licence is effective from the application date and remains in force for so long as the relevant declaration of significant discovery is in force, or until a production licence is issued for the relevant lands.

spot price

The price for a one-time open market transaction for immediate delivery of a specific quantity of product at a specific location where the commodity is purchased “on the spot” at current market rates.

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steam-assisted gravity drainage or SAGD

An enhanced oil recovery method used to produce heavy crude oil and bitumen in-situ. Steam is injected via a horizontal well along a producing formation. The temperature in the formation increases and lowers the viscosity of the crude oil allowing it to fall into a horizontal production well beneath the steam injection well.

stratigraphic test well

A hole drilled to delineate or derisk the geology, and may include the cutting of cores, to aid in exploring and developing for oil and gas and usually drilled without the intent of being completed for production.

sulphur

An element that occurs in natural gas and petroleum.

Superior Refinery

The crude oil refinery owned by the Company and located in Superior, Wisconsin.

synthetic crude oil

A mixture of hydrocarbons derived by upgrading heavy crude oils, including bitumen, through a process that reduces the carbon content and increases the hydrogen content.

thermal

Use of steam injection into the reservoir in order to enable the heavy oil and bitumen to flow to the well bore.

Tidewater

Tidewater Midstream and Infrastructure Ltd.

TSX

Toronto Stock Exchange.

turnaround

Performance of plant or facility maintenance.

Upgrader

The heavy oil upgrading facility owned and operated by the Company and located in Lloydminster, Saskatchewan.

waterflood

One method of secondary recovery in which water is injected into an oil reservoir for the purpose of forcing oil out of the reservoir and into the bore of a producing well.

wellhead

The structure, sometimes called the “Christmas tree”, that is positioned on the surface over a well and used to control the flow of oil or gas as it emerges from the subsurface casing head.

working interest

A percentage of ownership in an oil and gas lease granting its owners the right to explore, drill and produce oil and gas from a property.

2-D seismic survey

Two-dimensional seismic imaging uses seismic wave data recorded on one receiver line on the ground, to output a single cross-section of seismic data that is used to detect geologic variations in the subsurface.

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3-D seismic survey

Three-dimensional seismic imaging uses seismic wave data recorded simultaneously on a series of parallel receiver lines on the ground, to output a three-dimensional volume of seismic data that is used to detect geologic variations in the subsurface.

2018 U.S. Shelf Prospectus and Registration Statement

The universal short form base shelf prospectus filed by the Company on January 29, 2018 with the Alberta Securities Commission and the related U.S. registration statement (containing such prospectus) filed with the SEC that became effective on January 30, 2018.

2019 Canadian Shelf Prospectus

The universal short form base shelf prospectus filed by the Company on May 1, 2019 with the applicable securities regulators in each of the provinces of Canada.

2020 U.S. Shelf Prospectus and Registration Statement

The universal short form base shelf prospectus filed by the Company on March 3, 2020 with the Alberta Securities Commission and the related U.S. registration statement (containing such prospectus) filed with the SEC that became effective on March 4, 2020.

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EXCHANGE RATE INFORMATION

The following table discloses various indicators of the Canadian dollar/U.S. dollar rate of exchange or the cost of a U.S. dollar in Canadian currency for the three years indicated.

	Year ended December 31,
Exchange Rate Information (Cdn$ per US$)	2020		2019		2018
Year-end(1)		1.276		1.297		1.365
Low		1.272		1.297		1.228
High		1.454		1.359		1.365
Average		1.340		1.327		1.296

⁽¹⁾ The year-end exchange rates were quoted by the Thomson Reuters WM/R for the noon rate at the last day of the relevant period. The high, low and average rates were either quoted or calculated within each of the relevant periods.

CORPORATE STRUCTURE

Incorporation and Organization

Husky Energy Inc. was incorporated under the ABCA on June 21, 2000. The Company’s articles were amended effective February 28, 2011 to permit the issuance of common shares as payment of stock dividends on the common shares and to authorize preferred shares to be issued in one or more series. The Company’s articles were amended: effective March 11, 2011; to create Cumulative Redeemable Preferred Shares, Series 1 (the “Series 1 Preferred Shares”) and Cumulative Redeemable Preferred Shares, Series 2 (the “Series 2 Preferred Shares”); effective December 4, 2014; to create Cumulative Redeemable Preferred Shares, Series 3 (the “Series 3 Preferred Shares”) and Cumulative Redeemable Preferred Shares, Series 4 (the “Series 4 Preferred Shares”); effective March 9, 2015; to create Cumulative Redeemable Preferred Shares, Series 5 (the “Series 5 Preferred Shares”) and Cumulative Redeemable Preferred Shares, Series 6 (the “Series 6 Preferred Shares”); and effective June 15, 2015; to create Cumulative Redeemable Preferred Shares, Series 7 (the “Series 7 Preferred Shares”) and Cumulative Redeemable Preferred Shares, Series 8 (the “Series 8 Preferred Shares”). Husky’s registered office and head and principal office are located at 707 - 8^th Avenue S.W., Calgary, Alberta, T2P 1H5.

Intercorporate Relationships

The following table lists Husky’s significant subsidiaries and jointly-controlled entities and their respective places of incorporation, continuance or organization, as the case may be, as at December 31, 2020. All of the entities listed below, except as otherwise indicated, are 100% beneficially owned, or controlled or directed, directly or indirectly, by Husky.

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Significant Subsidiaries and Joint Operations(1)	Jurisdiction
Husky Oil Operations Limited	Alberta
Husky Energy International Corporation	Alberta
Lima Refining Company	Delaware
Husky Marketing and Supply Company	Delaware
Husky Oil Limited Partnership	Alberta
Husky Canadian Petroleum Marketing Partnership	Alberta
Husky Energy Marketing Partnership	Alberta
Sunrise Oil Sands Partnership (50%)	Alberta
BP-Husky Refining LLC (50%)	Delaware

⁽¹⁾ Principal operating subsidiaries exclusive of intercorporate relationships due to financing related receivables and financing investments.

GENERAL DEVELOPMENT OF HUSKY

Three-year History of Husky

The following is a description of how Husky’s business has developed over the last three completed financial years.

2018

On January 17, 2018, the Company announced that it would begin taking steps to suspend operations of the SeaRose FPSO and associated production facilities offshore NL to comply with an order received from the C-NLOPB related to an iceberg management incident that occurred in March 2017.

On January 26, 2018, the Company announced that the C-NLOPB had lifted the notice to suspend operations of the SeaRose FPSO and associated facilities and that the Company would resume operations.

On March 1, 2018, the Company announced the establishment of a quarterly cash dividend of $0.075 per common share.

On April 26, 2018, a fire occurred at the Superior Refinery and operations were suspended.

On May 18, 2018, the Company announced that it had drilled a successful exploration well on Block 15/33 in the South China Sea, signed two PSCs for Block 22/11 and Block 23/07 in the Beibu Gulf area of the South China Sea and made a discovery at the White Rose A-24 exploration well offshore NL.

On July 26, 2018, the Company announced that the Board had approved an increase in the quarterly cash dividend to $0.125 per common share.

During the third quarter of 2018, the BD Project achieved total daily sales targets of 100 mmcf/day of conventional natural gas (40 mmcf/day Husky working interest) and 6,000 bbls/day of associated NGL (2,400 bbls/day Husky working interest).

On October 2, 2018, the Company announced that it had commenced an unsolicited offer to acquire all of the outstanding common shares of MEG Energy Corp. (“MEG”).

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In October 2018, the Tucker Thermal Project reached nameplate capacity of 30,000 bbls/day.

Also in October 2018, the Rush Lake 2 thermal project achieved first production, with nameplate capacity of 10,000 bbls/day achieved in November 2018.

In November 2018, the Company shut in oil production at the White Rose field due to operational safety concerns resulting from severe weather and an oil release on November 16.

Also in November 2018, the Spruce Lake East thermal project in Saskatchewan was sanctioned.

In December 2018, the Sunrise Energy Project reached its nameplate capacity of 60,000 bbls/day (30,000 bbls/day Husky working interest).

2019

On January 8, 2019, the Company announced that it would be undertaking a strategic review and potentially selling its Canadian Retail and Commercial Fuels Network and the Prince George Refinery.

On January 16, 2019, the Company’s unsolicited offer to acquire all of the outstanding common shares of MEG expired with the minimum tender condition not having been met. The Company did not extend the offer due to a lack of support from the MEG board of directors and MEG shareholders.

On January 30, 2019, partial production resumed at the White Rose field following the shut-in of production announced in November 2018.

On March 15, 2019, the Company issued US$750 million of 4.400% notes maturing on April 15, 2029 by way of a prospectus supplement dated March 13, 2019 to the 2018 U.S. Shelf Prospectus and Registration Statement.

In the first quarter of 2019, regulatory approval was received for the Spruce Lake East thermal project.

On June 12, 2019, the Company entered guilty pleas on federal and provincial charges related to a 2016 oil spill in Saskatchewan and agreed to pay fines totaling $3.82 million.

On August 16, 2019, the Company announced that it would resume full production at the White Rose field.

On August 26, 2019, the Company announced that it had commenced production at its 10,000 barrel-per-day Dee Valley thermal project in Saskatchewan.

On September 30, 2019, the Company announced that it had received the required permit approvals to begin construction activities at the Superior Refinery following the April 2018 fire.

On November 1, 2019, the Company announced the closing of the sale of the Prince George Refinery to Tidewater for $215 million in cash plus a closing adjustment of approximately $53.5 million.

On December 20, 2019, production operations on the Terra Nova FPSO were safely shut-in in response to a C-NLOPB order citing insufficient redundancy of fire water pumps. See “Description of Husky’s Business - Offshore - Atlantic - Terra Nova Field”.

Husky Energy Inc. | Annual Information Form 2020 | 11

2020

On March 3, 2020, the Company filed the 2020 U.S. Shelf Prospectus and Registration Statement, which enabled the Company to offer up to US$3.0 billion of debt securities, common shares, preferred shares, subscription receipts, warrants and units of the Company in the U.S. On January 26, 2021, the Company terminated the effectiveness of the U.S. registration statement.

On March 12, 2020, the Company announced that it would be cutting its 2020 capital spending by $900 million and $100 million in additional cost-saving measures to fortify its business in response to challenging global market conditions.

On March 22, 2020, the Company announced that it would begin a systematic and orderly suspension of major construction activities related to the West White Rose Project in an effort to prevent the transmission of the COVID-19 virus among the Company’s employees and contractors and the local community.

On April 20, 2020, the Company announced that it would cut 2020 capital spending to $1.7 billion, that it had increased its liquidity with the addition of a $500 million term loan, that Integrated Corridor (as defined herein) upstream production had been reduced by over 80,000 bbls/day and that U.S. refinery throughput had been reduced by 95,000 bbls/day.

On April 20, 2020, the Company announced it has suspended the strategic review of its Canadian Retail and Commercial Fuels Network due to the market environment.

On August 4, 2020, the Company announced the release of its 2020 Environment, Social, and Governance Performance Report (the “ESG Report”), including a Scope 1 GHG emissions intensity reduction target of 25% by 2025 with an aspiration to be net zero by 2050. The Company also announced a gender diversity target of 25% women in senior leadership roles.

On August 7, 2020, the Company issued $1.25 billion of 3.50% notes maturing on February 7, 2028 by way of a prospectus supplement dated August 5, 2020 to the 2019 Canadian Shelf Prospectus.

On September 2, 2020, the Company announced that it had achieved first oil at the Spruce Lake Central thermal project and that it was moving towards startup of the Liuhua 29-1 field at the Liwan Gas Project.

On September 9, 2020, the Company announced that it would be conducting a review of the scope, schedule and cost of the West White Rose Project as a result of the one-year delay to first oil caused by the COVID-19 pandemic.

On September 29, 2020, the Company announced that commissioning had been completed at the third field at the Liwan Gas Project, ahead of schedule and $100 million below budget.

On October 25, 2020, the Company and Cenovus jointly announced that they had entered into a definitive arrangement agreement under which they would combine in an all-stock transaction by way of plan of arrangement under the ABCA (the “Cenovus Transaction”).

Recent Developments

On January 4, 2021, the Company announced that the Cenovus Transaction was completed on January 1, 2021. As a result of the Cenovus Transaction, Husky has become a wholly-owned subsidiary of Cenovus, and the Husky common shares and preferred shares were delisted from the TSX at the close of trading on January 5, 2021.

Husky Energy Inc. | Annual Information Form 2020 | 12

DESCRIPTION OF HUSKY’S BUSINESS

Overview

Husky is a Canadian integrated energy company based in Calgary, Alberta.

Effective January 1, 2020, the Company’s businesses were reorganized under two new 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

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

The Lloydminster Heavy Oil Value Chain includes the exploration for, and development and production of, heavy crude oil and bitumen, and production of ethanol. Blended heavy crude oil and bitumen are either sold directly to the Canadian market or transported utilizing the HMLP pipeline systems to the Keystone pipeline and other pipelines to be sold in the U.S. downstream market. Heavy crude oil can be upgraded at the Upgrader and Asphalt Refinery into synthetic crude oil, diesel fuel and asphalt. This business also includes the marketing and transportation of both the Company’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 the Company’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. The Company 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.

The Oil Sands business includes the exploration for, and development and production of, bitumen within the Sunrise Energy Project. It also includes the marketing and transportation of the Company’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.

The Western Canada Production business includes the exploration for, and development and production of, light crude oil, conventional natural gas and NGL in Western Canada. The Company’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.

The U.S. Refining business includes the refining of crude oil at the Lima Refinery, the BP-Husky Toledo Refinery and the Superior Refinery in the U.S. Midwest to produce diesel fuel, gasoline, jet fuel, asphalt and other products. The Company 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 its own and third-party volumes of refined petroleum products, including gasoline and diesel, through petroleum outlets.

Offshore

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

Husky Energy Inc. | Annual Information Form 2020 | 13

Corporate Strategy

The Company’s business strategy is to generate returns from investing in a portfolio of projects and other opportunities across the Integrated Corridor and Offshore businesses. These projects and investments are intended to provide for increasing margins, funds from operations and earnings. A strong balance sheet, deep physical integration and largely fixed price contracts in Asia Pacific provide resilience to market volatility while preserving upside exposure to rising commodity prices.

Integrated Corridor

Third-Party Pipeline Commitments

In 2010, the Company commenced its pipeline commitment on the Keystone pipeline system, which ships Canadian crude oil from Hardisty, Alberta to Patoka, Illinois. This commitment was part of a strategy, commenced in 2006, to expand the market for the Company’s crude oil into the U.S. Midwest. This strategy was further supported through the acquisition of the Lima Refinery in 2007, which enabled the Company’s Canadian synthetic crude oil and bitumen production, along with additional third-party crude and other feedstocks, to be processed at the refinery. The Company has the ability to utilize the portion of the Keystone pipeline system that continues to Cushing, Oklahoma, and the Company 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 the Company’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 the Company to transport crude oil through interconnecting pipeline systems to the Lima Refinery and/or sell it into the Cushing, Oklahoma market.

Since 2012, the pipeline systems leaving Canada have at times been subject to significant apportionment, affecting both Canadian export volumes and crude oil prices in Western Canada. The Company has mitigated these effects through the reliability of its proprietary pipeline system, its priority capacity on export pipelines and its demand for Canadian crude oil feedstock for its Canadian upgrading and refining assets. In 2017, the Company further enhanced this integration when it 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, the Company has a relatively balanced exposure to many location and grade differentials.

In December of 2018, the Government of Alberta imposed an oil production curtailment order through production quotas. Although the curtailment policy officially runs through 2021, curtailment was reduced to zero effective December 1, 2020.

Commodity Marketing

The Company has developed its commodity marketing operations to include the acquisition of third-party volumes to enhance the value of its Integrated Corridor assets.

Currently, the Company is a marketer of both its own and third-party production of crude oil, synthetic crude oil, NGL, natural gas and sulphur. The Company also markets petroleum coke, a by-product from the Upgrader and its Ohio refineries. The Company supplies feedstock to its Upgrader and Asphalt Refinery from its own and third-party heavy oil and bitumen production sourced from the Lloydminster and Cold Lake areas. The Company also sells blended heavy crude oil directly to refiners based in the U.S. and Canada. The extensive infrastructure in the Lloydminster area supports the Company’s heavy crude oil refining, upgrading and marketing operations. The Company markets light and medium crude oil and NGL sourced from its own production and third-party production. Light crude oil is acquired for processing by the Lima Refinery and the Superior Refinery. The Company supplies a portion of the synthetic crude oil produced at its Upgrader to the Lima Refinery and Superior Refinery, and markets the rest to refiners in Canada and the U.S.

Husky Energy Inc. | Annual Information Form 2020 | 14

The Company markets natural gas sourced from its own production and third-party production. The Company is currently committed to gas sales contracts with third parties, which in aggregate do not exceed amounts forecasted to be deliverable from the Company’s reserves. The Company trades natural gas to generate revenue from managed assets, including transportation and natural gas storage facilities.

Lloydminster Heavy Oil Value Chain

Thermal and Non-Thermal Developments

Heavy Oil and Bitumen

The majority of the Company’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 the Company’s operations are 100% working interest. The Company’s operations are supported by a network of facilities and pipelines that transport heavy crude oil and bitumen from the field locations to the Asphalt Refinery, the Upgrader and the Company’s other assets in the Integrated Corridor, thus providing full integration.

Production of heavy crude oil and bitumen from the Lloydminster area uses a variety of technologies, including SAGD, CHOPS, horizontal wells, waterflooded fields and non-thermal EOR.

Lloydminster Thermal Projects

Lloydminster bitumen production consists of 11 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. 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 in 2020 from Lloydminster thermal projects averaged 81,000 bbls/day.

The Company has an inventory of Saskatchewan thermal projects. These long-life developments are built with modular, repeatable designs and require low sustaining capital once brought online. Late in the first quarter of 2020, market conditions changed materially due to both the COVID-19 pandemic and falling commodity prices. Given the flexible nature of these projects, the Company has reduced activity on all future thermal projects.

The following table shows major projects and their status as at December 31, 2020:

Project Name	Nameplate Capacity (bbls/day)	Expected Project Production Date	Project Status
Spruce Lake Central	10,000	On Production	First oil was achieved on August 26, 2020 with design capacity reached early December.
Spruce Lake North	10,000	2024	Central Processing Facility (“CPF”) is 81% complete. CPF construction has been placed on hold. Overall project is 69% complete.

The remaining projects were placed on hold due to deteriorating market conditions in 2020 and are undergoing re-evaluation of production options to maximize value.

Tucker Thermal Project

The Tucker Thermal Project is a SAGD oil sands project located 30 kilometres northwest of Cold Lake, Alberta. It commenced bitumen production at the end of 2006.

Bitumen production for 2020 averaged 18,300 bbls/day.

A major plant turnaround was completed for the CPF and field in 2020.

Husky Energy Inc. | Annual Information Form 2020 | 15

Cold and EOR

Production from the Cold and EOR business consists of a combination of production technologies including CHOPS and horizontal wells and EOR projects.

During 2020, the Company 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. The Company is also piloting a CO₂ capture technology at its Pikes Peak South facility in Saskatchewan.

Production for 2020 averaged 21,400 bbls/day of heavy crude oil, 1,400 bbls/day of medium crude oil and 11.2 mmcf/day of conventional natural gas.

Upgrading Operations

The Company owns and operates the Upgrader. The 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 Upgrader was commissioned in 1992 with an original design capacity of 46,000 bbls/day of synthetic crude oil. In 2007, the Upgrader commenced production of transportation grade diesel. The Upgrader’s current rated production capacity is 81,500 bbls/day of synthetic crude oil, diluent and ultra low sulphur diesel.

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

Lloydminster Asphalt Refinery

The 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 bbls/day of heavy crude oil and bitumen. The refinery also produces straight run gasoline, bulk distillates and industrial products. The straight run gasoline stream is removed and re-circulated into HMLP’s pipeline network as pipeline diluent. The distillate stream is transferred to the 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 bbls/day of blended heavy crude oil and bitumen feedstock during 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. The Company 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 Asphalt Refinery to run at or near full capacity throughout the year.

Asphalt Distribution Network

In addition to sales directly from the Asphalt Refinery, the Company, 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. The Company also markets asphalt from independently operated terminals in the states of Washington, Minnesota, Wisconsin and Ohio.

Husky Energy Inc. | Annual Information Form 2020 | 16

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 the U.S. Refining business segment.

Ethanol Plants

In September 2006, the Company commissioned an ethanol plant in Lloydminster, Saskatchewan. The plant has an annual nameplate capacity of 130 million litres. In December 2007, the Minnedosa, Manitoba ethanol plant was commissioned also with an annual nameplate capacity of 130 million litres. In 2020, combined ethanol production averaged 733,000 litres/day.

During 2012, the Lloydminster plant commissioned a CO₂ capture facility. The plant is currently capturing CO₂ for use in the Company’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%, Power Assets Holdings Limited owns 48.75% and Husky owns 35% of HMLP and Husky is the operator. HMLP has approximately 2,200 kilometres of pipeline in the Lloydminster region, 5.9 million barrels of storage capacity at Hardisty and Lloydminster and other ancillary assets. The 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 Upgrader and 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. The Hardisty terminal, with a total storage capacity of 4.9 million barrels, acts as the exclusive blending hub for Western Canada Select (“WCS”), the largest heavy oil benchmark pricing point in North America. HMLP has diversified its operations with the Ansell Corser Gas Plant, with 120 mmcf/day of processing capacity.

HMLP has a separate board of directors from Husky and independent financing that supports both significant growth projects that are under construction and planned future expansions.

The Hardisty terminal was expanded in 2020 to provide additional pipeline connectivity and crude oil storage for customers. The assets play an integral role in the transportation of heavy oil and bitumen production to end markets by providing connections to the Upgrader and the Asphalt Refinery, third-party terminals and pipelines through strategic hubs such as the Hardisty Terminal.

Oil Sands

Sunrise Energy Project

On March 31, 2008, Husky and BP Corporation North America Inc. completed a transaction that created an 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 in 2020 averaged approximately 44,800 bbls/day (22,400 bbls/day Husky working interest).

At the end of 2020, there were 81 producing wells. Six infills have been drilled and are ready for tie-in. Three additional well pairs will be on production early in 2021.

The scheduled 2020 turnaround on plant 1B was deferred to 2021 due to COVID-19 pandemic concerns.

Husky Energy Inc. | Annual Information Form 2020 | 17

Western Canada Production

Northern Operations

The Company’s Northern Operations are located primarily in northwest Alberta. Production in 2020 consisted of approximately 1,176 bbls/day of light crude oil, 5,208 bbls/day of NGL and 148.2 mmcf/day of conventional natural gas reflecting heavily weighted conventional natural gas production of approximately 79%. 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. The Company holds an average 95% working interest in approximately 177 net sections of contiguous lands. The Company has been actively developing the Spirit River formations since 2012 using multi-stage fractured horizontal wells. Production from the Ansell and Galloway areas has doubled since 2012 and in 2020 averaged 1,420 bbls/day of NGL and 100.1 mmcf/day of conventional natural gas. In 2020, the Company drilled four wells and completed four wells.

Grande Prairie operations are located primarily in northwest Alberta and consist primarily of the Wembley, Kakwa, and Wapiti areas. Production from Grande Prairie in 2020 averaged 1,170 bbls/day of light crude oil, 3,794 bbls/day of NGL and 48.1 mmcf/day of conventional natural gas. A drilling program targeting the oil and liquids-rich natural gas Montney formation in the Wembley area continued with two wells drilled and three wells completed in 2020. Three of these wells were brought on production late in the first quarter of 2020 and had production of 500 boe/day in 2020. The Kakwa Spirit River liquids-rich natural gas resource play averaged 36 bbls/day of light crude oil, 1,861 bbls/day of NGL and 27.8 mmcf/day of conventional natural gas in 2020. Wapiti averaged 976 bbls/day of light crude oil, 585 bbls/day of NGL and 3.8 mmcf/day of conventional natural gas in 2020.

Southern Operations

The Company’s Southern Operations are primarily located in central and southern Alberta. As at December 31, 2020, the Company operated three natural gas facilities with approximately 600 active wells throughout the area. Production in 2020 averaged 265 bbls/day of light crude oil, 1,500 bbls/day of NGL and 23.1 mmcf/day of conventional natural gas. In February 2020, the Company sold its assets in the Hussar area. Production from these assets averaged 270 boe/day in 2020.

Rainbow Lake Operations

Rainbow Lake, located approximately 900 kilometres northwest of Edmonton, Alberta, is the site of the Company’s largest light crude oil production operation in Western Canada. Production during 2020 from the Rainbow Lake assets averaged 4,286 bbls/day of light crude oil, 3,500 bbls/day of NGL and 78.7 mmcf/day of conventional natural gas.

The Company holds a 50% interest in a 90 megawatt natural gas fired cogeneration facility adjacent to its Rainbow Lake processing plant. The cogeneration facility produces electricity and thermal energy, or steam, for the Rainbow Lake processing plant. Additional electricity is also generated for the Power Pool of Alberta.

Northwest Territories

The Company held two ELs acquired in 2011 in the Northwest Territories at the Slater River Canol shale play, which were consolidated as one EL in 2015 and cover 483,000 gross acres (466,000 net acres). Two pilot wells were drilled and suspended in 2012 which satisfied the requirements to extend the term of both the ELs to their full nine-year term. In 2016, the Company was awarded a Significant Discovery Declaration on 545 sections (150,000 hectares) of land within the ELs north of the Gambill Fault, and granted separately a Significant Discovery Licence over five sections of land south of the Gambill Fault. Abandonment work on the two pilot wells and 12 water monitoring wells in addition to reclamation of well sites and surplus infrastructure were completed in the third quarter of 2019. The existing infrastructure that will remain in place to service the Significant Discovery Declaration is under care and maintenance.

Husky Energy Inc. | Annual Information Form 2020 | 18

Canadian Refined Products

Retail and Commercial Network

In 2017, the Company and Imperial Oil combined commercial operations to create a single truck transport network of more than 150 cardlock sites, under the Esso brand. As part of the initial agreement, in 2019, 61 locations were converted to offer Esso Synergy fuel, including the retail fuel dispensers at the Company’s travel centres, as well as a select number of retail stations across the network.

As of December 31, 2020, there were 546 independently operated Husky and Esso-branded petroleum product outlets. The Company’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 the Company’s bulk distributors offer direct sales to commercial and agricultural markets in the Prairie provinces.

On April 20, 2020, the Company announced that it had suspended the strategic review of its Canadian Retail and Commercial Fuels business due to the market environment.

Retail outlets offer a variety of services, including convenience stores, service bays, 24-hour accessibility, car washes, Husky House Restaurants and proprietary and co-branded quick-serve restaurants. In addition to ethanol-blended gasoline, the Company sells diesel, propane and Mobil-branded lubricants to customers. The Company supplies refined petroleum products to its branded independent retailers on an exclusive basis and provides financial and other assistance for location improvements, marketing support and related services.

Other Supply Arrangements

During 2020, the Company purchased approximately 30,399 bbls/day of refined petroleum products of which 27,839 bbls/day were pursuant to agreements with Imperial Oil. The Company also acquired approximately 6,686 bbls/day of refined petroleum products pursuant to exchange agreements with third-party refiners.

The following table shows the number of Husky and Esso-branded petroleum outlets by province as of December 31, 2020:

	British Columbia		Alberta		Saskatchewan		Manitoba		Ontario		Quebec		New Brunswick		2020 Total		2019 Total
Husky-Branded Petroleum Outlets
Retail Owned Outlets		35		41		8		12		54		—		—		150		152
Leased		28		26		3		7		22		—		—		86		91
Independent Retailers		44		56		13		3		13		—		—		129		134
Total		107		123		24		22		89		—		—		365		377
Esso-Branded Petroleum Outlets
Retail Owned Outlets		18		19		4		4		15		—		—		60		59
Leased		3		4		—		3		3		—		—		13		13
Independent Retailers		35		24		4		6		32		6		1		108		103
Total		56		47		8		13		50		6		1		181		175
Cardlocks(1)		51		47		9		11		44		6		1		169		164
Convenience Stores(1)		76		79		14		21		92		—		—		282		291
Restaurants		8		8		3		1		13		—		—		33		34

⁽¹⁾ Located at branded petroleum outlets.

Husky Energy Inc. | Annual Information Form 2020 | 19

The Company also markets refined petroleum products directly to various commercial markets, including independent dealers, national rail companies and major industrial and commercial customers in Canada.

The following table shows average daily sales volumes of light refined petroleum products for the periods indicated:

	Years ended December 31,
Average Daily Sales Volume (mbbls/day)	2020		2019		2018
Gasoline		17.3		20.5		21.7
Diesel fuel		24.4		25.7		26.5
Liquefied petroleum gas		0.3		0.5		0.2
		42.0		46.7		48.4

U.S. Refining

Lima Refinery

The Lima Refinery has a crude oil throughput capacity of up to 175,000 bbls/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 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 production throughput at the Lima Refinery averaged 140,000 bbls/day. Production consisted of gasoline averaging 68,000 bbls/day, total distillates averaging 53,000 bbls/day and total other products averaging 19,000 bbls/day.

The crude oil flexibility project was commissioned in early 2020 and is designed to allow for the processing of up to 40,000 bbls/day of heavy crude oil feedstock from Western Canada, providing the ability to swing between light and heavy crude oil feedstock.

BP-Husky Toledo Refinery

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

A feedstock optimization project completed during the 2016 turnaround improved the BP-Husky Toledo Refinery’s ability to process high-TAN crude oil to support production from the Sunrise Energy Project. Since January 1, 2017, the Company has been marketing its share of the joint operation’s refined products.

During 2020, the Company’s share of total throughput averaged 65,400 bbls/day, with the Company’s share of sales of gasoline averaging 38,900 bbls/day, distillates averaging 20,100 bbls/day and other fuel and feedstock averaging 9,600 bbls/day.

Superior Refinery

On November 8, 2017, the Company completed the acquisition of the Superior Refinery, which had a permitted throughput capacity of 50,000 bbls/day and an operating capacity of 45,000 bbls/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.

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The refinery also has associated infrastructure including five storage and distribution terminals that are strategically located throughout the northern area of the United States. 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 the Company anticipates a substantial portion of the investment will be recovered from property damage insurance. The refinery is expected to restart around the first quarter of 2023, with a nameplate processing capacity of 49,000 mbbls/day, including capability to process up to 34,000 bbls/day of heavy oil while producing asphalt, gasoline and diesel.

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

The Company has a 49% working interest in the Liwan 3-1 and Liuhua 34-2 fields and a 75% working interest in the Liuhua 29-1 field, and CNOOC has 51% and 25% working interests, respectively. The initial development of the Liwan 3-1 and Liuhua 34-2 fields was separated into deepwater and shallow water development projects, with the Company acting as operator of the deepwater wells, the deepwater production systems and the pipeline while CNOOC is the operator of the shallow water platform and the onshore gas processing facility at Gaolan. The deepwater infrastructure includes the production wells and trees, as well as the subsea pipelines and infrastructure that produces through twin 22-inch deepwater pipelines running approximately 78 kilometres to the “shallow water” central platform which is about 260 km from shore. The shallow water infrastructure includes the central platform (“CEP”) standing in approximately 200 metres of water, a 261-kilometre 30-inch shallow water pipeline running from the CEP to the Gaolan Onshore Gas Plant (“OSGP”), which has liquids separation facilities, NGL storage tanks, a gas liquids export jetty, a facility control system as well as administrative and accommodation buildings.

The Liwan 3-1 field commenced production at the end of March 2014. The gas field is currently producing from nine wells. The single production well in the Liuhua 34-2 field was tied into the deepwater facilities of the Liwan 3-1 field and commenced production in December 2014.

An amendment to the gas sales agreement for the Liwan 3-1 field was executed in the third quarter of 2020. The amendment is effective from August 1, 2020 until April 30, 2022, and has the effect of increasing the volume of gas the buyer must take or pay during the term, and lowering the effective price of this gas. Following April 30, 2022, the original gas sales agreement terms will take effect. Husky anticipates no material impact to its cash flow from the Liwan 3-1 field as a result.

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 CEP and Gaolan OSGP. The buyer began taking 40 mmcf/d on November 4, 2020.

In 2020, total gas sales from Liwan 3-1, Liuhua 34-2 and Liuhua 29-1 averaged 366 mmcf/day, 34 mmcf/day and 6 mmcf/day, respectively. In 2020, the Company’s working interest share of production from the three fields was 201 mmcf/day of conventional natural gas and 8,600 bbls/day of NGL.

Block 15/33

The Company executed a 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 kilometres southeast of the Hong Kong Special Administrative Region and covers an area of 155 square kilometres in water depths of approximately 80 to 100 metres. The Company is the operator of the block during the exploration phase, with a working interest of 100%. In the event of a commercial discovery, its partner CNOOC may assume a working interest of up to 51% 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 the Company.

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

Block 16/25

The Company 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 kilometres southeast of the Hong Kong Special Administrative Region and approximately 72 kilometres northeast of Block 15/33. The block covers an area of 44 square kilometres in water depths of approximately 85 to 100 metres.

The Company drilled one exploration well in the third quarter of 2018, which encountered non-commercial hydrocarbons. This well was written off in 2019.

During 2020, an amendment agreement was signed between the Company 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 an 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

The Company 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. The Company is the operator of both blocks with a working interest of 100% during the exploration phase. In the event of a commercial discovery, its partner CNOOC may assume a participating partnership interest of up to 51% in either or both blocks for the development and production phases. The Company 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, the Company signed a joint venture agreement with CPC Corporation, the Taiwan national oil and gas company. The Company and CPC Corporation have rights to an exploration block in the South China Sea covering approximately 7,700 square kilometres located southwest of the island of Taiwan. The Company holds a 75% working interest during exploration, while CPC Corporation holds the remaining 25% and has the right to participate in any development programs up to a 50% interest.

The acquisition of 2-D seismic survey data was completed in 2014, and the acquisition of 3-D seismic survey data was completed in 2017.

Indonesia

Madura Strait

The Company has a 40% interest in the joint venture that holds the Madura Strait PSC encompassing approximately 622,000 acres (2,516 square kilometres) in the Madura Strait area, located offshore East Java, Indonesia. The Company’s two partners in the incorporated joint venture are CNOOC, which is the contracted operator and has a 40% 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.

In 2020, total BD field sales averaged 86 mmcf/day of gas and 6,000 bbls/day of associated liquids. The Company’s working interest share of production was 34 mmcf/day of conventional natural gas and 2,400 bbls/day of NGLs.

At the MDA and MBH fields, the two shallow water platforms have been fully installed. Five MDA and two MBH field production wells are scheduled to be drilled in the 2021/22 timeframe. The Indonesian energy regulator has approved amendments to

Husky Energy Inc. | Annual Information Form 2020 | 23

the Floating Production Unit (“FPU”) construction contract to facilitate financing. The contracting consortium has ordered long lead equipment and is completing shipyard selection while finalizing financing to fund FPU construction. Pending completion of financing and construction of the vessel, gas sales are expected to begin in 2022. An additional shallow water field, MDK, is scheduled to be developed and tied into the MDA and MBH infrastructure. The processed gas from these three fields will be tied directly into the East Java subsea pipeline system and sold to the East Java market under long-term contracts.

At the stand-alone MAC field development, tendering for engineering, procurement and construction of all required facilities was completed early in the first quarter of 2020. Tendering for the Mobile Offshore Production Unit is in progress and a final investment decision is expected in 2021.

In Indonesia, the energy regulator has made provisions for certain industrial gas buyers to have their gas purchase price reduced. The result is that the gas sales price for a portion of BD field gas production has been reduced, however, the government has compensated the PSC contractor for reduced revenues by way of lower royalty payments. As a result, Husky anticipates no material impact to its cash flow from the BD field.

Anugerah

The Company executed a PSC in February 2014 with the Government of Indonesia for the Anugerah contract area. The Company holds a 100% interest in the Anugerah Block, which is located in the East Java Basin approximately 150 kilometres east of the Madura Strait. The block covers an area of 2,030,000 acres (8,215 square kilometres).

During 2015, the Company previously acquired 2-D seismic and 3-D seismic survey data on the contract area, which was required during the first three years of the PSC. An analysis of those data and data from offset block information indicated that exploratory drilling is not economic. The block was relinquished in 2020.

Atlantic

Overview

The Company’s Atlantic exploration and development program has been focused in the Jeanne d’Arc Basin and the Flemish Pass offshore 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, the Company holds a 35% non-operated working interest in each of the Bay du Nord, Bay de Verde, Baccalieu, Harpoon and Mizzen discoveries. The Company 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. The Company also holds significant exploration acreage offshore NL.

White Rose Field and Satellite Extensions

The White Rose field is located 354 kilometres off the coast of NL and is approximately 48 kilometres east of the Hibernia field on the eastern flank of the Jeanne d’Arc Basin. The Company is the operator of the main White Rose field and satellite tiebacks, including the North Amethyst, West White Rose and South White Rose extensions. The Company has a 72.5% working interest in the main field and a 68.875% 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 FPSO.

First oil was achieved at White Rose in November 2005. The White Rose field currently has 13 production wells, 10 water injection wells and three gas injection wells. The Company’s share of light crude oil production from the White Rose field was 8,400 bbls/day (Husky working interest) during 2020.

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On May 31, 2010, first oil was achieved from North Amethyst, the first satellite extension at the White Rose field. The field is located approximately six kilometres southwest of the SeaRose FPSO. Production flows from North Amethyst to the SeaRose FPSO through a series of subsea flow lines. As of December 31, 2020, the field had seven production wells, four water injection wells and one gas injection well. During 2020, a production well was converted to gas injection service as an improved oil recovery initiative. Light crude oil production from North Amethyst was 4,200 bbls/day (Husky working interest) in 2020.

Initial production from West White Rose was achieved in September 2011 through a two-well pilot project. The pilot wells have helped provide further information on the reservoir to refine development plans for the full West White Rose field. During 2020, light crude oil production from this satellite field was 300 bbls/day (Husky working interest).

Production commenced from the South White Rose Extension in 2015 with production wells supported by both gas flood and water injection. As at December 31, 2020, the project had three production wells, one water injection well and one gas injection well. During 2020, light crude oil production from the South White Rose Extension was 4,700 bbls/day (Husky working interest).

In May 2017, the Company and its co-venturers announced plans to proceed with full field development at West White Rose using a fixed drilling platform. Construction of various components for the West White Rose platform is underway at sites in NL, and in Ingleside, Texas, where the facility’s topsides are being fabricated. Major construction was suspended in March 2020 due to the COVID-19 situation. In October, the Company announced the continued suspension of construction on the Concrete Gravity Structure in Argentia, NL.

As of December 31, 2020, the West White Rose Project was approximately 60% complete.

Terra Nova Field

The Terra Nova field is located approximately 350 kilometres southeast of St. John’s, NL. The Terra Nova field is divided into three distinct areas, known as the Graben, the East Flank and the Far East. Production at Terra Nova commenced in January 2002. The Company’s working interest in the field increased to 13% effective December 1, 2010.

As at December 31, 2020, there were 15 development wells drilled in the Graben area, consisting of nine production wells, four water injection wells and two gas injection wells. In the East Flank area, there were 12 development wells, consisting of eight production wells and four water injection wells. The Far East has one extended reach producer and an extended reach water injection well.

Production at Terra Nova has been shut in since December 2019. There was no production from the field during 2020.

East Coast Exploration

The Company holds working interests ranging from 5.8% to 100% in 24 significant discovery areas in the Jeanne d’Arc Basin and Flemish Pass Basin, offshore NL and Baffin Island.

The Company continues to evaluate previous hydrocarbon discoveries at the White Rose A-24 exploration well, north of the SeaRose FPSO (2018), and the Northwest White Rose A-78 well (2017).

The Company and its partner continue to assess potential development of Bay du Nord and other discoveries in the Flemish Pass Basin. The Company holds a 35% non-operated working interest in the Bay du Nord, Bay de Verde, Baccalieu, Harpoon and Mizzen discoveries. A Significant Discovery Licence was issued for the Harpoon discovery in October 2020.

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STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

Disclosure of Oil and Gas Activities

Operating Netback Analysis⁽¹⁾

The following tables show the Company’s netback analysis by product and area:

	Year Ended			Three Months Ended
Average Per Unit Amounts	Dec 31, 2020			Dec 31, 2020		Sept 30, 2020		June 30, 2020			Mar 31, 2020
Company Total(2)
Production volume (mboe/day)		272.0			284.2		258.4		246.5			298.9
Gross Revenue ($/boe)(3)	$	33.43		$	39.11	$	38.53	$	27.28		$	28.59
Royalties ($/boe)	$	2.10		$	2.53	$	2.40	$	1.45		$	1.95
Production and Operating Costs ($/boe)(3)	$	13.57		$	12.88	$	13.93	$	13.12		$	14.29
Transportation Costs ($/boe)(4)	$	0.18		$	0.19	$	0.17	$	0.20		$	0.16
Operating netback ($/boe)	$	17.58		$	23.51	$	22.03	$	12.51		$	12.19
Light and Medium Crude Oil ($/bbl)
Canada - Western Canada
Gross Revenue(3)	$	37.93		$	43.67	$	43.81	$	20.91		$	42.95
Royalties	$	3.71		$	4.02	$	2.68	$	1.48		$	5.96
Production and Operating Costs(3)	$	27.28		$	31.86	$	27.45	$	24.27		$	26.50
Operating netback	$	6.94		$	7.79	$	13.68	($	4.84	)	$	10.49
Canada - Atlantic Canada
Gross Revenue	$	49.31		$	64.70	$	55.74	$	34.22		$	45.45
Royalties	$	2.76		$	3.79	$	3.36	$	1.99		$	2.15
Production and Operating Costs	$	27.77		$	24.62	$	34.74	$	26.62		$	26.37
Transportation Costs(4)	$	2.74		$	3.11	$	3.03	$	2.53		$	2.39
Operating netback	$	16.04		$	33.18	$	14.61	$	3.08		$	14.54
Canada - Total
Gross Revenue(3)	$	46.03		$	59.34	$	52.08	$	30.64		$	44.66
Royalties	$	3.04		$	3.85	$	3.15	$	1.85		$	3.37
Production and Operating Costs(3)	$	27.63		$	26.47	$	32.51	$	25.99		$	26.41
Transportation Costs(4)	$	1.95		$	2.31	$	2.09	$	1.85		$	1.63
Operating netback	$	13.41		$	26.71	$	14.33	$	0.95		$	13.25
Heavy Crude Oil ($/bbl)
Canada - Total
Gross Revenue(3)	$	27.09		$	36.82	$	36.51	$	13.82		$	22.11
Royalties	$	2.29		$	2.65	$	2.77	$	2.07		$	1.87
Production and Operating Costs(3)	$	27.78		$	27.60	$	26.98	$	27.17		$	28.73
Operating netback	($	2.98	)	$	6.57	$	6.76	($	15.42	)	($	8.49	)
Bitumen ($/bbl)
Canada - Total
Gross Revenue(3)(4)	$	24.56		$	32.57	$	33.99	$	13.06		$	16.38
Royalties	$	1.69		$	2.03	$	2.96	$	0.50		$	1.09
Production and Operating Costs(3)	$	12.78		$	12.03	$	13.45	$	13.86		$	12.21
Operating netback	$	10.09		$	18.51	$	17.58	($	1.30	)	$	3.08

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	Year Ended			Three Months Ended
Average Per Unit Amounts	Dec 31, 2020			Dec 31, 2020		Sept 30, 2020			June 30, 2020			Mar 31, 2020
Conventional Natural Gas ($/mcf)
Canada - Total
Gross Revenue(3)(5)	$	2.06		$	2.41	$	2.09		$	1.85		$	1.94
Royalties(5)(6)	($	0.02	)	$	0.09	($	0.30	)	$	0.01		$	0.10
Production and Operating Costs(3)	$	1.80		$	1.86	$	1.66		$	1.69		$	1.98
Operating netback	$	0.28		$	0.46	$	0.73		$	0.15		($	0.14	)
China
Gross Revenue	$	13.94		$	12.58	$	13.52		$	15.00		$	14.93
Royalties	$	0.81		$	0.86	$	0.81		$	0.79		$	0.79
Production and Operating Costs	$	0.84		$	0.85	$	1.06		$	0.56		$	0.94
Operating netback	$	12.29		$	10.87	$	11.65		$	13.65		$	13.20
Indonesia(7)
Gross Revenue	$	9.72		$	9.25	$	9.19		$	10.36		$	10.05
Royalties	$	0.72		$	0.59	$	0.27		$	0.91		$	1.10
Production and Operating Costs	$	1.47		$	1.59	$	1.33		$	1.58		$	1.38
Operating netback	$	7.53		$	7.07	$	7.59		$	7.87		$	7.57
Total
Gross Revenue(3)	$	7.40		$	7.53	$	7.16		$	7.74		$	7.16
Royalties	$	0.37		$	0.48	$	0.19		$	0.39		$	0.42
Production and Operating Costs(3)	$	1.39		$	1.38	$	1.39		$	1.23		$	1.56
Operating netback	$	5.64		$	5.67	$	5.58		$	6.12		$	5.18
Natural Gas Liquids ($/bbl)
Canada - Total
Gross Revenue(3)	$	14.60		$	18.32	$	15.24		$	6.62		$	18.53
Royalties	$	1.06		$	1.63	$	1.03		($	0.16	)	$	1.77
Production and Operating Costs(3)	$	10.03		$	10.38	$	9.21		$	9.50		$	11.01
Operating netback	$	3.51		$	6.31	$	5.00		($	2.72	)	$	5.75
China
Gross Revenue	$	48.36		$	52.56	$	48.33		$	34.72		$	60.62
Royalties	$	2.78		$	3.08	$	2.76		$	1.98		$	3.45
Production and Operating Costs	$	5.05		$	5.08	$	6.34		$	3.38		$	5.64
Operating netback	$	40.53		$	44.40	$	39.23		$	29.36		$	51.53
Indonesia(7)
Gross Revenue	$	57.20		$	52.48	$	64.61		$	13.09		$	83.68
Royalties	$	9.21		$	7.58	$	9.64		$	5.47		$	12.78
Production and Operating Costs	$	8.63		$	9.52	$	7.78		$	9.46		$	8.27
Operating netback	$	39.36		$	35.38	$	47.19		($	1.84	)	$	62.63
Total
Gross Revenue(3)	$	33.16		$	37.75	$	35.21		$	19.21		$	40.95
Royalties	$	2.69		$	2.91	$	2.93		$	1.23		$	3.73
Production and Operating Costs(3)	$	7.84		$	7.83	$	7.88		$	6.87		$	8.86
Operating netback	$	22.63		$	27.01	$	24.40		$	11.11		$	28.36

⁽¹⁾ Operating netback is a non-GAAP measure. Refer to the Reader Advisories for further details.

⁽²⁾ Includes associated co-products converted to boe and mcf.

⁽³⁾ Transportation expenses have been deducted from both gross revenue and production and operating costs to reflect the actual price received at the oil and gas lease.

⁽⁴⁾ Includes offshore transportation costs shown separately from price received.

⁽⁵⁾ Includes sulphur sales revenues/royalties.

⁽⁶⁾ Alberta Gas Cost Allowance reported exclusively as gas royalties.

⁽⁷⁾ Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for consolidated financial statement purposes.

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Production History

	Year Ended		Three Months Ended
Average Gross Daily Production	Dec 31, 2020		Dec 31, 2020		Sept 30, 2020		June 30, 2020		Mar 31, 2020
Canada - Western Canada
Light and Medium Crude Oil (mbbls/day)		7.2		5.8		6.5		7.0		9.2
Heavy Crude Oil (mbbls/day)		21.4		20.2		18.4		16.7		30.4
Bitumen (mbbls/day)		121.8		136.4		117.4		95.1		138.0
Conventional Natural Gas (mmcf/day)		261.2		237.3		253.2		275.8		278.9
NGL (mbbls/day)		10.2		9.3		10.0		10.6		10.9
Canada - Atlantic
Light and Medium Crude Oil (mbbls/day)		17.6		17.1		14.8		19.0		19.6
China - Asia Pacific(1)
Conventional Natural Gas (mmcf/day)		201.3		229.2		190.7		211.3		174.0
NGL (mbbls/day)		8.6		10.1		8.4		9.3		6.8
Indonesia - Asia Pacific(2)
Conventional Natural Gas (mmcf/day)		34.4		32.3		34.9		34.6		35.7
NGL (mbbls/day)		2.4		2.2		3.1		1.8		2.6
Total Gross Production (mboe/day)		272.0		284.2		258.4		246.5		298.9

⁽¹⁾ Reported production volumes include Husky’s working interest production from the Liwan Gas Project.

⁽²⁾ Reported production volumes include Husky’s working interest production from the BD Project (40%). Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for consolidated financial statement purposes.

Producing and Non-Producing Wells^(1)(2)(3)

	Oil Wells				Conventional Natural Gas Wells				Total
Producing Wells	Gross		Net		Gross		Net		Gross		Net
Canada
Alberta		1,218		1,071		1,168		788		2,386		1,859
Saskatchewan		2,009		1,954		77		76		2,086		2,030
British Columbia		—		—		120		120		120		120
Newfoundland		22		6		—		—		22		6
		3,249		3,031		1,365		984		4,614		4,015
International
China		—		—		17		10		17		10
Indonesia		—		—		4		2		4		2
		—		—		21		12		21		12
As at December 31, 2020		3,249		3,031		1,386		996		4,635		4,027
	Oil Wells				Conventional Natural Gas Wells				Total
Non-Producing Wells	Gross		Net		Gross		Net		Gross		Net
Canada
Alberta		1,451		1,336		721		560		2,172		1,896
Saskatchewan		3,560		3,420		172		155		3,732		3,575
British Columbia		—		—		12		10		12		10
As at December 31, 2020		5,011		4,756		905		725		5,916		5,481

⁽¹⁾ The number of gross wells is the total number of wells in which the Company owns a working interest. The number of net wells is the sum of the fractional interests owned in the gross wells. Productive wells are those producing or capable of producing at December 31, 2020.

⁽²⁾ The above table does not include producing wells in which the Company has no working interest but does have a royalty interest. At December 31, 2020, the Company had a royalty interest in 794 wells, of which 417 were oil producers and 377 were gas producers.

⁽³⁾ For purposes of the table, multiple completions are counted as a single well. Where one of the completions in a given well is an oil completion, the well is classified as an oil well. In 2020, there were 940 gross and 855 net oil wells and 69 gross and 57 net conventional natural gas wells that were completed in two or more formations and from which production is not commingled.

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Of the 21 mmboe of Proved Developed Non-Producing reserves as of year-end 2020, approximately 15 mmboe are associated with wells drilled in the thermal bitumen projects and Sunrise Energy Project that will be placed on production in 2021 and 2022, respectively. An additional 2 mmboe are associated with the Company’s Wembley liquids-rich gas resource play. The remaining 4 mmboe are associated with temporarily shut-in wells and optimization programs within existing fields scheduled over the next five years. Because the remaining capital is small relative to drilling and completion costs, the associated reserves are considered developed. There are no other non-producing wells attributed with material reserves.

Properties with No Attributed Reserves

Unproved Acreage (thousands  of acres)	Gross		Net
Western Canada
Alberta		2,699		2,302
Saskatchewan		569		552
British Columbia		139		125
		3,407		2,979
Northwest Territories and Arctic		451		443
Atlantic		2,654		1,010
		6,512		4,432
China		292		280
Indonesia		618		247
Taiwan		1,904		1,428
As at December 31, 2020		9,326		6,387

Where Husky holds interests in different formations under the same surface area pursuant to separate leases, the acreage for each lease is included in the gross and net amounts.

As at December 31, 2020, over the next 12 months, development rights to approximately 241 thousand net acres, or less than 8%, of the Company’s net unproved acreage in Western Canada will be subject to expiry.

As at December 31, 2020, over the next 12 months, development rights to the 1,428 thousand net acres in Taiwan are subject to expiry.

The Company has commitments totaling approximately $103 million related to exploration to be completed in Atlantic between 2023 and 2024. Not fulfilling commitments in accordance with licensing timelines triggers forfeiture of security deposits of 30% of unfulfilled commitments.

The Company has a work deficiency penalty payment of approximately $45 million to secure the Significant Discovery Licence in the Northwest Territories.

The Company has commitments for offshore China of approximately $13 million to be completed by April 30, 2022.

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Significant Factors or Uncertainties Relevant to Properties with No Attributed Reserves

The Company holds interests in a diverse portfolio of undeveloped petroleum assets in Western Canada, Atlantic, Asia Pacific, the Northwest Territories and the Arctic. As part of its active portfolio management, the Company continually reviews the economic viability of its undeveloped properties using industry-standard economic evaluation techniques and pricing and economic environment assumptions. Each year, as part of this active management process, some properties are selected for further development activities, while others are held in abeyance, sold, swapped or relinquished back to the mineral rights owner. There is no guarantee that commercial reserves will be discovered or developed on these properties.

Husky Energy Inc. | Annual Information Form 2020 | 30

Abandonment and Reclamation Costs

There are no significant abandonment or reclamation costs, no unusually high expected development costs or operating costs and no contractual obligations to produce and sell a significant portion of production at prices substantially below those which could be realized but for those contractual obligations that have affected, or that the Company reasonably expects to affect, anticipated development or production activities on properties with no attributed reserves. For further information on abandonment and reclamation costs in respect of the Company’s properties, please refer to Note 18 of the Company’s audited consolidated financial statements as at and for the year ended December 31, 2020.

Drilling Activity - Number of Wells Drilled

	Year Ended December 31, 2020
	Western Canada				Atlantic				China				Indonesia
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Exploration
Oil		—		—		—		—		—		—		—		—
Gas		—		—		—		—		—		—		—		—
		—		—		—		—		—		—		—		—
Development
Oil		74.0		70.0		—		—		—		—		—		—
Gas		6.0		6.0		—		—		—		—		—		—
		80.0		76.0		—		—		—		—		—		—
		80.0		76.0		—		—		—		—		—		—
Stratigraphic Test Wells		1.0		1.0		—		—		—		—		—		—
Service Wells		22.0		22.0		—		—		—		—		—		—

Costs Incurred

($millions)	Total		Western Canada		Atlantic		Total Canada		China		Indonesia(1)
Property acquisition - Unproven		1		1		—		1		—		—
Property acquisition - Proven		—		—		—		—		—		—
Exploration		7		—		4		4		3		—
Development		1,094		670		260		930		161		3
2020		1,102		671		264		935		164		3

⁽¹⁾ Capital expenditures related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for consolidated financial statement purposes.

Husky Energy Inc. | Annual Information Form 2020 | 31

Oil and Gas Reserves Disclosure

Overview

Husky’s oil and gas reserves are estimated in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook (“COGEH”), and the reserves data disclosed conforms with the requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). All of Husky’s oil and gas reserves estimates are prepared by internal qualified reserves evaluation staff using a formalized process for determining, approving and booking reserves.

For the purposes of Husky’s NI 51-101 reserves disclosure in this year’s AIF, Sproule Associates Limited. (“Sproule”), an independent firm of qualified reserves evaluators, was engaged to conduct a complete audit and review of 100% 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 COGEH.

The Audit Committee has examined Husky’s procedures for assembling and reporting reserves data and other information associated with oil and gas activities and has reviewed that information with management. The Board has approved, on the recommendation of the Audit Committee , the content of Husky’s disclosure in this AIF of its reserves data and other oil and gas information.

Disclosure of Oil and Gas Information

Unless otherwise noted in this document, all provided reserves estimates have a preparation date of January 25, 2021 and an effective date of December 31, 2020 and are Husky’s total proved and probable reserves. Gross reserves or gross production are reserves or production attributable to Husky’s working interest prior to deduction of royalties; net reserves or net production represent the Company’s lessor royalty, overriding royalty and working interest share of the gross remaining reserves, after deduction of any crown, freehold and overriding royalty interests. Gross or net production reported refers to sales volume, unless otherwise indicated. Unless otherwise noted, production and reserves figures are stated on a gross basis. Unless otherwise indicated, oil and gas commodity prices are quoted after the effects of hedging gains and losses. Unless otherwise indicated, all financial information is in accordance with IFRS. Note that the numbers in each column of the tables throughout this section may not add due to rounding.

The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

Bitumen reserves include reserves from Husky’s thermal projects in the Lloydminster area.

The reserves information prepared in accordance with the rules of the U.S. Financial Accounting Standards Board and the SEC (collectively, the “U.S. Rules”) is included in the Company’s Form 40-F, which is available at www.sec.gov and on the Company’s website at www.huskyenergy.com. The material difference between reserves quantities disclosed under NI 51-101 and those disclosed under the U.S. Rules is that NI 51-101 requires the determination of reserves quantities to be based on forecast pricing assumptions whereas the U.S. Rules require the determination of reserves quantities to be based on constant price assumptions calculated using a 12-month average price for the year (sum of the benchmark price on the first calendar day of each month in the year divided by 12).

Husky Energy Inc. | Annual Information Form 2020 | 32

Summary of Oil and Conventional Natural Gas Reserves

As at December 31, 2020

Forecast Prices and Costs

Canada

	Light & Medium Crude Oil (mmbbls)				Heavy Crude Oil (mmbbls)				Bitumen (mmbbls)				Total Oil (mmbbls)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Proved
Developed Producing		20.4		18.1		31.0		30.0		123.8		115.8		175.1		163.9
Developed Non-producing		1.0		0.9		0.7		0.7		14.6		14.1		16.3		15.7
Undeveloped		—		—		1.1		1.1		759.2		703.8		760.3		704.9
Total Proved		21.4		19.0		32.8		31.8		897.5		833.7		951.7		884.5
Probable		147.0		134.9		16.1		15.6		255.1		228.5		418.2		379.0
Total Proved Plus Probable		168.3		153.9		48.9		47.4		1,152.6		1,062.2		1,369.9		1,263.5

	Conventional Natural Gas (bcf)				Natural Gas Liquids (mmbbls)				Total (mmboe)
	Gross		Net		Gross		Net		Gross		Net
Proved
Developed Producing		562.2		496.9		25.7		20.8		294.5		267.5
Developed Non-producing		19.6		17.7		1.5		1.3		21.1		19.9
Undeveloped		119.0		112.7		8.3		7.5		788.4		731.3
Total Proved		700.8		627.4		35.5		29.6		1,104.0		1,018.7
Probable		301.6		281.7		20.5		17.9		489.0		443.9
Total Proved Plus Probable		1,002.3		909.0		56.0		47.5		1,592.9		1,462.5

China

Light & Medium Crude Oil (mmbbls)

Heavy Crude Oil (mmbbls)

Bitumen (mmbbls)

Total Oil (mmbbls)

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Proved

Developed Producing

—

—

—

—

—

—

—

—

Developed Non-producing

—

—

—

—

—

—

—

—

Undeveloped

—

—

—

—

—

—

—

—

Total Proved

—

—

—

—

—

—

—

—

Probable

—

—

—

—

—

—

—

—

Total Proved Plus Probable

—

—

—

—

—

—

—

—

	Conventional Natural Gas (bcf)				Natural Gas Liquids (mmbbls)				Total (mmboe)
	Gross		Net		Gross		Net		Gross		Net
Proved
Developed Producing		493.3		472.4		17.6		16.9		99.8		95.6
Developed Non-producing		—		—		—		—		—		—
Undeveloped		—		—		—		—		—		—
Total Proved		493.3		472.4		17.6		16.9		99.8		95.6
Probable		62.5		59.2		1.9		1.8		12.3		11.7
Total Proved Plus Probable		555.9		531.6		19.5		18.7		112.1		107.3

Husky Energy Inc. | Annual Information Form 2020 | 33

Indonesia

Light & Medium Crude Oil (mmbbls)

Heavy Crude Oil (mmbbls)

Bitumen (mmbbls)

Total Oil (mmbbls)

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Proved

Developed Producing

—

—

—

—

—

—

—

—

Developed Non-producing

—

—

—

—

—

—

—

—

Undeveloped

—

—

—

—

—

—

—

—

Total Proved

—

—

—

—

—

—

—

—

Probable

—

—

—

—

—

—

—

—

Total Proved Plus Probable

—

—

—

—

—

—

—

—

Husky Energy Inc. | Annual Information Form 2020 | 34

	Conventional Natural Gas (bcf)				Natural Gas Liquids (mmbbls)				Total (mmboe)
	Gross		Net		Gross		Net		Gross		Net
Proved
Developed Producing		128.5		89.8		4.3		2.9		25.7		17.9
Developed Non-producing		—		—		—		—		—		—
Undeveloped		68.4		44.6		—		—		11.4		7.4
Total Proved		197.0		134.5		4.3		2.9		37.1		25.3
Probable		56.6		30.6		1.7		1.0		11.1		6.1
Total Proved Plus Probable		253.5		165.1		5.9		3.9		48.2		31.4

Total

	Light & Medium Crude Oil (mmbbls)				Heavy Crude Oil (mmbbls)				Bitumen (mmbbls)				Total Oil (mmbbls)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Proved
Developed Producing		20.4		18.1		31.0		30.0		123.8		115.8		175.1		163.9
Developed Non-producing		1.0		0.9		0.7		0.7		14.6		14.1		16.3		15.7
Undeveloped		—		—		1.1		1.1		759.2		703.8		760.3		704.9
Total Proved		21.4		19.0		32.8		31.8		897.5		833.7		951.7		884.5
Probable		147.0		134.9		16.1		15.6		255.1		228.5		418.2		379.0
Total Proved Plus Probable		168.3		153.9		48.9		47.4		1,152.6		1,062.2		1,369.9		1,263.5

	Conventional Natural Gas (bcf)				Natural Gas Liquids (mmbbls)				Total (mmboe)
	Gross		Net		Gross		Net		Gross		Net
Proved
Developed Producing		1,184.0		1,059.1		47.5		40.6		419.9		381.0
Developed Non-producing		19.6		17.7		1.5		1.3		21.1		19.9
Undeveloped		187.5		157.4		8.3		7.5		799.8		738.7
Total Proved		1,391.1		1,234.2		57.3		49.4		1,240.8		1,139.5
Probable		420.6		371.5		24.1		20.7		512.4		461.6
Total Proved Plus Probable		1,811.7		1,605.7		81.4		70.1		1,753.2		1,601.2

Husky Energy Inc. | Annual Information Form 2020 | 35

Future Net Revenue Tables

Summary of Net Present Values of Future Net Revenue - Before Income Taxes and Discounted

As at December 31, 2020

Forecast Prices and Costs

Canada

	Before Income Taxes and Discounted at (%/year)															Unit Value Discounted at 10%
($ millions)	0%			5%			10%			15%			20%			($/boe)
Proved
Developed Producing		(3,176.6	)		437.4			1,100.7			1,265.7			1,292.6			4.11
Developed Non-producing(1)		(193.0	)		(113.8	)		(77.9	)		(57.5	)		(44.9	)		(3.92	)
Undeveloped		10,655.4			3,720.6			1,614.5			745.2			314.0			2.21
Total Proved		7,285.8			4,044.3			2,637.3			1,953.3			1,561.7			2.59
Probable		8,754.3			5,568.6			3,566.7			2,339.0			1,563.9			8.04
Total Proved Plus Probable		16,040.1			9,612.9			6,204.0			4,292.3			3,125.6			4.24

⁽¹⁾ In the Heavy Oil properties there are approximately 9,000 oil and gas wells with no reserves assigned that carry surface land, maintenance and property taxes that also form part of each non-producing property’s (that has reserves) operating costs. Accordingly, these costs have been included in the reserves reports in the Proved Developed Non-producing category.

China

	Before Income Taxes and Discounted at (%/year)										Unit Value Discounted at 10%
($ millions)	0%		5%		10%		15%		20%		($/boe)
Proved
Developed Producing		5,048.5		4,224.5		3,634.9		3,196.5		2,859.8		38.03
Developed Non-producing		—		—		—		—		—		—
Undeveloped		—		—		—		—		—		—
Total Proved		5,048.5		4,224.5		3,634.9		3,196.5		2,859.8		38.03
Probable		565.5		404.7		308.9		247.7		206.0		26.44
Total Proved Plus Probable		5,614.0		4,629.2		3,943.8		3,444.1		3,065.9		36.77

Indonesia

	Before Income Taxes and Discounted at (%/year)										Unit Value Discounted at 10%
($ millions)	0%		5%		10%		15%		20%		($/boe)
Proved
Developed Producing		435.5		372.4		324.3		286.9		257.2		18.16
Developed Non-producing		—		—		—		—		—		—
Undeveloped		240.9		193.2		156.7		128.4		106.0		21.07
Total Proved		676.4		565.6		481.0		415.3		363.2		19.01
Probable		178.7		117.8		80.1		56.1		40.4		13.16
Total Proved Plus Probable		855.1		683.4		561.1		471.3		403.6		17.88

Husky Energy Inc. | Annual Information Form 2020 | 36

Total

	Before Income Taxes and Discounted at (%/year)															Unit Value Discounted at 10%
($ millions)	0%			5%			10%			15%			20%			($/boe)
Proved
Developed Producing		2,307.5			5,034.4			5,059.9			4,749.1			4,409.7			13.28
Developed Non-producing(1)		(193.0	)		(113.8	)		(77.9	)		(57.5	)		(44.9	)		(3.92	)
Undeveloped		10,896.3			3,913.8			1,771.2			873.5			420.0			2.40
Total Proved		13,010.8			8,834.4			6,753.2			5,565.0			4,784.7			5.93
Probable		9,498.4			6,091.1			3,955.7			2,642.7			1,810.3			8.57
Total Proved Plus Probable		22,509.2			14,925.4			10,708.8			8,207.8			6,595.1			6.69

⁽¹⁾ In the Heavy Oil properties there are approximately 9,000 oil and gas wells with no reserves assigned that carry surface land, maintenance and property taxes that are part of each non-producing property’s (that has reserves) operating costs. Accordingly, these costs have been included in the reserves reports in the Proved Developed Non-producing category.

Husky Energy Inc. | Annual Information Form 2020 | 37

Summary of Net Present Values of Future Net Revenue - After Income Taxes and Discounted

As at December 31, 2020

Forecast Prices and Costs

Canada

	After Income Taxes and Discounted at (%/year)
($ millions)	0%			5%			10%			15%			20%
Proved
Developed Producing		(2,308.2	)		352.7			832.2			948.1			964.7
Developed Non-producing(1)		(146.0	)		(87.5	)		(61.3	)		(46.3	)		(37.1	)
Undeveloped		7,996.0			2,653.0			1,067.0			425.3			113.3
Total Proved		5,541.7			2,918.2			1,837.9			1,327.1			1,040.9
Probable		6,380.3			3,963.5			2,461.0			1,550.6			983.2
Total Proved Plus Probable		11,922.0			6,881.7			4,299.0			2,877.7			2,024.1

⁽¹⁾ In the Heavy Oil properties there are approximately 9,000 oil and gas wells with no reserves assigned that carry surface land, maintenance and property taxes that are part of each non-producing property’s (that has reserves) operating costs. Accordingly, these costs have been included in the reserves reports in the Proved Developed Non-producing category.

China

	After Income Taxes and Discounted at (%/year)
($ millions)	0%		5%		10%		15%		20%
Proved
Developed Producing		3,784.6		3,167.8		2,726.7		2,398.9		2,147.5
Developed Non-producing		—		—		—		—		—
Undeveloped		—		—		—		—		—
Total Proved		3,784.6		3,167.8		2,726.7		2,398.9		2,147.5
Probable		424.0		303.4		231.6		185.7		154.5
Total Proved Plus Probable		4,208.5		3,471.2		2,958.3		2,584.6		2,301.9

Indonesia

	After Income Taxes and Discounted at (%/year)
($ millions)	0%		5%		10%		15%		20%
Proved
Developed Producing		289.5		255.5		228.5		206.6		188.8
Developed Non-producing		—		—		—		—		—
Undeveloped		165.9		133.4		108.3		88.6		73.0
Total Proved		455.4		388.9		336.7		295.3		261.8
Probable		79.4		54.3		38.1		27.5		20.3
Total Proved Plus Probable		534.8		443.2		374.9		322.7		282.1

Total

	After Income Taxes and Discounted at (%/year)
($ millions)	0%			5%			10%			15%			20%
Proved
Developed Producing		1,765.8			3,776.0			3,787.4			3,553.7			3,300.9
Developed Non-producing(1)		(146.0	)		(87.5	)		(61.3	)		(46.3	)		(37.1	)
Undeveloped		8,161.9			2,786.4			1,175.2			513.9			186.3
Total Proved		9,781.6			6,474.8			4,901.4			4,021.3			3,450.1
Probable		6,883.7			4,321.2			2,730.7			1,763.8			1,158.0
Total Proved Plus Probable		16,665.3			10,796.0			7,632.1			5,785.1			4,608.1

⁽¹⁾ In the Heavy Oil properties there are approximately 9,000 oil and gas wells with no reserves assigned that carry surface land, maintenance and property taxes that are part of each non-producing property’s (that has reserves) operating costs. Accordingly, these costs have been included in the reserves reports in the Proved Developed Non-producing category.

Husky Energy Inc. | Annual Information Form 2020 | 38

Total Future Net Revenue for Total Proved Plus Probable Reserves - Undiscounted

As at December 31, 2020

Forecast Prices and Costs

($ millions)	Revenue		Royalties		Operating Costs		Develop- ment Costs		Abandon- ment and Reclama- tion Costs		Future Net Revenue Before Income Taxes		Income Taxes		Future Net Revenue After Income Taxes
Canada
Total Proved		51,460.4		4,800.5		24,401.6		8,980.8		5,991.7		7,285.8		1,744.1		5,541.7
Total Proved Plus Probable		76,773.8		7,331.7		33,141.4		13,805.1		6,455.5		16,040.1		4,118.1		11,922.0
China
Total Proved		6,953.0		377.0		1,367.9		—		159.6		5,048.5		1,264.0		3,784.6
Total Proved Plus Probable		7,727.1		418.9		1,534.2		—		160.0		5,614.0		1,405.5		4,208.5
Indonesia
Total Proved		2,342.4		718.2		883.4		36.4		28.0		676.4		221.0		455.4
Total Proved Plus Probable		3,052.1		1,047.4		1,081.3		36.4		31.9		855.1		320.3		534.8
Total
Total Proved		60,755.9		5,895.7		26,652.9		9,017.2		6,179.3		13,010.8		3,229.1		9,781.6
Total Proved Plus Probable		87,553.0		8,798.1		35,756.8		13,841.6		6,647.4		22,509.2		5,843.9		16,665.3

Future Net Revenue by Product Type

As at December 31, 2020

Forecast Prices and Costs

	Future Net Revenue Before Income Taxes (discounted at  10%/year)(1)
	Canada						China				Indonesia				Total
	($ millions)			($/boe)			($ millions)		($/boe)		($ millions)		($/boe)		($ millions)			($/boe)
Total Proved
Light & Medium Crude Oil		45.7			0.65			—		—		—		—		45.7			0.65
Heavy Crude Oil		(394.1	)		(12.12	)		—		—		—		—		(394.1	)		(12.12	)
Bitumen		3,056.6			3.67			—		—		—		—		3,056.6			3.67
Total Oil		2,708.2			2.89			—		—		—		—		2,708.2			2.89
Conventional Natural Gas		(70.9	)		(0.86	)		3,634.9		38.03		481.0		19.01		4,045.0			19.89
Total Proved		2,637.3			2.59			3,634.9		38.03		481.0		19.01		6,753.2			5.93
Total Proved Plus Probable
Light & Medium Crude Oil		474.9			2.27			—		—		—		—		474.9			2.27
Heavy Crude Oil		(183.5	)		(3.79	)		—		—		—		—		(183.5	)		(3.79	)
Bitumen		5,742.2			5.41			—		—		—		—		5,742.2			5.41
Total Oil		6,033.6			4.57			—		—		—		—		6,033.6			4.57
Conventional Natural Gas		170.3			1.19			3,943.8		36.77		561.1		17.88		4,675.2			16.62
Total Proved Plus Probable		6,204.0			4.24			3,943.8		36.77		561.1		17.88		10,708.8			6.69

⁽¹⁾ By-products, including solution gas, NGL and other associated by-products, are included in their main product group (conventional natural gas or oil).

Husky Energy Inc. | Annual Information Form 2020 | 39

Pricing Assumptions

Except as noted below, the pricing assumptions disclosed in the following table were derived using the industry averages prescribed by McDaniel and Associates Consultants Ltd., Sproule and GLJ Ltd. China and Indonesia gas prices are derived from the GSAs specific to each set of projects. For historical prices realized during 2020, see “Statement of Reserves Data and Other Oil and Gas Information – Disclosure of Oil and Gas Activities – Operating Netback Analysis”.

	Light Crude Oil									Medium Crude Oil			Heavy Crude Oil
	WTI (U.S. $/bbl)			Brent (U.S. $/bbl)			Edmonton (Cdn $/bbl)			Hardisty Bow River (Cdn $/bbl)			Lloyd Heavy API (Cdn $/bbl)
Historical
2020		39.40			41.70			45.34			35.78			30.28
Forecast
2021		47.17			49.42			55.76			45.36			39.87
2022		50.17			52.85			59.89			48.96			43.20
2023		53.17			56.04			63.48			52.91			46.86
2024		54.97			57.87			65.76			54.95			48.67
2025		56.07			59.00			67.13			56.05			49.65
2026		57.19			60.15			68.53			57.16			50.65
2027		58.34			61.33			69.95			58.30			51.67
2028		59.50			62.53			71.40			59.47			52.71
2029		60.69			63.75			72.88			60.66			53.76
2030		61.91			65.03			74.34			61.87			54.84
Thereafter		2.00%/	yr		2.00%/	yr		2.00%/	yr		2.00%/	yr		2.00%/	yr
	Bitumen			Conventional Natural Gas			Natural Gas Liquids
	Hardisty WCS (Cdn $/bbl)			AECO (Cdn $/GJ)			Edmonton Propane (Cdn $/bbl)			Edmonton Butane (Cdn $/bbl)			Edmonton Condensate (Cdn $/bbl)
Historical
2020		35.94			2.12			16.26			22.06			49.45
Forecast
2021		44.63			2.63			18.18			26.36			59.24
2022		48.18			2.56			21.91			32.85			63.19
2023		52.10			2.48			24.57			39.20			67.34
2024		54.10			2.51			25.47			40.65			69.77
2025		55.19			2.56			26.00			41.50			71.18
2026		56.29			2.61			26.54			42.36			72.61
2027		57.42			2.66			27.09			43.24			74.07
2028		58.57			2.72			27.65			44.14			75.56
2029		59.74			2.77			28.23			45.06			77.08
2030		60.93			2.82			28.79			45.96			78.62
Thereafter		2.00%/	yr		2.00%/	yr		2.00%/	yr		2.00%/	yr		2.00%/	yr

Husky Energy Inc. | Annual Information Form 2020 | 40

	Asia Pacific
	China		Indonesia
	Conventional Natural Gas (U.S. $/mcf)(1)		Conventional Natural Gas (U.S. $/mcf)(1)		Inflation rates(2)		Exchange rates(3)
Historical
2020		10.12		7.48		0.87		0.75
Forecast
2021		8.98		7.53		—		0.77
2022		9.18		7.32		1.33		0.77
2023		8.96		7.17		2.00		0.76
2024		9.02		7.30		2.00		0.76
2025		9.08		7.44		2.00		0.76
2026		9.17		7.54		2.00		0.76
2027		9.22		7.68		2.00		0.76
2028		9.04		7.84		2.00		0.76
2029		8.93		7.92		2.00		0.76
2030		8.72		8.04		2.00		0.76
Thereafter						2.00		0.76

⁽¹⁾  Conventional natural gas prices in China and Indonesia have been updated from the prior year values due to changes in exchange rates and are the volume weighted average based on the various GSAs.

⁽²⁾  Inflation rates represent a percentage for forecasting costs.

⁽³⁾  Exchange rates used to generate the benchmark reference prices are quoted in U.S. dollar to Canadian dollar.

Husky Energy Inc. | Annual Information Form 2020 | 41

Reconciliation of Gross Proved Reserves

	Light & Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Bitumen (mmbbls)			Total Oil (mmbbls)			Conventional Natural Gas (bcf)			Natural Gas Liquids (mmbbls)			Total (mmboe)
Canada - Western Canada
End of 2019		18.3			46.6			943.3			1,008.3			815.0			56.6			1,200.7
Technical Revisions		(0.4	)		0.3			(9.2	)		(9.3	)		(83.2	)		(18.0	)		(41.2	)
Economic Factors		(1.5	)		(8.8	)		(2.9	)		(13.1	)		(14.0	)		(1.0	)		(16.4	)
Acquisitions		—			—			—			—			—			—			—
Dispositions		(0.5	)		—			—			(0.5	)		(10.3	)		(0.4	)		(2.6	)
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		0.3			3.0			10.9			14.1			88.7			2.0			30.9
Production		(2.1	)		(8.3	)		(44.6	)		(55.0	)		(95.6	)		(3.7	)		(74.7	)
End of 2020		14.1			32.8			897.5			944.5			700.8			35.5			1,096.7
Canada - Atlantic
End of 2019		84.9			—						84.9			—			—			84.9
Technical Revisions		(7.1	)		—			—			(7.1	)		—			—			(7.1	)
Economic Factors		(64.1	)		—			—			(64.1	)		—			—			(64.1	)
Acquisitions		—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—
Production		(6.4	)		—			—			(6.4	)		—			—			(6.4	)
End of 2020		7.3			—			—			7.3			—			—			7.3
China
End of 2019		—			—			—			—			495.8			17.0			99.7
Technical Revisions		—			—			—			—			71.3			3.7			15.6
Economic Factors		—			—			—			—			—			—			—
Acquisitions		—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—
Production		—			—			—			—			(73.7	)		(3.2	)		(15.4	)
End of 2020		—			—			—			—			493.3			17.6			99.8
Indonesia
End of 2019		—			—			—			—			241.6			5.1			45.4
Technical Revisions		—			—			—			—			(32.1	)		—			(5.3	)
Economic Factors		—			—			—			—			—			—			—
Acquisitions		—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—
Production		—			—			—			—			(12.6	)		(0.9	)		(3.0	)
End of 2020		—			—			—			—			197.0			4.3			37.1

Husky Energy Inc. | Annual Information Form 2020 | 42

	Light & Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Bitumen (mmbbls)			Total Oil (mmbbls)			Conventional Natural Gas (bcf)			Natural Gas Liquids (mmbbls)			Total (mmboe)
Total
End of 2019		103.2			46.6			943.3			1,093.2			1,552.4			78.8			1,430.7
Technical Revisions		(7.5	)		0.3			(9.2	)		(16.4	)		(44.0	)		(14.3	)		(38.1	)
Economic Factors		(65.6	)		(8.8	)		(2.9	)		(77.3	)		(14.0	)		(1.0	)		(80.6	)
Acquisitions		—			—			—			—			—			—			—
Dispositions		(0.5	)		—			—			(0.5	)		(10.3	)		(0.4	)		(2.6	)
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		0.3			3.0			10.9			14.1			88.7			2.0			30.9
Production		(8.5	)		(8.3	)		(44.6	)		(61.5	)		(181.9	)		(7.8	)		(99.6	)
End of 2020		21.4			32.8			897.5			951.7			1,391.1			57.3			1,240.8

At December 31, 2020, the Company’s proved oil and gas reserves were 1,241 mmboe, down from 1,431 mmboe at the end of 2019. The Company’s 2020 reserves replacement ratio, defined as net changes to proved reserves divided by total production during the period, was negative 10% excluding economic revisions (negative 91% including economic revisions).

