2018

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, 2018

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))

707-8th 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, 2018

10,435,932 Cumulative Redeemable Preferred Shares, Series 1 outstanding as of December 31, 2018

1,564,068 Cumulative Redeemable Preferred Shares, Series 2 outstanding as of December 31, 2018

10,000,000 Cumulative Redeemable Preferred Shares, Series 3 outstanding as of December 31, 2018

8,000,000 Cumulative Redeemable Preferred Shares, Series 5 outstanding as of December 31, 2018

6,000,000 Cumulative Redeemable Preferred Shares, Series 7 outstanding as of December 31, 2018

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 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.  ☐

This Annual Report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, the Registrant’s Registration Statement under the Securities Act of 1933: Form F-10 (File No. 333-222652); Form S-8 (File No. 333-187135).

† 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.

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, 2018 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, 2018 and December 31, 2017, 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, 2018 is included as Document C of this Annual Report on Form 40-F.

Certifications

See Exhibits 31.1, 31.2, 32.1 and 32.2, 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, 2018, 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, 2018, 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, 2018 and 2017, which is 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, 2018, 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

The Board of Directors of Husky has determined that William Shurniak is an “audit committee financial expert” (as defined in paragraph 8(b) of General Instruction B to Form 40-F) serving on its Audit Committee. Pursuant to paragraph 8(a)(2) of General Instruction B to Form 40-F, the Board has applied the definition of independence applicable to the audit committee members of New York Stock Exchange listed companies, although the Company’s securities are not listed on a U.S. stock exchange. Mr. Shurniak is a corporate director and is independent under the New York Stock Exchange standards. For a description of Mr. Shurniak’s relevant experience in financial matters, see Mr. Shurniak’s history in the section “Directors and Officers” and in the section “Audit Committee” in Husky’s AIF for the year ended December 31, 2018, which is included as Document A of this Annual Report on Form 40-F.

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 April 25, 2018, Husky amended its Code of Business Conduct effective as of April 25, 2018, 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, 2018. A copy of such amended Code of Business Conduct was posted on Husky’s website (together with a disclosure of the nature of the amendment) promptly after the amendment became effective. In the fiscal year ended December 31, 2018, Husky has not granted 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, 2018, 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, 2018, 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, 2018, 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 fiscal year ended December 31, 2018.

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. 333-222652) 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 26^th day of February, 2019

	Husky Energy Inc.
By:	/s/ Robert J. Peabody
	Name: Robert J. Peabody
	Title: President & Chief Executive 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, 2018

ANNUAL INFORMATION FORM

FOR THE YEAR ENDED DECEMBER 31, 2018

February 26, 2019

TABLE OF CONTENTS

NOTE TO READER	1
ABBREVIATIONS AND GLOSSARY OF TERMS	1
EXCHANGE RATE INFORMATION	6
CORPORATE STRUCTURE	6
GENERAL DEVELOPMENT OF HUSKY	7
DESCRIPTION OF HUSKY’S BUSINESS	10
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	21
SOCIAL AND ENVIRONMENTAL CONSIDERATIONS	43
INDUSTRY OVERVIEW	47
RISK FACTORS	57
HUSKY EMPLOYEES	65
DIVIDENDS	65
DESCRIPTION OF CAPITAL STRUCTURE	67
MARKET FOR SECURITIES	70
DIRECTORS AND OFFICERS	73
LEGAL PROCEDINGS	80
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	80
TRANSFER AGENTS AND REGISTRARS	80
INTERESTS OF EXPERTS	80
ADDITIONAL INFORMATION	81
READER ADVISORIES	81
APPENDIX A - AUDIT COMMITTEE MANDATE	85
APPENDIX B - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES AUDITOR	89
APPENDIX C - REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE	90
APPENDIX D - INDEPENDENT ENGINEER’S AUDIT OPINION	91

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, 2018, 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.

See also “Reader Advisories” on page 81 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	barrels
bbls/day	barrels per calendar day
bcf	billion cubic feet
boe	barrels of oil equivalent
boe/day	barrels of oil equivalent per calendar day
CO2e	carbon dioxide equivalent
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
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
tCO2e	tonnes of carbon dioxide equivalent

abandonment and reclamation costs

All costs associated with the process of restoring Husky’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.

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.

Atlantic Accord

The memorandum of agreement between the Government of Canada and the Government of the Province of Newfoundland and Labrador on offshore petroleum resource management and revenue sharing dated February 11, 1985, including any amendments to the memorandum of agreement.

barrel

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

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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.

Board or Board of Directors

The board of directors of the Company.

BP-Husky Toledo Refinery

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

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 oil, added to heavy oil and bitumen to facilitate the transmissibility of the oil through a pipeline.

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

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.

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.

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.

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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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 mixture consisting primarily of methane, but commonly including varying amounts of other higher alkanes, and sometimes a small percentage of carbon dioxide, nitrogen and/or hydrogen sulfide.

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.

oil sands

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

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.

Plan of Development

As it relates to the Company’s operations in Indonesia, a Plan of Development represents development planning on one or more oil and gas fields in an integrated and optimal plan for the production of hydrocarbon reserves considering technical, economical and environmental aspects. An initial Plan of Development in a development area needs both SKK Migas and the Minister of Energy and Mineral Resources approvals. Subsequent Plans of Development in the same development area only need SKK Migas approval.

Prince George Refinery

The light oil refinery owned by the Company and located in Prince George, British Columbia.

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.

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 GHG emissions

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

Scope 2 GHG emissions

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

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.

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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 or SDL

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.

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 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.

turnaround

Performance of plant or facility maintenance.

unproved property

Property or part of a party to which no reserves have been specifically attributed.

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.

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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.

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.

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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$)	2018		2017		2016
Year-end(1)		1.365		1.252		1.343
Low		1.228		1.213		1.254
High		1.365		1.374		1.459
Average		1.296		1.298		1.325

⁽¹⁾  The year-end exchange rates for 2018 and 2017 were as quoted by the Thomson Reuters WM/R for the noon rate at the last day of the relevant period. The year-end exchange rate for 2016 was as quoted by the Bank of Canada for the noon buying rate as at the last day of the relevant period. The Bank of Canada discontinued the publication of the noon buying rates during 2017. The high, low and average rates were either quoted by Thomson Reuters WM/R or the Bank of Canada, as applicable, or calculated from data from those sources within each of the relevant periods.

CORPORATE STRUCTURE

Incorporation and Organization

Husky Energy Inc. was incorporated under the Business Corporations Act (Alberta) 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, 2018. All of the entities listed below, except as otherwise indicated, are 100 percent beneficially owned, or controlled or directed, directly or indirectly, by Husky.

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 Terra Nova Partnership	Alberta
Husky Downstream General Partnership	Alberta
Husky Energy Marketing Partnership	Alberta
Sunrise Oil Sands Partnership (50 percent)	Alberta
BP-Husky Refining LLC (50 percent)	Delaware

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

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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.

2016

On March 9, 2016, the maturity date for one of the Company’s $2.0 billion revolving syndicated credit facilities, previously set to expire on December 14, 2016, was extended to March 9, 2020. In addition, the Company’s leverage covenant was modified to a debt-to-capital covenant.

On March 31, 2016, the Company announced that holders of 1,564,068 Series 1 Preferred Shares exercised their option to convert their shares, on a one-for-one basis, to Series 2 Preferred Shares and receive a floating rate quarterly dividend.

On April 18, 2016, the Company announced that it had commenced production at the 10,000 bbls/day Edam East Thermal Project in Saskatchewan.

On April 19, 2016, the Company commenced production from the Colony formation at the Tucker Thermal Project in the Cold Lake region of Alberta.

On May 25, 2016, the Company completed the sale of Western Canada royalty interests to a third party for gross proceeds of $165 million.

On June 16, 2016, the Company announced that it had commenced production at the 10,000 bbls/day Vawn Thermal Project in Saskatchewan.

Production from the Sunrise Energy Project was temporarily impacted by wildfires in the Fort McMurray region of Alberta in the second quarter of 2016. Operations were successfully restarted in the same quarter with all 55 well pairs back online and the plant being fully operational.

On July 15, 2016, the Company completed the sale of 65 percent of its ownership interest in select midstream assets in the Lloydminster region of Alberta and Saskatchewan for gross proceeds of $1.69 billion in cash. The assets included approximately 1,900 kilometres of pipeline in the Lloydminster region, 4.1 mmbbls of storage capacity at Hardisty and Lloydminster and other ancillary assets. The assets were sold to Husky Midstream Limited Partnership (“HMLP”), of which Husky owns 35 percent, Power Assets Holdings Limited (“PAH”) owns 48.75 percent and CK Infrastructure Holdings Limited (“CKI”) owns 16.25 percent. Proceeds from the transaction were received in the third quarter of 2016.

On August 2, 2016, the Company announced that its China subsidiary had signed a Heads of Agreement (“HOA”) with China National Offshore Oil Corporation (“CNOOC”) and relevant companies for the price adjustment of natural gas from the Liwan 3-1 and Liuhua 34-2 fields with the revised price set at Cdn$12.50-Cdn$15.00 per mcf. The price adjustment under the HOA was effective as of November 20, 2015, and the settlement of outstanding payment was calculated from that date.

On August 29, 2016, the Company commenced production at the 4,500 bbls/day Edam West Thermal Project in Saskatchewan.

On September 15, 2016, the Company commenced production at the North Amethyst Hibernia formation well offshore Newfoundland and Labrador (“NL”).

On November 9, 2016, the Canada-Newfoundland and Labrador Offshore Petroleum Board (“C-NLOPB”) announced that the Company was the successful bidder on two parcels of land in its 2016 land sale. The lands cover an area of 211,574 hectares and brought the Company’s exploration licences (“ELs”) in the region to eight. The southwest parcel is adjacent to the White Rose field and satellite extensions, while the other is northeast of the field and adjacent to other Husky operated ELs in the Jeanne d’Arc Basin.

On November 29, 2016, the Company commenced production from a third well at the South White Rose project in the Jeanne d’Arc Basin offshore NL.

In late 2016, the Company sanctioned three new Lloyd thermal projects with total design capacity of 30,000 bbls/day at Dee Valley, Spruce Lake North and Spruce Lake Central.

Also during 2016, the Company completed the sale of approximately 30,200 boe/day of legacy crude oil and gas assets in Western Canada for gross proceeds of $1.12 billion.

Husky Energy Inc. | Annual Information Form 2018 | 7

2017

On March 10, 2017, the Company issued $750 million of 3.60 percent notes due March 10, 2027 by way of a prospectus supplement dated March 7, 2017, to its base shelf prospectus. The notes are redeemable at the option of the Company at any time, subject to a make whole premium unless the notes are redeemed in the three-month period prior to maturity. Interest is payable semi-annually on March 10 and September 10 of each year, beginning September 10, 2017. The notes are unsecured and unsubordinated and rank equally with all of the Company’s other unsecured and unsubordinated indebtedness.

On April 13, 2017, the Company announced that it had signed a production sharing contract (“PSC”) for Block 16/25 in the Pearl River Mouth Basin in the South China Sea. Under the PSC, Husky has an obligation to drill two exploration wells within the first three years.

On May 5, 2017, the Company announced that, during the first quarter of 2017, it had commenced production from a new eight-well pad at the Tucker Thermal Project in the Cold Lake region of Alberta and from a new infill well at North Amethyst offshore NL.

On May 29, 2017, the Company announced that, together with its partners, it would be moving forward with the West White Rose Project in the Jeanne d’Arc Basin offshore NL, using a fixed wellhead platform tied back to the SeaRose FPSO.

Also in May 2017, the Company announced a new discovery at Northwest White Rose. The White Rose A-78 well was drilled approximately 11 kilometres northwest of the SeaRose FPSO in the first quarter of 2017 and delineated a light oil column of more than 100 metres (gross). The Company has a 93.23 percent working interest in the well.

On July 21, 2017, the Company announced that the construction and installation of the shallow water jackets and subsea pipelines for the MDA-MBH fields in the Madura Strait were completed. The contract for a leased floating production unit was signed, and planning for the build commenced.

On September 15, 2017, the Company repaid the maturing 6.20 percent notes issued under a trust indenture dated September 11, 2007. The amount paid to note holders was $365 million, including $11 million of interest.

On October 26, 2017, the Company announced that, during the third quarter of 2017, gas production from the BD Project commenced and was sold from the onshore gas distribution facility in East Java under a fixed price gas sales agreement (“GSA”).

Also in October 2017, the Company announced that the GSA for future gas production from Liuhua 29-1, the third deepwater gas field at the Liwan Gas Project, was signed. The project was sanctioned in the fourth quarter of 2017.

On November 8, 2017, the Company completed the purchase of the Superior Refinery, a 50,000 bbls/day permitted capacity facility located in Superior, Wisconsin, U.S., from Calumet Specialty Products Partners, L.P. (“Calumet”) for $670 million (US$527 million). The acquisition included the Superior Refinery’s associated logistics assets, including two asphalt terminals, 3.6 mmbbls of crude and product storage and a fuels and asphalt marketing business. See “Description of Husky’s Business – Downstream Operations – U.S. Refining and Marketing – Superior Refinery”.

In November 2017, the Company sanctioned two new 10,000 bbls/day thermal projects at Westhazel and Edam Central.

In November 2017, the C-NLOPB announced that the Company was the successful bidder on a parcel of land in its 2017 land sale (50 percent Husky working interest). The lands cover an area of 121,453 hectares in the Jeanne d’Arc Basin. The lands are adjacent to the Company’s other ELs in the basin.

Also in November 2017, the Company’s participation in the Wenchang oilfields petroleum contract expired, and the Company will not be entitled to any further production rights.

During 2017, the Company completed the sale of select assets in Western Canada, representing approximately 20,200 boe/day for gross proceeds of approximately $185 million.

Also during 2017, regulatory approval was received for the three Lloyd thermal projects sanctioned in late 2016, Dee Valley, Spruce Lake North and Spruce Lake Central.

Also during 2017, the Company and Imperial Oil closed their previously announced transaction to create a single expanded truck transport network of approximately 160 sites.

Husky Energy Inc. | Annual Information Form 2018 | 8

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 that the Board of Directors had approved 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. Normal operations are not expected to resume until 2020.

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 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”). The offer expired on January 16, 2019 without the minimum tender condition satisfied and the offer was not extended.

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

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. Operations resumed in the first quarter of 2019.

In November 2018, Spruce Lake East was sanctioned, with regulatory approval received in 2019.

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

Recent Developments

On January 8, 2019, the Company announced its intention to market and potentially sell its Prince George Refinery and Retail and Commercial Network.

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DESCRIPTION OF HUSKY’S BUSINESS

Overview

Husky is a publicly traded international integrated energy company headquartered in Calgary, Alberta, Canada.

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: Upstream and Downstream.

Upstream operations include exploration for, and development and production of, crude oil, bitumen, natural gas and NGL (“Exploration and Production”) and the marketing of the Company’s and other producers’ crude oil, natural gas, NGL, sulphur and petroleum coke. Additionally, it includes pipeline transportation, the blending of crude oil and natural gas, and storage of crude oil, diluent and natural gas (“Infrastructure and Marketing”). Infrastructure and Marketing markets and distributes products to customers on behalf of Exploration and Production and is grouped in the Upstream business segment based on the nature of its interconnected operations. The Company’s Upstream operations are located primarily in western Canada, offshore the east coast of Canada (“Atlantic”) and offshore China and Indonesia (“Asia Pacific”) (Atlantic and Asia Pacific collectively, “Offshore”).

Downstream operations in Canada include upgrading of heavy crude oil feedstock into synthetic crude oil (“Upgrading”), refining crude oil, marketing of refined petroleum products including gasoline, diesel, ethanol blended fuels, asphalt and ancillary products, and production of ethanol (“Canadian Refined Products”). It also includes refining of crude oil in the U.S. to produce and market diesel fuels, gasoline, jet fuel and asphalt (“U.S. Refining and Marketing”). Upgrading, Canadian Refined Products and U.S. Refining and Marketing all process and refine natural resources into marketable products and are grouped together as the Downstream business segment due to the similar nature of their products and services.

Corporate Strategy

The Company’s business strategy is to focus on returns from investment in a deep portfolio of opportunities that can generate increased cash flow from operating activities and funds from operations.

The Company has two main businesses: (i) an integrated Canada-U.S. Upstream and Downstream corridor ( “Integrated Corridor”); and (ii) production located Offshore.

Integrated Corridor

The Company’s business in the Integrated Corridor includes crude oil, bitumen, natural gas and NGL production from Western Canada, the Lloydminster upgrading and asphalt refining complex, HMLP (35 percent working interest and operatorship), and the Lima Refinery, BP-Husky Toledo Refinery (50 percent working interest) and Superior Refinery in the U.S. midwest. Natural gas production from the Western Canada portfolio is closely aligned with the Company’s energy requirements for refining and thermal bitumen production and acts as a natural hedge.

Offshore

The Company’s Offshore business includes operations, development and exploration in Atlantic and Asia Pacific. Each area generates high-netback production, with near and long-term investment potential.

Upstream Operations

Integrated Corridor

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 percent 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 Husky Lloydminster Asphalt Refinery, the Upgrader and the Company’s other assets in its Upstream Infrastructure and Marketing and its Downstream business segments, thus providing full integration.

Production of heavy crude oil and bitumen from the Lloydminister area uses a variety of technologies, including thermal SAGD, cold heavy oil production with sand (“CHOPS”), horizontal wells, waterflooded fields and non-thermal enhanced oil recovery (“EOR”).

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Lloydminster Thermal Projects

Lloydminster bitumen production consists of 10 thermal plants located in the Lloydminster region of Saskatchewan: Bolney/Celtic, Edam East, Edam West, Paradise Hill, Pikes Peak, Pikes Peak South, Rush Lake 1 & 2, Sandall and Vawn. Each plant has a number of production pads and utilizes SAGD technology. Production in 2018 from Lloydminster thermal projects averaged 76,800 bbls/day.

The Company is phasing execution of its long-life thermal projects to optimize capital efficiency and project execution. In 2018, the Company completed two land deals to create two Thermal hubs, one at Spruce Lake, and one at Dee Valley. This has resulted in the expectation that the Edam Central project will be completed in 2022 rather than the previously disclosed timeframe of late 2021, and in Westhazel being reprioritized.

The following table shows major projects and their status as at December 31, 2018:

Project Name	Estimated Production (bbls/day)	Expected Project Production Date	Project Status
Rush Lake 2	10,000	First quarter of 2019	Completed ahead of schedule with first production achieved in October 2018 and nameplate capacity of 10,000 bbls/day reached in November 2018.
Dee Valley	10,000	Fourth quarter of 2019	Work continued, with drilling of the second well pad completed and construction of the Central Processing Facility (“CPF”) continuing ahead of schedule. As of the end of 2018, the CPF was 80 percent complete.
Spruce Lake Central	10,000	2020	Construction of the CPF commenced in 2018.
Spruce Lake North	10,000	Around the end of 2020	Site clearing was completed in 2018.
Spruce Lake East	10,000	Around the end of 2021	Sanctioned in November 2018, with regulatory approval received in 2019.
			Prioritized ahead of Westhazel.
Edam Central	10,000	2022	Regulatory permit was received in early January 2019.
Dee Valley 2	10,000	2023	Regulatory applications were submitted in 2018, with approval expected in 2019.
Westhazel	10,000	Reprioritized	Regulatory applications were submitted in 2018, with approval expected in 2019.
			Reprioritized in order to optimize thermal sequence.

In February 2019, the Pike’s Peak thermal bitumen plant was closed down as it reached the end of its useful life. The plant achieved first production in September 1981 and produced 78 mmbbls over its useful life.

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.

Work to debottleneck the CPF and field was completed in the third quarter of 2018. Subsequently, production ramped up and nameplate capacity of 30,000 bbls/day was achieved in October 2018. Bitumen production for 2018 averaged 22,400 bbls/day, with fourth quarter production following the debottleneck averaging 25,200 bbls/day.

Production in 2019 is expected to be impacted by government-mandated production curtailment in Alberta. While specific volume reductions are uncertain, production in the first quarter of 2019 could be impacted by as much as 5,000 bbls/day.

Cold and EOR

In 2018, the Company sanctioned a full field polymer injection project at Aberfeldy with opportunities to expand to other areas.

During 2018, the Company operated five carbon dioxide (“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 several types of CO₂ capture technology at its Lashburn facility in Saskatchewan.

Production in 2019 is expected to be impacted by government-mandated production curtailment in Alberta.

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Sunrise Energy Project

On March 31, 2008, Husky and BP Corporation North America Inc. (“BP”) 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.

The Sunrise Energy Project is a SAGD oil sands project located in the Athabasca region of northern Alberta. During the fourth quarter of 2018, maintenance activities were completed and the project reached its nameplate capacity of 60,000 bbls/day.

At the end of 2018, there were 81 producing well pairs. In 2018, bitumen production averaged approximately 50,000 bbls/day (25,000 bbls/day Husky working interest).

Production in 2019 is expected to be impacted by government-mandated production curtailment in Alberta. While specific volume reductions are uncertain, production in the first quarter of 2019 could be impacted by as much as 15,000 bbls/day (7,500 bbls/day Husky working interest).

Western Canada

Northern Operations

The Company’s Northern operations are located primarily in western Alberta. Primary areas of operations include Edson and Grande Prairie, where operations are centered on a liquids-rich gas resource growth strategy.

Within its Northern operations, production in 2018 consisted of approximately 1,300 bbls/day of light crude oil, 4,800 bbls/day of NGL and 179.6 mmcf/day of natural gas. The area is heavily weighted towards natural gas production at approximately 84 percent. The Company is pursuing liquids-rich natural gas development opportunities within the existing asset portfolio primarily in the Ansell and Kakwa areas.

The Kakwa Spirit River liquids-rich natural gas resource play, in which 2018 production averaged 5,900 boe/day, is located south of Grande Prairie. The Company drilled 10 wells in 2018, and completed nine wells with eight wells on production by the end of 2018.

Edson operations are located primarily in northern Alberta and consist of the Ansell and Galloway areas. The Ansell liquids-rich natural gas resource play is located in the deep basin Cretaceous formations of west-central Alberta, with the Company holding an average 95 percent 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 2018 averaged 2,300 bbls/day of NGL and 131.8 mmcf/day of natural gas. The Company operates over 400 producing wells at Ansell including 65 Spirit River horizontal wells and 20 Cardium horizontal wells. In 2018, the Company drilled 11 horizontal wells and completed 13 horizontal wells with 11 wells on production at the end of 2018. The Company also participated in three non-operated wells.

A drilling program targeting the oil and liquids-rich natural gas Montney Formation in the Wembley and Karr areas is continuing with seven wells drilled in 2018 and six completed.

Resource oil development is focused on the Cardium oil play in the Wapiti area south of the city of Grand Prairie, Alberta, utilizing horizontal well and multi-stage fracturing technology to unlock crude oil reserves. During 2018, production from the Cardium play averaged 2,500 boe/day. A two well drilling program was completed in 2018 with six wells completed and on production. In addition, the Company participated in two non-operated wells.

In 2018, the Company participated in a 12-well non-operated Viking program in the North Blackstone area, which continued into 2019.

Southern Operations

The Company’s Southern operations are located in central Alberta and southwest Saskatchewan. As at December 31, 2018, the Company operated one crude oil and four natural gas facilities with approximately 400 active wells throughout the area. Production in 2018 averaged 1,000 bbls/day of crude oil, 2,000 bbls/day of NGL and 36.7 mmcf/day of natural gas.

Rainbow Lake Development

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 2018 from the Rainbow Lake Development operations averaged 5,200 bbls/day of light crude oil, 5,200 bbls/day of NGL and 55.1 mmcf/day of natural gas. The Company initiated an 11-well Muskeg oil appraisal program in 2018 with four wells on production at year end.

The Company holds a 50 percent 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.

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Northwest Territories

The Company held two exploration licenses (“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. Summer work in 2018 in the Slater River area included annual inspections of the two suspended wells and maintenance on the existing infrastructure. In the fourth quarter of 2018, the Company commenced operations that included abandonment of the two pilot wells, reclamation of the well sites, and remediation and maintenance of infrastructure. This program will continue into 2019.

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 percent working interest in the Liwan 3-1 and Liuhua 34-2 fields and a 75 percent working interest in the Liuhua 29-1 field, and CNOOC has 51 and 25 percent 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 deepwater operator and CNOOC acting as shallow water operator. The deepwater infrastructure includes production wells and trees, subsea pipelines and manifolds that produce to twin 22-inch deepwater pipelines running approximately 78 kilometres to a shallow water central platform. The shallow water infrastructure includes the central platform standing in approximately 120 metres of water, a 261-kilometre shallow water pipeline running from the central platform to the onshore Gaolan Gas Plant, which has liquids separation facilities, 10 spherical NGL storage tanks, an export jetty, control facilities 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.

In 2018, total gas sales from Liwan 3-1 and Liuhua 34-2 averaged 341 mmcf/day and 36 mmcf/day, respectively. In 2018, the Company’s working interest share of production from the two fields was 185 mmcf/day of conventional natural gas and 8,400 bbls/day of NGL.

Construction continues at Liuhua 29-1, the third deepwater gas field of the Liwan Gas Project. All of the major contracts have been executed and detailed design work is underway. The Environment Impact Assessment was approved by the Ministry of Ecology and Environment in January 2019. Drilling of the remaining three wells is expected to commence in the first quarter of 2019, which will add to the four previously drilled wells. First gas production from this seven-well development is expected around the end of 2020, with target production of 45 mmcf/day natural gas (Husky working interest) and 1,800 bbls/day NGL (Husky working interest) when fully ramped up.

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 percent. In the event of a commercial discovery, its partner CNOOC may assume a working interest of up to 51 percent during the development and production phase. Under the PSC, the corresponding CNOOC share of exploration costs is to be recovered from production allocated to the Company.

The Company is progressing commercial development plans following the successful drilling and testing of exploration well XJ 34-3-2.

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 to100 metres. The Company is the operator of the block during the exploration phase, with a working interest of 100 percent. In the event of a commercial discovery, its partner CNOOC may assume a working interest of up to 51 percent during the development and production phase. Under the PSC, the corresponding CNOOC share of exploration costs is to be recovered from production allocated to the Company.

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The Company drilled one exploration well in the third quarter of 2018, which encountered non-commercial hydrocarbons. Additional evaluation work is being conducted and a second exploration well may be drilled in the 2020 timeframe.

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 percent during the exploration phase. In the event of a commercial discovery, its partner CNOOC may assume a participating partnership interest of up to 51 percent in either or both blocks for the development and production phases.

Taiwan

In December 2012, the Company signed a joint venture agreement with CPC Corporation. 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 percent working interest during exploration, while CPC Corporation has the right to participate in the development program up to a 50 percent 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. The Company is analyzing the 3-D seismic survey data to identify potential drilling prospects.

Indonesia

Madura Strait

The Company has a 40 percent interest in approximately 622,000 acres (2,516 square kilometres) of the Madura Strait, located offshore East Java, in Indonesia. The Company’s two partners are CNOOC, which is the operator and has a 40 percent working interest, and Samudra Energy Ltd., which holds the remaining 20 percent interest through its affiliate, SMS Development Ltd. The Madura Strait includes the operating BD field and developments at the MDA, MBH, MDK and MAC fields and three additional discoveries.

In 2018 at the liquids-rich BD field, total gas sales ramped up to the full sales production target of 100 mmcf/day of gas and 6,000 bbls/day of associated liquids. Total BD field sales averaged 78 mmcf/day of gas and 6,200 bbls/day of associated liquids in 2018. The Company’s working interest share of production was 31 mmcf/day of gas and 2,500 bbls/day of associated liquids.

At the MDA and MBH fields, the two shallow water platforms have been fully installed and preparations are underway to drill the five MDA and two MBH field production wells in 2019. Gas production and sales are expected to start in the 2020 timeframe, following completion of the Floating Production Unit (“FPU”) which will be used to process and compress the gas. Subsequently, an additional shallow water field, named MDK, is scheduled to be developed and tied into the FPU. 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 with set prices that include escalation factors.

Pre-engineering activities and approvals progressed at the MAC field, where an approved Plan of Development is in place. Additional discoveries in the region are being evaluated for potential development.

Anugerah

The Company executed a PSC in February 2014 with the Government of Indonesia for the Anugerah contract area. The Company holds a 100 percent 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 acquired 2-D seismic survey 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 offset block information indicates that drilling is not economic and the block will be relinquished.

Atlantic

Overview

The Company’s Atlantic exploration and development program is focused in the Jeanne d’Arc Basin and the Flemish Pass. 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 percent 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.

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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 percent working interest in the main field and a 68.875 percent working interest in the satellite extensions. To date, production has been facilitated via subsea tie-ins with wells drilled independently through drill centres and connected via flowlines to the SeaRose FPSO.

First oil was achieved at White Rose in November 2005. The White Rose field currently has 11 production wells, 10 water injection wells and three gas injection wells. During 2018, the Company’s light crude oil production from the White Rose field was 6,400 bbls/ day (Husky working interest).

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. In September 2016, the Company began production from the deeper Hibernia formation at North Amethyst utilizing existing infrastructure. As of December 31, 2018, the field had eight production wells and four water injection wells. During 2018, light crude oil production from North Amethyst was 3,400 bbls/day (Husky working interest).

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 2018, light crude oil production from this satellite field was 800 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. The South White Rose Extension was developed in phases, with gas injection equipment installed in 2013 and oil production equipment installed in 2014. As at December 31, 2018, the project had three production wells, one water injection well and one gas injection well. During 2018, light crude oil production from the South White Rose Extension was 6,800 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. First oil is forecasted for 2022, with the West White Rose Project expected to ramp up to peak production of 52,500 bbls/day (Husky working interest) in 2025 as development wells are brought online. Like the other White Rose tiebacks, the platform will leverage existing offshore infrastructure including the SeaRose FPSO. 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. The accommodations module is progressing well in Marystown, NL and construction of the platform’s Concrete Gravity Structure (“CGS”) advanced in a purpose-built graving dock in Argentia, NL. The CGS was poured to a height of 46 metres during the 2018 construction season. Concrete works will continue in 2019.

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.

In late January 2019, the Company began a staged ramp-up production at the White Rose field. The field had been shut-in since mid-November, after a flowline connector failed near the South White Rose Extension, causing a spill of approximately 250 cubic metres of oil. The Company and its certifying authority have completed inspections of the SeaRose FPSO vessel as well as subsea infrastructure. Regulatory approval has been received for plans to recover the damaged flowline connector. An investigation into the cause of the incident is underway.

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 percent effective December 1, 2010.

As at December 31, 2018, there were 14 development wells drilled in the Graben area, consisting of eight 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. The operator continues to progress delineation and development opportunities at Terra Nova.

Light crude oil production during 2018 from the Terra Nova field was 4,000 bbls/day (Husky working interest).

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East Coast Exploration

The Company holds working interests ranging from 5.8 percent to 100 percent in 22 Significant Discovery Areas in the Jeanne d’Arc Basin and Flemish Pass Basin, offshore NL and Baffin Island.

In May 2018, the Company announced a near-field oil discovery at the White Rose A-24 exploration well, located approximately 10 kilometres north of the SeaRose FPSO. The well encountered more than 85 metres of oil-bearing sandstone. Additional delineation in the region is planned. The Company has a 68.875 percent ownership interest, with partners Suncor Energy and Nalcor Energy Oil and Gas holding 26.125 percent and five percent, respectively.

The Company continues to evaluate the results of a 2017 discovery at Northwest White Rose. The White Rose A-78 well was drilled approximately 11 kilometres northwest of the SeaRose FPSO in the first quarter of 2017 and delineated a light oil column of more than 100 metres. Husky has a 93.232 percent ownership interest.

Potential development of the A-24 and A-78 regions could leverage the SeaRose FPSO, existing subsea infrastructure and the future West White Rose platform.

The Company and its partner continue to assess potential development of Bay du Nord and other discoveries in the Flemish Pass Basin. A benefits framework agreement was reached with the Government of Newfoundland and Labrador in July 2018, based on an FPSO-based development concept to produce resources at Bay du Nord and Bay de Verde. Technological and commercial evaluations continue. The Company holds a 35 percent non-operated working interest in the Bay du Nord, Bay de Verde, Baccalieu, Harpoon and Mizzen discoveries.

The Company is a non-operating partner in two ELs awarded in the November 2018 C-NLOPB land sale. The ELs are adjacent to Terra Nova and White Rose in the Jeanne d’Arc Basin and will bring the Company’s total licence holdings in the region to nine.

Infrastructure and Marketing

Overview

The Company is engaged in the marketing of both its own and other producers’ crude oil, natural gas, NGL, sulphur and petroleum coke production. The Infrastructure and Marketing business manages the sale and transportation of the Company’s Upstream and Downstream production and third-party commodity trading volumes through access to capacity on third-party pipelines and storage facilities in both Canada and the U.S. The Company is able to capture 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.