Major changes to proved reserves in 2020 included:

• Western Canada Extensions & Improved Recovery additions of 31 mmboe associated with 17 mmboe from Western Canada conventional natural gas including new locations (89 bcf of conventional natural gas and 2 mmbbls of NGL), 11 mmbbls primarily from Sunrise, and 3 mmbbls mainly from cold heavy crude oil production new drills.

• Net negative technical revisions in Canada of 48 mmboe mainly associated with 32 mmboe of conventional natural gas and associated NGL revisions (negative 83 bcf conventional natural gas and 18 mmbbls of NGL), primarily due to performance analysis and revised development plans in response to current market conditions. An additional 9 mmboe negative technical revisions of bitumen are mainly from Sunrise due to deferred capital plans. Net negative technical revisions of 7 mmboe in Atlantic are primarily due to the Terra Nova suspension causing a transfer to probable, offset by positive performance in White Rose.

• Net positive technical revisions for offshore China of 16 mmboe (71 bcf conventional natural gas and 4 mmbbls of NGL) mainly due to transfers from probable and the expanded GSA in Liwan 3-1. Net negative technical revisions in Indonesia of 5 mmboe (32 bcf of conventional natural gas) are due to expiring agreements, which are currently being renegotiated, associated with project delays.

• Economic factors reduction of 81 mmboe associated with significantly lower oil prices in North America. As a result, the West White Rose Project proved reserves were transferred to probable. Cold heavy crude oil reserves were reduced by 9 mmbbls as a result of economics and shut-in wells.

Husky Energy Inc. | Annual Information Form 2020 | 43

Reconciliation of Gross Probable Reserves

	Light & Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Bitumen (mmbbls)			Total Oil (mmbbls)			Conventional Natural Gas (bcf)			Natural Gas Liquids (mmbbls)			Total (mmboe)
Canada - Western Canada
End of 2019		7.7			19.0			422.3			449.0			339.4			43.7			549.3
Technical Revisions		(4.3	)		(2.4	)		(167.2	)		(173.9	)		(139.4	)		(26.8	)		(224.0	)
Economic Factors		(0.2	)		(1.1	)		(1.0	)		(2.3	)		(2.5	)		(0.1	)		(2.8	)
Acquisitions		—			—			—			—			—			—			—
Dispositions		(0.1	)		—			—			(0.1	)		(1.2	)		—			(0.3	)
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		—			0.6			1.0			1.7			105.3			3.7			22.9
Production		—			—			—			—			—			—			—
End of 2020		3.1			16.1			255.1			274.4			301.6			20.5			345.1
Canada - Atlantic
End of 2019		84.1			—			—			84.1			—			—			84.1
Technical Revisions		(4.4	)		—			—			(4.4	)		—			—			(4.4	)
Economic Factors		64.1			—			—			64.1			—			—			64.1
Acquisitions		—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—
Production		—			—			—			—			—			—			—
End of 2020		143.8			—			—			143.8			—			—			143.8
China
End of 2019		—			—			—			—			119.5			4.5			24.4
Technical Revisions		—			—			—			—			(56.9	)		(2.6	)		(12.0	)
Economic Factors		—			—			—			—			—			—			—
Acquisitions		—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—
Production		—			—			—			—			—			—			—
End of 2020		—			—			—			—			62.5			1.9			12.3
Indonesia
End of 2019		—			—			—			—			91.5			1.6			16.9
Technical Revisions		—			—			—			—			(35.0	)		0.1			(5.8	)
Economic Factors		—			—			—			—			—			—			—
Acquisitions		—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—
Production		—			—			—			—			—			—			—
End of 2020		—			—			—			—			56.5			1.7			11.1

Husky Energy Inc. | Annual Information Form 2020 | 44

	Light & Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Bitumen (mmbbls)			Total Oil (mmbbls)			Conventional Natural Gas (bcf)			Natural Gas Liquids (mmbbls)			Total (mmboe)
Total
End of 2019		91.8			19.0			422.3			533.1			550.4			49.8			674.7
Technical Revisions		(8.7	)		(2.4	)		(167.2	)		(178.3	)		(231.3	)		(29.3	)		(246.2	)
Economic Factors		63.9			(1.1	)		(1.0	)		61.8			(2.5	)		(0.1	)		61.3
Acquisitions		—			—			—			—			—			—			—
Dispositions		(0.1	)		—			—			(0.1	)		(1.2	)		—			(0.3	)
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		—			0.6			1.0			1.7			105.3			3.7			22.9
Production		—			—			—			—			—			—			—
End of 2020		147.0			16.1			255.1			418.2			420.6			24.1			512.4

Major changes to probable reserves in 2020 included:

• Western Canada Extensions & Improved Recovery additions to natural gas resource plays of 105 bcf of conventional natural gas and 4 mmbbls of NGL including new locations.

• Bitumen technical revisions in Western Canada of negative 167 mmboe primarily due to the removal of expansion projects and associated locations that are no longer funded in the next five years at Sunrise and an existing Lloydminster SAGD project. Further revisions include revised mapping and performance analysis with updated information in Sunrise, Tucker and two existing Lloydminster SAGD projects.

• Conventional natural gas and associated NGL revisions in Western Canada of negative 50 mmboe (139 bcf conventional natural gas and 27 mmbbls of NGL) primarily due to revised development plans in response to current market conditions and performance analysis.

• Positive economic factors of 61 mmboe mainly associated with West White Rose Project proved reserves being transferred to probable as a result of significantly lower oil prices in North America.

• Asia Pacific negative technical revisions due to transfers from probable into proved for offshore China and expiring agreements, which are currently being renegotiated, associated with project delays in Indonesia.

Husky Energy Inc. | Annual Information Form 2020 | 45

Reconciliation of Gross Proved Plus Probable Reserves

	Light & Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Bitumen (mmbbls)			Total Oil (mmbbls)			Conventional Natural Gas (bcf)			Natural Gas Liquids (mmbbls)			Total (mmboe)
Canada - Western Canada
End of 2019		26.0			65.7			1,365.6			1,457.3			1,154.4			100.3			1,750.0
Technical Revisions		(4.7	)		(2.1	)		(176.4	)		(183.3	)		(222.6	)		(44.8	)		(265.2	)
Economic Factors		(1.7	)		(9.9	)		(3.9	)		(15.5	)		(16.5	)		(1.0	)		(19.3	)
Acquisitions		—			—			—			—			—			—			—
Dispositions		(0.6	)		—			—			(0.6	)		(11.4	)		(0.5	)		(2.9	)
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		0.4			3.6			11.9			15.8			194.0			5.7			53.9
Production		(2.1	)		(8.3	)		(44.6	)		(55.0	)		(95.6	)		(3.7	)		(74.7	)
End of 2020		17.3			48.9			1,152.6			1,218.8			1,002.3			56.0			1,441.9
Canada - Atlantic
End of 2019		169.1			—			—			169.1			—			—			169.1
Technical Revisions		(11.5	)		—			—			(11.5	)		—			—			(11.5	)
Economic Factors		(0.1	)		—			—			(0.1	)		—			—			(0.1	)
Acquisitions		—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—
Production		(6.4	)		—			—			(6.4	)		—			—			(6.4	)
End of 2020		151.1			—			—			151.1			—			—			151.1
China
End of 2019		—			—			—			—			615.2			21.5			124.0
Technical Revisions		—			—			—			—			14.3			1.1			3.5
Economic Factors		—			—			—			—			—			—			—
Acquisitions		—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—
Production		—			—			—			—			(73.7	)		(3.2	)		(15.4	)
End of 2020		—			—			—			—			555.9			19.5			112.1
Indonesia
End of 2019		—			—			—			—			333.1			6.8			62.3
Technical Revisions		—			—			—			—			(67.1	)		—			(11.1	)
Economic Factors		—			—			—			—			—			—			—
Acquisitions		—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—
Production		—			—			—			—			(12.6	)		(0.9	)		(3.0	)
End of 2020		—			—			—			—			253.5			5.9			48.2

Husky Energy Inc. | Annual Information Form 2020 | 46

	Light & Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Bitumen (mmbbls)			Total Oil (mmbbls)			Conventional Natural Gas (bcf)			Natural Gas Liquids (mmbbls)			Total (mmboe)
Total
End of 2019		195.0			65.7			1,365.6			1,626.3			2,102.8			128.6			2,105.4
Technical Revisions		(16.2	)		(2.1	)		(176.4	)		(194.8	)		(275.3	)		(43.7	)		(284.3	)
Economic Factors		(1.7	)		(9.9	)		(3.9	)		(15.5	)		(16.5	)		(1.0	)		(19.3	)
Acquisitions		—			—			—			—			—			—			—
Dispositions		(0.6	)		—			—			(0.6	)		(11.4	)		(0.5	)		(2.9	)
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		0.4			3.6			11.9			15.8			194.0			5.7			53.9
Production		(8.5	)		(8.3	)		(44.6	)		(61.5	)		(181.9	)		(7.8	)		(99.6	)
End of 2020		168.3			48.9			1,152.6			1,369.9			1,811.7			81.4			1,753.2

Undeveloped Reserves

Undeveloped reserves are attributed internally in accordance with standards and procedures contained in the COGEH. Proved undeveloped oil and gas reserves are those reserves that can be estimated with a high degree of certainty to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Probable undeveloped oil and gas reserves are those reserves that are less certain to be recovered than proved reserves and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. There are numerous uncertainties inherent in estimating quantities of crude oil and conventional natural gas reserves. Classifications of reserves as proved or probable are only attempts to define the degree of uncertainty associated with the estimates. In addition, whereas proved reserves are those reserves that can be estimated with a high degree of certainty to be economically producible, probable reserves are those reserves that are as likely as not to be recovered. Therefore, probable reserves estimates, by definition, have a higher degree of uncertainty than proved reserves.

Approximately 54% of Husky’s gross proved undeveloped reserves are assigned to the Sunrise Energy Project. Production from Phase I of the project started in March 2015, and wells will be drilled in the future to keep the plant at full capacity. Approximately 39% of Husky’s gross proved undeveloped reserves are assigned to 12 heavy oil thermal projects in the Lloydminster area that are classified as bitumen. Approximately 4% of Husky’s gross proved undeveloped reserves are assigned to Ansell and Wembley gas resource plays.

Husky has funded capital programs by cash generated from operating activities, cash on hand, equity issuances and short-term and long-term debt. Decisions on the priority and timing of developing the various proved undeveloped and probable undeveloped reserves, including decisions to defer development of proved undeveloped reserves beyond two years, are based on various factors including strategic considerations, changing economic conditions, changes to government regulations including the setting of production limits, technical performance, development plan optimization, facility capacity, pipeline constraints, and the size of the development program. The development opportunities have been pursued at a pace dependent on capital availability and its allocation in accordance with Husky’s business plans.

As at December 31, 2020, there were no material proved undeveloped reserves that have remained undeveloped for greater than five years, except as follows. The Sunrise Energy Project proved and probable undeveloped bitumen reserves are scheduled to be developed and produced over the next 50 years to fully utilize the steam plant and processing capacity over the life of the current facilities. The Spruce Lake North thermal bitumen project not yet on production is scheduled to start up in 2024. The Lloydminster thermals and Tucker bitumen proved and probable undeveloped locations for existing facilities are scheduled to be developed over the next one to 25 years to utilize each project’s steam and processing capacities. The West

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White Rose Project is scheduled to have the first probable undeveloped locations placed on production by 2024. Proved undeveloped reserves in Madura are scheduled to be brought on production in 2022. Wembley and Ansell’s proved and probable undeveloped locations are scheduled to be developed over the next five and seven years, respectively, in accordance with the Company’s development plan.

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Proved Undeveloped Reserves

	Light & Medium Crude Oil (mmbbls)				Heavy Crude Oil (mmbbls)				Bitumen (mmbbls)				Total Oil (mmbbls)
	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		8.4		69.8		1.0		1.0		177.3		747.9		186.6		818.6
2019		2.8		66.4		1.3		1.3		109.9		775.0		113.9		842.7
2020		—		—		1.1		1.1		10.9		759.2		12.0		760.3

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	Conventional Natural Gas (bcf)				Natural Gas Liquids (mmbbls)				Total (mmboe)
	First Attributed		Total at year-end		First Attributed		Total at year-end		First Attributed		Total at year-end
2018		310.4		739.1		9.2		12.4		247.6		954.2
2019		133.1		367.6		18.3		23.1		154.5		927.1
2020		67.5		187.5		1.3		8.3		24.6		799.8

Probable Undeveloped Reserves

	Light & Medium Crude Oil (mmbbls)				Heavy Crude Oil (mmbbls)				Bitumen (mmbbls)				Total Oil (mmbbls)
	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		0.7		71.2		1.9		2.2		265.6		778.4		268.2		851.8
2019		3.4		65.4		4.2		4.2		20.9		368.9		28.4		438.4
2020		—		115.3		0.2		3.3		1.0		199.5		1.2		318.1

	Conventional Natural Gas (bcf)				Natural Gas Liquids (mmbbls)				Total (mmboe)
	First Attributed		Total at year-end		First Attributed		Total at year-end		First Attributed		Total at year-end
2018		139.0		472.2		4.9		7.8		296.2		938.3
2019		224.9		348.8		37.0		39.7		102.9		536.3
2020		97.3		220.6		3.2		15.7		20.6		370.6

Significant Factors or Uncertainties Affecting Reserves Data

Husky’s reserves can be affected significantly by material fluctuations in product pricing, development plans and capital expenditures, operating costs, regulatory changes that impact costs and/or royalties and production performance. Actual product prices may vary significantly from the forecast price assumptions used by the Company to estimate its reserves, altering the allocation and level of capital expenditures, and accelerating or delaying project schedules. As new information is obtained, the above factors that affect costs, royalties and production performance are reviewed and updated accordingly, which may result in positive or negative revisions to reserves. The effective date of the reserves estimates in this AIF is December 31, 2020, which was prior to completion of the Cenovus Transaction. As a result of the Cenovus Transaction, the Company’s development plans and capital expenditure plans may change as Husky and Cenovus integrate their operations, which changes may impact the Company’s reserves estimates. For additional information on risk factors please see “Risk Factors – Reservoir Performance and Reserves Estimates Risk.”

There are no significant abandonment or reclamation costs, no unusually high expected development costs or operating costs and no contractual obligations to produce and sell a significant portion of production at prices substantially below those which could be realized but for those contractual obligations that have affected, or that the Company reasonably expects to affect, anticipated development or production activities on properties with reserves. For further information on abandonment and reclamation costs in respect of the Company’s properties, please refer to Note 18 of the Company’s audited consolidated financial statements as at and for the year ended December 31, 2020.

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Future Development Costs

With the completion of the Cenovus Transaction, the Company expects to fund its future development costs by cash generated from operating activities, cash on hand, credit facilities and short and long-term debt of the combined company. The cost associated with the combined company’s credit facilities and short and long-term debt would not affect reserves and would not be material in comparison with future net revenues.

The following table includes estimates of the forecasted costs of developing the Company’s proved and proved plus probable reserves as at December 31, 2020:

	Canada				China				Indonesia				Total
Year	Proved Reserves ($ millions)		Proved Plus Probable Reserves ($ millions)		Proved Reserves ($ millions)		Proved Plus Probable Reserves ($ millions)		Proved Reserves ($ millions)		Proved Plus Probable Reserves ($ millions)		Proved Reserves ($ millions)		Proved Plus Probable Reserves ($ millions)
2021		272.0		442.8		—		—		12.9		12.9		284.9		455.7
2022		350.0		1,046.6		—		—		23.5		23.5		373.5		1,070.1
2023		435.1		1,120.7		—		—		—		—		435.1		1,120.7
2024		365.7		1,197.2		—		—		—		—		365.7		1,197.2
2025		459.6		831.6		—		—		—		—		459.6		831.6
Remaining		7,098.4		9,166.2		—		—		—		—		7,098.4		9,166.2
Total		8,980.8		13,805.1		—		—		36.4		36.4		9,017.2		13,841.6

Production Estimates

Yearly Production Estimates for 2021

	Light & Medium Crude Oil (mbbls/day)		Heavy Crude Oil (mbbls/day)		Bitumen (mbbls/day)		Total Oil (mbbls/day)		Conventional Natural Gas (mmcf/day)		Natural Gas Liquids (mbbls/day)		Total (mboe/day)
Canada
Total Gross Proved		16.6		18.3		116.6		151.5		218.6		8.7		196.7
Total Gross Probable		1.8		2.1		17.4		21.3		10.8		0.6		23.6
Total Gross Proved Plus Probable		18.5		20.3		134.0		172.8		229.4		9.3		220.3
China
Total Gross Proved		—		—		—		—		234.7		9.2		48.3
Total Gross Probable		—		—		—		—		4.6		0.2		1.0
Total Gross Proved Plus Probable		—		—		—		—		239.3		9.4		49.3
Indonesia
Total Gross Proved		—		—		—		—		38.4		2.5		8.9
Total Gross Probable		—		—		—		—		—		—		—
Total Gross Proved Plus Probable		—		—		—		—		38.4		2.5		8.9
Total
Total Gross Proved		16.6		18.3		116.6		151.5		491.6		20.4		253.9
Total Gross Probable		1.8		2.1		17.4		21.3		15.4		0.8		24.6
Total Gross Proved Plus Probable		18.5		20.3		134.0		172.8		507.1		21.2		278.5

No individual property accounts for 20% or more of the estimated production disclosed.

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Environmental, Social and Governance Considerations

Environmental, Social and Governance Policies

In 2020, Husky had a corporate Health, Safety and Environment Policy that affirmed its commitment to operational integrity. Operational integrity at Husky has meant conducting all activities in a responsible, safe and reliable manner so that there is no harm to people, the public is protected, impact to the environment is minimized, the health and wellbeing of employees is safeguarded, contractors and customers are safe and physical assets (such as facilities and equipment) and reputation are protected from damage and loss. Husky management has also monitored environmental, social and governance (“ESG”) risks and reported to the Board through management’s Enterprise Risk Management Framework.

In 2020, the HS&E Committee was responsible for oversight of the Health, Safety and Environment Policy, oversight of audit results and monitoring compliance with Husky’s environmental policies, key performance indicators and regulatory requirements.

Authority for overall management of the Company’s ESG strategy, including climate, has been the responsibility of Husky’s Chief Executive Officer, who has delegated management of the Company’s ESG vision and goals to the Chair of the ESG Steering Committee, which is the Senior Vice President, Corporate Affairs and Human Resources. The ESG Steering Committee has also been responsible for the Company’s ESG disclosure strategy and ensuring compliance with Husky’s governance model, including providing ESG information to the Company’s Compliance and Risk Committee, which has then reported to the Board. In 2020, the Chair of the ESG Steering Committee reported to the Board on ESG matters, including climate, through the Corporate Governance Committee, which reviewed ESG matters as a standing item on its meeting agenda.

Husky’s HS&E strategy and objectives have been set by the Executive Health, Safety and Environment Committee (“EHSEC”), which has maintained oversight of the elements of the Company’s Enterprise Risk Matrix related to HS&E, including Climate-Related Risks and Air Emissions. The EHSEC has been the highest-level management committee with a mandate to provide executive level oversight and strategic direction for all critical HS&E issues, including regulatory and operational compliance relating to HS&E matters. This included operational climate-related issues, as these have been identified as a critical risk in the Enterprise Risk Matrix. In 2020, the EHSEC consisted of members of senior management (Vice President and above), and was chaired by the Senior Vice President, Safety, Operations Integrity and Environment. In 2020, the Audit Committee reviewed Husky’s risk register quarterly.

In 2020, Husky’s ESG strategy was integrated with its business plans and Enterprise Risk Matrix and aligned with the Husky Operational Integrity Management System (“HOIMS”).

As a result of the Cenovus Transaction, the Company’s ESG and HS&E strategy may change as Husky and Cenovus integrate their operations, which may impact the Company’s existing policies and objectives.

Husky is committed to conducting business ethically, and in compliance with applicable laws, as well as upholding high standards of business integrity. Husky seeks to deter wrongdoing and promote transparent, honest and ethical behaviour in all its business dealings. Husky has a Code of Business Conduct (the “Code”) that is compliant with the International Chamber of Commerce (“ICC”) Rules of Conduct and Recommendations to Combat Extortion and Bribery, and sets out the standards employees, including temporary and contract staff, officers and directors are expected to meet. This policy includes sections on compliance with laws, avoidance of conflict of interest, proper record- keeping, political contributions, safeguarding company resources, fair competition, avoidance of bribery or other offerings of improper payments, guidelines on accepting payments and entertainment, and other matters. The Code is available on the Company’s website at www.huskyenergy.com and on the SEDAR website at www.sedar.com.

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Husky has established an anonymous and confidential online reporting tool and toll-free telephone numbers (the “Ethics Help Line”) for employees, contractors and other stakeholders to report perceived breaches of the Code. The Ethics Help Line is hosted by EthicsPoint, an independent service provider. Information from submissions is captured and submitted anonymously to an Ethics Help Line committee made up of legal, audit, security, HS&E, and human resources personnel.

Husky’s Anti-Bribery & Anti-Corruption Policy reinforces the Code with additional guidance regarding applicable anti-bribery and anti-corruption laws. All officers and employees, including temporary and contract staff, are expected to observe the highest standards of honesty, integrity, diligence and fairness in all business activities, and undertake mandatory annual training.

Husky and its personnel conduct business in many nations around the world and are subject to various sanctions and anti-money laundering laws. Husky’s Sanctions & Anti-Money Laundering Policy applies to Husky and all of its subsidiaries and to all officers and employees including temporary and contract staff.

Husky’s Government Relations Policy sets out a transparent approach to government relations including roles and responsibilities on engagement and advocacy with governments for participation in industry and business associations for Husky personnel, including officers, directors, employees, and independent and third-party contractors. The Government Relations Policy also reinforces Husky’s prohibition on political contributions and sets clear parameters for employee’s personal political participation and associated reporting requirements.

Husky complies with competition laws, the purpose of which are to preserve and promote a competitive market. Husky’s Competition Act Compliance Policy assists Husky’s directors, officers and employees by providing relevant information about competition laws and guidelines to follow to ensure these laws are complied with and that any issues are handled appropriately.

Husky is an equal opportunity employer dedicated to an environment free of discrimination, harassment and violence and where respectful treatment is the norm. Husky’s Diversity and Respectful Workplace Policy applies to all employees and contractors.

As a responsible member of the communities in which it operates, Husky has a Corporate Citizenship Program that supports investments to reputable and eligible organizations aligned to strategic goals, priorities and values. Husky’s Community Investment Policy provides guidance with the general goal of ensuring that contributions under the Corporate Citizenship Program are supported by a consistent and rigorous decision-making process and reflect Husky’s core corporate values and business strategy.

Through the Corporate Citizenship Program, Husky’s Scholarship Program encourages the pursuit of advanced education by providing financial assistance to qualified students pursuing post-secondary studies at eligible post-secondary educational institutions. The Scholarship Program supports the principles of diversity and inclusion at Husky by creating opportunities for specific and general populations, to prepare for a career in the energy sector.

Husky values education and professional development and provides employees with opportunities to continue to develop and advance their skills, knowledge and experience. Husky’s Learning and Development Policy sets out guidelines, eligibility and support for employees.

Husky believes in securing and protecting personnel, physical assets, property and information from criminal, hostile or malicious acts, consistent with its Security Policy. This policy aims to reduce exposure to security risks with the general goal of ensuring the consistent application of security measures within Husky.

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Husky is also committed to the safety of all personnel, the public and the environment when handling and transporting dangerous substances classified as dangerous goods. Husky’s Transportation of Dangerous Goods (“TDG”) policy ensures dangerous goods are transported in compliance with all TDG laws and Husky standards and procedures.

Husky is committed to ensuring health and safety at work. The ability of every employee and contractor to perform his or her particular job duties satisfactorily and safely is critical to Husky’s continued success. Husky recognizes that the use of illicit drugs and other mood-altering substances, and the inappropriate use of alcohol and medications, can have serious adverse effects on job performance and ultimately on the safety and well-being of employees, contractors, customers, the public and the environment. In light of this, and the safety-sensitive nature of Husky’s operations, Husky’s Alcohol and Drug Policy outlines the standards and expectations associated with alcohol and other drug use, consistent with Husky’s overall safety culture. In October 2019, edible cannabis, cannabis extracts and cannabis topicals became legal in Canada and are now being sold under the Cannabis Act (Canada). As such, Husky has clarified its Alcohol and Drug Policy to include cannabis edibles, extracts and topicals, and to provide ongoing clarity that misuse of and presence at work while under the influence of legalized cannabis in all its forms is prohibited.

The aforementioned policies have been available to employees and contractors on Husky’s intranet. Communication of the policies has been provided through direct e-mail and articles published on Husky’s intranet. Mandatory training has been provided as relevant to the policy and the individual’s role via various mechanisms including in-class, web-based and self-serve courses.

Husky Operational Integrity Management System

Husky has managed operational risks by designing and building its facilities and conducting its operations in a safe and reliable manner. HOIMS is an interrelated framework that set the minimum requirements for all Husky operated entities. HOIMS established standards and procedures that provided a systematic way for Husky to identify, assess and control safety and operational integrity hazards as well as associated environmental risks integral to safe operations and protecting the environment. Risk registers, emergency preparedness, business continuity and security programs are in place for all operating areas. In January 2020, Husky launched the updated HOIMS 2.0.

The fundamental elements of HOIMS 2.0 are:

Leadership and Accountability

• Leaders manage the risks associated with their respective business activities. They are role models who are competent, visible, purposeful and systematic.

Training and Competency

• Personnel are trained and competent to perform their role responsibilities.

Risk Management

• Hazards are identified, and associated risks assessed, managed and prioritized to prevent incidents.

Operational Integrity Information

• Operational integrity and process safety information is accurate, current and easily accessible

Operating Procedures, Policies and Standards

• HOIMS entities document, maintain and follow operating procedures and standards to meet operational integrity goals.

Management of Change

• Risks associated with permanent, temporary and emergency changes that impact HSE and operational integrity are managed.

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Emergency Management

• Husky is prepared to manage an emergency, business interruption or security event.

Incident Reporting, Recording, Investigation and Learning

• Report, investigate and learn from Husky incidents and other external high-impact incidents to prevent recurrence.

Safety Control of Work

• Formal processes are in place to allow work to be completed safety. Work includes upstream, midstream and downstream operations, well, logistics, maintenance, inspection, construction and decommissioning activities.

Project Delivery

• Facilities are designed and built, and assets are developed to meet business, HSE and operational integrity requirements.

Supply Chain and Contractor Management

• Supplied services and materials meet Husky’s HS&E and operational integrity requirements. Asset Operation

• Husky’s assets and equipment are operated to meet operational integrity goals, preventing injury to people and damage to the environment

Reliability and Integrity

• Reliability and integrity are achieved and improved.

Regulatory Compliance

• Protect Husky’s privilege to operate through verifying compliance with legal and regulatory, environmental and social governance requirements.

Assurance, Performance and Improvement

• Performance meets HS&E and operational integrity goals and objectives, and continuously improves.

Pipeline Integrity

The Company has a risk-based Pipeline Integrity Management (“PIM”) Program which is implemented across all Husky-owned and operated pipelines. The PIM program is a framework supported by a suite of documents, including the Pipeline Operations and Maintenance (“POMM”) Procedures Manual, which provides guidelines on safe operation and maintenance of pipelines. Numerous processes are implemented throughout the pipeline lifecycle to ensure a proactive approach to managing the integrity, operations, and maintenance of the pipeline.

The major processes of managing pipeline integrity include:

• A risk management program, which is used to identify integrity threats throughout the pipeline lifecycle and the risk associated with each threat. Appropriate measures are taken to address these risks and reduce them to an acceptable level.

• A Geohazard Integrity Management Program, which is used to identify and manage the risks associated with any potential geohazards (geotechnical and hydrotechnical) on pipelines.

• Technology improvements such as fiber optic sensing technology, advanced technologies for flood monitoring at water crossings, satellite monitoring for landslides, and in-line visual inspection for high-consequence pipelines.

• Engineering assessment, which involves the evaluation of the fitness for service of pipelines when changes are made to design parameters and at line reactivation to proactively mitigate the risk to operational integrity.

• Incident investigation, which is used to establish the root cause(s) of a failure and use this knowledge to proactively enhance pipeline safety and integrity, and to improve integrity programs.

• Annual pipeline integrity reviews, which are conducted for all pipeline systems to review the effectiveness of integrity programs and, where applicable, make recommendations for improvement.

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• Training, including Husky’s well-established Learning Management System, which defines training and experience requirements for the employees who are engaged in maintaining asset integrity. Husky also has a web-based PIM training program for all employees involved in the operation and maintenance of pipelines.

• Performance targets, which have been set annually and tracked quarterly. Immediate steps are taken to address any deficiencies.

• A Management of Change process, which is followed for any changes that affect pipeline operational integrity.

• POMM self-assessments, which are conducted to identify any gaps between POMM requirements and actual practices, and steps are taken to address these gaps.

• A PIM Program review, which is a regular review of the PIM program and supporting procedures for alignment with the latest code and regulatory requirements, taking into consideration Husky experience and pipeline industry standards and practices.

Climate Change

General

Along with increased evidence and effects of climate change, concerns about climate change and its solutions have increased significantly in recent years. Technology related to managing man-made GHG emissions, a source of climate change, is improving and expectations regarding climate change risk management are growing, resulting in increased stakeholder, investor and consumer pressure to reduce carbon emissions and transition to a net zero carbon future. Third parties have initiated litigation related to climate change against certain oil and gas companies and governments around the world. Some oil and gas companies have set net zero carbon emissions targets in response to one or more of these pressures.

The current regulatory environment related to air emissions and climate policy is also dynamic. The impacts of emerging policy are becoming clearer as various jurisdictions finalize and implement new regulations. The Canadian government has tabled a bill to legislate net zero emissions by 2050. This ambitious target is supported by the Healthy Environment and a Healthy Economy Plan, which targets a carbon price of $170 per tonne by 2030.

Husky operates in many jurisdictions that regulate or have proposed to regulate air pollutants, including GHG emissions. Air regulations include:

• absolute and intensity-based emissions limits or targets.

• market based frameworks.

• equipment and/or facility level emissions performance standards and reporting.

• other regulatory measures including low carbon fuel and renewable fuel standards.

Risks associated with climate change trends and regulations are discussed under “Risk Factors”.

International Climate Change Agreements

Canada, Indonesia and China are all signatories to the Paris Agreement drafted at the United Nations Framework Convention on Climate Change Conference of the Parties held in Paris, France in December 2015.

Canada has submitted a Nationally Determined Contribution to reduce GHG emissions by 30% below 2005 levels by 2030. Indonesia has pledged a 29% reduction below a “business as usual” baseline by 2030. China announced that it will strengthen its 2030 climate target to see peak emissions before 2030, but with reductions per unit GDP by 60-65% from 2005 levels and aim to achieve carbon neutrality before 2060. There is a commitment to review and increase pledges every five years under the Paris Agreement.

In November 2018, China and Canada signed a memorandum of understanding on climate change cooperation.

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On November 4, 2019, the U.S. issued formal notification of withdrawal from the Paris Agreement, to take effect on November 4, 2020. However, on January 20, 2021 President Biden issued an executive order starting the process for the U.S. to rejoin the Paris Agreement.

Canadian Federal Regulations

The Government of Canada has begun addressing emissions from specific sectors of the economy, including working closely with the U.S. government on North American vehicle emissions standards. Canada has adopted renewable fuels regulations, requiring fuel producers and importers to have an average of at least 5% of their gasoline supply come from renewable sources (such as ethanol) and to have an average of at least 2% of their diesel supply come from renewable sources (such as biodiesel).

In 2012, the Canadian Council of Ministers of the Environment agreed to implement a new Air Quality Management System (“AQMS”) to protect human health and the environment through the continuous improvement of air quality in Canada. AQMS includes three main components: Canadian Ambient Air Quality Standards (“CAAQS”); Base-Level Industrial Emissions Requirements (“BLIERs”); and the management of air quality through local air zones and regional airsheds.

CAAQS are the AQMS driver and set the bar for air quality management across the country. New standards for ozone and fine particulate matter for 2015 and 2020 were published in 2013. New CAAQS for sulphur dioxide for 2020 and 2025 were announced in 2016, and new CAAQS for nitrogen dioxide for 2020 and 2025 were published in 2017.

Under the BLIERs, three regulations and a guideline were developed within the AQMS. The first of the Multi-Sector Air Pollutants Regulations was published in June 2016, which includes regulations applicable to reciprocating spark-ignited natural gas engines and non-utility boilers and heaters operating within the oil & gas sector. An emissions guideline under the Environmental Protection Act (Canada) for stationary gas turbines was published in November 2017. Other sectors and air pollutants are expected to be added to the regulations in the future.

The BLIERs pertaining to oxides of nitrogen (“NOx”) emissions from boilers and heaters and NOx emissions from reciprocating engines in industrial facilities are applicable to Husky’s Canadian upstream and downstream oil and gas facilities. The Boiler & Heater BLIER and Reciprocating Engine BLIER have introduced performance, design and monitoring standards for both existing and new equipment units, whereas the Stationary Gas Turbine BLIER has only introduced performance and design standards for new equipment.

In June 2018, the federally-enacted Greenhouse Gas Pollution Pricing Act came into force, under which the federal government seeks to implement its carbon-pricing plan outlined in the 2016 Pan-Canadian Framework on Clean Growth and Climate Change, including establishing a Canada-wide minimum price on carbon emissions through two key mechanisms: a carbon levy applied to fossil fuels ($20 per tonne of CO₂e starting on April 1, 2019 and increasing by $10 annually to $50 per tonne in 2022); and an output-based pricing system applicable to industrial facilities with GHG emissions above 50,000 tonnes of CO₂e per year with opt-in provisions for smaller facilities.

On July 10, 2019, the Government of Canada published the Output-Based Pricing System (“OBPS”) Regulations under the Greenhouse Gas Pollution Pricing Act. The federal OBPS includes sectorial Output-Based Standards, provisions pertaining to GHG emissions quantification and reporting, as well as details on the administration process and content of verification reports. The federal OBPS is applicable to Husky’s Minnedosa Ethanol Plant effective January 1, 2019.

A federal Clean Fuel Standard (“CFS”) Discussion Paper was released in February 2017. The CFS will be developed to achieve 30 megatonnes of annual reductions in GHG emissions by 2030 through requiring reductions in fuel carbon intensities based on a life- cycle analysis and will go beyond transportation fuels to include fuels used in industry and buildings. In December 2017, the CFS regulatory framework was published, and in December 2018, the Government of Canada published the Regulatory Design Paper on the CFS. The CFS Regulatory Design Paper focuses on the liquid fuel stream regulations, and key design elements include a carbon intensity reduction of 10 g CO2/MJ (approximately 11%) by 2030 from a 2016 baseline. A

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Proposed Regulatory Approach was also released in June 2019 that builds on the previous papers issued by Environment Canada. For liquid fuels, including transportation fuels, draft regulations were published in late 2020 with final regulations in 2021 coming into force in 2022.

The Government of Canada is committed to reducing methane emissions from the oil and gas sector by 40% to 45% below 2012 levels by 2025. Final methane reduction regulations for the upstream oil and gas industry were published on April 26, 2018. Emissions sources subject to these regulations include venting from wells and batteries (including associated gas at oil facilities), storage tanks, pneumatic devices, well completions, compressors and fugitive equipment leaks. Final regulations apply to new and existing sources, with the first requirements coming into force in 2020, and the remaining requirements by 2023. Alberta and Saskatchewan methane regulations achieved equivalency to the federal regulations in November 2020.

The Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Petroleum Sector) pertaining to the downstream oil and gas industry were published by the Government of Canada in November 2020. The regulations require the implementation of comprehensive Leak Detection and Repair programs at refineries, upgraders and certain petrochemical facilities. These facilities are also required to monitor the levels of certain volatile organic compounds at facility perimeters. The regulations come into force effective January 1, 2022.

Canadian Provincial Greenhouse Gas Regulations

Under the Greenhouse Gas Pollution Pricing Act regime, the federal carbon pollution pricing system can be implemented in provinces and territories that do not have a carbon pollution pricing system that meets the federal benchmark or that request it. Provinces and territories had until September 1, 2018, to outline their plans.

There remains uncertainty with respect to the extent of the Government of Canada’s jurisdiction to set minimum standards applicable to the provinces. On September 22 and 23, 2020, the Supreme Court of Canada heard appeals in relation to constitutional challenges of the validity of the federally-enacted Greenhouse Gas Pollution Pricing Act, but has yet to issue its decision.

In Alberta, the Emissions Management and Climate Resilience Act addresses carbon dioxide, methane and other specified GHG emissions. The Act establishes the framework and regulation-making authority for the governance of specified gas emissions and mandates reporting requirements for GHG emitters in Alberta.

Alberta’s provincial OBPS scheme under the Technology Innovation and Emissions Reduction Regulation (“TIER”) and the emissions sources it covers was confirmed to meet equivalency with the federal minimum standards on December 6, 2019. The federal fuel charge applies in Alberta where TIER does not apply. The TIER, effective January 1, 2020, regulates facilities in Alberta emitting over 100,000 tonnes CO₂e/year with an opt-in program for smaller emitters and for conventional oil and gas aggregate facilities. TIER allows for the option of a facility specific performance baseline or a sector specific best performance standard as the basis for reduction. The conventional oil and gas aggregated facility opt-in to TIER provides significant emissions intensive, trade exposed (“EITE”) protection for the sector as participation in the large emitters’ regulation exempts the facilities from the Federal Fuel Levy. Alberta’s TIER regulation is expected to lessen the financial burden associated with carbon compliance by allowing companies to improve emissions based on historical facility performance rather than being subject to sector intensity benchmarks that are typically set by the largest, most mature operations. Alberta is expected to follow federal pricing of $30/tonne CO₂e in 2020 escalating to $50/tonne CO₂e by 2022.

Alberta’s methane regulations, effective January 1, 2020 limit methane emissions at a site and equipment level at upstream oil and gas facilities, and focus on measurement, monitoring and reporting on methane emissions, including fugitive emissions. This regulatory framework is intended to achieve Alberta’s methane emissions reduction target of 45% by 2025 and equivalency with the Government of Canada’s methane reduction goals.

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In December 2017, the Government of Saskatchewan released “Prairie Resilience: A Made-In-Saskatchewan Climate Change Strategy” that includes the implementation of sector-specific output-based performance standards on facilities emitting more than 25,000 tonnes of CO₂e per year. The Management and Reduction of Greenhouse Gases Amendment Act (“MRGHG”), and various GHG regulations under the Act impose a carbon price (starting at $20 per tonne of CO₂e in 2019 escalating by $10/year up to $50/tonne in 2022) on facilities that emit more than 25,000 tonnes of CO₂e/year. Facilities such as the Upgrader, and Husky’s ethanol plant and Saskatchewan thermal projects are subject to MRGHG. The Province of Saskatchewan has a carbon tax that applies to all fuel for all facilities under that threshold. As part of the its October 23, 2018 announcement on climate policy equivalency, the Government of Canada announced the federal OBPS would be applicable to Saskatchewan’s electricity generation and natural gas transmission lines as of January 1, 2019. The federal fuel charge has also taken effect in Saskatchewan as of April 2019. Saskatchewan has published the Management and Reduction of Greenhouse Gases (Upstream and Gas Aggregate Facility) Standard and is allowing opt-in of the conventional oil and gas assets to provide EITE protection for the sector, as participation in the large emitters’ regulation exempts the facilities from the Federal Fuel Levy.

The Government of Saskatchewan published the Oil and Gas Emissions Management Regulations on December 14, 2018, effective January 1, 2019, which apply to oil and gas operations with aggregated emissions exceeding 50,000 tonnes of CO₂e per year. These regulations seek to reduce methane emissions from the oil and gas sector by setting target emissions intensities for various regions within the province. The regulations are intended to reduce provincial methane emissions intensity by 45% by 2025.

On October 3, 2018, Manitoba announced it was canceling its carbon tax. As part of the October 23, 2018 announcement by the federal government, the federal carbon policy applies in full in Manitoba including the application of an output-based standard to Husky’s Minnedosa ethanol plant.

On June 7, 2016 the Management of Greenhouse Gas Act passed in the House of Assembly of NL, establishing the legislative basis for a provincial industrial large emitters program and reporting regulations. The Management of Greenhouse Gas Reporting Regulations came into force on March 7, 2017. The Government of Newfoundland and Labrador, in consultation with industry, has developed and proposed GHG regulations for the offshore petroleum production sector to be incorporated by amendment to the Management of Greenhouse Gas Act and the Atlantic Accord. On October 23, 2018 the Government of Canada deemed the NL large emitter and fuel levy programs to price carbon as equivalent to federal standards. Subsequently, Budget Implementation Act, 2018, No. 2 (“Bill C-86”), was entered into the House of Commons on October 29, 2018 to amend the Atlantic Accord to enable the C-NLOPB to manage the requirements of the provincial GHG reporting regulations in the offshore petroleum sector.

The NL performance-based regulation imposes carbon pricing (beginning at $20/tonne in 2019 and escalating to $50/tonne in 2022) on petroleum production facilities with GHG emissions exceeding 25,000 tonnes/year. Beginning January 1, 2019, a levy of 4.42 cents per litre on gasoline and 5.37 cents per litre on diesel (both equivalent to $20/tonne) will be applied as part of the carbon tax. This provincial Gasoline and Diesel Tax will be adjusted with a goal of protecting economic competitiveness related to taxation (including carbon tax) of fuel products. The provincial carbon tax rates will only increase to match equivalent increases in carbon taxation programs in neighboring Atlantic provinces. There are noted exemptions for exploration drilling and aviation fuels. However, the addition of this carbon tax to marine diesel will increase operating costs for Atlantic region operations.

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U.S. Greenhouse Gas Regulations

The U.S. does not have federal legislation establishing targets for the reduction of, or limits on, GHG emissions. However, the federal Environmental Protection Agency (“EPA”) has and may continue to promulgate regulations concerning the reporting and control of GHG emissions. Since 2010, the EPA’s Greenhouse Gas Reporting Program (“GHGRP”) requires any facility releasing more than 25,000 tonnes of CO₂e emissions per year to report those emissions on an annual basis. In addition to reporting direct CO₂e emissions, the GHGRP requires refineries to estimate the CO₂e emissions from the potential subsequent combustion of the refinery’s products.

In May 2010, the EPA finalized the Greenhouse Gas Tailoring Rule. This rule updated the Clean Air Act (USA) by phasing in permitting requirements for GHG emissions, including Best Available Control Technology (“BACT”) requirements for new and modified sources of air emissions emitting more than a threshold quantity of GHG. In June 2014, the U.S. Supreme Court invalidated portions of the Greenhouse Gas Tailoring Rule but upheld the EPA’s authority to require BACT for GHG emissions associated with sources that must obtain Prevention of Significant Deterioration permits based on their non-GHG emissions.

U.S. Renewable Fuel Standard

The U.S. created its Renewable Fuel Standard (“RFS”) program with the stated intention of reducing GHG emissions and expanding the renewable fuels sector, while reducing U.S. reliance on imported oil. The RFS program was authorized under the Energy Policy Act (USA) of 2005 and expanded under the Energy Independence and Security Act (USA) of 2007. The EPA implements the RFS program in consultation with the U.S. Department of Agriculture and Department of Energy.

The RFS program is a national policy that requires a certain volume of renewable fuel to replace or reduce the quantity of petroleum-based transportation fuel. Obligated parties under the RFS program are refiners or importers of gasoline or diesel fuel. Compliance is achieved by blending renewable fuels into transportation fuels or by obtaining credits, called Renewable Identification Numbers (“RINs”) to meet an EPA-specified Renewable Volume Obligation (“RVO”). The RFS program, through the EPA-specified RVOs, requires refiners to add annually increasing amounts of renewable fuels to their petroleum products or to purchase RINS in lieu of such blending.

The EPA calculates and establishes RVOs every year through rulemaking. The standards are converted into a percentage, and obligated parties must demonstrate compliance annually.

Husky’s GHG Policies and Outlook

As part of long-range planning, Husky has assessed future compliance costs associated with regulations of GHG emissions in its operations and the evaluation of future projects, based on Husky’s outlook for carbon pricing under current and pending regulations. The impact of recently announced regulations in Canada has been evaluated as provinces and the federal government finalize carbon pricing regulations. Husky has monitored international and domestic efforts to address climate change, including international low carbon fuel standards and regulations and other emerging regulations in the jurisdictions in which Husky operates.

In 2020, Husky set and published a GHG Scope 1 emissions reduction target of 25% of 2015 emissions intensity by 2025, and an aspirational goal of net zero emissions by 2050. Performance against the 2025 greenhouse gas emissions intensity reduction target has been linked to executive pay. Asset-level carbon management plans have been prepared to ensure that climate change and emissions reductions have been at the forefront of business decisions. In 2019, Husky’s gross GHG Scope 1 emissions were 9,570,000 tonnes CO₂e. GHG Scope 2 emissions in 2019 were 1,915,000 tonnes CO₂e.

Concurrent with the announcement of the Cenovus Transaction, Cenovus stated that the combined company will maintain the ambition established independently by Cenovus and Husky of achieving net zero emissions by 2050, and that the combined company will remain committed to pursuing ESG targets and will undertake a thorough analysis before setting meaningful targets for the new portfolio.

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By estimating its current and projected future emissions and understanding forthcoming regulations that may impact its business, Husky has determined the areas of its operations that may face future compliance obligations or additional costs from regulation. In 2020 Husky conducted its Paris Accord 2-degree scenario analysis to test its resilience against the financial risks associated with emerging climate policies and commodity pricing in a carbon-constrained economy. Husky’s Enterprise Risk Management Framework has supported decision making via comprehensive and systematic identification and assessment of risks that could materially impact Husky’s results.

Husky’s GHG management framework has included a process for climate-related technology assessment, including new innovations that can reduce emissions intensity, and innovations that could have disrupted Husky’s business strategy. As new technologies have been identified by subject matter experts across Husky, they are shared through Husky’s Air Critical Competency Network and as appropriate, are incorporated into regular updates to EHSEC, the ESG Steering Committee and business unit leadership. Husky employs a Marginal Abatement Cost Curve tool as part of a process to review technologies that might qualify for external funding and enhance business cases for technology risk mitigation.

Husky recognizes the recommendations of the Financial Stability Board’s Task Force on Climate-related Financial Disclosures (“TCFD”). Husky voluntarily has responded annually to the Climate Disclosure Project (“CDP”) climate change questionnaire, which as of 2018 had fully adopted the TCFD recommendations.

Environmental Protection

General

Oil and conventional natural gas operations are subject to environmental regulations pursuant to a variety of federal, provincial, state and local laws and regulations, as well as international conventions (collectively, “environmental regulations”).

Environmental regulations, policies and legal agreements regulate and impose restrictions, liabilities and obligations on how industry is required to handle, store, transport, treat and dispose of emissions, water/waste water, hazardous substances and wastes. Controls and limits on spills, releases and emissions to the environment, including GHG emissions (as discussed in greater detail above) are required to be diligently managed. Environmental regulations also require that wells and facilities be constructed, operated, maintained, abandoned and reclaimed in compliance with pertinent regulatory requirements. In addition, certain types of operations, including exploration and development projects and significant changes to certain existing projects, may require the submission and approval of environmental impact assessments.

Some examples of potential new or enhanced environmental regulations, and impacts of possible changes, include:

• conventional air pollutant and GHG emissions regulations and mandatory reductions.

• calculation and regulation of carbon intensity of fuels, including transportation fuels.

• potential for restrictive operating policies on development in areas of value to species at risk.

• increased restrictions on freshwater licensing.

• increased restrictions on activities in fish-bearing water courses.

• enhanced groundwater and surface water monitoring.

• enhanced water discharge criteria.

• increased restrictions on waste water disposal.

• enhanced water recycle criteria.

• enhanced water crossing monitoring and reporting requirements.

• enhanced requirements for environmental assessment, including the potential for more projects to require assessments, longer review times, additional information requirements and increased requirements related to Indigenous consultation.

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• water management for hydraulic fracturing.

• wetland compensation.

• induced seismicity.

• feedstock and product transportation by rail, pipeline and roadway.

• pipeline integrity management.

• remediation regulation.

• reclamation criteria.

• increased financial security requirements for abandonment, remediation, and reclamation.

• constraints mapping, footprint reduction and land use.

• measurement requirements for oil and gas operations.

• investigations of operational upsets that result in emissions.

Bill C-69

In Canada, Bill C-69, An Act to enact the Impact Assessment Act and the Canadian Energy Regulator Act, to amend the Navigation Protection Act and to make consequential amendments to other Acts, (2019), was passed by Parliament on June 21, 2019. The Impact Assessment Act, the Canadian Energy Regulator Act, the Canadian Navigable Waters Act, and associated regulations came into force on August 28, 2019. Of note, the Impact Assessment Act creates the new Impact Assessment Agency of Canada, repeals the Canadian Environmental Assessment Act, 2012, and provides a new approach to the federal assessment of major projects in Canada. The Canadian Energy Regulator Act replaces the National Energy Board with the Canada Energy Regulator (“CER”) and defines its composition, mandate and powers. The role of the CER is to regulate the exploitation, development and transportation of energy within Parliament’s jurisdiction.

The Canadian Navigable Waters Act increases protections of navigable waters, expanding the regulation of major works and obstructions, and setting requirements for minor works on all navigable waters.

Bill C-68, An Act to amend the Fisheries Act and other Acts in consequence, (2019), was also passed in parliament on June 21, 2019 and outlined amendments to the Fisheries Act which came into effect on August 28, 2019. The fish and fish habitat protection provisions under this Act strengthen some protections for aquatic species and protect the interests of people who depend on them, particularly Indigenous communities.

Transport Canada

Effective August 3, 2020, new Transport Canada regulations, titled Transportation of Dangerous Goods by Rail Security Regulations, require security plans and security training to be established for TDG by rail. Specific requirements are based on quantity and type of dangerous goods transported by rail. The new security regulations will affect sites which load prior to, or unload following, rail transportation, or offer for transport dangerous goods by rail in quantities outlined in the regulations.

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Husky’s Operations

Husky’s operations are subject to various environmental requirements under federal, provincial, state and local laws and regulations, as well as international conventions. These laws and multiple regulatory requirements cover matters such as: control of air emissions, management and recycling of wastewater, non-saline water use, protection of surface water and groundwater, land disturbances and handling and disposal of waste materials. These regulatory requirements have grown in number and complexity over time, covering a broader scope of industry operations and products. Husky has been actively engaged with federal, state, provincial, local agencies and through industry associations to develop sustainable regulations that allow for compliant operations and are also protective of the environment. In addition to existing requirements, Husky recognizes that there are emerging regulatory frameworks that have a potential financial impact on Husky’s operations. As part of Husky’s review of proposed regulations that may affect its business and operations, Husky may, from time to time, audit and prepare an internal analysis of the possible or expected impact of new regulations, which are subject to various uncertainties. See “Risk Factors.”

Husky minimizes impact on the landscape through consideration and application of the mitigation hierarchy, with the implementation of avoidance and mitigation programs where appropriate. Monitoring the effectiveness of mitigation occurs where mandated by regulatory requirements or stakeholder commitments and may occur when Husky recognizes the value, such as for complex projects or learning opportunities. Where monitoring indicates that corrective action is warranted, Husky’s policy has been to take an adaptive proactive management approach.

Water

Numerous regulations are imposed on the oil and gas industry’s operations with the general goal of ensuring surface water and fresh groundwater resources are protected. Guidelines cover the following:

• oil and gas well, pipeline and facility offsets from fresh surface water courses and domestic water wells.

• drilling fluids, well construction materials and methods to isolate fresh groundwater aquifers from resource exploration, extraction and disposal activities.

• downhole offsets for completions operations, ensuring isolation from fresh groundwater aquifers, with specific risk mitigation expectations for hydraulic fracturing.

• monitoring of fresh groundwater aquifers and wetlands at major operating facilities.

• monitoring of assets that cross fish bearing streams ensuring passage is unrestricted.

• water discharge criteria for onshore and offshore facilities.

• fluid transport, handling and storage.

• process water recycling targets.

Water withdrawals are regulated in Husky’s operating jurisdictions with the goal of minimizing impacts to freshwater resources. Oil and gas companies have reporting requirements relating to most licenced freshwater withdrawals. Policies dictate water source selection and management. Water withdrawals are further governed by local watershed and/or industry water management plans.

Husky has a corporate Water Standard that mandates Water Risk Assessments and Water Management Plans for its facilities, which include consideration of regulatory risks. The purpose of these Water Risk Assessments is to try to identify and mitigate these risks. Water Risk Assessments consider both known proposed water regulations and possible future regulations (not currently proposed). Husky voluntarily responded annually to the CDP water questionnaire.

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Monitoring of surface water and ground water quality relating to hydraulic fracturing operations is not regulated in the jurisdictions in which Husky has these operations. Husky has proactively implemented a recommended practice for completing baseline quality and quantity tests for water wells located in proximity to its hydraulic fracturing operations.

As an active member of the In-situ Water Technology Development Centre and Canada’s Oil Sands Innovation Alliance (“COSIA”) Water Committees, Husky has been involved in developing new technologies to recycle wastewater, reduce water use and improve energy efficiency. Husky has had teams dedicated to solving water management challenges by leveraging expertise in hydrogeology, surface water aquatics, hydrology, water treatment and drilling waste management. Husky continues to pursue opportunities to conserve water, through alternative water sources and recycling of produced water. At the Tucker Thermal Project, produced water is recycled and make-up water is sourced from saline, non-potable groundwater. The Sunrise Energy Project recycles produced water and supplements this with process-affected water from a nearby oil sands operation after it has been treated, and lower quality non-saline groundwater that is in contact with bitumen to generate steam for oil recovery. The Lima Refinery has a wastewater reuse program that substantially reduces its water needs annually. As a specific action related to water supply risk in its operations, Husky is participating in a research project to understand potential climate impacts to industrial water supplies on the North Saskatchewan River. This multi-year study is a collaborative project with academia and another industry partner.

Migratory Birds and Species at Risk

Canada’s oil and gas industry may affect migratory birds and bird habitat as well as habitat impacting sensitive species through land disturbance activities and operating practices (e.g., sludge ponds, vegetation clearing). Industry activities risk contravening the Migratory Bird Convention Act (Canada) (“MBCA”) or the Species at Risk Act (Canada) (“SARA”) and supporting legislation that prohibits the disturbance and destruction of migratory birds, their eggs and/or their nests and mandates the protection and management of sensitive species habitat. There are maximum fines of up to $6 million, with all subsequent fines doubling, for corporations that are convicted under the MBCA. For corporations, current penalties under SARA include fines of $1 million, with potential to double based on subsequent contraventions. U.S. operations are subject to similar requirements pursuant to the Migratory Bird Treaty Act and the Endangered Species Act (USA).

In October 2020, Alberta Environment and Parks and Environment and Climate Change Canada signed an agreement for the conservation and recovery of the threatened woodland caribou in Alberta, under section 11 of the Species at Risk Act. The purpose of the agreement is to support the conservation and recovery of woodland caribou to naturally self-sustaining status by outlining measures to be taken by the parties. Industry and government activities in caribou ranges in Alberta must align with the principles of this agreement to avoid enactment of a federal Environmental Protection Compliance Order in the province.

Husky has improved the protection of migratory birds through development of a Standard for Pre-Construction Migratory Bird Incidental Take Mitigation, as well as the preparation of a Bird Deterrent Guidance document to assist environmental staff and operators in the awareness and selection of the most appropriate deterrent systems for each facility. For Atlantic operations, in accordance with Husky’s permit from the Canadian Wildlife Service (“CWS”), Husky’s Seabird Handling Procedure provides guidance to personnel on how to handle birds that arrive on an installation. Oiled birds are cleaned and rehabilitated at Husky’s Seabird Recovery Centre in consultation with CWS. Husky has improved protection of species at risk and their habitats by conducting environmental surveys and wildlife sweeps when appropriate to identify sensitive habitats, individuals and wildlife features (dens, for example) to allow implementation of appropriate mitigation measures. Husky representation at industry associations such as the Canadian Association of Petroleum Producers (“CAPP”), the Petroleum Technology Alliance Canada and COSIA which Husky joined in 2020, has allowed Husky to collaborate with other environmental professionals to discuss innovative ideas and participate in multi-stakeholder discussions. The associations work towards common goals such as developing industry-wide solutions to reduce risk of impacts to migratory birds and SARs.

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Ice Management

Husky has several policies in place to protect people, equipment and the environment in the event of extreme weather conditions and adverse ice conditions. Husky has developed Adverse Weather Guidelines for the SeaRose FPSO and is managing physical risk through engineering for 1:100-year weather events.

Husky’s Atlantic operations have a robust ice management program, which uses a range of resources including an industry shared ice surveillance aircraft, as well as synergistic relationships with government agencies including Environment and Climate Change Canada, the Coast Guard and Canadian Ice Service. Regular ice surveillance flights commenced in February 2020 and continue until the risk has abated. In addition, Atlantic operators employ a series of supply and support vessels to actively manage ice and icebergs. These vessels are equipped with a variety of ice management tools including towing ropes, towing nets and water cannons. Husky also maintains a series of ad-hoc relationships with contractors, allowing the quick mobilization of additional resources as required.

Husky regularly assesses all aspects of its ice management program to ensure that the program continues to evolve as more information about the characteristics of ice and icebergs in the Atlantic becomes available and as new technologies are developed. Husky continues to look at ways to improve its ability to predict and respond to sea ice and icebergs with ongoing research and development. Recent initiatives include the design and fabrication of modular, heavy weather nets with sensors and development of a Common Operating Picture on Husky’s contracted geographic information systems software module including ice flight information, location, drift models, and pack ice drift model runs. Husky now has a dedicated ice management room onshore, which mirrors the offshore and allows for real-time monitoring of field operations. Additional research and development activity related to ice management is continuing.

Abandonment, Reclamation and Remediation

Ongoing remediation and reclamation work is occurring at approximately 3,700 well sites and facilities in Western Canada. During 2020, Husky spent approximately $39 million on asset retirement obligations (“ARO”) in North America. Husky expects to spend approximately $71 million in 2021 on ARO and environmental site closure activities in North America, including abandonment, decommissioning, reclamation and remediation.

Husky has also pioneered a program-based approach to asset retirement whereby all retirement activities are undertaken as a single program, greatly increasing the efficiency and effectiveness of the work. The Alberta Energy Regulator has embraced Husky’s approach, now referred to as “Area-Based Closure”, has used it as a template for all of industry to adopt where possible and has incorporated it into its closure regulations.

In Asia Pacific and in accordance with the provisions of the regulations of the People’s Republic of China, Husky has deposited funds into separate accounts restricted to the funding of future ARO. As at December 31, 2020, Husky had deposited funds of $164 million, which were classified as non-current liabilities.

Husky completed a review of its ARO provisions, including estimated costs and projected timing of performing the abandonment and retirement operations. The results of this review have been incorporated into the estimated liability as disclosed in Note 18 of Husky’s audited consolidated financial statements as at and for the year ended December 31, 2020.

Husky has an ongoing environmental monitoring program at owned and leased retail locations and performs remediation where required. Husky also has ongoing monitoring programs at its downstream facilities, including refineries and the Upgrader. Husky has several inactive facilities ranging from former refineries to retail locations. Management and remediation plans are prepared for these sites based on current and future land use.

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RISK FACTORS

The following summarizes what the Company believes to be the most significant risks relating to its operations which should be considered when purchasing securities of the Company. The Company has developed an enterprise risk matrix to identify risks to its people, the environment, its assets and its reputation, and to systematically mitigate these risks to an acceptable level. The risk matrix and associated mitigation strategies are reviewed quarterly by senior management and the Audit Committee, and annually by the Board.

Operational and Safety Incidents

The Company’s businesses are subject to inherent operational risks which have the potential to impact safety, the environment, its assets and its reputation. In general, the Company’s operations are subject to operational risks, including, but not limited to: fires, loss of containment, blowouts, power outages, freeze-ups and other similar events; oil and natural gas leaks; encountering unexpected formations or pressures; premature declines of reservoir pressure or productivity; uncontrollable flows of oil, natural gas and well fluids; spills at truck terminals and hubs; spills associated with the loading and unloading of potentially harmful substances onto trucks; release of tailings or harmful substances into a water system; the breakdown or failure of equipment, pipelines and facilities, information systems and processes; the performance of equipment at levels below those originally intended (whether due to misuse, unexpected degradation or design, construction or manufacturing defects); releases or spills from shipping vessels; failure to maintain adequate supplies of spare parts; the compromise of information technology and control systems and related data; operator error; labour disputes; disputes with interconnected facilities and carriers; operational disruptions or apportionment on third-party systems or refineries, which may prevent the full utilization of the company’s facilities and pipelines; epidemics or pandemics; and catastrophic events, including, but not limited to, war, extreme weather events, natural disasters, explosions, acts of sabotage and other similar events.

Failure to manage the hazards and associated risks effectively could result in potential fatalities, environmental impacts, interruptions to activities or use of assets, or loss of license to operate. The Company implements an Operational Integrity Management System designed to systematically identify, assess and manage operational and safety risks to tolerable levels. In addition, the Company, in accordance with industry practice, maintains insurance coverage against losses from certain of these risks. Nonetheless, insurance proceeds may not be sufficient to cover all losses, and insurance coverage may not be available for all types of operational risks.

Commodity Price Volatility

The Company’s results of operations and financial condition are dependent on the prices received for its refined products, crude oil, NGL and conventional natural gas production. Lower prices for crude oil, NGL and conventional natural gas could adversely affect the value and quantity of the Company’s oil and gas reserves. The Company’s reserves include significant quantities of heavier grades of crude oil that often trade at a discount to light crude oil. Heavier grades of crude oil are typically more expensive to produce, process, transport and refine into high-value refined products. Refining and transportation capacity for various grades of crude oil may be constrained from time to time, creating the need for additional refining and transportation capacity. Wider price differentials between heavier and lighter grades of crude oil could have a material adverse effect on the Company’s results of operations and financial condition, reduce the value and quantities of the Company’s heavier crude oil reserves and delay or cancel projects that involve the development of heavier crude oil resources. There is no guarantee that pipeline development projects or other transportation alternatives will provide sufficient transportation capacity and access to refining capacity to accommodate expected increases in North American heavy crude oil and bitumen production.

Prices for refined products and crude oil are based on world supply and demand. Supply and demand can be affected by several factors including, but not limited to, actions taken by OPEC, non-OPEC crude oil supply, social conditions in oil producing countries, the occurrence of natural disasters, general and specific economic conditions, technological developments, prevailing weather patterns, government regulation and policies and the availability of alternate sources of energy.

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The Company’s conventional natural gas production is currently located in Western Canada and Asia Pacific. Western Canada’s conventional natural gas production is subject to North American market forces. North American natural gas supply and demand is affected by several factors including, but not limited to, the amount of conventional natural gas available to specific market areas either from the wellhead of existing or accessible conventional or unconventional sources (such as from shale) or from storage facilities, technological developments, prevailing weather patterns, the U.S. and Canadian economies, the occurrence of natural disasters and pipeline restrictions. The price received by the Company for production from Asia Pacific is determined by long-term contracts.

In certain instances, the Company will use derivative instruments to manage exposure to price volatility on a portion of its refined product, oil and gas production, inventory or volumes in long-distance transit. The Company may also use firm commitments for the purchase or sale of crude oil and conventional natural gas.

The fluctuations in refined products, crude oil and conventional natural gas prices are beyond the Company’s control and could have a material adverse effect on the Company’s results of operations and financial condition.

Commodity Price Risk

In certain instances, the Company uses derivative commodity instruments and futures contracts on commodity exchanges, including commodity put and call options under a short-term hedging program, to manage exposure to price volatility on a portion of its refined product, oil and gas production, and inventory or volumes in long distance transit. The Company may also use firm commitments for the purchase or sale of crude oil and conventional natural gas.

The Company’s results will be impacted by a decrease in the price of crude oil and conventional natural gas inventory. The Company has crude oil inventories that are feedstock, held at terminals or part of the in-process inventories at its refineries and at offshore sites. Due to the integrated nature, the Company has a natural partial mitigation to the WCS differential risk. The Company also has conventional natural gas inventory that could have an impact on earnings based on changes in conventional natural gas prices. All these inventories are subject to a lower of cost or net realizable value test on a quarterly basis.

Reservoir Performance and Reserves Estimate Risk

Lower than projected reservoir performance on the Company’s key growth projects could have a material adverse effect on the Company’s results of operations, financial condition, business strategy and reserves. Inaccurate appraisal of large project reservoirs could result in missed production, revenue and earnings targets and negatively affect the Company’s reputation and investor confidence.

In order to maintain the Company’s future production of crude oil, conventional natural gas and NGL and maintain the value of the reserves portfolio, additional reserves must be added through discoveries, extensions, improved recovery, performance related revisions and acquisitions. The production rate of oil and gas properties tends to decline as reserves are depleted while the associated unit operating costs increase. Maintaining an inventory of projects that can be developed depends upon, but is not limited to, obtaining and renewing rights to explore, develop and produce oil and natural gas, drilling success, completion of long lead time capital intensive projects on budget and on schedule and the application of successful exploitation techniques on mature properties.

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The reserves data contained or referenced in this AIF represent estimates only. The accurate assessment of oil and gas reserves is critical to the continuous and effective management of the Company’s upstream assets. Reserves estimates support various investment decisions about the development and management of oil and gas properties. In general, estimates of economically recoverable crude oil and conventional natural gas reserves and the future net cash flow therefrom are based upon a number of variable factors and assumptions, such as product prices, future operating and capital costs, historical production from the properties and the effects of regulation by government agencies, including with respect to royalty payments, all of which may vary considerably from actual results. The Company uses all available information at the effective date of the evaluation and internal qualified reserves evaluators to prepare the reserves estimates. As required by NI 51-101, the Company obtains the opinion of an independent reserves auditor on the Company’s reserves. The audit covers more than 75% of the future net revenue discounted at 10% attributable to proved plus probable reserves with the remainder reviewed by the independent qualified reserves auditor. However, given the best technical information and evaluation techniques, all such estimates are still to some degree uncertain. All reserves estimates involve a degree of ambiguity and, at times, rely on indirect measurement techniques to estimate the size and recoverability of the resource. While new technologies have increased the accuracy of these techniques, there remains the potential for human or systemic error in recording and reporting the magnitude of the Company’s oil and gas reserves. Estimates of the economically recoverable oil and gas reserves attributable to any particular property or group of properties, and estimates of future net revenues expected therefrom, may differ substantially from actual results even though the total company reserves are shown to be reliable through the historical total company technical reserves revisions. The Company has a diverse portfolio of assets by product type, reservoir type and location which is a factor in mitigating specific property risks.

Restricted Market Access and Pipeline Interruptions

The Company’s results of operations and financial condition depend upon the Company’s ability to deliver products to the most attractive markets. The Company’s results of operations could be materially adversely affected by restricted market access resulting from a lack of pipeline or other transportation alternatives to attractive markets as well as regulatory and/or other marketplace barriers. Interruptions and restrictions may be caused by the inability of a pipeline to operate, or they can be related to capacity constraints as the supply of feedstock into the system exceeds the infrastructure capacity. If oil production across North America experiences growth, the availability of infrastructure to carry the Company’s products to the marketplace may be restricted in the next few years. Restricted market access may potentially have a material adverse effect on the Company’s results of operations, financial condition and business strategy. Unplanned shutdowns and closures of its refineries or Upgrader may limit the Company’s ability to deliver product with a material adverse effect on sales and results of operations.

Aviation Incidents

The Company’s Offshore operations in Canada and China rely on regular travel by helicopter. A helicopter incident resulting in loss of life, facility shutdown or regulatory action could have a material adverse effect on the operations of the Company. This risk is managed through an aviation management process. Aviation Safety Reviews are conducted by third party specialist contractors to verify that helicopter service providers meet the Company’s and industry standards with respect to aviation safety. The reviews include evaluation of aircraft type, effectiveness of the safety and maintenance management systems and competency and training programs for critical roles in the operation of helicopters. Helicopters chartered to support Husky Offshore operations must be fit for service and as such are fitted with multiple redundant systems to address a wide range of potential in-flight emergencies. Additional measures specific to the Company’s challenging operating environments are specified in the Company’s design requirements including anti- icing and floatation systems effective for the maximum allowable sea height operating limits. Pilots are trained to address potential emergency situations through regular real-time and simulator training aligned with industry best practice.

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Security and Terrorist Threats

Security threats and terrorist or activist activities may impact the Company’s personnel, which could result in injury, death, extortion, hostage situations and/or kidnapping, including unlawful confinement. A security threat, terrorist attack or extremist incident targeted at a facility, office or offshore vessel/installation owned or operated by the Company could result in the interruption or cessation of key elements of the Company’s operations. Outcomes of such incidents could have a material adverse effect on the Company’s results of operations, financial condition and business strategy. The risk to employees and board members due to ongoing social unrest in Hong Kong is being managed through reduced travel and increased awareness and monitoring of the situation. The potential for detention and/ or incarceration of the Company’s employees/contractors entering or working in China remains, and as a result, review and reconsideration for travel into China has become a business/corporate process.

The Company does not own proved or probable reserves in or near areas of armed conflict. According to the Uppsala Conflict Data Program, armed conflict is defined as “contested incompatibility that concerns government and/or territory over which the use of armed force between the military forces of two parties, of which at least one is the government of a state, has resulted in at least 25 battle-related deaths each year.”

Skilled Workforce Attraction and Retention

Successful execution of the Company’s strategy is dependent on ensuring the Company’s workforce possesses the appropriate skill level. Failure to attract and retain personnel with the required skill levels could have a material adverse effect on the Company’s financial condition and results of operations.

Partner Misalignment

Joint venture partners operate or jointly control a portion of the Company’s assets in which the Company has an ownership interest. This can reduce the Company’s control and ability to manage risks. The Company is at times dependent upon its partners for the successful execution of various projects. If a dispute with partners were to occur over the development and operation of a project or if partners were unable to fund their contractual share of the capital expenditures, a project could be delayed and the Company could be partially or totally liable for its partner’s share of the project.

Major Project Execution

The Company manages a variety of oil and gas projects ranging from upstream to downstream assets across its global portfolio. The wide range of risks associated with project development and execution, as well as the commissioning and integration of new facilities with existing assets, can impact the economic viability of the Company’s projects. Project risks may result in extended stakeholder consultation, additional environmental assessments and public hearings which may delay necessary environmental and regulatory approvals. Project risks may also manifest through schedule delays, cost overruns and commodity price drops. Some risks can impact the Company’s safety and environmental records thereby negatively affecting the Company’s reputation and social license to operate.

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Government Regulation

Given the scope and complexity of the Company’s operations, the Company is subject to regulations and interventions by governments at the federal, provincial, state and municipal levels in the countries in which it conducts its operations, or development or exploratory activities. As these governments continually balance the needs of the community for economic growth with Indigenous interests and stakeholders, the Company recognizes that the magnitude of regulatory risks has the potential to change over time. Changes in government policy, legislation or regulations could impact the Company’s existing and planned projects as well as impose costs of compliance and increase capital expenditures and operating expenses. Examples of the Company’s regulatory risks include, but are not limited to, uncertain or negative interactions with governments, uncertain energy policies, uncertain climate policies, uncertain environmental and safety policies, penalties, taxes, royalties, government fees, reserves access, limitations or increases in costs relating to the exportation of commodities, production restrictions, restrictions on the acquisition of exploration and production rights and land tenure, expropriation or cancellation of contract rights, limitations on control over the development and abandonment of fields and loss of licences to operate.

Environmental Risks

Changes in environmental regulations could have a material adverse effect on the Company’s results of operations, financial condition and business strategy by requiring increased capital expenditures and operating costs or by impacting the quality of, formulation of or demand for the Company’s products, which may or may not be offset through market pricing.

The Company anticipates that further changes in environmental legislation could occur, which may result in stricter standards and enforcement, larger fines and liabilities, the introduction of emissions limits, increased compliance costs and approval delays for critical licences and permits. Public and investment community interest in ESG issues has also increased significantly in recent years, as evidenced by the large number of signatories to the United Nations Principles for Responsible Investment.

It is not possible to accurately forecast the amount of additional investment in new or existing facilities required in the future for environmental protection or to address all new regulatory compliance requirements, such as reporting. See “Environmental, Social and Governance Considerations - Environmental Protection”.

Climate Change Risks

Regulatory

Climate change regulations may become more onerous over time as governments implement policies to further reduce GHG emissions. As these regulations continue to evolve, they could have a material adverse effect on the Company’s competitiveness, financial condition and results of operations through increased capital and operating costs and change in demand for refined products such as transportation fuels. Costs associated with levy payments for emerging climate change regulations may be significant. In December 2020, the Government of Canada released a new carbon tax pricing schedule with annual increases of $15/tonne CO₂e per year beginning in 2023 (previously $10/tonne CO₂e annual increase) resulting in pricing of $65/tonne CO₂e for 2023 increasing to $170/tonne in 2030.

In December 2018, the Government of Canada published the Regulatory Design Paper on the CFS that focuses on the liquid fuel stream regulations. The final regulations for liquid fuels are planned for early 2021, with the regulations expected to come into force in 2022. In December 2020, the Canadian government announced it would not be going forward with legislation on the gaseous and solids streams of the CFS.

The Company’s U.S. Refining business could be exposed to increased costs related to U.S. federal GHG legislation/regulation that applies to the oil and gas industry, or consumption of petroleum products, or other legislation/regulation at the state or local level. Such legislation or regulations could require the Company’s U.S. Refining operations to significantly reduce emissions and/or purchase emissions credits, thereby increasing operating and capital costs, and could change the demand for refined products which may have a material adverse effect on the Company’s financial condition.

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The Company complies with the RFS program in the U.S. by blending renewable fuels manufactured by third parties and by purchasing RINs on the open market. Due to regulatory uncertainty and in part due to the U.S. fuel supply reaching the “blend wall” (the 10% limit prescribed by most automobile warranties), the price and availability of RINs have been volatile. The Company cannot predict the future prices of RINs and renewable fuel blendstocks, and the costs to obtain the necessary RINs and blendstocks could be material. The Company’s financial position and results of operations could be adversely affected if it is unable to pass the compliance costs on to its customers and if the Company pays significantly higher prices for RINs or blendstocks to comply with the RFS mandated standards.

See “Environmental, Social and Governance Considerations - Climate Change.”

Climatic Conditions

Extreme climatic conditions may also have material adverse effects on the Company’s financial condition and results of operations. Weather and climate affect demand, and therefore, the predictability of the demand for energy is affected to a large degree by the predictability of weather and climate. In addition, the Company’s exploration, production and construction operations, and the operations of major customers and suppliers, can be affected by extreme weather. This may result in cessation or diminishment of production, delay of exploration and development activities or delay of plant construction.

The Company operates in some of the harshest environments in the world, including offshore NL. Climate change may increase the frequency of severe weather conditions in these locations including winds, flooding and variable temperatures, which are contributing to the melting of northern ice and increased creation of icebergs. Icebergs off the coast of NL may threaten Atlantic oil production facilities, cause damage to equipment and possible production disruptions, spills, other asset damage and human impacts.

Transition

In addition to emissions regulations and the physical risks of climate change, climate-related transition risks could have a material adverse effect on the Company’s business, financial condition and results of operations, and could adversely impact the Company’s reputation. For example, increased opposition to companies in the oil sands industry could lead to constrained access to insurance, liquidity and capital and changes in demand for the Company’s products, which may impact revenue. Any increases in GHG emissions by the Company could lead to additional taxes and levies, which would increase the costs associated with certain projects. The potential need to develop new technologies to reduce the intensity of GHG emissions could require significant capital investment. Further, the Company may become subject to climate change litigation initiated by third parties. The Company’s management monitors these risks and reports to the Board through management’s Enterprise Risk Management framework.

Overall, the Company is not able to estimate at this time the degree to which climate change related regulatory, climatic conditions, and transition risks could impact the Company’s financial and operating results.

Cybersecurity Threats

As an oil and gas producer, the Company’s ability to operate effectively is dependent upon developing and maintaining information systems and infrastructure that support the financial and general operating aspects of the business. Concurrently, the oil and gas industry has become the subject of increased levels of cybersecurity threats.

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The Company has security measures, policies and controls designed to protect and secure the integrity of its information technology systems. The Company takes a proactive approach by continuing to invest in technology, processes and people to help minimize the impact of the changing cyber landscape and enhance the Company’s resilience to cyber incidents. However, cybersecurity threats frequently change and require ongoing monitoring and detection capabilities. Such cybersecurity threats include unauthorized access to information technology systems due to hacking, viruses and other causes for purposes of misappropriating assets or sensitive information, corrupting data or causing operational disruption. Cyber attacks could result in the loss or exposure of confidential information related to retail credit card information, personnel files, exploration activities, corporate actions, executive officer communications and financial results. The significance of any such event is difficult to quantify, but if the breach is material in nature, it could adversely affect the financial performance of the Company, its operations, its reputation and its standing and expose it to regulatory consequences and claims of third-party damage, all of which could materially adversely affect the Company’s results of operations and financial condition if the situation is not resolved in a timely manner, or if the financial impact of such adverse effects is not alleviated through insurance policies.

Although to date the Company has not experienced any material losses relating to cyber attacks or other information security breaches, there can be no assurance that the Company will not incur such losses in the future. The Company’s risk and exposure to these matters cannot be fully mitigated because of, among other things, the evolving nature of these threats. The Audit Committee has oversight of the Company’s risk mitigation strategies related to cybersecurity.