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 owns 16.25 percent, PAH owns 48.75 percent and Husky owns 35 percent of HMLP and is the operator. HMLP has approximately 2,200 kilometres of pipeline in the Lloydminster region, 4.1 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 Husky’s Upgrader and Asphalt Refinery in Lloydminster. 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 3.4 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 a separate Board of Directors from Husky and independent financing that supports both significant growth projects that are under construction and forecasted future expansions. Approximately $800 million in growth projects are underway. HMLP is in the process of diversifying its operations beyond the Lloydminster and Hardisty area and has commenced construction of the Ansell Corser Gas Plant, which is expected to add 120 mmcf/day of processing capacity when it comes online in the fourth quarter of 2019.

Husky Energy Inc. | Annual Information Form 2018 | 16

In 2018, HMLP commissioned a 150-kilometre pipeline system in Alberta to allow for third-party and Husky production growth. A second major pipeline project is underway in Saskatchewan to provide transportation for the anticipated increase in the Company’s bitumen production. The Hardisty terminal is also expanding to provide additional pipeline connectivity and crude oil storage for customers. The assets will play an integral and valuable role in the successful transportation of heavy oil and bitumen production to end markets by providing connections to the Husky Lloydminster Upgrader and Asphalt Refinery, third-party terminals and pipelines through strategic hubs such as the Hardisty Terminal.

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 midwest U.S. This strategy was further supported through the acquisition of the Lima Refinery in 2007, which enabled the Company’s Canadian synthetic 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 bitumen 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 bbls/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.

The Company has been monitoring opportunities to participate in growing crude oil markets accessed by rail, which have developed due to refiners’ desire for inland crude oil which has at times been priced at significant discounts to ocean imports. The Company has made crude oil deliveries to rail-loading facilities via trucks, where netbacks can be increased relative to pipeline alternatives. While the Company’s primary focus is on low-cost pipeline transportation options, it has developed the capability to employ rail transport to a variety of crude oil markets.

In December of 2018, the Government of Alberta imposed an oil production curtailment order with the goal of raising the price of oil sold in Alberta during 2019. This reduced the economic motivation to export crude by rail or develop longer term market access strategies.

Natural Gas Storage Facilities

The Company has operated a 25 bcf natural gas storage facility at Hussar, Alberta since 2000.

Commodity Marketing

The Company has developed its commodity marketing operations to include the acquisition of third-party volumes to enhance the value of its midstream 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 and Wisconsin refineries. The Company supplies feedstock to its Lloydminster 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 Prince George Refinery, the Lima Refinery and the Superior Refinery. The Company supplies a portion of the synthetic crude oil produced at its Upgrader in Lloydminster to the Lima and Superior refineries, and markets the rest to refiners in Canada and the U.S.

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.

Husky Energy Inc. | Annual Information Form 2018 | 17

Downstream Operations

Upgrading Operations

The Company owns and operates the Upgrader, a heavy oil upgrading facility located in Lloydminster, Saskatchewan. 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 recover 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 80,500 bbls/ day of synthetic crude oil, diluent and ultra low sulphur diesel.

Production at the Upgrader averaged 53,800 bbls/day of synthetic crude oil, 15,600 bbls/day of diluent and 6,200 bbls/day of ultra low sulphur diesel in 2018. In addition, as by-products of its upgrading operations, the Upgrader produced approximately 355 long ton/day of sulphur and 1,005 long ton/day of petroleum coke during 2018. These products are sold in Canadian and international markets.

Canadian Refined Products

The Company’s Canadian Refined Products operations include refining of light crude oil, manufacturing of fuel and fuel grade ethanol, manufacturing of asphalt products from heavy crude oil and bitumen and acquisition by purchase and exchange of refined petroleum products. The Company’s retail distribution network includes the wholesale, commercial and retail marketing of refined petroleum products and provides a platform for non-fuel related convenience product businesses.

Light oil refined products are produced at the Prince George Refinery and are also acquired from third-party refiners and marketed through the Company’s retail and commercial petroleum outlets and through direct marketing to third-party dealers and end users. Asphalt and residual products are produced at the Company’s Asphalt Refinery at Lloydminster, Alberta and are marketed directly or through the Company’s eight terminals located in western Canada and the U.S. midwest.

Lloydminster Asphalt Refinery

Husky’s Asphalt Refinery in Lloydminster, Alberta processes heavy crude oil and bitumen into asphalt products used in road construction and maintenance. The refinery has a throughput capacity of 29,000 bbls/day of heavy crude oil and bitumen. The refinery also produces straight run gasoline, bulk distillates and residuals. 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. Residuals 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 27,100 bbls/day of blended heavy crude oil and bitumen feedstock during 2018. 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 Lloydminster Asphalt Refinery to run at or near full capacity throughout the year.

Asphalt Distribution Network

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

In 2019, the Company plans to increase asphalt modification capacity, expand sales in U.S. markets and further market residual products as refinery feedstock.

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 and both plants are currently operating above that capacity due to efforts to optimize yield. In 2018, ethanol production averaged 819.4 thousand 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 Energy Inc. | Annual Information Form 2018 | 18

Prince George Refinery

The Prince George Refinery provides refined products to the Company and third-party retail outlets in the central and northern regions of British Columbia. Feedstock is delivered to the refinery by pipeline from northeastern British Columbia. The refinery has a throughput capacity of 12,000 bbls/day.

The Prince George Refinery produces all grades of unleaded gasoline, seasonal diesel fuels, mixed propane and butane and heavy fuel oil. During 2018, throughput averaged 10,700 bbls/day.

On January 8, 2019, the Company announced its intention to market and potentially sell the Prince George Refinery.

Other Supply Arrangements

During 2018, the Company purchased approximately 28,200 bbls/day of refined petroleum products of which 27,200 bbls/day were from the agreement with Imperial Oil. The Company also acquired approximately 7,600 bbls/day of refined petroleum products pursuant to exchange agreements with third-party refiners in addition to Imperial Oil.

Retail and Commercial Network

During 2015, the Company and Imperial Oil entered into a contractual agreement to create a single expanded truck transport cardlock network of approximately 160 sites. The agreement has been fully implemented, and the consolidation of the two cardlock networks, under the Esso brand, was completed in the third quarter of 2017.

As at December 31, 2018, there were 554 independently operated Husky and Esso-branded petroleum product outlets. These outlets include travel centres, convenience stores, cardlock and bulk distribution facilities located from coast to coast. The Company’s network of travel centres features a proprietary cardlock system that enables commercial customers to purchase products using a card system that processes transactions, provides detailed billing, fuel and sales tax information and offers advanced fraud protection. A variety of full and self-serve retail locations serve urban and rural markets across the network, while the Company’s bulk distributors offer direct sales to commercial and agricultural markets in the Prairie provinces.

The Company’s retail and commercial operating model is balanced by corporate-owned/dealer-operated and branded dealer owned and operated sites. 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 offers 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.

On January 8, 2019, the Company announced its intention to market and potentially sell its Retail and Commercial Network.

The following table shows the number of Husky and Esso-branded petroleum outlets by province as of December 31, 2018:

	British Columbia		Alberta		Saskatchewan		Manitoba		Ontario		Quebec		New Brunswick		2018 Total		2017 Total
Husky-Branded
Petroleum Outlets
Retail Owned Outlets		40		46		8		13		58		—		—		165		163
Leased		32		30		3		7		25		—		—		97		99
Independent Retailers		48		61		11		3		13		—		—		136		140
Total		120		137		22		23		96		—		—		398		402
Esso-Branded
Petroleum Outlets
Retail Owned Outlets		14		15		4		3		12		—		—		48		48
Leased		2		2		—		3		1		—		—		8		8
Independent Retailers		32		23		4		6		27		7		1		100		100
Total		48		40		8		12		40		7		1		156		156
Cardlocks(1)		49		45		9		11		40		7		1		162		167
Convenience Stores(1)		82		85		14		21		94		—		—		296		296
Restaurants		8		9		3		1		13		—		—		34		34

⁽¹⁾  Located at branded petroleum outlets.

Husky Energy Inc. | Annual Information Form 2018 | 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)	2018		2017		2016
Gasoline		21.7		22.3		22.4
Diesel fuel		26.5		22.8		18.5
Liquefied Petroleum Gas		0.2		0.2		0.2
		48.4		45.3		41.1

U.S. Refining and Marketing

Lima Refinery

The Lima Refinery has a crude oil throughput capacity, depending on crude slate, of up to 175,000 bbls/day. The Lima Refinery currently processes both light sweet crude oil and a small percentage of 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 2018, total production throughput at the Lima Refinery averaged 171,000 bbls/day excluding days for turnaround. Production excluding days for turnaround consisted of gasoline averaging 84,000 bbls/day, total distillates averaging 66,000 bbls/day and total other products averaging 21,000 bbls/day.

In 2016, the Company completed the first stage of the crude oil flexibility project and the refinery is now able to process up to 10,000 bbls/day of heavy crude oil feedstock. The project is designed to allow for the processing of up to 40,000 bbls/day of heavy crude oil from western Canada when completed, providing the ability to swing between light and heavy crude oil feedstock.

The timing of completion for the crude oil flexibility project is late 2019. This schedule coordinates project work with normal maintenance to provide higher levels of sustained production.

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 product.

During 2018, the Company’s share of total throughput averaged 73,200 bbls/day, with the Company’s share of production of gasoline averaging 42,600 bbls/day, distillates averaging 21,400 bbls/day and other fuel and feedstock averaging 9,100 bbls/day.

Superior Refinery

On November 8, 2017, the Company completed the acquisition of the Superior Refinery, which has a permitted throughput capacity of 50,000 bbls/day and an operating capacity of 45,000 bbls/day on its current crude slate. The refinery produces motor fuel products and asphalt from light and heavy crude oil originating from North Dakota and western Canada.

The refinery is responsible for the oversight of 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 refinery experienced an incident while preparing for a major turnaround. Operations at the refinery remain suspended. An engineering contractor has been appointed to oversee design work and rebuild of the refinery. The rebuild will commence once design work is complete and permits are obtained. Operations are expected to resume in 2020.

Husky Energy Inc. | Annual Information Form 2018 | 20

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, 2018		Dec 31, 2018			Sept 30, 2018		June 30, 2018		Mar 31, 2018
Company Total(2)
Sales volume (mboe/day)		299.2		304.3			296.7		295.5		300.4
Gross Revenue ($/boe)(3)	$	41.50	$	25.47		$	50.44	$	49.74	$	40.87
Royalties ($/boe)	$	3.30	$	2.08		$	4.24	$	3.98	$	2.98
Production and Operating Costs ($/boe)(3)	$	14.00	$	13.75		$	14.68	$	14.22	$	13.33
Transportation Costs ($/boe)(4)	$	0.22	$	0.22		$	0.22	$	0.23	$	0.19
Operating netback ($/boe)	$	23.98	$	9.42		$	31.30	$	31.31	$	24.37
Light and Medium Crude Oil ($/bbl)
Canada - Western Canada
Gross Revenue(3)	$	55.71	$	28.75		$	69.09	$	70.51	$	55.20
Royalties	$	8.70	$	4.97		$	12.75	$	9.08	$	7.86
Production and Operating Costs(3)	$	29.90	$	27.22		$	30.56	$	32.82	$	29.16
Operating netback	$	17.11	($	3.44	)	$	25.78	$	28.61	$	18.18
Canada - Atlantic Canada
Gross Revenue	$	95.97	$	83.41		$	104.08	$	101.67	$	90.70
Royalties	$	7.90	$	7.35		$	7.89	$	10.92	$	5.94
Production and Operating Costs	$	27.21	$	47.76		$	25.22	$	29.65	$	17.51
Transportation Costs(4)	$	3.01	$	5.11		$	2.77	$	3.31	$	2.02
Operating netback	$	57.85	$	23.19		$	68.20	$	57.79	$	65.23
Canada - Total
Gross Revenue(3)	$	83.71	$	60.19		$	93.84	$	92.23	$	82.08
Royalties	$	8.15	$	6.34		$	9.31	$	10.36	$	6.41
Production and Operating Costs(3)	$	28.03	$	39.03		$	26.79	$	30.61	$	20.34
Transportation Costs(4)	$	2.09	$	2.94		$	1.96	$	2.31	$	1.53
Operating netback	$	45.44	$	11.88		$	55.78	$	48.95	$	53.80
Heavy Crude Oil ($/bbl)
Canada - Total
Gross Revenue(3)	$	39.26	$	18.71		$	50.09	$	54.22	$	32.80
Royalties	$	3.89	$	1.32		$	5.70	$	5.49	$	2.89
Production and Operating Costs(3)	$	27.96	$	30.00		$	30.77	$	25.61	$	25.96
Operating netback	$	7.41	($	12.61	)	$	13.62	$	23.12	$	3.95
Bitumen ($/bbl)
Canada - Total
Gross Revenue(3)(4)	$	30.17	$	5.42		$	46.00	$	44.41	$	27.77
Royalties	$	2.09	$	0.56		$	3.33	$	2.73	$	1.95
Production and Operating Costs(3)	$	11.43	$	11.09		$	12.04	$	11.10	$	11.54
Operating netback	$	16.65	($	6.23	)	$	30.63	$	30.58	$	14.28

Husky Energy Inc. | Annual Information Form 2018 | 21

	Year Ended			Three Months Ended
Average Per Unit Amounts	Dec 31, 2018			Dec 31, 2018			Sept 30, 2018			June 30, 2018			Mar 31, 2018
Conventional Natural Gas ($/mcf)
Canada - Total
Gross Revenue(3)(5)	$	1.79		$	1.94		$	1.38		$	1.49		$	2.38
Royalties(5)(6)	($	0.12	)	($	0.05	)	($	0.09	)	($	0.17	)	($	0.16	)
Production and Operating Costs(3)	$	1.70		$	1.37		$	1.83		$	1.92		$	1.69
Operating netback	$	0.21		$	0.62		($	0.36	)	($	0.26	)	$	0.85
China
Gross Revenue	$	13.73		$	13.85		$	13.14		$	13.96		$	13.95
Royalties	$	0.80		$	0.86		$	0.76		$	0.82		$	0.74
Production and Operating Costs	$	0.77		$	0.66		$	0.81		$	0.89		$	0.71
Operating netback	$	12.16		$	12.33		$	11.57		$	12.25		$	12.50
Indonesia(7)
Gross Revenue	$	9.81		$	9.76		$	9.79		$	9.82		$	9.85
Royalties	$	1.07		$	1.09		$	1.07		$	1.07		$	1.02
Production and Operating Costs	$	1.67		$	1.77		$	1.66		$	1.37		$	1.98
Operating netback	$	7.07		$	6.90		$	7.06		$	7.38		$	6.85
Total
Gross Revenue(3)	$	6.64		$	6.86		$	6.15		$	6.53		$	7.03
Royalties	$	0.29		$	0.36		$	0.30		$	0.26		$	0.23
Production and Operating Costs(3)	$	1.36		$	1.14		$	1.46		$	1.51		$	1.33
Operating netback	$	4.99		$	5.36		$	4.39		$	4.76		$	5.47
Natural Gas Liquids ($/bbl)
Canada - Total
Gross Revenue(3)	$	35.71		$	31.65		$	36.37		$	36.54		$	38.76
Royalties	$	9.58		$	7.13		$	8.43		$	10.83		$	12.26
Production and Operating Costs(3)	$	9.97		$	7.82		$	11.17		$	11.28		$	9.72
Operating netback	$	16.16		$	16.70		$	16.77		$	14.43		$	16.78
China
Gross Revenue	$	72.77		$	69.76		$	76.13		$	71.88		$	73.60
Royalties	$	4.21		$	4.03		$	4.28		$	4.42		$	4.14
Production and Operating Costs	$	4.59		$	3.95		$	4.86		$	5.36		$	4.28
Operating netback	$	63.97		$	61.78		$	66.99		$	62.10		$	65.18
Indonesia(7)
Gross Revenue	$	95.67		$	96.83		$	95.61		$	98.37		$	87.53
Royalties	$	14.96		$	15.15		$	15.03		$	15.16		$	13.72
Production and Operating Costs	$	10.04		$	10.65		$	9.95		$	8.20		$	11.86
Operating netback	$	70.67		$	71.03		$	70.63		$	75.01		$	61.95
Total
Gross Revenue(3)	$	55.72		$	53.36		$	60.08		$	54.13		$	55.03
Royalties	$	8.19		$	6.88		$	8.13		$	8.90		$	9.08
Production and Operating Costs(3)	$	8.00		$	6.69		$	8.80		$	8.93		$	7.65
Operating netback	$	39.53		$	39.79		$	43.15		$	36.30		$	38.30

⁽¹⁾ The operating netback includes results from Upstream Exploration and Production and excludes results from Upstream Infrastructure and Marketing. 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 financial statement purposes.

Husky Energy Inc. | Annual Information Form 2018 | 22

Production History

	Year Ended		Three Months Ended
Average Gross Daily Production(1)	Dec 31, 2018		Dec 31, 2018		Sept 30, 2018		June 30, 2018		Mar 31, 2018
Canada - Western Canada
Light and Medium Crude Oil (mbbls/day)		9.4		9.6		9.9		9.0		9.1
Heavy Crude Oil (mbbls/day)		36.8		34.4		34.6		38.5		39.7
Bitumen (mbbls/day)		124.2		132.9		117.3		123.2		123.2
Conventional Natural Gas (mmcf/day)		291.0		302.6		297.6		285.0		278.7
NGL (mbbls/day)		12.0		12.7		11.9		12.3		11.3
Canada - Atlantic
Light and Medium Crude Oil (mbbls/day)		21.4		13.0		23.8		20.7		28.4
China - Asia Pacific(2)
Conventional Natural Gas (mmcf/day)		184.8		197.0		181.9		180.3		179.7
NGL (mbbls/day)		8.4		9.3		8.4		7.7		8.2
Indonesia - Asia Pacific(3)
Conventional Natural Gas (mmcf/day)		31.2		38.0		40.0		28.7		18.6
NGL (mbbls/day)		2.5		2.8		4.2		1.8		1.0
Total Gross Production (mboe/day)		299.2		304.3		296.7		295.5		300.4

⁽¹⁾ Total production volumes for 2018, for each product type, are set forth in the Reconciliation of Gross Proved Plus Probable Reserves table.

⁽²⁾ Reported production volumes include Husky’s working interest production from the Liwan Gas Project (49 percent).

⁽³⁾ Reported production volumes include Husky’s working interest production from the BD Project (40 percent). 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				Natural Gas Wells				Total
Producing Wells	Gross		Net		Gross		Net		Gross		Net
Canada
Alberta		1,712		1,507		1,975		1,406		3,687		2,913
Saskatchewan		2,678		2,596		88		86		2,766		2,682
British Columbia		—		—		121		121		121		121
Newfoundland		22		6		—		—		22		6
		4,412		4,109		2,184		1,613		6,596		5,722
International
China		—		—		10		5		10		5
Indonesia		—		—		4		2		4		2
		—		—		14		7		14		7
As at December 31, 2018		4,412		4,109		2,198		1,620		6,610		5,729
	Oil Wells				Natural Gas Wells				Total
Non-Producing Wells	Gross		Net		Gross		Net		Gross		Net
Canada
Alberta		1,733		1,598		1,159		931		2,892		2,529
Saskatchewan		4,100		3,937		213		192		4,313		4,129
British Columbia		—		—		11		9		11		9
As at December 31, 2018		5,833		5,535		1,383		1,132		7,216		6,667

⁽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, 2018.

⁽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, 2018, the Company had a royalty interest in 885 wells, of which 481 were oil producers and 404 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 2018, there were 1,054 gross and 952 net oil wells and 92 gross and 78 net natural gas wells that were completed in two or more formations and from which production is not commingled.

Husky Energy Inc. | Annual Information Form 2018 | 23

Of the 16 mmboe of Proved Developed Non-Producing reserves as of year-end 2018, approximately 10 mmboe are associated with wells drilled in 2018 that will be placed on production in 2019 and 2020. The remaining volumes are associated with 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		3,340		2,819
Saskatchewan		628		609
British Columbia		201		160
		4,169		3,588
Northwest Territories and Arctic		552		521
Atlantic		2,058		1,094
		6,779		5,203
China		787		776
Indonesia		2,033		1,664
Taiwan		1,904		1,428
As at December 31, 2018		11,504		9,071

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, 2018, over the next 12 months, development rights to approximately 247 thousand net acres, or less than seven percent, of the Company’s net unproved acreage in Western Canada will be subject to expiry.

As at December 31, 2018, over the next 12 months, development rights to the 1,428 thousand net acres in Taiwan are subject to expiry. The Company is analyzing the 3-D survey from 2017 to identify potential drilling prospects and is evaluating options to extend the expiry to beyond 2019 or proceed to the exploration phase.

The Company has commitments totaling approximately $69 million related to exploration to be completed in Atlantic between 2022 and 2023. Not fulfilling commitments on a timely basis commonly triggers forfeiture of security deposits of 25 percent of unfulfilled commitments.

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 2018 | 24

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 16 of the Company’s audited consolidated financial statements for the year ended December 31, 2018.

Drilling Activity - Number of Wells Drilled

	Year Ended December 31, 2018
	Western Canada				Atlantic			China				Indonesia
	Gross		Net		Gross	Net		Gross		Net		Gross	Net
Exploration
Oil		2.0		2.0	1.0		0.7		3.0		3.0	—		—
Gas		4.0		4.0	—		—		—		—	—		—
		6.0		6.0	1.0		0.7		3.0		3.0	—		—
Development
Oil		194.0		180.0	1.0		0.7		—		—	—		—
Gas		27.0		25.0	—		—		—		—	—		—
		221.0		205.0	1.0		0.7		—		—	—		—
		227.0		211.0	2.0		1.4		3.0		3.0	—		—
Stratigraphic Test Wells		15.0		13.0	—		—		—		—	—		—
Service Wells		—		—	—		—		—		—	—		—

Costs Incurred

($ millions)	Total		Western Canada		Atlantic		Total Canada		China		Indonesia(1)
Property acquisition - Unproven		11		11		—		11		—		—
Property acquisition - Proven		34		34		—		34		—		—
Exploration		245		110		72		182		63		—
Development		2,446		1,310		963		2,273		150		23
2018		2,736		1,465		1,035		2,500		213		23

⁽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 2018 | 25

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 Ltd. (“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. Sproule has also this year executed the Form 51-101F2 attached as Appendix B to this AIF.

The Audit Committee of the Board of Directors 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 of Directors 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 31, 2019 and an effective date of December 31, 2018 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 are reserves or production net of such royalties. 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 as issued by the International Accounting Standards Board. 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 thermal projects in Husky’s Lloydminster area. These projects also contain heavy oil that is lighter and less viscous than typical bitumen.

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 or on the Company’s website at www.huskyenergy.com. The material differences 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 2018 | 26

Summary of Oil and Natural Gas Reserves

As at December 31, 2018

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		41.1		35.5		52.0		49.7		135.0		123.0		228.2		208.2
Developed Non-producing		0.6		0.5		0.7		0.6		6.8		6.3		8.0		7.4
Undeveloped		69.8		64.2		1.0		0.9		747.9		651.5		818.6		716.6
Total Proved		111.5		100.3		53.7		51.2		889.7		780.7		1,054.9		932.2
Probable		89.2		73.1		21.9		20.5		831.8		632.1		942.9		725.7
Total Proved Plus Probable		200.6		173.3		75.6		71.7		1,721.5		1,412.8		1,997.8		1,657.8

	Conventional Natural Gas (bcf)				Natural Gas Liquids (mmbbls)				Total (mmboe)
	Gross		Net		Gross		Net		Gross		Net
Proved
Developed Producing		771.0		674.0		37.0		27.1		393.7		347.6
Developed Non-producing		32.7		30.1		2.5		2.1		16.0		14.5
Undeveloped		484.5		454.5		6.9		6.0		906.3		798.4
Total Proved		1,288.1		1,158.6		46.3		35.2		1,315.9		1,160.5
Probable		462.9		425.9		10.7		8.4		1,030.7		805.1
Total Proved Plus Probable		1,751.0		1,584.5		57.0		43.7		2,346.7		1,965.6

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		376.1		356.2		12.8		12.1		75.5		71.5
Developed Non-producing		—		—		—		—		—		—
Undeveloped		153.6		150.3		5.5		5.4		31.1		30.5
Total Proved		529.6		506.5		18.3		17.5		106.6		101.9
Probable		109.0		103.2		4.1		3.9		22.2		21.1
Total Proved Plus Probable		638.7		609.7		22.4		21.4		128.8		123.0

Husky Energy Inc. | Annual Information Form 2018 | 27

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

—

—

—

—

—

—

—

—

	Conventional Natural Gas (bcf)				Natural Gas Liquids (mmbbls)				Total (mmboe)
	Gross		Net		Gross		Net		Gross		Net
Proved
Developed Producing		152.7		112.6		6.1		4.7		31.5		23.4
Developed Non-producing		—		—		—		—		—		—
Undeveloped		101.0		69.1		—		—		16.8		11.5
Total Proved		253.7		181.8		6.1		4.7		48.3		34.9
Probable		91.5		50.1		1.7		0.5		16.9		8.9
Total Proved Plus Probable		345.1		231.8		7.7		5.2		65.3		43.8

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		41.1		35.5		52.0		49.7		135.0		123.0		228.2		208.2
Developed Non-producing		0.6		0.5		0.7		0.6		6.8		6.3		8.0		7.4
Undeveloped		69.8		64.2		1.0		0.9		747.9		651.5		818.6		716.6
Total Proved		111.5		100.3		53.7		51.2		889.7		780.7		1,054.9		932.2
Probable		89.2		73.1		21.9		20.5		831.8		632.1		942.9		725.7
Total Proved Plus Probable		200.6		173.3		75.6		71.7		1,721.5		1,412.8		1,997.8		1,657.8

	Conventional Natural Gas (bcf)				Natural Gas Liquids (mmbbls)				Total (mmboe)
	Gross		Net		Gross		Net		Gross		Net
Proved
Developed Producing		1,299.7		1,142.8		55.8		43.9		500.7		442.5
Developed Non-producing		32.7		30.1		2.5		2.1		16.0		14.5
Undeveloped		739.1		674.0		12.4		11.4		954.2		840.4
Total Proved		2,071.4		1,846.8		70.7		57.4		1,470.8		1,297.4
Probable		663.4		579.2		16.4		12.8		1,069.9		835.0
Total Proved Plus Probable		2,734.8		2,426.0		87.1		70.2		2,540.7		2,132.4

Husky Energy Inc. | Annual Information Form 2018 | 28

Future Net Revenue Tables

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

As at December 31, 2018

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		321.4		3,483.6		3,694.7			3,510.8			3,273.1			10.63
Developed Non-producing(1)		(1,068.6	)	(559.3)		(334.4	)		(219.2	)		(153.6	)		(23.08	)
Undeveloped		19,758.6		9,137.0		5,067.3			2,930.0			1,628.8			6.35
Total Proved		19,011.3		12,061.3		8,427.6			6,221.6			4,748.3			7.26
Probable		35,304.5		15,561.8		9,098.9			6,081.8			4,375.9			11.30
Total Proved Plus Probable		54,315.8		27,623.1		17,526.5			12,303.5			9,124.2			8.92

⁽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		4,702.3		3,980.9		3,448.3		3,043.4		2,727.6		48.24
Developed Non-producing		—		—		—		—		—		—
Undeveloped		1,282.4		797.1		479.2		263.5		112.7		15.73
Total Proved		5,984.7		4,778.0		3,927.5		3,306.9		2,840.3		38.53
Probable		1,260.8		767.5		510.7		367.0		280.6		24.24
Total Proved Plus Probable		7,245.5		5,545.5		4,438.2		3,673.9		3,120.9		36.08

Indonesia

	Before Income Taxes and Discounted at (%/year)										Unit Value Discounted at 10%
($ millions)	0%		5%		10%		15%		20%		($/boe)
Proved
Developed Producing		602.0		501.5		428.8		374.6		333.0		18.30
Developed Non-producing		—		—		—		—		—		—
Undeveloped		348.4		284.1		234.5		195.4		164.0		20.35
Total Proved		950.4		785.6		663.3		570.0		497.1		18.98
Probable		416.5		270.5		183.2		128.6		93.1		20.68
Total Proved Plus Probable		1,366.9		1,056.1		846.5		698.6		590.2		19.32

Husky Energy Inc. | Annual Information Form 2018 | 29

Total

	Before Income Taxes and Discounted at (%/year)															Unit Value Discounted at 10%
($ millions)	0%			5%			10%			15%			20%			($/boe)
Proved
Developed Producing		5,625.7			7,965.9			7,571.9			6,928.9			6,333.7			17.11
Developed Non-producing(1)		(1,068.6	)		(559.3	)		(334.4	)		(219.2	)		(153.6	)		(23.08	)
Undeveloped		21,389.3			10,218.3			5,781.0			3,388.9			1,905.6			6.88
Total Proved		25,946.5			17,624.9			13,018.4			10,098.5			8,085.6			10.03
Probable		36,981.8			16,599.8			9,792.8			6,577.4			4,749.7			11.73
Total Proved Plus Probable		62,928.2			34,224.7			22,811.2			16,676.0			12,835.3			10.70

⁽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 2018 | 30

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

As at December 31, 2018

Forecast Prices and Costs

Canada

	After Income Taxes and Discounted at (%/year)
($ millions)	0%			5%			10%			15%			20%
Proved
Developed Producing		215.4			2,496.4			2,640.6			2,503.7			2,330.6
Developed Non-producing(1)		(780.1	)		(409.0	)		(245.3	)		(161.5	)		(113.9	)
Undeveloped		14,093.8			6,297.9			3,275.4			1,683.0			717.0
Total Proved		13,529.2			8,385.4			5,670.7			4,025.1			2,933.7
Probable		25,415.5			11,090.9			6,423.2			4,254.2			3,034.0
Total Proved Plus Probable		38,944.6			19,476.2			12,093.9			8,279.3			5,967.7

⁽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		3,523.8		2,984.1		2,585.9		2,283.5		2,047.7
Developed Non-producing		—		—		—		—		—
Undeveloped		955.6		566.7		310.7		136.4		14.3
Total Proved		4,479.4		3,550.8		2,896.6		2,419.9		2,062.0
Probable		945.2		575.4		382.9		275.2		210.6
Total Proved Plus Probable		5,424.5		4,126.1		3,279.5		2,695.1		2,272.5

Indonesia

	After Income Taxes and Discounted at (%/year)
($ millions)	0%		5%		10%		15%		20%
Proved
Developed Producing		465.8		399.7		350.3		312.3		282.3
Developed Non-producing		—		—		—		—		—
Undeveloped		252.3		206.6		170.9		142.5		119.5
Total Proved		718.1		606.3		521.2		454.8		401.9
Probable		251.6		162.5		109.2		75.8		54.1
Total Proved Plus Probable		969.7		768.8		630.4		530.7		456.0

Total

	After Income Taxes and Discounted at (%/year)
($ millions)	0%			5%			10%			15%			20%
Proved
Developed Producing		4,204.9			5,880.1			5,576.9			5,099.5			4,660.6
Developed Non-producing(1)		(780.1	)		(409.0	)		(245.3	)		(161.5	)		(113.9	)
Undeveloped		15,301.8			7,071.2			3,757.0			1,961.9			850.8
Total Proved		18,726.7			12,542.4			9,088.5			6,899.9			5,397.6
Probable		26,612.2			11,828.7			6,915.3			4,605.2			3,298.6
Total Proved Plus Probable		45,338.9			24,371.1			16,003.8			11,505.1			8,696.2

⁽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 2018 | 31

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

As at December 31, 2018

Forecast Prices and Costs

($ millions)	Revenue		Royalties		Operating Costs		Development Costs		Abandonment and Reclamation Costs		Future Net Revenue Before Income Taxes		Income Taxes		Future Net Revenue After Income Taxes
Canada
Total Proved		79,702.3		10,674.3		30,796.6		12,441.0		6,779.0		19,011.3		5,482.2		13,529.2
Total Proved Plus Probable		156,537.5		28,954.4		45,725.0		20,550.2		6,992.0		54,315.8		15,371.2		38,944.6
China
Total Proved		8,203.1		454.8		1,022.9		553.9		186.8		5,984.7		1,505.3		4,479.4
Total Proved Plus Probable		9,937.5		549.7		1,401.3		553.9		187.2		7,245.5		1,821.0		5,424.5
Indonesia
Total Proved		2,896.2		779.8		1,070.8		55.9		39.3		950.4		232.3		718.1
Total Proved Plus Probable		4,107.5		1,349.4		1,250.7		96.4		44.0		1,366.9		397.2		969.7
Total
Total Proved		90,801.6		11,909.0		32,890.3		13,050.8		7,005.1		25,946.5		7,219.8		18,726.7
Total Proved Plus Probable		170.582.5		30,853.6		48,377.0		21,200.5		7,223.2		62,928.2		17,589.4		45,338.9