International Operations

International operations can expose the Company to uncertain political, economic and other risks. The Company’s operations in certain jurisdictions may be materially adversely affected by political, economic or social instability or events. These events may include, but are not limited to, onerous fiscal policy, renegotiation or nullification of agreements and treaties, imposition of onerous regulation, changes in laws governing existing operations, financial constraints, including currency restrictions and exchange rate fluctuations, unreasonable taxation and behaviour of public officials, joint venture partners or third-party representatives that could result in lost business opportunities for the Company. This could materially adversely affect the Company’s interest in its foreign operations, results of operations and financial condition.

Litigation, Administrative Proceedings and Regulatory Actions

The Company may be subject to litigation, claims, administrative proceedings and regulatory actions, which may be material. Such claims could relate to environmental damage, climate change and the impacts thereof, failure to comply with applicable laws and regulations, breach of contract, tax, bribery and employment matters, which could result in an unfavourable decision, including fines, sanctions, monetary damages, temporary suspensions of operations or the inability to engage in certain operations or transactions. The outcome of such claims can be difficult to assess or quantify and may have a material adverse effect on the Company’s reputation, financial condition and results of operations. The defence to such claims may be costly and could divert management’s attention away from day-to-day operations.

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Foreign Currency

The Company’s results are affected by the exchange rates between various currencies including the Canadian and U.S. dollars. The majority of the Company’s expenditures are in Canadian dollars while most of the Company’s revenues are received in U.S. dollars from the sale of oil and gas commodities that receive prices determined by reference to U.S. benchmark prices. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease the revenues received from the sale of oil and gas commodities. Correspondingly, a decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of oil and gas commodities. In addition, a change in the value of the Canadian dollar against the U.S. dollar will result in an increase or decrease in the Company’s U.S. dollar-denominated debt and related interest expense, as expressed in Canadian dollars. The fluctuations in exchange rates are beyond the Company’s control and could have a material adverse effect on the Company’s results of operations and financial condition.

The Company enters into short-dated foreign exchange contracts to fix the exchange rate for conversion of U.S. dollar denominated revenue to hedge against these potential fluctuations. The Company also designates its U.S. denominated debt as a hedge of the Company’s net investment in selected foreign operations with a U.S. dollar functional currency.

Interest Rate

Interest rate risk is the impact of fluctuating interest rates on financial condition. In order to manage interest rate risk and the resulting interest expense, the Company mitigates some of its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt through the use of its credit facilities and various financial instruments. The optimal mix maintained will depend on market conditions. The Company may also enter into interest rate swaps from time to time as an additional means of managing current and future interest rate risk.

Counterparty Credit

Credit risk represents the financial loss that the Company would suffer if the Company’s counterparties in a transaction fail to meet or discharge their obligation to the Company. The Company actively manages this exposure to credit and contract execution risk from both a customer and a supplier perspective. Internal credit policies govern the Company’s credit portfolio and limit transactions according to a counterparty’s and a supplier’s credit quality. Counterparties for financial derivatives transacted by the Company are generally major financial institutions or counterparties with investment grade credit ratings.

Liquidity

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. The Company’s process for managing liquidity risk includes ensuring, to the extent possible, that it has access to multiple sources of capital including: cash and cash equivalents, cash from operating activities, undrawn credit facilities and capacity to raise capital from various debt and equity capital markets under its shelf prospectuses. The availability of capital under its shelf prospectuses is dependent on market conditions at the time of sale.

Debt Covenants

The Company’s credit facilities include financial covenants, which contain a consolidated debt to total capitalization covenant. If the Company does not comply with the covenants under these credit facilities, there is a risk that repayment could be accelerated.

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Competition

The energy industry is highly competitive with respect to gaining access to the resources required to increase oil and gas reserves and production, and gaining access to markets. The Company competes with others to acquire prospective lands, retain drilling capacity and field operating and construction services, obtain sufficient pipeline and other transportation capacity, gain access to and retain adequate markets for its products and services and gain access to capital markets. The Company’s ability to successfully complete development projects could be materially adversely affected if it is unable to acquire economic supplies and services due to competition. Subsequent increases in the cost of or delays in acquiring supplies and services could result in uneconomic projects. The Company’s competitors comprise all types of energy companies, some of which have greater resources.

Credit Rating Risk

Credit ratings affect the Company’s ability to obtain both short-term and long-term financing and the cost of such financing. Additionally, the ability of the Company to engage in ordinary course derivative or hedging transactions and maintain ordinary course contracts with customers and suppliers on acceptable terms depends on the Company’s credit ratings. A reduction in the current rating on the Company’s debt by one or more of its rating agencies, particularly a downgrade below investment grade ratings, or a negative change in the Company’s ratings outlook could materially adversely affect the Company’s cost of financing and its access to sources of liquidity and capital. Credit ratings are intended to provide investors with an independent measure of credit quality of any issuer of securities. The credit ratings accorded to the Company’s securities by the rating agencies are not recommendations to purchase, hold or sell the securities in as much as such ratings do not comment as to market price or suitability for a particular investor. Any rating may not remain in effect for any given period of time or may be revised or withdrawn entirely by a rating agency in the future if in its judgment circumstances so warrant.

General Economic Conditions

General economic conditions may have a material adverse effect on the Company’s results of operations and financial condition. A decline in economic activity will reduce demand for petroleum products and adversely affect the price the Company receives for its commodities. The Company’s cash flow could decline, assets could be impaired, future access to capital could be restricted and major development projects could be delayed or abandoned.

Cost or Availability of Oil and Gas Field Equipment

The cost or availability of oil and gas field equipment may adversely affect the Company’s ability to undertake exploration, development and construction projects. The oil and gas industry is cyclical in nature and is prone to shortages of supply of equipment and services including drilling rigs, geological and geophysical services, engineering and construction services and construction materials. These materials and services may not be available when required at reasonable prices. Without compromising safety, overall quality and environmental impacts, the Company continually develops its approved suppliers base to provide undisrupted access to materials, equipment and services, while maintaining a competitive cost baseline via cost escalation mitigation strategies.

Financial Controls

While the Company has determined that its disclosure controls and procedures and internal controls over financial reporting are effective, such controls can only provide reasonable assurance with respect to financial statement preparation and disclosure. Failure to prevent, detect and correct misstatements could have a material adverse effect on the Company’s results of operations and financial condition.

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Possible Failure to Realize Anticipated Benefits of the Cenovus Transaction

Cenovus and Husky completed the Cenovus Transaction to create an integrated energy leader and realize certain benefits including, among other things, potential synergies and cost savings. Achieving the benefits of the Cenovus Transaction depends in part on successfully consolidating functions and integrating operations, procedures and personnel in a timely and efficient manner, as well as the combined company’s ability to realize the anticipated growth opportunities and synergies from integrating the respective businesses of Cenovus and Husky following completion of the Cenovus Transaction.

Achieving the benefits of the Cenovus Transaction also depends on the ability of the combined company to effectively capitalize on its scale, scope and leadership position in the oil sands and wider oil and natural gas industry, to realize the anticipated capital and operating synergies, to profitably sequence the growth prospects of its asset base and to maximize the potential of its improved growth opportunities and capital funding opportunities as a result of combining the businesses and operations of Cenovus and Husky.

The integration of the Cenovus and Husky assets will require the dedication of substantial management effort, time and resources which may divert management’s focus and resources from other strategic opportunities and from operational matters. The integration process may result in the loss of key employees and the disruption of ongoing business and employee relationships that may adversely affect the combined company’s ability to achieve the anticipated benefits of the Cenovus Transaction. A variety of factors, including those other risk factors set forth in this AIF may adversely affect the ability to achieve the anticipated benefits of the Cenovus Transaction.

Entry into New Business Activities

Completion of the Cenovus Transaction has resulted in a combination of the business activities previously carried on by each of Husky and Cenovus as separate entities. The combination of these activities into the combined company may expose shareholders to different business risks than those to which they were exposed prior to the completion of the Cenovus Transaction. As a result of the changing risk profile of the companies, the combined company may be subject to review of its credit ratings, which may result in a downgrade or negative outlook being assigned to the combined company.

Most operational and strategic decisions and certain staffing decisions with respect to integration have not yet been made. These decisions and the integration of the two companies will present challenges to management, including the integration of systems, policies and personnel of the two companies which may be geographically separated, unanticipated liabilities and unanticipated costs. It is possible that the integration process could result in the loss of key employees, the disruption of the respective ongoing businesses or inconsistencies in standards, controls, procedures and policies that adversely affect the ability of management to maintain relationships with customers, suppliers, employees and other constituencies or to achieve the anticipated benefits of the Cenovus Transaction. The performance of the combined company’s operations could be adversely affected if the combined company cannot retain key employees to assist in the integration and operation of Husky and Cenovus.

Any inability of management to successfully integrate the operations could have a material adverse effect on the business, financial condition and results of operations of the combined company.

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Ongoing Impacts of the COVID-19 Pandemic

The recent COVID-19 pandemic, and actions taken, and that may be taken, by governmental authorities in response thereto, have resulted and may continue to result in, among other things: increased volatility in financial markets and foreign currency exchange rates; disruptions to global supply chains; adverse effects on the health and safety of the Company’s workforce, or guidelines or restrictions to protect health and safety of such workforces, rendering employees unable to work or travel; temporary operational restrictions; and an overall slowdown in the global economy. In particular, the COVID-19 pandemic has resulted in, and may continue to result in, a reduction in the demand for, and prices of, commodities that are closely linked to the Company’s financial performance, including crude oil, refined petroleum products (such as jet fuel, diesel and gasoline), natural gas and electricity, and also increases the risk that storage for crude oil and refined petroleum products could reach capacity in certain geographic locations in which the Company operates. A prolonged period of decreased demand for, and prices of, these commodities, and any applicable storage constraints, could also result in the Company voluntarily curtailing or shutting in production and a decrease in the Company’s refined product volumes and refinery utilization rates, which could adversely impact the Company’s business, financial condition and results of operations.

The COVID-19 pandemic continues to rapidly evolve and its effect on supply and demand patterns is expected to result in negative impacts on the Company’s business, financial condition and results of operations over the near term. To the extent that the COVID-19 pandemic adversely affects the Company’s business, financial condition and results of operations, it may also have the effect of heightening many of the other risks described in this AIF, such as risks relating to: the Company’s ability to maintain its credit ratings; financing ongoing project development costs, including costs associated with the Company’s joint venture arrangements; meeting the Company’s financial obligations; and otherwise complying with the covenants contained in the agreements that govern the Company’s indebtedness.

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HUSKY EMPLOYEES

The following table shows the number of Husky’s permanent employees as at the dates indicated:

	As at December 31,
	2020		2019		2018
Number of permanent employees		4,600		4,802		5,157

DIVIDENDS

Dividend Amounts

The following table shows the aggregate amount of the dividends declared payable per share in respect of Husky’s last three financial years ended December 31, for the Company’s common shares, Series 1 Preferred Shares, Series 2 Preferred Shares, Series 3 Preferred Shares, Series 5 Preferred Shares and Series 7 Preferred Shares:

	2020		2019		2018
Dividends per Common Share	$	0.16	$	0.50	$	0.40
Dividends per Series 1 Preferred Share	$	0.60	$	0.60	$	0.60
Dividends per Series 2 Preferred Share	$	0.66	$	0.85	$	0.74
Dividends per Series 3 Preferred Share	$	1.17	$	1.13	$	1.13
Dividends per Series 5 Preferred Share	$	1.14	$	1.13	$	1.13
Dividends per Series 7 Preferred Share	$	1.07	$	1.15	$	1.15

On April 29, 2020, the Board reduced the quarterly common share cash dividend to $0.0125 per share from $0.125 per share, as a result of deteriorating market conditions and the Company’s focus on its balance sheet.

Dividend Policy and Restrictions

The declaration and payment of dividends are at the discretion of the Board, which will consider earnings, commodity price outlook, future capital requirements and financial condition of Husky, the satisfaction of the applicable solvency test in Husky’s governing corporate statute, the ABCA and other relevant factors. Upon completion of the Cenovus Transaction, Cenovus holds all of the Company’s common shares, Series 1 Preferred Shares, Series 2 Preferred Shares, Series 3 Preferred Shares, Series 5 Preferred Shares and Series 7 Preferred shares.

Common Share Dividends

The Board has the ability to declare dividends in common shares or in cash.

Series 1 Preferred Share Dividends

Holders of Series 1 Preferred Shares were entitled to receive a cumulative quarterly fixed dividend, payable on the last day of March, June, September and December in each year, of 4.45% annually for the initial period ending March 31, 2016, as and when declared by the Board. Thereafter, the dividend rate resets every five years at a rate equal to the five-year Government of Canada bond yield plus 1.73%. Holders of Series 1 Preferred Shares had the right, at their option, to convert their shares into Series 2 Preferred Shares, subject to certain conditions, on March 31, 2016. In the first quarter of 2016, Husky announced

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it did not intend to exercise its right to redeem the Series 1 Preferred Shares on March 31, 2016. As a result, the holders of the Series 1 Preferred Shares had the right to choose to retain any or all of their Series 1 Preferred Shares and continue to receive an annual fixed rate dividend paid quarterly, or convert, on a one-for-one basis, any or all of their Series 1 Preferred Shares into Series 2 Preferred Shares, and receive a floating rate quarterly dividend. Holders of Series 1 Preferred Shares receive the new fixed rate quarterly dividend applicable to the Series 1 Preferred Shares of 2.404% for the five-year period commencing March 31, 2016 to, but excluding, March 31, 2021. Effective March 31, 2016, Husky had 10,435,932 Series 1 Preferred Shares issued and outstanding. Holders of the Series 1 Preferred Shares will have the opportunity to convert their shares again on March 31, 2021, and on March 31 every five years thereafter as long as the shares remain outstanding.

Series 2 Preferred Share Dividends

Holders of the Series 2 Preferred Shares were entitled to receive a cumulative quarterly floating rate dividend, payable on the last day of March, June, September and December in each year, at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 1.73% as and when declared by the Board. Effective March 31, 2016, Husky had 1,564,068 Series 2 Shares issued and outstanding. Holders of the Series 2 Shares have the right, at their option, to convert their shares into Series 1 Preferred Shares, subject to certain conditions, on March 31, 2021, and on March 31 every five years thereafter as long as the shares remain outstanding.

Series 3 Preferred Share Dividends

Holders of the Series 3 Shares were entitled to receive a cumulative quarterly fixed dividend, payable on the last day of March, June, September and December in each year, of 4.50% annually for the initial period ending December 31, 2019 as declared by the Board. Thereafter, the dividend rate resets every five years at the rate equal to the five-year Government of Canada bond yield plus 3.13%. Holders of Series 3 Shares had the right, at their option, to convert their shares into Series 4 Preferred Shares, subject to certain conditions, on December 31, 2019. In the fourth quarter of 2019, Husky announced it did not intend to exercise its right to redeem the Series 3 Preferred Shares on December 31, 2019. As a result, the holders of the Series 3 Preferred Shares had the right to choose to retain any or all of their Series 3 Preferred Shares and continue to receive an annual fixed rate dividend paid quarterly, or convert, on a one-for-one basis, any or all of their Series 3 Preferred Shares into Series 4 Preferred Shares, and receive a floating rate quarterly dividend. Holders of the Series 3 Preferred Shares will receive the new fixed rate quarterly dividend applicable to the Series 3 Preferred Shares of 4.689% for the five-year period commencing December 31, 2019 to, but excluding, December 31, 2024. Effective December 31, 2019, Husky had 10,000,000 Series 3 Preferred Shares issued and outstanding and no Series 4 Preferred Shares were issued due to conditions for the conversion into Series 4 Preferred Shares not being satisfied. Holders of the Series 3 Preferred Shares will have the opportunity to convert their shares again on December 31, 2024, and on December 31 every five years thereafter as long as the shares remain outstanding.

Series 5 Preferred Share Dividends

Holders of the Series 5 Preferred Shares were entitled to receive a cumulative quarterly fixed dividend, payable on the last day of March, June, September and December in each year, of 4.50% annually for the initial period ending March 31, 2020 as declared by the Board. Thereafter, the dividend rate resets every five years at the rate equal to the five-year Government of Canada bond yield plus 3.57%. Holders of Series 5 Preferred Shares had the right, at their option, to convert their shares into Series 6 Preferred Shares, subject to certain conditions, on March 31, 2020. In the first quarter of 2020, Husky announced it did not intend to exercise its rights to redeem the Series 5 Preferred Shares on March 31, 2020. As a result, the holders of the Series 5 Preferred Shares had the right to choose to retain any or all of their Series 5 Preferred Shares and continue to receive an annual fixed rate dividend paid quarterly, or convert, on a one-for-one basis, any or all of their Series 5 Preferred Shares into Series 6 Preferred Shares, and receive a floating rate quarterly dividend. Holders of the Series 5 Preferred Shares will

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receive the new fixed rate quarterly dividend applicable to the Series 5 Preferred Shares of 4.591% for the five-year period commencing March 31, 2020 to, but excluding March 31, 2025. Effective March 31, 2020, Husky had 8,000,000 Series 5 Preferred Shares issued and outstanding and no Series 6 Preferred Shares were issued due to conditions for the conversion into Series 6 Preferred Shares not being satisfied. Holders of the Series 5 Preferred Shares will have the opportunity to convert their shares again on March 31, 2025, and on March 31 every five years thereafter as long as the shares remain outstanding.

Series 7 Preferred Share Dividends

Holders of the Series 7 Preferred Shares were entitled to receive a cumulative fixed dividend, payable on the last day of March, June, September and December in each year, of 4.60% annually for the initial period ending June 30, 2020 as declared by the Board. Thereafter, the dividend rate resets every five years at the rate equal to the five-year Government of Canada bond yield plus 3.52%. Holders of the Series 7 Preferred Shares had the right, at their option, to convert their shares into Series 8 Preferred Shares, subject to certain conditions, on June 30, 2020 and on June 30 every five years thereafter. In second quarter of 2020, Husky announced it did not intend to exercise its rights to redeem the Series 7 Preferred Shares on June 30, 2020. As a result, the holders of the Series 7 Preferred Shares had the right to choose to retain any or all of their Series 7 Preferred Shares and continue to receive an annual fixed rate dividend paid quarterly, or convert, on a one-for-one basis, any or all of their Series 7 Preferred Shares into Series 8 Preferred Shares, and receive a floating rate quarterly dividend. Holders of the Series 7 Preferred Shares receive the new fixed rate quarterly dividend applicable to the Series 7 Preferred Shares of 3.935% for the five-year period commencing June 30, 2020 to, but excluding, June 30, 2025. Effective June 30, 2020, Husky had 6,000,000 Series 7 Preferred Shares issued and outstanding and no Series 8 Preferred Shares were issued due to conditions for the conversion into Series 8 Preferred Shares not being satisfied. Holders of the Series 7 Preferred Shares will have the opportunity to convert their shares again on June 30, 2025, and on June 30 every five years thereafter as long as the shares remain outstanding.

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DESCRIPTION OF CAPITAL STRUCTURE

Common Shares

Husky is authorized to issue an unlimited number of no par value common shares. The holders of common shares are entitled to receive notice of and attend all meetings of shareholders, except meetings at which only holders of a specified class or series of shares are entitled to vote, and are entitled to one vote per common share held. Holders of common shares are also entitled to receive dividends as declared by the Board on the common shares payable in whole or in part as a stock dividend in fully paid and non-assessable common shares or by the payment of cash. Holders are also entitled to receive the remaining property of Husky upon dissolution in equal rank with the holders of all other common shares.

Preferred Shares

Husky is authorized to issue an unlimited number of no par value preferred shares. The preferred shares as a class have attached thereto the rights, privileges, restrictions and conditions set forth below.

The preferred shares may from time to time be issued in one or more series, and the Board may fix from time to time before such issue the number of preferred shares which is to comprise each series and the designation, rights, privileges, restrictions and conditions attached to each series of preferred shares including, without limiting the generality of the foregoing, any voting rights, the rate or amount of dividends or, the method of calculating dividends, the dates of payment thereof, the terms and conditions of redemption, purchase and conversion if any, and any sinking fund or other provision.

The preferred shares of each series shall, with respect to the payment of dividends and the distribution of assets or return of capital in the event of liquidation, dissolution or winding up of Husky, whether voluntary or involuntary, or any other return of capital or distribution of assets of Husky amongst its shareholders for the purpose of winding up its affairs, be entitled to preference over the common shares of Husky and over any other shares of Husky ranking by their terms junior to the preferred shares of that series. The preferred shares of any series may also be given such other preferences over the common shares of Husky and any other such preferred shares.

If any cumulative dividends or amounts payable on the return of capital in respect of a series of preferred shares are not paid in full, all series of preferred shares shall participate ratably in respect of accumulated dividends and return of capital.

In 2011, Husky issued 12 million Series 1 Preferred Shares and authorized the issuance of 12 million Series 2 Preferred Shares. In 2014, Husky issued 10 million Series 3 Preferred Shares and authorized the issuance of 10 million Series 4 Preferred Shares. In 2015, Husky issued 8 million Series 5 Preferred Shares and 6 million Series 7 Preferred Shares and authorized the issuance of 8 million Series 6 Preferred Shares and 6 million Series 8 Preferred Shares. See “Dividends — Dividend Policy and Restrictions — Series 1 Preferred Share Dividends” and “Dividends — Dividend Policy and Restrictions — Series 2 Preferred Share Dividends” and “Dividends — Dividend Policy and Restrictions — Series 3 Preferred Share Dividends” and “Dividends — Dividend Policy and Restrictions — Series 5 Preferred Share Dividends” and “Dividends — Dividend Policy and Restrictions — Series 7 Preferred Share Dividends”. None of the issued preferred shares is entitled to vote, except in accordance with the provisions of the ABCA.

Husky may, at its option, redeem all or any number of the then outstanding Series 1 Preferred Shares, subject to certain conditions, on March 31, 2021 and on March 31 every five years thereafter. Husky may, at its option, redeem all or any number of the then outstanding Series 2 Preferred Shares, subject to certain conditions, on March 31, 2021 and on March 31 every five years thereafter. Husky may, at its option, redeem all or any number of the then outstanding Series 3 Preferred Shares, subject

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to certain conditions, on December 31, 2024 and on December 31 every five years thereafter. Husky may, at its option, redeem all or any number of the then outstanding Series 5 Preferred Shares, subject to certain conditions, on March 31, 2025 and on March 31 every five years thereafter. Husky may, at its option, redeem all or any number of the then outstanding Series 7 Preferred Shares, subject to certain conditions, on June 30, 2025 and on June 30 every five years thereafter.

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Liquidity Summary

Overview

The following information relating to Husky’s current credit ratings is provided as it relates to Husky’s financing costs, liquidity and operations. Specifically, credit ratings affect Husky’s ability to obtain short-term and long-term financing and the cost of such financing. Additionally, the Company’s ability to engage in certain collateralized business activities on a cost effective basis depends on Husky’s credit ratings. A reduction in the current rating on Husky’s debt by one or more of its rating agencies, particularly a downgrade below investment grade ratings, or a negative change in Husky’s ratings outlook could adversely affect Husky’s cost of financing and its access to sources of liquidity and capital. In addition, changes in credit ratings may affect Husky’s ability to enter, and the associated costs of entering, (i) into ordinary course derivative or hedging transactions, which may require Husky to post additional collateral under certain of its contracts if certain adverse events occur with respect to credit ratings, and (ii) into, and maintaining, ordinary course contracts with customers and suppliers on acceptable terms.

With the announcement of the Cenovus Transaction on October 25, all rating agencies adjusted their ratings opinions.

On October 25, 2020, DBRS Morningstar (“DBRS”) placed Husky’s issuer rating and senior unsecured notes and debentures rating of “BBB(high)”, commercial paper rating of R-2(high) and preferred shares - cumulative rating of Pfd-3(high) Under Review with Negative Implications.

On October 25, 2020, Standard and Poor’s Rating Services (“S&P”) placed Husky’s “BBB” long-term issuer credit and senior unsecured debt rating and P-3(high) preferred share ratings on CreditWatch with Negative Implications.

On October 26, 2020, Moody’s Investor Services (“Moody’s”) placed Husky’s “Baa2” senior unsecured ratings On Review for Downgrade.

As at December 31, 2020, Husky had the following credit ratings:

	S&P	Moody’s	DBRS
Outlook/Trend	On CreditWatch with Negative Implications	On Review for Downgrade	Under Review with Negative Implications
Senior Unsecured Debt	BBB	Baa2	BBB (high)
Series 1 Preferred Shares	P-3(high)		Pfd-3(high)
Series 2 Preferred Shares	P-3(high)		Pfd-3(high)
Series 3 Preferred Shares	P-3(high)		Pfd-3(high)
Series 5 Preferred Shares	P-3(high)		Pfd-3(high)
Series 7 Preferred Shares	P-3(high)		Pfd-3(high)
Commercial Paper			R-2(high)

With the closing of the Cenovus Transaction announced on January 4, 2021, S&P, Moody’s, DBRS and Fitch Ratings (“Fitch”) finalized their rating opinions.

On January 4, 2021, DBRS downgraded Husky’s issuer rating and senior unsecured notes and debentures rating to “BBB” from “BBB (high)”, preferred shares ratings to “Pfd-3” from “Pfd-3 (high)”, and commercial paper to “R-2 (middle)” from “R-2 (high)” and assigned a stable outlook removing the ratings from Under Review with Negative Implications assigned on October 25, 2020.

On January 4, 2021, S&P lowered Husky’s long-term issuer credit and senior unsecured debt rating to “BBB-” from “BBB” and preferred share ratings to “P-3” from “P-3(High)” and assigned a stable outlook, removing the CreditWatch with Negative Implications previously assigned on October 25, 2020.

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On January 4, 2021, Moody’s downgraded Husky’s senior unsecured rating to “Baa3” from “Baa2” and assigned a negative outlook, removing the Under Review assigned on October 26, 2020.

On January 4, 2021, with Husky being a wholly-owned subsidiary of Cenovus, Fitch assigned a “BB+/RR4” rating to Husky’s senior unsecured debt and assigned a positive outlook.

Husky’s preferred shares were exchanged for Cenovus preferred shares pursuant to the Cenovus Transaction and those preferred share ratings have moved to Cenovus. DBRS has also discontinued and withdrawn its rating on Husky’s commercial paper at the request of the Company.

Husky currently has the following credit ratings:

	S&P	Moody’s	DBRS	Fitch
Outlook/Trend	Stable	Negative	Stable	Positive
Senior Unsecured Debt	BBB-	Baa3	BBB	BB+

Credit ratings are intended to provide investors with an independent measure of credit quality of any issuer of securities. The credit ratings accorded to Husky’s securities by the rating agencies are not recommendations to purchase, hold or sell the securities in as much as such ratings do not comment as to market price or suitability for a particular investor. Any rating may not remain in effect for any given period of time or may be revised or withdrawn entirely by a rating agency in the future if, in its judgment, circumstances so warrant. The Company pays an annual fee to S&P, Moody’s and DBRS. Additionally, Husky has paid fees to S&P, Moody’s and DBRS in order to receive ratings for debt or equity instruments upon issuance and for rating evaluation or assessment services in connection with the Cenovus Transaction.

Moody’s

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 Baa by Moody’s is within the fourth highest of nine categories and is assigned to debt securities which are judged 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 2 indicates a ranking in the mid-range of that generic rating category. The modifier 3 indicates a ranking in the lower end of that generic rating category. An “Under Review” outlook indicates a rating is under consideration for change in the near term. A “Negative” outlook indicates a possible rating downgrade over the medium term.

Standard and Poor’s

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. A rating of P-3 (high) by S&P on the Canadian preferred share rating scale is equivalent to a BB+ rating on the long-term credit rating scale. 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 (typically six months to two years). In determining a rating outlook, consideration is given to any changes in the economic and/or fundamental business conditions. A “CreditWatch with Negative Implications” outlook indicates that a rating is placed under special surveillance and may be lowered. A “Stable” outlook indicates that a rating is not likely to change.

DBRS

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(high) by DBRS is within the fourth highest of 10 categories and is assigned

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to debt securities considered to be of adequate credit quality. The capacity for payment of financial obligations is acceptable. 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. Credit ratings on commercial paper are on a short-term debt rating scale that ranges from R-1(high) to D, representing the range of such securities rated from highest to lowest quality. A rating of R-2(high) by DBRS is the fourth highest of 10 categories and is assigned to debt securities considered to be of adequate credit quality. The capacity for the payment of short-term financial obligations as they become due is acceptable. Entities in this category may be vulnerable to future events. The R-1 and R-2 commercial paper categories are denoted by (high), (middle) and (low) designations. DBRS preferred share ratings range from Pdf-1 (highest) to D (lowest). According to the DBRS ratings system, preferred shares rated Pfd-3 are generally of adequate credit quality where protection of dividends and principal is considered acceptable, but 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. An “Under Review with Negative Implications” outlook signals that the rating is likely to be lowered. A “Stable” outlook indicates that a rating is not likely to change.

Fitch

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 considered to be speculative. BB+ ratings 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. A Positive outlook indicates an upward trend on the rating scale. 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.

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MARKET FOR SECURITIES

Husky’s common shares, Series 1 Preferred Shares, Series 2 Preferred Shares, Series 3 Preferred Shares, Series 5 Preferred Shares, and Series 7 Preferred Shares were listed and posted for trading on the TSX under the respective trading symbols “HSE”, “HSE.PR.A”, “HSE.PR.B”, “HSE.PR.C”, “HSE.PR.E” and “HSE.PR.G”. The Series 1 Preferred Shares began trading on the TSX on March 18, 2011. The Series 2 Preferred Shares began trading on the TSX on March 31, 2016. The Series 3 Preferred Shares began trading on the TSX on December 9, 2014. The Series 5 Preferred Shares began trading on the TSX on March 12, 2015. The Series 7 Preferred Shares began trading on the TSX on June 17, 2015.

All of the above-referenced shares were delisted from the TSX at the close of trading on January 5, 2021.

The following table discloses the trading price range and volume of Husky’s common shares traded on the TSX during Husky’s financial year ended December 31, 2020:

	High		Low		Volume (000’s)
January		10.80		8.58		38,621
February		8.96		6.12		48,717
March		6.56		2.21		140,213
April		5.09		3.33		110,891
May		4.44		3.38		102,740
June		6.05		3.83		97,809
July		4.84		3.94		52,629
August		5.00		4.33		39,851
September		4.48		3.02		50,915
October		3.84		2.85		87,486
November		5.89		3.42		53,373
December		6.69		5.18		49,857

The following table discloses the trading price range and volume of the Series 1 Preferred Shares traded on the TSX during Husky’s financial year ended December 31, 2020:

	High		Low		Volume (000’s)
January		12.69		11.16		563
February		11.90		10.00		99
March		10.63		4.10		1,517
April		6.99		4.71		1,000
May		6.51		5.61		152
June		7.54		6.00		185
July		6.88		5.95		211
August		7.25		6.65		168
September		7.19		5.81		212
October		6.70		5.86		286
November		8.42		6.25		481
December		9.71		8.18		615

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The following table discloses the trading price range and volume of the Series 2 Preferred Shares traded on the TSX during Husky’s financial year ended December 31, 2020:

	High		Low		Volume (000’s)
January		12.50		11.49		29
February		12.20		11.10		19
March		11.30		4.28		63
April		6.85		5.00		153
May		6.58		5.71		47
June		7.41		6.06		79
July		7.33		6.11		32
August		7.45		6.56		23
September		7.37		5.76		35
October		6.80		5.78		21
November		8.21		6.34		41
December		9.46		8.28		41

The following table discloses the trading price range and volume of the Series 3 Preferred Shares traded on the TSX during Husky’s financial year ended December 31, 2020:

	High		Low		Volume (000’s)
January		18.25		17.19		412
February		17.80		15.91		143
March		15.96		6.58		498
April		11.51		8.05		630
May		11.50		10.20		267
June		12.00		10.60		126
July		13.49		10.80		158
August		13.81		11.92		410
September		13.85		11.20		151
October		12.97		11.03		353
November		15.46		12.01		451
December		16.78		15.00		322

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The following table discloses the trading price range and volume of the Series 5 Preferred Shares traded on the TSX during Husky’s financial year ended December 31, 2020:

	High		Low		Volume (000’s)
January		19.60		18.70		85
February		19.50		16.61		171
March		17.09		6.89		319
April		12.42		8.01		660
May		11.64		10.50		156
June		12.75		10.99		110
July		14.20		11.05		106
August		14.45		12.66		68
September		14.35		11.60		160
October		13.30		11.05		245
November		16.00		12.60		254
December		17.68		15.33		334

The following table discloses the trading price range and volume of the Series 7 Preferred Shares traded on the TSX during Husky’s financial year ended December 31, 2020:

	High		Low		Volume (000’s)
January		19.45		18.53		54
February		19.31		16.77		139
March		17.24		6.56		331
April		10.89		7.65		689
May		10.76		9.95		174
June		11.50		10.19		186
July		13.45		10.11		167
August		14.00		12.02		55
September		13.88		10.78		67
October		13.00		10.42		283
November		15.30		11.61		379
December		17.20		15.13		393

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DIRECTORS AND OFFICERS

Directors

The following are the names and residences of the directors of Husky as of the date of this AIF, their positions and offices with Husky and their principal occupations for at least the five preceding years. Each director will hold office until the Company’s next annual meeting or until his or her successor is appointed or elected.

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Fok, Canning K. N. (Non-independent) Hong Kong Special Administrative Region	Mr. Fok is an Executive Director and Group Co-Managing Director of CK Hutchison Holdings Limited. Mr. Fok has been a director of Cenovus Energy Inc. since January 2021.
Director since August 25, 2000	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 obtained a Bachelor of Arts degree from St. John’s University, Minnesota in 1974 and a Diploma in Financial Management from the University of New England, Australia in 1976. He has been a member of the Institute of Chartered Accountants in Australia (which amalgamated with the New Zealand Institute of Chartered Accountants to become Chartered Accountants Australia and New Zealand) since 1979 and has been a Fellow of the Chartered Accountants Australia and New Zealand since 2015.
	Board & Committee Memberships (2020)			Meeting Attendance
	Board of Directors			4 of 4	100%
	Publicly Traded Company Directorships		Committee Memberships		Listing Exchange
	CK Hutchison Holding Limited		N/A		Hong Kong
	CK Infrastructure Holdings Limited		N/A		Hong Kong
	Power Assets Holdings Limited		Remuneration Committee		Hong Kong
	HK Electric Investments Limited		Remuneration Committee		Hong Kong
	Hutchison Telecommunications Hong Kong Holdings Limited		Nomination Committee Remuneration Committee		Hong Kong
	Hutchison Telecommunications (Australia) Limited		Governance, Nomination & Compensation Committee (Chairman)		Australia
	Hutchison Port Holdings Management Pte. Limited as trustee manager of Hutchison Port Holdings Trust		N/A		Singapore
	TPG Telecom Limited		N/A		Australia
	Cenovus Energy Inc.		N/A		TSX, New York
	Equity Ownership
	Year	Common Shares	DSUs	Market Value as at December 31 (based on closing price on last trading day of the year)
	2020	255,365	Nil	$1,613,907
Kwok, Eva L. (Independent) British Columbia, Canada	Mrs. Kwok is Chairman, a Director and Chief Executive Officer of Amara Holdings Inc. (a private investment holding company). Mrs. Kwok has been a director of Cenovus Energy Inc. since January 2021. 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.
Member of the Audit Committee	Mrs. Kwok was a Director of Shoppers Drug Mart Corporation from 2004 to 2006 and of the Bank of Montreal Group of Companies from 1999 until March 2009.
Director since August 25, 2000	Mrs. Kwok obtained a Master’s degree in Science from the University of London in 1967.

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	Board & Committee Memberships (2020)			Meeting Attendance
	Board of Directors			4 of 4	100%
	Compensation Committee			3 of 3	100%
	Corporate Governance Committee			3 of 3	100%
	Publicly Traded Company Directorships		Committee Memberships		Listing Exchange
	CK Life Sciences Int’l., (Holdings) Inc.		Remuneration Committee (Chair)		Hong Kong
	CK Infrastructure Holdings Limited		Nomination Committee (Chair)		Hong Kong
	Cenovus Energy Inc.		Human Resources and Compensation Committee Nominating and Corporate Governance Committee		TSX, New York
	Equity Ownership
	Year	Common Shares	DSUs	Market Value as at December 31 (based on closing price on last trading day of the year)
	2020	10,215	149,420	$944,336
Shaw, Wayne E. (Independent) Ontario, Canada	Mr. Shaw is the President of G.E. Shaw Investments Limited (a private investment holding company). Mr. Shaw has been a director of Cenovus Energy Inc. since January 2021. 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.
Member of the Audit Committee	Mr. Shaw holds a Bachelor of Arts degree and a Bachelor of Laws degree, both received from the University of Alberta in 1967. He is a member of the Law Society of Ontario.
Director since August 25, 2000	Board & Committee Memberships (2020)			Meeting Attendance
	Board of Directors			4 of 4	100%
	Audit Committee			4 of 4	100%
	Corporate Governance Committee			3 of 3	100%
	Health, Safety and Environment Committee			2 of 2	100%
	Publicly Traded Company Directorships		Committee Memberships		Listing Exchange
	Cenovus Energy Inc.		Audit Committee Safety, Environment, Responsibility and Reserves Committee		TSX, New York
	Equity Ownership
	Year	Common Shares	DSUs	Market Value as at December 31 (based on closing price on last trading day of the year)
	2020	16,343	58,077	$367,049

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Sixt, Frank J. (Non-independent) Hong Kong Special Administrative Region Chair of the Audit Committee Director since August 25, 2000	Mr. Sixt is an Executive Director, Group Finance Director and Deputy Managing Director of CK Hutchison Holdings Limited. Mr. Sixt has been a director of Cenovus Energy Inc. since January 2021. 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. Mr. Sixt obtained a Master’s degree in Arts from McGill University, Canada in 1978 and a Bachelor’s degree in Civil Law from Université de Montréal in 1978. He is a member of the Bar and of the Law Society of the Provinces of Quebec and Ontario, Canada.
	Board & Committee Memberships (2020)			Meeting Attendance
	Board of Directors			4 of 4	100%
	Compensation Committee			3 of 3	100%
	Publicly Traded Company Directorships		Committee Memberships		Listing Exchange
	CK Hutchison Holding Limited		Sustainability Committee (Chair)		Hong Kong
	CK Infrastructure Holdings Limited		N/A		Hong Kong
	Hutchison Telecommunications (Australia) Limited		Audit & Risk Committee		Australia
	TOM Group Limited		Remuneration Committee		Hong Kong
	TPG Telecom Limited		Governance, Remuneration & Nomination Committee		Australia
	Cenovus Energy Inc.		Nominating and Corporate Governance Committee		TSX, New York
	Equity Ownership
	Year	Common Shares	DSUs	Market Value as at December 31 (based on closing price on last trading day of the year)
	2020	70,190	Nil	$443,601

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Officers

The following are the names and residences of the executive officers of Husky Energy Inc. as of the date of this AIF, their positions and offices with Husky Energy Inc. and their principal occupations for at least the five preceding years.

Name and Residence	Office or Position	Principal Occupation During Past Five Years
Hart, Jeffrey R. Alberta, Canada	Acting Chief Executive Officer & Chief Financial Officer	Executive Vice-President & Chief Financial Officer of Cenovus since January 2021. Chief Financial Officer of Husky from November 2018. Acting Chief Financial Officer of Husky from April 2018 to November 2018. Vice President, Controller of Husky Oil Operations Limited from February 2015 to April 2018.
Dahlin, Andrew Alberta, Canada	Acting Chief Operating Officer	Executive Vice-President, Safety & Operations Technical Services of Cenovus since January 2021. Executive Vice President, Downstream & Midstream of Husky from November 2020. Executive Vice President, Western Canada Upstream of Husky from May 2020 to November 2020. Senior Vice President, Heavy Oil & Oil Sands of Husky Oil Operations Limited from May 2018 to April 2020. Senior Vice President, Heavy Oil of Husky Oil Operations Limited from June 2017 to May 2018. Vice President, Upstream of Husky Oil Operations Limited from April 2012 to May 2017.
Robert M. Hinkel (Hong Kong Special Administrative Region)	Chief Operating Officer, Offshore	Senior Vice-President, Asia Pacific Region of Cenovus since January 2021. Chief Operating Officer, Offshore of Husky since April 16, 2020. Chief Operating Officer, Asia Pacific of Husky Oil Operations Limited from December 2010 to April 2020.
Girgulis, James D. Alberta, Canada	Senior Vice President, General Counsel & Secretary	Senior Vice President, General Counsel & Secretary of Husky since April 2012.

As at February 3, 2021, the directors and executive officers of Husky Energy Inc., as a group, beneficially owned or controlled or directed, directly or indirectly, nil common shares of Husky.

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Conflicts of Interest

The executive officers and directors of Husky may also become officers and/or directors of other companies engaged in the oil and gas business generally and which may own interests in oil and gas properties in which Husky holds or may in the future, hold an interest. As a result, situations may arise where the interests of such directors and officers conflict with their interests as directors and officers of other companies. In the case of the directors, the resolution of such conflicts is governed by applicable corporate laws that require that directors act honestly, in good faith and with a view to the best interests of Husky and, in respect of the ABCA, Husky’s governing statute that directors declare, and refrain from voting on, any matter in which a director may have a conflict of interest.

Corporate Cease Trade Orders or Bankruptcies

None of those persons who are directors or executive officers of Husky is, or has been within the past 10 years, a director, chief executive officer or chief financial officer of any company, including Husky and any personal holding companies of such person that, while such person was acting in that capacity, was the subject of a cease trade or similar order or an order that denied the Company access to any exemption under securities legislation, for a period of more than 30 consecutive days, or after such persons ceased to be a director, chief executive officer or chief financial officer of the Company was the subject of a cease trade or similar order or an order that denied the Company access to any exemption under securities legislation, for a period of more than 30 consecutive days, which resulted from an event that occurred while such person was acting in such capacity.

In addition, none of those persons who are directors or executive officers of Husky is, or has been within the past 10 years, a director or executive officer of any company, including Husky and any personal holding companies of such persons, that while such 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.

Individual Penalties, Sanctions or Bankruptcies

None of the persons who are directors or executive officers of Husky (or any personal holding companies of such persons) has, within the past 10 years, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or were subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold his or her assets.

None of the persons who are directors or executive officers of the Company (or any personal holding companies of such persons) has been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or have entered into a settlement agreement with a securities regulatory authority or been subject to 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.

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EXTERNAL AUDITOR SERVICE FEES

The following table provides information about the fees billed to the Company for professional services rendered by KPMG LLP, the Company’s external auditors, during the fiscal years indicated:

($ thousands)	2020		2019
Audit Fees		3,999		4,133
Audit-related Fees		424		235
Tax Fees		105		283
		4,528		4,651

Audit fees consist of fees for the audit of the Company’s annual financial statements or services that are normally provided in connection with statutory and regulatory filings, including the Sarbanes-Oxley Act of 2002. Audit-related fees included fees for attest services not required by statute or regulation. Tax fees included fees for tax planning and various taxation matters.

The Audit Committee has the sole authority to review in advance, and grant any appropriate pre-approvals of, all non-audit services to be provided by the independent auditors and to approve fees in connection therewith. The Audit Committee pre-approved all of the audit-related and tax services provided by KPMG LLP in 2020.

PRINCIPAL HOLDERS OF VOTING SECURITIES

Cenovus Energy Inc. holds 1,005,121,738 common shares, which represent 100% of the Company’s voting securities.

EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Husky’s Compensation Committee was appointed by the Board to oversee the development and implementation of the Company’s executive compensation program (the “Compensation Program”) and ensure alignment with the delivery of shareholder value. Among its responsibilities, the Compensation Committee reviewed and approved the President & Chief Executive Officer’s compensation recommendations for the Company’s executive officers and also reviewed and monitored the design and competitiveness of major new compensation programs for the Company and its operating subsidiaries. See “Executive Compensation - Compensation Committee Mandate”.

All members of the Compensation Committee had the skills and experience to fulfill their responsibilities and to make decisions on the suitability of the Company’s compensation policies and practices. They developed skills and experience in making executive compensation decisions through leadership positions within large organizations and through serving on compensation committees of other large publicly-traded companies. Their collective experience in handling executive compensation matters was broad in nature and included experience within a diverse range of industries.

Performance in 2020

The Company marked good progress on its goal to become a High Reliability Organization and a global top-quartile safety performer. This was Husky’s primary objective and the Company delivered improvements on several critical metrics, particularly in the reduction of significant process safety incidents. Husky also took a major step forward by setting targets to reduce its carbon intensity, move toward net zero emissions by 2050 and to set gender diversity targets for senior executives positions.

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On the financial front, Husky finished the year with operating costs trending about $400 million below 2019. Capital spending was managed down to $1.65 billion, less than half the original budget of $3.7 billion and net debt was in the range of $5.5 billion. If not for Husky’s swift and aggressive actions on capital and operating costs in early spring 2020, the Company’s debt would have likely exceeded $8.5 billion due to the precipitous drop in prices and margins due to COVID-19 and the global economic fallout. In 2020, Husky maintained its investment-grade credit ratings.

On the operations side, there were many highlights:

• Both Spruce Lake Central and the 29-1 field at Liwan were brought onstream ahead of schedule and under budget.

• Completion of a major turnaround at the Lloyd Upgrader without a single lost-time incident, despite having 3,000 workers on site. At the same time, increasing the diesel capacity at the Upgrader, which improved competitive positioning.

• While work was slowed by COVID-19, the Superior Refinery rebuild has progressed safely.

• The upstream and downstream worked together to continue to optimize value capture in extreme market conditions.

The Compensation Committee’s decisions have been based on the achievement of specific corporate and individual performance-related objectives. The Company’s strategic objectives in 2020 included:

• to rapidly move towards achieving top-quartile process and occupational safety performance;

• to formulate and execute a corporate strategy which maintains a strong balance sheet, while preserving the Company’s growth opportunities;

• to continue to strengthen the core Integrated Corridor and Offshore business by lowering average production and throughput costs while expanding margin capture;

• to ensure strict financial discipline aimed at maintaining a strong balance sheet;

• to create shareholder value through responsible growth and ESG risk management;

• to ensure a robust management succession plan is in place; and

• to identify significant risks to the Company’s businesses and ensure mitigation strategies are established.

All of the factors and results discussed above assisted in the evaluation of individual performance and impacted compensation decisions for 2020, as they formed the basis for the calculation of the corporate multiplier applied to the short-term incentive program. Paying for performance forms the basis for the Company’s compensation objectives and philosophy. 

Compensation Objectives and Philosophy

The Compensation Program was intended to attract, motivate, reward and retain the management talent needed to achieve the Company’s business objectives and create long-term value for shareholders. It consisted of base salary, short-term incentives (annual bonuses) and long-term incentives (performance share units (“PSUs”) and stock options). Based on a pay-for-performance philosophy, it rewarded executive officers on the basis of individual performance and achievement of corporate objectives.

The Board, with the President & Chief Executive Officer, developed a long term strategic plan for the Company. From the long-term plan annual corporate milestones were established and individual performance contracts for each executive officer were set, all with the objective of achieving the long term strategic plan.

Base salary and short-term incentives primarily rewarded executive officers for delivering results on annual milestones, and were important to incentivize executive officers to work towards the common goals of the Company and the shareholders. However, the Compensation Program was designed to contain significant pay at risk, with base salary comprising less than 35% of the target total compensation. The Compensation Program was intentionally more heavily weighted towards performance based elements of compensation.

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Long-term incentive awards focus executive officers to make decisions that not only achieve annual milestones, but also continue to deliver results over the longer term. The long-term incentive program was weighted 80% to a Performance Share Unit Plan (the “PSU Plan”) that with vesting targets aligned with the achievement of corporate measures, including relative total shareholder return (“TSR”) against a pre-defined peer group. The remaining 20% of the long-term incentive award was provided in stock options. Stock options provided value to executive officers with share price appreciation. If the share price appreciated, shareholders saw more value and the compensation of the executive officers increased accordingly. Without share price appreciation, executive officers received less compensation through their long-term incentive plans, thus reinforcing the Company’s pay-for-performance philosophy. The Company elected not to use restricted share units, which carry no performance condition, in order to ensure better alignment with shareholders.

Risk Mitigation

The Compensation Program was designed to provide executive officers incentives for the achievement of near-term and long-term objectives, without motivating them to take unnecessary risk. As part of its review and discussion of the Compensation Program, the Compensation Committee noted the following facts:

• all the directors, including the members of the Compensation Committee, have been regularly apprised of the Company’s financial and operating performance throughout the year and the risk characteristics of corporate decisions;

• executive compensation has been tied to the overall results of the Company, both financial and operational, with consideration given to personal performance as it relates to the bonus award;

• the annual incentive program features capped payouts so as not to encourage excessive risk taking;

• there has been an effective balance, in each case, between cash and equity mix, near-term and long-term focus, corporate and individual performance, and financial and non-financial performance;

• the Company’s approach to performance evaluation and compensation has provided greater rewards to an executive officer achieving both short-term and long-term agreed upon objectives;

• an Anti-Hedging Policy had been adopted (see “Executive Compensation - Executive Equity Compensation Anti-Hedging Policy”);

• a Clawback Policy had been adopted (see “Executive Compensation - Clawback Policy”); and

• a Share Ownership Guideline Policy was implemented effective January 2019 (see “Executive Compensation - Share Ownership Guideline Policy”).

Compensation Governance

Succession Planning

The Compensation Committee was entrusted with the responsibility of overseeing the Company’s succession planning for senior executive officer roles. As part of this process the Compensation Committee reviewed, at least annually, the succession plan for the Company’s senior executive officers. This involved a review of the positions and an evaluation of the qualifications and experience needed to fill these roles. In some instances, internal candidates were identified and evaluated to determine their strengths and areas in need of development. The Compensation Committee reported annually to the Board on the effectiveness of the succession planning processes.

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Compensation Process

The President & Chief Executive Officer recommended to the Compensation Committee the individual compensation packages for the executive officers. The Compensation Committee took these recommendations into consideration when making final decisions on compensation for those executive officers. Compensation decisions regarding the President & Chief Executive Officer were made entirely by the Compensation Committee and were based primarily on the achievement of individual and corporate goals and objectives including long-term strategic objectives.

The Company participated in annual executive compensation surveys (the “Surveys”) conducted by Willis Towers Watson. The Surveys looked at base salaries and other short-term and long-term incentive programs in effect at the Company’s peer companies in Canada and were used, along with the disclosure in such peer companies’ annual management information circulars, as a reference by the Compensation Committee to assess the competitiveness of the Compensation Program. In the case of executive officers, compensation was targeted at the 50^th percentile of the remuneration paid to executive officers who operated in similar business environments and whose positions were of similar capacity, scope and complexity.

The Compensation Committee reviewed the list of the Company’s peer companies to ensure their continued appropriateness. The peer group for 2020 was:

Canadian Natural Resources Limited	Cenovus Energy Inc.	Enbridge Inc.
Imperial Oil Limited	Nutrien Ltd.	Ovintiv Inc. (1)
Pembina Pipeline Corporation	Suncor Energy Inc.	TC Energy Corporation
Teck Resources Limited

⁽¹⁾ Ovintiv Inc. (formerly Encana Corporation) relocated its headquarters to the U.S. in early 2020. Husky did not remove Ovintiv Inc. from its peer group once it was re-domiciled.

In choosing the peer companies, the Compensation Committee selected: (i) commodity-cyclical, resource-based companies with integrated operations; (ii) similarly-sized (as measured by annual revenue) energy companies headquartered or with significant operations in Canada; and (iii) similarly-sized (as measured by assets) capital-intensive companies operating in Canada. The Compensation Committee believed these metrics were appropriate for determining peers because they provided a reasonable point of reference for comparing executive officers with similar positions and responsibilities as well as representing a source of competition for executive talent.

The Company retained Willis Towers Watson to provide specific analysis on executive compensation in respect of the competitiveness of the Company’s compensation practices. The Compensation Committee considered this analysis in making its decisions on all elements of compensation for executive officers.

Executive Compensation External Consultant Fees

The Company continued its engagement of Willis Towers Watson to assist in determining the 2020 compensation for the Company’s directors and executive officers. Willis Towers Watson, which has been retained by the Company since at least 2007, has protocols in place to ensure that it is in a position to provide independent advice. While the Compensation Committee considered the information provided by Willis Towers Watson in making its decisions on all elements of compensation for the Company’s executive officers, the Compensation Committee remained wholly responsible for its own decisions, which may have reflected other considerations.

The following table provides information about the fees billed to the Company for services rendered by Willis Towers Watson during the financial years indicated.

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($)	2020		2019
Executive Compensation-Related Fees		239,724		178,848

Executive Compensation-Related Fees consist of fees for services related to determining compensation for any of the Company’s directors and executive officers. All other fees paid to Willis Towers Watson were $1,772,640 in 2020 and $2,184,632 in 2019 for services related to the review of the Company’s long-term incentive plans, the compilation of compensation market data, comparator peer group development, administrative and actuarial services related to the Company’s pension and benefits plans, corporate risk and broking services and other general management consulting services.

Elements of Compensation

Base Salary

The base salary of each of the Company’s executive officers was determined by the Compensation Committee based on the level of responsibility and the experience of the individual, the relative importance of the position to the Company and the performance of the individual over time. The Compensation Committee believed that a competitive base salary for all employees of the Company was a key factor in achieving and maintaining the Company’s desired competitive positioning in the oil and gas industry.

Short-term Incentive Program

The purpose of the short-term incentive program was to relate a component of compensation directly to the achievement of stated annual objectives from a corporate and individual standpoint. Awards were based on overall performance and each executive officer was assessed on the same consistent basis with bonuses being determined only after the Company’s financial results for the preceding financial year were known. Actual awards received by executive officers may have been higher or lower than the target bonus opportunity depending on the results. With respect to the Named Executive Officers (as defined under “Executive Compensation - Summary Compensation Table”), the target bonus opportunity and range of opportunity in 2020 were as follows:

Position	Target Bonus Opportunity (percentage of base salary)	Corporate Performance Range of Opportunity	Individual Performance Range of Opportunity
President & Chief Executive Officer	125%	50 – 150%	50 – 150%
Chief Financial Officer	75%	50 – 150%	50 – 150%
Chief Executive Officer, Offshore	57%	50 – 150%	50 – 150%
Executive Vice President, Downstream & Midstream	57%	50 – 150%	50 – 150%
Executive Vice President, Western Canada Upstream	48%	50 – 150%	50 – 150%
Chief Operating Officer	80%	50 – 150%	50 – 150%

The Compensation Committee and the President & Chief Executive Officer developed the corporate scorecard, which formed the basis for the calculation of the corporate multiplier for the short-term incentive program. Corporate performance, for the purpose of calculating the short-term incentive corporate multiplier, was determined through the Board’s evaluation of performance of the Company as a whole relative to the annual budget and strategic plan. Specific measures examined included performance against targets for upstream operating unit costs, refinery/upgrading unit costs, production, refinery/upgrading throughput, and reserves replacement.

These metrics were also assessed in relation to performance by the Company’s peers. Targets for these metrics were driven by the economic environment and were aligned with the Company’s overall strategic objectives, including ESG. As Husky believes

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the targets provide competitively sensitive information about its operational strategy, and if disclosed would seriously prejudice its interests, it is relying on the exemption in applicable securities laws from disclosing quantitative targets. As these targets were set based on the budget approved by the Board, there was an expectation by the Compensation Committee that the targets would be met.

Weighting	Metric
50%	Operating Metrics The operating metrics used to assess the financial performance of the Company included net debt, upstream/operating cost, refining/upgrading operating cost and headcount.	Modified by safety factor(1)
30%	Production/Reserves Performance in production took into account the Company’s total production, refinery/upgrading throughput and reserves replacement ratio.
20%	Qualitative Assessment The qualitative assessment was based on certain 2020 commercial achievements and the execution of the Company’s capital and operations plan.

⁽¹⁾ The adjustment factor used to apply the value of process and occupational safety, as well as environmental performance to the bonus program. The factor was a rating between 0.8 and 1.2.

Individual performance for an executive officer was determined against achievement of his or her own specific targets as set out in his or her annual performance contract. Executive officer individual objectives were set to support the corporate scorecard and the Company’s strategic objectives, including ESG. Key performance metrics were identified and targets were set annually in order to gauge the results of actions undertaken by the President & Chief Executive Officer, the other executive officers and the employees generally in executing the Company’s strategic plan. The President & Chief Executive Officer and the Compensation Committee would also evaluate a broad range of qualitative factors, including reliability in delivering financial and growth objectives, a track record of integrity, a good safety record, environmental stewardship, good judgment, the vision and ability to create further growth, the ability to lead others and stewardship through varying economic conditions. This multiplier could vary between 50% and 150%.

Operational safety was expected in the achievement of all of the metrics in the corporate scorecard. To apply the corresponding value of safety to performance, safety did not have its own weighting within the scorecard, but was used as the adjustment factor S to the total overall corporate multiplier as described above.

Long-term Incentive Compensation

To align with short and long-term business performance and shareholder value creation, long-term incentives consisted of a combination of PSUs and stock options. In determining the appropriate long-term incentive fair value granted to the Named Executive Officers (as defined under “Executive Compensation - Summary Compensation Table”), the Compensation Committee considered external market data, as well as other factors such as leadership and talent retention.

In administering long-term incentives for executive officers, the Company granted PSUs and stock options. While PSUs and stock options are both tied to share price, the incentive and retention value of stock options was limited in circumstances where, notwithstanding strong corporate and individual performance, the share price performance was negatively impacted by external factors. Unlike stock options, PSUs continued to provide an incentive for executives to remain with the Company during such periods, continuing to tie compensation to share price performance and comparison to peer company performance. A vested PSU will always have value equal to the share price.

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Granting Process for Share-based and Option-based Awards

In determining the size of individual PSU and stock option grants, the Compensation Committee considered the recommendations of the President & Chief Executive Officer, other than with respect to any PSUs and stock options to be granted to the President & Chief Executive Officer, and considered the aggregate number of common shares available under the Company’s Incentive Stock Option Plan (the “Plan”) and the number of individuals to whom the Company wished to grant PSUs and stock options. The Compensation Committee also considered the range of potential compensation levels that may be yielded by the PSUs and stock options. The Compensation Committee reserved the discretion to consider any factors it considered relevant, including, but not limited to, any previous grants to an executive officer or eligible employee, and to give all factors considered the relative weight it considered appropriate under the circumstances then prevailing, in reaching its determination regarding the size and timing of PSU and stock option grants. PSU and stock option grants to existing eligible employees were made on an annual pre-determined date. Similarly, PSU and stock option grants to newly hired employees and those employees receiving job promotions were made on pre-determined dates during the calendar year.

The Compensation Committee approved the maximum number of PSUs and stock options to be granted for the year, along with the specific PSU and stock option grants for the President & Chief Executive Officer and the other executive officers. The allocations of PSUs and stock options for the annual grant, based on employee level, were approved through the delegation given by the Board to the Compensation Committee. See “Executive Compensation - Long-term Incentive Plans”.

Perquisites and Benefit Plans

Along with all other employees, the executive officers participated in the benefit plans provided by the Company. There were no special benefit plans in place for any of the executive officers. The executive officers could participate in a supplemental pension plan that was available to all employees where Husky contributions exceeded the Income Tax Act (Canada) maximum pension limits. The Company had a 5% savings plan for all employees, including the executive officers. Employees, including executive officers, could direct all or a portion of their contribution to the savings plan to be used to purchase common shares in the market. The executive officers also received a monthly vehicle allowance and paid parking.

Compensation Decisions for 2020

Base Salary

On May 1, 2020, Mr. Hinkel was promoted to Chief Operating Officer, Offshore and Mr. Dahlin was promoted to Executive Vice President, Western Canada Upstream, which resulted in salary increases of 1.5% and 13.6%, respectively. On November 1, 2020, Mr. Dahlin was promoted to Executive Vice President, Downstream & Midstream and Mr. Alexander was promoted to Executive Vice President, Western Canada Upstream. This resulted in a salary increase for Mr. Alexander of 15.1%.

Short-term Incentive Program

Each executive officer’s payment under the short-term incentive program was calculated by applying the executive officer’s target bonus opportunity to salary, modified by the individual performance multiplier and then modified by the corporate multiplier. The 2020 corporate multiplier for the short-term incentive program was determined to be 100%, comprised of a 90% assessment on targeted financial and operational metrics multiplied by a safety factor of 1.1 reflecting significant improvements in safety performance.

The individual performance multiplier for an executive officer was determined against achievement of his or her own specific targets as set out in his or her annual performance contract.

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Long-term Incentive Grants

The following table outlines the number of PSUs and stock options granted in 2020 to the Named Executive Officers. See “Executive Compensation - Summary Compensation Table” for the corresponding valuations of the PSUs and stock options granted.

Named Executive Officer	Number of PSUs granted		Number of stock options granted
Robert J. Peabody		573,000		564,500
Jeffrey R. Hart		169,450		167,100
Robert M. Hinkel		137,510		135,490
Andrew Dahlin		137,510		135,490
Gerald F. Alexander		137,510		135,490
Robert W. P. Symonds		252,100		248,400

Total Cost of Compensation

During the financial year ended December 31, 2020, the aggregate compensation amount for the Named Executive Officers (as defined under “Executive Compensation - Summary Compensation Table”) was $11,209,884.

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Performance Graph

The following performance graph compares the Company’s cumulative TSR on Common Shares over the period from December 31, 2015 to December 31, 2020, assuming a $100 initial investment and the reinvestment of all dividends, with the cumulative TSR on the S&P/TSX Composite Index and on the S&P/TSX Energy Index.

	31-Dec-15		31-Dec-16		31-Dec-17		31-Dec-18		31-Dec-19		31-Dec-20
Husky		100		114		124		101		77		48
S&P/TSX Composite Index		100		118		125		110		131		134
S&P/TSX Energy Index		100		131		118		93		108		75

The Company’s executive officers receive long-term incentives as part of their compensation. The actual value received from long-term incentives by individual executive officers is proportional to any increase (or decrease) in the market price of Husky’s common shares on the TSX. See “Executive Compensation - Compensation Discussion and Analysis - Elements of Compensation - Long-term Incentive Compensation”. In reviewing individual executive officer compensation reported in the Summary Compensation Table, there is a general correlation between market price performance of Husky’s common shares and the total compensation received by the executive officers for the three-year period disclosed in the Summary Compensation Table.

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Summary Compensation Table

The following table details compensation information for the three most recently completed financial years of the Company for the Company’s: President & Chief Executive Officer, Robert J. Peabody; Chief Financial Officer, Jeffrey R. Hart; Chief Operating Officer, Offshore, Robert M. Hinkel; Executive Vice President, Downstream & Midstream, Andrew Dahlin; Executive Vice President, Western Canada Upstream, Gerald F. Alexander and retired Chief Operating Officer, Robert W. P. Symonds (collectively, the “Named Executive Officers”).

									Non-equity incentive plan compensation ($)
Name and principal position	Year		Salary $		Share- based awards ($) (1)		Option- based awards ($) (2)		Annual incentive plans (3)			Long- term incentive plans		Pension value ($) (4)		All other compensation ($) (5)			Total Compensation ($)
Robert J. Peabody President & Chief Executive Officer		2020 2019 2018		1,626,000 1,614,500 1,528,750		1,101,822 3,572,474 3,431,528		249,033 838,556 846,703		1,053,000 1,738,000	(11)		—   —   —		178,860 177,595 168,163		113,675 179,944 171,132			3,269,390 7,436,069 7,884,275
Jeffrey R. Hart(6) Chief Financial Officer		2020 2019 2018		515,000 511,250 385,604		325,835 1,357,353 962,392		73,717 318,646 406,821		386,300 200,000 171,000			—   —   —		56,650 56,238 35,232		50,350 50,852 39,963			1,407,852 2,494,340 2,001,013
Robert M. Hinkel(7) Chief Operating Officer, Offshore		2020 2019 2018		700,710 681,032 646,554		331,103 535,824 540,633		101,515 125,772 219,070		516,478 278,649 386,119			—   —   —		63,064 61,293 58,190		280,355 331,744 351,126			1,993,225 2,014,314 2,201,693
Andrew Dahlin(8) Executive Vice President, Downstream & Midstream		2020 2019 2018		480,000 430,000 395,000		331,103 535,824 570,227		101,515 125,772 241,969		355,300 163,000 194,000			—   —   —		52,800 47,300 43,133		48,638 46,950 45,144			1,369,356 1,348,846 1,489,473
Gerald F. Alexander(9) Executive Vice President, Western Canada Upstream		2020 2019 2018		427,500 407,500 374,450		385,580 428,603 432,484		153,564 100,632 423,553		245,300 139,000 225,000			—   —   —		47,025 44,825 37,964		47,593 46,346 54,119			1,306,562 1,166,906 1,547,570
Robert W. P. Symonds(10) Chief Operating Officer (retired)		2020 2019 2018		541,333 806,250 763,250		484,763 1,571,702 1,422,832		109,583 368,951 576,626		—   —   521,000	(12)		—   —   —		178,417 88,688 83,958		549,400 65,258 63,260	(11)		1,863,497 2,900,847 3,430,924

⁽¹⁾  The accounting grant date fair value of PSUs granted but not vested is based on the number of PSUs multiplied by a valuation ratio of 0.67 and the closing price of Husky’s common shares on the TSX on the grant date of the PSUs. The Company uses this methodology as it is a commonly recognized way of calculating a meaningful and reasonable estimate of fair value. In connection with the Cenovus Transaction, all unvested PSUs became vested and were paid out at a valuation ratio of 1.00.

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⁽²⁾  The Company has calculated the accounting grant date fair value of the options granted to Named Executive Officers using the Black-Scholes model. The Company chose this methodology because it is recognized as the most commonly used methodology of valuing options. The Black-Scholes assumptions used by the Company were:

Assumptions	2018	2019	2020
Initial expected useful life	1.95 years (based on option vest date)	1.95 years (based on option vest date)	1.96 years (based on option vest date)
Expected annual dividend	$0.68 per share (based on option grant date)	$0.53 per share (based on option grant date)	$0.39 per share (based on option grant date)
Volatility	28.40% - 31.40% (range within tranches of March grant)	30.17% - 32.22% (range within tranches of March grant)	39.46% - 42.43% (range within tranches of March grant)
Risk-free interest rate	1.83% - 2.08% (range within tranches of March grant)	1.65% (range within tranches of March grant)	0.51% - 0.68% (range within tranches of March grant)

Mr. Hart also received options on August 15, 2018 and December 17, 2018. Mr. Dahlin and Mr. Hinkel received options on August 11, 2020 and Mr. Alexander received options on November 23, 2020. The values of the August 15, 2018 and December 17, 2018 option grants are based on the following assumptions: initial expected useful life of 1.95 years (both grants); expected annual dividend $0.60 per share, $0.56 per share; volatility 29.10% - 32.22% and 30.09% - 31.51%; risk-free interest rate 2.09% - 2.19%, 1.96% - 1.98%. The values of the August 11, 2020 and November 23, 2020 option grants are based on the following assumptions: initial expected useful life 1.98 years, 1.99 years; expected annual dividend $0.27 per share, $0.21 per share; volatility 51.46% - 55.06% and 53.20% - 55.18%; risk-free interest rate 0.28% - 0.38%, 0.27% - 0.44%.

⁽³⁾  The bonuses disclosed in the table for each year were earned in respect of performance for that year and are paid in the following year.

⁽⁴⁾  Represents contributions the Company has made on behalf of the Named Executive Officers to the Retirement Plan (as defined herein), which consists of a Defined Contribution Pension Plan, a non-registered after-tax account for contributions in excess of the income tax limit (for the years prior to 2019), matching contributions and taxable cash. Mr. Peabody, Mr. Hart, Mr. Symonds, Mr. Dahlin, and Mr. Alexander, participated in the Company’s Defined Contribution Pension Plan. The amounts in the table also include a supplementary pension plan which was introduced effective January 1, 2019 specifically for Husky contributions that are over the Income Tax Act (Canada) pension limits. Husky has maintained a notional account which accumulates with the annual Husky contribution and notional investment income. The notional account is paid out at retirement or when the employee leaves the Company. Employees defer tax until receipt of the notional account. Mr. Hinkel received taxable cash.

⁽⁵⁾  Includes executive officer perquisites (parking, vehicle allowances), unused vacation payouts, location premiums and allowances and employer contributions to Company-sponsored benefits and savings plan programs, with the exception of the Retirement Plan (as defined herein), which is shown under the column “Pension value”. The items included in the column “All other compensation” are paid in cash or are taxable benefits to the Named Executive Officers and therefore the amounts shown are cash costs to the Company. Other than as indicated, the Named Executive Officers did not receive any perquisites, including property or personal benefits not generally available to all employees, that in aggregate were worth $50,000 or more, or were worth 10% or more of the Named Executive Officer’s total salary for the financial year.

⁽⁶⁾  Mr. Hart was appointed Acting Chief Financial Officer on April 5, 2018 and Chief Financial Officer on November 16, 2018. He was previously Vice President, Controller of Husky Oil Operations Limited.

⁽⁷⁾  All figures for Mr. Hinkel were converted from U.S. dollars, the currency in which Mr. Hinkel is paid, to Canadian dollars using the Bank of Canada annual average exchange rate for the applicable year. For the annual averages for 2018, 2019 and 2020, the exchange rates were $1.2957, $1.3269, and $1.3415, respectively.

⁽⁸⁾  Mr. Dahlin was promoted to Executive Vice President, Western Canada Upstream effective May 1, 2020 and to Executive Vice President, Downstream & Midstream effective November 1, 2020.

⁽⁹⁾  Mr. Alexander was promoted to Executive Vice President, Western Canada Upstream effective November 1, 2020.

⁽¹⁰⁾  Mr. Symonds retired effective August 31, 2020.

⁽¹¹⁾  Mr. Peabody’s earned bonus for 2020 was included as part of his retirement package paid in 2021.

⁽¹²⁾  Mr. Symonds’ earned bonus for 2019 was included as part of his retirement package.

Husky Energy Inc. | Annual Information Form 2020 | 104

Incentive Plan Awards

Outstanding Share-based Awards and Option-based Awards

The following table sets forth information in respect of incentive plan awards outstanding at the end of the financial year ended December 31, 2020 held by the Named Executive Officers.

	Option-based Awards							Share-based Awards
Name	Number of securities underlying unexercised options		Option exercise price ($)		Option expiration date	Value of unexercised in-the- money options ($)(1)		Number of PSUs that have not vested(2)		Market or payout value of PSUs that have not vested ($)(3)		Market or payout value of vested PSUs not paid out or distributed ($)
Robert J. Peabody		135,000 317,990 298,300 355,900 564,500		15.67 16.16 17.05 14.39 2.77	May 3, 2021 March 7, 2022 March 8, 2023 March 7, 2024 March 22, 2025		—   —   —   —   1,992,685		1,137,120 —   —   —   —		7,163,856 —   —   —   —		—   —   —   —   —
Jeffrey R. Hart		17,250 28,550 28,550 29,330 82,000 135,240 167,100		15.67 16.16 17.05 21.87 15.57 14.39 2.77	May 3, 2021 March 7, 2022 March 8, 2023 August 14, 2023 Dec 16, 2023 March 7, 2024 March 22, 2025		—   —   —   —   —   —   589,863		366,638 —   —   —   —   —   —		2,309,819 —   —   —   —   —   —		—   —   —   —   —   —   —
Robert M. Hinkel		37,921 84,640 77,180 53,380 84,680 50,810		15.67 16.16 17.05 14.39 2.77 4.66	May 3, 2021 March 7, 2022 March 8, 2023 March 7, 2024 March 22, 2025 August 10, 2025		—   —   —   —   298,920 83,328		223,494 —   —   —   —   —		1,408,012 —   —   —   —   —		—   —   —   —   —   —
Andrew Dahlin		22,500 33,860 33,850 61,750 15,430 53,380 84,680 50,810		15.67 16.16 14.61 17.05 21.87 14.39 2.77 4.66	May 3, 2021 March 7, 2022 August 14, 2022 March 8, 2023 August 14, 2023 March 7, 2024 March 22, 2025 August 10, 2025		—   —   —   —   —   —   298,920 83,328		223,494 —   —   —   —   —   —   —		1,408,012 —   —   —   —   —   —   —		—   —   —   —   —   —   —   —
Gerald F. Alexander		18,980 67,710 61,750 42,710 67,740 67,750		15.67 16.16 17.05 14.39 2.77 4.89	May 3, 2021 March 7, 2022 March 8, 2023 March 7, 2024 March 22, 2025 November 22, 2025		—   —   —   —   239,122 95,528		206,290 —   —   —   —   —		1,299,627 —   —   —   —   —		—   —   —   —   —   —
Robert W. P. Symonds		63,630 162,520 203,150 156,590 165,600		15.67 16.16 17.05 14.39 2.77	May 3, 2021 March 7, 2022 March 8, 2023 June 21, 2023 June 21, 2023		—   —   —   —   584,568		411,653 —   —   —   —		2,593,414 —   —   —   —		—   —   —   —   —

⁽¹⁾  Calculated by subtracting the exercise price of the stock options from the closing price of Husky’s common shares on the TSX on December 31, 2020 ($6.30) and multiplying the amount by the number of Husky’s common shares issuable upon exercise of the options.

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⁽²⁾  Represents the aggregate number of PSUs held as of December 31, 2020.

⁽³⁾  The market or payout value of PSUs that have not vested was determined by multiplying the number of unvested PSUs by the closing price of Husky’s common shares on the TSX on December 31, 2020 ($6.30), which assumes maximum performance. In accordance with the terms of the PSU Plan, actual market or payout value would be equal to the number of vested PSUs multiplied by Husky’s performance factor and by the weighted average trading price of Husky’s common shares on the TSX for the five trading days immediately preceding the vesting date.

Incentive Plan Awards - Value Vested or Earned During the Year

The following table sets forth information in respect of the value of incentive plan awards held by the Named Executive Officers that vested during the Company’s most recently completed financial year.

Name	Option-based awards - Value vested during the year(1) ($)		Share-based awards - Value vested during the year(2) ($)		Non-equity incentive plan compensation - Value earned during the year (3) ($)
Robert J. Peabody		—		751,975	—
Jeffrey R. Hart		—		112,782	386,300
Robert M. Hinkel		—		144,570	516,478
Andrew Dahlin		—		115,276	355,300
Gerald F. Alexander		—		115,670	245,300
Robert W. P. Symonds		—		308,034	—

⁽¹⁾  Represents the aggregate dollar value that would have been realized if the options had been exercised on the vesting date based on the difference between the closing price of Husky’s common shares on the TSX on the vesting date and the exercise price of the options held. Where the vesting date is a weekend or a holiday the most recent closing price immediately prior to the vest date is used.

⁽²⁾  Amounts shown are actual payments of vested PSUs calculated by multiplying the number of units granted by the applicable performance vesting factor by the weighted average trading price of Husky’s common shares on the TSX for the five trading days immediately preceding the applicable vesting date.

⁽³⁾  Amounts shown are corporate bonus payments related to the 2020 performance year. The figure shown for Mr. Hinkel was converted to Canadian dollars using the Bank of Canada 2020 annual average exchange rate of $1.3415. Mr. Peabody’s earned bonus for 2020 was included as part of his retirement package paid in 2021.

Options Exercised during the Year

The following table sets forth information in respect of the number of stock options exercised by the Named Executive Officers and the aggregate value realized upon the exercise of these options during the Company’s most recently completed financial year.

Name	Number of Options exercised (#)		Aggregate Value Realized ($)
Robert J. Peabody		—		—
Jeffrey R. Hart		—		—
Robert M. Hinkel		—		—
Andrew Dahlin		—		—
Gerald F. Alexander		—		—
Robert W. P. Symonds		—		—

Performance Share Unit Grants Vested in 2020

PSUs vest on the second and third anniversary dates of the grant date in percentages determined by the Compensation Committee based on the Company meeting the performance conditions the Compensation Committee set at the time of grant. With respect to the outstanding PSUs in 2020, up to 50% of the granted PSUs would have vested based on the TSR ranking within the Company’s industry peer group, and up to 50% would have vested based on return on capital in use (“ROCIU”) (see “Reader Advisories - Non - GAAP Measures”) targets set by the Company. See “Executive Compensation - Long-term Incentive Plans”.

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Two grants of PSUs vested in 2020. PSUs vest on the second and third anniversary dates, resulting in 60% of the 2017 granted PSUs eligible to vest and 40% of the 2018 granted PSUs eligible to vest.

Pursuant to the terms of the PSU Plan, the calculated performance factor for the second vesting tranche of the 2017 PSU grant was 55.08%, resulting in the following payouts.

Named Executive Officer	PSUs granted in 2017 (#)		PSUs Eligible to vest (60%) in 2020 (#)		Performance Factor			Share Price at time of vest ($)		Payout under 2017 Grant vesting in 2020 ($)
Mr. Peabody		246,800		148,080		55.08	%	$	5.89	$	480,403
Mr. Hart		17,640		10,584		55.08	%	$	5.89	$	34,337
Mr. Hinkel		52,290		31,374		55.08	%	$	5.89	$	101,784
Mr. Dahlin		20,920		12,552		55.08	%	$	5.89	$	40,721
Mr. Dahlin		20,920		12,552		55.08	%	$	4.82	$	33,324
Mr. Alexander		41,840		25,104		55.08	%	$	5.89	$	81,443
Mr. Symonds		100,400		60,240		55.08	%	$	5.89	$	195,431

Pursuant to the terms of the PSU Plan, the calculated performance factor for the first vesting tranche of the 2018 PSU grant was 38.08%, resulting in the following payouts:

Named Executive Officer	PSUs granted in 2018 (#)		PSUs Eligible to vest (40%) in 2020 (#)		Performance Factor			Share Price at time of vest ($)		Payout under 2018 Grant vesting in 2020 ($)
Mr. Peabody		302,700		121,080		38.08	%	$	5.89	$	271,572
Mr. Hart		17,640		7,056		38.08	%	$	5.89	$	15,826
Mr. Hart		18,130		7,252		38.08	%	$	4.82	$	13,311
Mr. Hart		50,660		20,264		38.08	%	$	6.39	$	49,309
Mr. Hinkel		47,690		19,076		38.08	%	$	5.89	$	42,786
Mr. Dahlin		38,150		15,260		38.08	%	$	5.89	$	34,227
Mr. Dahlin		9,540		3,816		38.08	%	$	4.82	$	7,004
Mr. Alexander		38,150		15,260		38.08	%	$	5.89	$	34,227
Mr. Symonds		125,510		50,204		38.08	%	$	5.89	$	112,603

Husky Energy Inc. | Annual Information Form 2020 | 107

Retirement Plan

The Named Executive Officers participated in a Company-sponsored retirement plan (the “Retirement Plan”) made available to all employees. Under the Retirement Plan, the Company contributed a percentage of an employee’s base pay each month into the Company’s defined contribution pension plan, and the employee decided how to invest the funds. The contributions made on behalf of employees varied with years of continuous service with the Company, ranging from 5% to 9% of base salary. Effective January 1, 2018, the Company contributed 9% of base salary for management and senior management personnel regardless of years of service. Also effective January 1, 2018, the Company matched 50% of employee contributions up to 2% of base earnings.