Future Net Revenue by Product Type

As at December 31, 2018

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		342.6			2.09			—		—		—		—		342.6			2.09
Heavy Crude Oil		(221.4	)		(4.21	)		—		—		—		—		(221.4	)		(4.21	)
Bitumen		7,720.8			9.89			—		—		—		—		7,720.8			9.89
Total Oil		7,842.0			7.86			—		—		—		—		7,842.0			7.86
Conventional Natural Gas		585.6			3.59			3,927.5		38.53		663.3		18.98		5,176.4			17.24
Total Proved		8,427.6			7.26			3,927.5		38.53		663.3		18.98		13,018.4			10.03
Total Proved Plus Probable
Light & Medium Crude Oil		2,615.0			10.80			—		—		—		—		2,615.0			10.80
Heavy Crude Oil		125.5			1.70			—		—		—		—		125.5			1.70
Bitumen		13,743.0			9.73			—		—		—		—		13,743.0			9.73
Total Oil		16,483.5			9.54			—		—		—		—		16,483.5			9.54
Conventional Natural Gas		1,043.0			4.40			4,438.2		36.08		846.5		19.32		6,327.7			15.68
Total Proved Plus Probable		17,526.5			8.92			4,438.2		36.08		846.5		19.32		22,811.2			10.70

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

Husky Energy Inc. | Annual Information Form 2018 | 32

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 Associates Limited and GLJ Petroleum Consultants Ltd. China and Indonesia gas prices are derived from the GSAs specific to each set of projects. For historical prices realized during 2018, 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
2018	64.77	70.97	69.31	52.33	39.33
Forecast
2019	58.58	65.92	67.30	52.61	43.92
2020	64.60	69.47	75.84	60.50	52.76
2021	68.20	71.65	80.17	66.60	59.10
2022	71.00	73.72	83.22	69.32	61.60
2023	72.81	75.58	85.34	71.25	63.39
2024	74.59	77.39	87.33	73.07	65.14
2025	76.42	79.27	89.50	75.08	66.99
2026	78.40	81.27	91.89	77.22	69.06
2027	79.98	82.88	93.76	78.89	70.60
2028	81.59	84.54	95.68	80.60	72.17
Thereafter	2.00%/yr	2.00%/yr	2.00%/yr	2.00%/yr	2.00%/yr
	Bitumen	Natural Gas	Natural Gas Liquids
	Hardisty WCS (Cdn $/bbl)	AECO (Cdn $/mmbtu)	Edmonton Propane (Cdn $/bbl)	Edmonton Butane (Cdn $/bbl)	Edmonton Condensate (Cdn $/bbl)
Historical
2018	49.82	1.53	27.25	33.29	78.95
Forecast
2019	51.55	1.88	26.13	27.32	70.10
2020	59.58	2.31	31.27	41.10	79.21
2021	65.89	2.74	34.58	49.28	83.33
2022	68.61	3.05	37.25	55.65	86.20
2023	70.53	3.21	38.73	57.92	88.16
2024	72.34	3.31	39.75	59.27	90.20
2025	74.31	3.39	40.76	60.77	92.43
2026	76.44	3.46	41.93	62.37	94.87
2027	78.10	3.54	42.84	63.65	96.80
2028	79.81	3.62	43.80	64.97	98.79
Thereafter	2.00%/yr	2.00%/yr	2.00%/yr	2.00%/yr	2.00%/yr

Husky Energy Inc. | Annual Information Form 2018 | 33

	Asia Pacific
	China		Indonesia
	Natural Gas (U.S. $/mcf)(1)		Natural Gas (U.S. $/mcf)(1)		Inflation rates(2)		Exchange rates(3)
Historical
2018		10.60		7.56		—		0.77
Forecast
2019		10.55		7.53		—		0.76
2020		11.33		6.98		2.00		0.78
2021		10.94		7.10		2.00		0.80
2022		9.87		7.25		2.00		0.80
2023		9.89		7.37		2.00		0.81
2024		9.89		7.54		2.00		0.81
2025		9.89		7.70		2.00		0.81
2026		9.89		7.83		2.00		0.81
2027		9.90		7.98		2.00		0.81
2028		9.93		8.10		2.00		0.81
Thereafter						2.00		0.84

⁽¹⁾  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 2018 | 34

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 2017		24.6			63.8			747.4			835.8			1,174.1			41.4			1,073.0
Technical Revisions		(4.5	)		2.1			8.3			5.9			4.0			2.3			8.9
Economic Factors		—			(3.4	)		0.1			(3.2	)		(9.7	)		(0.1	)		(5.0	)
Acquisitions		—			—			2.2			2.2			8.4			0.3			3.9
Dispositions		(0.4	)		(0.2	)		—			(0.5	)		(1.9	)		—			(0.9	)
Discoveries		0.1			—			—			0.1			0.1			—			0.1
Extensions & Improved Recovery		1.7			4.7			177.1			183.5			219.4			6.8			226.9
Production		(3.4	)		(13.4	)		(45.3	)		(62.2	)		(106.2	)		(4.4	)		(84.3	)
End of 2018		18.2			53.7			889.7			961.6			1,288.1			46.3			1,222.6
Canada - Atlantic
End of 2017		96.8			—			—			96.8			—			—			96.8
Technical Revisions		(3.3	)		—			—			(3.3	)		—			—			(3.3	)
Economic Factors		—			—			—			—			—			—			—
Acquisitions		—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		7.6			—			—			7.6			—			—			7.6
Production		(7.8	)		—			—			(7.8	)		—			—			(7.8	)
End of 2018		93.3			—			—			93.3			—			—			93.3
China
End of 2017		—			—			—			—			397.9			14.0			80.3
Technical Revisions		—			—			—			—			45.6			1.9			9.5
Economic Factors		—			—			—			—			—			—			—
Acquisitions		—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—
Discoveries		—			—			—			—			153.6			5.5			31.1
Extensions & Improved Recovery		—			—			—			—			—			—			—
Production		—			—			—			—			(67.4	)		(3.1	)		(14.3	)
End of 2018		—			—			—			—			529.6			18.3			106.6
Indonesia
End of 2017		—			—			—			—			264.0			6.9			50.9
Technical Revisions		—			—			—			—			1.1			—			0.2
Economic Factors		—			—			—			—			—			—			—
Acquisitions		—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—
Production		—			—			—			—			(11.5	)		(0.9	)		(2.8	)
End of 2018		—			—			—			—			253.7			6.1			48.3

Husky Energy Inc. | Annual Information Form 2018 | 35

	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 2017		121.5			63.8			747.4			932.7			1,836.1			62.4			1,301.1
Technical Revisions		(7.7	)		2.1			8.3			2.6			50.7			4.2			15.3
Economic Factors		—			(3.4	)		0.1			(3.2	)		(9.7	)		(0.1	)		(5.0	)
Acquisitions		—			—			2.2			2.2			8.4			0.3			3.9
Dispositions		(0.4	)		(0.2	)		—			(0.5	)		(1.9	)		—			(0.9	)
Discoveries		0.1			—			—			0.1			153.6			5.5			31.2
Extensions & Improved Recovery		9.3			4.7			177.1			191.1			219.4			6.8			234.5
Production		(11.3	)		(13.4	)		(45.3	)		(70.0	)		(185.1	)		(8.4	)		(109.2	)
End of 2018		111.5			53.7			889.7			1,054.9			2,071.4			70.7			1,470.8

At December 31, 2018, the Company’s proved oil and gas reserves were 1,471 mmboe, up from 1,301 mmboe at the end of 2017. The Company’s 2018 reserves replacement ratio, defined as net additions of proved reserves divided by total production during the period, was 260 percent excluding economic revisions (255 percent including economic revisions).

Major changes to proved reserves in 2018 included:

• Western Canada Extensions & Improved Recovery additions of 227 mmboe including 102 mmbbls in the Sunrise Energy Project from new locations as part of a full field optimized development plan, 63 mmbbls for two new Lloydminster thermal bitumen SAGD projects, and 43 mmboe in Ansell, Kakwa, North Blackstone, Wapiti and Wembley from new locations.

• Discoveries included 154 bcf of conventional natural gas and 5 mmbbls of NGL for Liuhua 29-1 with the volumes transferred from probable reserves as Technical Revisions.

• Strong Lloydminster thermal bitumen performance added 31 mmbbls which were offset by a reduction of 23 mmbbls at the Sunrise Energy Project as a result of applying a more conservative estimate of the recovery factor early in the fifty-year life of the field.

• Atlantic Extensions & Improved Recovery include the addition of 8 mmbbls for the West White Rose Project transferred from probable as Technical Revisions.

• Technical Revisions of 9 mmboe in China due to higher natural gas performance as a transfer from probable reserves.

• Economic Factors include 4 mmboe associated with the shut-in of producing wells required because of the production curtailment implemented by the Government of Alberta.

Husky Energy Inc. | Annual Information Form 2018 | 36

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 2017		6.5			21.8			861.8			890.0			422.5			7.5			967.9
Technical Revisions		(2.1	)		(2.6	)		(295.1	)		(299.8	)		(37.3	)		(0.1	)		(306.1	)
Economic Factors		0.1			—			1.0			1.1			(4.0	)		(0.1	)		0.3
Acquisitions		—			—			0.5			0.5			2.1			0.1			1.0
Dispositions		(0.1	)		—			—			(0.1	)		(0.1	)		—			(0.1	)
Discoveries		0.1			—			—			0.1			—			—			0.1
Extensions & Improved Recovery		0.9			2.8			263.6			267.3			79.6			3.3			283.9
Production		—			—			—			—			—			—			—
End of 2018		5.4			21.9			831.8			859.1			462.9			10.7			946.9
Canada - Atlantic
End of 2017		99.4			—			—			99.4			—			—			99.4
Technical Revisions		(15.7	)		—			—			(15.7	)		—			—			(15.7	)
Economic Factors		—			—			—			—			—			—			—
Acquisitions		—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—
Production		—			—			—			—			—			—			—
End of 2018		83.8			—			—			83.8			—			—			83.8
China
End of 2017		—			—			—			—			214.0			7.6			43.2
Technical Revisions		—			—			—			—			(185.2	)		(6.4	)		(37.3	)
Economic Factors		—			—			—			—			—			—			—
Acquisitions		—			—			—			—			80.3			2.9			16.3
Dispositions		—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—
Production		—			—			—			—			—			—			—
End of 2018		—			—			—			—			109.0			4.1			22.2
Indonesia
End of 2017		—			—			—			—			138.5			2.0			25.1
Technical Revisions		—			—			—			—			(47.0	)		(0.4	)		(8.2	)
Economic Factors		—			—			—			—			—			—			—
Acquisitions		—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—
Production		—			—			—			—			—			—			—
End of 2018		—			—			—			—			91.5			1.7			16.9

Husky Energy Inc. | Annual Information Form 2018 | 37

	Light
	& Medium			Heavy									Conventional			Natural Gas
	Crude Oil			Crude Oil			Bitumen			Total Oil			Natural Gas			Liquids			Total
	(mmbbls)			(mmbbls)			(mmbbls)			(mmbbls)			(bcf)			(mmbbls)			(mmboe)
Total
End of 2017		105.9			21.8			861.8			989.5			775.0			17.1			1,135.7
Technical Revisions		(17.7	)		(2.6	)		(295.1	)		(315.4	)		(269.5	)		(6.9	)		(367.3	)
Economic Factors		0.1			—			1.0			1.1			(4.0	)		(0.1	)		0.3
Acquisitions		—			—			0.5			0.5			82.4			3.0			17.3
Dispositions		(0.1	)		—			—			(0.1	)		(0.1	)		—			(0.1	)
Discoveries		0.1			—			—			0.1			—			—			0.1
Extensions & Improved Recovery		0.9			2.8			263.6			267.3			79.6			3.3			283.9
Production		—			—			—			—			—			—			—
End of 2018		89.2			21.9			831.8			942.9			663.4			16.4			1,069.9

Major changes to probable reserves in 2018 included:

• Western Canada Extensions & Improved Recovery additions of 284 mmboe including 246 mmbbls from new Sunrise Energy Project locations which were offset by negative Technical Revisions of 263 mmbbls for other locations no longer part of the optimized development plan.

• Other Extensions and Improved Recovery include 17 mmbbls for two new Lloydminster thermal bitumen SAGD projects, and 16 mmboe for new locations in Ansell, Kakwa, Wembley and other fields. Other Technical Revisions include the transfer of 18 mmbbls to Proved reserves for the Lloydminster thermal bitumen SAGD projects due to strong performance.

• The working interest in Liuhua 29-1 increased from 50 percent to 75 percent resulting in an acquisition of 16 mmboe.

• Indonesia negative Technical Revisions of 8 mmboe were a result of a GSA not being finalized for one of the fields.

Husky Energy Inc. | Annual Information Form 2018 | 38

Reconciliation of Gross Proved Plus Probable Reserves

	Light
	& Medium Crude Oil			Heavy Crude Oil			Bitumen			Total Oil			Conventional Natural Gas			Natural Gas Liquids			Total
	(mmbbls)			(mmbbls)			(mmbbls)			(mmbbls)			(bcf)			(mmbbls)			(mmboe)
Canada - Western Canada
End of 2017		31.1			85.6			1,609.2			1,725.8			1,596.7			48.9			2,040.9
Technical Revisions		(6.5	)		(0.5	)		(286.8	)		(293.8	)		(33.3	)		2.2			(297.2	)
Economic Factors		0.2			(3.4	)		1.1			(2.2	)		(13.8	)		(0.2	)		(4.7	)
Acquisitions		—			—			2.7			2.7			10.5			0.4			4.9
Dispositions		(0.4	)		(0.2	)		—			(0.7	)		(1.9	)		—			(1.0	)
Discoveries		0.1			—			—			0.1			0.1			—			0.2
Extensions & Improved Recovery		2.6			7.5			440.7			450.8			298.9			10.1			510.8
Production		(3.4	)		(13.4	)		(45.3	)		(62.2	)		(106.2	)		(4.4	)		(84.3	)
End of 2018		23.5			75.6			1,721.5			1,820.7			1,751.0			57.0			2,169.6
Canada - Atlantic
End of 2017		196.3			—			—			196.3			—			—			196.3
Technical Revisions		(18.9	)		—			—			(18.9	)		—			—			(18.9	)
Economic Factors		—			—			—			—			—			—			—
Acquisitions		—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		7.6			—			—			7.6			—			—			7.6
Production		(7.8	)		—			—			(7.8	)		—			—			(7.8	)
End of 2018		177.1			—			—			177.1			—			—			177.1
China
End of 2017		—			—			—			—			611.9			21.6			123.6
Technical Revisions		—			—			—			—			(139.6	)		(4.6	)		(27.8	)
Economic Factors		—			—			—			—			—			—			—
Acquisitions		—			—			—			—			80.3			2.9			16.3
Dispositions		—			—			—			—			—			—			—
Discoveries		—			—			—			—			153.6			5.5			31.1
Extensions & Improved Recovery		—			—			—			—			—			—			—
Production		—			—			—			—			(67.4	)		(3.1	)		(14.3	)
End of 2018		—			—			—			—			638.7			22.4			128.8
Indonesia
End of 2017		—			—			—			—			402.5			9.0			76.1
Technical Revisions		—			—			—			—			(45.9	)		(0.4	)		(8.0	)
Economic Factors		—			—			—			—			—			—			—
Acquisitions		—			—			—			—			—			—			—
Dispositions		—			—			—			—			—			—			—
Discoveries		—			—			—			—			—			—			—
Extensions & Improved Recovery		—			—			—			—			—			—			—
Production		—			—			—			—			(11.5	)		(0.9	)		(2.8	)
End of 2018		—			—			—			—			345.1			7.7			65.3

Husky Energy Inc. | Annual Information Form 2018 | 39

	Light
	& Medium Crude Oil			Heavy Crude Oil			Bitumen			Total Oil			Conventional Natural Gas			Natural Gas Liquids			Total
	(mmbbls)			(mmbbls)			(mmbbls)			(mmbbls)			(bcf)			(mmbbls)			(mmboe)
Total
End of 2017		227.4			85.6			1,609.2			1,922.1			2,611.1			79.5			2,436.8
Technical Revisions		(25.5	)		(0.5	)		(286.8	)		(312.8	)		(218.8	)		(2.8	)		(352.0	)
Economic Factors		0.2			(3.4	)		1.1			(2.2	)		(13.8	)		(0.2	)		(4.7	)
Acquisitions		—			—			2.7			2.7			90.8			3.4			21.2
Dispositions		(0.4	)		(0.2	)		—			(0.7	)		(1.9	)		—			(1.0	)
Discoveries		0.1			—			—			0.1			153.7			5.5			31.2
Extensions & Improved Recovery		10.2			7.5			440.7			458.4			298.9			10.1			518.3
Production		(11.3	)		(13.4	)		(45.3	)		(70.0	)		(185.1	)		(8.4	)		(109.2	)
End of 2018		200.6			75.6			1,721.5			1,997.8			2,734.8			87.1			2,540.7

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 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 45 percent 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 34 percent of Husky’s gross proved undeveloped reserves are assigned to 14 heavy oil thermal projects in the Lloydminster area that are classified as bitumen. Approximately eight percent of Husky’s gross proved undeveloped reserves are assigned to the liquids-rich Ansell area. Approximately five percent of Husky’s gross proved undeveloped reserves are assigned to the International area. Approximately seven percent of Husky’s gross proved undeveloped reserves are assigned to the West White Rose Project fields and were added in 2017 and 2018 with the sanctioning of the project by Husky and its partners.

Husky funds 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 are pursued at a pace dependent on capital availability and its allocation in accordance with Husky’s business plans. As at December 31, 2018, there were no material proved undeveloped reserves that have remained undeveloped for greater than five years, except as described below.

The Sunrise Energy Project proved undeveloped thermal 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. Similarly, the probable undeveloped bitumen reserves are scheduled to be developed and produced over the next 50 years which includes capital spending on facility debottlenecks, expansions and additions within the next five years. For the existing three Lloydminster thermal bitumen projects, one project is scheduled to start up in 2019, and two in 2020. Two new Lloydminster thermal bitumen projects received regulatory approval in early 2019 and are scheduled to be brought online in 2021 and 2022. The Lloydminster thermal bitumen proved and probable undeveloped locations and Tucker bitumen probable locations are scheduled to be developed over the next one to 20 years to utilize each of the project’s steam and processing capacities. The West White Rose Project is scheduled to have the first proved undeveloped reserves placed on production in 2022. The remaining proved and probable undeveloped locations are scheduled to be placed on production by 2028. Proved undeveloped reserves in Madura are scheduled to be brought on production in 2020. Proved undeveloped reserves for Liuhua 29-1 are scheduled to be brought on production in 2020. Ansell’s proved and probable undeveloped locations are scheduled to be developed over the next five and seven years, respectively, all in keeping with the the Company’s business plan for that project.

Husky Energy Inc. | Annual Information Form 2018 | 40

Proved Undeveloped Reserves

	Light & Medium Crude Oil (mmbbls)				Heavy Crude Oil (mmbbls)				Bitumen (mmbbls)				Total Oil (mmbbls)
	First		Total at		First		Total at		First		Total at		First		Total at
	Attributed		year-end		Attributed		year-end		Attributed		year-end		Attributed		year-end
2016		—		5.7		—		0.3		9.1		488.3		9.1		494.3
2017		61.8		60.8		—		—		136.9		585.0		198.7		645.9
2018		8.4		69.8		1.0		1.0		177.3		747.9		186.6		818.6

	Conventional				Natural Gas Liquids				Total
	Natural Gas (bcf)				(mmbbls)				(mmboe)
	First		Total at		First		Total at		First		Total at
	Attributed		year-end		Attributed		year-end		Attributed		year-end
2016		1.6		435.2		—		3.2		9.4		570.0
2017		71.9		451.6		1.0		3.6		211.6		724.7
2018		310.4		739.1		9.2		12.4		247.6		954.2

Probable Undeveloped Reserves

	Light & Medium				Heavy Crude Oil				Bitumen				Total Oil
	Crude Oil (mmbbls)				(mmbbls)				(mmbbls)				(mmbbls)
	First		Total at		First		Total at		First		Total at		First		Total at
	Attributed		year-end		Attributed		year-end		Attributed		year-end		Attributed		year-end
2016		11.8		133.7		—		0.1		1.3		1,234.0		13.1		1,367.7
2017		0.3		80.8		—		—		42.3		810.9		42.7		891.8
2018		0.7		71.2		1.9		2.2		265.6		778.4		268.2		851.8

	Conventional				Natural Gas Liquids				Total
	Natural Gas (bcf)				(mmbbls)				(mmboe)
	First		Total at		First		Total at		First		Total at
	Attributed		year-end		Attributed		year-end		Attributed		year-end
2016		48.1		345.4		0.4		3.4		21.5		1,428.7
2017		302.7		558.8		7.1		9.0		100.2		993.9
2018		139.0		472.2		4.9		7.8		296.2		938.3

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. For additional information on risk factors please see “Risk Factors – Reserves Data and Future Net Revenue Estimates”.

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 16 of the Company’s audited consolidated financial statements for the year ended December 31, 2018.

Husky Energy Inc. | Annual Information Form 2018 | 41

Future Development Costs

The Company expects to fund its future development costs by cash generated from operating activities, cash on hand and short and long-term debt. In addition, the Company has access to additional funding through credit facilities and the issuance of equity through shelf prospectuses, subject to market conditions. The cost associated with this funding 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, 2018:

	Canada				China				Indonesia				Total
			Proved				Proved				Proved				Proved
			Plus				Plus				Plus				Plus
	Proved		Probable		Proved		Probable		Proved		Probable		Proved		Probable
	Reserves		Reserves		Reserves		Reserves		Reserves		Reserves		Reserves		Reserves
Year	($ millions)		($ millions)		($ millions)		($ millions)		($ millions)		($ millions)		($ millions)		($ millions)
2019		1,846.4		2,007.5		327.0		327.0		55.9		83.1		2,229.3		2,417.6
2020		1,597.6		1,787.5		226.8		226.8		—		13.3		1,824.4		2,027.6
2021		1,245.3		1,377.6		—		—		—		—		1,245.3		1,377.6
2022		693.9		844.9		—		—		—		—		693.9		844.9
2023		689.9		839.3		—		—		—		—		689.9		839.3
Remaining		6,367.9		13,693.5		—		—		—		—		6,367.9		13,693.5
Total		12,441.0		20,550.2		553.9		553.9		55.9		96.4		13,050.8		21,200.5

Production Estimates

Yearly Production Estimates for 2019

	Light &
	Medium Crude Oil		Heavy Crude Oil		Bitumen		Total Oil		Conventional Natural Gas		Natural Gas Liquids		Total
	(mbbls/day)		(mbbls/day)		(mbbls/day)		(mbbls/day)		(mmcf/day)		(mbbls/day)		(mboe/day)
Canada
Total Gross Proved		24.3		26.4		124.4		175.2		278.7		13.3		234.9
Total Gross Probable		5.6		2.1		7.1		14.9		35.7		2.1		22.9
Total Gross Proved Plus Probable		30.0		28.5		131.5		190.0		314.4		15.4		257.9
China
Total Gross Proved		—		—		—		—		187.0		7.7		38.9
Total Gross Probable		—		—		—		—		1.2		0.1		0.3
Total Gross Proved Plus Probable		—		—		—		—		188.1		7.8		39.1
Indonesia
Total Gross Proved		—		—		—		—		38.4		2.5		8.9
Total Gross Probable		—		—		—		—		—		0.1		0.1
Total Gross Proved Plus Probable		—		—		—		—		38.4		2.6		9.0
Total
Total Gross Proved		24.3		26.4		124.4		175.2		504.0		23.5		282.7
Total Gross Probable		5.6		2.1		7.1		14.9		36.9		2.3		23.3
Total Gross Proved Plus Probable		30.0		28.5		131.5		190.0		540.9		25.8		306.0

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

Husky Energy Inc. | Annual Information Form 2018 | 42

Social and Environmental Considerations

Social and Environmental Policy

Husky has a Health, Safety and Environment Policy that affirms its commitment to operational integrity. Operational integrity at Husky means conducting all activities safely and reliably so that the public is protected, impact to the environment is minimized, the health and wellbeing of employees are safeguarded, contractors and customers are safe, and physical assets (such as facilities and equipment) are protected from damage or loss.

The Health, Safety and Environment Committee of the Board of Directors (the “HS&E Committee”) is responsible for oversight of the Health, Safety and Environment Policy, oversight of audit results and monitoring compliance with the Company’s environmental policies, key performance indicators and regulatory requirements. The mandate of the HS&E Committee is available in the Governance section of the Husky website at www.huskyenergy.com.

To reinforce the Health, Safety and Environment Policy, Husky holds an annual summit for leaders, attended by members of the HS&E Committee and led by the Chief Executive Officer. During the summit, CEO awards are presented for the initiatives that demonstrate the highest level of operational integrity. Guest and internal speakers present on pertinent issues and the latest developments in the fields of operational integrity and corporate responsibility.

Husky is committed to upholding high standards of business integrity and seeks to deter wrongdoing and promote transparent, honest and ethical behaviour in all its business dealings. The Company has a Code of Business Conduct that sets out the standards employees, contractors, officers and directors are expected to meet. The 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 of Business Conduct is available on the Husky website at www.huskyenergy.com.

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 Company’s Code of Business Conduct. 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, health, safety and environment, and human resources personnel.

Husky is committed to conducting business fairly, with integrity and in compliance with applicable laws. It has an Anti-Bribery & Anti-Corruption Policy to reinforce the Code of Business Conduct 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.

Husky is committed to conducting business ethically and legally. A key component of this commitment is to comply with competition laws, the purpose of which is to preserve and promote a competitive market. The Company’s Competition Act Compliance Policy assists employees by providing relevant information about competition laws and guidelines to follow in order to ensure these laws are complied with and that any issues are handled appropriately.

Husky is an equal opportunity employer committed to an environment free of discrimination, harassment and violence and where respectful treatment is the norm. The 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 Community Investment Program that supports local charitable organizations. The Community Investment Policy provides guidance with the general goal of ensuring that contributions under the Community Investment Program are supported by a consistent and rigorous decision-making process and reflect Husky’s core corporate values and business strategy.

Husky has an External Scholarships and Educational Support Policy that encourages advanced education by providing financial assistance to qualified students pursuing studies at several post-secondary educational institutions, reinforcing Husky’s commitment to support the communities where it operates. The policy includes Husky’s Scholarships for Aboriginal Students which assists Aboriginal people in achieving greater career success by encouraging them to pursue an advanced education.

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

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

Husky Energy Inc. | Annual Information Form 2018 | 43

Husky is committed to ensuring health and safety at work. The ability of every employee or 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, the Alcohol and Drug Policy outlines the standards and expectations associated with alcohol and other drug use, consistent with Husky’s overall safety culture.

The above policies are available to employees and contractors on the Company’s intranet. Communication of the policies is provided through direct e-mail and articles published on the Company’s intranet. Mandatory training is 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’s Operational Integrity Management System (“HOIMS”) is a set of interrelated policies, aims, expectations and processes that provides a systematic way for the Company to identify, assess, and control health, safety and environmental (“HSE”) hazards and associated risks. Additionally, HOIMS establishes standards and procedures integral to safe operations and protecting the environment. Strong leadership, with adherence to HOIMS, delivers on Husky’s strategic operational integrity objectives and drives HSE performance.

The fundamental elements of HOIMS are:

Accountability

• All personnel demonstrate accountability for operational integrity.

Occupational Health & Safety

• Health and safety risks are effectively managed.

Risk Management

• All hazards are identified, analyzed, and evaluated and associated risks are managed.

Emergency Management

• Emergency response, business continuity, and security programs are implemented.

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

Reliability & Integrity

• Manage equipment and controls that are essential to reliability and integrity.

Training & Competency

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

Incident Management

• Investigate and learn from incidents to improve operational integrity performance.

Environmental Stewardship

• Responsibly manage our environmental impact.

Management of Change

• Permanent, temporary, and emergency changes that impact operational integrity, and the risks associated with those changes, are managed.

Information Management

• Operational integrity information is accurate and current.

• The right people can access the right information at the right time.

Regulatory Compliance

• Husky complies with regulatory requirements.

Project Delivery

• Facilities are designed and built, and assets are developed, to meet operational integrity aims and expectations of HOIMS.

Supply Chain

• Supplied services and materials meet Husky’s operational integrity requirements.

Assurance & Improvement

• Learn from results to continually improve Husky’s processes, procedures, competencies and operational integrity performance.

Husky Energy Inc. | Annual Information Form 2018 | 44

Pipeline Integrity

Husky implements a life cycle risk-based Pipeline Integrity Management (“PIM”) program across all Husky owned and operated pipelines. The program is a framework that is supported by a suite of documents including but not limited to the Pipeline Operations and Maintenance Procedures Manual (“POMM”), which provides guidelines on the safe operation and maintenance of pipelines. Numerous processes are required and utilized throughout the pipeline lifecycle to ensure a proactive approach to managing the integrity, operations and maintenance of the pipelines.

Processes for the management of pipeline integrity include:

• Risk management program: used to identify the integrity threats throughout the pipeline’s life cycle, and the risks associated with each threat. Appropriate measures are taken to address these risks and reduce them to as low a level as reasonably practicable.

• Geotechnical program: to identify, monitor and mitigate potential impacts to pipelines from natural earth movements.

• Engineering assessments: evaluate the fitness for service of pipelines when changes to design are made in order to proactively mitigate the risk to process safety.

• Failure investigations: establish root cause of any failures and apply the learnings to improve integrity programs.

• Annual pipeline integrity reviews: completed for all pipeline systems to review the effectiveness of integrity programs and where applicable make recommendations for improvement.

• Training: Husky has a Learning Management System (“LMS”) which defines mandatory training requirements for all employees. Husky has a web-based PIM and POMM training program on LMS that is available for all employees involved in the operation and maintenance of pipelines.

• Performance targets (number of incidents/1,000 km of pipeline) are set annually. Targets are tracked quarterly by the pipeline steering committee and immediate steps are taken to address any deficiencies.

• PIM program sustainment and continuous improvement: a comprehensive self-assessment process is being implemented to ensure effective sustainment and the continuous improvement of the PIM program.

• PIM program review: regular review of the PIM program is completed to ensure it aligns with the latest code and regulatory requirements. The reviews also consider Husky experience and pipeline industry standards and practices.

Environmental Protection

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 regulations cover matters such as air emissions, wastewater discharge, 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. In addition to existing requirements, Husky recognizes that there are emerging regulatory frameworks that may have a financial impact on the Company’s operations. See “Risk Factors” and “Industry Overview”.

Directly and through joint venture partnerships, Husky is a member of several industry associations that collaborate to identify and implement best practices on environmental performance. The International Petroleum Industry Environmental Conservation Association (“IPIECA”) produces guidelines that Husky uses to improve its operations and environmental practices, enhance its strategic planning and engage with regulators. In Canada, Husky is a member of both the upstream oil and gas industry association, the Canadian Association of Petroleum Producers (“CAPP”), and downstream industry association, the Canadian Fuels Association (“CFA”). Husky participates in technology research for energy efficiency and emissions reduction through membership and participation in the Petroleum Technology Alliance Canada (“PTAC”) and the Clean Resource Innovation Network (“CRIN”)

As an active member of the In-situ Water Technology Development Centre, Husky is developing new technologies to reduce water use and improve energy efficiency. Husky dedicates teams 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, after it has been treated, from a nearby oil sands operation and lower quality non-saline groundwater that is in contact with bitumen to generate steam for oil recovery.

Ongoing remediation and reclamation work is occurring at approximately 3,000 well sites and facilities in western Canada. During 2018, Husky spent approximately $181 million on asset retirement obligations (“ARO”) in North America, and the Company expects to spend approximately $202 million in 2019 on ARO and environmental site closure activities in North America, including abandonment, decommissioning, reclamation and remediation.

Husky Energy Inc. | Annual Information Form 2018 | 45

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 (“AER”) 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 their 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, 2018, the Company had deposited funds of $128 million, which was classified as non-current liabilities.

The Company 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 16 of the Company’s 2018 audited consolidated financial statements.

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.

As part of the Company’s review of proposed regulations that may affect its business and operations, the Company may, from time to time, prepare an internal analysis of the possible or expected impact of new regulations, which are subject to various uncertainties. It is not possible to predict with certainty the amount of additional investment in new or existing facilities required in the future for environmental protection or to address regulatory compliance requirements, such as reporting. Costs associated with levy payments for emerging climate change regulations may be significant. See “Risk Factors - Climate Change Regulations” for a description of the impact that climate change regulations may have on the Company.

Husky Energy Inc. | Annual Information Form 2018 | 46

INDUSTRY OVERVIEW

The operations of the oil and gas industry are governed by a number of laws and regulations mandated by multiple levels of government and regulatory authorities in Canada, the U.S. and other foreign jurisdictions. These laws and regulations, along with global economic conditions, have shaped the developing trends of the industry. The following discussion summarizes the trends, legislation and regulations that the Company believes have the most significant impact on the short and long-term operations of the oil and gas industry.