A supplementary pension plan was introduced, effective January 1, 2019, specifically for Husky contributions that were over the Income Tax Act (Canada) pension limits. Husky maintained a notional account which accumulated with the annual Husky contribution and notional investment income. The notional account was to be paid out at retirement or when the employee left the Company. Employees deferred tax until receipt of the notional account. Where applicable, the following table sets forth information in respect of the Company’s defined contribution pension plan payments on behalf of the Named Executive Officers for the Company’s most recently completed financial year. Mr. Peabody, Mr. Hart, Mr. Dahlin and Mr. Alexander were enrolled in the Company’s defined contribution pension plan as of December 31, 2020. Mr. Hinkel received taxable cash.

Name	Accumulated value at start of year ($)		Compensatory ($)(1)		Accumulated value at year end ($)(2)
Robert J. Peabody		283,055		178,860		503,719
Jeffrey R. Hart		230,883		56,650		320,346
Robert M. Hinkel		—		—		—
Andrew Dahlin		147,435		52,800		233,100
Gerald Alexander		147,147		52,290		216,949
Robert W. P. Symonds		196,741		59,547		266,332

⁽¹⁾  Represents contributions to the defined contribution pension plan and supplemental pension (effective January 1, 2019).

⁽²⁾  Includes investment earnings in 2020.

Employment Agreements

All of the Named Executive Officers had Executive Employment Agreements with Husky Oil Operations Limited, the Company’s principal operating subsidiary.

The terms of the Executive Employment Agreements provided that in the event of the termination of the Named Executive Officer by the Company without just cause or by the Named Executive Officer following a change of control, the Named Executive Officer would be entitled to receive a retiring allowance consisting of a lump sum cash amount equal to two times the Named Executive Officer’s base annual salary plus the continuation of all group benefits for a period of 24 months following the termination of employment, or at the Company’s option, in lieu of such continued coverage, an additional cash payment equal to 15% of two times the Named Executive Officer’s base annual salary. In addition, pursuant to the Plan, the Board had the authority to accelerate the vesting of all outstanding options held by the Named Executive Officers.

The total amount that would have been payable under the Executive Employment Agreement to each of the Named Executive Officers as at December 31, 2020, assuming a cash payment in lieu of continued benefit coverage, no accrued and unpaid vacation pay and no acceleration of the vesting of unvested options, is set out in the following table:

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Name	Salary Related ($)		Benefits Related ($)		Total ($)
Robert J. Peabody		3,252,000		487,800		3,739,800
Jeffrey R. Hart		1,030,000		154,500		1,184,500
Robert M. Hinkel(1)		1,408,575		211,286		1,619,861
Andrew Dahlin		1,000,000		150,000		1,150,000
Gerald Alexander		960,000		144,000		1,104,000

⁽¹⁾  Mr. Hinkel is paid in United States dollars. His salary and benefits were converted to Canadian dollars using the Bank of Canada 2020 annual average exchange rate. For the annual average for 2020, the Canadian dollar was at $1.3415.

In the event a Named Executive Officer terminated his Executive Employment Agreement upon a change of control, the Named Executive Officer agreed, at the Company’s option, to continue his employment for a period of up to six months following such termination at his existing compensation package, to assist the Company in an orderly transition of management. The Executive Employment Agreements also contained non-competition and standard confidentiality provisions. The Named Executive Officers agreed: (i) that so long as they were employed by the Company, they were not to engage in any practice or business in competition with the business of the Company or any of its affiliates; (ii) that except with the consent of the Board in writing not to disclose any confidential information to any unauthorized persons whether or not the Named Executive Officer continued to be employed by the Company; and (iii) not to, directly or indirectly, solicit any employee or contract personnel for employment or contract position for a period of 12 months following the expiry or termination of their respective Executive Employment Agreements.

In April 2018, the Company began including an anti-compete clause in its Executive Employment Agreements, with an expectation that such a provision would be incorporated into its Executive Employment Agreements on a go-forward basis. The anti-compete clause prohibited the executive officer from working for any Competing Business within a defined territory for a period of 12 months after leaving the Company. Competing Business was defined as any company contained in the list of industry peer group companies used by Husky’s Compensation Committee to determine PSU payouts, as published in the Company’s most recent management information circular at the time of termination. All of the Named Executive Officers, other than Mr. Dahlin, had signed revised Executive Employment Agreements that included this clause.

Executive Equity Compensation Anti-Hedging Policy

In accordance with the Company’s Company Communications, Disclosure and Insider Trading/Reporting Policy, directors and officers of the Company were not permitted, at any time, to:

• engage in the practice of selling “short” securities of the Company;

• engage in the practice of buying or selling a “call” or “put” or any other derivative security in respect of the securities of the Company; or

• enter into any other short or long-term financial transaction that is designed to hedge or offset any decrease in the market value of the Company’s securities or which could result in profit from a decrease in the market value of the Company’s securities.

Clawback Policy

The Company has in place a Clawback Policy. Pursuant to the Clawback Policy, the Compensation Committee could require that certain key executive officers, as described in the policy, return incentive compensation paid to them if the financial results upon which the awards were based were materially restated due to intentional misconduct or fraud of the executive officer.

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In situations where: (i) the amount of incentive compensation received by an executive officer or former executive officer to whom the policy applies was calculated based or contingent upon the achievement of certain financial results that were subsequently the subject of or affected by a material restatement of all or a portion of the Company’s financial statements; and (ii) the executive officer or former executive officer engaged in intentional misconduct or fraud that caused, or potentially caused, the need for the restatement, as admitted by the executive officer or, in the absence of such admission, as determined by a court of competent jurisdiction in a final judgment that cannot be appealed; and (iii) the incentive compensation payment received would have been lower had the financial statements been properly reported, then the Compensation Committee may, to the extent permitted by applicable laws and to the extent it determines that it is in the Company’s best interest to do so, require reimbursement of the amount by which the after-tax incentive compensation received by such executive officer under the Company’s annual and long-term incentive plans exceeded that which the executive officer would have received had the financial statements not been materially restated.

Share Ownership Guideline Policy

The Company adopted a Share Ownership Guideline Policy effective January 1, 2019. The Share Ownership Guideline Policy required the President & Chief Executive Officer and certain other executive officers to hold a minimum number of common shares of the Company.

President & Chief Executive Officer	2 x base annual salary as at December 31st
All other Named Executive Officers	1 x base annual salary as at December 31st

All designated executive officers for which the Share Ownership Guideline Policy applied had seven years to satisfy the requirement from the date each executive was subject to the Policy.

Compensation Committee Mandate

The Company’s Compensation Committee Mandate provides as follows:

A.    PURPOSE

The Compensation Committee (the “Committee”) is a committee of the Board of Directors (the “Board”) of Husky Energy Inc. (the “Company”). The Committee’s primary function is to assist the Board in carrying out its responsibilities with respect to:

1. determining the general compensation structure and benefit programs for the Company, including that such compensation is linked appropriately to corporate performance;

2. determining compensation of the, President and Chief Executive Officer and senior management, including that such compensation is linked appropriately to corporate performance;

3. setting in advance and evaluating the annual performance objectives for the President and Chief Executive Officer and senior management, and advising the Board in this regard;

4. oversight of the succession planning process for the President and Chief Executive Officer and senior management; and

5. oversight of the Company’s long term incentive planning, including any stock grant, stock option equity linked or similar plan.

B.    COMPOSITION

The Committee will consist of not less than three directors, as determined by the Board, all of whom shall be independent of management.

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Members of the Committee will be appointed annually at a meeting of the Board, on the recommendation of the Corporate Governance Committee to the Co-Chairs, and will be listed in the annual report to shareholders.

Committee members may be removed or replaced at any time by the Board, and will, 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 Committee Chair will be appointed by the Board, on the recommendation of the Corporate Governance Committee to the Co-Chairs.

C.    MEETINGS

The Committee will meet at least once annually at the call of the Chair or any other Committee member, and as many additional times as the Committee deems necessary.

Committee members will strive to be present at all meetings either in person, by telephone or other communications facilities as permit all persons participating in the meeting to hear each other.

A majority of Committee members, present in person, by telephone, or by other permissible communication facilities will constitute a quorum.

The Committee will appoint a secretary who need not be a member of the Committee or a director of the Company. The secretary will keep minutes of the meetings of the Committee. Minutes will be sent to all Committee members, on a timely basis.

D.    AUTHORITY

The Committee has the authority to engage and set the compensation of independent counsel and other advisors, at the Company’s expense, as it determines necessary to carry out its duties.

E.    SPECIFIC DUTIES & RESPONSIBILITIES

The Committee will have the oversight responsibilities and specific duties as described below.

1. Act in an advisory capacity to the Board.

2. Establish industry benchmarks and comparables for the Company’s approach to compensation.

3. Determine the compensation of the President and Chief Executive Officer, subject to the terms of any existing contractual arrangements.

4. After considering the recommendation of the President and Chief Executive Officer, to determine:

(i) the general compensation structure and programs for the Company; and

(ii) the compensation levels for the senior management.

5. Review the Company’s long term incentive plans (including any stock grant, stock option, equity linked or similar plan) and establish, modify or discontinue such plans from time to time as it judges appropriate, and to approve any issuance or allocation under any such plan in relation to any period and the terms thereof.

6. Review and make recommendations to the Board on issues that arise in relation to any employment contracts in force from time to time.

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7. Review benefit programs for salaried personnel, when required.

8. Review and approve severance arrangements for senior management.

9. Deliver the annual report to shareholders on executive compensation required to be included in the information circular for the annual general meeting.

10. Review and report annually to the Board on the effectiveness of the succession planning processes of the Company.

11. Review and monitor the overall employment environment of the Company, looking both internally and externally.

12. Carry out such other responsibilities as the Board may from time to time, set forth.

13. Advise and report to the Co-Chairs of the Board and the Board, relative to the duties and responsibilities set out above, from time to time, and in such detail as is reasonably appropriate.

Long-term Incentive Plans

Performance Share Units

PSUs were aligned with the Company’s pay-for-performance philosophy in that participants received the value of the PSUs only if performance targets were achieved.

Pursuant to the PSU Plan, the Compensation Committee could grant executive officers and eligible employees PSUs based on certain factors, including: (i) the desire to achieve certain corporate performance measures; (ii) compensation data for comparable benchmark positions among the Company’s competitors; (iii) the duties and seniority of the executive officer or eligible employee; (iv) individual and/or departmental contributions and potential contributions to the success of the Company; and (v) such other factors as the Compensation Committee deemed relevant in connection with accomplishing the purposes of the PSU Plan.

PSUs would vest on the second and third anniversary dates of the grant date in percentages determined by the Compensation Committee based on the Company meeting the performance conditions the Compensation Committee set at the time of grant. With respect to the outstanding PSUs in 2020, up to 50% of the granted PSUs would have vested based on the TSR ranking within the Company’s industry peer group, and up to 50% would have vested based on ROCIU targets set by the Company. The PSU Plan provides that ROCIU is defined as net earnings of the Company plus after tax interest expense divided by the two year average capital employed, less any capital invested in assets that are not generating cash flows. Net earnings represent actual net earnings of the Company adjusted for the difference between actual realized and budgeted commodity prices and foreign exchange rates and other actual and budgeted exceptional items.

The industry peer group used by the Compensation Committee consisted of comparable North American based public oil and gas issuers and other issuers for which oil and gas operations were a significant business segment, were competitors of

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the Company and were included in North American equity market energy indices. The peer companies applicable to PSU grants from and after January 1, 2020 for the determination of PSU payouts were:

ARC Resources Ltd.	Canadian Natural Resources Limited
Cenovus Energy Inc.	Chevron Corporation
ConocoPhillips Corp.	Crescent Point Energy
Devon Energy Corporation	Exxon Mobil Corporation
Hess Corp.	Imperial Oil Limited
Marathon Oil Corporation	Murphy Oil Corporation
Occidental Petroleum Corporation	Ovintiv Inc. (1)
Seven Generations Energy Ltd.	Suncor Energy Inc.
Tourmaline Oil Corp.

⁽¹⁾ Ovintiv Inc. (formerly Encana Corporation) relocated its headquarters to the U.S. in early 2020. Husky did not remove Ovintiv Inc. from its peer group once it was re-domiciled.

The performance factor was on a scale, interpolated between the reference points detailed below:

		50%	50%
Performance level achieved	Performance Factor applied at vest date (to # of PSUs eligible to vest)	TSR ranking (against peer companies point over point over two and three years)	ROCIU budget (two and three year averages)
Below threshold	0%	<25th percentile	<Budget -20%
Threshold performance	33.3%	25th percentile	Budget -20%
Target performance	66.6%	50th percentile	Budget
Maximum performance	100%	75th percentile	Budget +20%
Above maximum	100%	>100th percentile	>Budget +20%

Upon vesting, the holder of the PSUs would receive a cash payment equal to the number of PSUs that vested multiplied by the weighted average trading price of the Company’s common shares on the TSX for the five trading days immediately preceding the vesting date less withholding taxes.

The PSUs were non-transferable and, other than in the case of retirement, disability or death, terminated immediately upon the executive officer’s or eligible employee’s termination with or without cause and upon voluntary resignation. Upon termination, all PSUs held and all rights to receive a cash amount thereafter were forfeited by the grantee. Effective September 1, 2018, the Compensation Committee approved an amendment to the PSU Plan to provide in the event of the grantee’s death or retirement PSUs would continue to vest on a prorated basis. The proration was applicable to PSUs granted in the year of death or retirement and was based on the period of active employment starting January 1^st of the year of death or retirement with a minimum of six months worked in that calendar year. In the event of disability, the PSUs held by the grantee would generally continue to vest in accordance with their terms.

Incentive Stock Option Plan

The Plan was designed, through the grant of stock options in the appropriate circumstances, to reward executive officers and key employees in relation to the Company’s common share price performance. The Plan was an integral component of the Company’s total Compensation Program in terms of attracting and retaining key employees and enhancing shareholder value by aligning the interests of executive officers with the growth and profitability of the Company. The longer term focus of this compensation element complemented and balanced the short-term incentive program.

Pursuant to the Plan, the Compensation Committee granted from time to time to executive officers and other eligible employees of the Company (each an “Eligible Person”) options to purchase the Company’s common shares. Stock options were granted to Eligible Persons on an annual basis. Similarly, stock option grants to newly hired employees and those employees receiving job promotions were made on pre-determined dates during the calendar year. Non-executive directors were not Eligible Persons and did not receive stock options.

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The exercise price at which common shares may be purchased pursuant to an option was established at the time such stock option was granted and was the weighted average trading price per common share on the TSX for the five trading days preceding the grant date. The term of each stock option was five years, subject to the Board determining at the time of grant that a particular stock option would have a shorter or longer term, provided that no term was to exceed 10 years. Stock options vested as to one-third on each of the first three anniversary dates of the date of grant of the stock options, subject to the right of the Board to determine, at the time of grant, that particular stock options would be exercisable in whole or in part on earlier dates and to determine, after the grant date, that a particular stock option would be exercisable in whole or in part on earlier dates for any reason, including the occurrence of a proposal by the Company or any other person or company to implement a transaction that would, if implemented, result in a change of control (as defined in the Plan).

Eligible Persons could surrender their stock options to the Company in consideration for the receipt by the Eligible Person of an amount in cash equal to the excess of the aggregate fair market value of the common shares able to be purchased pursuant to the vested and exercisable portion of such stock options on the date of surrender over the aggregate exercise price for those common shares pursuant to those stock options. The fair market value of common shares was calculated as the closing price of the common shares on the date on which board lots of common shares traded immediately preceding the date a holder of the stock options provided notice to the Company that he or she wished to surrender his or her stock options to the Company in lieu of exercise.

The stock options were not assignable and terminated immediately upon the Eligible Person being dismissed from his or her employment for cause or resigning at the request of the Company, or terminated after 90 days upon the Eligible Person resigning his or her office or employment (other than at the request of the Company) or upon being dismissed without cause. Effective September 1, 2018, the Compensation Committee approved an amendment to the Plan to provide that in the event of the Eligible Person’s retirement, stock options would continue to vest on a prorated basis and all vested stock options would have to be exercised within the earlier of 90 days after the last vest date or the expiry date of the stock options. The proration was applicable to stock options granted in the year of retirement and was based on the period of active employment starting January 1^st of the year of retirement, with a minimum of six months worked in that calendar year. Effective November 16, 2018 the Compensation Committee approved an amendment to the Plan to change the vesting of options in the event of death to provide that all unvested options shall vest as of the date of death and may be exercised by the Eligible Person’s personal representatives during the period ending 12 months after the death of the Eligible Person. Shareholder approval was not obtained for the amendments made in 2018 as they were amendments of the nature allowed under the Plan to be made by the Compensation Committee without shareholder approval.

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Director Compensation

Approach to Director Compensation

In designing a compensation program for non-executive directors, the Board’s objective was to ensure that the Company attracted and retained highly qualified, committed and talented members of the Board with an extensive and relevant breadth of experience, as well as to align the interests of directors with those of the shareholders. The effect of the Cenovus Transaction is that the Company became a wholly-owned subsidiary of Cenovus. Effective January 1, 2021, the Board was reconstituted to consist of four directors, being Canning K.N. Fok, Eva L. Kwok, Wayne E. Shaw and Frank J. Sixt. The disclosure in this section relates to the Company’s director compensation practices prior to the completion of the Cenovus Transaction.

The Board set the compensation of non-executive directors based on the Corporate Governance Committee’s recommendations. The Corporate Governance Committee annually reviewed the compensation of non-executive directors and recommended to the Board such adjustments as it considered appropriate and necessary to recognize the workload, time commitment and responsibility of the members of the Board and Board Committees and to remain competitive with director compensation trends in Canada with comparable companies. The Board sets director compensation at the 50th percentile of that paid to directors by comparative oil and gas industry peer companies. The peer group for 2020 is set out below:

Barrick Gold Corporation	Canadian Natural Resources Limited	Cenovus Energy Inc.
Enbridge Inc.	Nutrien Ltd.	Ovintiv Inc. (1)
Suncor Energy Inc.	Teck Resources Limited	TC Energy Corporation

⁽¹⁾ Ovintiv Inc. (formerly Encana Corporation) relocated its headquarters to the U.S. in early 2020. Husky did not remove Ovintiv Inc. from its peer group once it was re-domiciled.

In April 2019, the Corporate Governance Committee recommended, and the Board approved, increasing the compensation of non-executive directors by including an annual equity grant in the form of DSUs. In the event the grant of DSUs was problematic for any individual non-independent director that director can request that the DSUs be paid out in cash. The annual retainer of the Chair of the Audit Committee was also increased from $20,000 to $25,000.

The Company had a Share Accumulation Plan for Directors whereby the directors could elect to have the cash portion of the fees payable to them paid in the form of the issuance of DSUs and/or used to purchase common shares in the market. Directors were able to elect annually whether they wished for their directors’ fees to be so used and could specify a portion of their directors’ fees that were to be used for DSUs and/or the purchase of common shares, with the remaining amount of fees paid in cash. A DSU was a bookkeeping entry that tracked the value of one common share. When cash dividends were paid on common shares, eligible directors were credited with additional DSUs. The number of additional DSUs was calculated by multiplying the cash dividend per common share by the number of DSUs in the director’s account as of the date of record divided by the fair market value of a common share on the payment date of the dividend. DSUs accumulated over a director’s term of service and were not paid out until the director leaves the Board, which provided the director with an ongoing stake in Husky during his or her term of service. When the director left the Board, payment for the DSUs was made in cash or common shares purchased on the open market at the option of the director.

The Company does not have a retirement policy for directors.

The following table sets out the annual fees paid in 2020 to non-executive directors of the Company with no separate meeting attendance fees:

Name & Residence	Annual Retainer (2020)
Director Retainer		$120,000 and $85,000 of DSUs
Chair of Audit Committee		$25,000
Member of Audit Committee		$12,500

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The directors of the Company were also entitled to reimbursement for out-of-pocket expenses for attendance at meetings of the Board and any Board Committees. During the financial year ended December 31, 2020, the directors of the Company earned compensation in the aggregate amount of $3,170,000 ($2,223,492 in cash and $946,508 in DSUs).

The Company does not have any security ownership requirements for directors, as the Company is a wholly-owned subsidiary of Cenovus.

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The following table sets out the compensation paid to directors of the Company consisting of cash and DSUs for the financial year ended December 31, 2020.

											As elected by the director Total Fees received in the form of:
Name	DSUs(1)		Board Retainer ($)		Committee Chair Retainer ($)		Committee Member Retainer Fee ($)		Total Fees ($)		DSUs ($)		Common Shares ($)		Cash ($)
Victor T. K. Li		—		205,000		—		—		205,000		—		—		205,000
Canning K. N. Fok		—		205,000		5,000		—		210,000		—		—		210,000
Stephen E. Bradley		21,773		120,000		—		17,500		222,500		85,000		—		137,500
Asim Ghosh		21,773		120,000		—		5,000		210,000		85,000		—		125,000
Martin J. G. Glynn		21,773		120,000		10,000		17,500		232,500		85,000		—		147,500
Poh Chan Koh		—		205,000		—		—		205,000		—		—		205,000
Eva L. Kwok		21,773		120,000		—		10,000		215,000		215,000		—		—
Stanley T. L. Kwok		21,773		120,000		—		5,000		210,000		85,000		—		125,000
Frederick S. H. Ma		21,773		120,000		6,250		14,375		225,625		85,000		—		143,750
George C. Magnus		21,773		120,000		—		12,500		217,500		85,000		—		132,500
Neil D. McGee		—		205,000		—		5,000		210,000		—		—		210,000
Robert J. Peabody(2)		—		—		—		—		—		—		—		—
Colin S. Russel		21,773		120,000		5,000		17,500		227,500		85,000		—		142,500
Wayne E. Shaw		21,773		120,000		—		22,500		227,500		85,000		—		142,500
William Shurniak		14,481		72,717		15,150		—		139,375		51,508		—		87,867
Frank J. Sixt		—		205,000		2,500		5,000		212,500		—		—		212,500

⁽¹⁾ In the event the grant of the DSU portion of their annual retainer is problematic for any individual non-independent director that director could request that those DSUs be paid out in cash.

⁽²⁾ As an executive office, Mr. Peabody did not receive director fees.

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Outstanding Share-based Awards

The following table sets forth information in respect of incentive plan awards outstanding at the end of the financial year ended December 31, 2020 held by the directors of the Company. Non-executive directors of the Company do not receive option-based awards. The share-based awards were in the form of DSUs that were received in accordance with the Share Accumulation Plan for Directors.

	Share-based Awards
Name	Number of DSUs that have not vested(2)		Market or payout value of DSUs that have not vested ($)(3)
Victor T. K. Li		—		—
Canning K. N. Fok		—		—
Stephen E. Bradley		25,015		158,096
Asim Ghosh		21,875		138,250
Martin J. G. Glynn		47,995		303,330
Poh Chan Koh		—		—
Eva L. Kwok		149,420		944,335
Stanley T. L. Kwok		25,015		158,096
Frederick S. H. Ma		25,015		158,096
George C. Magnus		68,274		431,493
Neil D. McGee		—		—
Robert J. Peabody(1)		—		—
Colin S. Russel		42,440		268,221
Wayne E. Shaw		58,077		367,049
William Shurniak(4)		—		—
Frank J. Sixt		—		—

⁽¹⁾ Information with respect to share-based awards and option-based awards held by Mr. Peabody is included under “Executive Compensation – Incentive Plan Awards – Outstanding Share-based Awards and Option-based Awards”.

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⁽²⁾ Amounts reported include DSUs credited as dividend equivalents.

⁽³⁾ Based on the volume-weighted average price (VWAP) of the common shares on the TSX on December 31, 2020 of $6.32.

⁽⁴⁾ All 17,714 of Mr. Shurniak’s DSUs vested on August 8, 2020.

Value Vested or Earned During the Year

Information with respect to vested option-based awards held by Mr. Peabody is included under “Executive Compensation – Incentive Plan Awards – Incentive Plan Awards – Value Vested or Earned During the Year” for Named Executive Officers (as defined under “Executive Compensation – Summary Compensation Table”). DSUs held by directors do not vest until the director leaves the Board.

In connection with the Cenovus Transaction, all of the directors resigned and all DSUs were paid out.

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY

COMPENSATION PLANS

The following table sets forth information as at December 31, 2020 with respect to the Company’s compensation plans under which equity securities of the Company are authorized for issuance.

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (1)		Weighted-average exercise price of outstanding options, warrants and rights ($)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in first column)
Equity compensation plans approved by security holders		18,883,146	$	12.01		29,549,368
Equity compensation plans not approved by security holders		Nil		N/A		N/A
Total		18,883,146	$	12.01		29,549,368

⁽¹⁾  All outstanding options were transferred to Cenovus effective January 1, 2021 pursuant to the Cenovus Transaction for options to acquire common shares of Cenovus.

LEGAL PROCEEDINGS

The Company is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company’s favour, the Company does not currently believe that the outcome of adverse decisions in any pending or threatened proceedings related to these or other matters or any amount which it may be required to pay by reason thereof would have a material adverse impact on its financial condition, results of operations or liquidity.

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INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

None of the Company’s directors, executive officers or persons or companies that beneficially own or control or direct, directly or indirectly or a combination of both, more than 10% of Husky’s common shares, or their associates and affiliates, had any material interest, direct or indirect, in any transaction with the Company within the three most recently completed financial years or during the current financial year that has materially affected or would reasonably be expected to materially affect the Company.

INTERESTS OF EXPERTS

Certain information relating to the Company’s reserves included in this AIF has been calculated by the Company and audited, reviewed and opined upon as at December 31, 2020 by Sproule. Sproule is an independent petroleum engineering consultant retained by Husky, and such reserves information has been so included in reliance on the opinion and analysis of Sproule, given upon the authority of said firm as experts in reserves engineering. The partners, employees and consultants of Sproule, as a group, beneficially own, directly or indirectly, less than 1% of the Company’s securities of any class.

KPMG LLP are the auditors of the Company and have confirmed that they are independent with respect to the Company within the meaning of the relevant rules and related interpretations prescribed by the relevant professional bodies in Canada and any applicable legislation or regulations and also that they are independent accountants with respect to the Company under all relevant U.S. professional and regulatory standards.

ADDITIONAL INFORMATION

Additional financial information is provided in Husky’s audited consolidated financial statements and management’s discussion and analysis (“MD&A”) for the financial year ended December 31, 2020.

Additional information relating to Husky Energy Inc. is available on the System for Electronic Document Analysis and Retrieval (“SEDAR”) at www.sedar.com and on the Electronic Data Gathering, Analysis, and Retrieval system (“EDGAR”) at www.sec.gov.

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READER ADVISORIES

Forward-looking Statements

Certain statements in this AIF are forward-looking statements and information (collectively “forward-looking statements”), within the meaning of the applicable Canadian securities legislation, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. The forward-looking statements contained in this AIF are forward-looking and not historical facts.

Some of the forward-looking statements may be identified by statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as “will likely result”, “are expected to”, “will continue”, “is anticipated”, “is targeting”, “estimated”, “intend”, “plan”, “projection”, “could”, “aim”, “vision”, “goals”, “objective”, “target”, “schedules” and “outlook”). In particular, forward-looking statements in this AIF include, but are not limited to, references to:

• with respect to the business, operations and results of the Company generally: the Company’s GHG emissions intensity reduction targets; the Company’s gender diversity target; expected effects of abandonment and reclamation costs, development costs and operating costs on anticipated development or production activities on properties with attributed reserves and on properties with no attributed reserves; scheduled timing of development of the Company’s proved and probable undeveloped reserves; expected sources of funding for future development costs; estimates of the forecasted costs of developing the Company’s proved and proved plus probable reserves as at December 31, 2020; the Company’s 2021 production estimates broken down by product type and location; expected spending in 2021 on ARO and environmental site closure activities in North America; anticipated effects of and cost of compliance with certain future or proposed laws and regulations on the Company’s operations; and goal to become a global top-quartile safety performer;

• with respect to the Lloydminster Heavy Oil Value Chain, estimated production and expected timing of first production from the Spruce Lake North project;

• with respect to Oil Sands, the expected timing for production from three additional well pairs at the Sunrise Energy Project; and timing for a scheduled turnaround at the Sunrise Energy Project;

• with respect to U.S. Refining, the scheduled completion for the rebuild of the Superior Refinery; and

• with respect to the Company’s Offshore business in Asia Pacific: the scheduled drilling of five MDA field production wells and two MBH field production wells, and the expected timing of first gas sales therefrom; the expected timing of development and tie-in of the additional MDK shallow water field; and timing for final investment decision for the MAC field development and expected timing for first production if the decision is made to proceed with the development.

In addition, statements relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary from reserve and production estimates.

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Although the Company believes that the expectations reflected by the forward-looking statements presented in this AIF are reasonable, the Company’s forward-looking statements have been based on assumptions and factors concerning future events that may prove to be inaccurate. Those assumptions and factors are based on information currently available to the Company about itself and the businesses in which it operates. Information used in developing forward-looking statements has been acquired from various sources, including third party consultants, suppliers and regulators, among others. The material factors and assumptions used to develop the forward-looking statements include, but are not limited to:

• with respect to the business, operations and results of the Company generally: the absence of significant adverse changes to commodity prices, interest rates, applicable royalty rates and tax laws, and foreign exchange rates; the absence of significant adverse changes to energy markets, competitive conditions, the supply and demand for crude oil, conventional natural gas, NGL and refined petroleum products, or the political, economic and social stability of the jurisdictions in which the Company operates; continuing availability of economical capital resources, labour and services; demand for products and cost of operations; the absence of significant adverse legislative and regulatory changes, in particular changes to the legislation and regulation governing fiscal regimes and environmental issues; and stability of general domestic and global economic, market and business conditions;

• with respect to the Company’s Offshore business in Asia Pacific and Atlantic, upstream operations in the Lloydminster Heavy Oil Value Chain, Oil Sands and Western Canada Production: the accuracy of future production rates and reserve estimates; the securing of sales agreements to underpin the commercial development and regulatory approvals for the development of the Company’s properties; the absence of significant delays in the procurement, development, construction or commissioning of the Company’s projects, for which the Company or a third party is the designated operator, that may result from the inability of suppliers to meet their commitments, lack of regulatory or third-party approvals or other governmental actions, harsh weather or other calamitous event; the absence of significant disruption of operations such as may result from harsh weather, natural disaster, work stoppages related to COVID-19, accident, civil unrest or other calamitous event; the absence of significant unexpected technological or commercial difficulties that adversely affect exploration, development, production, processing or transportation; the sufficiency of budgeted capital expenditures in carrying out planned activities; and the absence of significant increases in the cost of major growth projects; and

• with respect to downstream operations in the Lloydminster Heavy Oil Value Chain, U.S. Refining and Canadian Refined Products: the absence of significant delays in the development, construction or commissioning of the Company’s projects that may result from the inability of suppliers to meet their commitments, lack of regulatory or third-party approvals or other governmental actions, harsh weather or other calamitous event; the absence of significant disruption of operations such as may result from harsh weather, natural disaster, work stoppages related to COVID-19, accident, civil unrest or other calamitous event; the absence of significant unexpected technological or commercial difficulties that adversely affect processing or transportation; the sufficiency of budgeted capital expenditures in carrying out planned activities; and the absence of significant increase in the cost of major growth projects.

Because actual results or outcomes could differ materially from those expressed in any forward-looking statements, investors should not place undue reliance on any such forward-looking statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the predicted outcomes will not occur. Some of these risks, uncertainties and other factors are similar to those faced by other oil and gas companies and some are unique to Husky. The risks, uncertainties and other factors, many of which are beyond

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Husky’s control, that could cause actual results to differ (potentially significantly) from those expressed in the forward-looking statements include, but are not limited to:

• with respect to the business, operations and results of the Company generally: those risks, uncertainties and other factors described under “Risk Factors” in this AIF and throughout the Company’s MD&A for the year ended December 31, 2020; the extent to which COVID-19 impacts the global economy and harms commodity prices; the extent to which COVID-19 impacts our operations; the demand for the Company’s products and prices received for crude oil and conventional natural gas production and refined petroleum products; the economic conditions of the markets in which the Company conducts business; the exchange rate between the Canadian and U.S. dollar; the foreign currency risk relating to gas and liquids sales agreements which are denominated in Chinese Yuan; the ability to replace reserves of oil and gas, whether sourced from exploration, improved recovery or acquisitions; potential actions of governments, regulatory authorities and other stakeholders that may impose operating costs or restrictions in the jurisdictions where the Company has operations; changes to royalty regimes; changes to government fiscal, monetary and other financial policies; changes in workforce demographics; and the cost and availability of capital, including access to capital markets at acceptable rates;

• with respect to the Company’s Offshore business in Asia Pacific and Atlantic, upstream operations in the Lloydminster Heavy Oil Value Chain, Oil Sands and Western Canada Production: the availability of prospective drilling rights; the costs to acquire exploration rights, undertake geological studies, appraisal drilling and project development; the availability and cost of labour, technical expertise, material and equipment to efficiently, effectively and safely undertake capital projects; the costs to operate properties, plants and equipment in an efficient, reliable and safe manner; prevailing climatic conditions in the Company’s operating locations; regulations to deal with climate change issues; the competitive actions of other companies, including increased competition from other oil and gas companies; business interruptions because of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events affecting the Company or other parties whose operations or assets directly or indirectly affect the Company and that may or may not be financially recoverable; the co-operation of business partners especially where the Company is not operator of production projects or developments in which it has an interest; the inability to obtain regulatory approvals to operate existing properties or develop significant growth projects; risk associated with transportation of production or product to market or transportation of feedstock to processing facilities resulting from an interruption in pipeline and other transportation services both owned and contracted, due to calamitous event or regulatory obligation; and the inability to reach estimated production levels from existing and future oil and gas development projects as a result of technological or commercial difficulties; the continued availability of third-party owned equipment for operations; and

• with respect to downstream operations in the Lloydminster Heavy Oil Value Chain, U.S. Refining and Canadian Refined Product: the costs to operate properties, plants and equipment in an efficient, reliable and safe manner; regulatory (environmental, licence to operate, social and political) and prevailing climatic conditions in the Company’s operating locations; regulations to deal with climate change issues; the competitive actions of other companies, including increased competition from other oil and gas companies; business interruptions because of unexpected events such as fires, loss of containment, freeze-ups, equipment failures and other similar events affecting Husky or other parties whose operations or assets directly or indirectly affect the Company and that may or may not be financially recoverable; risk associated with transportation of production or product to market or transportation of feedstock to processing facilities resulting from an interruption in pipeline and other transportation services both owned and contracted, due to calamitous event or regulatory obligation; and the inability to obtain regulatory approvals to operate existing properties or develop significant growth projects.

These and other factors are discussed throughout this AIF and in the MD&A for the year ended December 31, 2020, which is available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov.

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In the discussions above, the Company has categorized the material factors and assumptions used to develop the forward-looking statements, and the risks, uncertainties and other factors that could influence actual results, by region, properties, plays and segments. These categories reflect the Company’s current views regarding the factors, assumptions, risks and uncertainties most relevant to the particular region, property, play or segment. Other factors, assumptions, risks or uncertainties could impact a particular region, property, play or segment, and a factor, assumption, risk or uncertainty categorized under a particular region, property, play or segment could also influence results with respect to another region, property, play or segment.

New factors emerge from time to time and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company’s course of action would depend upon management’s assessment of the future considering all information available to it at the relevant time. Any forward-looking statement speaks only as of the date on which such statement is made and, except as required by applicable securities laws, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.

Non-GAAP Measures

This AIF contains references to the terms “operating netback”, “return on capital in use” and “net debt”, which do not have standardized meanings prescribed by IFRS and are therefore unlikely to be comparable to similar measures presented by other issuers. None of these measures is used to enhance the Company’s reported financial performance or positions. There measures are useful complementary measures in assessing the Company’s financial performance, efficiency and liquidity. With the exception of “net debt”, there are no comparable measures to these non-GAAP measures under IFRS.

“Operating netback” or “netback” is a common non-GAAP measure used in the oil and gas industry. This measure assists management and investors to evaluate the specific operating performance by product at the oil and gas lease level. Operating netback is calculated as realized price less royalties, operating costs and transportation costs on a per unit basis,

“Return on capital” in use or “ROCIU” is a measure used by the Corporation to gauge the capital productivity of assets currently in production. ROCIU is a non-GAAP measure used to assist in analyzing shareholder value and return on capital. ROCIU equals net earnings plus after tax interest expense divided by the two-year average capital employed, less any capital invested in assets that are not in use.

“Net debt” is a non-GAAP measure that equals the sum of long-term debt, long-term debt due within one year and short-term debt, less cash and cash equivalents. Net debt is considered to be a useful measure in assisting management and investors to evaluate the Company’s financial strength.

Net Debt ($ millions)	December 31, 2020
Short-term debt		40
Long-term debt due within one year		—
Long-term debt		6,117
Total debt		6,157
Cash and cash equivalents		(735	)
Net debt		5,422

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Disclosure of Oil and Gas Information

Unless otherwise indicated: (i) reserves estimates have been prepared by internal qualified reserves evaluators in accordance with the Canadian Oil and Gas Evaluation Handbook, has been audited and reviewed by Sproule, an independent qualified reserves auditor, have an effective date of December 31, 2020 and represent the Company’s working interest share (ii) projected and historical production volumes quoted are gross, which represents the total or the Company’s working interest, as applicable share before deduction of royalties (iii) all Husky working interest production volumes quoted are before deduction of royalties; and (iv) historical production volumes provided are for the year ended December 31, 2020.

The Company uses the term “barrels of oil equivalent” (or “boe”), which is consistent with other oil and gas companies’ disclosures, and is calculated on an energy equivalence basis applicable at the burner tip whereby one barrel of crude oil is equivalent to six thousand cubic feet of conventional natural gas. The term boe is used to express the sum of the total company products in one unit that can be used for comparisons. Readers are cautioned that the term boe may be misleading, particularly if used in isolation. This measure is used for consistency with other oil and gas companies and does not represent value equivalency at the wellhead.

The Company uses the term reserves replacement ratio, which is consistent with other oil and gas companies’ disclosures. Reserves replacement ratios for a given period are determined by taking the Company’s proved reserve changes for that period divided by the Company’s upstream gross production for the same period. Reserves changes include: revisions, purchases, sales, improved recovery, discoveries and extensions. The reserves replacement ratio measures the amount of reserves changes to a company’s reserves base during a given period relative to the amount of oil and gas produced during that same period. A company’s reserves replacement ratio must be at least 100% for the company to maintain its reserves. Reserves replacement ratios that exclude economic factors will exclude the impacts that changing oil and gas prices, inflation, and exchange rates and the regulatory curtailment imposed by the Alberta government have.

Note to U.S. Readers

The Company reports its reserves and resources information in accordance with Canadian practices and specifically in accordance with NI 51-101, adopted by the Canadian securities regulators. Because the Company is permitted to prepare its reserves and resources information in accordance with Canadian disclosure requirements, it may use certain terms in that disclosure that U.S. oil and gas companies generally do not include or may be prohibited from including in their filings with the SEC.

All currency is expressed in Canadian dollars unless otherwise directed.

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Appendix A

Husky Energy Inc.

Report on Reserves Data by Independent Qualified Reserves Auditors

To the board of directors of Husky Energy Inc. (the “Company”):

(1) We have audited or reviewed the Company’s reserves data as at December 31, 2020. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2020, estimated using forecast prices and costs.

(2) The reserves data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the reserves data based on our audit and review.

(3) We carried out our audit and review in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the “COGE Handbook”), maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).

(4) Those standards require that we plan and perform an audit and review to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An audit and review also includes assessing whether the reserves data are in accordance with the principles and definitions presented in the COGE Handbook.

(5) The following table shows the net present value of future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10%, included in the reserves data of the Company audited and reviewed for the year ended December 31, 2020, and identifies the respective portions thereof that we have audited and reviewed and reported on to the Company’s management and board of directors.

Independent Qualified Reserves Evaluator or Auditor	Effective Date		Location of Reserves (Country)		Net Present Value of Future Net Revenue (Before Income Taxes,10% Discount Rate)
					Audited (MM$)		Evaluated (MM$)	Reviewed (MM$)			Total (MM$)(2)
Sproule Associates		December 31, 2020		Canada		7,551.4	Nil		(1,347.4	)(1)		6,204.0
Limited				China		3,943.8	Nil		—			3,943.8
				Indonesia		561.1	Nil		—			561.1
Total						12,056.3	Nil		(1,347.4	)(1)		10,708.8

⁽¹⁾ Negative NPV10 results from inclusion of Canadian Abandonment and Reclamation costs plus suspended well operating costs for all existing assets

Husky Energy Inc. | Annual Information Form 2020 | 126

⁽²⁾ Numbers may not add due to rounding

(6) In our opinion, the reserves data audited by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.

(7) We have no responsibility to update our report referred to in paragraph 5 for events and circumstances occurring after the effective date of our report.

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

Sproule Associates Limited

Calgary, Alberta

January 25, 2021

/s/ Cameron P. Six, P. Eng.

Cameron P. Six, P. Eng.

Sr. Petroleum Engineer

/s/ Alec Kovaltchouk, P. Geo.

Alec Kovaltchouk, P. Geo.

VP, Geoscience

Husky Energy Inc. | Annual Information Form 2020 | 127

Appendix B

Husky Energy Inc.

Report of Management and Directors on Oil and Gas Disclosure

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

An independent qualified reserves auditor has audited and reviewed the Company’s reserves data. The report of the independent qualified reserves auditor will be filed with securities regulatory authorities concurrently with this report.

The Audit Committee of the board of directors of the Company has:

a. reviewed the Company’s procedures for providing information to the independent qualified reserves auditor;

b. met with the independent qualified reserves auditor to determine whether any restrictions affected the ability of the independent qualified reserves auditor to report without reservation; and

c. reviewed the reserves data with management and the independent qualified reserves auditor.

The Audit Committee of the board of directors has reviewed the Company’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 Audit Committee, approved:

a. the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;

b. the filing of Form 51-101F2, which is the report of the independent qualified reserves auditor on the reserves data; and

c. the content and filing of this report.

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

/s/ Jeffrey R. Hart	Feb. 9, 2021
Jeffrey R. Hart Acting Chief Executive Officer & Chief Financial Officer
/s/ Andrew Dahlin	Feb. 9, 2021
Andrew Dahlin Acting Chief Operating Officer
/s/ Frank J. Sixt	Feb. 9, 2021
Frank J. Sixt Director
/s/ Wayne E. Shaw	Feb. 9, 2021
Wayne E. Shaw Director

Husky Energy Inc. | Annual Information Form 2020 | 128

Appendix C

Husky Energy Inc.

Independent Qualified Reserves Auditor Audit Opinion

Husky Energy Inc.

707 - 8th Avenue S.W.

Calgary, Alberta

T2P 3G7

Attention: Ms. Nicole Labrecque, Director, Reserves

Re: Audit of Husky Energy Inc.’s 2020 Year-End Reserves

As requested by Husky Energy Inc. (“Husky” or the “Company”), Sproule has conducted an audit of Husky’s reserves estimates and the respective net present values as at December 31, 2020. Husky internally evaluates all of their properties. Husky’s detailed reserves information was provided to us for this audit. Sproule’s responsibility is to express an independent opinion on the reasonableness of the reserves estimates and the respective net present value estimates, in the aggregate, based on our audit tests and to assess the quality of the Company’s processes and guidelines applied in the preparation of the reserves information.

We conducted our audit in accordance with generally accepted audit standards as recommended by the Society of Petroleum Engineers and the Canadian Oil and Gas Evaluation Handbook (section 5.3.3 of the Third Edition). As part of our audit, Sproule reviewed and assessed the policies, procedures, documentation and guidelines the Company has in place with respect to the estimation, review, documentation, and approval of Husky’s reserves information. The audit included confirming on a test basis that there is adherence on the part of Husky’s internal reserve evaluators and other employees to the reserves management and administration policies and procedures established by the Company. As well, the audit also included conducting reserves evaluation on a sufficient number of the Company’s internally evaluated properties as considered necessary in order to express an opinion.

For the 2020 year-end audit Sproule also reviewed the internal Husky reserve evaluation for all of the intermediate and minor properties that were not audited. Thus, for the 2020 year-end Sproule has either audited or reviewed every Husky property that was assigned reserves.

Based on the results of our audit, it is our opinion 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.

The results of the Husky internally generated reserves and net present values (based on forecast prices) supplied to us as part of the audit process are summarized below:

Husky Energy Inc. Internally Evaluated Reserves and Net Present Values Forecast Prices and Costs As of December 31, 2020
	Working Interest Before Royalty Company Share of Remaining Reserves (mmboe)	Company Share of Net Present Value Before Income Tax (MM$) @ 10%
Total Proved	1,241	6,753
Total Proved Plus Probable	1,753	10,709

Husky Energy Inc. | Annual Information Form 2020 | 129

Sincerely,

Sproule Associates Limited

/s/ Cameron P. Six, P. Eng.

Cameron P. Six, P. Eng.

Sr. Petroluem Engineer

Calgary, Alberta

January 23, 2021

Husky Energy Inc. | Annual Information Form 2020 | 130

Document B

Form 40-F

Consolidated Financial Statements and

Auditors’ Report to Shareholders

For the Year Ended December 31, 2020

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Husky Energy Inc.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Husky Energy Inc. (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of loss, comprehensive loss, changes in shareholders’ equity, and cash flows for each of the years then ended, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the years then ended, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2020, based on the criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated Feb. 8, 2021 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Assessment of the recoverable amount of the Lloydminster Heavy Oil & Gas, Tucker, Northern, Rainbow, Sunrise, White Rose and Terra Nova cash generating units

As discussed in Note 9 to the consolidated financial statements, the Company recorded an impairment charge of $5,967 million related to the Lloydminster Heavy Oil & Gas, Tucker, Northern, Rainbow, Sunrise, White Rose and Terra Nova cash generating units (collectively the “Canadian Upstream CGUs”). The Company identified an indicator of impairment at December 31, 2020

for each of the Canadian Upstream CGUs and performed an impairment test to estimate the recoverable amount of each of the Canadian Upstream CGUs. The estimated recoverable amount of each of the Canadian Upstream CGUs involves numerous estimates, including the cash flows associated with the estimated proved and probable oil and gas reserves and the discount rate. The estimation of proved and probable oil and gas reserves involves the expertise of qualified reserves evaluators, who take into consideration assumptions related to forecasted production volumes, forecasted operating, royalty and capital cost assumptions and forecasted oil and gas prices (“reserve assumptions”). The Company engages independent qualified reserves evaluators to audit the proved and probable oil and gas reserves estimates associated with the Canadian Upstream CGUs.

We identified the assessment of the recoverable amount of the Canadian Upstream CGUs as of December 31, 2020 as a critical audit matter. Changes in reserve assumptions and the discount rate could have had a significant impact on the estimates of the recoverable amount of the Canadian Upstream CGUs. A high degree of auditor judgement was required in evaluating the Company’s estimates of the proved and probable oil and gas reserves, and the related reserve assumptions, for the Canadian Upstream CGUs and the discount rate, which were inputs into the calculation of the recoverable amount of the Canadian Upstream CGUs. Additionally, the nature and extent of audit effort associated with these estimates required specialized skills and knowledge.

The following are the primary procedures we performed to address the critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the Company’s determination of the recoverable amount of the Canadian Upstream CGUs, including controls related to the development of the discount rate and the estimation of the oil and gas reserves and the related reserve assumptions associated with the Canadian Upstream CGUs. We evaluated the competence, capabilities and objectivity of the independent qualified reserves evaluators engaged by the Company, who audited the proved and probable oil and gas reserves estimates associated with the Canadian Upstream CGUs. We evaluated the methodology used by the independent qualified reserves evaluators to audit the estimates of proved and probable reserves associated with the Canadian Upstream CGUs for compliance with regulatory standards. We compared the 2020 actual production, operating, royalty and capital costs of the Company to those estimates used in the prior year’s estimates of proved reserves to assess the Company’s ability to accurately forecast the reserve assumptions. We assessed the forecasted commodity prices used in the estimates of proved and probable reserves by comparing them to those published by other reserve engineering companies. We assessed the estimates of forecasted production, forecasted operating, royalty and capital cost assumptions used in the estimates of proved and probable reserves by comparing them to historical results. We involved a valuation professional with specialized skills and knowledge, who assisted in evaluating the Company’s discount rate, by comparing it against market data and other external data. The valuations specialist evaluated the recoverable amount of the Canadian Upstream CGUs using the estimates of the cash flows associated with the Canadian Upstream CGUs’ reserves and the discount rate evaluated by the specialist and compared the results to market data and other external pricing data.

Assessment of the recoverable amount of the Lima Refinery, BP-Husky Toledo Refinery, and Superior Refinery cash generating units

As discussed in Notes 9 and 11 to the consolidated financial statements, the Company recorded an impairment charge of $3,956 million related to the Lima Refinery, BP-Husky Toledo Refinery, and Superior Refinery cash generating units (collectively the “US Downstream CGUs”). The Company identified an indicator of impairment at September 30, 2020 for each of the US Downstream CGUs and performed impairment tests to estimate the recoverable amount of each of the US Downstream CGUs. The estimated recoverable amount of each of the US Downstream CGUs involves numerous assumptions, including the estimated future revenue net of oil purchases used in the production of gas, diesel and other petroleum products (“crack spreads”), future capital expenditures and the discount rate.

We identified the assessment of the recoverable amount of the US Downstream CGUs as a critical audit matter. Changes in estimated crack spreads, capital expenditures and the discount rate could have had a significant impact on the estimated recoverable amount of the US Downstream CGUs. A high degree of auditor judgment was required in evaluating estimated crack spreads, capital expenditures and the discount rate. Additionally, the nature and extent of audit effort associated with this estimate required specialized skills and knowledge.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the assessment of the recoverable amount of the US Downstream CGUs, including controls related to the development of the estimated crack spreads, capital expenditures and discount rate assumptions. We compared the Company’s historical crack spreads and capital expenditures to forecasts the Company prepared in the prior year to assess the Company’s ability to accurately forecast. We evaluated the forecasted crack spreads and capital expenditures for the US Downstream CGU’s by comparing the forecasted amounts to historical results considering the impact of changes in conditions and events affecting the US Downstream CGUs. We involved a valuation professional with specialized skills and knowledge, who assisted in evaluating the Company’s discount rate, by comparing it against market data and other external data. The valuations professional evaluated the recoverable amount of the US Downstream CGUs using the cash flow forecast of the US Downstream CGUs and the discount rate evaluated by the specialist and compared the result to market data and other external pricing data.

Impact of estimated oil and gas reserves on depletion expense related to oil and gas properties

As discussed in Note 3(d) to the consolidated financial statements, the Company depletes its oil and gas properties using the unit-of-production method. Under such method, capitalized costs are depleted over proved developed producing reserves of the particular field, except in the case of assets whose useful life is shorter or longer than the lifetime of the proved developed producing reserves of that field in which case either the straight-line method or a unit-of-production method based on total proved plus probable reserves is applied as appropriate in the circumstances. As indicated in Note 9, for the year ended December 31, 2020, the Company recorded depletion expense related to oil and gas properties of $1,468 million. The estimation of proved and probable oil and gas reserves, which are used in the calculation of depletion expense, requires the expertise of qualified reserves evaluators, who take into consideration reserve assumptions. The Company engages independent qualified reserves evaluators to audit the Company’s proved and probable oil and gas reserves estimates.

We identified the assessment of the impact of estimated proved and probable oil and gas reserves on the calculation of depletion expense as a critical audit matter. Changes in reserve assumptions could have had a significant impact on the calculation of depletion expense. A high degree of auditor judgment was required in evaluating the Company’s estimate of proved and probable oil and gas reserves, and the related reserve assumptions, which were an input to the calculation of depletion expense.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the calculation of depletion expense, including controls over the estimation of proved and probable oil and gas reserves and the related reserve assumptions. We assessed the calculation of depletion expense for compliance with regulatory standards. We evaluated the competence, capabilities and objectivity of the independent qualified reserves evaluators engaged by the Company, who audited the proved and probable oil and gas reserves estimates. We evaluated the methodology used by the independent qualified reserves evaluators to audit the estimate of proved and probable reserves for compliance with regulatory standards. We compared the Company’s 2020 actual production, operating, royalty and capital costs to those estimates used in the prior year estimate of proved reserves to assess the Company’s ability to accurately forecast. We assessed the forecasted commodity prices used in the estimate of proved and probable reserves by comparing them to those published by other reserve engineering companies. We assessed the estimates of forecasted production, forecasted operating, royalty and capital cost assumptions used in the estimate of proved and probable reserves by comparing them to historical results.

/s/ KPMG LLP

KPMG LLP

Chartered Professional Accountants

We have served as the Company’s auditor since 1951.

Calgary, Canada

Feb. 8, 2021

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Husky Energy Inc.:

Opinion on Internal Control Over Financial Reporting

We have audited Husky Energy Inc.’s (the “Company”) internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2020 and 2019, the related consolidated statements of loss, comprehensive loss, changes in shareholders’ equity, and cash flows for each of the years then ended, and the related notes (collectively, the consolidated financial statements, and our report dated Feb. 8, 2021 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting included in the Management’s Discussion and Analysis. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ KPMG LLP

KPMG LLP

Chartered Professional Accountants

Calgary, Canada

Feb. 8, 2021

MANAGEMENT’S REPORT

The management of Husky Energy Inc. (“the Company”) is responsible for the financial information and operating data presented in this financial document.

The consolidated financial statements have been prepared by management in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. When alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances. Financial statements are not precise as they include certain amounts based on estimates and judgments. Management has determined such amounts on a reasonable basis in order to ensure that the financial statements are presented fairly, in all material respects. Financial information presented elsewhere in this financial document has been prepared on a basis consistent with that in the consolidated financial statements.

The Company maintains systems of internal accounting and administrative controls. These systems are designed to provide reasonable assurance that the financial information is relevant, reliable and accurate and that the Company’s assets are properly accounted for and adequately safeguarded. Management’s evaluation concluded that the Company’s internal control over financial reporting was effective as of December 31, 2020. The system of internal controls is further supported by an internal audit function.

The Audit Committee of the Board of Directors, composed of independent non-management directors, meets regularly with management, internal auditors as well as the external auditors, to discuss audit (external, internal and joint venture), internal controls, accounting policy and financial reporting matters as well as the reserves determination process. The Committee reviews the annual consolidated financial statements with both management and the independent auditors and reports its findings to the Board of Directors before such statements are approved by the Board. The Committee is also responsible for the appointment of the external auditors for the Company.

The consolidated financial statements have been audited by KPMG LLP, the independent auditors, in accordance with the standards of the Public Company Accounting Oversight Board (United States) on behalf of the shareholder. KPMG LLP has full and free access to the Audit Committee.

”Jeffrey R. Hart”

Jeffrey R. Hart

Acting Chief Executive Officer & Chief Financial Officer

Calgary, Canada

Feb. 8, 2021

Husky Energy Inc. | Consolidated Financial Statements | 1

Independent auditor’s report

To the Shareholder and Board of Directors of Husky Energy Inc.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Husky Energy Inc. (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of loss, comprehensive loss, changes in shareholders’ equity, and cash flows for each of the years then ended, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the years then ended, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2020, based on the criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated Feb. 8, 2021 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Assessment of the recoverable amount of the Lloydminster Heavy Oil & Gas, Tucker, Northern, Rainbow, Sunrise, White Rose and Terra Nova cash generating units

As discussed in Note 9 to the consolidated financial statements, the Company recorded an impairment charge of $5,967 million related to the Lloydminster Heavy Oil & Gas, Tucker, Northern, Rainbow, Sunrise, White Rose and Terra Nova cash generating

Husky Energy Inc. | Consolidated Financial Statements | 2

units (collectively the “Canadian Upstream CGUs”). The Company identified an indicator of impairment at December 31, 2020 for each of the Canadian Upstream CGUs and performed an impairment test to estimate the recoverable amount of each of the Canadian Upstream CGUs. The estimated recoverable amount of each of the Canadian Upstream CGUs involves numerous estimates, including the cash flows associated with the estimated proved and probable oil and gas reserves and the discount rate. The estimation of proved and probable oil and gas reserves involves the expertise of qualified reserves evaluators, who take into consideration assumptions related to forecasted production volumes, forecasted operating, royalty and capital cost assumptions and forecasted oil and gas prices (“reserve assumptions”). The Company engages independent qualified reserves evaluators to audit the proved and probable oil and gas reserves estimates associated with the Canadian Upstream CGUs.

We identified the assessment of the recoverable amount of the Canadian Upstream CGUs as of December 31, 2020 as a critical audit matter. Changes in reserve assumptions and the discount rate could have had a significant impact on the estimates of the recoverable amount of the Canadian Upstream CGUs. A high degree of auditor judgement was required in evaluating the Company’s estimates of the proved and probable oil and gas reserves, and the related reserve assumptions, for the Canadian Upstream CGUs and the discount rate, which were inputs into the calculation of the recoverable amount of the Canadian Upstream CGUs. Additionally, the nature and extent of audit effort associated with these estimates required specialized skills and knowledge.

We identified the assessment of the recoverable amount of the Canadian Upstream CGUs as of December 31, 2020 as a critical audit matter. Changes in reserve assumptions and the discount rate could have had a significant impact on the estimates of the recoverable amount of the Canadian Upstream CGUs. A high degree of auditor judgement was required in evaluating the Company’s estimates of the proved and probable oil and gas reserves, and the related reserve assumptions, for the Canadian Upstream CGUs and the discount rate, which were inputs into the calculation of the recoverable amount of the Canadian Upstream CGUs. Additionally, the nature and extent of audit effort associated with these estimates required specialized skills and knowledge.

The following are the primary procedures we performed to address the critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the Company’s determination of the recoverable amount of the Canadian Upstream CGUs, including controls related to the development of the discount rate and the estimation of the oil and gas reserves and the related reserve assumptions associated with the Canadian Upstream CGUs. We evaluated the competence, capabilities and objectivity of the independent qualified reserves evaluators engaged by the Company, who audited the proved and probable oil and gas reserves estimates associated with the Canadian Upstream CGUs. We evaluated the methodology used by the independent qualified reserves evaluators to audit the estimates of proved and probable reserves associated with the Canadian Upstream CGUs for compliance with regulatory standards. We compared the 2020 actual production, operating, royalty and capital costs of the Company to those estimates used in the prior year’s estimates of proved reserves to assess the Company’s ability to accurately forecast the reserve assumptions. We assessed the forecasted commodity prices used in the estimates of proved and probable reserves by comparing them to those published by other reserve engineering companies. We assessed the estimates of forecasted production, forecasted operating, royalty and capital cost assumptions used in the estimates of proved and probable reserves by comparing them to historical results. We involved a valuation professional with specialized skills and knowledge, who assisted in evaluating the Company’s discount rate, by comparing it against market data and other external data. The valuations specialist evaluated the recoverable amount of the Canadian Upstream CGUs using the estimates of the cash flows associated with the Canadian Upstream CGUs’ reserves and the discount rate evaluated by the specialist and compared the results to market data and other external pricing data.

Assessment of the recoverable amount of the Lima Refinery, BP-Husky Toledo Refinery, and Superior Refinery cash generating units

As discussed in Notes 9 and 11 to the consolidated financial statements, the Company recorded an impairment charge of $3,956 million related to the Lima Refinery, BP-Husky Toledo Refinery, and Superior Refinery cash generating units (collectively

Husky Energy Inc. | Consolidated Financial Statements | 3

the “US Downstream CGUs”). The Company identified an indicator of impairment at September 30, 2020 for each of the US Downstream CGUs and performed impairment tests to estimate the recoverable amount of each of the US Downstream CGUs. The estimated recoverable amount of each of the US Downstream CGUs involves numerous assumptions, including the estimated future revenue net of oil purchases used in the production of gas, diesel and other petroleum products (“crack spreads”), future capital expenditures and the discount rate.

We identified the assessment of the recoverable amount of the US Downstream CGUs as a critical audit matter. Changes in estimated crack spreads, capital expenditures and the discount rate could have had a significant impact on the estimated recoverable amount of the US Downstream CGUs. A high degree of auditor judgment was required in evaluating estimated crack spreads, capital expenditures and the discount rate. Additionally, the nature and extent of audit effort associated with this estimate required specialized skills and knowledge.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the assessment of the recoverable amount of the US Downstream CGUs, including controls related to the development of the estimated crack spreads, capital expenditures and discount rate assumptions. We compared the Company’s historical crack spreads and capital expenditures to forecasts the Company prepared in the prior year to assess the Company’s ability to accurately forecast. We evaluated the forecasted crack spreads and capital expenditures for the US Downstream CGU’s by comparing the forecasted amounts to historical results considering the impact of changes in conditions and events affecting the US Downstream CGUs. We involved a valuation professional with specialized skills and knowledge, who assisted in evaluating the Company’s discount rate, by comparing it against market data and other external data. The valuations professional evaluated the recoverable amount of the US Downstream CGUs using the cash flow forecast of the US Downstream CGUs and the discount rate evaluated by the specialist and compared the result to market data and other external pricing data.

Impact of estimated oil and gas reserves on depletion expense related to oil and gas properties

As discussed in Note 3(d) to the consolidated financial statements, the Company depletes its oil and gas properties using the unit-of-production method. Under such method, capitalized costs are depleted over proved developed producing reserves of the particular field, except in the case of assets whose useful life is shorter or longer than the lifetime of the proved developed producing reserves of that field in which case either the straight-line method or a unit-of-production method based on total proved plus probable reserves is applied as appropriate in the circumstances. As indicated in Note 9, for the year ended December 31, 2020, the Company recorded depletion expense related to oil and gas properties of $1,468 million. The estimation of proved and probable oil and gas reserves, which are used in the calculation of depletion expense, requires the expertise of qualified reserves evaluators, who take into consideration reserve assumptions. The Company engages independent qualified reserves evaluators to audit the Company’s proved and probable oil and gas reserves estimates.

We identified the assessment of the impact of estimated proved and probable oil and gas reserves on the calculation of depletion expense as a critical audit matter. Changes in reserve assumptions could have had a significant impact on the calculation of depletion expense. A high degree of auditor judgment was required in evaluating the Company’s estimate of proved and probable oil and gas reserves, and the related reserve assumptions, which were an input to the calculation of depletion expense.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the calculation of depletion expense, including controls over the estimation of proved and probable oil and gas reserves and the related reserve assumptions. We assessed the calculation of depletion expense for compliance with regulatory standards. We evaluated the competence, capabilities and objectivity of the independent qualified reserves evaluators engaged by the Company, who audited the proved and probable oil and gas reserves estimates. We evaluated the methodology used by the independent qualified reserves evaluators to audit

Husky Energy Inc. | Consolidated Financial Statements | 4

the estimate of proved and probable reserves for compliance with regulatory standards. We compared the Company’s 2020 actual production, operating, royalty and capital costs to those estimates used in the prior year estimate of proved reserves to assess the Company’s ability to accurately forecast. We assessed the forecasted commodity prices used in the estimate of proved and probable reserves by comparing them to those published by other reserve engineering companies. We assessed the estimates of forecasted production, forecasted operating, royalty and capital cost assumptions used in the estimate of proved and probable reserves by comparing them to historical results.

We have served as the Company’s auditor since 1951.

/s/ KPMG LLP

KPMG LLP

Chartered Professional Accountants

Calgary, Canada

Feb. 8, 2021

Husky Energy Inc. | Consolidated Financial Statements | 5

CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Balance Sheets

(millions of Canadian dollars)	December 31, 2020			December 31, 2019
Assets
Current assets
Cash and cash equivalents (note 4)		735			1,775
Accounts receivable (notes 5, 25)		1,119			1,499
Income taxes receivable		—			30
Inventories (note 6)		1,115			1,486
Prepaid expenses		161			148
		3,130			4,938
Restricted cash (notes 7, 18)		164			142
Exploration and evaluation assets (note 8)		46			643
Property, plant and equipment, net (note 9)		13,496			23,623
Right-of-use assets, net (note 10)		698			1,202
Goodwill (note 11)		—			656
Investment in joint ventures (note 12)		457			1,182
Long-term income taxes receivable		202			212
Deferred tax assets (note 13)		1,328			—
Other assets (note 14)		166			524
Total Assets		19,687			33,122
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities (note 16)		2,129			3,465
Income taxes payable		27			—
Short-term debt (notes 15, 17)		40			550
Long-term debt due within one year (note 17)		—			400
Lease liabilities (note 10)		102			109
Asset retirement obligations (note 18)		94			112
		2,392			4,636
Long-term debt (note 17)		6,117			4,570
Other long-term liabilities (note 19)		410			454
Lease liabilities (note 10)		1,298			1,353
Asset retirement obligations (note 18)		2,068			2,643
Deferred tax liabilities (note 13)		338			2,170
Total Liabilities		12,623			15,826
Shareholders’ equity
Common shares (note 20)		7,293			7,293
Preferred shares (note 20)		874			874
Contributed surplus		2			2
Retained earnings (deficit)		(1,855	)		8,365
Accumulated other comprehensive income		735			748
Non-controlling interest		15			14
Total Shareholders’ Equity		7,064			17,296
Total Liabilities and Shareholders’ Equity		19,687			33,122

The accompanying notes to the consolidated financial statements are an integral part of these statements.

On behalf of the Board:
”Frank J. Sixt”	”Wayne E. Shaw”
Frank J Sixt	Wayne E. Shaw
Director	Director

Husky Energy Inc. | Consolidated Financial Statements | 6

Consolidated Statements of Loss

	Years ended December 31,
(millions of Canadian dollars, except share data)	2020			2019
Gross revenues(1)		13,463			20,047
Royalties		(191	)		(323	)
Marketing and other(1)		29			178
Revenues, net of royalties		13,301			19,902
Expenses
Purchases of crude oil and products(1)		9,281			12,826
Production, operating and transportation expenses(1) (note 21)		2,560			3,030
Selling, general and administrative expenses (note 21)		745			693
Depletion, depreciation, amortization and impairment (notes 9, 10, 11, 12)		12,920			5,496
Exploration and evaluation expenses (note 8)		733			547
Gain on sale of assets		(25	)		(8	)
Other – net(1) (notes 14, 25, 26)		(262	)		(687	)
		25,952			21,897
Loss from operating activities		(12,651	)		(1,995	)
Share of equity investment income (note 12)		7			59
Financial items (note 22)
Net foreign exchange gain		14			44
Finance income		25			74
Finance expenses		(399	)		(351	)
		(360	)		(233	)
Loss before income taxes		(13,004	)		(2,169	)
Provisions for (recovery of) income taxes (note 13)
Current		202			175
Deferred		(3,190	)		(974	)
		(2,988	)		(799	)
Net loss		(10,016	)		(1,370	)
Loss per share (note 20)
Basic		(10.00	)		(1.40	)
Diluted		(10.00	)		(1.41	)
Weighted average number of common shares outstanding (note 20)
Basic (millions)		1,005.1			1,005.1
Diluted (millions)		1,005.1			1,005.1

⁽¹⁾  Results for certain items in the consolidated statements of loss reported for 2019 have been recast to reflect various reclassifications due to a change in presentation of the Integrated Corridor and Offshore business units.

The accompanying notes to the consolidated financial statements are an integral part of these statements.

Husky Energy Inc. | Consolidated Financial Statements | 7

Consolidated Statements of Comprehensive Loss

	Years ended December 31,
(millions of Canadian dollars)	2020			2019
Net loss		(10,016	)		(1,370	)
Other comprehensive loss
Items that will not be reclassified into earnings, net of tax:
Remeasurements of pension plans (note 23)		(6	)		—
Items that may be reclassified into earnings, net of tax:
Derivatives designated as cash flow hedge		—			(6	)
Equity investment – share of other comprehensive loss		(8	)		(2	)
Exchange differences on translation of foreign operations		(49	)		(550	)
Hedge of net investment (note 25)		44			146
Other comprehensive loss		(19	)		(412	)
Comprehensive loss		(10,035	)		(1,782	)

The accompanying notes to the consolidated financial statements are an integral part of these statements.

Husky Energy Inc. | Consolidated Financial Statements | 8

Consolidated Statements of Changes in Shareholders’ Equity

	Attributable to Equity Holders
										AOCI (1)
(millions of Canadian dollars)	Common Shares		Preferred Shares		Contributed Surplus		Retained Earnings (deficit)			Foreign Currency Translation			Hedging			Non- Controlling Interest		Total Shareholders’ Equity
Balance as at December 31, 2018		7,293		874		2		10,273			1,154			6			12		19,614
Net loss		—		—		—		(1,370	)		—			—			—		(1,370	)
Other comprehensive income (loss)
Remeasurements of pension plans (net of tax expense of $1 million) (notes 13, 23)		—		—		—		—			—			—			—		—
Derivatives designated as cash flow hedges (net of tax recovery of $3 million) (note 13)		—		—		—		—			—			(6	)		—		(6	)
Equity investment – share of other comprehensive loss		—		—		—		—			—			(2	)		—		(2	)
Exchange differences on translation of foreign operations (net of tax recovery of $58 million) (note 13)		—		—		—		—			(550	)		—			—		(550	)
Hedge of net investment (net of tax expense of $30 million) (notes 13, 25)		—		—		—		—			146			—			—		146
Total comprehensive loss		—		—		—		(1,370	)		(404	)		(8	)		—		(1,782	)
Transactions with owners recognized directly in equity:
Dividends declared on common shares (note 20)		—		—		—		(503	)		—			—			—		(503	)
Dividends declared on preferred shares (note 20)		—		—		—		(35	)		—			—			—		(35	)
Non-controlling interest in subsidiary		—		—		—		—			—			—			2		2
Balance as at December 31, 2019		7,293		874		2		8,365			750			(2	)		14		17,296
Net loss		—		—		—		(10,016	)		—			—			—		(10,016	)
Other comprehensive loss
Remeasurements of pension plans (net of tax recovery of $2 million) (notes 13, 23)		—		—		—		(6	)		—			—			—		(6	)
Derivatives designated as cash flow hedges (net of tax recovery of $3 million) (note 13)		—		—		—		—			—			—			—		—
Equity investment – share of other comprehensive loss		—		—		—		—			—			(8	)		—		(8	)
Exchange differences on translation of foreign operations (net of tax expense of $29 million) (note 13)		—		—		—		—			(49	)		—			—		(49	)
Hedge of net investment (net of tax expense of $6 million) (notes 13, 25)		—		—		—		—			44			—			—		44
Total comprehensive loss		—		—		—		(10,022	)		(5	)		(8	)		—		(10,035	)
Transactions with owners recognized directly in equity:
Dividends declared on common shares (note 20)		—		—		—		(163	)		—			—			—		(163	)
Dividends declared on preferred shares (note 20)		—		—		—		(35	)		—			—			—		(35	)
Non-controlling interest in subsidiary		—		—		—		—			—			—			1		1
Balance as at December 31, 2020		7,293		874		2		(1,855	)		745			(10	)		15		7,064

⁽¹⁾  Accumulated other comprehensive income.

The accompanying notes to the consolidated financial statements are an integral part of these statements.

Husky Energy Inc. | Consolidated Financial Statements | 9

Consolidated Statements of Cash Flows

	Years ended December 31,
(millions of Canadian dollars)	2020			2019
Operating activities
Net loss		(10,016	)		(1,370	)
Items not affecting cash:
Accretion (notes 18, 22)		104			106
Depletion, depreciation, amortization and impairment (notes 9, 10, 11, 12)		12,920			5,496
Inventory write-down to net realizable value (note 6)		7			15
Exploration and evaluation expenses (note 8)		594			355
Deferred income taxes (note 13)		(3,190	)		(974	)
Foreign exchange		(3	)		(26	)
Stock-based compensation (notes 20, 21)		16			(2	)
Gain on sale of assets		(25	)		(8	)
Unrealized mark to market loss (note 25)		10			44
Share of equity investment income (note 12)		(7	)		(59	)
Gain on insurance recoveries for damage to property (note 14)		(19	)		(207	)
Other		67			12
Settlement of asset retirement obligations (note 18)		(39	)		(276	)
Deferred revenue (notes 17, 19)		(115	)		(42	)
Distribution from joint ventures (note 12)		190			187
Change in non-cash working capital (note 24)		347			(280	)
Cash flow – operating activities		841			2,971
Financing activities
Long-term debt issuance (repayment) (note 17)		1,200			(389	)
Short-term debt issuance (repayment) (note 17)		(510	)		350
Debt issue costs (note 17)		(7	)		(9	)
Dividends on common shares (note 20)		(276	)		(503	)
Dividends on preferred shares (note 20)		(35	)		(35	)
Finance lease payments (notes 10, 17)		(111	)		(233	)
Other		2			(1	)
Change in non-cash working capital (note 24)		11			3
Cash flow – financing activities		274			(817	)
Investing activities
Capital expenditures		(1,587	)		(3,432	)
Capitalized interest (note 22)		(60	)		(177	)
Proceeds from asset sales (note 9)		30			277
Investment in joint ventures (note 12)		(91	)		(40	)
Other		2			2
Change in non-cash working capital (note 24)		(423	)		173
Cash flow – investing activities		(2,129	)		(3,197	)
Decrease in cash and cash equivalents		(1,014	)		(1,043	)
Effect of exchange rates on cash and cash equivalents		(26	)		(48	)
Cash and cash equivalents at beginning of year		1,775			2,866
Cash and cash equivalents at end of year		735			1,775
Supplementary cash flow information
Net interest paid		(302	)		(330	)
Net Income taxes paid		(135	)		(41	)

The accompanying notes to the consolidated financial statements are an integral part of these statements.

Husky Energy Inc. | Consolidated Financial Statements | 10

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1 Description of Business and Segmented Disclosures

Husky Energy Inc. (“Husky” or “the Company”) is an international integrated energy company incorporated under the Business Corporations Act (Alberta). The Company’s common shares were listed on the Toronto Stock Exchange (“TSX”) under the symbol “HSE” and the Cumulative Redeemable Preferred Shares, Series 1, Cumulative Redeemable Preferred Shares, Series 2, Cumulative Redeemable Preferred Shares, Series 3, Cumulative Redeemable Preferred Shares, Series 5 and Cumulative Redeemable Preferred Shares, Series 7 were listed under the symbols, ”HSE.PR.A”, “HSE.PR.B”, ”HSE.PR.C”, ”HSE.PR.E” and ”HSE.PR.G”, respectively. The registered office is located at 39th Flr, 707 - 8th Avenue SW, Calgary, Alberta, T2P 3G7.

On January 4, 2021, Husky announced the transaction to strategically combine with Cenovus Energy Inc. (“Cenovus”) had closed. Husky’s common shares and preferred shares were delisted by the TSX at the close of market on January 5, 2021. The combined company operates as Cenovus Energy Inc. These consolidated financial statements and notes are presented for Husky Energy Inc. and its consolidated entities without giving effect to the combination with Cenovus.

Management has identified segments for the Company’s business based on differences in products, services and management responsibility. The Company’s business is conducted predominantly through two major business segments – Integrated Corridor and Offshore.

Integrated Corridor

The Company’s business in the Integrated Corridor includes:

The Lloydminster Heavy Oil Value Chain includes the exploration for, and development and production of, heavy crude oil and bitumen, and 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 Keystone pipeline and other pipelines to be sold in the U.S. downstream market. Heavy crude oil can be upgraded at the Company’s Lloydminster upgrading and asphalt refining complex into synthetic crude oil, diesel fuel and asphalt. This business also includes the marketing and transportation of both the Company’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 the Company’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. The Company 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.

The Oil Sands business includes the exploration for, and development and production of, bitumen within the Sunrise Energy Project. It also includes the marketing and transportation of the Company’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.

The Western Canada Production business includes the exploration for, and development and production of, light crude oil, conventional natural gas and natural gas liquids (“NGL”) in Western Canada. The Company’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.

The U.S. Refining business includes the refining of crude oil at the Lima Refinery, the BP-Husky Toledo Refinery and the Superior Refinery in the U.S. Midwest to produce diesel fuel, gasoline, jet fuel, asphalt and other products. The Company also markets its own and third-party volumes of refined petroleum products including gasoline and diesel fuel.

Husky Energy Inc. | Consolidated Financial Statements | 11

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

Offshore

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

Husky Energy Inc. | Consolidated Financial Statements | 12

Segmented Financial Information

	Integrated Corridor
($ millions)	Lloydminster Heavy Oil Value Chain(1)						Oil Sands						Western Canada Production						U.S. Refining
Years ended December 31,	2020			2019			2020			2019			2020			2019			2020			2019
Gross revenues(3)		3,753			5,601			306			649			367			514			6,636			10,253
Royalties		(92	)		(160	)		(2	)		(13	)		(10	)		(41	)		—			—
Marketing and other(3)		22			52			(48	)		4			15			99			40			23
Revenues, net of royalties		3,683			5,493			256			640			372			572			6,676			10,276
Expenses
Purchases of crude oil and products(3)		1,827			2,395			153			246			22			40			6,500			8,934
Production, operating and transportation expenses(3)		1,059			1,212			114			140			250			313			797			872
Selling, general and administrative expenses		204			155			24			27			64			106			72			51
Depletion, depreciation, amortization and impairment		2,058			941			1,749			938			802			1,034			4,419			735
Exploration and evaluation expenses		182			54			(1	)		2			1			111			—			—
Loss (gain) on sale of assets		(4	)		—			—			—			(20	)		(2	)		—			1
Other – net(3)		21			9			(26	)		(28	)		(7	)		1			(84	)		(654	)
		5,347			4,766			2,013			1,325			1,112			1,603			11,704			9,939
Earnings (loss) from operating activities		(1,664	)		727			(1,757	)		(685	)		(740	)		(1,031	)		(5,028	)		337
Share of equity investment income (loss)		(32	)		9			—			—			—			—			—			—
Financial items
Net foreign exchange gain		—			—			—			—			—			—			—			—
Finance income		—			—			—			—			—			—			—			—
Finance expenses		(47	)		(48	)		(57	)		(59	)		(19	)		(24	)		(18	)		(18	)
		(47	)		(48	)		(57	)		(59	)		(19	)		(24	)		(18	)		(18	)
Earnings (loss) before income taxes		(1,743	)		688			(1,814	)		(744	)		(759	)		(1,055	)		(5,046	)		319
Provisions for (recovery of) income taxes
Current		—			(2	)		—			10			—			—			—			17
Deferred		(434	)		186			(452	)		(209	)		(189	)		(283	)		(1,121	)		54
		(434	)		184			(452	)		(199	)		(189	)		(283	)		(1,121	)		71
Net earnings (loss)		(1,309	)		504			(1,362	)		(545	)		(570	)		(772	)		(3,925	)		248

⁽¹⁾  Includes $110 million of revenue (2019 - $201 million) and $99 million of associated costs (2019 - $269 million) for construction contracts in progress with revenue recognized as performance obligations are met.