Crude Oil and Natural Gas Production

During the first half of 2018, certain members of the Organization of Petroleum Exporting Countries (“OPEC”) and some key non-OPEC members voluntarily reduced production, which led to the increase of the global crude oil market benchmarks for the first half of 2018. However, towards the latter half of 2018, certain members of OPEC and some key non-OPEC members increased production as the global crude oil inventory decreased.

On December 7, 2018, OPEC and several non-OPEC members announced a production reduction of 1.2 mmbbls/day from their October 2018 production levels for six months beginning in January 2019. The cuts were in response to increasing evidence that oil markets could become oversupplied in 2019, which was evidenced in the recent price declines.⁽¹⁾

In Canada, the western Canadian crude oil supply is forecasted to increase in the long term. In the Canadian Association of Petroleum Producers’ (“CAPP”) June 2018 publication, production in Canada was forecasted to increase from 4.2 mmbbls/day in 2017 to 6.2 mmbbls/day in 2035. The growth of Canada’s crude oil industry depends on new pipelines and new policies.⁽²⁾

The Alberta government has set province-wide mandatory oil production cuts in an attempt to rebalance the market. This curtailment became effective January 1, 2019, and is expected to continue through the end of the year. The provincial government is targeting to reduce production by 325,000 bbls/day for the first quarter of 2019, before adjusting volume targets for the remainder of the year⁽³⁾.

Total U.S. natural gas inventories were 19 percent lower at the end of November 2018 than the five-year (2013 – 2018) average for the end of November. Natural gas production is forecasted to grow in 2019 by approximately eight percent from 2018 volumes.⁽¹⁾

⁽¹⁾ “Short-Term Energy Outlook”, December 2018, U.S. Energy Information Administration

⁽²⁾ “Crude Oil Forecast, Markets and Transportation”, June 2018, Canadian Association of Petroleum Producers

⁽³⁾ “Protecting the value of our resources”, December 2018, Alberta Government Website

Commodity Pricing

Crude oil and natural gas producers negotiate purchase and sale contracts directly with respective buyers and these contracts are typically based on the prevailing market price of the commodity. The market price for crude oil is determined largely by global factors, and the contract price considers oil quality, transportation and other terms of the agreement. The price for natural gas in Canada is determined primarily by North America fundamentals because virtually all natural gas production in North America is consumed by North American customers, predominantly in the U.S. Commodity prices are based on supply and demand which may fluctuate due to market uncertainty and other factors beyond the control of entities operating in the industry.

Global crude oil benchmarks strengthened in the first half of 2018 due to market rebalancing, but weakened towards the end of the year due to record levels of oil production from the world’s largest producers leading to increased global inventories, combined with uncertainties regarding future global demand. Furthermore, the WCS benchmark weakened towards the end of 2018 primarily due to an oversupply of Canadian crude oil resulting from continued transportation constraints. Consequently the WCS benchmark traded at a greater discount compared to other North American benchmarks. The price of West Texas Intermediate (“WTI”) averaged US

$64.77/bbl in 2018 compared to US$50.95/bbl in 2017. The price of Brent averaged US$70.97/bbl in 2018 compared to US$54.28/bbl in 2017. The price of WCS averaged US$38.46/bbl in 2018 compared to US$38.98/bbl in 2017.

In December of 2018, the Government of Alberta imposed an oil production curtailment order with the goal of raising the price of oil sold in Alberta during 2019.

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Market Access⁽¹⁾

The existing pipeline network servicing western Canada is operating at capacity and producers are relying more on rail to move incremental volumes. Pipelines are the preferred mode of transporting large volumes of crude oil for long distances over land, given the inherent economies of scale associated with pipelines.

In December of 2018, the Government of Alberta imposed an oil production curtailment order with the goal of raising the price of oil sold in Alberta during 2019. This reduced the economic motivation to export crude by rail or develop longer term market access strategies.

Currently, there is insufficient pipeline capacity originating in western Canada to transport crude oil out of the supply basin to meet the needs of producers. Both the Enbridge Mainline pipeline system and Trans Mountain pipeline continue to operate under apportionment, whereby the pipeline companies must reduce shippers’ nominated volumes to derive an aggregate amount which can be transported by the pipeline in accordance with its available capacity.

Only three major pipeline projects remain under active development following the cancellation of TransCanada’s Energy East pipeline project in October 2017. The combined capacity from Enbridge’s Line 3 Replacement project, Trans Mountain Corporation’s Trans Mountain Expansion, and TransCanada’s Keystone XL would equal 1.79 mmbbls/day.

Existing pipeline infrastructure to transport crude oil production is at capacity and it is uncertain when additional pipeline capacity will become available.

⁽¹⁾ “Crude Oil Forecast, Markets and Transportation”, June 2018, Canadian Association of Petroleum Producers.

Royalties, Incentives and Income Taxes

Canada

The amount of royalties payable on production from privately owned lands is negotiated between the mineral freehold owner and the lessee, and this production may also be subject to certain provincial taxes and royalties. Royalty rates for production from Crown lands are determined by provincial governments. When setting royalty rates, commodity prices, levels of production and operating and capital costs are considered. Royalties payable are generally calculated as a percentage of the value of gross production and generally depend on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery, depth of well and the type or quality of the petroleum product produced. Other royalties and royalty-like interests are, from time to time, carved out of the owner’s working interest through non-public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests or net carried interests.

Royalty rates as a percentage of gross revenues averaged eight percent in 2018 compared to seven percent in 2017. Royalty rates in Western Canada averaged nine percent in 2018, compared to seven percent in 2017, primarily due to higher WTI prices for the majority of 2018. Royalty rates in Atlantic averaged eight percent in 2018 compared to nine percent in 2017, primarily due to lower production combined with with higher eligible costs.

The Canadian federal corporate income tax rate was 15 percent in 2018 and 2017. Provincial rates ranged between 11 percent and 16 percent in both 2018 and 2017.

Other Jurisdictions

Royalty rates in Asia Pacific averaged seven percent in 2018, compared to six percent in 2017, primarily due to higher production from the BD Project which has higher royalty rates than the Liwan Gas Project.

Operations in the U.S. are subject to the U.S. federal tax rate of 21 percent and various state-level taxes. Operations in China are subject to the Chinese tax rate of 25 percent. Operations in Indonesia are subject to tax at a rate of 40 percent as governed by each project’s PSC.

Land Tenure Regulation

In Canada, rights to natural resources are largely owned by the provincial and federal governments. Rights are granted to explore for and produce oil and natural gas subject to shared jurisdiction agreements, ELs, SDLs and production licences, leases, permits and provincial legislation which may include contingencies such as obligations to perform work or make payments.

For international jurisdictions, rights to natural resources are largely owned by national governments that grant rights in forms such as ELs and permits, production licences and PSCs. Companies in the oil and gas industry are subject to ongoing compliance with the regulatory requirements established by the relevant country for the right to explore, develop and produce petroleum and natural gas in that particular jurisdiction.

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Environmental Regulations

General

Oil and 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 impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances to the environment, including emissions of greenhouse gases (“GHGs”). Environmental regulations also require that wells, facilities and other properties associated with Husky’s operations 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 regulations, and impacts of possible changes, include:

• conventional air pollutant and GHG emission regulations and mandatory reductions in jurisdictions where the Company has operations.

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

• fuel reformulation and substitution to support reduced GHG emissions.

• managing air pollutant emissions at equipment and facility levels with the general goal of ensuring compliance with increasingly more stringent ambient air quality standards and air pollutant regulations.

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

• increased restrictions on freshwater licensing and 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 and additional information requirements.

• 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.

• land use.

• measurement requirements for oil and gas operations.

Water

Numerous regulations are imposed on Husky’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.

• baseline domestic water well testing practices.

• 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. Husky has reporting requirements relating to most licensed freshwater withdrawals. Policies dictate water source selection and management. Water withdrawals are further governed by local watershed and/or industry water management plans.

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Husky recognizes the importance of water security to the success of its operations and engages in dialogue on proposed regulatory changes, both directly and through industry associations. Husky believes it is sufficiently prepared to comply with new water regulations. 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 has realized financial impacts due to regulation changes. Proposed and future regulation changes could also have financial impacts.

Migratory Birds

Canada’s oil and gas industry may affect migratory birds and bird habitat through land disturbance activities and operating practices (e.g., sludge ponds). Industry activities risk contravening the Migratory Bird Convention Act (Canada) (“MBCA”) and supporting legislation that prohibits the disturbance and destruction of migratory birds, their eggs and/or their nests. In 2016, the Environmental Enforcement Act (Canada) introduced a new fine regime that increased maximum fines up to $6 million, with all subsequent fines doubling, for corporations that are convicted under the MBCA. The Company’s U.S. operations are subject to similar requirements pursuant to the Migratory Bird Treaty Act. The Company 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 the Company’s permit from the Canadian Wildlife Service (“CWS”), the Company’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 the Company’s Seabird Recovery Centre in consultation with CWS.

Air and Climate Change

General

The current regulatory environment related to air emissions and climate policy is dynamic. The impacts of emerging policy are becoming clearer as various jurisdictions finalize and implement new regulations. Husky engages in consultations for the design of proposed regulations and supports efforts to harmonize regulations across jurisdictions, both directly with regulators and through industry associations. Risk associated with these regulations is discussed under “Risk Factors”.

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 emission performance standards and reporting.

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

In 2017, Husky’s gross Scope 1 GHG emissions were 11,180,000 tCO₂e. Scope 2 GHG emissions in that year were 2,221,000 tCO₂e. The Company uses an internal GHG management framework to guide the process of integrating climate change into its business strategy. Elements of the GHG management framework that inform corporate business strategy include GHG inventory and quantification, GHG reporting and verification, an emissions reduction strategy and a regulatory policy system.

In addition to climate policy risk, the industry faces physical risks attributable to a changing climate. Husky operates in some of the harshest environments in the world, including offshore NL. Climate change is expected to increase the frequency of severe weather conditions including winds, flooding and variable temperatures, which are contributing to the melting of northern ice and increased iceberg activity. The Company has several policies in place to protect people, equipment and the environment in the event of extreme weather conditions and adverse ice conditions.

Husky is managing physical risk through engineering for 1:100-year weather events. The Company’s Atlantic business ice management program uses a range of resources, including a dedicated 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 commence in February 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. The Company also maintains a series of ad-hoc relationships with contractors, allowing the quick mobilization of additional resources as required.

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

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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 percent below 2005 levels by 2030. Indonesia has pledged a 29 percent reduction below a “business as usual” baseline by 2030. China has pledged for total emissions to peak in 2030, but with reductions in emissions per unit GDP by 60-65 percent from 2005 levels.

There is a commitment to review and increase pledges every five years under the Paris Agreement.

On August 4, 2017, the U.S. submitted formal notice of intention to withdraw from the Paris Agreement; however, under the terms of the Paris Agreement, the U.S. will remain a party until approximately August 2020.

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

Canadian Federal Regulations

The Canadian federal government 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 five percent of their gasoline supply come from renewable sources (such as ethanol) and to have an average of at least two percent of their diesel supply come from renewable sources (such as bio-diesel).

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 tranche of the Multi-Sector Air Pollutants Regulations was published in June 2016. These regulations have included three BLIERs developed under AQMS for the cement sector, reciprocating spark-ignited natural gas engines and non-utility boilers and heaters in industrial sectors. An emissions guideline under the Canadian Environmental Protection Act 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. For example, a ‘Code of Practice for the Management of Air Emissions from Pulp and Paper Facilities’ was published in July 2018.

The BLIERs pertaining to nitrogen oxides (“NOx”) emissions from boilers and heaters and NOx emissions from reciprocating engines in industrial facilities are applicable to the Company’s Canadian upstream and downstream oil and gas facilities, with the exception of the Prince George Refinery since a sector-specific Refining BLIER will be developed separately for petroleum refineries. 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.

On October 23, 2018, the Government of Canada announced the federal carbon pricing system would be implemented in part or in whole in Saskatchewan, Manitoba, Ontario and New Brunswick in 2019 as an element of the Pan Canadian Framework on Clean Growth and Climate Change. The remaining provinces and territories either elected to adopt the federal carbon pricing system or presented provincial policies that were deemed equivalent by the federal government. The federal carbon policy has two key elements: a carbon levy applied to fossil fuels ($20 per tonne starting on April 1, 2019 and increasing by $10 annually to $50 per tonne in 2022); and an output-based pricing system for industrial facilities emitting GHGs above 50,000 tonnes per year.

On December 20, 2018, the Government of Canada published the Regulatory Proposal for the Output-Based Pricing System (“OBPS”) Regulation under the Greenhouse Gas Pollution Pricing Act. The OBPS Regulatory Proposal includes draft sectorial Output-Based Standards, provisions pertaining to GHG emission quantification and reporting, as well as details on the administration process and content of verification reports. Stakeholder comments are accepted by February 15, 2019. Although final OBPS regulations will be published only in the summer of 2019, the regulatory requirements will be applied retroactively starting on January 1, 2019.

A federal Clean Fuel Standard (“CFS”) Discussion Paper was also 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. Proposed regulations for liquid fuels are expected to be published in 2019. Consultations on the federal CFS are ongoing.

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On December 20, 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 percent) by 2030 from a 2016 baseline. For liquid fuels, including transportation fuels, draft regulations are expected to be published in mid-2019 and final regulations in 2020 with coming into force in 2022. Stakeholder comments on the CFS Regulatory Design Paper are accepted by February 1, 2019, but CFS consultations will be ongoing.

The Government of Canada is committed to reducing methane emissions from the oil and gas sector by 40 percent to 45 percent below 2012 levels by 2025. Final methane reduction regulations for the upstream oil and gas industry were published on April 26, 2018. Emission 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 expected to come into force as early as 2020, and the remaining requirements by 2023.

Draft “Regulations Respecting Reduction in the Release of Volatile Organic Compounds (Petroleum Sector)” pertaining to the downstream oil and gas industry were published by the Government of Canada in May 2017. The regulations will require the implementation of comprehensive Leak Detection and Repair (“LDAR”) programs at refineries, upgraders and certain petrochemical facilities. These facilities will also be required to monitor the levels of certain volatile organic compounds at facility perimeters. The final regulations are targeted for publication in June 2019, with the fenceline monitoring requirements expected to be implemented starting in 2020 and the enhanced LDAR requirements coming into force in 2021.

Canadian Provincial Greenhouse Gas Regulations

In 2015, Alberta announced a major shift in its climate regulations through its Climate Leadership Plan. It includes four key areas in which the Government of Alberta is moving forward:

• Phasing out emissions from coal-generated electricity and developing more renewable energy.

• Implementing a new carbon price on GHG emissions.

• A legislated oil sands emission limit.

• Employing a new methane emission reduction plan.

As of January 1, 2018, large final emitters (“LFEs”), i.e., facilities that emit over 100,000 tonnes of CO₂e per year, fall under the Carbon Competitiveness Incentive Regulation (“CCIR”) that employs output-based allocations to benchmark facilities against peers within the same industrial sector in the province. CCIR applies to Husky’s Tucker and Sunrise facilities.

As of January 1, 2018, Alberta increased its broad-based carbon levy to $30 per tonne. Emissions from the combustion of produced fuel at upstream oil and gas facilities emitting less than 100,000 tonnes of CO₂e per year will be exempt from a fuel use levy until January 1, 2023, to allow time for these facilities to reduce methane emissions under provincial and federal methane regulations. Finally, total emissions from the oil sands will be capped at a maximum of 100 megatonnes in any year, with provisions for cogeneration and new upgrading capacity. The details of how this emissions limit will be implemented have not been finalized.

The AER is working collaboratively to develop and implement a regulatory framework that achieves the Government of Alberta’s methane emissions reduction outcome of 45 percent by 2025. Alberta has announced that it intends to reduce methane emissions from oil and gas operations using the following approaches:

• Applying new emissions design standards to new Alberta facilities.

• Improving measurement and reporting of methane emissions, as well as leak detection and repair requirements.

• Developing a joint initiative on methane reduction and verification for existing facilities and backstopping this with regulated standards that take effect in 2020, with the general goal of ensuring the 2025 target is met.

• On December 13, 2018, the AER released final methane regulations which are effective January 1, 2020.

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 draft “The Management and Reduction of Greenhouse Gases Amendment Act”, and various GHG regulations under the Act impose a carbon price (starting at $20 per tonne in 2019) on facilities that emit more than 25,000 tonnes of CO₂e/year. These would include the Upgrader and Husky’s ethanol plant, and the Saskatchewan thermal plants. As part of the October 23, 2018 Government of Canada’s announcement on climate policy equivalency, the Province of Saskatchewan will have a carbon tax applied to fuel for all facilities under that threshold, which would include Husky’s Cold operations. Saskatchewan has launched a court case to challenge federal jurisdiction in imposing the carbon tax.