⁽²⁾  Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices. Segment results include transactions between business segments.

⁽³⁾  Results for certain items in the consolidated statements of loss reported for 2019 have been recast to reflect various reclassifications due to a change in presentation of the Integrated Corridor and Offshore business units.

Husky Energy Inc. | Consolidated Financial Statements | 13

Segmented Financial Information Con’t

Integrated Corridor																		Offshore						Corporate						Total
Canadian Refined Products						Eliminations(2)						Total
2020			2019			2020			2019			2020			2019			2020			2019			2020			2019			2020			2019
	1,488			2,425			(602	)		(948	)		11,948			18,494			1,515			1,553			—			—			13,463			20,047
	—			—			—			—			(104	)		(214	)		(87	)		(109	)		—			—			(191	)		(323	)
	—			—			—			—			29			178			—			—			—			—			29			178
	1,488			2,425			(602	)		(948	)		11,873			18,458			1,428			1,444			—			—			13,301			19,902
	1,349			2,175			(602	)		(948	)		9,249			12,842			32			(16	)		—			—			9,281			12,826
	65			153			—			—			2,285			2,690			275			340			—			—			2,560			3,030
	44			9			—			—			408			348			75			55			262			290			745			693
	62			83			—			—			9,090			3,731			3,738			1,661			92			104			12,920			5,496
	—			—			—			—			182			167			551			380			—			—			733			547
	—			(6	)		—			—			(24	)		(7	)		(1	)		(1	)		—			—			(25	)		(8	)
	(4	)		—			—			—			(100	)		(672	)		(5	)		1			(157	)		(16	)		(262	)		(687	)
	1,516			2,414			(602	)		(948	)		21,090			19,099			4,665			2,420			197			378			25,952			21,897
	(28	)		11			—			—			(9,217	)		(641	)		(3,237	)		(976	)		(197	)		(378	)		(12,651	)		(1,995	)
	—			—			—			—			(32	)		9			39			50			—			—			7			59
	—			—			—			—			—			—			—			—			14			44			14			44
	—			—			—			—			—			—			7			3			18			71			25			74
	(11	)		(13	)		—			—			(152	)		(162	)		(41	)		(38	)		(206	)		(151	)		(399	)		(351	)
	(11	)		(13	)		—			—			(152	)		(162	)		(34	)		(35	)		(174	)		(36	)		(360	)		(233	)
	(39	)		(2	)		—			—			(9,401	)		(794	)		(3,232	)		(961	)		(371	)		(414	)		(13,004	)		(2,169	)
	—			—			—			—			—			25			150			125			52			25			202			175
	(10	)		—			—			—			(2,206	)		(252	)		(963	)		(393	)		(21	)		(329	)		(3,190	)		(974	)
	(10	)		—			—			—			(2,206	)		(227	)		(813	)		(268	)		31			(304	)		(2,988	)		(799	)
	(29	)		(2	)		—			—			(7,195	)		(567	)		(2,419	)		(693	)		(402	)		(110	)		(10,016	)		(1,370	)

Husky Energy Inc. | Consolidated Financial Statements | 14

Segmented Financial Information

	Integrated Corridor
($ millions)	Lloydminster Heavy Oil Value Chain						Oil Sands						Western Canada Production
Years ended December 31,	2020			2019			2020			2019			2020			2019
Expenditures on exploration and evaluation assets(1)		—			17			—			—			—			3
Expenditures on property, plant and equipment(1)		594			939			9			38			57			191
As at December 31,
Exploration and evaluation assets		—			154			—			—			—			2
Developing and producing assets at cost		15,212			15,453			3,021			3,104			12,849			13,300
Accumulated depletion, depreciation, amortization and impairment		(11,411	)		(10,345	)		(2,498	)		(1,020	)		(12,207	)		(11,764	)
Other property, plant and equipment at cost		4,189			3,820			76			3			55			62
Accumulated depletion, depreciation and amortization		(2,752	)		(2,410	)		(9	)		—			(30	)		(40	)
Total exploration and evaluation assets and property, plant and equipment, net		5,238			6,672			590			2,087			667			1,560
Total right-of-use assets, net		68			54			167			430			4			9
Total assets		6,650			8,312			993			2,757			707			1,709

⁽¹⁾  Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the year. Includes assets acquired through acquisition, but excludes assets acquired through corporate acquisition.

Geographical Financial Information

($ millions)	Canada						United States
Years ended December 31,	2020			2019			2020		2019
Gross revenues(1)(2)		5,648			8,734			6,636		10,253
Royalties		(122	)		(263	)		—		—
Marketing and other(2)		(11	)		155			40		23
Revenue, net of royalties		5,515			8,626			6,676		10,276
As at December 31,
Restricted cash – non-current		—			—			—		—
Exploration and evaluation assets		—			599			—		—
Property, plant and equipment, net		7,893			14,630			2,868		6,053
Right-of-use assets, net		616			1,044			81		156
Goodwill		—			—			—		656
Investment in joint ventures		—			666			—		—
Long-term income tax receivable		202			212			—		—
Deferred tax assets		1,127			—			187		—
Other assets(3)		30			47			119		458
Total non-current assets		9,868			17,198			3,255		7,323

⁽¹⁾  Sales to external customers are based on the location of the seller.

⁽²⁾  Results reported for 2019 have been recast to reflect various reclassifications due to a change in presentation of the Integrated Corridor and Offshore business units.

⁽³⁾ Includes insurance proceeds of $98 million (2019 - $435 million), related to the Superior Refinery incident.

Husky Energy Inc. | Consolidated Financial Statements | 15

Segmented Financial Information Con’t

Integrated Corridor																						Offshore						Corporate						Total
U.S. Refining						Canadian Refined Products						Eliminations				Total
2020			2019			2020			2019			2020		2019		2020			2019			2020			2019			2020			2019			2020			2019
	—			—			—			—			—		—		—			20			1			26			—			—			1			46
	489			768			5			73			—		—		1,154			2,009			367			1,246			65			131			1,586			3,386
	—			—			—			—			—		—		—			156			46			487			—			—			46			643
	—			—			—			—			—		—		31,082			31,857			15,102			14,730			—			—			46,184			46,587
	—			—			—			—			—		—		(26,116	)		(23,129	)		(11,773	)		(8,219	)		—			—			(37,889	)		(31,348	)
	10,057			9,540			1,287			1,284			—		—		15,664			14,709			7			7			1,388			1,377			17,059			16,093
	(7,190	)		(3,488	)		(794	)		(743	)		—		—		(10,775	)		(6,681	)		—			—			(1,083	)		(1,028	)		(11,858	)		(7,709	)
	2,867			6,052			493			541			—		—		9,855			16,912			3,382			7,005			305			349			13,542			24,266
	82			157			102			122			—		—		423			772			3			138			272			292			698			1,202
	4,469			8,645			625			838			—		—		13,444			22,261			4,570			8,077			1,673			2,784			19,687			33,122

Geographical Financial Information Con’t

China						Other International				Total
2020			2019			2020		2019		2020			2019
	1,179			1,060			—		—		13,463			20,047
	(69	)		(60	)		—		—		(191	)		(323	)
	—			—			—		—		29			178
	1,110			1,000			—		—		13,301			19,902
	164			142			—		—		164			142
	41			39			5		5		46			643
	2,735			2,938			—		2		13,496			23,623
	1			2			—		—		698			1,202
	—			—			—		—		—			656
	—			—			457		516		457			1,182
	—			—			—		—		202			212
	—			—			14		—		1,328			—
	—			—			17		19		166			524
	2,941			3,121			493		542		16,557			28,184

Husky Energy Inc. | Consolidated Financial Statements | 16

Disaggregation of Revenue

	Integrated Corridor
($ millions)	Lloydminster Heavy Oil Value Chain				Oil Sands					Western Canada Production				U.S. Refining
Years ended December 31,	2020		2019		2020			2019		2020		2019		2020		2019
Primary Geographical Markets
Canada		3,753		5,601		306			649		367		514		—		—
United States		—		—		—			—		—		—		6,636		10,253
China		—		—		—			—		—		—		—		—
Total revenue		3,753		5,601		306			649		367		514		6,636		10,253
Major Product Lines(1)
Synthetic crude oil		981		1,495		—			—		—		—		—		—
Gasoline		—		—		—			—		—		—		3,453		5,414
Diesel & distillates		170		260		—			—		—		—		2,282		3,644
Asphalt		475		609		—			—		—		—		85		136
Total upgraded and refined products		1,626		2,364		—			—		—		—		5,820		9,194
Diluted bitumen		—		—		308			640		—		—		—		—
Blended crude oil		1,500		2,197		—			—		—		—		—		—
Light & medium crude oil		—		—		—			—		82		167		—		—
NGL		—		—		—			—		101		168		—		—
Natural gas		—		—		—			—		153		162		—		—
Total unrefined products		1,500		2,197		308			640		336		497		—		—
Other		627		1,040		(2	)		9		31		17		816		1,059
Total revenue		3,753		5,601		306			649		367		514		6,636		10,253

⁽¹⁾  Results reported for 2019 have been recast to reflect a change in reclassification of intersegment sales eliminations and a change in presentation of the Integrated Corridor and Offshore business units.

Husky Energy Inc. | Consolidated Financial Statements | 17

Disaggregation of Revenue Con’t

Integrated Corridor														Offshore				Corporate				Total
Canadian Refined Products				Eliminations						Total
2020		2019		2020			2019			2020		2019		2020		2019		2020		2019		2020		2019
	1,488		2,425		(602	)		(948	)		5,312		8,241		336		493		—		—		5,648		8,734
	—		—		—			—			6,636		10,253		—		—		—		—		6,636		10,253
	—		—		—			—			—		—		1,179		1,060		—		—		1,179		1,060
	1,488		2,425		(602	)		(948	)		11,948		18,494		1,515		1,553		—		—		13,463		20,047
	—		—		—			—			981		1,495		—		—		—		—		981		1,495
	620		904		—			—			4,073		6,318		—		—		—		—		4,073		6,318
	793		1,152		—			—			3,245		5,056		—		—		—		—		3,245		5,056
	—		—		—			—			560		745		—		—		—		—		560		745
	1,413		2,056		—			—			8,859		13,614		—		—		—		—		8,859		13,614
	—		—		—			—			308		640		—		—		—		—		308		640
	—		—		—			—			1,500		2,197		—		—		—		—		1,500		2,197
	—		—		—			—			82		167		336		493		—		—		418		660
	—		—		—			—			101		168		152		182		—		—		253		350
	—		—		—			—			153		162		1,026		875		—		—		1,179		1,037
	—		—		—			—			2,144		3,334		1,514		1,550		—		—		3,658		4,884
	75		369		—			—			1,547		2,494		1		3		—		—		1,548		2,497
	1,488		2,425		(602	)		(948	)		11,948		18,494		1,515		1,553		—		—		13,463		20,047

Husky Energy Inc. | Consolidated Financial Statements | 18

Note 2 Basis of Presentation

a) Basis of Measurement and Statement of Compliance

The consolidated financial statements have been prepared by management on a historical cost basis with some exceptions, as detailed in the accounting policies set out below in accordance with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”). These accounting policies have been applied consistently for all periods presented in these consolidated financial statements.

These consolidated financial statements were approved by the Board of Directors on February 8, 2021.

Certain prior years’ amounts have been reclassified to conform with current presentation.

b) Principles of Consolidation

The consolidated financial statements include the accounts of Husky Energy Inc. and its subsidiaries. Subsidiaries are defined as any entities, including unincorporated entities such as partnerships, for which the Company has the power to govern their financial and operating policies to obtain benefits from their activities. The Company’s accounts reflect the proportionate share of the assets, liabilities, revenues, expenses and cash flows from the Company’s activities that are conducted jointly with third parties. Intercompany balances, net earnings and unrealized gains and losses arising from intercompany transactions are eliminated in preparing the consolidated financial statements. A portion of the Company’s activities relate to joint ventures (see Note 12), which are accounted for using the equity method.

c) Use of Estimates, Judgments and Assumptions

The timely preparation of the consolidated financial statements requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies, if any, as at the date of the financial statements and the reported amounts of revenue and expenses during the period. Actual results may differ from these estimates, judgments and assumptions.

Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and on a prospective basis. By their nature, estimates are subject to measurement uncertainty and changes in such estimates in future years could require a material change in the consolidated financial statements. These underlying assumptions are based on historical experience and other factors that management believes to be reasonable under the circumstances, and are subject to change as new events occur, as more industry experience is acquired, as additional information is obtained, and as the Company’s operating environment changes. Specifically, amounts recorded for depletion, depreciation, amortization and impairment, recoveries from insurance claims, asset retirement obligations, assets and liabilities measured at fair value, employee future benefits, income taxes and reserves and contingencies are based on estimates.

Management makes judgments regarding the application of IFRS for each accounting policy. Critical judgments that have the most significant effect on the amounts recognized in the consolidated financial statements include determination of technical feasibility and commercial viability, impairment assessments, the determination of cash generating units (“CGUs”), changes in reserves estimates, the determination of a joint arrangement, the designation of the Company’s functional currency and the fair value of related party transactions.

In early March 2020, the World Health Organization declared the COVID-19 coronavirus outbreak to be a pandemic. Responses to the spread of COVID-19 have resulted in significant disruption to business operations and a significant increase in economic

Husky Energy Inc. | Consolidated Financial Statements | 19

uncertainty, with more volatile commodity prices and currency exchange rates, and a marked decline in long-term interest rates. Although economies are beginning to re-open, these events are resulting in a challenging economic climate in which it is difficult to reliably estimate the length or severity of these developments and their financial impact. The results of the potential economic downturn and any potential resulting direct and indirect impact to the Company has been considered in management’s estimates described above at the period end; however there could be a further prospective material impact in future periods.

Significant estimates, judgments and assumptions made by management in the preparation of these consolidated financial statements are outlined in detail in Note 3.

Husky Energy Inc. | Consolidated Financial Statements | 20

d) Functional and Presentation Currency

The consolidated financial statements are presented in Canadian dollars, which is the Company’s functional currency. All financial information is presented in millions of Canadian dollars, except per share amounts and unless otherwise stated.

The designation of the Company’s functional currency is a management judgment based on the currency of the primary economic environment in which the Company operates.

Note 3 Significant Accounting Policies

a) Cash and Cash Equivalents

Cash and cash equivalents consist of cash on hand less outstanding cheques and deposits with an original maturity of less than three months at the time of purchase. When outstanding cheques are in excess of cash on hand and short-term deposits, and the Company has the ability to net settle, the excess is reported in bank operating loans.

Cash and cash equivalents held that are not available for use are classified as restricted cash. When restricted cash is not expected to be used within 12 months, it is classified as a non-current asset.

b) Inventories

Crude oil, natural gas, refined petroleum products and sulphur inventories are valued at the lower of cost or net realizable value. Cost is determined using average cost or on a first-in, first-out basis, as appropriate. Materials, parts and supplies are valued at the lower of average cost or net realizable value. Cost consists of raw material, labour, direct overhead, operating costs, transportation and depreciation, depletion and amortization. Commodity inventories held for trading purposes are carried at fair value and measured at fair value less costs to sell based on Level 2 observable inputs, refer to policy Note 3 (l). Any changes in commodity trading inventory fair value are included as gains or losses in Marketing and Other in the consolidated statements of loss during the period of change. Previous inventory impairment provisions are reversed when there is a change in the condition that caused the impairment and the inventory remains on hand. Unrealized intersegment net earnings on inventory sales are eliminated.

c) Precious Metals

The Company uses precious metals in conjunction with a catalyst as part of the downstream upgrading and refining processes. These precious metals remain intact; however, there is a loss during the reclamation process. The estimated loss is amortized to production and operating expenses over the period that the precious metal is in use, which is approximately two to five years. After the reclamation process, the actual loss is compared to the estimated loss and any difference is recognized in net loss. Precious metals are included in other assets on the balance sheet.

d) Exploration and Evaluation Assets and Property, Plant and Equipment

i) Cost

Oil and gas properties and other property, plant and equipment are recorded at cost, including expenditures that are directly attributable to the purchase or development of an asset. Borrowing costs directly attributable to the acquisition, construction or production of a qualifying asset are included in the asset cost. Capitalization ceases when substantially all activities necessary to prepare the qualifying asset for its intended use are complete or when the construction and development of a project is suspended.

Husky Energy Inc. | Consolidated Financial Statements | 21

ii) Exploration and Evaluation Costs

The accounting treatment of costs incurred for oil and natural gas exploration, evaluation and development is determined by the classification of the underlying activities as either exploratory or developmental. The results from an exploration drilling program can take considerable time to analyze, and the determination that commercial reserves have been discovered requires determination of technical feasibility, commercial viability and industry experience. Exploration activities can fluctuate from year to year, due to such factors as the level of exploratory spending, the level of risk sharing with third parties participating in exploratory drilling and the degree of risk associated with drilling in particular areas. Properties that are assumed to be productive may, over a period of time, actually deliver oil and gas in quantities different than originally estimated because of changes in reservoir performance.

Husky Energy Inc. | Consolidated Financial Statements | 22

Costs incurred after the legal right to explore an area has been obtained and before technical feasibility and commercial viability of the area have been established are capitalized as exploration and evaluation assets. These costs include costs to acquire acreage and exploration rights, legal and other professional fees and land brokerage fees. Pre-license costs and geological and geophysical costs associated with exploration activities are expensed in the period incurred. Costs directly associated with an exploration well are initially capitalized as an exploration and evaluation asset until the drilling of the well is complete and the results have been evaluated. If extractable hydrocarbons are found and are likely to be developed commercially, but are subject to further appraisal activity, which may include the drilling of wells, the costs continue to be carried as an exploration and evaluation asset while sufficient and continued progress is made in assessing the commercial viability of the hydrocarbons. Capitalized exploration and evaluation costs or assets are not depreciated and are carried forward until technical feasibility and commercial viability of the area is determined or the assets are determined to be impaired. Management determines technical feasibility and commercial viability when exploration and evaluation assets are reclassified to property, plant and equipment. This decision considers several factors, including the existence of reserves, establishing commercial and technical feasibility and whether the asset can be developed using a proved development concept and has received internal approval. Upon the determination of technical feasibility and commercial viability, capitalized exploration and evaluation assets are then transferred to property, plant and equipment. All such carried costs are subject to technical, commercial and management review, as well as review for impairment indicators, at least every reporting period to confirm the continued intent to develop or otherwise extract value from the discovery. These costs are also tested for impairment when transferred to property, plant and equipment. Capitalized exploration and evaluation expenditures related to wells that do not find reserves, or where no future activity is planned, are expensed as exploration and evaluation expenses.

The application of the Company’s accounting policy for exploration and evaluation costs requires judgment in determining whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. Judgments may change as new information becomes available.

iii) Development Costs

Expenditures, including borrowing costs, on the construction, installation and completion of infrastructure facilities, such as platforms, pipelines and the drilling of development wells, are capitalized as oil and gas properties. Costs incurred to operate and maintain wells and equipment to lift oil and gas to the surface are expensed as production and operating expenses.

iv) Other Property, Plant and Equipment

Repair and maintenance costs, other than major turnaround costs, are expensed as incurred. Major turnaround costs are capitalized as part of property, plant and equipment when incurred and are amortized over the estimated period of time to the anticipated date of the next turnaround.

v) Depletion, Depreciation and Amortization

Oil and gas properties are depleted on a unit-of-production basis over the proved developed producing reserves of the particular field, except in the case of assets whose useful life is shorter or longer than the lifetime of the proved developed producing reserves of that field, in which case the straight-line method or a unit-of-production method based on total proved plus probable reserves is applied. The unit-of-production rate for the depletion of oil and gas properties related to total proved plus probable reserves takes into account expenditures incurred to date together with sanctioned future development expenditures required to develop the field.

Oil and gas reserves are evaluated internally and audited by independent qualified reserve engineers. The estimation of reserves is an inherently complex process and involves the exercise of professional judgment. Estimates are based on projected future rates of production, estimated commodity prices, operating and royalty costs, engineering data and the estimated amount and timing of future expenditures, all of which are subject to uncertainty. Changes in reserve estimates can have an impact on reported net loss through revisions to depletion, depreciation and amortization expense, in addition to determining possible impairments and reversal of impairments of property, plant and equipment.

Husky Energy Inc. | Consolidated Financial Statements | 23

Net reserves represent the Company’s undivided gross working interest in total reserves after deducting crown, freehold and overriding royalty interests. Assumptions reflect market and regulatory conditions, as applicable, as at the balance sheet date and could differ significantly from other points in time throughout the year or future periods. Changes in market and regulatory conditions and assumptions can materially impact the estimation of net reserves.

Depreciation for substantially all other property, plant and equipment is provided using the straight-line method based on the estimated useful lives of assets, which range from five to forty-five years. The useful lives of assets are estimated based upon the period the asset is expected to be available for use by the Company.

Depletion, depreciation and amortization rates for all capitalized costs associated with the Company’s activities are reviewed at least annually, or when events or conditions occur that impact capitalized costs, reserves and estimated service lives.

e) Joint Arrangements

Joint arrangements represent activities where the Company has joint control established by a contractual agreement. Joint control requires unanimous consent for financial and operational decisions. A joint arrangement is either a joint operation, whereby the parties have rights to the assets and obligations for the liabilities, or a joint venture, whereby the parties have rights to the net assets.

For a joint operation, the consolidated financial statements include the Company’s proportionate share of the assets, liabilities, revenues, expenses and cash flows of the joint arrangement. The Company reports items of a similar nature to those on the financial statements of the joint arrangement, on a line-by-line basis, from the date that joint control commences until the date that joint control ceases.

Joint ventures are accounted for using the equity method of accounting and recognized at cost and adjusted thereafter for the post-acquisition change in the Company’s share of the joint venture’s net assets. The Company’s consolidated financial statements include its share of the joint venture’s profit or loss and other comprehensive income (“OCI”) included in investment in joint ventures, until the date that joint control ceases.

Classification of a joint arrangement as either joint operation or joint venture requires judgment. Management’s considerations include, but are not limited to, determining if the arrangement is structured through a separate vehicle and whether the legal form and contractual arrangements give the entity direct rights to the assets and obligations for the liabilities within the normal course of business. Other facts and circumstances are also assessed by management, including the entity’s rights to the economic benefits of assets and its involvement and responsibility for settling liabilities associated with the arrangement.

f) Business Combinations

Business combinations are accounted for using the acquisition method. Determining whether an acquisition meets the definition of a business combination or represents an asset purchase requires judgment on a case-by-case basis. If the acquisition meets the definition of a business combination, the assets and liabilities are recognized based on the contractual terms, economic conditions, the Company’s operating and accounting policies and other factors that exist on the acquisition date, which is the date on which control is transferred to the Company. The identifiable assets and liabilities are measured at their fair values on the acquisition date with limited exceptions. Any additional consideration payable, contingent upon the occurrence of a future event, is recognized at fair value on the acquisition date; subsequent changes in the fair value of the liability are recognized in net loss. Acquisition costs incurred are expensed and included in selling, general and administrative expenses in the consolidated statements of loss.

Husky Energy Inc. | Consolidated Financial Statements | 24

g) Goodwill

Goodwill is the excess of the purchase price paid over the recognized amount of net assets acquired through business combinations, which is inherently imprecise as judgment is required in the determination of the fair value of assets and liabilities. Goodwill, which is not amortized, is assigned to appropriate CGUs or groups of CGUs. Goodwill is tested for impairment annually and when circumstances indicate that the carrying value may be impaired. Impairment losses are recognized in net loss and are not subject to reversal. On the disposal or termination of a previously acquired business, any remaining balance of associated goodwill is included in the determination of the gain or loss on disposal.

h) Impairment and Reversals of Impairment on Non-Financial Assets

The carrying amounts of the Company’s non-financial assets, other than inventories and deferred tax assets but including right-of-use assets, are reviewed at the end of each reporting period to determine whether there is an indication of impairment or reversal of previously recorded impairment. If such indication exists, the recoverable amount is estimated.

Determining whether there are any indications of impairment or impairment reversals requires significant judgment of external factors, such as an extended change in prices or margins for oil and gas commodities or refined products, a significant change in an asset’s market value, a significant revision of estimated volumes, revision of future development costs, a change in the entity’s market capitalization or significant changes in the technological, market, economic or legal environment that would have an impact on the Company’s CGUs. If any indication of impairment or impairment reversals exist, an estimate of the asset’s recoverable amount is calculated as the higher of the fair value less costs to sell (“FVLCS”) and the asset’s value in use (“VIU”) for an individual asset or CGU. If the asset does not generate cash inflows that are largely independent of those from other assets or groups of assets, the asset is tested as part of a CGU, which is the smallest identifiable group of assets, liabilities and associated goodwill that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. Determination of the Company’s CGUs is subject to management’s judgment.

FVLCS is the amount that would be obtained from the sale of a CGU in an arm’s length transaction between knowledgeable and willing parties. The FVLCS is generally determined as the net present value of the estimated future cash flows expected to arise from a CGU, including any expansion prospects, and its eventual disposal, using assumptions that an independent market participant may take into account. These cash flows are discounted using a rate that would be applied by a market participant to arrive at a net present value of the CGU, less cost to dispose.

VIU is the net present value of the estimated future cash flows expected to arise from the continued use of the asset in its present form and its eventual disposal. VIU is determined by applying assumptions specific to the Company’s continued use and can only take into account sanctioned future development costs. Estimates of future cash flows used in the evaluation of impairment of assets are made using management’s forecasts of commodity prices, royalty rates, operating costs and future capital expenditures, forecasted crack spreads, growth rate, discount rate and, in the case of oil and gas properties, expected production volumes. Expected production volumes take into account assessments of field reservoir performance and include expectations about proved and probable volumes and where applicable economically recoverable resources associated with interests in certain Husky properties which are risk-weighted utilizing geological, production, recovery, market price and economic projections. Either the cash flow estimates or the discount rate is risk-adjusted to reflect local conditions as appropriate.

Given that the calculations for recoverable amounts require the use of estimates and assumptions, including forecasts of commodity prices, marketing supply and demand, product margins and in the case of oil and gas properties, expected production volumes, it is possible that the assumptions may change, which may impact the estimated life of the CGU and may require a material adjustment to the carrying value of goodwill and non-financial assets.

Husky Energy Inc. | Consolidated Financial Statements | 25

An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses recognized with respect to CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the units and then to reduce the carrying amounts of the other assets in the CGU or group of CGUs on a pro rata basis. Impairment losses are recognized in depletion, depreciation, amortization and impairment in the consolidated statements of loss.

Impairment losses recognized in prior years are assessed at the end of each reporting period for indications that the impairment has decreased or no longer exists. An impairment loss is reversed only to the extent that the carrying amount of the asset or CGU does not exceed the carrying amount that would have been determined, net of depletion, depreciation and amortization, if no impairment loss had been recognized.

i) Asset Retirement Obligations (“ARO”)

A liability is recognized for future legal or constructive retirement obligations associated with the Company’s assets. The Company has significant obligations to remove tangible assets and restore land after operations cease and the Company retires or relinquishes the asset. The retirement of Upstream and Downstream assets consists primarily of plugging and abandoning wells, abandoning surface and subsea plant and equipment and facilities and restoring land to a state required by regulation or contract. The amount recognized is the net present value of the estimated future expenditures determined in accordance with local conditions, current technology and current regulatory requirements. The obligation is calculated using the current estimated costs to retire the asset inflated to the estimated retirement date and then discounted using a credit-adjusted risk-free discount rate. The liability is recorded in the period in which an obligation arises with a corresponding increase to the carrying value of the related asset. The liability is progressively accreted over time as the effect of discounting unwinds, creating an expense recognized in finance expenses. The costs capitalized to the related assets are amortized in a manner consistent with the depletion, depreciation and amortization of the underlying assets. Actual retirement expenditures are charged against the accumulated liability as incurred.

Liabilities for ARO are adjusted every reporting period for changes in estimates. These adjustments are accounted for as a change in the corresponding capitalized cost, except where a reduction in the provision is greater than the undepreciated capitalized cost of the related assets, in which case the capitalized cost is reduced to nil and the remaining adjustment is recognized in net loss. Changes to the amount of capitalized costs will result in an adjustment to future depletion, depreciation and amortization, and to finance expenses.

Estimating the ARO requires significant judgment as restoration technologies and costs are constantly changing, as are regulatory, political, environmental and safety considerations. Inherent in the calculation of the ARO are numerous assumptions including the ultimate settlement amounts, future third-party pricing, inflation factors, risk-free discount rates, credit risk, timing of settlement and changes in the legal, regulatory, environmental and political environments. Future revisions to these assumptions may result in material changes to the ARO liability. Adjustments to the estimated amounts and timing of future ARO cash flows are a regular occurrence in light of the significant judgments and estimates involved.

j) Legal and Other Contingent Matters

Provisions and liabilities for legal and other contingent matters are recognized in the period when the circumstance becomes probable that a future cash outflow resulting from past operations or events will occur and the amount of the cash outflow can be reasonably estimated. The timing of recognition and measurement of the provision requires the application of judgment to existing facts and circumstances, which can be subject to change, and the carrying amounts of provisions and liabilities are

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reviewed regularly and adjusted accordingly. The Company is required to both determine whether a loss is probable based on judgment and interpretation of laws and regulations, and determine that the loss can be reasonably estimated. When a loss is recognized, it is charged to net loss. The Company continually monitors known and potential contingent matters and makes appropriate disclosure and provisions when warranted by the circumstances present.

k) Share Capital

Preferred shares are classified as equity since they are cancellable and redeemable only at the Company’s option and dividends are discretionary and payable only if declared by the Board of Directors. Incremental costs directly attributable to the issuance of shares and stock options are recognized as a deduction from equity, net of tax. Common share dividends are paid out in common shares, or in cash, and preferred share dividends are paid in cash. Both common and preferred share dividends are recognized as distributions within equity.

l) Financial Instruments

Financial instruments are any contracts that give rise to a financial asset of one entity and a financial liability or equity instrument of another entity. Financial assets are classified in one of the following categories: subsequently measured at amortized cost, fair value through other comprehensive income (“FVTOCI”), or fair value through profit or loss (“FVTPL”). Financial liabilities are initially recognized at fair value, and subsequently measured based on classification in one of the following categories: subsequently measured at amortized cost and FVTPL. Financial assets and liabilities are not offset unless there is a currently enforceable legal right to offset the recognized amounts and there is an intention to settle on a net basis, to realize the assets and settle the liabilities simultaneously.

Financial assets and liabilities subsequently measured at amortized costs are measured using the effective interest method. The effective interest method is a method of calculating the amortized costs of a financial liability and of allocating interest expense over the relevant period. Transaction costs that are directly attributable to the acquisition or issue of a financial instrument are measured at amortized cost and added to the fair value initially recognized.

Financial instruments at FVTPL are stated at fair value, with any gains or losses arising on remeasurement recognized in profit or loss. Unrealized gains and losses on FVTPL financial instruments related to trading activities are recognized in marketing and other in the consolidated statements of loss, and unrealized gains and losses on all other FVTPL financial instruments are recognized in other – net. Transaction costs directly attributable to the acquisition of financial assets or liabilities at FVTPL are recognized immediately in net loss.

Financial instruments at FVTOCI are stated at fair value, with any gains or losses arising on remeasurement recognized in OCI except for impairment gains or losses and foreign exchange gains and losses.

Financial instruments subsequently revalued at fair value are further categorized using a three-level hierarchy that reflects the significance of the inputs used in determining fair value. Level 1 fair value is determined by reference to quoted prices in active markets for identical assets and liabilities. Level 2 fair value is based on inputs that are independently observable for similar assets or liabilities. Level 3 fair value is not based on independently observable market data. The disclosure of the fair value hierarchy excludes financial assets and liabilities where book value approximates fair value.

A financial asset is derecognized when the contractual rights to the cash flows from the financial asset have expired, or it transfers the contractual rights to receive the cash flows of the financial assets and the Company has transferred substantially all the risks and rewards of ownership of the financial asset. A financial liability is derecognized when the liability is extinguished, discharged, cancelled or expires.

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m) Derivative Instruments and Hedging Activities

Derivatives are financial instruments for which the fair value changes in response to market risks, require little or no initial investment and are settled at a future date. Derivative instruments are utilized by the Company to manage various market risks including volatility in commodity prices, foreign exchange rates and interest rate exposures. The Company’s policy is not to utilize derivative instruments for speculative purposes. The Company may enter into swap and other derivative transactions to hedge or mitigate the Company’s commercial risk, including derivatives that reduce risks that arise in the ordinary course of the Company’s business. The Company may choose to apply hedge accounting to derivative instruments.

The fair values of derivatives are determined using valuation models that require assumptions concerning the amount and timing of future cash flows and discount rates. These estimates are also subject to change with fluctuations in commodity prices, interest rates, foreign currency exchange rates and estimates of non-performance. When able, the Company will determine fair value by incorporating forward market prices and rates that are compared to quotes received from financial institutions to ensure reasonability. The actual settlement of a derivative instrument could differ materially from the fair value recorded and could impact future results.

i) Derivative Instruments

All derivative instruments, other than those designated as effective hedging instruments or certain non-financial derivative contracts that meet the Company’s own use requirements, are classified as FVTPL and are recorded at fair value. Gains and losses on these instruments are recorded in the consolidated statements of loss in the period they occur.

The Company may enter into commodity price contracts in order to offset fixed or floating prices with market rates to manage exposures to fluctuations in commodity prices. The estimation of the fair value of commodity derivatives incorporates forward prices and adjustments for quality or location. The related inventory is measured at fair value based on exit prices. Gains and losses from these derivative contracts, which are not designated as effective hedging instruments, are recognized in revenues or purchases of crude oil and products and are initially recorded at settlement date. Derivative instruments that have been designated as effective hedging instruments are further classified as either fair value or cash flow hedges (see “Hedging Activities”).

ii) Embedded Derivatives

Derivatives embedded within a hybrid contract containing a financial asset host are not accounted for separately, rather the whole instrument is classified as FVTPL. Derivatives embedded in other hybrid contracts are recorded separately when the economic characteristics and risks of the embedded derivative are not clearly and closely related to those of the host contract and the host contract is not measured at FVTPL. The definition of an embedded derivative is the same as freestanding derivatives. Embedded derivatives are measured at fair value with gains and losses recognized in net loss.

iii) Hedging Activities

At the inception of a derivative transaction, if the Company elects to use hedge accounting, formal designation and documentation is required. The documentation must include: identification of the hedged item or transaction, the hedging instrument, the nature of the risk being hedged, the Company’s risk management objective and strategy for undertaking the hedge and how the Company will assess the hedging instrument’s effectiveness in offsetting the exposure to changes in the hedged item.

A hedge is assessed at inception and at the end of each reporting period to ensure that it is highly effective in offsetting changes in fair values or cash flows of the hedged item. For a fair value hedge, the gain or loss from remeasuring the hedging instrument at fair value is recognized immediately in net loss with the offsetting gain or loss on the hedged item. When fair value hedge accounting is discontinued, the carrying amount of the hedging instrument is deferred and amortized to net loss over the remaining maturity of the hedged item.

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For a cash flow hedge, the effective portion of the gain or loss is recorded in OCI. Any hedge or portion of a hedge that is ineffective is immediately recognized in net loss. Hedge accounting is discontinued on a prospective basis when the hedging relationship no longer qualifies for hedge accounting. Any gain or loss on the hedging instrument resulting from the discontinuation of a cash flow hedge is deferred in OCI until the forecasted transaction date. If the forecasted transaction date is no longer expected to occur, the gain or loss is recognized in net loss in the period of discontinuation.

A net investment hedge of a foreign operation is accounted for similarly to a cash flow hedge. The Company may designate certain U.S. dollar denominated debt as a hedge of its net investment in foreign operations for which the U.S. dollar is the functional currency. The unrealized foreign exchange gains and losses arising from the translation of the debt are recorded in OCI, net of tax, and are limited to the translation gain or loss on the net investment.

n) Comprehensive Loss

Comprehensive loss consists of net loss and OCI. OCI is comprised of the change in the fair value of the effective portion of the derivatives used as hedging items in a cash flow hedge or net investment hedge, the exchange gains and losses arising from the translation of foreign operations with a functional currency that is not Canadian dollars and the actuarial gains and losses on defined benefit pension plans. Amounts included in OCI are shown net of tax. Other reserves is an equity category comprised of the cumulative amounts of OCI, relating to foreign currency translation and hedging.

o) Impairment of Financial Assets

A financial asset is assessed at the end of each reporting period to determine whether it is impaired, based on objective evidence indicating that one or more events have had a negative effect on the estimated future cash flows of that asset. Objective evidence used by the Company to assess impairment of financial assets includes quoted market prices for similar financial assets and historical collection rates.

An impairment loss with respect to a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the net present value of the estimated future cash flows discounted at the original effective interest rate, according to the expected credit loss model. Significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed for lifetime expected credit losses collectively in groups that share similar credit risk characteristics. All impairment losses are recognized in net loss. An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized.

Given that the calculations for the net present value of estimated future cash flows related to derivative financial assets require the use of estimates and assumptions, including forecasts of commodity prices, marketing supply and demand, product margins and expected production volumes, it is possible that the assumptions may change, which may require a material adjustment to the carrying value of financial assets.

p) Pensions and Other Post-employment Benefits

The Company maintains various defined contribution and defined benefit pension plans for its employees.

The cost of the pension benefits earned by employees in the defined contribution pension plans is expensed as incurred. The cost of the benefits earned by employees in the defined benefit pension plans is determined using the projected unit credit funding method. Actuarial gains and losses are recognized in retained earnings as incurred.

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The defined benefit asset or liability is comprised of the fair value of plan assets from which the obligations are to be settled and the present value of the defined benefit obligation. Plan assets are measured at fair value based on the closing bid price when there is a quoted price in an active market. Plan assets are assets that are held by a long-term employee benefit fund or qualifying insurance policies. Plan assets are not available to the Company’s creditors. The value of any defined benefit asset is restricted to the sum of any past service costs and the present value of refunds from and reductions in future contributions to the plan. Defined benefit obligations are estimated by discounting expected future payments using the year-end market rate of interest for high-quality corporate debt instruments with cash flows that match the timing and amount of expected benefit payments.

Post-retirement medical benefits are also provided to qualifying retirees. In some cases the benefits are provided through medical care plans to which the Company, the employees, the retirees and covered family members contribute. In some plans there is no funding of the benefits before retirement. These plans are recognized on the same basis as described above for the defined benefit pension plan.

The determination of the cost of the defined benefit pension plan and the other post-retirement benefit plans reflects a number of assumptions that affect the expected future benefit payments. The valuation of these plans is prepared by an independent actuary engaged by the Company. These assumptions include, but are not limited to, the estimate of expected plan investment performance, salary escalation, retirement age, attrition, future health care costs and mortality. The fair value of the plan assets is used for the purposes of calculating the expected return on plan assets

The assumptions for each pension plan are reviewed each year and are adjusted where necessary to reflect changes in fund experience and actuarial recommendations. Mortality rates are based on the latest available standard mortality tables for the individual countries concerned. The rate of return on pension plan assets is based on a projection of real long-term bond yields and an equity risk premium, which are combined with local inflation assumptions and applied to the actual asset mix of each plan. The amount of the expected return on plan assets is calculated using the expected rate of return for the year and the fair value of assets at the beginning of the year. Future salary increases are based on expected future inflation rates for the individual countries.

q) Income Taxes

Current income tax is recognized in net loss in the period unless it relates to items recognized directly to equity, including OCI, in which case the deferred income tax is also recorded in equity. Management periodically evaluates positions taken in the Company’s tax returns with respect to situations in which applicable tax regulations are subject to interpretation and reassessment and establishes provisions where appropriate.

Deferred tax is measured using the liability method on temporary differences at the reporting date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes.

Deferred tax assets and liabilities are recognized at expected tax rates in effect in the year when the asset is expected to be realized or the liability settled, based on tax rates and tax laws that have been enacted or substantively enacted at the reporting date. Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net loss in the period that the change occurs unless it relates to items recognized directly to equity, including OCI, in which case the deferred income tax is also recorded in equity. Deferred tax assets and deferred tax liabilities are offset if a legally enforceable right exists to set off current tax assets against current income tax liabilities and the deferred taxes relate to the same taxable entity and the same taxation authority.

The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. Estimates that require significant judgments are also made with respect to the timing of

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temporary difference reversals, the realizability of tax assets and in circumstances where the transaction and calculations for which the ultimate tax determination are uncertain. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management.

r) Asset Exchange Transactions

Asset exchange transactions are measured at cost if the transaction lacks commercial substance or the fair value of neither the asset received nor the asset given up is reliably measurable. Otherwise, asset exchange transactions are measured at the fair value of the asset given up, unless the fair value of the asset received is more clearly evident. If the acquired item is not measured at fair value, its cost is measured at the carrying amount of the asset given up. Gains and losses are recorded in other – net in the consolidated statements of loss in the period they occur.

s) Revenue Recognition

Revenue is recognized when the performance obligations are satisfied, and revenue can be reliably measured. Revenue is measured at the consideration specified in the contract and represents amounts receivable for goods or services provided in the normal course of business, net of discounts, customs duties and sales taxes. The Company has no obligation for returns, refunds, warranties or similar obligations. Royalties are recognized as a reduction to gross revenues.

The Company generates revenue from the following material products and services;

• Sale of crude oil, bitumen, natural gas, NGLs and synthetic crude;

• Crude oil and natural gas processing services;

• Pipeline transportation, the blending of crude oil and natural gas and the storage of crude oil, diluent and natural gas;

• Sale of refined petroleum products such as gasoline, diesel, ethanol blended fuels, asphalt and ancillary products, and production of ethanol; and

• Construction services.

Performance obligations are satisfied on the sale of crude oil, bitumen, natural gas, NGLs, synthetic crude, and refined products such as gasoline, diesel, ancillary retail products, ethanol blended fuels, asphalt, ancillary refined products, and the production of ethanol at the point in time when the products are delivered to and the title passes to the customer. Whereas the performance obligations are satisfied on the provision of services for crude oil and natural gas processing services, pipeline transportation, the blending of crude oil and natural gas, and the storage of crude oil, diluent and natural gas at the point in time when the services are provided. All sales prices are floating based upon market rates or contracted amounts, including long-term fixed pricing for Asia-Pacific natural gas. Sales, services and royalties are billed and paid on a weekly or monthly basis.

Physical exchanges of inventory are recognized as non-monetary exchanges and are reported on a net basis for swaps of similar items, as are sales and purchases made with a common counterparty as part of an arrangement similar to a physical exchange.

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Under take-or-pay contracts, the Company makes a long-term supply commitment in return for a commitment from the buyer to pay for minimum quantities, whether or not the customer takes the delivery. If a buyer has a right to get a ‘make-up’ delivery at a later date the performance obligation is not satisfied, and revenue is deferred and recognized only when the product is delivered, or the ‘make-up’ provision can no longer be made. Determining when the ‘make-up’ product can no longer be taken, or how much can no longer be taken, requires estimates of future deliveries. Changes in these estimates may result in a material difference in deferred revenue recognized. If no such option exists within the contractual terms, the performance obligation is satisfied, and revenue is recognized when the take-or-pay is triggered.

Construction revenue relates to general contractor services provided to HMLP of which the Company owns 35%. The Company acts as a general contractor for fixed price and cost-plus contracts. Revenue from fixed price contracts is recognized as performance obligations are met. Revenue from cost plus contracts are recognized as services are performed. Construction services are billed and paid monthly, or upon the completion of the project.

t) Foreign Currency

Functional currency is the currency of the primary economic environment in which the Company and its subsidiaries operate and is normally the currency in which the entity primarily generates and expends cash. The financial statements of Husky’s subsidiaries are translated into Canadian dollars, which is the presentation and functional currency of the Company. The assets and liabilities of subsidiaries whose functional currencies are other than Canadian dollars are translated into Canadian dollars at the foreign exchange rate at the balance sheet date, while revenues and expenses of such subsidiaries are translated using average monthly foreign exchange rates, which approximate the foreign exchange rates on the dates of the transactions. Foreign exchange differences arising on translation are included in OCI.

The Company’s transactions in foreign currencies are translated to the appropriate functional currency at the foreign exchange rate on the dates of the transactions. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency at the foreign exchange rate at the balance sheet date and differences arising on translation are recognized in net loss. Non-monetary assets that are measured in terms of historical cost in a foreign currency are translated using the exchange rate at the dates of the transactions.

u) Share-based Payments

In accordance with the Company’s stock option plan, stock options to acquire common shares may be granted to officers and certain other employees. The Company records compensation expense over the vesting period based on the fair value of options granted. Compensation expense is recorded in net loss as part of selling, general and administrative expenses.

The Company’s stock option plan is a tandem plan that provides the stock option holder with the right to exercise the stock option or surrender the option for a cash payment. A liability for the stock options is accrued over their vesting period and measured at fair value using the Black-Scholes option pricing model. The liability is revalued each reporting period until it is settled to reflect changes in the fair value of the options. The net change is recognized in net loss. When stock options are surrendered for cash, the cash settlement paid reduces the outstanding liability. When stock options are exercised for common shares, consideration paid by the stock option holders and the previously recognized liability associated with the stock options are recorded as share capital.

The Company’s Performance Share Unit Plan provides a time-vested award to certain officers and employees of the Company. Performance Share Units (“PSU”) entitle participants to receive cash based on the Company’s share price at the time of vesting. The amount of cash payment is contingent on the Company’s total shareholder return relative to a peer group of companies and achieving a return on capital in use (“ROCIU”) target. ROCIU equals net loss plus after-tax interest expense divided by the two-year average capital employed, less any capital invested in assets that are not in use. Net loss is adjusted for the difference

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between actual realized and budgeted commodity prices and foreign exchange rates and other actual and budgeted exceptional items. A liability for expected cash payments is accrued over the vesting period of the PSUs and is revalued at each reporting date based on the market price of the Company’s common shares and the expected vesting percentage. Upon vesting, a cash payment is made to the participants and the outstanding liability is reduced by the payment amount.

v) Loss per share

The number of basic common shares outstanding is the weighted average number of common shares outstanding for each period. Shares issued during the period are included in the weighted average number of shares from the date consideration is received. The calculation of basic loss per common share is based on net loss attributable to common shareholders divided by the weighted average number of common shares outstanding.

The number of diluted common shares outstanding is calculated using the treasury stock method, which assumes that any proceeds received from in-the-money stock options would be used to buy back common shares at the average market price for the period. The calculation of diluted loss per share is based on net loss attributable to common shareholders divided by the weighted average number of common shares outstanding adjusted for the effects of all potential dilutive common share issuances, which are comprised of common shares issuable upon exercise of stock options granted to employees. Stock options granted to employees provide the holder with the ability to settle in cash or equity. For the purposes of the diluted loss per share calculation, the Company must adjust the numerator for the more dilutive effect of cash-settlement versus equity-settlement despite how the stock options are accounted for in net loss. As a result, net loss reported based on accounting of cash-settled stock options may be adjusted for the results of equity-settlements for the purposes of determining the numerator for the diluted loss per share calculation.

w) Government Grants

Government grants are recognized when there is reasonable assurance that the grant will be received and all attached conditions will be complied with. If a grant is received but reasonable assurance and compliance with conditions is not achieved, the grant is recognized as a deferred liability until such conditions are fulfilled. When the grant relates to an expense item, it is recognized as income in the period in which the costs are incurred. Where the grant relates to an asset, it is recognized as a reduction to the net book value of the related asset and recognized in net loss in equal amounts over the expected useful life of the related asset through lower depletion, depreciation and amortization.

x) Related Party Judgments and Estimates

The Company entered into transactions and agreements in the normal course of business with certain related parties, joint arrangements and associates. Proceeds for disposition of assets to related parties are recognized at fair value, based on discounted cash flow forecast from those assets. Independent opinions of the fair value may be obtained. Changes in the assumptions used to determine these fair values may result in a material difference in the proceeds and any gain or loss on disposition.

y) Leases

Contractual arrangements, which signify a right to control the use of an identified asset for a period of time are considered leases. Each contractual arrangement is assessed to determine if the Company obtains substantially all the economic benefit from use of the identified asset. Leases for which the Company is a lessee are capitalized at the earlier of commencement of the lease term or when the asset becomes available for use, at the present value of the lease payments applying the implicit

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interest rate, if readily determined, or the Company’s incremental borrowing rate. Adjustments to the lease asset are made if the contractual arrangement includes costs to dismantle the asset or any incentives received. Generally, lease components are considered in the present value calculation, with non-lease components expensed as incurred. Leased assets are depreciated over the shorter of the estimated useful life of the asset or the lease term. The lease liability is remeasured when there is a change in future lease payments arising from a change in rate, if there is a change to the Company’s expected residual value guarantee payable, or if there are changes in the assessment for exercising a purchase, termination or extension option. If this occurs, a corresponding adjustment to the carrying value of the right-of-use asset is completed. If the carrying amount of the right-of-use asset has already been reduced to zero, the adjustment is recognized in net loss. The Company applies the recognition exemption for short-term leases 12 months or less in length, and leases for which the underlying asset is of low value. The expenses for these leases are recognized systematically over the lease term in either production, operating and transportation expense, purchases of crude oil and products or selling, general and administrative expenses.

i) Nature of Leasing Activities

Oil and Gas Properties

The Company leases offshore vessels and associated equipment for use in developing reserves on oil and gas properties. These leases vary in length and, in certain cases, expenses incurred are allocated to the carrying value of other assets in property, plant and equipment. Additionally, the Company leases land, buildings and equipment for sustainment of the Company’s upstream oil and gas operations.

Processing Transportation and Storage

The Company leases tanks with dedicated storage capacity at terminals or facilities while transporting various oil and gas products. The Company also records leases for any pipelines where the Company has a right to substantially all the economic benefits. The terms of these leases vary depending on capacity constraints by third parties and negotiations of take-or-pay arrangements. The Company also employs rail transportation, where the Company leases dedicated rail cars.

Upgrading

The Company does not have any significant leasing arrangements in the upgrading asset class.

Refining

The Company leases supply facilities and pipelines for products used in the refining process when the Company has the right to substantially all the capacity of the asset. The Company also uses rail transportation, where it enters into arrangements for dedicated rail cars.

Retail and Other

The Company leases land and buildings for its office space and retail marketing locations. The leases of office space and marketing locations typically run for approximately 10-20 years with the option to renew for additional periods. When extension options are reasonably certain to be exercised, they are included in the non-cancellable lease term at lease commencement. If there is a significant change in circumstances, extension options are reassessed. Terms and conditions are often renegotiated upon renewals to allow for operational flexibility. The Company leases dedicated tanks or facilities for storage of refined products.

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z) Recent Accounting Standards

The Company has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective.

aa) Change in Accounting Policy

The Company has not adopted any changes to material accounting policies during the fiscal year ended December 31, 2020.

Note 4 Cash and Cash Equivalents

Cash and cash equivalents at December 31, 2020 included $709 million of cash (December 31, 2019 – $327 million) and $26 million of short-term investments with original maturities less than three months at the time of purchase (December 31, 2019 – $1,448 million).

Note 5 Accounts Receivable

Accounts Receivable

($ millions)	December 31, 2020			December 31, 2019
Trade receivables		773			1,327
Provision for expected credit losses		(36	)		(34	)
Derivatives due within one year		33			38
Other(1)		349			168
End of year		1,119			1,499

⁽¹⁾  Includes insurance proceeds of $312 million (2019 – $114 million), related to the Superior Refinery incident.

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Note 6 Inventories

Inventories

($ millions)	December 31, 2020		December 31, 2019
Crude oil, natural gas and NGL		409		627
Refined petroleum products		411		553
Trading inventories measured at fair value less costs to sell		121		155
Materials, supplies and other		174		151
End of year		1,115		1,486

Impairment of inventory to net realizable value for the year ended December 31, 2020 was $7 million (December 31, 2019 – $15 million), as a result of declining market benchmark prices.

Trading inventories measured at fair value less costs to sell consist of natural gas inventories and crude oil inventories. The fair value measurement incorporates exit commodity prices and adjustments for quality and location.

Note 7 Restricted Cash

In accordance with the provisions of the regulations of the People’s Republic of China, the Company is required to deposit funds into separate accounts restricted to the funding of future asset retirement obligations in offshore China. As at December 31, 2020, the Company had deposited funds of $164 million which have been classified as non-current (2019 – $142 million).

Note 8 Exploration and Evaluation Assets

Exploration and Evaluation Assets

($ millions)	2020			2019
Beginning of year		643			997
Additions		1			46
Transfers to property, plant and equipment (note 9)		(3	)		(44	)
Expensed exploration expenditures previously capitalized		(594	)		(355	)
Exchange adjustments		(1	)		(1	)
End of year		46			643

During 2020, $439 million and $150 million (2019 - $331 million due primarily to Offshore and Western Canada Production) of the expensed exploration expenditures previously capitalized related to write-downs within the Offshore and Lloydminster Heavy Oil Value Chain business segments, respectively. The write-downs were primarily due to changes in management’s future development plans resulting from the sustained decline in forecasted crude oil prices.

The following exploration and evaluation expenses for the years ended December 31, 2020 and 2019 relate to activities associated with the exploration for and evaluation of crude oil and natural gas resources and were recorded in the Integrated Corridor and Offshore business segments.

Exploration and Evaluation Expense Summary⁽¹⁾

($ millions)	2020		2019
Seismic, geological and geophysical		117		131
Expensed drilling		612		409
Expensed land		4		7
		733		547

⁽¹⁾  Includes expensed exploration expenditures previously capitalized.

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Note 9 Property, Plant and Equipment

Property, Plant and Equipment

($ millions)	Oil and Gas Properties			Processing, Transportation and Storage			Upgrading			Refining			Retail and Other			Total
Cost
December 31, 2018		44,196			101			2,659			10,691			3,095			60,742
Transfers to right-of-use assets(1) (note 10)		(336	)		—			—			(180	)		—			(516	)
Additions		2,340			2			58			899			160			3,459
Acquisitions		10			—			—			—			—			10
Transfers from exploration and evaluation (note 8)		44			—			—			—			—			44
Transfers from right-of-use assets(2) (note 10)		101			—			—			—			—			101
Intersegment transfers		2			—			—			27			(29	)		—
Changes in asset retirement obligations (note 18)		469			1			5			19			23			517
Disposals and derecognition		(16	)		(2	)		(1	)		(943	)		(2	)		(964	)
Exchange adjustments		(223	)		(1	)		—			(496	)		(2	)		(722	)
December 31, 2019		46,587			101			2,721			10,017			3,245			62,671
Additions		852			—			216			502			70			1,640
Acquisitions		1			—			—			—			—			1
Transfers from exploration and evaluation (note 8)		3			—			—			—			—			3
Transfers from right-of-use assets(2) (note 10)		4			—			—			—			—			4
Intersegment transfers		18			41			—			—			(59	)		—
Changes in asset retirement obligations (note 18)		(530	)		—			(13	)		(51	)		(33	)		(627	)
Disposals and derecognition		(419	)		(2	)		—			(12	)		(2	)		(435	)
Exchange adjustments		(80	)		(3	)		—			64			(1	)		(20	)
December 31, 2020		46,436			137			2,924			10,520			3,220			63,237
Accumulated depletion, depreciation, amortization and impairment
December 31, 2018		(27,379	)		(50	)		(1,585	)		(3,933	)		(1,995	)		(34,942	)
Transfers to right-of-use assets(1) (note 10)		12			—			—			40			—			52
Depletion, depreciation, amortization and impairment		(4,082	)		(2	)		(115	)		(736	)		(239	)		(5,174	)
Intersegment transfers		—			—			—			(17	)		17			—
Disposals and derecognition		8			—			—			724			2			734
Exchange adjustments		93			1			—			187			1			282
December 31, 2019		(31,348	)		(51	)		(1,700	)		(3,735	)		(2,214	)		(39,048	)
Depletion, depreciation, amortization and impairment		(7,083	)		(46	)		(90	)		(3,644	)		(228	)		(11,091	)
Intersegment transfers		(9	)		—			—			—			9			—
Disposals and derecognition		380			12			—			—			1			393
Exchange adjustments		47			1			—			(44	)		1			5
December 31, 2020		(38,013	)		(84	)		(1,790	)		(7,423	)		(2,431	)		(49,741	)
Net book value
December 31, 2019		15,239			50			1,021			6,282			1,031			23,623
December 31, 2020		8,423			53			1,134			3,097			789			13,496

⁽¹⁾  Transfer to right-of-use assets due to the adoption of IFRS 16 on January 1, 2019.

⁽²⁾  Includes capitalized depreciation from right-of-use assets.

Costs of property, plant and equipment, including major development projects, not subject to depletion, depreciation and amortization as at December 31, 2020 were $2.0 billion (December 31, 2019 – $6.8 billion) including undeveloped land assets of $118 million as at December 31, 2020 (December 31, 2019 – $127 million).

Husky Energy Inc. | Consolidated Financial Statements | 37

Included in depletion, depreciation, amortization and impairment expenses for the year ended December 31, 2020 is a pre-tax impairment charge of $8,945 million on Oil and Gas Properties located at Lloydminster Heavy Oil Value Chain, Oil Sands and Western Canada within the Integrated Corridor business segment, the White Rose and Terra Nova CGUs within the Offshore business segment and Refining assets located in the U.S. Refining CGUs within the Integrated Corridor business segment (year ended December 31, 2019 - $2,584 million on CGUs located at Oil Sands, Western Canada, and US Refining within the Integrated Corridor business segment and the White Rose CGU within the Offshore business segment). The impairment charge was primarily the result of the market impact from the COVID-19 pandemic, which has resulted in declines in forecasted long-term commodity prices, refinery crack spread, reduced capital investment, management’s decision to delay capital investment in the White Rose CGU and considered market indicators including the strategic combination with Cenovus Energy Inc. The recoverable amount of the impaired CGUs was estimated based on fair value less costs to sell methodology using estimated after-tax discounted cash flows on proved plus probable reserves for the Lloydminster Heavy Oil Value Chain, Sunrise, Western Canada and Offshore CGUs and after-tax discounted cash flows based on forecasted crack spreads for refining CGUs (Level 3). The Company used an after-tax discount rate of 12% (2019 - 10%) (Level 3).

The following table summarizes impairment for each CGU within the Integrated Corridor business segment for the year ended December 31, 2020:

CGU

($ millions)	Allocated to PP&E		Allocated to right-of-use assets  (note 10)		Allocated to Goodwill (note 11)		Allocated to Joint Arrangements (note 12)		Total impairment recorded
Lloydminster Heavy Oil & Gas		270		1		—		—		271
Tucker		271		—		—		—		271
Minnedosa Ethanol Plant		42		—		—		—		42
Lloydminster Ethanol Plant		57		3		—		—		60
Husky Midstream Limited Partnership		—		—		—		606		606
Lloyd Heavy Oil Value Chain CGUs total		640		4		—		606		1,250
Northern		517		2		—		—		519
Rainbow		119		—		—		—		119
Western Canada CGUs total		636		2		—		—		638
Lima Refinery		1,203		50		669		—		1,922
BP-Husky Toledo Refinery		1,662		6		—		—		1,668
Superior Refinery		366		—		—		—		366
U.S. Refining CGUs total		3,231		56		669		—		3,956
Sunrise CGU		1,428		255		—		—		1,683
Total		5,935		317		669		606		7,527

The following table summarizes impairment for each CGU within the Offshore business segment for the year ended December 31, 2020:

CGU

($ millions)	Allocated to PP&E		Allocated to right-of-use assets (note  10)		Total impairment recorded
White Rose		2,760		94		2,854
Terra Nova		250		—		250
Total		3,010		94		3,104

The recoverable amount of the impaired CGUs with Oil and Gas Properties, at December 31, 2020, and U.S. Refining CGUs, at September 30, 2020, was $6,204 million. The recoverable amounts are sensitive to commodity prices, crack spreads, discount rate, production volumes, royalties, operating costs and future capital expenditures. Commodity prices and crack spreads are based on market indicators at the end of the period. Management’s long-term assumptions are benchmarked against forward price curves and pricing forecasts prepared by external firms.

Husky Energy Inc. | Consolidated Financial Statements | 38

The table below summarizes the forecasted prices used in determining the recoverable amounts:

	WTI ($US/bbl)		Brent ($US/bbl)		Edmonton Light ($CDN/bbl)		AECO ($CDN/mcf)		Chicago 3:2:1 Crack Spread ($US/bbl)(1)		Foreign Exchange ($USD/$CDN)
2021		47.17		49.42		55.76		2.78		12.00		0.77
2022		50.17		52.85		59.89		2.70		14.00		0.77
2023		53.17		56.04		63.48		2.61		14.00		0.76
2024		54.97		57.87		65.76		2.65		16.00		0.76
2025(2)		56.07		59.00		67.13		2.70		16.00		0.76

⁽¹⁾ Prices are based on September 30, 2020 assessment of U.S. Refining CGUs.

⁽²⁾ Prices are escalated at 2% thereafter.

The discount rate for FVLCS represents the rate a market participant would apply to the cash flows in a market transaction. The discount rate is derived from the Company’s post-tax weighted average cost of capital with appropriate adjustments made to reflect the risks specific to the CGUs. Production volumes, throughput, operating costs, royalties and future capital expenditures are based on management’s best estimates.

A change in the discount rate or forward price curve over the life of the reserves and refineries will result in the following impact on the impaired CGUs:

	Discount Rate					Commodity Price
($ millions)	1% Increase in Discount Rate		1% Decrease in Discount Rate			5% Increase in Forward Price			5% Decrease in Forward Price
Total impairment – Increase (Decrease)		599		(687	)		(1,511	)		1,530

Husky Energy Inc. | Consolidated Financial Statements | 39

Note 10 Right-of-use Assets and Lease Liabilities

Right-of-use Assets

($ millions)	Oil and Gas Properties			Processing, Transportation and Storage			Upgrading		Refining			Retail and Other			Total
January 1, 2019
Transfers from property, plant and equipment (note 9)		324			—			—		140			—			464
Initial recognition		721			100			—		70			412			1,303
		1,045			100			—		210			412			1,767
Additions		1			—			—		80			5			86
Transfers to property, plant and equipment (note 9)		(101	)		—			—		—			—			(101	)
Disposals and derecognition		(11	)		—			—		(31	)		2			(40	)
Revaluation		(194	)		1			—		(1	)		8			(186	)
Depreciation and impairment		(222	)		(11	)		—		(50	)		(39	)		(322	)
Other		2			—			—		(4	)		—			(2	)
December 31, 2019		520			90			—		204			388			1,202
Additions		5			6			—		15			4			30
Transfers to property, plant and equipment (note 9)		(4	)		—			—		—			—			(4	)
Disposals and derecognition		(3	)		—			—		—			—			(3	)
Revaluation		—			16			—		11			—			27
Depreciation and impairment		(399	)		(11	)		—		(91	)		(53	)		(554	)
Other		1			(1	)		—		—			—			—
December 31, 2020		120			100			—		139			339			698

During the year ended December 31, 2020, a pre-tax impairment charge of $411 million (year ended December 31, 2019 - $165 million) on right-of-use assets was recorded on the Lloydminster Heavy Oil Value Chain, Sunrise, Western Canada and U.S. Refining CGUs within the Integrated Corridor and White Rose CGU within Offshore business segments. Refer to Note 9.

Husky Energy Inc. | Consolidated Financial Statements | 40

Lease Liabilities

Balance Sheets

($ millions)	December 31, 2020		December 31, 2019
Current lease liabilities		102		109
Non-current lease liabilities		1,298		1,353

Husky Energy Inc. | Consolidated Financial Statements | 41

Maturity Analysis

	Within 1 year				After 1 year but no more than 5 years				More than 5 years				Total
($ millions)	2020		2019		2020		2019		2020		2019		2020		2019
Future lease payments		195		205		643		653		2,031		2,174		2,869		3,032
Interest		93		96		337		352		1,039		1,122		1,469		1,570
Present value of lease payments		102		109		306		301		992		1,052		1,400		1,462

Husky Energy Inc. | Consolidated Financial Statements | 42

Results of Operations

($ millions)	December 31, 2020		December 31, 2019
Interest expense on lease liabilities (note 22)		97		106
Expenses relating to short-term leases		13		18

Husky Energy Inc. | Consolidated Financial Statements | 43

Cash Flow Summary

($ millions)	December 31, 2020		December 31, 2019
Total cash flow used for leases		208		339

The Company’s major office building leases contain extension options that are exercisable by the Company up to one year prior to the end of the non-cancellable lease term. As at December 31, 2020, $361 million of lease liabilities related to office buildings have been recognized. Discounted potential lease payments associated with extension options not included in lease liabilities amount to $250 million.

Note 11 Goodwill

Goodwill

($ millions)	December 31, 2020			December 31, 2019
Beginning of year(1)		656			690
Exchange adjustments		13			(34	)
Impairment (note 9)		(669	)		—
End of year		—			656

⁽¹⁾ Goodwill relates to the Lima Refinery.

During the year ended December 31, 2020, the Company determined the carrying amount of the Lima Refinery CGU in the U.S. Refining segment exceeded its recoverable amount and the impairment was attributable to goodwill and physical refining assets. A pre-tax goodwill impairment charge of $669 million was included in depletion, depreciation, amortization and impairment expense for the year ended December 31, 2020. The recoverable amount of goodwill was $nil as at September 30, 2020 and estimated using the FVLCS methodology based on cash flows expected over a 50-year period and an after-tax discount rate of 12% (2019 – 9%).

Management used the FVLCS calculation for the Lima Refinery CGU, which is sensitive to changes in discount rate, forecasted crack spread and future capital expenditures. The discount rate is derived from the after-tax weighted average cost of capital, with appropriate adjustments made to reflect the risks specific to the Lima refinery.

After-tax cash flow projections for the initial 10-year period were based on management estimates of future cash flows (level 3), inflated by long-term growth rates of 1% and 2%, for future EBITDA and capital expenditures, respectively, for the remaining 40-year period. The inflation rate was based upon an average expected inflation rate for the U.S. of 2% (2019 – 2%).

Note 12 Joint Arrangements

Joint Operations

BP-Husky Refining LLC

The Company holds a 50% ownership interest in BP-Husky Refining LLC, which owns and operates the BP-Husky Toledo Refinery in Ohio.

Sunrise Oil Sands Partnership

The Company holds a 50% interest in the Sunrise Oil Sands Partnership, which is engaged in operating an oil sands project in Northern Alberta.

Husky Energy Inc. | Consolidated Financial Statements | 44

Joint Venture

Husky-CNOOC Madura Ltd.

The Company holds 40% joint control in Husky-CNOOC Madura Ltd., which is engaged in the exploration for and production of oil and gas resources in Indonesia. Results of the joint venture are included in the consolidated statements of loss in the Offshore business segment.

Summarized below is the financial information for Husky-CNOOC Madura Ltd. accounted for using the equity method:

Results of Operations

($ millions, except share of equity investment)	2020			2019
Revenues		386			424
Expenses		(280	)		(267	)
Net earnings		106			157
Share of equity investment		40	%		40	%
Proportionate share of equity investment		39			50

Balance Sheets

($ millions, except share of equity investment)	December 31, 2020			December 31, 2019
Current assets(1)		215			208
Non-current assets		1,657			1,840
Current liabilities		(77	)		(70	)
Non-current liabilities(2)		(1,160	)		(1,427	)
Net assets		635			551
Share of net assets		40	%		40	%
Carrying amount in balance sheet		457			516

⁽¹⁾  Includes cash and cash equivalents of $48 million (2019 – $42 million).

⁽²⁾  Includes deferred revenue of $8 million (2019 – $nil) related to take-or-pay commitments, with respect to natural gas production volumes from the BD Project, not taken by the purchaser. As per the terms of the agreement, the purchaser has until the end of the agreement to take these volumes.

The Company’s share of equity investment and carrying amount of share of net assets does not equal the 40% joint control of the expenses and net assets of Husky-CNOOC Madura Ltd. due to differences in the accounting policies of the joint venture and the Company and non-current liabilities of the joint venture which are not included in the Company’s carrying amount of net assets due to equity accounting.

Husky Midstream Limited Partnership

The Company holds a 35% interest in HMLP, which owns midstream assets in Alberta and Saskatchewan. The assets are held by HMLP, of which Husky owns 35%, Power Assets Holdings Ltd. (“PAH”) owns 48.75% and CK Infrastructure Holdings Ltd. (“CKI”) owns 16.25%. Results of the joint venture are included in the consolidated statements of loss in Lloydminster Heavy Oil Value Chain in the Integrated Corridor business segment.

Summarized below is the financial information for HMLP accounted for using the equity method:

Results of Operations

($ millions, except share of equity investment)	2020			2019
Revenues		322			316
Expenses		(206	)		(228	)
Net earnings		116			88
Share of equity investment		35	%		35	%
Proportionate share of equity investment(1)		(32	)		9

⁽¹⁾ As at December 31, 2020, the Company’s share of pre-tax losses relating to its investment in HMLP were $7 million (2019 – $nil) which were unrecognized as a result of the investment being fully written off in the third quarter of 2020.

Husky Energy Inc. | Consolidated Financial Statements | 45

Balance Sheet

($ millions, except share of net assets)	December 31, 2020			December 31, 2019
Current assets(1)		108			171
Non-current assets		3,075			3,031
Current liabilities		(30	)		(163	)
Non-current liabilities		(1,175	)		(1,059	)
Net assets		1,978			1,980
Share of net assets		35	%		35	%
Carrying amount in balance sheet		—			666

⁽¹⁾  Current assets include cash and cash equivalents of $30 million (2019 – $86 million).

The Company’s share of equity investment and carrying amount of share of net assets does not equal the 35% joint control of the net income and net assets of HMLP due to the potential fluctuation in the partnership profit structure.

During the year ended December 31, 2020, the Company determined the carrying amount of the investment in the HMLP joint venture in the Integrated Corridor segment exceeded its recoverable amount and the amount of impairment was attributable to the Company’s carrying amount of the investment. A pre-tax impairment charge of $606 million was included in depletion, depreciation, amortization and impairment expense for the year ended December 31, 2020. The recoverable amount was $nil as at September 30, 2020, the date of the impairment test, and was estimated using the FVLCS methodology based on cash flows expected over a 40-year period and an after-tax discount rate of 12% (Level 3).

The impairment charge was a result of sustained declines in forecasted short and long-term cash distributions. Management used the FVLCS calculation for the investment in HMLP, which is sensitive to changes in the Company’s share of net income and net assets in HMLP as a result of the partnership profit structure, future capital expenditures from the investment and discount rate. The discount rate is derived from the Company’s post-tax weighted average cost of capital, with appropriate adjustments made to reflect the risks specific to the investment. Throughput volumes, cash distributions and future capital expenditures are based on management’s best estimates.

Note 13 Income Taxes

The major components of income tax expense (recovery) for the years ended December 31, 2020 and 2019 were as follows:

Income Tax Expense (Recovery)

($ millions)	2020			2019
Current income tax
Current income tax charge		183			174
Adjustments to current income tax estimates		19			1
		202			175
Deferred income tax
Relating to origination and reversal of temporary differences		(3,248	)		(723	)
Adjustments to deferred income tax estimates		58			(251	)
		(3,190	)		(974	)

Husky Energy Inc. | Consolidated Financial Statements | 46

Included in recovery of income taxes for the year-ended December 31, 2020, was a $2,654 million deferred income tax recovery associated with the recognition of pre-tax impairment and exploration asset write-down charges of $11,220 million on Oil and Gas Properties, Refining assets, Goodwill and the investment in the HMLP joint venture.

Deferred Tax Items in OCI

($ millions)	2020			2019
Deferred tax items expensed (recovered) directly in OCI
Derivatives designated as cash flow hedges		(3	)		(3	)
Remeasurement of pension plans		(2	)		1
Exchange differences on translation of foreign operations		29			(58	)
Hedge of net investment		6			30
		30			(30	)

The provision for income taxes in the consolidated statements of loss reflects an effective tax rate which differs from the expected statutory tax rate. Differences for the years ended December 31, 2020 and 2019 were as follows:

Reconciliation of Effective Tax Rate

($ millions, except tax rate)	2020			2019
Earnings (loss) before income taxes
Canada		(8,799	)		(3,170	)
United States		(4,969	)		337
Other foreign jurisdictions		764			664
		(13,004	)		(2,169	)
Statutory Canadian income tax rate		24.9	%		26.8	%
Expected income tax		(3,238	)		(582	)
Effect on income tax resulting from:
Capital gains and losses		1			—
Foreign jurisdictions		202			61
Non-taxable items		(16	)		(25	)
Adjustments with respect to previous year		77			(250	)
Revaluation of foreign tax pools		(12	)		(4	)
Other – net		(2	)		1
Income tax recovery		(2,988	)		(799	)

The statutory tax rate is 24.9% in 2020 (2019 – 26.8%). The 2020 and 2019 tax rates changed due to a previously announced 2% decrease to the Alberta Provincial Tax rate (from 10% to 8%) that was accelerated to July 1, 2020.

The following reconciles the movements in the deferred income tax liabilities and assets:

Deferred Tax Liabilities and Assets

($ millions)	January 1, 2020			Recognized in Loss			Recognized in OCI			December 31, 2020
Deferred tax liabilities
Exploration and evaluation assets and property, plant and equipment		(3,053	)		2,578			(14	)		(489	)
Foreign exchange gains taxable on realization		(150	)		151			(4	)		(3	)
Debt issue costs		(5	)		—			—			(5	)
Financial assets at fair value		(9	)		2			—			(7	)
Other temporary differences		(152	)		51			—			(101	)
Deferred tax assets
Pension plans		16			10			2			28
Asset retirement obligations		666			(138	)		(2	)		526
Loss carry-forwards		517			536			(12	)		1,041
		(2,170	)		3,190			(30	)		990

Husky Energy Inc. | Consolidated Financial Statements | 47

Deferred Tax Liabilities and Assets

($ millions)	January 1, 2019			Recognized in Loss			Recognized in OCI			December 31, 2019
Deferred tax liabilities
Exploration and evaluation assets and property, plant and equipment		(4,089	)		967			69			(3,053	)
Foreign exchange gains taxable on realization		(174	)		51			(27	)		(150	)
Debt issue costs		(4	)		(1	)		—			(5	)
Other temporary differences		(28	)		(124	)		—			(152	)
Financial assets at fair value		(9	)		—			—			(9	)
Deferred tax assets
Pension plans		8			9			(1	)		16
Asset retirement obligations		654			16			(4	)		666
Loss carry-forwards		468			56			(7	)		517
		(3,174	)		974			30			(2,170	)

The Company has temporary differences associated with its investments in its foreign subsidiaries, branches, and interests in joint ventures. At December 31, 2020, the Company had $nil deferred tax liabilities in respect to these investments (December 31, 2019 – $nil).

At December 31, 2020, the Company recorded a net deferred tax asset of $803 million and $187 million in Canada and the United States, respectively, as it is probable that there will be sufficient future taxable profits in the various jurisdictions to utilize these deductible temporary differences. Included in such deductible temporary differences are $4,401 million (December 31, 2019 – $2,105 million) of tax losses that will expire between 2036 and 2040.

Note 14 Other Assets

Other Assets

($ millions)	December 31, 2020		December 31, 2019
Long-term receivables(1)		130		489
Precious metals		21		22
Other		15		13
End of year		166		524

⁽¹⁾  Includes insurance proceeds of $98 million (2019 – $435 million), related to the Superior Refinery incident.

For the year ended December 31, 2020, the Company accrued pre-tax recoveries for rebuild costs, incident costs and business interruption associated with the Superior Refinery incident of $85 million (December 31, 2019 - $630 million), which is included in other-net in the consolidated statements of loss.

Note 15 Bank Operating Loans

At December 31, 2020, the Company had unsecured short-term borrowing lines of credit with banks totaling $975 million⁽¹⁾ (December 31, 2019 – $900 million) and letters of credit under these lines of credit totaling $427 million (December 31, 2019 – $436 million). As at December 31, 2020, bank operating loans were $40 million (December 31, 2019 – $nil). Interest payable is based on Bankers’ Acceptance, CAD Prime Rate, U.S. LIBOR, or U.S. Base Rates.

Sunrise Oil Sands Partnership has an unsecured demand credit facility of $10 million (December 31, 2019 – $10 million) available for general purposes. The Company’s proportionate share of the credit facility is $5 million (December 31, 2019 – $5 million). As at December 31, 2020, there was no balance outstanding under this credit facility (December 31, 2019 – no balance).

⁽¹⁾  Includes $125 million demand facilities available specifically for letters of credit only.

Husky Energy Inc. | Consolidated Financial Statements | 48

Note 16 Accounts Payable and Accrued Liabilities

Accounts Payable and Accrued Liabilities

($ millions)	December 31, 2020		December 31, 2019
Trade payables		772		1,178
Accrued liabilities		1,115		1,954
Dividend payable (note 20)		13		126
Stock-based compensation		22		19
Derivatives due within one year		31		21
Other		176		167
End of year		2,129		3,465

Note 17 Debt and Credit Facilities

Short-term Debt

($ millions)	December 31, 2020		December 31, 2019
Commercial paper(1)		—		550
Bankers’ Acceptances		40		—

⁽¹⁾  The weighted average interest rate as at December 31, 2019 was 1.98% per annum.

Long-term Debt

			Canadian $ Amount						U.S. $ Denominated
			December 31, 2020			December 31, 2019			December 31, 2020		December 31, 2019
($ millions)	Maturity
Long-term debt
Syndicated Credit Facility		2022		350			—			—		—
3.95% notes(1)(3)		2022		637			648			500		500
4.00% notes(1)(3)		2024		957			973			750		750
3.55% notes(4)		2025		750			750			—		—
3.60% notes(4)		2027		750			750			—		—
3.50% notes(4)		2028		1,250			—			—		—
4.40% notes(1)(3)		2029		957			973			750		750
6.80% notes(1)(3)		2037		493			501			387		387
Debt issue costs(2)				(27	)		(25	)		—		—
Long-term debt				6,117			4,570			2,387		2,387
Long-term debt due within one year 5.00% notes(4)		2020		—			400			—		—
Long-term debt due within one year				—			400			—		—

⁽¹⁾  The U.S. dollar denominated debt is designated as a hedge of the Company’s net investment in selected foreign operations with a U.S. dollar functional currency. Refer to Note 25 for Foreign Currency Risk Management.

⁽²⁾  Calculated using the effective interest rate method.

⁽³⁾  The 3.95%, the 4.00%, the 4.40% and the 6.80% notes represent unsecured securities under a trust indenture dated September 11, 2007.

⁽⁴⁾  The 5.00%, the 3.55%, the 3.60% and the 3.50% notes represent unsecured securities under a trust indenture dated December 21, 2009.

Credit Facilities

On April 7, 2020 the Company entered into a $500 million unsecured non-revolving term credit facility. Interest payable is based on pricing referenced to CAD Bankers’ Acceptance or CAD Prime Rates. The facility was repaid on October 5, 2020.

Husky Energy Inc. | Consolidated Financial Statements | 49

As at December 31, 2020 the covenant under the Company’s credit facilities was a debt to capital ratio, calculated as total debt (long-term debt including long-term debt due within one year and short-term debt) and certain adjusting items specified in the credit agreements divided by total debt and shareholders’ equity. This covenant is used to assess the Company’s financial strength. If the Company does not comply with the covenant under the credit facilities, there is risk that repayment could be accelerated. The Company was in compliance with this covenant under its credit facilities at December 31, 2020, and assessed the risk of non-compliance to be low. As at December 31, 2020, the Company had $350 million outstanding under its $2.0 billion committed syndicated credit facility expiring June 19, 2022 (December 31, 2019 – no direct borrowings), and no direct borrowings under its $2.0 billion committed syndicated credit facility expiring March 9, 2024 (December 31, 2019 – no direct borrowings).

Interest payable is based on Bankers’ Acceptance, CAD Prime Rate, U.S. LIBOR, or U.S. Base Rates, depending on the borrowing option selected and credit ratings assigned by certain credit rating agencies to the Company.

Notes

On March 15, 2019, the Company issued US$750 million in senior unsecured notes. The notes bear an annual interest rate of 4.40% and are due on April 15, 2029. The Company raised the net proceeds of the offering for general corporate purposes, which included the repayment of certain outstanding debt securities that matured in 2019.

On May 1, 2019, the Company filed a universal short form base shelf prospectus (the “2019 Canadian Shelf Prospectus”) with applicable securities regulators in each of the provinces of Canada that enabled the Company to offer up to $3.0 billion of common shares, preferred shares, debt securities, subscription receipts, warrants and other units in Canada. As a result of the delisting of Husky’s shares from the TSX, the Company is unable to sell securities under the 2019 Canadian Shelf Prospectus.

On June 17, 2019, the Company repaid the maturing 6.15% notes. The amount paid to note holders was $402 million.

On December 16, 2019, the Company repaid the maturing 7.25% notes. The amount paid to note holders was $987 million.

On March 3, 2020, the Company filed a universal short form base shelf prospectus (the “2020 U.S. Shelf Prospectus”) with the Alberta Securities Commission. On March 4, 2020, the Company’s related U.S. registration statement filed with the SEC containing the 2020 U.S. Shelf Prospectus became effective which enabled the Company to offer up to US$3.0 billion of debt securities, common shares, preferred shares, subscription receipts, warrants and units of the Company in the U.S. During the period that the 2020 U.S. Shelf Prospectus and the related U.S registration statement were effective, securities could be offered in amounts, at prices and on terms set forth in a prospectus supplement. On January 26, 2021, the Company terminated the effectiveness of the U.S. registration statement.

On March 12, 2020, the Company repaid the maturing 5.00% notes. The principal paid to note holders was $400 million.

On August 7, 2020, the Company issued $1.25 billion of notes. The notes have a coupon of 3.50% and are due on February 7, 2028. Proceeds were for general corporate purposes, which included the repayment of Husky’s $500 million unsecured non-revolving term loan credit facility on October 5, 2020.

At December 31, 2020, the Company had unused capacity of $1.75 billion under the 2019 Canadian Shelf Prospectus and US$3.0 billion under the 2020 U.S. Shelf Prospectus and related U.S. registration statement.

The Company’s notes, credit facilities and short-term lines of credit rank equally in right of payment.

Husky Energy Inc. | Consolidated Financial Statements | 50

Reconciliation of Changes of Liabilities to Cash Flows from Financing Activities

	Liabilities
($ millions)	Short-term debt			Long-term debt due within one year			Long-term debt			Other long-term liabilities			Lease liabilities due within one year			Lease liabilities
December 31, 2019		550			400			4,570			454			109			1,353
Changes from financing cash flows
Long-term debt issuance, net		—			(1,400	)		2,600			—			—			—
Short-term debt issuance, net		(510	)		—			—			—			—			—
Debt issue costs		—			—			(7	)		—			—			—
Finance lease payments		—			—			—			—			(111	)		—
Total change from financing cash flows		(510	)		(1,400	)		2,593			—			(111	)		—
Other changes – liability-related
Foreign exchange		—			—			—			(1	)		—			—
Fair value changes		—			—			—			8			—			32
Net additions of lease liabilities		—			—			—			—			—			23
Reclassification		—			1,000			(1,000	)		—			107			(107	)
Deferred revenue		—			—			—			(115	)		—			—
Amortization of debt issuance costs		—			—			4			—			—			—
Foreign exchange recognized in OCI		—			—			(50	)		—			(1	)		(2	)
Other		—			—			—			64			(2	)		(1	)
Total other changes – liability related		—			1,000			(1,046	)		(44	)		104			(55	)
December 31, 2020		40			—			6,117			410			102			1,298

Note 18 Asset Retirement Obligations

At December 31, 2020, the estimated total undiscounted inflation-adjusted amount required to settle the Company’s ARO was $9.5 billion (December 31, 2019 – $10.0 billion). These obligations will be settled based on the useful lives of the underlying assets, which currently extend an average of 45 years (December 31, 2019 – 45 years) into the future. This amount has been discounted using credit-adjusted risk-free rates of 3.6% to 6.2% (December 31, 2019 – 3.9% to 4.4%) and an inflation rate of 2% (December 31, 2019 – 2%). Obligations related to future environmental remediation and cleanup of oil and gas assets are included in the estimated ARO.

While the provision is based on management’s best estimates of future costs, discount rates and the economic lives of the assets, there is uncertainty regarding the amount and timing of incurring these costs.

A reconciliation of the carrying amount of asset retirement obligations at December 31, 2020 and 2019 is set out below:

Asset Retirement Obligations

($ millions)	2020			2019
Beginning of year		2,755			2,424
Additions		63			76
Liabilities settled		(39	)		(276	)
Liabilities disposed		(39	)		(6	)
Change in discount rate		(544	)		285
Change in estimates		(146	)		156
Exchange adjustment		8			(10	)
Accretion (note 22)		104			106
End of year		2,162			2,755
Expected to be incurred within 1 year		94			112
Expected to be incurred beyond 1 year		2,068			2,643

Husky Energy Inc. | Consolidated Financial Statements | 51

At December 31, 2020, the Company had deposited funds of $164 million into the restricted accounts for funding of future asset retirement obligations in offshore China (December 31, 2019 – $142 million). These amounts have been classified as non-current and included in restricted cash.

Note 19 Other Long-term Liabilities

Other Long-term Liabilities

($ millions)	December 31, 2020		December 31, 2019
Employee future benefits (note 23)		233		214
Stock-based compensation		19		19
Deferred revenue		37		152
Other		121		69
End of year		410		454

Deferred revenue

Deferred revenue relates to take-or-pay commitments, with respect to natural gas production volumes from the Liwan 3-1 field in Asia Pacific, not taken by the purchaser. As per the terms of the agreement, the purchaser has until the end of the agreement to take these volumes.

($ millions)	December 31, 2020			December 31, 2019
Beginning of year		152			205
Revenue recognized		(115	)		(42	)
Exchange adjustment		—			(11	)
End of year		37			152

Note 20 Share Capital

Common Shares

The Company is authorized to issue an unlimited number of no par value common shares.

Common Shares	Number of Shares		Amount ($ millions)
December 31, 2018, 2019 and 2020		1,005,121,738		7,293

Quarterly dividends may be declared in an amount expressed in dollars per common share or could be paid by way of issuance of a fraction of a common share per outstanding common share determined by dividing the dollar amount of the dividend by the volume-weighted average trading price of the Common Shares on the principal stock exchange on which the common shares are traded. The volume-weighted average trading price of the common shares is calculated by dividing the total value by the total volume of common shares traded over the five trading day period immediately prior to the payment date of the dividend on the common shares.

Common Share Dividends

	2020				2019
($ millions)	Declared		Paid		Declared		Paid
		163		276		503		503

At December 31, 2020, Common Share dividends payable were $13 million (December 31, 2019 – $126 million).

Preferred Shares

The Company is authorized to issue an unlimited number of no par value preferred shares.

Husky Energy Inc. | Consolidated Financial Statements | 52

Cumulative Redeemable Preferred Shares	Number of Shares		Amount ($ millions)
December 31, 2018, 2019 and 2020		36,000,000		874

Cumulative Redeemable Preferred Shares Dividends

2020				2019
($ millions)	Declared		Paid		Declared		Paid
Series 1 Preferred Shares		6		6		6		6
Series 2 Preferred Shares		1		1		1		1
Series 3 Preferred Shares		12		12		12		12
Series 5 Preferred Shares		9		9		9		9
Series 7 Preferred Shares		7		7		7		7
		35		35		35		35

At December 31, 2020, Preferred Share dividends payable were $nil (December 31, 2019 – $nil).

Holders of the Cumulative Redeemable Preferred Shares, Series 1 (the ”Series 1 Preferred Shares”) are entitled to receive a cumulative quarterly fixed dividend yielding 2.404% annually for a five year period ending March 31, 2021, as and when declared by the Company’s Board of Directors. Thereafter, the dividend rate will be reset every five years at a rate equal to the five-year Government of Canada bond yield plus 1.73%. Holders of Series 1 Preferred Shares have the right, at their option, to convert their shares into Cumulative Redeemable Preferred Shares, Series 2 (the “Series 2 Preferred Shares”), subject to certain conditions, on March 31, 2021 and on March 31 every five years thereafter.

Holders of the Series 2 Preferred Shares are entitled to receive a cumulative quarterly floating rate dividend that is reset every quarter for a five year period ending March 31, 2021, as and when declared by the Company’s Board of Directors. The dividend rate applicable to the Series 2 Preferred Shares, for the three month period commencing September 30, 2020 but excluding December 31, 2020, was 1.887% based on the sum of the Government of Canada 90 day Treasury bill rate on November 24, 2020 plus 1.73%. Holders of Series 2 Preferred Shares have the right, at their option, to convert their shares into Series 1 Preferred Shares, subject to certain conditions, on March 31, 2021 and on March 31 every five years thereafter.

Holders of the Cumulative Redeemable Preferred Shares, Series 3 (the ”Series 3 Preferred Shares”) are entitled to receive a cumulative quarterly fixed dividend yielding 4.689% annually for the initial period ending December 31, 2024 as and when declared by the Company’s Board of Directors. Thereafter, the dividend rate will be reset every five years at the rate equal to the five-year Government of Canada bond yield plus 3.13%. Holders of Series 3 Preferred Shares will have the right, at their option, to convert their shares into Cumulative Redeemable Preferred Shares, Series 4 (the ”Series 4 Preferred Shares”), subject to certain conditions, on December 31, 2024 and on December 31 every five years thereafter. Holders of the Series 4 Preferred Shares will be entitled to receive cumulative quarterly floating dividends at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 3.13%.

On March 2, 2020, the Company announced that it did not intend to exercise its right to redeem its Cumulative Redeemable Preferred Shares, Series 5 (the “Series 5 Preferred Shares”) on March 31, 2020. As a result, subject to certain conditions, the holders of Series 5 Preferred Shares were notified of their right to choose one of the following options with regard to their shares: retain any or all of their Series 5 Preferred Shares and continue to receive an annual fixed-rate dividend paid quarterly; or convert, on a one-for-one basis, any or all of their Series 5 Preferred Shares into Cumulative Redeemable Preferred Shares, Series 6 (the “Series 6 Preferred Shares”) of Husky Energy and receive a floating rate quarterly dividend. In March 2020, 40,800 Series 5 Preferred Shares were tendered for conversion, which is less than the one million shares required to give effect to conversions into Series 6 Preferred Shares. As a result, none of the Series 5 Preferred Shares were converted into Series 6 Preferred Shares on March 31, 2020. The new annual fixed-rate dividend applicable to the Series 5 Preferred Shares for the five-year period commencing March 31, 2020, to, but excluding, March 31, 2025 is 4.591%, being equal to the sum of the Government of Canada five-year bond yield of 1.021% plus 3.57% in accordance with the terms of the Series 5 Preferred Shares.

Husky Energy Inc. | Consolidated Financial Statements | 53

On June 1, 2020, the Company announced that it did not intend to exercise its right to redeem its Cumulative Redeemable Preferred Shares, Series 7 (the “Series 7 Preferred Shares”) on June 30, 2020. As a result, subject to certain conditions, the holders of Series 7 Preferred Shares were notified of their right to choose one of the following options with regard to their shares: retain any or all of their Series 7 Preferred Shares and continue to receive an annual fixed-rate dividend paid quarterly; or convert, on a one-for-one basis, any or all of their Series 7 Preferred Shares into Cumulative Redeemable Preferred Shares, Series 8 (the “Series 8 Preferred Shares”) of Husky Energy and receive a floating rate quarterly dividend. In June 2020, 212,461 Series 7 Preferred Shares were tendered for conversion, which is less than the one million shares required to give effect to conversions into Series 8 Preferred Shares. As a result, none of the Series 7 Preferred Shares were converted into Series 8 Preferred Shares on June 30, 2020. The new annual fixed-rate dividend applicable to the Series 7 Preferred Shares for the five-year period commencing June 30, 2020, to, but excluding, June 30, 2025 is 3.935%, being equal to the sum of the Government of Canada five-year bond yield of 0.415% plus 3.52% in accordance with the terms of the Series 7 Preferred Shares.

Stock Option Plan

Pursuant to the Incentive Stock Option Plan (the “Option Plan”), the Company may grant from time to time to executive officers and certain employees of the Company options to purchase common shares of the Company. The term of each option is five years, and vests one-third on each of the first three anniversary dates from the grant date. The Option Plan provides the option holder with the right to exercise the option to acquire one common share at the exercise price or surrender the option for a cash payment. The exercise price of the option is equal to the weighted average trading price of the Company’s common shares during the five trading days prior to the grant date. When the stock option is surrendered to the Company, the cash payment is equal to the excess of the aggregate fair market value of the common shares able to be purchased pursuant to the vested and exercisable portion of such stock options on the date of surrender over the aggregate exercise price for those common shares pursuant to those stock options. The fair market value of common shares is calculated as the closing price of the common shares on the date on which board lots of common shares have traded immediately preceding the date a holder of the stock options provides notice to the Company that they wish to surrender their stock options to the Company in lieu of exercise.

Included in accounts payable and accrued liabilities and other long-term liabilities in the consolidated balance sheets at December 31, 2020 was $13 million (December 31, 2019 – $4 million) representing the estimated fair value of options outstanding. The total expense recognized in selling, general and administrative expenses in the consolidated statements of loss for the Option Plan for the year ended December 31, 2020 was $9 million (December 31, 2019 – recovery of $6 million). At December 31, 2020, the intrinsic value of stock options exercisable for cash was $9 million (December 31, 2019 – less than one million).

The following options to purchase common shares have been awarded to officers and certain other employees:

Outstanding and Exercisable Options

	2020					2019
	Number of Options (thousands)			Weighted Average Exercise Prices ($)		Number of Options (thousands)			Weighted Average Exercise Prices ($)
Outstanding, beginning of year		18,498			17.75		19,967			21.48
Granted(1)		6,113			2.86		4,241			14.31
Surrendered for cash		—			—		(4	)		15.67
Expired or forfeited		(5,728	)		20.78		(5,706	)		28.27
Outstanding, end of year		18,883			12.01		18,498			17.75
Exercisable, end of year		9,651			16.11		10,596			19.27

⁽¹⁾  Options granted during the year ended December 31, 2020 were attributed a fair value of $0.36 per option (December 31, 2019 – $2.34) at grant date.

Husky Energy Inc. | Consolidated Financial Statements | 54

Outstanding and Exercisable Options

	Outstanding Options						Exercisable Options
Range of Exercise Price	Number of Options (thousands)		Weighted Average Exercise Prices ($)		Weighted Average Contractual Life (years)		Number of Options (thousands)		Weighted Average Exercise Prices ($)
$2.77 - $8.00		5,650		2.85		4.17		—		—
$8.01 - $15.92		6,085		14.88		1.92		3,802		15.22
$15.93 - $21.87		7,148		16.80		1.69		5,849		16.70
December 31, 2020		18,883		12.01		2.51		9,651		16.11

The fair value of the share options is estimated at each reporting date using the Black-Scholes option pricing model, taking into account the terms and conditions upon which the share options are granted and for the performance options, the current likelihood of achieving the specified target. The following table lists the assumptions used in the Black-Scholes option pricing model for the share options and performance options:

Black-Scholes Assumptions

	December 31, 2020		December 31, 2019
	Tandem Options		Tandem Options
Dividend per option		0.21		0.42
Range of expected volatilities used (percent)		47.2 - 90.2		27.5 - 35.5
Range of risk-free interest rates used (percent)		0.06 - 0.39		1.66 - 1.74
Expected life of share options from vesting date (years)		1.99		1.97
Expected forfeiture rate (percent)		8.6		8.8
Weighted average exercise price		13.71		18.19
Weighted average fair value		0.87		0.25

The expected life of the share options is based on historical data and current expectations and is not necessarily indicative of exercise patterns that may occur. The expected volatility reflects the assumption that the historical volatility over a period similar to the expected life of the options is indicative of future trends, which may also not necessarily be the actual outcome.

Performance Share Units

The Company has a Performance Share Unit Plan for executive officers and certain employees of the Company. The term of each PSU is three years, and the PSU vests on the second and third anniversary dates of the grant date in percentages determined by the Compensation Committee based on the Company’s total shareholder return relative to a peer group of companies and achieving a ROCIU target set by the Company. ROCIU equals net loss plus after-tax interest expense divided by the two-year average capital employed, less any capital invested in assets that are not in use. Net loss is adjusted for the difference between actual realized and budgeted commodity prices and foreign exchange rates and other actual and budgeted exceptional items. Upon vesting, PSU holders receive a cash payment equal to the number of vested PSUs multiplied by the weighted average trading price of the Company’s common shares for the five preceding trading days. As at December 31, 2020, the carrying amount of the liability relating to PSUs was $29 million (December 31, 2019 – $34 million). The total expense recognized in selling, general and administrative expenses in the consolidated statements of loss for the PSUs for the year ended December 31, 2020 was $7 million (2019 – $4 million). The Company paid out $12 million (2019 – $34 million) for performance share units which vested in the year. The weighted average contractual life of the PSUs at December 31, 2020 was two years (December 31, 2019 – two years).

Husky Energy Inc. | Consolidated Financial Statements | 55

The number of PSUs outstanding was as follows:

Performance Share Units	2020			2019
Beginning of year		14,318,642			11,606,644
Granted		10,828,280			7,673,960
Exercised		(2,111,552	)		(2,429,816	)
Forfeited		(3,735,485	)		(2,532,146	)
Outstanding, end of year		19,299,885			14,318,642
Vested, end of year		4,621,999			3,264,840

Loss per Share

Loss per Share

($ millions)	2020			2019
Net loss		(10,016	)		(1,370	)
Effect of dividends declared on preferred shares in the year		(35	)		(35	)
Net loss – basic		(10,051	)		(1,405	)
Dilutive effect of accounting for stock options		4			(15	)
Net loss – diluted		(10,047	)		(1,420	)
(millions)
Weighted average common shares outstanding – basic		1,005.1			1,005.1
Weighted average common shares outstanding – diluted		1,005.1			1,005.1
Loss per share – basic ($/share)		(10.00	)		(1.40	)
Loss per share – diluted ($/share)		(10.00	)		(1.41	)

For the year ended December 31, 2020, 13 million tandem options (2019 – 18 million) were excluded from the calculation of diluted loss per share as these options were anti-dilutive.

Note 21 Production, Operating and Transportation and Selling, General and Administrative Expenses

The following table summarizes production, operating and transportation expenses in the consolidated statements of loss for the years ended December 31, 2020 and 2019:

Production, Operating and Transportation Expenses

($ millions)	2020		2019
Services and support costs		1,119		1,255
Salaries and benefits		576		773
Materials, equipment rentals and leases		191		250
Energy and utility		476		482
Licensing fees		160		204
Transportation		18		17
Other		20		49
Total production, operating and transportation expenses(1)		2,560		3,030

⁽¹⁾ Results reported for 2019 have been recast to reflect various reclassifications due to a change in presentation of the Integrated Corridor and Offshore business units.

Husky Energy Inc. | Consolidated Financial Statements | 56

The following table summarizes selling, general and administrative expenses in the consolidated statements of loss for the years ended December 31, 2020 and 2019:

Selling, General and Administrative Expenses

($ millions)	2020		2019
Employee costs(1)		443		450
Stock-based compensation expense (recovery)(2)		16		(2	)
Contract services		128		133
Equipment rentals and leases		16		11
Maintenance and other		142		101
Total selling, general and administrative expenses		745		693

⁽¹⁾  Employee costs are comprised of salary and benefits earned during the year, plus cash bonuses awarded during the year. Annual bonus awards settled in shares are included in stock-based compensation expense.

⁽²⁾  Stock-based compensation expense represents the cost to the Company for participation in share-based payment plans.

Note 22 Financial Items

Financial Items

($ millions)	2020			2019
Foreign exchange gain
Non-cash working capital		7			17
Other foreign exchange		7			27
Net foreign exchange gain		14			44
Finance income		25			74
Finance expenses
Long-term debt		(251	)		(310	)
Lease liabilities (note 10)		(97	)		(106	)
Other		(7	)		(6	)
		(355	)		(422	)
Interest capitalized(1)		60			177
		(295	)		(245	)
Accretion of asset retirement obligations (note 18)		(104	)		(106	)
Finance expenses		(399	)		(351	)
Total Financial Items		(360	)		(233	)

⁽¹⁾  Interest capitalized on project costs is calculated using the Company’s annualized effective interest rate of 3% (2019 – 5%).

Note 23 Pensions and Other Post-employment Benefits

The Company currently provides defined contribution pension plans for all qualified employees and other post-employment benefit plans to its retirees. The other post-employment benefit plans provide certain retired employees with health care and dental benefits. The Company also maintains one defined benefit pension plan, which is closed to new entrants. The defined benefit pension plan provides pension benefits to certain employees based on years of service and final average earnings. The amount and timing of funding of this plan is subject to the funding policy as approved by the Board of Directors.

The measurement date of all plan assets and the accrued benefit obligations was December 31, 2020. The Company is required to file an actuarial valuation of its defined benefit pension with the provincial or state regulator at least every three years. The most recent actuarial valuation was December 31, 2019 for the U.S defined benefit plan. The most recent actuarial valuation was April 30, 2018 for the Canadian Other Post-employment benefit plan. The most recent actuarial valuation of the U.S. Other Post-employment benefit plan was January 18, 2019.

Defined Contribution Pension Plan

During the year ended December 31, 2020, the Company recognized a $56 million expense (2019 – $59 million) for the defined contribution and U.S. 401(k) plans in net loss.

Husky Energy Inc. | Consolidated Financial Statements | 57

Defined Benefit Pension Plans (“DB Pension Plan”) and Other Post-employment Benefit Plans (“OPEB Plans”)

Defined Benefit Obligations

	DB Pension Plans						OPEB Plans
($ millions)	2020			2019			2020			2019
Beginning of year		39			79			201			199
Current service cost		—			—			9			10
Interest cost		1			2			6			7
Benefits paid		(2	)		(3	)		(5	)		(4	)
Past service cost		—			3			—			(29	)
Settlements		—			(49	)		—			—
Remeasurements
Actuarial gain – experience		—			—			(1	)		(1	)
Actuarial loss – financial assumptions		4			9			14			20
Effect of changes in foreign exchange rates		(1	)		(2	)		—			(1	)
End of year		41			39			224			201

Fair Value of Plan Assets

	DB Pension Plans						OPEB Plans
($ millions)	2020			2019			2020			2019
Beginning of year		31			71			—			—
Contributions by employer		—			(1	)		3			2
Benefits paid		(2	)		(3	)		(3	)		(2	)
Interest income		1			2			—			—
Return on plan assets greater than discount rate		3			16			—			—
Settlements		—			(52	)		—			—
Effect of changes in foreign exchange rates		(1	)		(2	)		—			—
End of year		32			31			—			—

Funded status

	DB Pension Plans						OPEB Plans
($ millions)	2020			2019			2020			2019
Net liability		(9	)		(8	)		(224	)		(201	)

The Company has accrued the total net liability for the DB Pension Plan and the OPEB Plans in the consolidated balance sheets in other long-term liabilities.

On July 25, 2019, the Company completed the transaction related to the Canadian DB Pension Plan initiated on July 25, 2017. The transaction settled the remaining service costs for active plan members, thereby settling the defined benefit obligation related to active plan members. This resulted in the Company recognizing a $5 million actuarial gain (net of tax of $1 million) in other comprehensive loss in 2019.

The composition of the DB Pension Plan assets at December 31, 2020 and 2019 was as follows:

DB Pension Plan Assets

(percent)	Target allocation range		2020		2019
Money market type funds		—		—		—
Equity securities		35		35		35
Debt securities		65		65		65

Husky Energy Inc. | Consolidated Financial Statements | 58

The following table summarizes amounts recognized in net loss and OCI for the DB Pension Plans and the OPEB Plans for the years ended December 31, 2020 and 2019:

	DB Pension Plans						OPEB Plans
($ millions)	2020			2019			2020			2019
Amounts recognized in net loss
Current service cost		—			—			9			10
Past service cost		—			3			—			(29	)
Net Interest cost		—			—			6			7
Benefit cost		—			3			15			(12	)
Remeasurements
Actuarial gain due to liability experience		—			—			(1	)		(1	)
Actuarial loss due to liability assumption changes		4			9			14			20
Gain on plan assets		(3	)		(16	)		—			—
Remeasurement effects recognized in OCI		1			(7	)		13			19

The following long-term assumptions were used to estimate the value of the defined benefit obligations, the plan assets and the OPEB Plans:

Assumptions

	DB Pension Plans				OPEB Plans
(percent)	2020		2019		2020		2019
Discount rate for benefit expense and obligation		0.8 - 3.2		2.3 - 4.2		2.5 - 3.2		3.0 - 3.7
Rate of compensation expense		3.5		3.5		N/A		N/A

The average health care cost trend rate used for the benefit expense for the Canadian OPEB Plan was 6.0% for 2018, 2019 and 2020, grading 0.5% per year for 2 years to 5.0% in 2022 and thereafter. The average health care cost trend rate used for the obligation related to the Canadian OPEB Plan was 6.0% for 2018, 2019 and 2020, grading 0.5% per year for 2 years to 5.0% in 2022 and thereafter.

The average health care cost trend rate used for the benefit expense for the U.S. OPEB Plan was 6.5% for 2018, grading 0.25% per year for 6 years to 5.0% per year in 2026 and thereafter. The average health care cost trend rate used for the obligation related to the U.S. OPEB Plan was 6.5% for 2019 and 2020, grading 0.25% per year for 6 years to 5.0% in 2026 and thereafter.

The sensitivity of the defined benefit and OPEB obligations to changes in relevant actuarial assumption is shown below:

Sensitivity Analysis

	DB Pension Plans					OPEB Plans
($ millions)	1% increase			1% decrease		1% increase			1% decrease
Discount rate		(5	)		6		(25	)		31
Health care cost trend rate		N/A			N/A		25			(22	)

Note 24 Cash Flows – Change in Non-cash Working Capital

Non-cash Working Capital

($ millions)	2020			2019
Decrease (increase) in non-cash working capital
Accounts receivable		724			(176	)
Inventories		377			(502	)
Prepaid expenses		(14	)		(30	)
Accounts payable and accrued liabilities		(1,152	)		604
Change in non-cash working capital		(65	)		(104	)
Relating to:
Operating activities		347			(280	)
Financing activities		11			3
Investing activities		(423	)		173

Husky Energy Inc. | Consolidated Financial Statements | 59

Note 25 Financial Instruments and Risk Management

Financial Instruments

The Company’s financial instruments include cash and cash equivalents, accounts receivable, restricted cash, accounts payable and accrued liabilities, short-term debt, long-term debt, derivatives, portions of other assets, lease liabilities and other long-term liabilities. Derivative instruments are measured at fair value through profit or loss (”FVTPL”). The Company’s remaining financial instruments are measured at amortized cost. For financial instruments measured at amortized cost, the carrying values approximate their fair value with the exception of long-term debt.

The following table summarizes the Company’s financial instruments that are carried at fair value in the consolidated balance sheets:

Financial Instruments at Fair Value

($ millions)	December 31, 2020			December 31, 2019
Commodity contracts – FVTPL
Natural gas(1)		33			31
Crude oil(2)		8			11
Crude oil call options(3)		(23	)		(2	)
Crude oil put options(3)		8			(4	)
Foreign currency contracts – FVTPL
Foreign currency forwards		—			2
Other assets – FVTPL		1			1
End of year		27			39

⁽¹⁾  Natural gas contracts includes a $25 million increase at December 31, 2020 (December 31, 2019 – $4 million decrease) to the fair value of held-for-trading inventory, recognized in the consolidated balance sheets, related to third party physical purchase and sale contracts for natural gas held in storage. Total fair value of the related natural gas storage inventory was $37 million at December 31, 2020 (December 31, 2019 – $19 million).

⁽²⁾  Crude oil contracts includes a $5 million increase at December 31, 2020 (December 31, 2019 – $12 million increase) to the fair value of held-for-trading inventory, recognized in the consolidated balance sheets, related to third party crude oil physical purchase and sale contracts. Total fair value of the related crude oil inventory was $84 million at December 31, 2020 (December 31, 2019 – $136 million).

⁽³⁾  Excludes net unsettled premiums of $12 million.

The fair value of long-term debt represents the present value of future cash flows associated with the debt. Market information, such as treasury rates and credit spreads, are used to determine the appropriate discount rates. These fair value determinations are compared to quotes received from financial institutions to ensure reasonability. At December 31, 2020, the carrying value of the Company’s long-term debt was $6.1 billion and the estimated fair value was $6.6 billion (December 31, 2019 – carrying value of $5.0 billion, estimated fair value of $5.3 billion).

All financial assets and liabilities are classified as Level 2 fair value measurements, except commodity put and call options under a short-term hedging program, which are classified as Level 1 fair value measurements as they are determined using quoted market prices. During the year ended December 31, 2020, there were no transfers between Level 1 and Level 2 fair value measurements, and no transfers into or out of Level 3 fair value measurements.

Risk Management Overview

The Company is exposed to risks related to the volatility of commodity prices, foreign exchange rates and interest rates. It is also exposed to financial risks related to liquidity, credit and contract risks. The current challenging economic climate has significantly increased the Company’s exposure to these risks. Governments and central banks have reacted with significant monetary and fiscal interventions designed to stabilize economic conditions; however, the success of these interventions is

Husky Energy Inc. | Consolidated Financial Statements | 60

not currently determinable. Risk management strategies and policies are employed to ensure that any exposures to risk are in compliance with the Company’s business objectives and risk tolerance levels. Responsibility for the oversight of risk management is held by the Company’s Board of Directors and is implemented and monitored by senior management within the Company.

a) Market Risk

i) Commodity Price Risk Management

The Company uses derivative commodity instruments to manage exposure to price volatility on a portion of its crude oil and natural gas production, and it also uses firm commitments for the purchase or sale of crude oil and natural gas. These contracts meet the definition of a derivative instrument and have been recorded at their fair value in accounts receivable, inventory, other assets, accounts payable and accrued liabilities and other long-term liabilities. All derivatives are measured at fair value through profit or loss other than non-financial derivative contracts that meet the Company’s own use requirements.

At December 31, 2020, the Company was party to crude oil purchase and sale derivative contracts to mitigate its exposure to fluctuations in the benchmark price between the time a sales agreement is entered into and the time inventory is delivered. The Company was also party to third party physical natural gas purchase and sale derivative contracts in order to mitigate commodity price fluctuations. For the year ended December 31, 2020, the net unrealized loss recognized on the derivative contracts was $1 million (2019 – net unrealized loss of $38 million).

During the year ended December 31, 2020, the Company continued a commodity short-term hedging program using put and call options to manage risks related to volatility of commodity prices.

Western Texas Intermediate Crude Oil Call and Put Option Contracts

Type	Transaction	Term	Volume (bbls/day)		Price (US/$bbl)(1)
Call options	Sold	January - March 2021		82,337		48.11
Put options	Bought	January - March 2021		95,380		41.25
Put options	Sold	January - March 2021		6,522		37.00

⁽¹⁾ Prices reported are the weighted average prices for the period.

For the year ended December 31, 2020, the Company incurred an unrealized loss of $9 million (December 31, 2019 – $6 million). For the year ended December 31, 2020, the Company incurred a realized gain of $88 million (December 31, 2019 – $16 million). These amounts are recorded in other – net in the consolidated statements of loss.

II) Foreign Exchange Risk Management

The Company’s results are affected by the exchange rates between various currencies and the Company’s functional currency in Canadian dollars. As the majority of the Company’s revenues are denominated in U.S. dollars or based upon a U.S. benchmark price, fluctuations in the value of the Canadian dollar relative to the U.S. dollar may affect revenues significantly. To limit the exposure to foreign exchange risk, the Company hedges against these fluctuations by entering into short-dated foreign exchange contracts to fix the exchange rate for conversion of U.S. revenue dollars.

Foreign exchange fluctuations will result in a change in value of the U.S. dollar denominated debt and related finance expense when expressed in Canadian dollars. At December 31, 2020, the Company had designated US $2.4 billion denominated debt as a hedge of the Company’s selected net investments in its foreign operations with a U.S. dollar functional currency (December 31, 2019 – US$2.4 billion). For the year ended December 31, 2020, the unrealized gain arising from the translation of the debt was $44 million (December 31, 2019 – unrealized gain of $146 million), net of tax expense of $6 million (December 31, 2019 – expense of $30 million), which was recorded in hedge of net investment within OCI.

Husky Energy Inc. | Consolidated Financial Statements | 61

III) Interest Rate Risk Management

The Company is exposed to fluctuations in short-term interest rates as the Company maintains a portion of its debt capacity in revolving and floating rate bank facilities and invests surplus cash in short-term debt instruments and money market instruments. The Company is also exposed to interest rate risk when fixed rate debt instruments are maturing and require refinancing or when new debt capital needs to be raised.

By maintaining a mix of both fixed and floating rate debt, the Company mitigates some of its exposure to interest rate changes. The optimal mix maintained will depend on market conditions. The Company may also enter into fair value or cash flow hedges using interest rate swaps.

IV) Offsetting Financial Assets and Liabilities

The tables below outline the financial assets and financial liabilities that are subject to set-off rights and related arrangements, and the effect of those rights and arrangements on the consolidated balance sheets:

Offsetting Financial Assets and Liabilities

	As at December 31, 2020
($ millions)	Gross Amount			Amount Offset			Net Amount
Financial Assets
Financial derivatives		69			(51	)		18
Normal purchase and sale agreements		391			(311	)		80
End of year		460			(362	)		98
Financial Liabilities
Financial derivatives		(116	)		87			(29	)
Normal purchase and sale agreements		(540	)		307			(233	)
End of year		(656	)		394			(262	)

Offsetting Financial Assets and Liabilities

	As at December 31, 2019
($ millions)	Gross Amount			Amount Offset			Net Amount
Financial Assets
Financial derivatives		79			(26	)		53
Normal purchase and sale agreements		817			(274	)		543
End of year		896			(300	)		596
Financial Liabilities
Financial derivatives		(48	)		25			(23	)
Normal purchase and sale agreements		(843	)		281			(562	)
End of year		(891	)		306			(585	)

V) Market Risk Sensitivity Analysis

A sensitivity analysis for commodities and foreign currency exchange risks has been calculated by increasing or decreasing commodity prices or foreign currency exchange rates, as appropriate. These sensitivities represent the increase or decrease in loss before income taxes resulting from changing the relevant rates, with all other variables held constant. These sensitivities have only been applied to financial instruments held at fair value. The Company’s process for determining these sensitivities has not changed during the year.

Commodity Price Risk⁽¹⁾

($ millions)	10% price increase			10% price decrease
Crude oil price		(8	)		8
Natural gas price		(2	)		2

⁽¹⁾  Based on average crude oil and natural gas market prices as at December 31, 2020.

Husky Energy Inc. | Consolidated Financial Statements | 62

b) Financial Risk

i) Liquidity Risk Management

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. The Company’s processes for managing liquidity risk include ensuring, to the extent possible, that it has access to multiple sources of capital including cash and cash equivalents, cash from operating activities, undrawn credit facilities and capacity to raise capital from various debt and equity capital markets under its shelf prospectuses. The Company prepares annual capital expenditure budgets, which are monitored and updated as required. In addition, the Company requires authorizations for expenditures on projects, which assists with the management of capital.

Since the Company operates in the oil and gas industry, it requires significant cash to fund capital programs necessary to maintain or increase production, develop reserves, acquire strategic oil and gas assets and repay maturing debt. The Company’s capital programs have been funded principally by cash provided from operating activities and issuances of debt and equity. During times of low oil and gas prices, a portion of capital programs can generally be deferred. However, due to the long cycle times and the importance to future cash flow of maintaining the Company’s production, it may be necessary to utilize alternative sources of capital to continue the Company’s strategic investment plan during periods of low commodity prices. As a result, the Company frequently evaluates the options available with respect to sources of short and long-term capital resources. Occasionally, the Company will economically hedge a portion of its production to protect cash flow in the event of commodity price declines.

The Company had the following available credit facilities as at December 31, 2020:

Credit Facilities

($ millions)	Available		Unused
Operating facilities(1) (note 15)		975		508
Syndicated bank facilities(2) (note 17)		4,000		3,650
End of year		4,975		4,158

⁽¹⁾  Consists of demand credit facilities.

⁽²⁾  Commercial paper outstanding is supported by the Company’s Syndicated credit facilities.

In addition to the credit facilities listed above, the Company had unused capacity under the Canadian Shelf Prospectus of $1.75 billion and unused capacity under the U.S Shelf Prospectus and related U.S registration statement of US$3.0 billion. The ability of the Company to raise additional capital utilizing these Shelf Prospectuses is dependent on market conditions.

The Company believes it has sufficient funding through the use of these facilities and access to the capital markets to meet its future capital requirements.

ii) Credit and Contract Risk Management

Credit and contract risk represent the financial loss that the Company would suffer if a counterparty in a transaction fails to meet its obligations in accordance with the agreed terms. The Company actively manages its exposure to credit and contract execution risk from both a customer and a supplier perspective. The Company’s accounts receivables are broad based with customers in the energy industry and midstream and end user segments and are subject to normal industry risks. The Company’s policy to mitigate credit risk includes granting credit limits consistent with the financial strength of the counterparties and customers, requiring financial assurances as deemed necessary, reducing the amount and duration of credit exposures and close monitoring of all accounts. The Company is closely monitoring counterparty and customer risk in the current economic climate. The Company had one external customer that constituted more than 10% of gross revenues during the years ended December 31, 2020 and December 31, 2019. Sales to this customer were approximately $2.3 billion for the year ended December 31, 2020 (December 31, 2019 – $3.9 billion).

Husky Energy Inc. | Consolidated Financial Statements | 63

Cash and cash equivalents include cash bank balances and short-term deposits maturing in less than three months. The Company manages the credit exposure related to short-term investments by monitoring exposures daily on a per issuer basis relative to predefined investment limits.

The carrying amounts of cash and cash equivalents, accounts receivable and restricted cash represent the Company’s maximum credit exposure.

The Company’s accounts receivable was aged as follows at December 31, 2020:

Accounts Receivable Aging

($ millions)	December 31, 2020
Current		1,076
Past due (1 - 30 days)		63
Past due (31 - 60 days)		4
Past due (61 - 90 days)		3
Past due (more than 90 days)		9
Provision for expected credit losses		(36	)
		1,119

The Company recognizes a valuation provision when collection of accounts receivable is in doubt. Accounts receivable are impaired directly when collection is no longer expected. For the year ended December 31, 2020, the Company wrote off $1 million (December 31, 2019 – $4 million) of uncollectible receivables.

Note 26 Government Grants

For year ended December 31, 2020, the Company recorded pre-tax recoveries for the Canadian Emergency Wage Subsidy of $82 million (December 31, 2019 – $nil), which is included in other-net in the consolidated statements of loss.

Note 27 Related Party Transactions

The following table lists the Company’s significant subsidiaries and jointly-controlled entities and their respective places of incorporation, continuance or organization, as the case may be, and the Company’s percentage equity interest (to the nearest whole number) as at December 31, 2020. All of the entities listed below, except as otherwise indicated, are 100% beneficially owned, or controlled or directed, directly or indirectly, by the Company.

Significant Subsidiaries and Joint Operations	%		Jurisdiction
Husky Oil Operations Limited		100		Alberta
Husky Energy International Corporation		100		Alberta
Lima Refining Company		100		Delaware
Husky Marketing and Supply Company		100		Delaware
Husky Oil Limited Partnership		100		Alberta
Husky Canadian Petroleum Marketing Partnership		100		Alberta
Husky Energy Marketing Partnership		100		Alberta
Sunrise Oil Sands Partnership		50		Alberta
BP-Husky Refining LLC		50		Delaware

Husky Energy Inc. | Consolidated Financial Statements | 64

The Company performs management services as the operator of the assets held by HMLP for which it recovers shared service costs. The Company is also the contractor for HMLP and constructs its assets on a cost recovery basis with certain restrictions. HMLP charges an access fee to the Company for the use of its pipeline systems in performing the Company’s blending business, and the Company also pays for transportation and storage services. These transactions were related party transactions as of December 31, 2020, as the Company has a 35% ownership interest in HMLP and the remaining ownership interests in HMLP belong to PAH and CKI, which are affiliates of one of the Company’s principal shareholders prior to the completion of the business combination with Cenovus. For the year ended December 31, 2020, the Company charged HMLP $250 million (December 31, 2019 – $424 million) related to construction costs and management services. For the year ended December 31, 2020, the Company had purchases from HMLP of $239 million (December 31, 2019 – $219 million) related to the use of the pipeline for the Company’s blending activities, transportation and storage activities, received distributions of $144 million (December 31, 2019 – $94 million) and paid capital contributions of $83 million (December 31, 2019 – $37 million). At December 31, 2020, the Company had $23 million due from HMLP, of which $10 million relates to unbilled revenue from construction contracts (December 31, 2019 – $143 million and $nil, respectively). At December 31, 2020, the Company had $20 million due to HMLP (December 31, 2019 – $16 million).

Key management includes Directors (executive and non-executive), Executive Officers and Senior Vice Presidents of the Company. The amounts disclosed in the table below are the amounts recognized as an expense during the reporting period related to key management personnel:

Compensation of Key Management Personnel

($ millions)	2020		2019
Short-term employee benefits(1)		15		18
Stock-based compensation(2)		15		26
		30		44

⁽¹⁾  Short-term employee benefits are comprised of salary and benefits earned during the year, plus cash bonuses awarded during the year. Annual bonus awards settled in shares are included in stock-based compensation expense.

⁽²⁾  Stock-based compensation expense represents the cost to the Company for participation in share-based payment plans.

Note 28 Commitments and Contingencies

At December 31, 2020, the Company had commitments that require the following minimum future payments, which are not accrued in the consolidated balance sheets:

Minimum Future Payments for Commitments

($ millions)	Within 1 year		After 1 year but not more than 5 years		More than 5 years		Total
Operating agreements(1)		97		381		525		1,003
Firm transportation agreements(1)(4)		552		2,396		4,473		7,421
Unconditional purchase obligations(2)		1,766		3,327		3,324		8,417
Lease rentals and exploration work agreements		74		244		838		1,156
Obligations to fund equity investee(3)		54		319		280		653
		2,543		6,667		9,440		18,650

⁽¹⁾  Included in operating agreements and firm transportation agreements are blending and storage agreements and transportation commitments of $1.2 billion and $1.7 billion respectively with HMLP.

⁽²⁾  Includes processing services, distribution services, insurance premiums, drilling services, natural gas purchases and the purchase of refined petroleum products.

⁽³⁾  Equity investee refers to the Company’s investment in Husky-CNOOC Madura Ltd. joint venture, which is accounted for under the equity method for consolidated financial statement purposes^.

⁽⁴⁾  Includes transportation commitments of $1.7 billion (2019 – $1.6 billion) that are subject to regulatory approval or have been approved, but are not yet in service. Terms are up to 20 years subsequent to the date of commencement.

Husky Energy Inc. | Consolidated Financial Statements | 65

The Company has income tax and royalty filings that are subject to audit and potential reassessment. The findings may impact the liabilities of the Company. The final results are not reasonably determinable at this time, and management believes that it has adequately provided for current and deferred income taxes.

The Company is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company’s favour, the Company does not currently believe that the outcome of adverse decisions in any pending or threatened proceedings related to these and other matters would have a material adverse impact on its financial position, results of operations or liquidity.

Note 29 Capital Disclosures

The Company’s objectives when managing capital are to maintain a flexible capital structure, which optimizes the cost of capital at acceptable risk, and to maintain investor, creditor and market confidence to sustain the future development of the business. The Company manages its capital structure and makes adjustments as economic conditions and the risk characteristics of its underlying assets change. The Company considers its capital structure to include shareholders’ equity and debt which was $13.2 billion as at December 31, 2020 (December 31, 2019 – $22.8 billion). To maintain or adjust the capital structure, the Company may, from time to time, issue shares, raise or paydown debt and/or adjust its capital spending to manage its current and projected debt levels.

The Company monitors its financing requirements and capital structure using, among other things, non-GAAP financial metrics consisting of debt to capital employed and debt to funds from operations. Debt to capital employed is defined as long-term debt, long-term debt due within one year, and short-term debt divided by capital employed which is equal to long-term debt, long-term debt due within one year, short-term debt and shareholders’ equity. Debt to funds from operations is defined as long-term debt, long-term debt due within one year and short-term debt divided by funds from operations which is equal to cash flow – operating activities excluding change in non-cash working capital.

At December 31, 2020, debt to capital employed was 46.6% (December 31, 2019 – 24.2%) and debt to funds from operations was 12.5 times (December 31, 2019 – 1.7 times). The Company is subject to a leverage covenant in its credit facilities that limits debt to capital (subject to specific definitions in the credit agreements) to less than 65%, temporarily increased to 75% until the intended amalgamation of the Company and Cenovus is completed. The Company is in compliance with this covenant and considers the risk of non-compliance low. The Company also targets a debt to funds from operations ratio of less than 2.0 times over the longer term.

To facilitate the management of these ratios, the Company prepared annual budgets, which are updated depending on varying factors such as general market conditions and successful capital deployment.

There were no changes in the Company’s approach to capital management from the previous year.

Note 30 Subsequent Event

On January 4, 2021 the Company announced the transaction to strategically combine with Cenovus had closed on January 1, 2021.

The transaction was completed through a definitive arrangement agreement announced on October 25, 2020 under which Cenovus and Husky agreed to combine in an all-stock transaction. Pursuant to the transaction agreement, Husky common shareholders received 0.7845 of a Cenovus common share and 0.0651 of a Cenovus common share purchase warrant in exchange for each Husky common share. In addition, Husky preferred shareholders exchanged each Husky preferred share for one Cenovus preferred share with substantially identical terms.

Husky Energy Inc. | Consolidated Financial Statements | 66

Husky common shares and preferred shares were delisted by the TSX at the close of market on January 5, 2021.

In accordance with the terms of the Husky PSU plan, all PSUs as at January 1, 2021 were fully vested and paid out. The amount paid out in January 2021 was $122 million.

Husky Energy Inc. | Consolidated Financial Statements | 67

Document C

Form 40-F

Management’s Discussion and Analysis

MANAGEMENT’S DISCUSSION AND ANALYSIS

1.0 Financial Summary

Selected Annual Information ($ millions, except where indicated)	2020			2019			2018(1)
Gross revenues and Marketing and other(1)		13,492			20,225			22,587
Net earnings (loss) by business segment
Integrated Corridor(2)		(7,195	)		(567	)		1,269
Offshore(3)		(2,419	)		(693	)		523
Corporate		(402	)		(110	)		(335	)
Net earnings (loss)		(10,016	)		(1,370	)		1,457
Net earnings (loss) per share – basic		(10.00	)		(1.40	)		1.41
Net earnings (loss) per share – diluted		(10.00	)		(1.41	)		1.40
Cash flow – operating activities		841			2,971			4,134
Funds from operations(4)		494			3,251			4,004
Ordinary dividends per common share declared during the year		0.1625			0.5000			0.4500
Dividends per cumulative redeemable preferred share, series 1		0.60			0.60			0.60
Dividends per cumulative redeemable preferred share, series 2		0.66			0.85			0.74
Dividends per cumulative redeemable preferred share, series 3		1.17			1.13			1.13
Dividends per cumulative redeemable preferred share, series 5		1.14			1.13			1.13
Dividends per cumulative redeemable preferred share, series 7		1.07			1.15			1.15
Total assets		19,687			33,122			35,225
Total debt(5)		6,157			5,520			5,747
Net debt(5)		5,422			3,745			2,881

⁽¹⁾ Gross revenues and Marketing and other results reported for 2019 have been recast to reflect a change in reclassification of intersegment sales eliminations and a change in presentation of Integrated Corridor and Offshore business units. The results for 2018 have not been recast for this change.

⁽²⁾ The Integrated Corridor business segment includes Lloydminster Heavy Oil Value Chain, Oil Sands, Western Canada Production, U.S. Refining and Canadian Refined Products.

⁽³⁾ The Offshore business segment includes Asia Pacific and Atlantic.

⁽⁴⁾ Funds from operations is a non-GAAP measure. Refer to Section 9.3 for a reconciliation to the corresponding GAAP measure.

⁽⁵⁾ Total debt is a non-GAAP measure that equals the sum of long-term debt, long-term debt due within one year and short-term debt. Net debt is a non-GAAP measure that equals total debt less cash and cash equivalents. Refer to Section 9.3 for reconciliations to the corresponding GAAP measures.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 1

2.0 Husky Business Overview

Husky Energy Inc. (“Husky” or the “Company”) is a Canadian integrated energy company and is based in Calgary, Alberta. The Company’s common shares were listed on the Toronto Stock Exchange (“TSX”) under the symbol “HSE” and the Cumulative Redeemable Preferred Shares Series 1, Series 2, Series 3, Series 5 and Series 7 were listed under the symbols “HSE.PR.A”, “HSE.PR.B”, “HSE.PR.C”, “HSE.PR.E” and “HSE.PR.G”, respectively. The Company operates in Canada, the United States and the Asia Pacific region with Integrated Corridor and Offshore business units (as such terms are defined below).

On January 4, 2021, Husky announced the transaction to strategically combine with Cenovus Energy Inc. (“Cenovus”) had closed (the “Cenovus Transaction”). The Cenovus Transaction was completed through a definitive arrangement agreement under which Cenovus and Husky agreed to combine in an all-stock transaction. Pursuant to the transaction agreement, Husky common shareholders received 0.7845 of a Cenovus common share and 0.0651 of a Cenovus common share purchase warrant in exchange for each Husky common share. In addition, Husky preferred shareholders exchanged each Husky preferred share for one Cenovus preferred share with substantially identical terms. Husky’s common shares and preferred shares were delisted by the TSX at the close of market on January 5, 2021. The combined company operates as Cenovus Energy Inc.

This MD&A is for the year ended December 31, 2020, and is in respect of Husky and its consolidated entities and considers the completion of the Cenovus Transaction.

2.1 Corporate Strategy

The Company has two main businesses: (i) an integrated Canada-U.S. upstream and downstream corridor (“Integrated Corridor”); and (ii) production located offshore the east coast of Canada (“Atlantic”) and offshore China and Indonesia (“Asia Pacific” and with Atlantic, collectively “Offshore”). Husky has prudently managed its business during the COVID-19 pandemic, focused on safe and reliable operations, strong capital discipline with reinforced liquidity, and the implementation of sustainable cost saving measures.

Integrated Corridor

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

The Lloydminster Heavy Oil Value Chain includes the exploration for, and development and production of, heavy crude oil and bitumen, and 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 Keystone pipeline and other pipelines to be sold in the U.S. downstream market. Heavy crude oil can be upgraded at the Company’s Lloydminster upgrading and asphalt refining complex into synthetic crude oil, diesel fuel and asphalt. This business also includes the marketing and transportation of both the Company’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 the Company’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. The Company 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.

The Oil Sands business includes the exploration for, and development and production of, bitumen within the Sunrise Energy Project. It also includes the marketing and transportation of the Company’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 natural gas liquids (“NGL”) in Western Canada. The Company’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.

The U.S. Refining business includes the refining of crude oil at the Lima Refinery, the BP-Husky Toledo Refinery and the Superior Refinery in the U.S. Midwest to produce diesel fuel, gasoline, jet fuel, asphalt and other products. The Company 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 its own and third-party volumes of refined petroleum products, including gasoline and diesel, through petroleum outlets.

Offshore

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

2.2 Operations Overview and 2020 Highlights

Integrated Corridor Operations Overview

Lloydminster Heavy Oil Value Chain

Thermal Developments

The Company has an inventory of Saskatchewan thermal projects. These long-life developments are built with modular, repeatable designs and require low sustaining capital once brought online. Late in the first quarter of 2020, market conditions changed materially due to both the COVID-19 pandemic and falling commodity prices. Given the flexible nature of these projects, the Company ramped down activity on all future thermal projects.

Lloydminster thermal production and Tucker thermal production have been ramped up to full rates following a deliberate ramp down late in the first quarter of 2020 in response to market conditions. A planned turnaround began at the Tucker Thermal Project in September and was completed in mid-October.

Lloydminster Thermal Projects

The following table shows major projects and their status as at December 31, 2020:

Project Name	Nameplate Capacity (bbls/day)		Expected Project Production Date		Project Status
Spruce Lake Central		10,000		On Production	First oil was achieved on August 26, 2020 with design capacity reached in early December.
Spruce Lake North		10,000		2024	Central Processing Facility (“CPF”) is 81% complete. CPF construction has been placed on hold. Overall project is 69% complete.

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The remaining projects were placed on hold due to deteriorating market conditions in 2020 and are undergoing re-evaluation of production options to maximize value.

Cold Heavy Oil Production

Production in Cold and Enhanced Oil Recovery (“EOR”) consists of a combination of production technologies including cold heavy oil production with sand (“CHOPS”) operations with an active optimization program as well as using waterflooding and polymer injection technology.

Production remained low through the end of 2020, compared to 2019, following a deliberate ramp down which began late in the first quarter of 2020 in response to market conditions.

Upgrading

The Upgrader produces synthetic crude oil, diluent and ultra-low sulphur diesel. Synthetic crude oil is used as refinery feedstock for the production of transportation fuels in Canada and the U.S. In addition, the Upgrader recovers diluent, which is blended with the heavy crude oil and bitumen prior to pipeline transportation to reduce viscosity and facilitate its movement, and returns it to the field to be reused.

The planned maintenance turnaround for the Upgrader was completed in October. During the turnaround, additional projects were completed that increased crude throughput capacity to 81,500 bbls/day and increased diesel production capacity from 6,000 bbls/day to 10,000 bbls/day.

Lloydminster Asphalt Refinery

The Asphalt Refinery in Lloydminster, Alberta, has a throughput capacity of 30,000 bbls/day and is integrated with the local heavy crude oil and bitumen production, as well as transportation and upgrading infrastructure. The Company is the largest marketer of paving asphalt in Western Canada.

Ethanol Plants

The Company is the largest producer of ethanol in Western Canada. The Company has two ethanol plants, one in Lloydminster,

Saskatchewan and one in Minnedosa, Manitoba, with a combined capacity of 260 million litres per year.

Husky Midstream Limited Partnership

Husky Midstream Limited Partnership (“HMLP”) has approximately 2,200 kilometres of pipeline in the Lloydminster region, storage at Hardisty and Lloydminster, and other ancillary assets. The pipeline systems transport blended heavy crude oil to Lloydminster, accessing markets through the Upgrader and the 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. The Hardisty Terminal acts as the exclusive blending hub for Western Canada Select, the largest heavy crude oil benchmark pricing point in North America. HMLP has diversified its operations with the Ansell Corser Gas Plant, with 120 mmcf/day of processing capacity.

Saskatchewan Gathering System Expansion

A multi-year expansion program that will provide transportation of diluent and heavy crude oil blend for additional thermal plants has been suspended. Construction is complete on the Spruce Lake Central phase of the program.

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Hardisty Tanks

Construction is complete on 1.5 mmbbls of incremental storage at the Hardisty Terminal and this new capacity has been put into service.

Oil Sands

Production at the Sunrise Energy Project has ramped up to full rates. A planned second quarter turnaround at Plant 1B has been deferred to 2021.

Western Canada Production

Production was impacted by the shut-in of uneconomic production late in the first quarter of 2020 in response to market conditions. Activity can be ramped up as conditions allow.

U.S. Refining

Lima Refinery

The Lima Refinery in Ohio has a crude oil throughput capacity of 175,000 bbls/day and produces low sulphur gasoline, gasoline blend stocks, ultra-low sulphur diesel, jet fuel, petrochemical feedstock and other by-products.

The crude oil flexibility project was commissioned during the first quarter of 2020 and is designed to allow for the processing of up to 40,000 bbls/day of heavy crude oil feedstock from Western Canada, providing the ability to swing between light and heavy crude oil feedstock.

Throughput volumes continue to be optimized in line with market conditions.

BP-Husky Toledo Refinery

The BP-Husky Toledo Refinery in Ohio has a nameplate throughput capacity of 160,000 bbls/day and produces low sulphur gasoline, ultra-low sulphur diesel, aviation fuels, and by-products. The crude oil refinery is owned 50% by the Company and 50% by BP Products North America Inc. (“BP”), and is operated by BP.

Throughput volumes continue to be optimized in line with market conditions.

Superior Refinery

On April 26, 2018, the Superior Refinery experienced an incident while preparing for a major turnaround and was taken out of operation. The rebuild is ongoing and the Company anticipates a substantial portion of the investment will be recovered from property damage insurance. The refinery is being rebuilt with a nameplate processing capacity of 49,000 bbls/day, including capability to process up to 34,000 bbls/day of heavy crude oil while producing asphalt, gasoline and diesel.

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Canadian Refined Products

The Company is a major regional motor fuel marketer with an average of 549 retail marketing locations in 2020, including bulk plants and travel centres, with strategic land positions in Western Canada and Ontario.

On April 20, 2020, the Company announced it has suspended the strategic review of its Canadian Retail and Commercial Fuels Network due to the market environment.

Offshore Operations Overview

Asia Pacific

China

Block 29/26

Construction work was completed during the third quarter of 2020 at the Liuhua 29-1 field, the third deepwater gas field of the Liwan Gas Project. First gas production and sales from the development started in November 2020. This seven well subsea development has been fully built and installed. It utilizes the existing Liwan gas gathering system, the facilities located on the central processing platform and the Gaolan onshore gas plant. The gas buyer began taking 40 mmcf/day (30 mmcf/day Husky working interest) on November 4, 2020 and gas liquids sales began the same month. The gas sales ramped up to 47 mmcf/day (35 mmcf/day Husky working interest) starting in 2021. The Company’s share of revenues from this field reflects its 75% working interest plus exploration cost recovery. CNOOC Limited holds the remaining 25% working interest. The project was completed ahead of schedule and below the budgeted cost.

An amendment to the gas sales agreement for the Liwan 3-1 field was executed in the third quarter of 2020. The amendment is effective from August 1, 2020 until April 30, 2022, and has the effect of increasing the volume of gas the buyer must take or pay during the term, and lowering the effective price of this gas. Following April 30, 2022, the original gas sales agreement terms will take effect. Husky anticipates no material impact to its cash flow from the Liwan 3-1 field as a result.

Block 15/33

During the third quarter of 2020, an agreement was signed between the Company and CNOOC Limited to extend the end of the second phase of the exploration period of the petroleum contract to December 31, 2021. This will allow for additional drilling and testing on the shallow water block planned for 2021.

The Company is the operator of the block with a working interest of 100% during the exploration phase. In the event of a commercial discovery, CNOOC Limited may assume a participating partnership interest of up to 51% during the development phase. Under the Production Sharing Contracts (“PSC”), the corresponding share of exploration costs is to be recovered from production allocated to the Company.

Block 16/25

An agreement was signed between the Company and CNOOC Limited in the third quarter of 2020 to extend the first phase of the exploration period to April 30, 2022, relinquish the contract area of Block 16/25 and to drill the second obligatory exploration well of the first phase of the exploration period at another selected exploration PSC area.

Block 23/07 and 22/11

The Company and CNOOC Limited signed PSCs for Block 22/11 and Block 23/07 in the Beibu Gulf area of the South China Sea in 2018. The Company entered into the second exploration phase of two years in the first quarter of 2020, and committed to drill one exploration well before November 30, 2021. Block 22/11 was relinquished in the first quarter of 2020.

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The Company is the operator of Block 23/07 with a working interest of 100% during the exploration phase. In the event of a commercial discovery, CNOOC Limited may assume a participating partnership interest of up to 51% during the development phase. Under the PSC, the corresponding share of exploration costs is to be recovered from production allocated to the Company.

Indonesia

Madura Strait

At the MDA and MBH fields, the Indonesian government regulatory body approved amendments to the Floating Production Unit (“FPU”) construction contract to facilitate third party financing. The contracting consortium has ordered long lead equipment and is completing shipyard selection while they finalize financing for FPU construction. Pending completion of financing and construction of the vessel, gas production and sales are expected to begin in 2022. An additional shallow water field, MDK, is scheduled to be developed via a separate platform and tied into the MDA and MBH infrastructure.

At the stand-alone MAC field development, tendering for engineering, procurement and construction of all required facilities was completed early in the first quarter of 2020. Tendering for the Mobile Offshore Production Unit is in progress and a final investment decision is expected in 2021.

In Indonesia, the government regulatory body has made provisions for certain industrial gas buyers to have their gas purchase price reduced as a subsidy for certain utilities. The result is that the sales price of gas from a portion of the BD field gas production has been reduced, however, the government is compensating the affected PSC contractors by way of lower royalty payments. Husky anticipates no material impact to its cash flow from the BD field as a result.

Anugerah

An analysis of previously acquired data and data from offset blocks indicated that exploratory drilling would not be economic. Therefore, this block was relinquished in February 2020 with no further commitments.

Atlantic

White Rose Field and Satellite Extensions

In early September 2020, the Company announced a review of the West White Rose Project. Major construction was suspended in March 2020 due to impacts related to the global COVID-19 pandemic and most activities will remain suspended in 2021. Options beyond 2021 continue to be evaluated. The project is approximately 60% complete.

Offshore Newfoundland and Labrador, the SeaRose FPSO vessel remained in production at the White Rose field with enhanced screening provisions and physical distancing measures for site workers.

A 14-day planned maintenance turnaround was safely and successfully completed on the SeaRose FPSO during the third quarter of 2020.

Terra Nova Field

The Terra Nova FPSO is being preserved quayside as the operator and partners determine next steps. Production operations at the Terra Nova field have been suspended since December 2019.

Exploration

In October 2020, the Canada-Newfoundland and Labrador Offshore Petroleum Board issued a Significant Discovery Licence for the Harpoon O-85 well.

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Actual Production and Throughput

The following table shows actual daily production and throughput for 2020 and 2019.

Production & Throughput	2020		2019
Integrated Corridor (mboe/day)
Lloydminster Heavy Oil Value Chain
Lloydminster Thermal Projects		81.0		80.5
Tucker Thermal Project		18.3		23.7
Cold Heavy Oil Production/Enhanced Oil Recovery		24.7		34.4
Oil Sands		22.4		24.6
Western Canada Production		57.6		66.7
Integrated Corridor total (mboe/day)		204.0		229.9
Offshore (mboe/day)
Asia Pacific(1)		50.4		43.8
Atlantic		17.6		16.4
Offshore total (mboe/day)		68.0		60.2
Total production (mboe/day)		272.0		290.1
Light & medium crude oil (mbbls/day)		24.8		25.0
NGL (mbbls/day)		21.2		22.6
Heavy crude oil & bitumen (mbbls/day)		143.2		159.0
Conventional natural gas (mmcf/day)		496.9		500.9
Total production (mboe/day)		272.0		290.1
Upgrading		63.8		74.9
Lloydminster Refinery		28.0		26.4
Prince George Refinery		—		7.2
Lima Refinery		138.2		136.4
BP-Husky Toledo Refinery		65.4		63.1
Superior Refinery		—		—
Total throughput (mbbls/day)		295.4		308.0

⁽¹⁾ Includes Husky’s working interest production from the BD Project (40%). Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for consolidated financial statement purposes.

Integrated Corridor

During the year ended December 31, 2020, production decreased primarily due to:

• the safe and orderly reduction, or shut-in, of production beginning in March 2020 to align with changing market conditions; and

• the planned turnaround at the Tucker Thermal Project during the third and fourth quarter of 2020.

Partially offset by:

• Lloydminster thermal projects ramping up to full rates by late in the third quarter of 2020 and the Spruce Lake Central thermal project reaching design capacity in early December 2020; and

• the Tucker Thermal Project and Oil Sands ramping up to full rates by the fourth quarter of 2020.

During the year ended December 31, 2020, throughput decreased primarily due to:

• optimization of the Lima Refinery’s, the BP-Husky Toledo Refinery’s and the Upgrader’s operating rates in line with market demand for refined products;

• the planned turnaround at the Upgrader completed in October 2020; and

• the sale of the Prince George refinery completed on November 1, 2019.

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Partially offset by:

• the planned turnaround at the BP-Husky Toledo Refinery during the second and third quarters of 2019; and

• the planned turnaround at the Lima Refinery during the third and fourth quarters of 2019.

Offshore

During the year ended December 31, 2020, Offshore production increased primarily due to:

• higher production from the Liwan Gas Project, including commencement of production at Liuhua 29-1 in November 2020; and

• higher production from the White Rose field, which resumed full production in mid-August 2019.

Partially offset by:

• lower production from the Terra Nova field due to suspended operations.

Production and Throughput Guidance

The following table shows the updated and previous issued production and throughput guidance for 2020.

	Updated Guidance(1)		Previous Guidance(1)
Production & Throughput Guidance	March 12, 2020		December 2, 2019
Upstream production (mboe/day)		275 - 300		295 - 310
Downstream throughput (mbbls/day)		320 - 340		320 - 340

⁽¹⁾ Includes curtailment allowance of 5,000 bbls/day in first half of 2020

On April 20, 2020, the Company announced that Integrated Corridor production was being aligned with upgrading and refining requirements as throughput was optimized in line with the changing market conditions. As a result, no further updated production and throughput guidance for 2020 was provided.

Actual Capital Expenditures

The following table shows actual capital expenditures for 2020 and 2019.

Capital Expenditures(1)(2) ($ millions)	2020		2019
Integrated Corridor
Lloydminster Heavy Oil Value Chain		594		956
Oil Sands		9		38
Western Canada Production		57		194
U.S. Refining(3)		489		768
Canadian Refined Products		5		73
		1,154		2,029
Offshore
Asia Pacific(4)		123		347
Atlantic		245		925
		368		1,272
Corporate		65		131
Total		1,587		3,432

⁽¹⁾ Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the period.

⁽²⁾ Includes capital expenditures used for exploration, development and acquisitions.

⁽³⁾ Includes Superior Refinery rebuild capital.

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⁽⁴⁾ Capital expenditures in Asia Pacific exclude amounts related to the Husky-CNOOC Madura Ltd. joint venture, which is accounted for under the equity method for consolidated financial statement purposes.

Integrated Corridor Operations

Lloydminster Heavy Oil Value Chain

During 2020, $594 million (36%) was invested in the Lloydminster Heavy Oil Value Chain compared to $956 million (28%) in 2019. Capital expenditures in 2020 related primarily to construction work at the Spruce Lake Central and Spruce Lake North thermal projects, and the turnaround at the Upgrader.

Oil Sands

During 2020, $9 million (1%) was invested in Oil Sands compared to $38 million (1%) in 2019. Capital expenditures in 2020 related primarily to sustainment activities.

Western Canada Production

During 2020, $57 million (4%) was invested in Western Canada Production compared to $194 million (6%) in 2019. Capital expenditures in 2020 related primarily to resource play development targeting the Spirit River Formation at Ansell and the Montney Formation at Wembley.

U.S. Refining

During 2020, $489 million (31%) was invested in U.S. Refining compared to $768 million (22%) in 2019. Capital expenditures in 2020 related primarily to the ongoing rebuild of the Superior Refinery and the crude oil flexibility project at the Lima Refinery, which was commissioned during the first quarter of 2020.

Canadian Refined Products

During 2020, $5 million (1%) was invested in Canadian Refined Products compared to $73 million (2%) in 2019. Capital expenditures in 2019 related primarily to a planned turnaround at the Prince George Refinery, which was sold in the fourth quarter of 2019.

Offshore Operations

Asia Pacific

During 2020, $123 million (8%) was invested in Asia Pacific compared to $347 million (10%) in 2019. Capital expenditures in 2020 related primarily to the development of Liuhua 29-1.

Atlantic

During 2020, $245 million (15%) was invested in Atlantic compared to $925 million (27%) in 2019. Capital expenditures in 2020 related primarily to the West White Rose Project.

Corporate

During 2020, $65 million (4%) was invested in Corporate compared to $131 million (4%) in 2019.

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Drilling Activity

Integrated Corridor Operations

The following table discloses the number of wells drilled during 2020 and 2019:

	2020				2019
Wells Drilled (wells)(1)	Gross		Net		Gross		Net
Thermal developments		65		65		68		65
Non-thermal developments		25		25		47		47
Western Canada		12		8		21		17
Total		102		98		136		129

⁽¹⁾ Excludes service/stratigraphic test wells for evaluation purposes.

Offshore Operations

No new wells were drilled in Offshore operations during 2020.

3.0 The 2020 Business Environment

The Company’s operations were significantly influenced by domestic and international factors in 2020, including, but not limited to, the following:

• Significant crude oil demand reduction as a result of measures taken by governments around the world to contain the COVID-19 pandemic, and volatility continuing throughout the year;

• Increased global crude oil supplies in the first and second quarters of 2020 as OPEC negotiations broke down;

• The Government of Alberta’s mandatory production quotas introduced in 2019 were lifted in December 2020;

• A continued emphasis on health and safety, the environment, the impacts of climate change, enterprise risk management, resource sustainability and corporate social responsibility concerns.

• Alternative and improved extraction methods have rapidly evolved in North American and international onshore and offshore regions.

Major business factors are considered in formulating short and long-term business strategies.

The Company is exposed to a number of risks inherent in the exploration for, and development, production, marketing, transportation, storage, refining, and sale of, crude oil, liquids-rich natural gas and related products. For a discussion on risk and risk management, see Section 5.0 and the Company’s Annual Information Form for the year ended December 31, 2020.

Average Benchmarks

Commodity prices, refining crack spreads and foreign exchange rates are some of the most significant factors that affect the results of the Company’s operations. The following average benchmarks have been provided to assist in understanding the Company’s financial results.

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Average Benchmarks Summary			2020			2019
West Texas Intermediate (“WTI”) crude oil(1)	(US$/bbl	)		39.40			57.03
Brent crude oil(2)	(US$/bbl	)		41.70			64.30
Western Canada Select (“WCS”) at Hardisty(3)	(US$/bbl	)		26.81			44.28
WCS at Cushing(4)	(US$/bbl	)		35.08			52.10
Light/heavy crude oil differential for WTI less WCS at Hardisty	(US$/bbl	)		12.59			12.75
Light/heavy crude oil differential for WTI less WCS at Cushing	(US$/bbl	)		4.32			4.93
Condensate at Edmonton	($/bbl	)		49.45			70.20
Synthetic at Edmonton	($/bbl	)		48.27			74.90
NYMEX natural gas(5)	(US$/mmbtu	)		2.08			2.63
Nova Inventory Transfer (“NIT”) natural gas	($/GJ	)		2.12			1.54
Chicago Regular Unleaded Gasoline	(US$/bbl	)		44.85			70.29
Chicago Ultra-low Sulphur Diesel	(US$/bbl	)		50.13			78.00
Chicago 3:2:1 crack spread	(US$/bbl	)		7.21			15.80
Canadian/U.S. dollar exchange rate	(US$	)		0.746			0.754
Canadian dollar/Chinese Yuan (“RMB”) exchange rate	(RMB	)		5.147			5.208
Canadian $ Equivalents(6)
WTI crude oil	($/bbl	)		52.82			75.64
Brent crude oil	($/bbl	)		55.90			85.27
WCS at Hardisty	($/bbl	)		35.94			58.72
WCS at Cushing	($/bbl	)		47.02			69.10
NYMEX natural gas	($/mmbtu	)		2.79			3.49
Synthetic/WTI differential	($/bbl	)		(4.55	)		(0.74	)

⁽¹⁾ Calendar month average of settled prices for WTI at Cushing, Oklahoma.

⁽²⁾ Calendar month average of settled prices for Dated Brent.

⁽³⁾ WCS is a heavy blended crude oil, comprised of conventional and bitumen crude oils blended with diluent. Quoted prices are indicative of the Index for WCS at Hardisty, Alberta, set in the month prior to delivery.

⁽⁴⁾ Quoted prices are indicative of the Index for WCS at Cushing, Oklahoma, set in the month prior to delivery.

⁽⁵⁾ Prices quoted are average settlement prices during the period.

⁽⁶⁾ Prices quoted are calculated using U.S. dollar benchmark commodity prices and monthly average U.S./Canadian dollar exchange rates.

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As an integrated producer, the Company’s profitability is largely determined by realized prices for crude oil and natural gas, margins on committed pipeline capacity and refinery margins, as well as the effect of changes in the U.S./Canadian dollar exchange rate. All of the Company’s crude oil production and the majority of its natural gas production receive the prevailing market prices. The price realized for crude oil is determined by North American and global factors. The price realized for natural gas production from Western Canada is determined primarily by North American fundamentals since virtually all natural gas production in North America is consumed by North American customers. In Asia Pacific, the natural gas price received is determined by long-term contracts.

The refining business is heavily impacted by the price of crude oil, as the largest cost factor is crude oil feedstock, a portion of which is heavy crude oil and bitumen. At the Upgrader, heavy crude oil feedstock is processed into light synthetic crude oil. The Company’s U.S. Refining segment processes a mix of different types of crude oil from various sources, but the mix is primarily light sweet crude oil at the Lima Refinery and approximately 75% heavy crude oil and bitumen feedstock at the BP-Husky Toledo Refinery. The Canadian Refined Products segment relies primarily on supply contracts to purchase refined products for resale in the retail distribution network, as well as diesel from the Upgrader.

Crude Oil Benchmarks

Global crude oil benchmarks weakened in 2020 primarily due to reduced demand as a result of the COVID-19 pandemic. WTI averaged US$39.40/bbl in 2020 compared to US$57.03/bbl in 2019. Brent averaged US$41.70/bbl in 2020 compared to US$64.30/bbl in 2019. WCS averaged US$26.81/bbl in 2020 compared to US$44.28/bbl in 2019.

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The price received by the Company for crude oil production in the Integrated Corridor is primarily driven by the price of WTI, adjusted to Western Canada for location and quality. The price received by the Company for crude oil production from Atlantic and for NGL production from Asia Pacific is primarily driven by the price of Brent. A significant portion of the Company’s crude oil production in the Integrated Corridor is classified as either heavy crude oil or bitumen, which trades at a discount to light crude oil and can be impacted by the geographical market to which it is exported. The Company’s crude oil and NGL production was 76% heavy crude oil and bitumen in 2020 compared to 77% in 2019. The Company upgrades heavy crude oil and bitumen into a sweet synthetic crude oil, the Husky Synthetic Blend (“HSB”), at the Upgrader. The price realized by HSB is primarily driven by the price of WTI and by the supply and demand of sweet synthetic crude oil from Western Canada, which influences the synthetic to WTI differential. The remaining blended heavy crude oil production that the Company does not upgrade or refine at Lloydminster is delivered to either Canadian markets or U.S. markets through pipeline systems. Therefore, the price received by the Company can be impacted by both Canadian heavy crude oil pricing and U.S. Gulf Coast heavy crude oil pricing.

The Company’s heavy crude oil and bitumen production is blended with diluent (condensate) in order to facilitate its transportation through pipelines. Therefore, the price received for a barrel of blended heavy crude oil or bitumen is impacted by the prevailing market price for condensate. The price of condensate at Edmonton decreased in 2020 compared to 2019, primarily due to the decrease in crude oil benchmark pricing.

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Natural Gas Benchmarks

The price received by the Company for natural gas from Western Canada Production is largely driven by the NIT near-month contract price of natural gas and the location differential (net of transportation costs) between NIT and the market prices in the hubs at the end of the Company’s long-haul export pipelines. The price received by the Company for production from Asia Pacific is determined by long-term contracts.

North American natural gas has been consumed internally by the Company’s Integrated Corridor operations, helping to mitigate the impact of weak natural gas benchmark prices on results.

Refining Benchmarks

Lloydminster Heavy Oil Value Chain

The Company produces HSB, diesel fuel and asphalt at the Lloydminster upgrading and asphalt refining complex. The price realized for HSB, diesel fuel and asphalt is primarily driven by the supply and demand of refined products in Western Canada and the U.S. market.

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U.S. Refining

The Chicago 3:2:1 crack spread is a key indicator for U.S. Midwest refining margins and reflects refinery gasoline output that is approximately twice the distillate output, and is calculated as the price of two-thirds of a barrel of gasoline plus one-third of a barrel of distillate fuel less one barrel of crude oil. Market crack spreads are based on quoted near-month contracts for WTI and spot prices for gasoline and diesel and do not reflect the actual crude purchase costs or the product configuration of a specific refinery. The Chicago Regular Unleaded Gasoline and the Chicago Ultra-low Sulphur Diesel average benchmark prices are the standard products included in the Chicago 3:2:1 crack spread.

The Chicago 3:2:1 crack spread is a gross margin based on the prices of unblended fuels. The cost of purchasing Renewable Identification Numbers (“RINs”) or physically blending biofuel into a final gasoline or diesel product has not been deducted from the Chicago 3:2:1 gross margin. The market value of gasoline or distillate that has been blended may be lower than the value of unblended petroleum products given the value a buyer of unblended petroleum can gain by generating RINs through blending. The Company sells both blended and unblended fuels with the goal of maximizing margins net of RINs purchases.

The Company’s realized refining margins are affected by the product configuration of its refineries, crude oil feedstock, product slates, transportation costs to benchmark hubs and the time lag between the purchase and delivery of crude oil. The product slates produced at the Lima and BP-Husky Toledo refineries contain approximately 14% of other products that are sold at discounted market prices compared to gasoline and distillate. The Company’s realized refining margins are accounted for on a first in first out (”FIFO”) basis in accordance with International Financial Reporting Standards (“IFRS”).

Foreign Exchange

The majority of the Company’s revenues are received in U.S. dollars from the sale of oil and gas commodities and refined products whose prices are determined by reference to U.S. benchmark prices. The majority of the Company’s non-hydrocarbon related expenditures are denominated in Canadian dollars. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease the revenues received from the sale of oil and gas commodities. A decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of oil and gas commodities. In addition, changes in foreign exchange rates impact the translation of U.S. and Asia Pacific operations and U.S. dollar denominated debt. The Canadian dollar averaged US$0.746 in 2020 compared to US$0.754 in 2019.

A portion of the Company’s long-term sales contracts in Asia Pacific are priced in RMB. An increase in the value of the Canadian dollar relative to the RMB will decrease the revenues received in Canadian dollars from the sale of natural gas commodities in the region. The Canadian dollar averaged RMB 5.147 in 2020 compared to RMB 5.208 in 2019.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 16

Sensitivity Analysis

The following table is indicative of the impact of changes in certain key variables in 2020 on earnings before income taxes and net earnings. The table below reflects what the expected effect would have been on the financial results for 2020 had the indicated variable increased by the notional amount. The analysis is based on business conditions and production volumes during 2020. Each separate item in the sensitivity analysis shows the approximate effect of an increase in that variable only; all other variables are held constant. While these sensitivities are indicative for the period and magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances or upon greater magnitudes of change.

	2020				Effect on Earnings						Effect on
Sensitivity Analysis	Average		Increase		before Income Taxes(1)						Net Earnings(1)
					($ millions)			($/share)(2)			($ millions)			($/share)(2)
WTI benchmark crude oil price(3)(4)		39.40		US$1.00/bbl		88			0.09			66			0.07
NYMEX benchmark natural gas price(5)		2.08		US$0.20/mmbtu		—			—			—			—
WTI/WCS at Cushing differential		4.32		US$1.00/bbl		(7	)		(0.01	)		(5	)		—
Canadian asphalt margins		20.14		Cdn $1.00/bbl		11			0.01			8			0.01
Chicago 3:2:1 crack spread		7.21		US$1.00/bbl		103			0.10			80			0.08
Exchange rate (US $ per Cdn $)(3)(6)		0.746		US$0.01		(25	)		(0.02	)		(18	)		(0.02	)

⁽¹⁾  Excludes mark to market accounting impacts.

⁽²⁾  Based on 1,005.1 million common shares outstanding as of December 31, 2020.

⁽³⁾  Does not include gains or losses on inventory.

⁽⁴⁾  Includes impacts related to Brent-based production.

⁽⁵⁾ Includes impact of natural gas consumption by the Company.

⁽⁶⁾  Assumes no foreign exchange gains or losses on U.S. dollar denominated long-term debt and other monetary items, including cash balances.

The Company’s five-year plan was updated at its Investor Day in May 2019, which included guidance for 2020 of cash flow – operating activities and funds from operations, each in the range of $4.4 billion, and a free cash flow projection of $1.0 billion. These projections were based on several pricing assumptions, including WTI benchmark crude at US$60/bbl, Brent crude oil at US$65/bbl and a Chicago 3:2:1 crack spread of US$16.50 US/bbl.

In December 2019 the Company issued corporate guidance which included a revised projection for 2020 free cash flow of $500 million based on revised price assumptions (WTI benchmark crude at US$55/bbl, Brent Crude oil at US$65/bbl, and a NYMEX 321 crack spread of US$18/bbl). Free cash flow in 2020 was negative $1.1 billion (free cash flow is a non-GAAP measure, see section 9.3 for a reconciliation to the corresponding GAAP measure).

Actual cash flow - operating activities, funds from operations and free cash flow differed materially due to the market impact of the COVID-19 pandemic and other domestic and international factors that impacted our business, which are described above.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 17

4.0 Results of Operations

4.1 Segment Earnings

Segmented Earnings	Earnings (Loss) before Income Taxes						Net Earnings (Loss)
($ millions)	2020			2019			2020			2019
Integrated Corridor
Lloydminster Heavy Oil Value Chain		(1,743	)		688			(1,309	)		504
Oil Sands		(1,814	)		(744	)		(1,362	)		(545	)
Western Canada Production		(759	)		(1,055	)		(570	)		(772	)
U.S. Refining		(5,046	)		319			(3,925	)		248
Canadian Refined Products		(39	)		(2	)		(29	)		(2	)
Offshore		(3,232	)		(961	)		(2,419	)		(693	)
Corporate		(371	)		(414	)		(402	)		(110	)
Total		(13,004	)		(2,169	)		(10,016	)		(1,370	)

4.2 Integrated Corridor

Integrated Corridor Consolidated

Integrated Corridor Earnings Summary ($ millions)	2020			2019
Revenues, net of royalties		11,873			18,458
Operating margin(1)		(69	)		2,578
Expenses
Depletion, depreciation, amortization and impairment (“DD&A”)		9,090			3,731
Exploration and evaluation		182			167
Gain on sale of assets		(24	)		(7	)
Other – net		(100	)		(672	)
Share of equity investment loss (income)		32			(9	)
Financial items		152			162
Recovery of income taxes		(2,206	)		(227	)
Net loss		(7,195	)		(567	)

⁽¹⁾ Operating margin is a non-GAAP measure. Refer to Section 9.3.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 18

Integrated Corridor Financial Highlights

Change in results for the year ended December 31, 2020

($ millions)
Operating margin	Decreased	Decreased primarily due to lower realized crude oil and refined product pricing and lower margins in the Lloydminster Heavy Oil Value Chain and the U.S. Refining segments, as a result of the significant decline in crude oil and refined product prices.
DD&A	Increased	Increased primarily due to the recognition of a pre-tax impairment charge of $7,527 million in the Lloydminster Heavy Oil Value Chain, Oil Sands, Western Canada Production and U.S. Refining segments due to declines in forecasted commodity prices, reduced capital investment and delayed future development plans; partially offset by the recognition of a pre-tax impairment charge of $1,841 million in 2019.
Other - net income	Decreased	Decreased primarily due to lower insurance recoveries recognized for business interruption and incident costs associated with the Superior Refinery.
Share of equity investment loss	Increased	Increased primarily due to lower income from HMLP.
Recovery of income taxes	Increased	Increased primarily due to lower earnings before income taxes.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 19

Lloydminster Heavy Oil Value Chain

Lloydminster Heavy Oil Value Chain Operating Margin Summary

($ millions, except where indicated)	2020			2019
Gross revenues(1)
Synthetic crude oil and refined products		1,626			2,364
Blended crude oil(2)		1,500			2,197
Other revenues(3)		627			1,040
		3,753			5,601
Royalties		(92	)		(160	)
Marketing and other(1)		22			52
Revenue, net of royalties		3,683			5,493
Expenses
Purchases of crude oil and products(1)		1,827			2,395
Production, operating and transportation expenses(1)		1,059			1,212
Selling, general and administrative expenses		204			155
Operating margin(4)		593			1,731
Select operating data:
Total sales volumes (mboe/day)		175.6			174.7
Synthetic crude oil and refined products		78.2			81.0
Blended crude oil		97.4			93.7
Total realized price per unit sold ($/boe)		48.63			71.52
Synthetic crude oil and refined products		56.78			79.96
Blended crude oil		42.09			64.23
Total daily gross production (mboe/day)		124.0			138.6
Medium crude oil (mbbls/day)		1.4			1.5
Heavy crude oil (mbbls/day)		21.4			30.2
Bitumen (mbbls/day)		99.3			104.2
Conventional natural gas (mmcf/day)		11.2			15.7
Total throughput (mbbls/day)		91.8			101.3
Upgrading throughput (mbbls/day)(5)		63.8			74.9
Lloydminster Refinery throughput (mbbls/day)(6)		28.0			26.4
Unit operating cost ($/boe)(7)(9)		10.99			13.48
Unit operating margin ($/boe)(8)(9)		13.13			30.67

⁽¹⁾ Results reported for 2019 have been recast to reflect a change in reclassification of intersegment sales eliminations and a change in presentation of the Integrated Corridor and Offshore.

⁽²⁾ Blended heavy crude oil and bitumen.

⁽³⁾ Includes revenues from pipeline construction activities, the Lloydminster and Minnedosa Ethanol plants and processing income.

⁽⁴⁾ Operating margin is a non-GAAP measure. Refer to Section 9.3.

⁽⁵⁾ Throughput includes diluent returned to the field.

⁽⁶⁾ Includes all crude oil, feedstock, intermediate feedstock and blend-stocks used in producing sales volumes from the refinery.

⁽⁷⁾ Excludes operating costs not directly attributable to the sale of synthetic crude and refined product, and blended crude oil.

⁽⁸⁾ Excludes revenue and expenses not directly attributable to sale of synthetic crude and refined product, and blended crude oil.

⁽⁹⁾ Per unit cost calculated based on sales volumes.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 20

Lloydminster Heavy Oil Value Chain Financial Highlights

Change in results for the year ended December 31

($ millions)
Synthetic crude oil and refined products revenues	Decreased	Decreased primarily due to lower realized pricing from HSB and asphalt sales.
Blended crude oil revenues	Decreased	Decreased primarily due to lower commodity pricing.
Other revenues	Decreased	Decreased primarily due to lower marketing revenue from third party light crude oil sales, combined with lower construction revenue.
Royalties	Decreased	Decreased primarily due to lower bitumen and heavy crude oil production, combined with lower realized sales prices.
Marketing and other	Decreased	Decreased primarily due to limited arbitrage opportunities driven by narrowed price differentials between the Canadian and U.S. markets and forward commodity pricing trending lower than spot prices.
Purchases of crude oil and products	Decreased	Decreased primarily due to lower blending costs as a result of the decline in condensate prices.
Production, operating and transportation expenses	Decreased	Decreased primarily due to cost savings initiatives and reduced operational activity.

Lloydminster Heavy Oil Value Chain Operational Highlights

Change in operational performance for the year ended December 31

Total realized price per unit sold ($/boe)
Synthetic crude oil and refined products	Decreased	Decreased primarily due to the significant decline in commodity price benchmarks and an unfavourable synthetic differential.
Blended crude oil	Decreased	Decreased primarily due to the significant decline in commodity price benchmarks.
Unit operating cost ($/bbl)	Decreased	Decreased primarily due to cost savings initiatives and reduced operational activity.
Unit operating margin ($/bbl)	Decreased	Decreased primarily due to the decline in refined product and crude oil prices.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 21

Oil Sands

Oil Sands Operating Margin Summary

($ millions, except where indicated)	2020			2019
Gross revenues(1)		306			649
Royalties		(2	)		(13	)
Marketing and other		(48	)		4
Revenues, net of royalties		256			640
Expenses
Purchases of crude oil and products(1)		153			246
Production, operating and transportation expenses		114			140
Selling, general and administrative expenses		24			27
Operating margin(2)		(35	)		227
Select operating data:
Total sales volumes
Diluted bitumen (mbbls/day)		26.7			30.9
Total realized price per unit sold
Diluted bitumen ($/bbl)		31.45			56.72
Total daily gross production
Bitumen (mbbls/day)		22.4			24.6
Unit operating cost ($/bbl)(3)		11.68			12.41
Unit operating margin ($/bbl)(3)		(1.34	)		20.03

⁽¹⁾ Results reported for 2019 have been recast to reflect a change in reclassification of intersegment sales eliminations and a change in presentation of the Integrated Corridor and Offshore business units.

⁽²⁾ Operating margin is a non-GAAP measure. Refer to Section 9.3.

⁽³⁾ Per unit cost calculated based on sales volumes.

Oil Sands Financial Highlights

Change in results for the year ended December 31

($ millions)
Gross revenues	Decreased	Decreased primarily due to lower average WCS benchmark prices, combined with lower volume of diluted bitumen sales.
Marketing and other	Decreased	Decreased primarily due to the limited arbitrage opportunities driven by tightened price differentials between the Canadian and U.S. markets.
Purchases of crude oil and products	Decreased	Decreased primarily due to lower diluent prices and volumes purchased, combined with the impact of a third-party pipeline outage in September 2020.
Production, operating and transportation expenses	Decreased	Decreased primarily due to cost saving initiatives and reduced operational activity.

Oil Sands Operational Highlights

Change in operational performance for the year ended December 31

Total sales volumes (mbbls/day)	Decreased	Decreased primarily due to lower diluent sales as a result of a third-party pipeline outage in September 2020 and lower bitumen production from the Sunrise Energy Project.
Total realized price per unit sold ($/bbl)	Decreased	Decreased primarily due to the significant decline in global commodity prices.
Unit operating margin ($/bbl)	Decreased	Decreased primarily due to lower average WCS prices and lower sales volumes.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 22

Western Canada Production

Western Canada Production Operating Margin Summary

	2020			2019
Gross revenues(1)		367			514
Royalties		(10	)		(41	)
Marketing and other(1)		15			99
Revenues, net of royalties		372			572
Expenses
Purchases of crude oil and products(1)		22			40
Production, operating and transportation expenses(1)		250			313
Selling, general and administrative expenses		64			106
Operating margin(2)		36			113
Select operating data:
Total sales volumes (mboe/day)(3)		57.6			66.7
Light crude oil (mbbls/day)		5.7			7.0
NGL (mbbls/day)		10.2			12.7
Conventional natural gas (mmcf/day)		250.0			281.6
Total realized price per unit sold ($/boe)		15.97			20.27
Light crude oil ($/bbl)		39.50			65.02
Conventional natural gas & NGL ($/mcf)		2.23			2.51
Unit operating cost ($/boe)		11.84			12.84

⁽¹⁾ Results reported for 2019 have been recast to reflect a change in reclassification of intersegment sales eliminations and a change in presentation of the Integrated Corridor and Offshore business units.

⁽²⁾ Operating margin is a non-GAAP measure. Refer to Section 9.3.

⁽³⁾ Sales volumes approximate total daily gross production.

Western Canada Production Financial Highlights

Change in results for the year ended December 31

($ millions)
Gross revenues	Decreased	Decreased primarily due to lower sales volumes and lower realized crude oil and NGL prices in 2020.
Royalties	Decreased	Decreased primarily due to lower realized prices and production volumes.
Marketing and other	Decreased	Decreased primarily due to reduced margin in natural gas exports as the Canada to U.S. gas price spread weakened.
Production, operating and transportation expenses	Decreased	Decreased primarily due to cost saving initiatives and reduced activities.
Selling, general and administrative expenses	Decreased	Decreased primarily due to cost saving initiatives and reduced activities.

Western Canada Production Operational Highlights

Change in operational performance for the year ended December 31

Total sales volumes (mboe/day)	Decreased	Decreased primarily due to shut-ins of uneconomic production in response to market conditions.
Total realized price per unit sold ($/boe)	Decreased	Decreased primarily due to the significant decline in commodity benchmarks.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 23

U.S. Refining

U.S. Refining Operating Margin Summary

($ millions, except where indicated)	2020			2019
Gross revenues(1)		6,636			10,253
Marketing and other(1)		40			23
Revenues		6,676			10,276
Expenses
Purchases of crude oil and products		6,500			8,934
Production, operating and transportation expenses(1)		797			872
Selling, general and administrative expenses		72			51
Operating margin(2)		(693	)		419
Select operating data:
Total throughput (mbbls/day)		203.6			199.5
Lima Refinery (mbbls/day)(3)		138.2			136.4
BP-Husky Toledo Refinery (mbbls/day)(3)(4)		65.4			63.1
Unit refining and marketing margin (US$/bbl crude throughput)(5)		1.93			14.40
Refinery inventory (mmbbls)(6)		8.5			5.0

⁽¹⁾ Results reported for 2019 have been recast to reflect a change in reclassification of intersegment sales eliminations and a change in presentation of the Integrated Corridor and Offshore business units.

⁽²⁾ Operating margin is a non-GAAP measure. Refer to Section 9.3.

⁽³⁾ Includes all crude oil feedstock, intermediate feedstock and blend-stocks used in producing sales volumes from the refinery.

⁽⁴⁾ Reported throughput volumes include Husky’s working interest from the BP-Husky Toledo Refinery (50%).

⁽⁵⁾ Refining and marketing margin is a non-GAAP measure. Refer to Section 9.3.

⁽⁶⁾ Feedstock and refined products are included in refinery inventory.

U.S. Refining Financial Highlights

Change in results for the year ended December 31

($ millions)
Gross revenues	Decreased	Decreased primarily due to the lower average realized refined product prices.
Purchases of crude oil and products	Decreased	Decreased primarily due to lower crude oil feedstock costs.
Production, operating and transportation expenses	Decreased	Decreased primarily due to planned turnarounds at the Lima and BP-Husky Toledo Refineries in 2019.

U.S. Refining Operational Highlights

Change in operational performance for the year ended December 31

Unit refining and marketing margin (US$/bbl crude throughput) Decreased Decreased primarily due to tightening refining margins.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 24

Canadian Refined Products

Canadian Refined Products Operating Margin Summary

($ millions, except where indicated)	2020		2019
Gross revenues		1,488		2,425
Expenses
Purchases of crude oil and products		1,349		2,175
Production, operating and transportation expenses		65		153
Selling, general and administrative expenses		44		9
Operating margin(1)		30		88
Select operating data:
Fuel sales volume, including wholesale
Fuel sales (millions of litres/day)		6.7		7.4
Fuel sales per retail outlet (thousands of litres/day)		12.1		12.7

⁽¹⁾ Operating margin is a non-GAAP measure. Refer to Section 9.3.

Canadian Refined Products Financial Highlights

Change in results for the year ended December 31

($ millions)
Gross revenues	Decreased	Decreased primarily due to the sale of the Prince George Refinery in the fourth quarter of 2019 and the decline in gasoline and diesel prices.
Purchases of crude oil and products	Decreased	Decreased primarily due to the sale of the Prince George Refinery in the fourth quarter of 2019 and the decline in gasoline and diesel prices.
Production, operating and transportation expenses	Decreased	Decreased primarily due to cost saving initiatives and the sale of the Prince George Refinery in the fourth quarter of 2019.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 25

4.3 Offshore

Offshore Consolidated

Offshore Earnings Summary

($ millions, except where indicated)	2020			2019
Revenues, net of royalties		1,428			1,444
Operating margin(1)		1,046			1,065
Expenses
DD&A		3,738			1,661
Exploration and evaluation		551			380
Gain on sale of assets		(1	)		(1	)
Other – net		(5	)		1
Share of equity investment income		(39	)		(50	)
Financial items		34			35
Recovery of income taxes		(813	)		(268	)
Net loss		(2,419	)		(693	)

⁽¹⁾ Operating margin is a non-GAAP measure. Refer to Section 9.3.

Offshore Financial Highlights

Change in results for the year ended December 31

($ millions)
DD&A	Increased	Increased primarily due to the recognition of a pre-tax impairment of $3,104 million in Atlantic operations resulting from sustained declines in forecasted crude oil prices and management’s decision to delay capital investment in the West White Rose Project, partially offset by the recognition of a pre-tax impairment charge of $908 million in 2019.
Exploration and evaluation	Increased	Increased primarily due to the recognition of a pre-tax write-down of $439 million related to certain Exploration and Evaluation assets in the Atlantic operation. The write-down was primarily due to changes in management’s future development plans resulting from sustained declines in forecasted prices for crude oil. The increase is partially offset by the recognition of a pre-tax write-down of $245 million in 2019.
Recovery of income taxes	Increased	Increased primarily due to lower earnings before taxes in 2020.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 26

Asia Pacific

Asia Pacific Operating Margin Summary

($ millions, except where indicated)	2020			2019
Gross revenues		1,179			1,060
Royalties		(69	)		(60	)
Revenues, net of royalties		1,110			1,000
Expenses
Production, operating and transportation expenses		78			71
Selling, general and administrative expenses		37			49
Operating margin(1)		995			880
Select operating data:
Total sales volume (mboe/day)(2)(3)(4)		50.4			43.8
NGL (mbbls/day)(2)(3)		11.0			9.9
Conventional natural gas (mmcf/day)(3)(4)		235.7			203.4
Total realized price per unit sold ($/boe)		73.37			78.47
NGL ($/bbl)		50.68			72.70
Conventional natural gas ($/mcf)		13.33			13.36
Unit operating cost ($/boe)(5)		5.64			6.03

⁽¹⁾ Operating margin is a non-GAAP measure. Refer to Section 9.3.

⁽²⁾ Sales volumes approximates total daily gross production.

⁽³⁾ Reported sales volumes include Husky’s working interest production from the Liwan Gas Project.

⁽⁴⁾ Reported sales volumes include Husky’s working interest production from the BD Project (40%). Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for consolidated financial statement purposes.

⁽⁵⁾ Reported operating costs include Husky’s working interest production from the BD Project (40%). Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for consolidated financial statement purposes.

Asia Pacific Financial Highlights

Change in results for the year ended December 31

($ millions)
Gross revenues	Increased	Increased primarily due to higher sales volumes, which was partially offset by lower average realized NGL prices.

Asia Pacific Operational Highlights

Change in operational performance for the year ended December 31

Total sales volume (mboe/day)	Increased	Increased primarily due to higher production from the Liwan Gas Project including commencement of production at Liuhua 29-1 in November 2020.
Average sales price realized NGL ($/bbl)	Decreased	Decreased primarily due to the significant decline in global commodity prices.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 27

Atlantic

Atlantic Operating Margin Summary

($ millions, except where indicated)	2020			2019
Gross revenues		336			493
Royalties		(18	)		(49	)
Revenues, net of royalties		318			444
Expenses
Purchases of crude oil and products(1)		32			(16	)
Production, operating and transportation expenses		197			269
Selling, general and administrative expenses		38			6
Operating margin(2)		51			185
Select operating data:
Total sales volumes
Light crude oil (mbbls/day)		17.8			15.9
Total realized price per unit sold
Light crude oil ($/bbl)		51.43			84.99
Total daily gross production
Light crude oil (mbbls/day)		17.6			16.4
Unit operating cost ($/bbl)(3)		27.45			43.44

⁽¹⁾ Results reported for 2019 have been recast to reflect a change in reclassification of intersegment sales eliminations and a change in presentation of the Integrated Corridor and Offshore business units.

⁽²⁾ Operating margin is a non-GAAP measure. Refer to Section 9.3.

⁽³⁾ Per unit cost calculated based on sales volumes.

Atlantic Financial Highlights

Change in results for the year ended December 31

($ millions)
Gross revenues	Decreased	Decreased primarily due to lower realized sales pricing, partially offset by higher sales volumes.
Royalties	Decreased	Decreased primarily due to the same factors that impacted gross revenues.
Purchases of crude oil and products	Increased	Increased primarily due to the timing difference between production and sales.
Production, operating and transportation expenses	Decreased	Decreased primarily due to well intervention scopes completed in 2019.

Atlantic Operational Highlights

Change in operational performance for the year ended December 31

Total sales volumes (mbbl/day)	Increased	Increased primarily due to higher production combined with timing differences between production and sales.
Total realized price per unit sold ($/boe)	Decreased	Decreased primarily due to the significant decline in crude oil benchmark prices.
Unit operating cost ($/bbl)	Decreased	Decreased primarily due to higher sales volumes and lower operating costs.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 28

4.4 Corporate

Corporate Summary	2020			2019
Selling, general and administrative expenses		(262	)		(290	)
DD&A		(92	)		(104	)
Other – net		157			16
Net foreign exchange gain		14			44
Finance income		18			71
Finance expense		(206	)		(151	)
Recovery of (provisions for) income taxes		(31	)		304
Net loss		(402	)		(110	)

The Corporate segment reported a net loss of $402 million in 2020 compared to a net loss of $110 million in 2019. Other-net income increased by $141 million, primarily due to pre-tax recoveries for the Canadian Emergency Wage Subsidy of $82 million, and a net realized and unrealized gain of $79 million on the Company’s commodity short-term hedging program. Finance income decreased by $53 million primarily due to a lower cash and cash equivalents balance. Finance expense increased by $55 million primarily due to an increase in the long-term debt balance and lower capitalized interest as a result of reduced capital activity. Recovery of income taxes decreased by $335 million primarily due to the recognition of tax recoveries in 2019 related to the reduction of the Alberta provincial corporate tax rate that was substantively enacted in the second quarter of 2019.

Net foreign exchange gain decreased by $30 million due to the items noted below.

Foreign Exchange Summary ($ millions, except where indicated)	2020		2019
Non-cash working capital		7		17
Other foreign exchange		7		27
Net foreign exchange gain		14		44
U.S./Canadian dollar exchange rates:
At beginning of year	US$	0.771	US$	0.733
At end of year	US$	0.784	US$	0.771

Included in other foreign exchange are realized and unrealized gains and losses on working capital and intercompany financing. The foreign exchange gains and losses on these items can vary significantly due to the large volume and timing of transactions through these accounts in the period. The Company manages its exposure to foreign currency fluctuations with the goal of minimizing the impact of foreign exchange gains and losses on the consolidated financial statements.

Consolidated Income Taxes

Consolidated Income Taxes ($ millions)	2020			2019
Recovery of income taxes		(2,988	)		(799	)
Cash income taxes paid		135			41

Consolidated income taxes were a recovery of $2,988 million in 2020 compared to a recovery of $799 million in 2019. The increase in consolidated income taxes recovery was primarily due to a $2,654 million deferred income tax recovery associated with the recognition of pre-tax impairment and exploration asset write-down charge of $11,220 million in 2020. The increase was offset by a $741 million deferred income tax recovery associated with the recognition of pre-tax impairment and exploration asset write-down charge of $3,080 in the fourth quarter of 2019.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 29

4.5 Oil and Gas Reserves

The Company’s reserves disclosure was prepared in accordance with Canadian Securities Administrators’ National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) effective December 31, 2020 with a preparation date of January 25, 2021.

Proved and Probable Reserves at December 31:

Note: All Lloydminster thermal reserves are classified as bitumen.

The Company’s complete oil and gas reserves disclosure, prepared in accordance with NI 51-101, is contained in the Company’s Annual Information Form for the year ended December 31, 2020, which is available at www.sedar.com, and certain supplementary oil and gas reserves disclosure prepared in accordance with U.S. disclosure requirements is contained in the Company’s Form 40-F, which is available at www.sec.gov and on the Company’s website at www.huskyenergy.com.

Sproule Associates Limited (“Sproule”), an independent firm of qualified oil and gas reserves evaluation engineers, was engaged to conduct an audit and review of the Company’s oil and gas reserves estimates. Sproule issued an audit opinion on January 25, 2021 stating that the Company’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 Canadian Oil and Gas Evaluation Handbook.

The effective date of the reserves estimates in this MD&A is December 31, 2020 which was prior to completion of the Cenovus Transaction. As a result of the Cenovus Transaction, the Company’s development plans and capital expenditure plans may change as the Company and Cenovus integrate their operations, which may impact the Company’s reserves estimates.

At December 31, 2020, the Company’s proved oil and gas reserves were 1,241 mmboe, down from 1,431 mmboe at the end of 2019. The Company’s 2020 reserves replacement ratio, defined as net changes to proved reserves divided by total production during the period, was negative 10% excluding economic revisions (negative 91% including economic revisions).

Major changes to proved reserves in 2020 included:

• Western Canada Extensions & Improved Recovery additions of 31 mmboe associated with 17 mmboe from Western Canada conventional natural gas including new locations (89 bcf of conventional natural gas and 2 mmbbls of NGL), 11 mmbbls primarily from Sunrise, and 3 mmbbls mainly from cold heavy crude oil production new drills.

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• Net negative technical revisions in Canada of 48 mmboe mainly associated with 32 mmboe of conventional natural gas and associated NGL revisions (negative 83 bcf conventional natural gas and 18 mmbbls of NGL), primarily due to performance analysis and revised development plans in response to current market conditions. An additional 9 mmboe negative technical revisions of bitumen are mainly from Sunrise due to deferred capital plans. Net negative technical revisions of 7 mmboe in Atlantic are primarily due to the Terra Nova suspension causing a transfer to probable, offset by positive performance in White Rose.

• Net positive technical revisions for offshore China of 16 mmboe (71 bcf conventional natural gas and 4 mmbbls of NGL) mainly due to transfers from probable and the expanded GSA in Liwan 3-1. Net negative technical revisions in Indonesia of 5 mmboe (32 bcf of conventional natural gas) are due to expiring agreements, which are currently being renegotiated, associated with project delays.

• Economic factors reduction of 81 mmboe associated with significantly lower oil prices in North America. As a result, the West White Rose Project proved reserves were transferred to probable. Cold heavy crude oil reserves were reduced by 9 mmbbls as a result of economics and shut-in wells.

Proved Plus Probable Reserves and Production at December 31, 2020:

Reconciliation of Proved Reserves⁽¹⁾

	Canada															International						Total
	Western Canada												Atlantic
(forecast prices and costs before royalties)	Light/Medium Crude Oil & NGL (mmbbls)			Heavy Crude Oil (mmbbls)(2)			Bitumen (mmbbls)(2)			Conventional Natural Gas (bcf)			Light Crude Oil (mmbbls)			Light Crude Oil & NGL (mmbbls)			Conventional Natural Gas (bcf)			Crude Oil, Bitumen & NGL (mmbbls)			Conventional Natural Gas (bcf)			Equivalent Units (mmboe)
Proved reserves
December 31, 2019		75			47			943			815			85			22			737			1,172			1,552			1,431
Technical revisions		(18	)		—			(9	)		(83	)		(7	)		4			39			(30	)		(44	)		(37	)
Acquisitions		—			—			—			—			—			—			—			—			—			—
Dispositions		(1	)		—			—			(10	)		—			—			—			(1	)		(10	)		(3	)
Discoveries, extensions and improved recovery		2			3			11			89			—			—			—			16			89			31
Economic factors		(2	)		(9	)		(3	)		(14	)		(64	)		—			—			(78	)		(14	)		(81	)
Production		(6	)		(8	)		(45	)		(96	)		(7	)		(4	)		(86	)		(70	)		(182	)		(100	)
Proved reserves December 31, 2020		50			33			897			701			7			22			690			1,009			1,391			1,241
Proved and probable reserves December 31, 2020		73			49			1,153			1,002			151			25			810			1,451			1,812			1,753
December 31, 2019		126			66			1,366			1,155			169			28			948			1,755			2,103			2,105

⁽¹⁾ Numbers in the above table may not align with other disclosures due to rounding.

⁽²⁾ Lloydminster thermal property reserves are classified as bitumen.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 31

Reconciliation of Proved Developed Reserves⁽¹⁾

	Canada															International						Total
	Western Canada												Atlantic
(forecast prices and costs before royalties)	Light/Medium Crude Oil & NGL (mmbbls)			Heavy Crude Oil (mmbbls)(2)			Bitumen (mmbbls)(2)			Conventional Natural Gas (bcf)			Light Crude Oil (mmbbls)			Light Crude Oil & NGL (mmbbls)			Conventional Natural Gas (bcf)			Crude Oil, Bitumen & NGL (mmbbls)			Conventional Natural Gas (bcf)			Equivalent Units (mmboe)
Proved developed reserves
December 31, 2019		55			46			168			709			21			16			476			306			1,185			504
Technical revisions		(6	)		—			6			(39	)		(8	)		4			72			(4	)		33			1
Transfer from proved undeveloped		1			1			11			10			—			6			160			19			170			48
Acquisitions		—			—			—			—			—			—			—			—			—			—
Dispositions		(1	)		—			—			(10	)		—			—			—			(1	)		(10	)		(3	)
Discoveries, extensions and improved recovery		1			2			—			21			—			—			—			3			21			6
Economic factors		(3	)		(9	)		(2	)		(13	)		—			—			—			(14	)		(13	)		(15	)
Production		(6	)		(8	)		(45	)		(96	)		(6	)		(4	)		(86	)		(69	)		(182	)		(100	)
December 31, 2020		41			32			138			582			7			22			622			240			1,204			441

⁽¹⁾ Numbers in the above tables may not align with other disclosures due to rounding.

⁽²⁾ Lloydminster thermal property reserves are classified as bitumen.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 32

5.0 Risk and Risk Management

5.1 Enterprise Risk Management

The Company’s enterprise risk management program supports decision-making via comprehensive and systematic identification and assessment of risks that could materially impact the results of the Company. Through this framework, the Company builds risk management and mitigation into strategic planning and operational processes for its business units through the adoption of standards and best practices. The Company has developed an enterprise risk matrix to identify risks to its people, the environment, its assets and its reputation, and to systematically mitigate these risks to an acceptable level.

The Company attempts to mitigate its financial, operational and strategic risks to an acceptable level through a variety of policies, systems and processes. The following provides a list of the most significant risks relating to the Company and its operations.

5.2 Significant Risk Factors

Operational and Safety Incidents

The Company’s businesses are subject to inherent operational risks which have the potential to impact safety, the environment, its assets and its reputation. In general, the Company’s operations are subject to operational risks, including, but not limited to: fires, loss of containment, blowouts, power outages, freeze-ups and other similar events; oil and natural gas leaks; encountering unexpected formations or pressures; premature declines of reservoir pressure or productivity; uncontrollable flows of oil, natural gas and well fluids; spills at truck terminals and hubs; spills associated with the loading and unloading of potentially harmful substances onto trucks; release of tailings or harmful substances into a water system; the breakdown or failure of equipment, pipelines and facilities, information systems and processes; the performance of equipment at levels below those originally intended (whether due to misuse, unexpected degradation or design, construction or manufacturing defects); releases or spills from shipping vessels; failure to maintain adequate supplies of spare parts; the compromise of information technology and control systems and related data; operator error; labour disputes; disputes with interconnected facilities and carriers; operational disruptions or apportionment on third-party systems or refineries, which may prevent the full utilization of the company’s facilities and pipelines; epidemics or pandemics; and catastrophic events, including, but not limited to, war, extreme weather events, natural disasters, explosions, acts of sabotage and other similar events.

Failure to manage the hazards and associated risks effectively could result in potential fatalities, environmental impacts, interruptions to activities or use of assets, or loss of license to operate. The Company implements an Operational Integrity Management System designed to systematically identify, assess and manage operational and safety risks to tolerable levels. In addition, the Company, in accordance with industry practice, maintains insurance coverage against losses from certain of these risks. Nonetheless, insurance proceeds may not be sufficient to cover all losses, and insurance coverage may not be available for all types of operational risks.

Commodity Price Volatility

The Company’s results of operations and financial condition are dependent on the prices received for its refined products, crude oil, NGL and conventional natural gas production. Lower prices for crude oil, NGL and conventional natural gas could adversely affect the value and quantity of the Company’s oil and gas reserves. The Company’s reserves include significant quantities of heavier grades of crude oil that often trade at a discount to light crude oil. Heavier grades of crude oil are typically more expensive to produce, process, transport and refine into high-value refined products. Refining and transportation capacity for various grades of crude oil may be constrained from time to time, creating the need for additional refining and

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 33

transportation capacity. Wider price differentials between heavier and lighter grades of crude oil could have a material adverse effect on the Company’s results of operations and financial condition, reduce the value and quantities of the Company’s heavier crude oil reserves and delay or cancel projects that involve the development of heavier crude oil resources. There is no guarantee that pipeline development projects or other transportation alternatives will provide sufficient transportation capacity and access to refining capacity to accommodate expected increases in North American heavy crude oil and bitumen production.

Prices for refined products and crude oil are based on world supply and demand. Supply and demand can be affected by several factors including, but not limited to, actions taken by OPEC, non-OPEC crude oil supply, social conditions in oil producing countries, the occurrence of natural disasters, general and specific economic conditions, technological developments, prevailing weather patterns, government regulation and policies and the availability of alternate sources of energy.

The Company’s conventional natural gas production is currently located in Western Canada and Asia Pacific. Western Canada’s conventional natural gas production is subject to North American market forces. North American natural gas supply and demand is affected by several factors including, but not limited to, the amount of conventional natural gas available to specific market areas either from the wellhead of existing or accessible conventional or unconventional sources (such as from shale) or from storage facilities, technological developments, prevailing weather patterns, the U.S. and Canadian economies, the occurrence of natural disasters and pipeline restrictions. The price received by the Company for production from Asia Pacific is determined by long-term contracts.

In certain instances, the Company will use derivative instruments to manage exposure to price volatility on a portion of its refined product, oil and gas production, inventory or volumes in long-distance transit. The Company may also use firm commitments for the purchase or sale of crude oil and conventional natural gas.

The fluctuations in refined products, crude oil and conventional natural gas prices are beyond the Company’s control and could have a material adverse effect on the Company’s results of operations and financial condition.

Commodity Price Risk

In certain instances, the Company uses derivative commodity instruments and futures contracts on commodity exchanges, including commodity put and call options under a short-term hedging program, to manage exposure to price volatility on a portion of its refined product, oil and gas production, and inventory or volumes in long distance transit. The Company may also use firm commitments for the purchase or sale of crude oil and conventional natural gas.

The Company’s results will be impacted by a decrease in the price of crude oil and conventional natural gas inventory. The Company has crude oil inventories that are feedstock, held at terminals or part of the in-process inventories at its refineries and at offshore sites. Due to the integrated nature, the Company has a natural partial mitigation to the WCS differential risk. The Company also has conventional natural gas inventory that could have an impact on earnings based on changes in conventional natural gas prices. All these inventories are subject to a lower of cost or net realizable value test on a quarterly basis.

Reservoir Performance and Reserves Estimate Risk

Lower than projected reservoir performance on the Company’s key growth projects could have a material adverse effect on the Company’s results of operations, financial condition, business strategy and reserves. Inaccurate appraisal of large project reservoirs could result in missed production, revenue and earnings targets and negatively affect the Company’s reputation and investor confidence.

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In order to maintain the Company’s future production of crude oil, conventional natural gas and NGL and maintain the value of the reserves portfolio, additional reserves must be added through discoveries, extensions, improved recovery, performance related revisions and acquisitions. The production rate of oil and gas properties tends to decline as reserves are depleted while the associated unit operating costs increase. Maintaining an inventory of projects that can be developed depends upon, but is not limited to, obtaining and renewing rights to explore, develop and produce oil and natural gas, drilling success, completion of long lead time capital intensive projects on budget and on schedule and the application of successful exploitation techniques on mature properties.

The reserves data contained or referenced in this MD&A represent estimates only. The accurate assessment of oil and gas reserves is critical to the continuous and effective management of the Company’s upstream assets. Reserves estimates support various investment decisions about the development and management of oil and gas properties. In general, estimates of economically recoverable crude oil and conventional natural gas reserves and the future net cash flow therefrom are based upon a number of variable factors and assumptions, such as product prices, future operating and capital costs, historical production from the properties and the effects of regulation by government agencies, including with respect to royalty payments, all of which may vary considerably from actual results. The Company uses all available information at the effective date of the evaluation and internal qualified reserves evaluators to prepare the reserves estimates. As required by NI 51-101, the Company obtains the opinion of an independent reserves auditor on the Company’s reserves. The audit covers more than 75% of the future net revenue discounted at 10% attributable to proved plus probable reserves with the remainder reviewed by the independent qualified reserves auditor. However, given the best technical information and evaluation techniques, all such estimates are still to some degree uncertain. All reserves estimates involve a degree of ambiguity and, at times, rely on indirect measurement techniques to estimate the size and recoverability of the resource. While new technologies have increased the accuracy of these techniques, there remains the potential for human or systemic error in recording and reporting the magnitude of the Company’s oil and gas reserves. Estimates of the economically recoverable oil and gas reserves attributable to any particular property or group of properties, and estimates of future net revenues expected therefrom, may differ substantially from actual results even though the total company reserves are shown to be reliable through the historical total company technical reserves revisions. The Company has a diverse portfolio of assets by product type, reservoir type and location which is a factor in mitigating specific property risks.

Restricted Market Access and Pipeline Interruptions

The Company’s results of operations and financial condition depend upon the Company’s ability to deliver products to the most attractive markets. The Company’s results of operations could be materially adversely affected by restricted market access resulting from a lack of pipeline or other transportation alternatives to attractive markets as well as regulatory and/or other marketplace barriers. Interruptions and restrictions may be caused by the inability of a pipeline to operate, or they can be related to capacity constraints as the supply of feedstock into the system exceeds the infrastructure capacity. If oil production across North America experiences growth, the availability of infrastructure to carry the Company’s products to the marketplace may be restricted in the next few years. Restricted market access may potentially have a material adverse effect on the Company’s results of operations, financial condition and business strategy. Unplanned shutdowns and closures of its refineries or Upgrader may limit the Company’s ability to deliver product with a material adverse effect on sales and results of operations.

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Aviation Incidents

The Company’s Offshore operations in Canada and China rely on regular travel by helicopter. A helicopter incident resulting in loss of life, facility shutdown or regulatory action could have a material adverse effect on the operations of the Company. This risk is managed through an aviation management process. Aviation Safety Reviews are conducted by third party specialist contractors to verify that helicopter service providers meet the Company’s and industry standards with respect to aviation safety. The reviews include evaluation of aircraft type, effectiveness of the safety and maintenance management systems and competency and training programs for critical roles in the operation of helicopters. Helicopters chartered to support Husky Offshore operations must be fit for service and as such are fitted with multiple redundant systems to address a wide range of potential in-flight emergencies. Additional measures specific to the Company’s challenging operating environments are specified in the Company’s design requirements including anti- icing and floatation systems effective for the maximum allowable sea height operating limits. Pilots are trained to address potential emergency situations through regular real-time and simulator training aligned with industry best practice.

Security and Terrorist Threats

Security threats and terrorist or activist activities may impact the Company’s personnel, which could result in injury, death, extortion, hostage situations and/or kidnapping, including unlawful confinement. A security threat, terrorist attack or extremist incident targeted at a facility, office or offshore vessel/installation owned or operated by the Company could result in the interruption or cessation of key elements of the Company’s operations. Outcomes of such incidents could have a material adverse effect on the Company’s results of operations, financial condition and business strategy. The risk to employees and board members due to ongoing social unrest in Hong Kong is being managed through reduced travel and increased awareness and monitoring of the situation. The potential for detention and/ or incarceration of the Company’s employees/contractors entering or working in China remains, and as a result, review and reconsideration for travel into China has become a business/corporate process.

The Company does not own proved or probable reserves in or near areas of armed conflict. According to the Uppsala Conflict Data Program, armed conflict is defined as “contested incompatibility that concerns government and/or territory over which the use of armed force between the military forces of two parties, of which at least one is the government of a state, has resulted in at least 25 battle-related deaths each year.”

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Skilled Workforce Attraction and Retention

Successful execution of the Company’s strategy is dependent on ensuring the Company’s workforce possesses the appropriate skill level. Failure to attract and retain personnel with the required skill levels could have a material adverse effect on the Company’s financial condition and results of operations.

Partner Misalignment

Joint venture partners operate or jointly control a portion of the Company’s assets in which the Company has an ownership interest. This can reduce the Company’s control and ability to manage risks. The Company is at times dependent upon its partners for the successful execution of various projects. If a dispute with partners were to occur over the development and operation of a project or if partners were unable to fund their contractual share of the capital expenditures, a project could be delayed and the Company could be partially or totally liable for its partner’s share of the project.

Major Project Execution

The Company manages a variety of oil and gas projects ranging from upstream to downstream assets across its global portfolio. The wide range of risks associated with project development and execution, as well as the commissioning and integration of new facilities with existing assets, can impact the economic viability of the Company’s projects. Project risks may result in extended stakeholder consultation, additional environmental assessments and public hearings which may delay necessary environmental and regulatory approvals. Project risks may also manifest through schedule delays, cost overruns and commodity price drops. Some risks can impact the Company’s safety and environmental records thereby negatively affecting the Company’s reputation and social license to operate.

Government Regulation

Given the scope and complexity of the Company’s operations, the Company is subject to regulations and interventions by governments at the federal, provincial, state and municipal levels in the countries in which it conducts its operations, or development or exploratory activities. As these governments continually balance the needs of the community for economic growth with Indigenous interests and stakeholders, the Company recognizes that the magnitude of regulatory risks has the potential to change over time. Changes in government policy, legislation or regulations could impact the Company’s existing and planned projects as well as impose costs of compliance and increase capital expenditures and operating expenses. Examples of the Company’s regulatory risks include, but are not limited to, uncertain or negative interactions with governments, uncertain energy policies, uncertain climate policies, uncertain environmental and safety policies, penalties, taxes, royalties, government fees, reserves access, limitations or increases in costs relating to the exportation of commodities, production restrictions, restrictions on the acquisition of exploration and production rights and land tenure, expropriation or cancellation of contract rights, limitations on control over the development and abandonment of fields and loss of licences to operate.

Environmental Risks

Changes in environmental regulations could have a material adverse effect on the Company’s results of operations, financial condition and business strategy by requiring increased capital expenditures and operating costs or by impacting the quality of, formulation of or demand for the Company’s products, which may or may not be offset through market pricing.

The Company anticipates that further changes in environmental legislation could occur, which may result in stricter standards and enforcement, larger fines and liabilities, the introduction of emissions limits, increased compliance costs and approval delays for critical licences and permits. Public and investment community interest in environmental, social and governance issues has also increased significantly in recent years, as evidenced by the large number of signatories to the United Nations Principles for Responsible Investment.

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It is not possible to accurately forecast the amount of additional investment in new or existing facilities required in the future for environmental protection or to address all new regulatory compliance requirements, such as reporting.

Climate Change Risks

Regulatory

Climate change regulations may become more onerous over time as governments implement policies to further reduce greenhouse gases (“GHG“) emissions. As these regulations continue to evolve, they could have a material adverse effect on the Company’s competitiveness, financial condition and results of operations through increased capital and operating costs and change in demand for refined products such as transportation fuels. Costs associated with levy payments for emerging climate change regulations may be significant.

In December 2018, the Government of Canada published the Regulatory Design Paper on the Clean Fuel Standard (“CFS”) that focuses on the liquid fuel stream regulations. The final regulations for liquid fuels are planned for early 2021, with the regulations expected to come into force in 2022. In December 2020, the Canadian government announced it would not be going forward with legislation on the gaseous and solids streams of the CFS.

The Company’s U.S. Refining business could be exposed to increased costs related to Environmental Protection Agency’s (”EPA”) climate change rules by future U.S. GHG legislation that applies to the oil and gas industry, or consumption of petroleum products, or other legislation/regulation at the state or local level. Such legislation or regulations could require the Company’s U.S. Refining operations to significantly reduce emissions and/or purchase emissions credits, thereby increasing operating and capital costs, and could change the demand for refined products which may have a material adverse effect on the Company’s financial condition.

The Company complies with the Renewable Fuel Standard (“RFS”) program in the U.S. by blending renewable fuels manufactured by third parties and by purchasing RINs on the open market. Due to regulatory uncertainty and in part due to the U.S. fuel supply reaching the “blend wall” (the 10% limit prescribed by most automobile warranties), the price and availability of RINs have been volatile. The Company cannot predict the future prices of RINs and renewable fuel blendstocks, and the costs to obtain the necessary RINs and blendstocks could be material. The Company’s financial position and results of operations could be adversely affected if it is unable to pass the compliance costs on to its customers and if the Company pays significantly higher prices for RINs or blendstocks to comply with the RFS mandated standards.

Climatic Conditions

Extreme climatic conditions may also have material adverse effects on the Company’s financial condition and results of operations. Weather and climate affect demand, and therefore, the predictability of the demand for energy is affected to a large degree by the predictability of weather and climate. In addition, the Company’s exploration, production and construction operations, and the operations of major customers and suppliers, can be affected by extreme weather. This may result in cessation or diminishment of production, delay of exploration and development activities or delay of plant construction.

The Company operates in some of the harshest environments in the world, including offshore NL. Climate change may increase the frequency of severe weather conditions in these locations including winds, flooding and variable temperatures, which are contributing to the melting of northern ice and increased creation of icebergs. Icebergs off the coast of NL may threaten Atlantic oil production facilities, cause damage to equipment and possible production disruptions, spills, other asset damage and human impacts.

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Transition

In addition to emissions regulations and the physical risks of climate change, climate-related transition risks could have a material adverse effect on the Company’s business, financial condition and results of operations, and could adversely impact the Company’s reputation. For example, increased opposition to companies in the oil sands industry could lead to constrained access to insurance, liquidity and capital and changes in demand for the Company’s products, which may impact revenue. Any increases in GHG emissions by the Company could lead to additional taxes and levies, which would increase the costs associated with certain projects. The potential need to develop new technologies to reduce the intensity of GHG emissions could require significant capital investment. Further, the Company may become subject to climate change litigation initiated by third parties. The Company’s management monitors these risks and reports to the Board through management’s Enterprise Risk Management framework.

Overall, the Company is not able to estimate at this time the degree to which climate change related regulatory, climatic conditions, and transition risks could impact the Company’s financial and operating results.

Cybersecurity Threats

As an oil and gas producer, the Company’s ability to operate effectively is dependent upon developing and maintaining information systems and infrastructure that support the financial and general operating aspects of the business. Concurrently, the oil and gas industry has become the subject of increased levels of cybersecurity threats.

The Company has security measures, policies and controls designed to protect and secure the integrity of its information technology systems. The Company takes a proactive approach by continuing to invest in technology, processes and people to help minimize the impact of the changing cyber landscape and enhance the Company’s resilience to cyber incidents. However, cybersecurity threats frequently change and require ongoing monitoring and detection capabilities. Such cybersecurity threats include unauthorized access to information technology systems due to hacking, viruses and other causes for purposes of misappropriating assets or sensitive information, corrupting data or causing operational disruption. Cyber attacks could result in the loss or exposure of confidential information related to retail credit card information, personnel files, exploration activities, corporate actions, executive officer communications and financial results. The significance of any such event is difficult to quantify, but if the breach is material in nature, it could adversely affect the financial performance of the Company, its operations, its reputation and its standing and expose it to regulatory consequences and claims of third-party damage, all of which could materially adversely affect the Company’s results of operations and financial condition if the situation is not resolved in a timely manner, or if the financial impact of such adverse effects is not alleviated through insurance policies.

Although to date the Company has not experienced any material losses relating to cyber attacks or other information security breaches, there can be no assurance that the Company will not incur such losses in the future. The Company’s risk and exposure to these matters cannot be fully mitigated because of, among other things, the evolving nature of these threats.

International Operations

International operations can expose the Company to uncertain political, economic and other risks. The Company’s operations in certain jurisdictions may be materially adversely affected by political, economic or social instability or events. These events may include, but are not limited to, onerous fiscal policy, renegotiation or nullification of agreements and treaties, imposition of onerous regulation, changes in laws governing existing operations, financial constraints, including currency restrictions and exchange rate fluctuations, unreasonable taxation and behaviour of public officials, joint venture partners or third-party representatives that could result in lost business opportunities for the Company. This could materially adversely affect the Company’s interest in its foreign operations, results of operations and financial condition.

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Litigation, Administrative Proceedings and Regulatory Actions

The Company may be subject to litigation, claims, administrative proceedings and regulatory actions, which may be material. Such claims could relate to environmental damage, climate change and the impacts thereof, failure to comply with applicable laws and regulations, breach of contract, tax, bribery and employment matters, which could result in an unfavourable decision, including fines, sanctions, monetary damages, temporary suspensions of operations or the inability to engage in certain operations or transactions. The outcome of such claims can be difficult to assess or quantify and may have a material adverse effect on the Company’s reputation, financial condition and results of operations. The defence to such claims may be costly and could divert management’s attention away from day-to-day operations.

Foreign Currency

The Company’s results are affected by the exchange rates between various currencies including the Canadian and U.S. dollars. The majority of the Company’s expenditures are in Canadian dollars while most of the Company’s revenues are received in U.S. dollars from the sale of oil and gas commodities that receive prices determined by reference to U.S. benchmark prices. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease the revenues received from the sale of oil and gas commodities. Correspondingly, a decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of oil and gas commodities. In addition, a change in the value of the Canadian dollar against the U.S. dollar will result in an increase or decrease in the Company’s U.S. dollar-denominated debt and related interest expense, as expressed in Canadian dollars. The fluctuations in exchange rates are beyond the Company’s control and could have a material adverse effect on the Company’s results of operations and financial condition.

The Company enters into short-dated foreign exchange contracts to fix the exchange rate for conversion of U.S. dollar denominated revenue to hedge against these potential fluctuations. The Company also designates its U.S. denominated debt as a hedge of the Company’s net investment in selected foreign operations with a U.S. dollar functional currency.

Interest Rate

Interest rate risk is the impact of fluctuating interest rates on financial condition. In order to manage interest rate risk and the resulting interest expense, the Company mitigates some of its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt through the use of its credit facilities and various financial instruments. The optimal mix maintained will depend on market conditions. The Company may also enter into interest rate swaps from time to time as an additional means of managing current and future interest rate risk.

Counterparty Credit

Credit risk represents the financial loss that the Company would suffer if the Company’s counterparties in a transaction fail to meet or discharge their obligation to the Company. The Company actively manages this exposure to credit and contract execution risk from both a customer and a supplier perspective. Internal credit policies have governed the Company’s credit portfolio and have limited transactions according to a counterparty’s and a supplier’s credit quality. Counterparties for financial derivatives transacted by the Company are generally major financial institutions or counterparties with investment grade credit ratings.

Liquidity

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. The Company’s process for managing liquidity risk includes ensuring, to the extent possible, that it has access to multiple sources of capital.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 40

Debt Covenants

The Company’s credit facilities include financial covenants, which contain a consolidated debt to total capitalization covenant. If the Company does not comply with the covenants under these credit facilities, there is a risk that repayment could be accelerated.

Credit Rating Risk

Credit ratings affect the Company’s ability to obtain both short-term and long-term financing and the cost of such financing. Additionally, the ability of the Company to engage in ordinary course derivative or hedging transactions and maintain ordinary course contracts with customers and suppliers on acceptable terms depends on the Company’s credit ratings. A reduction in the current rating on the Company’s debt by one or more of its rating agencies, particularly a downgrade below investment grade ratings, or a negative change in the Company’s ratings outlook could materially adversely affect the Company’s cost of financing and its access to sources of liquidity and capital. Credit ratings are intended to provide investors with an independent measure of credit quality of any issuer of securities. The credit ratings accorded to the Company’s securities by the rating agencies are not recommendations to purchase, hold or sell the securities in as much as such ratings do not comment as to market price or suitability for a particular investor. Any rating may not remain in effect for any given period of time or may be revised or withdrawn entirely by a rating agency in the future if in its judgment circumstances so warrant.

As at December 31, 2020, Husky had the following credit ratings:

	Standard and Poor’s Rating Services (“S&P”)	Moody’s Investor Service (“Moody’s”)	Dominion Bond Rating Services Limited (“DBRS”)
Outlook/Trend	On CreditWatch with Negative Implications	On Review for Downgrade	Under Review with Negative Implications
Senior Unsecured Debt	BBB	Baa2	BBB (high)
Series 1 Preferred Shares	P-3(high)		Pfd-3(high)
Series 2 Preferred Shares	P-3(high)		Pfd-3(high)
Series 3 Preferred Shares	P-3(high)		Pfd-3(high)
Series 5 Preferred Shares	P-3(high)		Pfd-3(high)
Series 7 Preferred Shares	P-3(high)		Pfd-3(high)
Commercial Paper			R-2(high)

With the closing of the Cenovus Transaction announced on January 4, 2021, all rating agencies revised their rating opinions and Husky’s credit ratings now are:

	Standard and Poor’s Rating Services (“S&P”)	Moody’s Investor Service (“Moody’s”)	Dominion Bond Rating Services Limited (“DBRS”)	Fitch Ratings (“Fitch”)
Outlook/Trend	Stable	Negative	Stable	Positive
Senior Unsecured Debt	BBB-	Baa3	BBB	BB+

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 41

Refer to section 6.3 for the full timeline of ratings actions. Husky preferred shares were delisted by the TSX at the close of market on January 5, 2021 and the preferred share ratings were transferred to Cenovus. DBRS Morningstar has discontinued and withdrawn its rating on the Commercial Paper at the request of the Company. As a result of Husky now being a subsidiary of Cenovus, Fitch has applied the BB+ Positive rating to Husky and its long-term debt.

General Economic Conditions

General economic conditions may have a material adverse effect on the Company’s results of operations and financial condition. A decline in economic activity will reduce demand for petroleum products and adversely affect the price the Company receives for its commodities. The Company’s cash flow could decline, assets could be impaired, future access to capital could be restricted and major development projects could be delayed or abandoned.

Competition

The energy industry is highly competitive with respect to gaining access to the resources required to increase oil and gas reserves and production, and gaining access to markets. The Company competes with others to acquire prospective lands, retain drilling capacity and field operating and construction services, obtain sufficient pipeline and other transportation capacity, gain access to and retain adequate markets for its products and services and gain access to capital markets. The Company’s ability to successfully complete development projects could be materially adversely affected if it is unable to acquire economic supplies and services due to competition. Subsequent increases in the cost of or delays in acquiring supplies and services could result in uneconomic projects. The Company’s competitors comprise all types of energy companies, some of which have greater resources.

Cost or Availability of Oil and Gas Field Equipment

The cost or availability of oil and gas field equipment may adversely affect the Company’s ability to undertake exploration, development and construction projects. The oil and gas industry is cyclical in nature and is prone to shortages of supply of equipment and services including drilling rigs, geological and geophysical services, engineering and construction services and construction materials. These materials and services may not be available when required at reasonable prices. Without compromising safety, overall quality and environmental impacts, the Company continually develops its approved suppliers base to provide undisrupted access to materials, equipment and services, while maintaining a competitive cost baseline via cost escalation mitigation strategies.

Financial Controls

While the Company has determined that its disclosure controls and procedures and internal controls over financial reporting are effective, such controls can only provide reasonable assurance with respect to financial statement preparation and disclosure. Failure to prevent, detect and correct misstatements could have a material adverse effect on the Company’s results of operations and financial condition.

Possible Failure to Realize Anticipated Benefits of the Cenovus Transaction

Cenovus and Husky completed the Cenovus Transaction to create an integrated energy leader and realize certain benefits including, among other things, potential synergies and cost savings. Achieving the benefits of the Cenovus Transaction depends in part on successfully consolidating functions and integrating operations, procedures and personnel in a timely and efficient manner, as well as the combined company’s ability to realize the anticipated growth opportunities and synergies from integrating the respective businesses of Cenovus and Husky following completion of the Cenovus Transaction.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 42

Achieving the benefits of the Cenovus Transaction also depends on the ability of the combined company to effectively capitalize on its scale, scope and leadership position in the oil sands and wider oil and natural gas industry, to realize the anticipated capital and operating synergies, to profitably sequence the growth prospects of its asset base and to maximize the potential of its improved growth opportunities and capital funding opportunities as a result of combining the businesses and operations of Cenovus and Husky.

The integration of the Cenovus and Husky assets will require the dedication of substantial management effort, time and resources which may divert management’s focus and resources from other strategic opportunities and from operational matters. The integration process may result in the loss of key employees and the disruption of ongoing business and employee relationships that may adversely affect the combined company’s ability to achieve the anticipated benefits of the Cenovus Transaction. A variety of factors, including those other risk factors set forth in this MD&A may adversely affect the ability to achieve the anticipated benefits of the Cenovus Transaction.

Entry into New Business Activities

Completion of the Cenovus Transaction has resulted in a combination of the business activities previously carried on by each of Husky and Cenovus as separate entities. The combination of these activities into the combined company may expose shareholders to different business risks than those to which they were exposed prior to the completion of the Cenovus Transaction. As a result of the changing risk profile of the companies, the combined company may be subject to review of its credit ratings, which may result in a downgrade or negative outlook being assigned to the combined company.

Most operational and strategic decisions and certain staffing decisions with respect to integration have not yet been made. These decisions and the integration of the two companies will present challenges to management, including the integration of systems, policies and personnel of the two companies which may be geographically separated, unanticipated liabilities and unanticipated costs. It is possible that the integration process could result in the loss of key employees, the disruption of the respective ongoing businesses or inconsistencies in standards, controls, procedures and policies that adversely affect the ability of management to maintain relationships with customers, suppliers, employees and other constituencies or to achieve the anticipated benefits of the Cenovus Transaction. The performance of the combined company’s operations could be adversely affected if the combined company cannot retain key employees to assist in the integration and operation of Husky and Cenovus.

Any inability of management to successfully integrate the operations could have a material adverse effect on the business, financial condition and results of operations of the combined company.

Ongoing Impacts of the COVID-19 Pandemic

The recent COVID-19 pandemic, and actions taken, and that may be taken, by governmental authorities in response thereto, have resulted and may continue to result in, among other things: increased volatility in financial markets and foreign currency exchange rates; disruptions to global supply chains; adverse effects on the health and safety of the Company’s workforce, or guidelines or restrictions to protect health and safety of such workforces, rendering employees unable to work or travel; temporary operational restrictions; and an overall slowdown in the global economy. In particular, the COVID-19 pandemic has resulted in, and may continue to result in, a reduction in the demand for, and prices of, commodities that are closely linked to the Company’s financial performance, including crude oil, refined petroleum products (such as jet fuel, diesel and gasoline), natural gas and electricity, and also increases the risk that storage for crude oil and refined petroleum products could reach capacity in certain geographic locations in which the Company operates. A prolonged period of decreased demand for, and prices of, these commodities, and any applicable storage constraints, could also result in the Company voluntarily curtailing or shutting in production and a decrease in the Company’s refined product volumes and refinery utilization rates, which could adversely impact the Company’s business, financial condition and results of operations.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 43

The COVID-19 pandemic continues to rapidly evolve and its effect on supply and demand patterns is expected to result in negative impacts on the Company’s business, financial condition and results of operations over the near term. To the extent that the COVID-19 pandemic adversely affects the Company’s business, financial condition and results of operations, it may also have the effect of heightening many of the other risks described in this MD&A.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 44

6.0 Liquidity and Capital Resources

6.1 Summary of Cash Flow

Cash Flow Summary ($ millions)	2020			2019
Cash flow
Operating activities		841			2,971
Financing activities		274			(817	)
Investing activities		(2,129	)		(3,197	)

Cash Flow from Operating Activities

Cash flow generated from operating activities decreased by $2,130 million in 2020 compared to 2019. The decrease was primarily due to lower realized crude oil and refined product pricing and lower refining margins in the Lloydminster Heavy Oil Value Chain and the U.S. Refining segments, as a result of the significant decline in crude oil and refined product prices in 2020.

Cash Flow from Financing Activities

Cash flow generated for financing activities increased by $1,091 million in 2020 compared to 2019. The increase was primarily due to long-term debt issuances combined with lower common share dividend payments in 2020.

Cash Flow used for Investing Activities

Cash flow used for investing activities decreased by $1,068 million in 2020 compared to 2019. The decrease was primarily due to reduced capital expenditures in 2020.

6.2 Working Capital Components

Working capital is the amount by which current assets exceed current liabilities. At December 31, 2020, the Company’s working capital was $738 million compared to $302 million at December 31, 2019. The Company’s working capital is as follows:

Working Capital ($ millions)	December 31, 2020			December 31, 2019			Change
Cash and cash equivalents		735			1,775			(1,040	)
Accounts receivable		1,119			1,499			(380	)
Income taxes receivable		—			30			(30	)
Inventories		1,115			1,486			(371	)
Prepaid expenses		161			148			13
Accounts payable and accrued liabilities		(2,129	)		(3,465	)		1,336
Income taxes payable		(27	)		—			(27	)
Short-term debt		(40	)		(550	)		510
Long-term debt due within one year		—			(400	)		400
Lease liabilities		(102	)		(109	)		7
Asset retirement obligations		(94	)		(112	)		18
Net working capital		738			302			436

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 45

The decrease in cash and cash equivalents was primarily due to lower cash flow from operating activities. The decrease in accounts receivable was primarily due to lower revenues in the fourth quarter of 2020 compared to the fourth quarter of 2019. The decrease in inventories was primarily due to lower commodity prices at the end of 2020 compared to 2019. The decrease in accounts payable and accrued liabilities was primarily due to lower capital expenditures, a lower common share dividend and timing of settlements in 2020 compared to 2019. The decrease in short-term debt and long-term debt due within one year was due to repayments in 2020.

6.3 Sources of Liquidity

Liquidity describes a company’s ability to access cash. Sources of liquidity include cash and cash equivalents on hand, funds from operations, proceeds from the issuance of short and long-term debt, availability of short and long-term credit facilities and proceeds from asset sales. Since the Company operates in the upstream oil and gas industry, it requires significant cash to fund capital programs necessary to maintain or increase production, develop reserves, acquire strategic oil and gas assets and repay maturing debt.

During times of low oil and gas prices, a portion of capital programs can generally be deferred. However, due to the long cycle times and the importance to future cash flow in maintaining the Company’s production, it may be necessary to utilize alternative sources of capital to continue the Company’s strategic investment plan during periods of low commodity prices. As a result, the Company frequently evaluates the options available with respect to sources of short and long-term capital resources. The Company believes that it has sufficient liquidity to sustain its operations, fund capital programs and meet non-cancellable contractual obligations and commitments in the short and long-term principally by cash generated from operating activities, cash on hand, the issuance of debt, borrowings under committed and uncommitted credit facilities and cash proceeds from asset sales.

At December 31, 2020, the Company had the following available credit facilities:

Credit Facilities ($ millions)	Available		Unused
Operating facilities(1)		975		508
Syndicated credit facilities		4,000		3,650
		4,975		4,158

⁽¹⁾  Consists of demand credit facilities.

At December 31, 2020, the Company had $4,158 million of unused credit facilities of which $3,650 million were long-term committed credit facilities and $508 million were short-term uncommitted credit facilities. A total of $427 million short-term uncommitted borrowing credit facilities was used in support of outstanding letters of credit and $nil of long-term committed borrowing credit facilities was used in support of commercial paper. At December 31, 2020, the Company had $40 million of direct borrowing against the short-term uncommitted credit facilities. At December 31, 2020, the Company had $350 million outstanding under its $2.0 billion committed syndicated credit facility expiring June 19, 2022 (December 31, 2019 – no direct borrowings), and no direct borrowings under its $2.0 billion committed syndicated credit facility expiring March 9, 2024 (December 31, 2019 – no direct borrowings). The Company’s ability to renew existing bank credit facilities and issuances of new debt are dependent upon maintaining an investment grade credit rating and the condition of capital and credit markets. Credit ratings may be affected by the Company’s level of debt, from time to time.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 46

The Company’s leverage covenant under its credit facilities is a debt to capital ratio and calculated as total debt (long-term debt including long-term debt due within one year and short-term debt) and certain adjusting items specified in the credit agreements divided by total debt and shareholders’ equity. This covenant is used to assess the Company’s financial strength. If the Company does not comply with the covenant under the credit facilities, there is risk that repayment could be accelerated. The Company was in compliance with this covenant under its credit facilities at December 31, 2020, and assessed the risk of non-compliance to be low.

Sunrise Oil Sands Partnership has an unsecured demand credit facility of $10 million available for general purposes. The Company’s proportionate share is $5 million. There were no amounts drawn on this demand credit facility at December 31, 2020.

On March 15, 2019, the Company issued US$750 million in senior unsecured notes. The notes bear an annual interest rate of 4.40% and are due on April 15, 2029. The Company raised the net proceeds of the offering for general corporate purposes, which included the repayment of certain outstanding debt securities that matured in 2019.

On May 1, 2019, the Company filed a universal short form base shelf prospectus (the “2019 Canadian Shelf Prospectus”) with applicable securities regulators in each of the provinces of Canada that enabled the Company to offer up to $3.0 billion of common shares, preferred shares, debt securities, subscription receipts, warrants and other units in Canada. As a result of the delisting of Husky’s shares from the TSX, the Company is unable to sell securities under the 2019 Canadian Shelf Prospectus.

On June 17, 2019, the Company repaid the maturing 6.15% notes. The amount paid to note holders was $402 million.

On December 16, 2019, the Company repaid the maturing 7.25% notes. The amount paid to note holders was $987 million.

On March 3, 2020, the Company filed a universal short form base shelf prospectus (the “2020 U.S. Shelf Prospectus”) with the Alberta Securities Commission. On March 4, 2020, the Company’s related U.S. registration statement filed with the SEC containing the 2020 U.S. Shelf Prospectus became effective which enabled the Company to offer up to US$3.0 billion of debt securities, common shares, preferred shares, subscription receipts, warrants and units of the Company in the U.S. During the period that the 2020 U.S. Shelf Prospectus and the related U.S registration statement were effective, securities could be offered in amounts, at prices and on terms set forth in a prospectus supplement. On January 26, 2021, the Company terminated the effectiveness of the U.S. registration statement.

On March 12, 2020, the Company repaid the maturing 5.00% notes. The principal paid to note holders was $400 million.

On April 7, 2020 the Company entered into a $500 million unsecured non-revolving term credit facility. Interest payable is based on pricing referenced to CAD Bankers’ Acceptance or CAD Prime Rates. The facility was repaid on October 5, 2020.

On June 17, 2020, DBRS Morningstar downgraded Husky’s issuer rating and senior unsecured notes and debentures rating to BBB(high) from A(low), its commercial paper rating to R-2(high) from R-1(low) and its preferred shares - cumulative rating to Pfd-3(high) from Pfd-2(low). All trends were negative. With this action, DBRS Morningstar removed the ratings from under review with negative implications which were placed on March 26, 2020 in response to the extreme price declines and heightened volatility in crude oil markets largely caused by the rapid spread of the COVID-19 pandemic and the concurrent crude oil-price war between OPEC, led by Saudi Arabia and Russia.

On June 30, 2020, S&P Global Ratings affirmed all of its ratings on Husky, including its ‘BBB’ issuer credit and senior unsecured debt ratings. At the same time, they also affirmed the P-3(High) rating on the Company’s preferred shares. All trends remained negative.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 47

On August 7, 2020, the Company issued $1.25 billion of notes. The notes have a coupon of 3.50% and are due on February 7, 2028. Proceeds were for general corporate purposes, which included the repayment of Husky’s $500 million unsecured non-revolving term loan credit facility on October 5, 2020.

On August 11, 2020 Moody’s affirmed its Baa2 stable issuer credit rating on Husky.

With the announcement of the Cenovus Transaction on October 25, all rating agencies adjusted their ratings opinions.

On October 25, 2020, DBRS Morningstar placed Husky’s issuer rating and senior unsecured notes and debentures rating of “BBB(high)”, commercial paper rating of R-2(high) and preferred shares - cumulative rating of Pfd-3(high) Under Review with Negative Implications.

On October 25, 2020, S&P placed Husky’s “BBB” long-term issuer credit and senior unsecured debt rating and P-3(high) preferred share ratings on CreditWatch with Negative Implications.

On October 26, 2020, Moody’s placed Husky’s “Baa2” senior unsecured ratings On Review for Downgrade.

At December 31, 2020, the Company had unused capacity of $1.75 billion under the 2019 Canadian Shelf Prospectus and US$3.0 billion under the 2020 U.S. Shelf Prospectus and related U.S. registration statement.

With the closing of the Cenovus Transaction announced on January 4, 2021, all rating agencies finalized their rating opinions.

On January 4, 2021, DBRS Morningstar downgraded Husky’s issuer rating and senior unsecured notes and debentures rating to “BBB” from “BBB (high)”, preferred shares ratings to “Pfd-3” from “Pfd-3 (high)”, and commercial paper to “R-2 (middle)” from “R-2 (high)” and assigned a stable outlook removing the ratings from Under Review with Negative Implications assigned on October 25, 2020.

On January 4, 2021, S&P lowered Husky’s long-term issuer credit and senior unsecured debt rating to “BBB-” from “BBB” and preferred share ratings to “P-3” from “P-3(High)” and assigned a stable outlook, removing the CreditWatch with Negative Implications previously assigned on October 25, 2020.

On January 4, 2021, Moody’s downgraded Husky’s senior unsecured rating to “Baa3” from “Baa2” and assigned a negative outlook, removing the Under Review assigned on October 26, 2020.

On January 4, 2021, with Husky being a wholly-owned subsidiary of Cenovus, Fitch assigned a “BB+/RR4” rating to Husky’s senior unsecured debt and assigned a positive outlook.

Husky’s preferred shares were exchanged for Cenovus preferred shares pursuant to the Cenovus Transaction and those preferred share ratings have moved to Cenovus. DBRS Morningstar has also discontinued and withdrawn its rating on Husky’s commercial paper at the request of the Company.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 48

Net Debt

The Company had total debt of $6,157 million and cash and cash equivalents of $735 million at December 31, 2020, compared to total debt of $5,520 million and cash and cash equivalents of $1,775 million at December 31, 2019. The Company’s net debt at December 31, 2020 increased by $1,677 million when compared to December 31, 2019:

Net Debt(1) ($ millions)	December 31, 2020			December 31, 2019
Net debt at beginning of period		(3,745	)		(2,881	)
Change in net debt due to:
Funds from operations(1)		494			3,251
Debt issue costs		(7	)		(9	)
Dividends on common shares		(276	)		(503	)
Dividends on preferred shares		(35	)		(35	)
Finance lease payments		(111	)		(233	)
Capital expenditures		(1,587	)		(3,432	)
Capitalized interest		(60	)		(177	)
Proceeds from asset sales		30			277
Investment in joint ventures		(91	)		(40	)
Change in non-cash working capital		(65	)		(104	)
Other		7			1
Effect of exchange rates on cash and cash equivalents		(26	)		(48	)
Effect of exchange rates on long-term debt		50			188
		(1,677	)		(864	)
Net debt at end of period		(5,422	)		(3,745	)

⁽¹⁾ Net debt and funds from operations are non-GAAP measures. Refer to Section 9.3 for reconciliations to the corresponding GAAP measures.

During the year ended December 31, 2020, the Company’s capital expenditures were primarily funded by funds from operations and cash on hand. The Company’s funds from operations are dependent on a number of factors, including commodity prices, production and sales volumes, refining and marketing margins, operating expenses, taxes, royalties and foreign exchange rates. Management prepares capital expenditure budgets annually which are regularly monitored and updated to adapt to changes in market factors. In addition, the Company requires authorizations for capital expenditures on projects, which assists with the management of capital.

6.4    Capital Structure

Capital Structure	December 31, 2020
($ millions)	Outstanding
Total debt(1)		6,157
Shareholders’ equity		7,064

⁽¹⁾ Total debt is a non-GAAP measure. Refer to Section 9.3 for a reconciliation to the corresponding GAAP measure.

The Company’s objectives when managing capital have been to maintain a flexible capital structure in order to optimize the cost of capital at acceptable risk, and maintain investor, creditor and market confidence to sustain the future development of the business. The Company has managed its capital structure and made adjustments as economic conditions and the risk characteristics of its underlying assets change. The Company considers its capital structure to include shareholders’ equity and debt, which was $13.2 billion at December 31, 2020 (December 31, 2019 – $22.8 billion).

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 49

The Company has monitored its financing requirements and capital structure using, among other things, non-GAAP financial metrics consisting of debt to capital employed and debt to funds from operations (refer to Section 9.3). At December 31, 2020, debt to capital employed was 46.6% (December 31, 2019 – 24.2%) and debt to funds from operations was 12.5 times (December 31, 2019 – 1.7 times). The increase in the Company’s debt to funds from operations ratio reflects the impact of the sharp decline in the global economic environment from COVID-19 and falling commodity prices which resulted in significantly lower funds from operations. The Company has taken measures to strengthen its financial position and navigate through this commodity down cycle by, among other things, reducing the 2020 budgeted capital and operating spending, and reducing the quarterly common share dividend. The Company is subject to a leverage covenant in its credit facilities that limits debt to capital (subject to specific definitions in the credit agreements) to less than 65%, temporarily increased to 75% until the intended amalgamation of the Company and Cenovus is completed. The Company is in compliance with this covenant and considers the risk of non-compliance low. The Company also targets a debt to funds from operations ratio of less than 2.0 times over the longer term.

To facilitate the management of these ratios, the Company prepared annual budgets, which are updated depending on varying factors such as general market conditions and successful capital deployment.

6.5     Contractual Obligations, Commitments and Off-Balance Sheet Arrangements

Contractual Obligations and Other Commercial Commitments

In the normal course of business, the Company is obligated to make future payments. The following summarizes known non-cancellable contracts and other commercial commitments:

Contractual Obligations

Payments due by period ($ millions)	2021		2022-2023		2024-2025		Thereafter		Total
Long-term debt and interest on fixed rate debt		236		1,073		2,059		4,150		7,518
Operating agreements(1)		97		215		166		525		1,003
Firm transportation agreements(1)(4)		552		1,192		1,204		4,473		7,421
Unconditional purchase obligations(2)		1,766		1,904		1,423		3,324		8,417
Lease rentals and exploration work agreements		74		154		90		838		1,156
Obligations to fund equity investee(3)		54		153		166		280		653
Lease obligations(5)		195		346		297		2,031		2,869
Asset retirement obligations		94		192		173		9,111		9,570
		3,068		5,229		5,578		24,732		38,607

⁽¹⁾  Included in operating agreements and firm transportation agreements are blending and storage agreements and transportation commitments of $1.2 billion and $1.7 billion respectively with HMLP.

⁽²⁾  Includes processing services, distribution services, insurance premiums, drilling services, natural gas purchases and the purchase of refined petroleum products.

⁽³⁾ Equity investee refers to the Company’s investment in Husky-CNOOC Madura Ltd. joint venture, which is accounted for under the equity method for consolidated financial statement purposes^.

⁽⁴⁾  Includes transportation commitments of $1.7 billion (2019 – $1.6 billion) that are subject to regulatory approval or have been approved, but are not yet in service. Terms are up to 20 years subsequent to the date of commencement.

⁽⁵⁾ Refer to Note 10 in the 2020 consolidated financial statements.

Other Obligations

The Company is involved in various claims and litigation arising in the normal course of business. While the outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company’s favour, the Company does not currently believe that decisions in any pending or threatened proceedings related to these and other matters, or any amount which it may be required to pay, would have a material adverse impact on its financial position, results of operations or liquidity.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 50

The Company has income tax filings that are subject to audit and potential reassessment. The findings may impact the tax liability of the Company. The final results are not reasonably determinable at this time. Management believes that it has adequately provided for current and deferred income taxes.

In accordance with the provisions of the regulations of the People’s Republic of China, the Company is required to deposit funds into separate accounts restricted to the funding of future asset retirement obligations in offshore China. As at December 31, 2020, the Company has deposited funds of $164 million, which has been reclassified as non-current.

The Company is also subject to various contingent obligations that become payable only if certain events or rulings occur. The inherent uncertainty surrounding the timing and financial impact of these events or rulings prevents any meaningful measurement, which is necessary to assess their impact on future liquidity. Such obligations include environmental contingencies, contingent consideration and potential settlements resulting from litigation.

The Company has a number of contingent environmental liabilities, which individually have been estimated to be immaterial. These contingent environmental liabilities are primarily related to the migration of contamination at fuel outlets and certain legacy sites where the Company had previously conducted operations. The contingent environmental liabilities involved have been considered in aggregate and based on reasonable estimates the Company does not believe they will result, in aggregate, in a material adverse effect on its financial position, results of operations or liquidity.

Off-Balance Sheet Arrangements

The Company does not believe it has any guarantees or off-balance sheet arrangements that have, or are reasonably likely to have, a current or future effect on the Company’s financial condition, results of operations, liquidity or capital expenditures.

Standby Letters of Credit

On occasion, the Company issues letters of credit in connection with transactions in which the counterparty requires such security.

6.6     Transactions with Related Parties

The Company performs management services as the operator of the assets held by HMLP for which it recovers shared service costs. The Company is also the contractor for HMLP and constructs its assets on a cost recovery basis with certain restrictions. HMLP charges an access fee to the Company for the use of its pipeline systems in performing the Company’s blending business, and the Company also pays for transportation and storage services. These transactions were related party transactions as of December 31, 2020, as the Company has a 35% ownership interest in HMLP and the remaining ownership interests in HMLP belong to Power Assets Holdings Limited and CK Infrastructure Holdings Limited, which were affiliates of one of the Company’s principal shareholders prior to completion of the Cenovus Transaction. For the year ended December 31, 2020, the Company charged HMLP $250 million related to construction costs and management services. For the year ended December 31, 2020, the Company had purchases from HMLP of $239 million related to the use of the pipeline for the Company’s blending, transportation and storage activities. As at December 31, 2020, the Company had $23 million due from HMLP and $20 million due to HMLP.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 51

6.7     Outstanding Share Data

Authorized:

• unlimited number of common shares

• unlimited number of preferred shares

Issued and outstanding: December 31, 2020

•   common shares	1,005,121,738
•   cumulative redeemable preferred shares, series 1	10,435,932
•   cumulative redeemable preferred shares, series 2	1,564,068
•   cumulative redeemable preferred shares, series 3	10,000,000
•   cumulative redeemable preferred shares, series 5	8,000,000
•   cumulative redeemable preferred shares, series 7	6,000,000
•   stock options	18,883,146
•   stock options exercisable	9,650,528

Husky common shares and preferred shares were delisted at the close of market on January 5, 2021. Husky stock options were converted to Cenovus stock options on January 5, 2021.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 52

7.0     Critical Accounting Estimates and Key Judgments

The Company’s consolidated financial statements have been prepared in accordance with IFRS as issued by the International Accounting Standards Board (“IASB”). Significant accounting policies are disclosed in Note 3 to the 2020 consolidated financial statements. Some of the Company’s accounting policies require subjective judgment and estimation about uncertain circumstances.

7.1      Accounting Estimates

Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and on a prospective basis. By their nature, estimates are subject to measurement uncertainty and changes in such estimates in future years could require a material change in the consolidated financial statements. These underlying assumptions are based on historical experience and other factors that management believes to be reasonable under the circumstances, and are subject to change as new events occur, as more industry experience is acquired, as additional information is obtained, and as the Company’s operating environment changes. Specifically, amounts recorded for depletion, depreciation, amortization and impairment, recoveries from insurance claims, asset retirement obligations, assets and liabilities measured at fair value, employee future benefits, income taxes and reserves and contingencies are based on estimates.

In early March 2020, the World Health Organization declared the COVID-19 coronavirus outbreak to be a pandemic. Responses to the spread of COVID-19 have resulted in significant disruption to business operations and a significant increase in economic uncertainty, with more volatile commodity prices and currency exchange rates, and a marked decline in long-term interest rates. Although economies are beginning to re-open, these events are resulting in a challenging economic climate in which it is difficult to reliably estimate the length or severity of these developments and their financial impact. The results of the potential economic downturn and any potential resulting direct and indirect impact to the Company has been considered in management’s estimates described above at the period end; however there could be a further prospective material impact in future periods.

Depletion, Depreciation, Amortization and Impairment

Eligible costs associated with oil and gas activities are capitalized on a unit of measure basis. Depletion expense is subject to estimates including petroleum and natural gas reserves, future petroleum and natural gas prices, estimated future remediation costs, future interest rates as well as other fair value assumptions. The aggregate of capitalized costs, net of accumulated DD&A, less estimated salvage values, is charged to DD&A over the life of the proved developed reserves using the unit of production method, except in the case of assets whose useful life is shorter or longer than the lifetime of the proved developed reserves of that field, in which case the straight-line method or a unit-of-production method based on total proved plus probable reserves is applied.

Impairment and Reversals of Impairment of Non-Financial Assets

The carrying amounts of the Company’s non-financial assets are reviewed at the end of each reporting period to determine whether there is any indication of impairment or reversal of impairment. Determining whether there are any indications of impairment, or reversal of impairment, requires significant judgment of external factors, such as an extended change in prices or margins for oil and gas commodities or products, a significant change in an asset’s market value, a significant change and revision of estimated volumes, revision of future development costs, a change in the entity’s market capitalization or significant changes in the technological, market, economic or legal environment that would have an adverse impact on the entity. If impairment, or reversal of impairments, is indicated the amount by which the carrying value is different from the estimated recoverable amount of the long-lived asset is charged to net earnings.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 53

The determination of the recoverable amount for impairment, or reversal of impairment, involves the use of numerous assumptions and estimates. Estimates of future cash flows used in the evaluation of assets are made using management’s forecasts of commodity prices, operating costs and future capital expenditures, marketing supply and demand, forecasted crack spreads, growth rate, discount rate and, in the case of oil and gas properties, expected production volumes. Expected production volumes take into account assessments of field reservoir performance and include expectations about proved and probable volumes and where applicable economically recoverable resources associated with interests in certain Husky properties which are risk-weighted utilizing geological, production, recovery, market price and economic projections. Either the cash flow estimates or the discount rate is risk-adjusted to reflect local conditions as appropriate. Future revisions to these assumptions impact the recoverable amount.

Impairment losses recognized for assets in prior years are assessed at the end of each reporting period for indications that the impairment has decreased or no longer exists. An impairment loss is reversed only to the extent that the carrying amount of the asset or cash generating units (”CGUs”) does not exceed the carrying amount that would have been determined, net of depletion, depreciation and amortization, if no impairment loss had been recognized.

Asset Retirement Obligations

Estimating asset retirement obligations requires that the Company estimates costs that are many years in the future. Restoration technologies and costs are constantly changing, as are regulatory, political, environment, safety and public relations considerations. Inherent in the calculation of asset retirement obligations are numerous assumptions and estimates, including the ultimate settlement amounts, future third-party pricing, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. Future revisions to these assumptions may result in changes to the asset retirement obligations.

Fair Value of Financial Instruments

The Company’s financial instruments include cash and cash equivalents, accounts receivable, restricted cash, accounts payable and accrued liabilities, short-term debt, long-term debt, derivatives, portions of other assets, lease liabilities and other long-term liabilities. Derivative instruments are measured at fair value through profit or loss. The Company’s remaining financial instruments are measured at amortized cost. For financial instruments measured at amortized cost, the carrying values approximate their fair value with the exception of long-term debt.

The Company’s financial assets and liabilities that are recorded at fair value on a recurring basis have been categorized into one of three categories based upon the fair value hierarchy. Level 1 fair value measurements are determined by reference to quoted prices in active markets for identical assets and liabilities. Fair value measurements of assets and liabilities in Level 2 include valuations using inputs other than quoted prices but for which all significant outputs are observable, either directly or indirectly. Level 3 fair value measurements are based on inputs that are unobservable and significant to the overall fair value measurement.

The fair values of derivatives are determined using valuation models which require assumptions concerning the amount and timing of future cash flows and discount rates. These estimates are also subject to change with fluctuations in commodity prices, interest rates, foreign currency exchange rates and estimates of non-performance. The actual settlement of a derivative instrument could differ materially from the fair value recorded and could impact future results.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 54

Employee Future Benefits

The determination of the cost of the defined benefit pension plan and the other post-retirement benefit plans reflects a number of estimates that affect expected future benefit payments. These estimates include, but are not limited to, attrition, mortality, the rate of return on pension plan assets, salary escalations for the defined benefit pension plan and expected health care cost trends for the post-retirement health and dental care plan. The fair value of the plan assets is used for the purposes of calculating the expected return on plan assets.

Income Taxes

The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. Estimates that require significant judgments are also made with respect to the timing of temporary difference reversals, the realizability of tax assets and in circumstances where the transaction and calculations for which the ultimate tax determination are uncertain. All tax filings are subject to audit and potential reassessment, often after the passage of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management.

Legal, Environmental Remediation and Other Contingent Matters

The Company is required to determine both whether a loss is probable based on judgment and interpretation of laws and regulations and whether the loss can be reasonably estimated. When a loss is determined it is charged to net earnings. The Company must continually monitor known and potential contingent matters and make appropriate provisions by charges to net earnings when warranted by circumstances.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 55

7.2    Key Judgments

Management makes judgments regarding the application of IFRS for each accounting policy. Critical judgments that have the most significant effect on the amounts recognized in the consolidated financial statements include determination of technical feasibility and commercial viability, impairment assessments, the determination of CGUs, changes in reserve estimates, the determination of a joint arrangement, the designation of the Company’s functional currency and the fair value of related party transactions.

Exploration and Evaluation Costs

Costs directly associated with an exploration well are initially capitalized as exploration and evaluation assets. Expenditures related to wells that do not find reserves or where no future activity is planned are expensed as exploration and evaluation expenses. Exploration and evaluation costs are excluded from costs subject to depletion until technical feasibility and commercial viability is assessed or production commences. At that time, costs are either transferred to property, plant and equipment or their value is impaired. Impairment is charged directly to net earnings. Drilling results, required operating costs and capital expenditure and estimated reserves are important judgments when making this determination and may change as new information becomes available.

Impairment of Financial Assets

A financial asset is assessed at the end of each reporting period to determine whether it is impaired based on objective evidence indicating that one or more events have had a negative effect on the estimated future cash flows of that asset. Objective evidence used by the Company to assess impairment of financial assets includes quoted market prices for similar financial assets and historical collection rates. Given that the calculations for the net present value of estimated future cash flows related to derivative financial assets require the use of estimates and assumptions, including forecasts of commodity prices, marketing supply and demand, product margins and expected production volumes, it is possible that the assumptions may change, which may require a material adjustment to the carrying value of financial assets.

Cash Generating Units

The Company’s assets are grouped into respective CGUs, which is the smallest identifiable group of assets, liabilities and associated goodwill that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. The determination of the Company’s CGUs is subject to management’s judgment.

Reserves

Oil and gas reserves are evaluated internally and audited by independent qualified reserve engineers. The estimation of reserves is an inherently complex process and involves the exercise of professional judgment. Estimates are based on projected future rates of production, estimated commodity prices, engineering data and the timing of future expenditures, all of which are subject to uncertainty. Changes in reserve estimates can have an impact on reported net earnings through revisions to depletion, depreciation and amortization expense, in addition to determining possible impairments and reversal of impairments of property, plant and equipment.

Net reserves represent the Company’s lessor royalty, overriding royalty and working interest share of the gross remaining reserves, after deduction of any crown, freehold and overriding royalty interests. Assumptions reflect market and regulatory conditions, as applicable, as at the balance sheet date and could differ significantly from other points in time throughout the year or future periods. Changes in market and regulatory conditions and assumptions can materially impact the estimation of net reserves.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 56

Joint Arrangements

Joint arrangements represent activities where the Company has joint control established by a contractual agreement. Joint control requires unanimous consent for financial and operational decisions. A joint arrangement is either a joint operation, whereby the parties have rights to the assets and obligations for the liabilities, or a joint venture, whereby the parties have rights to the net assets.

Classification of a joint arrangement as either joint operation or joint venture requires judgment. Management’s considerations include, but are not limited to, determining if the arrangement is structured through a separate vehicle and whether the legal form and contractual arrangements give the entity direct rights to the assets and obligations for the liabilities within the normal course of business. Other facts and circumstances are also assessed by management, including the entity’s rights to the economic benefits of assets and its involvement and responsibility for settling liabilities associated with the arrangement.

Functional and Presentation Currency

Functional currency is the currency of the primary economic environment in which the Company and its subsidiaries operate and is normally the currency in which the entity primarily generates and expends cash. The designation of the Company’s functional currency is a management judgment based on the composition of revenues and costs in the locations in which it operates.

Related Party Judgments and Estimates

The Company entered into transactions and agreements in the normal course of business with certain related parties, joint arrangements and associates. Proceeds for disposition of assets to related parties are recognized at fair value, based on discounted cash flow forecast from those assets. Independent opinions of the fair value may be obtained. Changes in the assumptions used to determine these fair values may result in a material difference in the proceeds and any gain or loss on disposition.

8.0     Recent Accounting Standards and Changes in Accounting Policies

Recent Accounting Standards

The Company has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective.

Change in Accounting Policy

The Company has not adopted any changes to material accounting policies during the fiscal year ended December 31, 2020.

9.0    Reader Advisories

9.1     Forward-Looking Statements

Certain statements in this document are forward-looking statements and information (collectively “forward-looking statements”), within the meaning of the applicable Canadian securities legislation, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. The forward-looking statements contained in this document are forward-looking and not historical facts.

Some of the forward-looking statements may be identified by statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as “will likely result”, “are expected to”, “will continue”, “is anticipated”, “is targeting”, “is estimated”,

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 57

“intend”, “plan”, “projection”, “could”, “aim”, “vision”, “goals”, “objective”, “target”, “schedules” and “outlook”). In particular, forward-looking statements in this document include, but are not limited to, references to:

• with respect to the business, operations and results of the Company generally, and the company’s target debt to funds from operations ratio;

• with respect to Oil Sands, the expected timing of a planned turnaround at Plant 1B at the Sunrise Energy Project;

• with respect to U.S. Refining: anticipated insurance recoveries for property damage associated with the Superior Refinery rebuild; and expectations regarding the operating capacity and capabilities of the rebuilt Superior Refinery;

• with respect to the Company’s Offshore business in Asia Pacific: the expected impact of the gas sales agreement amendment on cash flow from Liwan 3-1; the expected timing of additional drilling and testing at Block 15/33; the expected timing of commencement of production and gas sales at MDA and MBH; development of the MDK field; and the expected timing of a final investment decision at the MAC field; and

• with respect to the Company’s Offshore business in the Atlantic, expectations regarding the suspension of activities at the West White Rose Project.

In addition, statements relating to “reserves“ are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary from reserves and production estimates.

Although the Company believes that the expectations reflected by the forward-looking statements presented in this document are reasonable, the Company’s forward-looking statements have been based on assumptions and factors concerning future events, including the timing of regulatory approvals, that may prove to be inaccurate. Those assumptions and factors are based on information currently available to the Company about itself and the businesses in which it operates. Information used in developing forward-looking statements has been acquired from various sources, including third party consultants, suppliers and regulators, among others.

Because actual results or outcomes could differ materially from those expressed in any forward-looking statements, investors should not place undue reliance on any such forward-looking statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the predicted outcomes will not occur. Some of these risks, uncertainties and other factors are similar to those faced by other oil and gas companies and some are unique to the Company.

The Company’s Annual Information Form for the year ended December 31, 2020, this MD&A and other documents filed with securities regulatory authorities (accessible through the SEDAR website www.sedar.com and the EDGAR website www.sec.gov) describe risks, material assumptions and other factors that could influence actual results and are incorporated herein by reference.

New factors emerge from time to time and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company’s course of action would depend upon management’s assessment of the future considering all

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 58

information available to it at the relevant time. Any forward-looking statement speaks only as of the date on which such statement is made and, except as required by applicable securities laws, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.

9.2 Oil and Gas Reserves Reporting

Disclosure of Oil and Gas Reserves and Other Oil and Gas Information

Unless otherwise indicated: (i) reserves estimates have been prepared by internal qualified reserves evaluators in accordance with the Canadian Oil and Gas Evaluation Handbook, has been audited and reviewed by Sproule, an independent qualified reserves auditor, have an effective date of December 31, 2020 and represent the Company’s working interest share (ii) projected and historical production volumes quoted are gross, which represents the total or the Company’s working interest, as applicable share before deduction of royalties (iii) all Husky working interest production volumes quoted are before deduction of royalties; and (iv) historical production volumes provided are for the year ended December 31, 2020.

The Company uses the term “barrels of oil equivalent” (or “boe”), which is consistent with other oil and gas companies’ disclosures, and is calculated on an energy equivalence basis applicable at the burner tip whereby one barrel of crude oil is equivalent to six thousand cubic feet of conventional natural gas. The term boe is used to express the sum of the total company products in one unit that can be used for comparisons. Readers are cautioned that the term boe may be misleading, particularly if used in isolation. This measure is used for consistency with other oil and gas companies and does not represent value equivalency at the wellhead.

The Company uses the term reserves replacement ratio, which is consistent with other oil and gas companies’ disclosures. Reserves replacement ratios for a given period are determined by taking the Company’s proved reserve changes for that period divided by the Company’s upstream gross production for the same period. Reserves changes include: revisions, purchases, sales, improved recovery, discoveries and extensions. The reserves replacement ratio measures the amount of reserves changes to a company’s reserves base during a given period relative to the amount of oil and gas produced during that same period. A company’s reserves replacement ratio must be at least 100% for the company to maintain its reserves. Reserves replacement ratios that exclude economic factors will exclude the impacts that changing oil and gas prices, inflation, and exchange rates and the regulatory curtailment imposed by the Alberta government have.

Note to U.S. Readers

The Company reports its reserves information in accordance with Canadian practices and specifically in accordance with NI 51-101. Because the Company is permitted to prepare its reserves and resources information in accordance with Canadian disclosure requirements, it may use certain terms in that disclosure that U.S. oil and gas companies generally do not include or may be prohibited from including in their filings with the SEC.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 59

9.3 Non-GAAP Measures

Disclosure of non-GAAP Measures

The Company uses measures primarily based on IFRS and also uses some secondary non-GAAP measures. The non-GAAP measures included in this MD&A and related disclosures are: debt to capital, debt to capital employed, debt to funds from operations, funds from operations, free cash flow, operating margin, net debt, total debt, refining and marketing margin and sustaining capital. None of these measures are used to enhance the Company’s reported financial performance or position. There are no comparable measures in accordance with IFRS for debt to capital employed or debt to funds from operations. These are useful complementary measures that are used by management in assessing the Company’s financial performance, efficiency and liquidity, and they may be used by the Company’s investors for the same purpose. The non-GAAP measures do not have standardized meanings prescribed by IFRS and therefore are unlikely to be comparable to similar measures presented by other issuers. They are common in the reports of other companies but may differ by definition and application. All non-GAAP measures are defined below.

Debt to Capital

Debt to capital is a non-GAAP measure and is equal to total debt and certain adjusting items specified in the Company’s credit agreement divided by total debt and shareholder’s equity. Management believes this measure assists management and investors in evaluating the Company’s financial strength.

Debt to Capital Employed

Debt to capital employed percentage is a non-GAAP measure and is equal to total debt divided by capital employed. Capital employed is equal to total debt and shareholders’ equity. Management believes this measurement assists management and investors in evaluating the Company’s financial strength.

Debt to Funds from Operations

Debt to funds from operations is a non-GAAP measure and is equal to total debt divided by funds from operations. Funds from operations is equal to cash flow - operating activities excluding change in non-cash working capital. Management believes this measurement assists management and investors in evaluating the Company’s financial strength.

The following table shows the reconciliation of debt to funds from operations for the periods ended December 31, 2020, 2019 and 2018:

Debt to Funds from Operations ($ millions)	December 31, 2020		December 31, 2019		December 31, 2018
Total debt		6,157		5,520		5,747
Funds from operations		494		3,251		4,004
Debt to funds from operations		12.5		1.7		1.4

Funds from Operations and Free Cash Flow

Funds from operations is a non-GAAP measure which should not be considered an alternative to, or more meaningful than, ”cash flow – operating activities” as determined in accordance with IFRS, as an indicator of financial performance. Funds from operations equals cash flow – operating activities excluding change in non-cash working capital. Management believes that impacts of non-cash working capital items on cash flow – operating activities may reduce comparability between periods, accordingly, funds from operations is presented in the Company’s financial reports to assist management and investors in analyzing operating performance of the Company in the stated period compared to prior periods.

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Free cash flow is a non-GAAP measure, which should not be considered an alternative to, or more meaningful than, “cash flow – operating activities” as determined in accordance with IFRS, as an indicator of financial performance. Free cash flow is presented to assist management and investors in analyzing operating performance by the business in the stated period. Free cash flow equals funds from operations less capital expenditures.

The following tables show the reconciliation of net earnings (loss) to funds from operations and free cash flow, and related per share amounts for the periods ended:

Reconciliation of Cash Flow	Year ended
($ millions)	Dec. 31 2020			Dec. 31 2019			Dec. 31 2018
Net earnings (loss)		(10,016	)		(1,370	)		1,457
Items not affecting cash:
Accretion		104			106			97
Depletion, depreciation, amortization and impairment		12,920			5,496			2,591
Inventory write-down to net realizable value		7			15			60
Exploration and evaluation expenses		594			355			29
Deferred income taxes (recoveries)		(3,190	)		(974	)		396
Foreign exchange gain		(3	)		(26	)		(6	)
Stock-based compensation		16			(2	)		44
Gain on sale of assets		(25	)		(8	)		(4	)
Unrealized market to market loss (gain)		10			44			(150	)
Share of equity investment loss (gain)		(7	)		(59	)		(69	)
Gain on insurance recoveries for damage to property		(19	)		(207	)		(253	)
Other		67			12			21
Settlement of asset retirement obligations		(39	)		(276	)		(181	)
Deferred revenue		(115	)		(42	)		(100	)
Distribution from joint ventures		190			187			72
Change in non-cash working capital		347			(280	)		130
Cash flow – operating activities		841			2,971			4,134
Change in non-cash working capital		(347	)		280			(130	)
Funds from operations		494			3,251			4,004
Capital expenditures		(1,587	)		(3,432	)		(3,578	)
Free cash flow		(1,093	)		(181	)		426
Funds from operations – basic		0.49			3.23			3.98
Funds from operations – diluted		0.49			3.23			3.98

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 61

Reconciliation of Cash Flow	Three months ended
($ millions)	Dec. 31 2020			Sept. 30 2020			Jun. 30 2020			Mar. 31 2020			Dec. 31 2019			Sept. 30 2019			Jun.30 2019			Mar. 31 2019
Net earnings (loss)		(926	)		(7,081	)		(304	)		(1,705	)		(2,341	)		273			370			328
Items not affecting cash:
Accretion		26			27			25			26			27			26			26			27
Depletion, depreciation, amortization and impairment		1,620			8,636			590			2,074			3,520			703			643			630
Inventory write-down to net realizable value		(38	)		45			(362	)		362			15			—			—			—
Exploration and evaluation expenses		(2	)		598			(2	)		—			332			—			23			—
Deferred income taxes		(439	)		(2,030	)		(137	)		(584	)		(789	)		22			(250	)		43
Foreign exchange loss (gain)		(7	)		2			(1	)		3			(11	)		(1	)		(2	)		(12	)
Stock-based compensation (recovery)		29			(3	)		8			(18	)		(13	)		(9	)		13			7
Gain on sale of assets		(8	)		(9	)		(2	)		(6	)		(3	)		(3	)		—			(2	)
Unrealized mark to market loss (gain)		24			(19	)		96			(91	)		(13	)		4			(4	)		57
Share of equity investment loss (gain)		(8	)		1			10			(10	)		5			(19	)		(23	)		(22	)
Gain on insurance recoveries for damage to property		(19	)		—			—			—			(194	)		(13	)		—			—
Other		60			1			7			(1	)		11			5			5			(9	)
Settlement of asset retirement obligations		(9	)		(3	)		(3	)		(24	)		(90	)		(73	)		(41	)		(72	)
Deferred revenue		(23	)		(34	)		(41	)		(17	)		(14	)		(7	)		(5	)		(16	)
Distribution from joint ventures		23			17			134			16			27			113			47			—
Change in non-cash working capital		114			(69	)		(28	)		330			397			(221	)		(42	)		(414	)
Cash flow - operating activities		417			79			(10	)		355			866			800			760			545
Change in non-cash working capital		(114	)		69			28			(330	)		(397	)		221			42			414
Funds from operations		303			148			18			25			469			1,021			802			959
Capital expenditures		(311	)		(354	)		(310	)		(612	)		(894	)		(868	)		(858	)		(812	)
Free cash flow		(8	)		(206	)		(292	)		(587	)		(425	)		153			(56	)		147
Funds from operations – basic		0.30			0.15			0.02			0.02			0.47			1.02			0.80			0.95
Funds from operations – diluted		0.30			0.15			0.02			0.02			0.47			1.02			0.80			0.95

Operating Margin

Operating margin is a non-GAAP measure which should not be considered an alternative to, or more meaningful than, “revenue, net of royalties” as determined in accordance with IFRS, as an indicator of financial performance. Operating margin is presented to assist management and investors in analyzing operating performance of the Company in the stated period. Operating margin equals revenues net of royalties less purchases of crude oil and products, production, operating and transportation expenses, and selling, general and administrative expenses.

The following table shows the reconciliation of operating margins for the Integrated Corridor and Offshore business segments for the three months and years ended December 31:

Operating margin	Three months ended December 31									Year ended December 31
	Integrated Corridor				Offshore					Integrated Corridor					Offshore
($ millions)	2020		2019		2020		2019			2020			2019		2020		2019
Revenues, net of royalties		3,119		4,400		410		433			11,873			18,458		1,428		1,444
Expenses
Purchases of crude oil and products		2,285		3,288		37		(18	)		9,249			12,842		32		(16	)
Production, operating and transportation expenses		577		709		66		89			2,285			2,690		275		340
Selling, general and administrative expenses		100		85		18		11			408			348		75		55
Operating margin		157		318		289		351			(69	)		2,578		1,046		1,065

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 62

Net Debt

Net debt is a non-GAAP measure that equals total debt less cash and cash equivalents. Management believes this measurement assists management and investors in evaluating the Company’s financial strength.

The following table shows the reconciliation of total debt to net debt as at December 31, 2020, 2019 and 2018:

Net Debt ($ millions)	December 31, 2020			December 31, 2019			December 31, 2018
Total debt		6,157			5,520			5,747
Cash and cash equivalents		(735	)		(1,775	)		(2,866	)
Net debt		5,422			3,745			2,881

Total debt

Total debt is a non-GAAP measure that equals the sum of long-term debt, long-term debt due within one year and short-term debt. Management believes this measurement assists management and investors in evaluating the Company’s financial strength.

The following table shows the reconciliation of total debt as at December 31, 2020, 2019 and 2018:

Total Debt ($ millions)	December 31, 2020		December 31, 2019		December 31, 2018
Short-term debt		40		550		200
Long-term debt due within one year		—		400		1,433
Long-term debt		6,117		4,570		4,114
Total debt		6,157		5,520		5,747

Refining and Marketing Margin

Refining and marketing margin is a non-GAAP measure which should not be considered an alternative to, or more meaningful than, “gross revenue” as determined in accordance with IFRS, as an indicator of financial performance. Refining and marketing margin is presented to assist management and investors in analyzing operating performance of the Company in the stated period. Refining and marketing margin equals gross revenue and marketing and other less purchases of crude oil and products.

Sustaining Capital

Sustaining capital is the additional development capital that is required by the business to maintain production and operations at existing levels. Development capital includes the cost to drill, complete, equip and tie-in wells to existing infrastructure. Sustaining capital does not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other issuers.

9.4 Additional Reader Advisories

Intention of Management’s Discussion and Analysis

This Management’s Discussion and Analysis is intended to provide an explanation of financial and operational performance compared with prior periods and the Company’s prospects and plans. It provides additional information that is not contained in the Company’s consolidated financial statements.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 63

Review by the Audit Committee

This Management’s Discussion and Analysis was reviewed by the Company’s Audit Committee and approved by the Board of Directors on February 8, 2021. Any events subsequent to that date could materially alter the veracity and usefulness of the information contained in this document.

Additional Husky Documents Filed with Securities Commissions

This Management’s Discussion and Analysis dated Feb. 8, 2021, should be read in conjunction with the 2020 consolidated financial statements and related notes. Readers are also encouraged to refer to the Company’s interim reports filed for 2020, which contain Management’s Discussion and Analysis and consolidated financial statements, and the Company’s Annual Information Form for the year ended December 31, 2020, filed separately with Canadian securities regulatory authorities, and annual Form 40-F filed with the SEC, the U.S. federal securities regulatory agency. These documents are available at www.sedar.com, at www.sec.gov and www.huskyenergy.com.

Use of Pronouns and Other Terms

“Husky” and “the Company” refer to Husky Energy Inc. on a consolidated basis.

Standard Comparisons in this Document

Unless otherwise indicated, comparisons of results are for the years ended December 31, 2020 and 2019 and the Company’s financial position at December 31, 2020 and 2019.

Reclassifications and Materiality for Disclosures

Certain prior year amounts have been reclassified to conform to current year presentation. Materiality for disclosures is determined on the basis of whether the information omitted or misstated would cause a reasonable investor to change his or her decision to buy, sell or hold Husky’s securities.

Additional Reader Guidance

Unless otherwise indicated:

• Financial information is presented in accordance with IFRS as issued by the IASB.

• All dollar amounts are in Canadian dollars, unless otherwise indicated.

• Unless otherwise indicated, all production volumes quoted are gross, which represents the Company’s working interest share before royalties.

• Prices are presented before the effect of hedging.

• This MD&A is for the year ended December 31, 2020, and is in respect of Husky and its consolidated entities and considers the completion of the Cenovus Transaction.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 64

Terms
Asia Pacific	Includes oil and gas exploration and production activities located offshore China and Indonesia
Asphalt Refinery	The asphalt refinery owned by the Company and located in Lloydminster, Alberta
Atlantic	Includes upstream oil and gas exploration and production activities located offshore Newfoundland and Labrador
Bitumen	Bitumen is a naturally occurring solid or semi-solid hydrocarbon consisting mainly of heavier hydrocarbons, with a viscosity greater than 10,000 millipascal-seconds or 10,000 centipoise measured at the hydrocarbon’s original temperature in the reservoir and at atmospheric pressure on a gas-free basis, and that is not primarily recoverable at economic rates through a well without the implementation of enhanced recovery methods
Capital employed	Long-term debt, long-term debt due within one year, short-term debt and shareholders’ equity
Capital expenditures	Includes capitalized administrative expenses but does not include asset retirement obligations or capitalized interest
Capital program	Capital expenditures not including capitalized administrative expenses or capitalized interest
Debt to capital	Total debt and certain adjusting items specified in the Company’s credit agreement divided by total debt and shareholder’s equity
Debt to capital employed	Long-term debt, long-term debt due within one year and short-term debt divided by capital employed
Debt to funds from operations	Long-term debt, long-term debt due within one year and short-term debt divided by funds from operations
Diluent	A lighter gravity liquid hydrocarbon, usually condensate or synthetic oil, added to heavy oil and bitumen to facilitate transmissibility of the oil through a pipeline
Feedstock	Raw materials which are processed into petroleum products
Free cash flow	Funds from operations less capital expenditures
Funds from operations	Cash flow - operating activities excluding change in non-cash working capital
Gross/net wells	Gross refers to the total number of wells in which a working interest is owned. Net refers to the sum of the fractional working interests owned by a company
Gross reserves/production	A company’s working interest share of reserves/production before deduction of royalties
Heavy crude oil	Crude oil with a relative density greater than 10 degrees API gravity and less than or equal to 22.3 degrees API gravity
Light crude oil	Crude oil with a relative density greater than 31.1 degrees API gravity
Medium crude oil	Crude oil with a relative density that is greater than 22.3 degrees API gravity and less than or equal to 31.1 degrees API gravity
Net debt	Total debt less cash and cash equivalents
Net revenue	Gross revenues less royalties
NOVA Inventory Transfer (“NIT”)	Exchange or transfer of title of gas that has been received into the NOVA pipeline system but not yet delivered to a connecting pipeline
Oil sands	Sands and other rock materials that contain crude bitumen and include all other mineral substances in association therewith
OPEC	Organization of the Petroleum Exporting Countries
Operating margin	Revenues net of royalties less purchases of crude oil and products, production, operating and transportation expenses, and selling, general and administrative expenses.
Probable reserves	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

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 65

Proved developed reserves	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 into producing and non-producing
Proved reserves	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
RIN	Renewable Identification Numbers
Shareholders’ equity	Common shares, preferred shares, contributed surplus, retained earnings, accumulated other comprehensive income and non-controlling interest
Stratigraphic test well	A geologically directed test well to obtain information. These wells are usually drilled without the intention of being completed for production
Synthetic crude oil	A mixture of hydrocarbons derived by upgrading heavy crude oils, including bitumen, through a process that reduces the carbon content and increases the hydrogen content
Thermal	Use of steam injection into the reservoir in order to enable heavy crude oil and bitumen to flow to the well bore
Total debt	Long-term debt including long-term debt due within one year and short-term debt
Turnaround	Performance of scheduled plant or facility maintenance requiring the complete or partial shutdown of the plant or facility operations
Upgrader	The heavy crude oil upgrading facility owned and operated by the Company and located in Lloydminster, Saskatchewan

Units of Measure

bbls	barrels	mboe	thousand barrels of oil equivalent
bbls/day	barrels per day	mboe/day	thousand barrels of oil equivalent per day
bcf	billion cubic feet	mcf	thousand cubic feet
boe	barrels of oil equivalent	mcfge	million cubic feet of gas equivalent
boe/day	barrels of oil equivalent per day	mmbbls	million barrels
CO2e	carbon dioxide equivalent	mmboe	million barrels of oil equivalent
GJ	gigajoule	mmbtu	million British Thermal Units
mbbls	thousand barrels	mmcf	million cubic feet
mbbls/day	thousand barrels per day	mmcf/day	million cubic feet per day

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 66

9.5 Disclosure Controls and Procedures

Disclosure Controls and Procedures

Husky’s management, under supervision of the Acting Chief Executive Officer & Chief Financial Officer, have evaluated the effectiveness of Husky’s disclosure controls and procedures (as defined in the rules of the SEC and the Canadian Securities Administrators (“CSA”) as at December 31, 2020, and have concluded that such disclosure controls and procedures are effective.

Management’s Annual Report on Internal Control over Financial Reporting

The following report is provided by management in respect of Husky’s internal controls over financial reporting (as defined in the rules of the SEC and the CSA):

1) Husky’s management, under the supervision of the Acting Chief Executive Officer & Chief Financial Officer, is responsible for designing, establishing and maintaining adequate internal control over financial reporting for Husky. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

2) Husky’s management has used the Committee of Sponsoring Organizations of the Treadway Commission (2013) framework to evaluate the effectiveness of Husky’s internal control over financial reporting.

3) As at December 31, 2020, management, under the supervision of the Acting Chief Executive Officer & Chief Financial Officer, evaluated the effectiveness of Husky’s internal control over financial reporting and concluded that such internal control over financial reporting is effective.

4) KPMG LLP, who has audited the consolidated financial statements of Husky for the year ended December 31, 2020, has also issued a report on internal controls over financial reporting under Auditing Standard No. 5 of the Public Company Accounting Oversight Board (United States) that attests to the effectiveness Husky’s internal controls over financial reporting.

Changes in Internal Control over Financial Reporting

There have been no changes in Husky’s internal control over financial reporting during the year ended December 31, 2020, that have materially affected or are reasonably likely to materially affect its internal control over financial reporting.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 67

10.0     Selected Quarterly Financial and Operating Information

10.1     Summary of Quarterly Results

	Three months ended
Fourth Quarter Results Summary ($ millions, except where indicated)	Dec. 31 2020			Dec. 31 2019
Gross revenues and marketing and other(1)
Integrated Corridor
Lloydminster Heavy Oil Value Chain		1,065			1,360
Oil Sands		110			134
Western Canada Production		108			166
U.S. Refining		1,690			2,321
Canadian Refined Products		381			658
Eliminations		(200	)		(185	)
Offshore		438			467
Total gross revenues and marketing and other		3,592			4,921
Net earnings (loss)
Integrated Corridor
Lloydminster Heavy Oil Value Chain		171			43
Oil Sands		(498	)		(619	)
Western Canada Production		(118	)		(630	)
U.S. Refining		(69	)		(189	)
Canadian Refined Products		(7	)		(1	)
Offshore		(273	)		(778	)
Corporate		(132	)		(167	)
Net loss		(926	)		(2,341	)
Per share – Basic		(0.93	)		(2.34	)
Per share – Diluted		(0.92	)		(2.34	)
Cash flow – operating activities		417			866
Funds from operations(2)		303			469
Per share – Basic		0.30			0.47
Per share – Diluted		0.30			0.47
Daily sales volume
Integrated Corridor
Lloydminster Heavy Oil Value Chain (mboe/day)		175.9			170.6
Synthetic crude oil and refined products (mboe/day)		69.9			80.1
Blended crude oil (mboe/day)(3)		106.0			90.5
Oil Sands
Diluted bitumen (mbbls/day)		30.1			33.4
Western Canada Production (mboe/day)		51.7			66.9
Light crude oil (mbbls/day)		4.6			7.3
NGL (mbbls/day)		9.4			12.6
Conventional natural gas (mmcf/day)		226.6			281.7
Offshore
Asia Pacific (mboe/day)(4)(5)		55.9			45.3
NGL (mbbls/day)(4)(5)		12.3			10.4
Conventional natural gas (mmcf/day)(4)(5)		261.5			209.7
Atlantic
Light crude oil (mbbls/day)		22.5			22.2

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 68

Fourth Quarter Results Summary (continued) ($ millions, except where indicated)	Dec. 31 2020		Dec. 31 2019
Realized price per unit sold
Integrated Corridor
Lloydminster Heavy Oil Value Chain ($/boe)		53.14		69.83
Synthetic crude oil and refined products ($/boe)		57.08		78.75
Blended crude oil ($/boe)(3)		50.55		61.94
Oil Sands
Diluted bitumen ($/bbl)		40.55		45.51
Western Canada Production ($/boe)		18.00		22.58
Light crude oil ($/bbl)		39.13		62.74
Conventional natural gas & NGL ($/mcf)		2.65		2.94
Offshore
Asia Pacific ($/boe)		68.52		80.15
NGL ($/bbl)		52.55		72.36
Conventional natural gas ($/mcf)		12.17		13.74
Atlantic
Light crude oil ($/bbl)		60.13		83.88
Refinery throughput
Upgrader (mbbls/day)(6)		60.8		79.6
Lloydminster Refinery (mbbls/day)(7)		28.1		28.2
Prince George Refinery (mbbls/day)(8)		—		3.9
Lima Refinery (mbbls/day)(7)		137.4		21.4
BP-Husky Toledo Refinery (mbbls/day)(7)(9)		66.1		70.3
Superior Refinery (mbbls/day)(7)		—		—
Total throughput (mbbls/day)		292.4		203.4
Operating margin(2)
Lloydminster Heavy Oil Value Chain ($/bbl)(10)		15.69		29.37
Oil Sands ($/bbl)		14.71		10.63
Western Canada Production ($/boe)		4.09		7.30
Offshore
Asia Pacific ($/boe)		54.63		68.11
Atlantic ($/bbl)		15.66		50.89
Retail fuel sales (million of litres/day)		6.8		7.4
U.S. Refining refining and marketing margin (US$/bbl crude throughput)(2)		4.59		8.34
U.S./Canadian dollar exchange rate (US$)		0.768		0.758

⁽¹⁾ Gross revenue and marketing and other results reported for 2019 have been recast to reflect a change in the classification of intersegment sales eliminations and a change in presentation of the Integrated Corridor and Offshore business units.

⁽²⁾ Funds from operations, operating margin and refining and marketing margin are non-GAAP measures. Refer to Section 9.3 for a reconciliation to the corresponding GAAP measure.

⁽³⁾ Blended crude oil and bitumen.

⁽⁴⁾ Reported sales volumes include Husky’s working interest production from the Liwan Gas Project.

⁽⁵⁾ Reported sales volumes include Husky’s working interest production from the BD Project (40%). Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for consolidated financial statement purposes.

⁽⁶⁾ Upgrading throughput includes diluent returned to the field.

⁽⁷⁾ Includes all crude oil, feedstock, intermediate feedstock and blend-stocks used in producing sales volumes from the refinery.

⁽⁸⁾ Prince George Refinery was sold on November 1, 2019.

⁽⁹⁾ Reported throughput volumes include Husky’s working interest from the BP-Husky Toledo Refinery (50%).

⁽¹⁰⁾ Excludes revenue and expenses not directly attributable to sale of synthetic crude and refined product, and blended crude oil.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 69

Gross Revenue and Marketing and Other

The Company’s consolidated gross revenues and marketing and other decreased by $1,329 million in the fourth quarter of 2020 compared to the fourth quarter of 2019.

In the Integrated Corridor business, gross revenues decreased primarily due to lower realized crude oil, refined product, gasoline and diesel pricing in the Lloydminster Heavy Oil Value Chain, U.S. Refining and Canadian Refined Products segments, as a result of the significant decline in benchmark commodity prices. The decrease is partially offset by higher throughput volumes at the Lima Refinery where a planned turnaround was completed in the fourth quarter of 2019.

In the Offshore business, gross revenues decreased primarily due to lower realized crude oil, natural gas and NGL pricing in Asia Pacific and Atlantic operations, combined with lower production from the Terra Nova field due to the suspension of operations in December 2019. The decrease is partially offset by higher sales volumes from Asia Pacific operations.

Net Earnings (Loss)

The Company’s consolidated net loss decreased by $1,415 million in the fourth quarter of 2020 compared to the fourth quarter of 2019.

In the Integrated Corridor business, net loss decreased primarily due to after-tax impairment charges and derecognitions of $1,399 million in the fourth quarter of 2019 within the Sunrise Energy Project, Western Canada Production, Lloyd Ethanol Plant, Minnedosa Ethanol Plant and Lima Refinery. The decrease is partially offset by after-tax impairment charges of $443 million, lower insurance recoveries recognized for business interruption and incident costs associated with the Superior Refinery and lower realized crude oil and refined product pricing in the Lloydminster Heavy Oil Value Chain.

In the Offshore business, net loss decreased primarily due to an after-tax impairment charge of $690 million and an after-tax write-down of exploration and evaluation assets of $186 million within the Atlantic in the fourth quarter of 2019. The decrease was partially offset by after-tax impairment charges of $361 million, combined with the same factors that impacted gross revenue and marketing and other.

Cash Flow – Operating Activities and Funds from Operations

Cash flow – operating activities and funds from operations decreased by $449 million and $166 million, respectively, in the fourth quarter of 2020 compared to the fourth quarter of 2019, primarily due to the same factors that impacted gross revenue and marketing and other. The decrease is partially offset by lower production, operating and transportation expenses due to cost savings initiatives.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 70

Daily Sales Volume

In the Lloydminster Heavy Oil Value Chain segment, daily sales volumes increased due to higher volumes of bitumen and heavy crude oil sales, partially offset by the planned turnaround at the Upgrader completed in October 2020.

In the Western Canada Production segment, daily sales volumes decreased due to the continued reduction, or shut-in, of production since March 2020 in response to market conditions.

During the fourth quarter of 2020, Offshore sales volumes increased primarily due to higher production from the Liwan Gas Project, including commencement of production at Liuhua 29-1 in November 2020, partially offset by lower production from the Terra Nova field due to the suspension of operations in December 2019.

Refinery Throughput

The Company’s refinery throughput increased by 89.0 mbbls/day in the fourth quarter of 2020 primarily due to the planned turnaround at the Lima Refinery completed in the fourth quarter of 2019, partially offset by the planned turnaround at the Upgrader completed in October 2020.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 71

Segmented Operational Information

Segmented Operational Information	2020												2019
($ millions, except where indicated)	Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
Gross revenues and Marketing and other
Integrated Corridor
Lloydminster Heavy Oil Value Chain		1,065			936			633			1,141			1,360			1,511			1,554			1,228
Oil Sands		110			61			34			53			134			182			198			139
Western Canada Production		108			87			62			125			166			140			107			200
U.S. Refining		1,690			1,730			1,134			2,122			2,321			2,743			2,837			2,375
Canadian Refined Products		381			393			258			456			658			611			582			574
Eliminations		(200	)		(141	)		(108	)		(153	)		(185	)		(213	)		(335	)		(215	)
Offshore		438			313			395			369			467			399			378			309
Total gross revenues and marketing and other		3,592			3,379			2,408			4,113			4,921			5,373			5,321			4,610
Net earnings (loss)
Integrated Corridor
Lloydminster Heavy Oil Value Chain		171			(1,311	)		(156	)		(13	)		43			189			198			74
Oil Sands		(498	)		(502	)		(19	)		(343	)		(619	)		21			18			35
Western Canada Production		(118	)		(192	)		(39	)		(221	)		(630	)		(47	)		(89	)		(6	)
U.S. Refining		(69	)		(3,248	)		(74	)		(534	)		(189	)		121			117			199
Canadian Refined Products		(7	)		2			(15	)		(9	)		(1	)		(2	)		(8	)		9
Offshore		(273	)		(1,621	)		38			(563	)		(778	)		26			4			55
Corporate		(132	)		(209	)		(39	)		(22	)		(167	)		(35	)		130			(38	)
Net earnings (loss)		(926	)		(7,081	)		(304	)		(1,705	)		(2,341	)		273			370			328
Per share – Basic		(0.93	)		(7.05	)		(0.31	)		(1.71	)		(2.34	)		0.26			0.36			0.32
Per share – Diluted		(0.92	)		(7.06	)		(0.31	)		(1.71	)		(2.34	)		0.25			0.36			0.31
Cash flow – operating activities		417			79			(10	)		355			866			800			760			545
Funds from operations(1)		303			148			18			25			469			1,021			802			959
Per share – Basic		0.30			0.15			0.02			0.02			0.47			1.02			0.80			0.95
Per share – Diluted		0.30			0.15			0.02			0.02			0.47			1.02			0.80			0.95
U.S./Canadian dollar exchange rate (US$)		0.768			0.751			0.722			0.745			0.758			0.757			0.748			0.752
Daily production, before royalties
Crude oil & NGL production (mbbls/day)
Light & Medium crude oil		22.9			21.3			26.0			28.8			33.3			30.5			19.6			16.5
NGL(4)		21.6			21.5			21.7			20.3			23.0			22.4			20.3			24.7
Heavy crude oil		20.2			18.4			16.7			30.4			32.6			31.6			28.9			27.6
Bitumen		136.4			117.4			95.1			138.0			137.8			126.4			120.4			130.3
Total crude oil & NGL production (mbbls/day)		201.1			178.6			159.5			217.5			226.7			210.9			189.2			199.1
Conventional Natural gas (mmcf/day)(4)		498.8			478.8			522.0			488.7			507.4			503.3			475.1			516.8
Total production (mboe/day)		284.2			258.4			246.5			298.9			311.3			294.8			268.4			285.2
Total sales volume
Integrated Corridor
Lloydminster Heavy Oil Value Chain (mboe/day)		175.9			166.5			165.4			194.4			170.6			186.9			184.8			156.0
Synthetic crude oil and refined products (mboe/day)		69.9			77.6			78.8			86.5			80.1			92.0			84.1			67.4
Blended crude oil (mboe/day)		106.0			88.9			86.6			107.9			90.5			94.9			100.7			88.6
Oil Sands
Diluted bitumen (mbbls/day)		30.1			21.6			19.8			35.2			33.4			34.3			33.0			22.9
Western Canada Production (mboe/day) (2)		51.7			55.7			60.5			62.6			66.9			70.3			60.5			69.2
Light crude oil (mbbls/day)		4.6			5.2			5.7			7.5			7.3			7.9			5.8			7.3
Conventional natural gas & NGL (mboe/day)		282.7			303.2			328.7			330.9			357.5			374.1			328.1			371.5
Offshore
Asia Pacific (mboe/day)(2)(3)(4)		55.9			49.1			52.1			44.3			45.3			41.5			42.2			46.1
NGL (mbbls/day)(2)(3)		12.3			11.5			11.1			9.4			10.4			9.4			9.6			10.3
Conventional natural gas (mmcf/day)(3)(4)		261.5			225.6			245.9			209.7			209.7			192.9			195.5			215.0
Atlantic
Light crude oil (mbbls/day)		22.5			7.3			26.0			15.4			22.2			21.6			15.2			4.4

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 72

	2020										2019
Segmented Operational Information (continued)	Q4		Q3		Q2			Q1			Q4		Q3		Q2			Q1
Total realized price per unit sold
Integrated Corridor
Lloydminster Heavy Oil Value Chain ($/boe)		53.14		50.27		33.93			55.67			69.83		74.00		76.36			64.66
Synthetic crude oil and refined products ($/boe)		57.08		60.86		44.44			64.13			78.75		79.51		86.60			73.83
Blended crude oil ($/boe)		50.55		41.03		24.36			48.87			61.94		68.66		67.82			57.70
Oil Sands
Diluted bitumen ($/bbl)		40.55		36.73		11.07			31.88			45.51		57.29		66.58			57.82
Western Canada Production ($/boe)		18.00		16.29		10.86			18.92			22.58		17.00		18.28			23.11
Light crude oil ($/bbl)		39.13		41.47		24.65			48.66			62.74		65.12		70.23			60.25
Conventional natural gas & NGL ($/mcf)		2.65		2.28		1.57			2.47			2.94		1.82		2.13			3.12
Offshore
Asia Pacific ($/boe)		68.52		71.40		74.37			80.84			80.15		74.17		79.55			79.73
NGL ($/bbl)		52.55		52.69		31.18			67.00			72.36		68.04		78.04			72.33
Conventional natural gas ($/mcf)		12.17		12.85		14.35			14.10			13.74		12.66		13.34			13.64
Atlantic
Light crude oil ($/bbl)		60.13		57.20		32.97			67.11			83.88		84.12		92.07			69.18
Unit upstream operating cost($/boe)(5)(6)		12.88		13.93		13.12			14.29			15.25		14.83		15.83			16.30
Unit operating margin(7)
Integrated Corridor
Lloydminster Heavy Oil Value Chain ($/boe)(8)		15.69		11.03		6.88			17.93			29.37		30.47		33.31			29.26
Synthetic crude oil and refined products ($/boe)		21.42		15.35		14.25			30.94			39.14		38.24		43.42			46.17
Blended crude oil ($/boe)		11.92		7.26		0.17			7.48			20.73		22.94		24.88			16.43
Oil Sands
Diluted bitumen ($/bbl)		14.71		17.48		(4.90	)		(24.92	)		10.63		21.26		15.28			38.91
Western Canada Production ($/boe)		4.09		5.86		(3.05	)		0.21			7.30		3.69		(2.99	)		9.59
Light crude oil ($/bbl)		0.53		9.93		0.36			16.94			21.70		32.15		21.30			15.41
Conventional natural gas & NGL ($/mcf)		0.73		0.89		(0.57	)		(0.35	)		0.92		0.03		(0.93	)		1.48
Offshore
Asia Pacific ($/boe)		54.63		59.29		64.94			68.11			68.11		61.51		66.69			66.80
NGL ($/bbl)		39.30		40.30		23.51			53.46			59.85		54.31		63.55			58.62
Conventional natural gas ($/mcf)		9.82		10.84		12.69			12.01			11.75		10.60		11.27			11.52
Atlantic
Light crude oil ($/bbl)		15.66		24.38		(2.81	)		19.69			50.89		41.60		25.35			(62.73	)
Lloydminster Heavy Oil Value Chain
Refinery throughput
Upgrading (mbbls/day)(9)		60.8		51.6		65.7			77.5			79.6		75.6		73.4			71.2
Lloydminster Refinery (mbbls/day)(10)		28.1		27.1		28.2			28.6			28.2		28.3		26.1			22.8
U.S. Refining
Refinery throughput(10)
Lima Refinery (mbbls/day)		137.4		153.7		130.0			131.4			21.4		174.3		179.8			171.4
BP-Husky Toledo Refinery (mbbls/day)(11)		66.1		67.7		57.4			70.3			70.3		66.8		57.5			58.0
Superior Refinery (mbbls/day)		—		—		—			—			—		—		—			—
Canadian Refined Products
Fuel sales (millions of litres/day)		6.8		7.2		5.7			6.9			7.4		7.5		7.2			7.5
Prince George Refinery throughput (mbbls/day)(12)		—		—		—			—			3.9		11.4		3.5			10.2

⁽¹⁾ Funds from operations is a non-GAAP measure. Refer to Section 9.3 for a reconciliation to the corresponding GAAP measure.

⁽²⁾ Sales volumes approximates total daily gross production.

⁽³⁾ Reported sales volumes include Husky’s working interest production from the Liwan Gas Project.

⁽⁴⁾ Reported production and sales volumes include Husky’s working interest production from the BD Project (40%). Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for consolidated financial statement purposes.

⁽⁵⁾ Reported production volumes and associated per unit values include Husky’s net working interest production from the Madura-BD Gas Project (40%). Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for consolidated financial statement purposes.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 73

⁽⁶⁾  Excludes operating costs not directly attributable to the production of upstream products.

⁽⁷⁾ Per unit cost calculated based on sales volumes.

⁽⁸⁾ Excludes revenue and expenses not directly attributable to sale of synthetic crude and refined product, and blended crude oil.

⁽⁹⁾ Upgrading throughput includes diluent returned to the field.

⁽¹⁰⁾ Includes all crude oil, feedstock, intermediate feedstock and blend-stocks used in producing sales volumes from the refinery.

⁽¹¹⁾ Reported throughput volumes include Husky’s working interest from the BP-Husky Toledo Refinery (50%).

⁽¹²⁾ Sale of Prince George Refinery closed on November 1, 2019.

Significant Items Impacting Gross Revenues, Net Earnings (Loss) and Funds from Operations

Variations in the Company’s gross revenues, net earnings (loss) and funds from operations are primarily driven by changes in production volumes, commodity prices, commodity price differentials, refining crack spreads, foreign exchange rates and planned turnarounds. Significant declines in crude oil and crack spread benchmarks were partially offset by higher production at the Liwan Gas Project. This resulted in a decrease to the Company’s gross revenues, net earnings and funds from operations. Other significant items which impacted gross revenues, net earnings and funds from operations over the last eight quarters include:

2020

Q4:

• The Company recognized a pre-tax impairment of $1,155 million in the Lloydminster Heavy Oil Value Chain, Oil Sands and Western Canada Production within the Integrated Corridor business and the Atlantic operation within the Offshore business, due to the sustained market impact from the COVID-19 pandemic, which has resulted in declines in forecasted long-term commodity prices, management’s decision to reduce capital investment, delayed future development plans, and considered market indicators including the Cenovus Transaction.

• At the Liuhua 29-1 field at Liwan, first gas was achieved.

• At the Spruce Lake Central project, nameplate capacity was reached.

• At the Upgrader, projects were completed that increased crude throughput capacity to 81.5 mbbls/day and increased diesel production capacity from 6 mbbls/day to 10 mbbls/day.

• At the Hardisty Terminal, construction on 1.0 mmbbls of incremental storage was completed and put into service.

• The Company recognized $85 million in pre-tax insurance recoveries for rebuild costs, incident costs and business interruption associated with the incident at the Superior Refinery.

• The Company recognized $12 million in pre-tax recoveries for the Canadian Emergency Wage Subsidy.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 74

Q3:

• The Company recognized a pre-tax impairment of $8,649 million, including exploration write-offs, in the Lloydminster Heavy Oil Value Chain, Oil Sands, Western Canada Production and U.S. Refining segments within the Integrated Corridor business and the Atlantic operation within the Offshore business, due to the sustained market impact from the COVID-19 pandemic, which has resulted in declines in forecasted long-term commodity prices, management’s decision to reduce capital investment and delayed future development plans.

• At the Spruce Lake Central project, first oil was achieved.

• At the Hardisty Terminal, construction on 0.5 mmbbls of incremental storage was completed and put into service.

• The Company recognized $23 million in pre-tax recoveries for the Canadian Emergency Wage Subsidy.

Q2:

• In the Integrated Corridor business, production and refinery operating rates were impacted by a deliberate ramp-down which began late in the first quarter of 2020 in response to market conditions as a result of the COVID-19 pandemic.

• The Company recognized $47 million in pre-tax recoveries for the Canadian Emergency Wage Subsidy.

Q1:

• The Company recognized a pre-tax impairment of $1,416 million, in the Oil Sands and Western Canada Production segments within the Integrated Corridor business and the Atlantic segment within the Offshore business, due to the market impact from the COVID-19 pandemic, which has resulted in declines in current and forecasted crude oil prices and management’s decision to delay capital investment in the West White Rose Project.

• The Company commenced the safe and orderly reduction, or shut-in, of production within the Integrated Corridor, to align with the upgrading and refining requirements as throughput was optimized in line with the changing market conditions.

• At the Lima Refinery, the crude oil flexibility project was commissioned.

2019

Q4:

• The Company recognized a pre-tax impairment charge of $2,405 million in the Oil Sands and Western Canada Production segments within the Integrated Corridor business and the Atlantic segment within the Offshore business. The impairment charge was primarily due to sustained declines in forecasted short and long-term crude oil and natural gas prices and management’s decision to reduce capital investment in these areas.

• The Company recognized a pre-tax write-down of $339 million related to certain Exploration and Evaluation assets in the Western Canada Production segment within the Integrated Corridor business and the Atlantic segment within the Offshore business. The write-down was primarily due to changes in management’s future development plans resulting from sustained declines in forecasted short and long-term prices for crude oil.

• The Company recognized a pre-tax derecognition charge of $254 million on the carrying value of components replaced as part of the crude oil flexibility project at the Lima Refinery.

• The Company closed the sale of the Prince George Refinery to Tidewater Midstream and Infrastructure.

• The Company recognized a pre-tax impairment charge of $90 million on the Lloyd Ethanol Plant and Minnedosa Ethanol Plant, primarily due to sustained declines in forecasted ethanol margins.

• At the Spruce Lake Central project, construction on the CPF was completed.

• At the Wembley area, in the Montney Formation, six liquids-rich wells were started up.

• At the Liuhua 29-1 field at Liwan, the remaining four of seven wells were completed.

• At the Lima Refinery a planned turnaround was completed, with final tie-ins made for the crude oil flexibility project.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 75

• The Company recognized $308 million in pre-tax insurance recoveries for rebuild costs, incident costs and business interruption associated with the incident at the Superior Refinery.

Q3:

• At the Dee Valley Thermal Project, first oil was achieved and nameplate capacity was reached.

• At the Spruce Lake North Thermal Project, concrete work was completed.

• At the Spruce Lake East Thermal Project, regulatory approval was received and lease construction was completed.

• At the Karr area, in the Montney Formation, one well was drilled.

• At the Liuhua 29-1 field at Liwan, three of the seven wells were fully completed.

• At the White Rose field and satellite extension, full production was restored.

• At the Superior Refinery, permits necessary for the rebuild were received and rebuilding work began.

• The Company recognized $138 million in pre-tax insurance recoveries for incident costs and business interruption associated with the incident at the Superior Refinery.

Q2:

• At the Dee Valley Thermal Project, first steam was achieved.

• At the Spruce Lake North Thermal Project, site piling was completed and concrete work progressed.

• At the Spruce Lake East Thermal Project, lease construction started.

• At the Dee Valley 2 and Edam Central Thermal Projects, regulatory approval was received.

• At the Ansell and Kakwa areas, in the liquids-rich Cardium and Spirit River formations, two wells were drilled and four were completed.

• At the Liuhua 29-1 field, three development wells were drilled.

• Two infill wells were completed at the White Rose field and satellite extensions.

• The Company wrote off the Tiger’s Eye D-17 exploration well.

• An exploration well drilled on Block 16/25 in 2018, which did not encounter commercial hydrocarbons, was written off.

• The Company recognized $233 million in tax recoveries related to the reduction in the Alberta provincial corporate tax rate.

• The Company recognized $71 million in pre-tax insurance recoveries for incident costs and business interruption associated with the incident at the Superior Refinery.

Q1:

• At the Dee Valley Thermal Project, drilling and fabrication of the Central Processing Facility was completed.

• At the Spruce Lake Central Thermal Project, site piling, concrete work and drilling were all completed. Large vessel and module fabrication progressed.

• At the Spruce Lake North Thermal Project, site preparation was completed, and large vessel and module fabrication progressed.

• At the Spruce Lake East Thermal Project, site preparation was completed, regulatory approval was received, and site clearing commenced.

• At the Ansell and Kakwa areas, in the liquids-rich Cardium and Spirit River Formations, eight wells drilled and six completed.

• At the Sinclair and Wembley areas, in the Montney Formation, four wells were drilled.

• Two infill wells were drilled at the White Rose field and satellite extensions.

• The Company recognized $113 million in pre-tax insurance recoveries for incident costs and business interruption associated with the incident at the Superior Refinery.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 76

Segmented Financial Information

	Integrated Corridor
	Lloydminster Heavy Oil Value Chain												Oil Sands												Western Canada Production
2020 ($ millions)	Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
Gross revenues		1,048			932			603			1,170			109			68			26			103			98			85			65			119
Royalties		(31	)		(36	)		(8	)		(17	)		—			(1	)		—			(1	)		(4	)		4			(1	)		(9	)
Marketing and other		17			4			30			(29	)		1			(7	)		8			(50	)		10			2			(3	)		6
Revenues, net of royalties		1,034			900			625			1,124			110			60			34			52			104			91			61			116
Expenses
Purchases of crude oil and products		514			454			333			526			34			9			10			100			10			(1	)		—			13
Production, operating and transportation expenses		273			261			234			291			30			26			23			35			60			56			60			74
Selling, general and administrative expenses		51			49			53			51			6			4			5			9			15			16			7			26
Depletion, depreciation, amortization and impairment		57			1,590			179			232			694			684			10			361			180			280			41			301
Exploration and evaluation expenses		1			154			—			27			(1	)		—			—			—			—			1			—			—
Loss (gain) on sale of assets		(4	)		—			—			—			—			—			—			—			(1	)		(11	)		(2	)		(6	)
Other – net		1			8			12			—			(4	)		(8	)		(7	)		(7	)		(7	)		—			—			—
		893			2,516			811			1,127			759			715			41			498			257			341			106			408
Earnings (loss) from operating activities		141			(1,616	)		(186	)		(3	)		(649	)		(655	)		(7	)		(446	)		(153	)		(250	)		(45	)		(292	)
Share of equity investment income (loss)		—			(14	)		(15	)		(3	)		—			—			—			—			—			—			—			—
Financial items
Net foreign exchange gains (losses)		—			—			—			—			—			—			—			—			—			—			—			—
Finance income		—			—			—			—			—			—			—			—			—			—			—			—
Finance expenses		(11	)		(12	)		(12	)		(12	)		(14	)		(14	)		(14	)		(15	)		(4	)		(5	)		(5	)		(5	)
		(11	)		(12	)		(12	)		(12	)		(14	)		(14	)		(14	)		(15	)		(4	)		(5	)		(5	)		(5	)
Earnings (loss) before income tax		130			(1,642	)		(213	)		(18	)		(663	)		(669	)		(21	)		(461	)		(157	)		(255	)		(50	)		(297	)
Provisions for (recovery of) income taxes
Current		—			1			(2	)		1			—			—			—			—			—			—			—			—
Deferred		(41	)		(332	)		(55	)		(6	)		(165	)		(167	)		(2	)		(118	)		(39	)		(63	)		(11	)		(76	)
		(41	)		(331	)		(57	)		(5	)		(165	)		(167	)		(2	)		(118	)		(39	)		(63	)		(11	)		(76	)
Net earnings (loss)		171			(1,311	)		(156	)		(13	)		(498	)		(502	)		(19	)		(343	)		(118	)		(192	)		(39	)		(221	)
Capital expenditures		100			178			53			263			1			—			—			8			13			2			(5	)		47
Total assets		6,650			6,210			7,756			7,959			993			1,583			2,210			2,333			707			1,068			1,284			1,369

⁽¹⁾  Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices. Segment results include transactions between segments.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 77

Integrated Corridor (continued)
U.S. Refining												Canadian Refined Products												Eliminations(1)												Total
Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
	1,704			1,737			1,131			2,064			381			393			258			456			(200	)		(141	)		(108	)		(153	)		3,140			3,074			1,975			3,759
	—			—			—			—			—			—			—			—			—			—			—			—			(35	)		(33	)		(9	)		(27	)
	(14	)		(7	)		3			58			—			—			—			—			—			—			—			—			14			(8	)		38			(15	)
	1,690			1,730			1,134			2,122			381			393			258			456			(200	)		(141	)		(108	)		(153	)		3,119			3,033			2,004			3,717
	1,582			1,604			884			2,430			345			351			231			422			(200	)		(141	)		(108	)		(153	)		2,285			2,276			1,350			3,338
	199			195			183			220			15			17			17			16			—			—			—			—			577			555			517			636
	17			12			21			22			11			10			10			13			—			—			—			—			100			91			96			121
	59			4,091			137			132			16			16			15			15			—			—			—			—			1,006			6,661			382			1,041
	—			—			—			—			—			—			—			—			—			—			—			—			—			155			—			27
	—			—			—			—			1			(2	)		1			—			—			—			—			—			(4	)		(13	)		(1	)		(6	)
	(84	)		—			—			—			—			(4	)		—			—			—			—			—			—			(94	)		(4	)		5			(7	)
	1,773			5,902			1,225			2,804			388			388			274			466			(200	)		(141	)		(108	)		(153	)		3,870			9,721			2,349			5,150
	(83	)		(4,172	)		(91	)		(682	)		(7	)		5			(16	)		(10	)		—			—			—			—			(751	)		(6,688	)		(345	)		(1,433	)
	—			—			—			—			—			—			—			—			—			—			—			—			—			(14	)		(15	)		(3	)
	—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—
	—			—			—			—			—			—			—			—			—			—			—			—			—			—			—			—
	(5	)		(4	)		(4	)		(5	)		(3	)		(3	)		(2	)		(3	)		—			—			—			—			(37	)		(38	)		(37	)		(40	)
	(5	)		(4	)		(4	)		(5	)		(3	)		(3	)		(2	)		(3	)		—			—			—			—			(37	)		(38	)		(37	)		(40	)
	(88	)		(4,176	)		(95	)		(687	)		(10	)		2			(18	)		(13	)		—			—			—			—			(788	)		(6,740	)		(397	)		(1,476	)
	1			5			(8	)		2			—			—			—			—			—			—			—			—			1			6			(10	)		3
	(20	)		(933	)		(13	)		(155	)		(3	)		—			(3	)		(4	)		—			—			—			—			(268	)		(1,495	)		(84	)		(359	)
	(19	)		(928	)		(21	)		(153	)		(3	)		—			(3	)		(4	)		—			—			—			—			(267	)		(1,489	)		(94	)		(356	)
	(69	)		(3,248	)		(74	)		(534	)		(7	)		2			(15	)		(9	)		—			—			—			—			(521	)		(5,251	)		(303	)		(1,120	)
	118			95			113			163			1			1			1			2			—			—			—			—			233			276			162			483
	4,469			4,415			8,710			8,881			625			735			732			763			—			—			—			—			13,444			14,011			20,692			21,305

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 78

Offshore											Corporate												Total
Q4		Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
	438		313			395			369			—			—			—			—			3,578			3,387			2,370			4,128
	(28)		(20	)		(21	)		(18	)		—			—			—			—			(63	)		(53	)		(30	)		(45	)
	—		—			—			—			—			—			—			—			14			(8	)		38			(15	)
	410		293			374			351			—			—			—			—			3,529			3,326			2,378			4,068
	37		(37	)		22			10			—			—			—			—			2,322			2,239			1,372			3,348
	66		75			64			70			—			—			—			—			643			630			581			706
	18		16			23			18			78			73			67			44			196			180			186			183
	592		1,952			183			1,011			22			23			25			22			1,620			8,636			590			2,074
	67		460			15			9			—			—			—			—			67			615			15			36
	—		—			(1	)		—			(4	)		4			—			—			(8	)		(9	)		(2	)		(6	)
	(5)		—			—			—			30			(25	)		(46	)		(116	)		(69	)		(29	)		(41	)		(123	)
	775		2,466			306			1,118			126			75			46			(50	)		4,771			12,262			2,701			6,218
	(365)		(2,173	)		68			(767	)		(126	)		(75	)		(46	)		50			(1,242	)		(8,936	)		(323	)		(2,150	)
	8		13			5			13			—			—			—			—			8			(1	)		(10	)		10
	—		—			—			—			32			4			28			(50	)		32			4			28			(50	)
	2		2			2			1			1			2			2			13			3			4			4			14
	(10)		(10	)		(11	)		(10	)		(66	)		(63	)		(57	)		(20	)		(113	)		(111	)		(105	)		(70	)
	(8)		(8	)		(9	)		(9	)		(33	)		(57	)		(27	)		(57	)		(78	)		(103	)		(73	)		(106	)
	(365)		(2,168	)		64			(763	)		(159	)		(132	)		(73	)		(7	)		(1,312	)		(9,040	)		(406	)		(2,246	)
	45		37			35			33			7			28			10			7			53			71			35			43
	(137)		(584	)		(9	)		(233	)		(34	)		49			(44	)		8			(439	)		(2,030	)		(137	)		(584	)
	(92)		(547	)		26			(200	)		(27	)		77			(34	)		15			(386	)		(1,959	)		(102	)		(541	)
	(273)		(1,621	)		38			(563	)		(132	)		(209	)		(39	)		(22	)		(926	)		(7,081	)		(304	)		(1,705	)
	62		69			130			107			16			9			18			22			311			354			310			612
	4,570		4,874			7,224			7,486			1,673			2,525			1,543			2,294			19,687			21,410			29,459			31,085

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 79

	Integrated Corridor
	Lloydminster Heavy Oil Value Chain												Oil Sands												Western Canada Production
2019 ($ millions)	Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
Gross revenues		1,373			1,506			1,540			1,182			139			182			208			120			143			112			109			150
Royalties		(37	)		(42	)		(47	)		(34	)		(3	)		(4	)		(4	)		(2	)		(14	)		(7	)		(7	)		(13	)
Marketing and other		(13	)		5			14			46			(5	)		—			(10	)		19			23			28			(2	)		50
Revenues, net of royalties		1,323			1,469			1,507			1,194			131			178			194			137			152			133			100			187
Expenses
Purchases of crude oil and products		559			637			705			494			61			73			100			12			8			18			12			2
Production, operating and transportation expenses		322			302			291			297			37			33			30			40			80			69			81			83
Selling, general and administrative expenses		35			44			37			39			7			7			6			7			29			26			24			27
Depletion, depreciation, amortization and impairment		303			210			192			236			862			28			25			23			784			80			93			77
Exploration and evaluation expenses		19			14			4			17			1			1			—			—			99			7			3			2
Loss (gain) on sale of assets		—			—			—			—			—			—			—			—			—			—			—			(2	)
Other – net		3			(6	)		4			8			(7	)		(7	)		(14	)		—			5			(7	)		3			—
		1,241			1,201			1,233			1,091			961			135			147			82			1,005			193			216			189
Earnings (loss) from operating activities		82			268			274			103			(830	)		43			47			55			(853	)		(60	)		(116	)		(2	)
Share of equity investment income (loss)		(13	)		4			8			10			—			—			—			—			—			—			—			—
Financial items
Net foreign exchange gains (losses)		—			—			—			—			—			—			—			—			—			—			—			—
Finance income		—			—			—			—			—			—			—			—			—			—			—			—
Finance expenses		(12	)		(13	)		(12	)		(11	)		(15	)		(15	)		(21	)		(8	)		(7	)		(5	)		(6	)		(6	)
		(12	)		(13	)		(12	)		(11	)		(15	)		(15	)		(21	)		(8	)		(7	)		(5	)		(6	)		(6	)
Earnings (loss) before income tax		57			259			270			102			(845	)		28			26			47			(860	)		(65	)		(122	)		(8	)
Provisions for (recovery of) income taxes
Current		11			(3	)		(6	)		(4	)		(3	)		6			7			—			—			—			—			—
Deferred		3			73			78			32			(223	)		1			1			12			(230	)		(18	)		(33	)		(2	)
		14			70			72			28			(226	)		7			8			12			(230	)		(18	)		(33	)		(2	)
Net earnings (loss)		43			189			198			74			(619	)		21			18			35			(630	)		(47	)		(89	)		(6	)
Capital expenditures		282			205			208			261			3			7			18			10			6			32			60			96
Total assets		8,312			8,172			7,982			7,900			2,757			3,546			3,567			3,630			1,709			2,427			2,512			2,543

⁽¹⁾  Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices. Segment results include transactions between segments.

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 80

Integrated Corridor (continued)
U.S. Refining											Canadian Refined Products												Eliminations(1)												Total
Q4		Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
	2,318		2,743			2,855			2,337			658			611			582			574			(185	)		(213	)		(335	)		(215	)		4,446			4,941			4,959			4,148
	—		—			—			—			—			—			—			—			—			—			—			—			(54	)		(53	)		(58	)		(49	)
	3		—			(18	)		38			—			—			—			—			—			—			—			—			8			33			(16	)		153
	2,321		2,743			2,837			2,375			658			611			582			574			(185	)		(213	)		(335	)		(215	)		4,400			4,921			4,885			4,252
	2,232		2,417			2,406			1,879			613			549			518			495			(185	)		(213	)		(335	)		(215	)		3,288			3,481			3,406			2,667
	242		197			218			215			28			40			47			38			—			—			—			—			709			641			667			673
	13		13			13			12			1			3			2			3			—			—			—			—			85			93			82			88
	380		117			122			116			17			22			22			22			—			—			—			—			2,346			457			454			474
	—		—			—			—			—			—			—			—			—			—			—			—			119			22			7			19
	—		1			—			—			(2	)		(4	)		—			—			—			—			—			—			(2	)		(3	)		—			(2	)
	(307)		(163	)		(76	)		(108	)		—			—			—			—			—			—			—			—			(306	)		(183	)		(83	)		(100	)
	2,560		2,582			2,683			2,114			657			610			589			558			(185	)		(213	)		(335	)		(215	)		6,239			4,508			4,533			3,819
	(239)		161			154			261			1			1			(7	)		16			—			—			—			—			(1,839	)		413			352			433
	—		—			—			—			—			—			—			—			—			—			—			—			(13	)		4			8			10
	—		—			—			—			—			—			—			—			—			—			—			—			—			—			—			—
	—		—			—			—			—			—			—			—			—			—			—			—			—			—			—			—
	(4)		(5	)		(5	)		(4	)		(2	)		(4	)		(3	)		(4	)		—			—			—			—			(40	)		(42	)		(47	)		(33	)
	(4)		(5	)		(5	)		(4	)		(2	)		(4	)		(3	)		(4	)		—			—			—			—			(40	)		(42	)		(47	)		(33	)
	(243)		156			149			257			(1	)		(3	)		(10	)		12			—			—			—			—			(1,892	)		375			313			410
	—		10			2			5			—			—			—			—			—			—			—			—			8			13			3			1
	(54)		25			30			53			—			(1	)		(2	)		3			—			—			—			—			(504	)		80			74			98
	(54)		35			32			58			—			(1	)		(2	)		3			—			—			—			—			(496	)		93			77			99
	(189)		121			117			199			(1	)		(2	)		(8	)		9			—			—			—			—			(1,396	)		282			236			311
	241		196			202			129			10			12			41			10			—			—			—			—			542			452			529			506
	8,645		8,873			8,523			8,767			838			1,115			1,088			1,043			—			—			—			—			22,261			24,133			23,672			23,883

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 81

Offshore											Corporate												Total
Q4		Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
	467		399			378			309			—			—			—			—			4,913			5,340			5,337			4,457
	(34)		(28	)		(25	)		(22	)		—			—			—			—			(88	)		(81	)		(83	)		(71	)
	—		—			—			—			—			—			—			—			8			33			(16	)		153
	433		371			353			287			—			—			—			—			4,833			5,292			5,238			4,539
	(18)		4			19			(21	)		—			—			—			—			3,270			3,485			3,425			2,646
	89		86			79			86			—			—			—			—			798			727			746			759
	11		14			15			15			120			42			85			43			216			149			182			146
	1,147		221			164			129			27			25			25			27			3,520			703			643			630
	271		19			79			11			—			—			—			—			390			41			86			30
	—		(1	)		—			—			(1	)		1			—			—			(3	)		(3	)		—			(2	)
	1		—			—			—			(5	)		(22	)		9			2			(310	)		(205	)		(74	)		(98	)
	1,501		343			356			220			141			46			119			72			7,881			4,897			5,008			4,111
	(1,068)		28			(3	)		67			(141	)		(46	)		(119	)		(72	)		(3,048	)		395			230			428
	8		15			15			12			—			—			—			—			(5	)		19			23			22
	—		—			—			—			20			(8	)		2			30			20			(8	)		2			30
	2		—			—			1			12			24			16			19			14			24			16			20
	(10)		(9	)		(10	)		(9	)		(29	)		(33	)		(48	)		(41	)		(79	)		(84	)		(105	)		(83	)
	(8)		(9	)		(10	)		(8	)		3			(17	)		(30	)		8			(45	)		(68	)		(87	)		(33	)
	(1,068)		34			2			71			(138	)		(63	)		(149	)		(64	)		(3,098	)		346			166			417
	17		36			35			37			7			2			8			8			32			51			46			46
	(307)		(28	)		(37	)		(21	)		22			(30	)		(287	)		(34	)		(789	)		22			(250	)		43
	(290)		8			(2	)		16			29			(28	)		(279	)		(26	)		(757	)		73			(204	)		89
	(778)		26			4			55			(167	)		(35	)		130			(38	)		(2,341	)		273			370			328
	312		380			300			280			40			36			29			26			894			868			858			812
	8,077		9,073			8,917			9,122			2,784			3,406			3,565			4,369			33,122			36,612			36,154			37,374

Husky Energy Inc. | Management’s Discussion and Analysis 2020 | 82

Exhibit     No.	Description
23.1	Consent of KPMG LLP, independent registered public accounting firm.
23.2	Consent of Sproule Associates Limited, independent qualified reserves auditor.
31.1	Certification of Acting Chief Executive Officer & Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.
32.1	Certification of Acting Chief Executive Officer & Chief Financial Officer pursuant to Rule 13(a)-14(b) or Rule 15d-14(b)and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
99.1	Supplemental Disclosures of Oil and Gas Activities.
99.2	Amended Code of Business Conduct.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.