The Government of Saskatchewan has drafted the “Oil and Gas Emissions Management Regulations” that would 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 emission intensities for various regions within the province. The proposed regulations are intending to reduce provincial methane emission intensity by 45 percent by 2025.

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In British Columbia, regulations established in 2008 target a provincial reduction in GHG emissions of at least 33 percent below 2007 levels by 2020 and 80 percent below 2007 levels by 2050. British Columbia had a $30 per tonne carbon tax from January 1 to March 31, 2018, which has been increased to $35 per tonne since April 1, 2018. Additionally, British Columbia has a Renewable and Low Carbon Fuel Requirements Regulation in place that requires a reduction in the allowable carbon intensities of transportation fuels, with penalties applied for intensities that do not meet targets.

The British Columbia government released its Climate Leadership Plan in August 2016. The 21 actions are targeted across major sectors of the economy, including annual reductions of up to five million tCO₂e by 2050 in the oil and gas sector through a focus on methane emissions, carbon capture and storage, and electrification. The British Columbia government has committed to increasing the provincial price on carbon by $5 per tonne annually (starting in April 2018) to $50 per tonne in 2021.

British Columbia released its Clean BC strategy on December 5, 2018, which is the first part of a longer-term strategy and aims to allow the province to reach 75% of its 2030 GHG reduction target. Over the next 18 to 24 months, it is expected that British Columbia will identify additional reductions to help the province meet or exceed the remaining 25% of its 2030 goal. A new round of stakeholder engagement is expected to begin in 2019 to inform the next steps of Clean BC that focuses on key actions in the transportation, building, waste management, and clean industry sectors.

To achieve cleaner transportation, by 2020 British Columbia will require automakers to meet an escalating annual percentage of new light-duty zero-emission vehicle sales. By 2040, all new light-duty cars and trucks sold in the province must run on clean electricity. After 2025, new vehicles will be subject to increasing tailpipe emissions standards. By 2030, fuel suppliers will be required to reduce the carbon intensity of diesel and gasoline by 20%. British Columbia will also work with renewable fuel providers to increase new production of renewable fuels by 2030, and the province will also implement a minimum requirement for 15% renewable content in natural gas by 2030.

To incentivize cleaner industry, the Government of British Columbia has signed a Memorandum of Understanding (“MOU”) with the Business Council of British Columbia, setting out a framework to develop a low-carbon industrial strategy. The MOU commits both parties to keeping energy-intensive, trade-exposed industries competitive. The Clean BC strategy will also direct a portion of the carbon tax paid by industry into incentives for cleaner operations specifically designed for regulated large industrial operations.

The British Columbia Oil and Gas Commission is also developing regulations to reduce methane emissions in the upstream production of natural gas by 45% by 2025, and the province is planning to develop a regulatory framework for underground CO₂ storage for both the natural gas sector and direct air capture.

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 will apply in full in Manitoba. This will include the application of an output-based standard to the Company’s Minnedosa ethanol plant.

On July 3, 2018, Ontario canceled its cap and trade program. As part of the October 23, 2018 announcement by the federal government, the federal carbon policy will apply in full in Ontario. Ontario has launched a court case to challenge federal jurisdiction to impose the federal carbon policy.

On June 7, 2016 the “Management of Greenhouse Gas Act” passed in the House of the Assembly of Newfoundland and Labrador, 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, 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 performance-based regulation imposes carbon pricing (beginning at $20/tonne in 2019) on petroleum production facilities with GHG emissions exceeding 25,000 tonnes/year and Mobile Offshore Drilling Units (MODUs) with GHG emissions exceeding 15,000 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. The 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.

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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 “tailored” the Clean Air Act 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 GHGs. In June 2014, the U.S. Supreme Court invalidated portions of the 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.

The EPA has not yet issued proposed or final GHG emissions standards for new or existing refineries but could do so in the future. The EPA has, however, issued GHG standards for oil and gas production operations, including hydraulic fracturing and these or similar regulations could affect refineries by indirect impacts on crude oil supplies and costs. These and other EPA regulations regarding GHG emissions are generally subject to judicial challenges and could be modified by regulatory actions or new legislation.

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 of 2005 and expanded under the Energy Independence and Security Act 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 RVOs set in November 2018 for calendar year 2019 were substantially higher for cellulosic biofuel (418 million gallons compared to 288 million gallons) and were similar or somewhat higher for other renewable categories. It is possible that advocacy groups will challenge the RVOs with the goal of forcing the EPA to establish more stringent RVOs.

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

Abandonment Liability

The AER manages abandonment liability and the licence transfer process using the provisions of Directive 006: Licencee Liability Rating Program and Licence Transfer Process. Directive 006 is designed to prevent Alberta taxpayers from incurring costs to suspend, abandon, remediate and reclaim a well, facility or pipeline. Under the Licencee Liability Rating Program, each licencee is assigned a Liability Management Rating. The Liability Management Rating is the ratio of a licencee’s eligible deemed assets under the Licencee Liability Rating Program, the Large Facility Liability Management Program and the Oilfield Waste Liability Program to its deemed liabilities in these programs. The Liability Management Rating assessment is designed to assess a licencee’s ability to address its suspension, abandonment, remediation and reclamation liabilities. This assessment is conducted monthly and on receipt of a licence transfer application in which the licencee is the transferor or transferee.

If a licencee’s deemed liabilities exceed its deemed assets, the licencee is required to post a security deposit with the AER to make up the shortfall. If a licencee fails to post security, if required, then the AER may take a number of steps to enforce these provisions, which include non-compliance fees, partial or full suspension of operations, suspension and/or cancellation of a permit, licence or approval and prevention of the transfer of licences held by licencees that do not meet the new requirements.

As a result of the Redwater Energy Corp. (“Redwater”) bankruptcy court ruling released in May 2016, whereby the court found that receivers and trustees of AER licencees may selectively disclaim unprofitable assets (and their associated abandonment and reclamation obligations) under section 14.06 of the Bankruptcy and Insolvency Act (Canada), the AER and the Orphan Well Association developed regulatory measures to mitigate the liability impact of licencee’s abandonment, reclamation and remediation obligations falling back to the industry.

Consequently, as of June 2016 a condition of transferring existing AER licences, approvals and permits requires transferees to demonstrate that they have a liability management ratio (“LMR”) of 2.0 or higher immediately following the transfer. If the transfer of the licence does not improve the purchaser’s LMR to 2.0 (or higher), the purchaser can post a security deposit, address existing abandonment obligations or transfer some of its assets.

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Like the AER, the Government of Saskatchewan has established an LMR rating of 1.0 as its threshold for providing a deposit. If a licencee’s LMR is less than 1.0, meaning the liability is greater than the deemed assets, that licencee will be required to submit a deposit to the Saskatchewan Ministry of Energy and Resources for the difference.

In response to the Redwater ruling, all licence transfer applications in Saskatchewan will be reviewed in detail, and the Ministry of Energy and Resources will consider relevant factors in calculating transfer deposit requirements. In addition to increased deposit requirements, The Ministry of Energy and Resources may incorporate additional conditions with licence transfer approvals which may impact the decision to proceed with certain transactions.

The Government of Saskatchewan intervened in the Alberta Court proceedings regarding Redwater’s bankruptcy with the general goal of ensuring their views were fully considered by the courts. The Saskatchewan Ministry of Justice has indicated opposition to any attempt by a receiver in Saskatchewan to renounce uneconomic oil and gas assets which are subject to the LMR program in Saskatchewan. The Saskatchewan ministry has stated that licence transfer applications in Saskatchewan will be considered non-routine as the Saskatchewan ministry will not be strictly relying on the standard LMR calculations in evaluating deposit requirements.

In January 2019, the Supreme Court of Canada’s ruling in Redwater was released, wherein the court held that abandonment and reclamation obligations of a debtor are binding on a Trustee, are not creditor claims nor claims provable in bankruptcy, and do not conflict with the general priority scheme in the Bankruptcy and Insolvency Act (Canada). The court ruled that the provincial regulatory regime can coexist with and apply alongside the Bankruptcy and Insolvency Act (Canada). The governments of Alberta and Saskatchewan have not yet made changes to the abandonment and reclamation obligations of licencees. Similarly, the Government of Canada has not yet made changes to the federal insolvency regime to account for the character and needs of Canada’s natural resource industries.

Hydraulic Fracturing

Hydraulic fracturing is a method of increasing well production by injecting fluid under high pressure down a well to crack the hydrocarbon bearing rock. In the case of water-based fractures, the fluid typically consists of water, sand and a relatively small amount of chemicals. This mixture flows into the cracks where the sand remains to keep the cracks open and enable natural gas or liquids to be recovered. Fracturing is designed so that the fracturing fluids can be produced back to the surface through the wellbore and are stored for reuse or future disposal in accordance with provincial regulations. The wells are designed and installed to provide multiple barriers protecting fresh groundwater aquifers from the fracturing process.

The Government of Canada manages use of chemicals through its Chemical Management Plan and New Substances Program. Some provinces require the details of fracturing fluids to be submitted to regulators. In Alberta, the AER requires that all fracturing operations submit reports regarding the quantity of fluids and additives. For Alberta and British Columbia, the website www.FracFocus.ca provides the public with access to individual well summaries of the fluids and chemicals reported.

In response to concerns that hydraulic fracturing may induce seismic events, the AER has imposed requirements for seismic monitoring, mitigation response plans and reporting in select areas of the province.

Inter-wellbore communication during hydraulic fracturing operations is the transfer of pressure from the wellbore being stimulated to an adjacent offset well. This event is dependent on a number of factors such as distance between wells, type of fluid used and whether an energizer is being used during operations. AER Directive 83 and IRP 24 provide rules and guidelines addressing this concern.

Land Use

In 2012, the Government of Alberta approved the Lower Athabasca Regional Plan (“LARP”), which covers the lower Athabasca region and includes Husky’s oil sands assets and major projects in the province. The LARP was developed to consider cumulative effects within the region using formal management frameworks for: Air Quality, Surface Water Quality and Quantity, Groundwater Management and Biodiversity.

The use of each framework establishes approaches with the general goal of ensuring trends are identified and assessed, regional limits are not exceeded, and air, water and biodiversity remain healthy for the region’s residents and ecosystems during oil sands development. To date, the Biodiversity Framework under LARP has not been finalized.

The South Saskatchewan Regional Plan was approved by the Government of Alberta in 2014, and was subsequently amended in 2017, and covers the southern portion of Alberta, including some Husky Western Canada assets. The plan details Alberta’s long-term commitment to conservation, protection of watersheds, sustaining biodiversity and sensitive habitats.

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Industry Collaboration Initiatives

Husky participates in industry associations and sustainability groups to better understand environmental, safety and social issues while benefitting from, and contributing to, industry innovation and good management practices.

Through Husky’s membership in Canada’s upstream industry association, CAPP, and the Canadian Fuels Association, which represents Canada’s refining and transportation fuels industry, and the American Fuels and Petrochemical Manufacturers which represents the U.S. refining and petrochemicals industry, the Company enhances its ability to identify and address potential policy and regulatory risks to its business and participates in advocacy related activity to reduce those risks. Husky participates on the CAPP Board of Governors, as well as various Executive Policy Groups and working level groups and committees that focus on areas of policy or regulation that have been identified as areas of interest or impact to Husky’s business. Similarly, Husky participates in the Canadian Fuels Association Board of Directors, Strategy & Planning Group, as well as various resource groups and national committees.

Husky is a member of IPIECA, the global oil and gas industry association for environmental and social issues and is participating in its Water Task Force and Climate Change Working Group as well as other topic-focused groups. The Company is also a member of Oil Spill Response Limited, an international industry-owned cooperative whose objective is to respond effectively to oil spills wherever in the world they may occur.

Husky also collaborates on water and carbon management and risk mitigation through involvement in industry initiatives and committees. As a member of the joint-industry Water Technology Development Centre and other joint-industry projects, Husky is committed to developing technologies that will reduce water and energy use for in-situ thermal bitumen operations.

Husky holds memberships with, or participates in, the following sustainability groups and industry associations: Alberta Industrial Fire and Emergency Management Association; Allen County Environmental Citizen’s Advisory Committee; Allen County Local Emergency Planning Committee; American Fuel and Petrochemical Manufacturers; Calgary Region Airshed Zone; CAAP; Canadian Brownfields Network; Canadian Fuels Association; Canadian Land Reclamation Association; Canadian Standards Association; Canadian Technical Asphalt Association; CDP; Center for Chemical Process Safety, an American Institute of Chemical Engineers Technological Community; China Offshore Environmental Services; China Offshore Oil Operation Safety Office Under Ministry of Emergency Management of the People’s Republic of China; China’s Marine Safety Administration; CHWMEG Inc.; Clean Resource Innovation Network; Clearwater Mutual Aid CO-OP; Conference Board of Canada - Council on Emergency Management; Devonian Aquifer Working Group - COSIA joint industry project; Earth Rangers; Eastern Canada Response Corporation; Edson Mutual Aid Committee; Emergency Response Assistance Canada; Energy Safety Canada; Environmental Services Association of Alberta; Environmental Studies Research Funds; Faster Forests - COSIA joint industry project; Foothills Research Institute - Grizzly Bear Program; Foothills Stream Crossing Partnership; Hardisty Mutual Aid Plan; Indonesian Petroleum Association; Industry Footprint Reduction Operations Group; International Oil & Gas Producers Association; Industrial Power Consumers Association of Alberta; IPIECA; Lakeland Industry and Community Association; Land Spill Emergency Program; Lima Area Security and Emergency Response Task Force; Lloydminster Emergency Preparedness Stakeholder Group; Mackenzie Delta Spill Response Corporation ; Ministry of Ecology and Environment of the People’s Republic of China; Monitoring Avian Productivity and Survivorship; Monitoring Priority Area - COSIA joint industry project; Mutual Aid Alberta; Natural Sciences and Engineering Research Council FlareNet Network; North Saskatchewan Watershed Alliance; Ohio Chemistry Technology Council; Ohio Manufacturer’s Association; Oil Sand Monitoring; Oil Spill Response Limited; One Ocean; Orphan Well Association; Ottawa River Coalition; Parkland Airshed Management Zone; Petroleum Research Newfoundland and Labrador; Petroleum Technology Alliance Canada; Prince George Air Improvement Roundtable; Prince George Industrial Mutual Aid Committee; Red Deer Air Quality Advisory Group (formerly PM 2.5 Response Advisory Committee); RM Wood Buffalo Mutual Aid Group; Saskatchewan Environmental Industry and Managers Association; Saskatchewan Industrial Energy Consumers Association; Saskatchewan Petroleum Industry Government Environmental Committee; Shawnee Industrial Neighbors Group; Strathcona District Mutual Assistance Emergency Response Assistance; Agreement; Superior Petroleum Partners; Transportation Community Awareness and Emergency Response; Water Technology Development Centre - COSIA joint industry project; Well Abandonment and Integrity Society; Western Canada Marine Response Corporation; Western Canadian Spill Services; Western Yellowhead Air Management Zone; Wood Buffalo Environmental Association.

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RISK FACTORS

The following summarizes what Husky believes to be the most significant risks relating to its operations which should be considered when purchasing securities of Husky. Husky 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 of Directors.

Operational, Environmental and Safety Incidents

The Company’s businesses are subject to inherent operational risks with respect to safety and the environment that require continuous vigilance. The Company seeks to minimize these operational risks by designing and building its facilities and conducting its operations in a safe and reliable manner using HOIMS, an integrated management system that considers environmental requirements as well as process and occupational safety. Failure to manage the risks effectively could result in potential fatalities, serious injury, interruptions to activities or use of assets, damage to assets, environmental impact or loss of licence to operate. Enterprise risk management, emergency preparedness, business continuity and security policies and programs are in place for all operating areas and are adhered to on an ongoing basis. 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 natural gas production. Lower prices for crude oil, NGL and 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 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 heavy crude oil and bitumen is limited and planned increases of North American heavy crude oil and bitumen production may create the need for additional heavy oil and bitumen 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 a number of 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 natural gas production is currently located in Western Canada and Asia Pacific. Western Canada’s natural gas production is subject to North American market forces. North American natural gas supply and demand is affected by a number of factors including, but not limited to, the amount of 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.

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 natural gas.

The fluctuations in refined products, crude oil and 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.

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Reservoir Performance 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, investor confidence and the Company’s ability to deliver on its growth strategy.

In order to maintain the Company’s future production of crude oil, 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. To mitigate the effects of this, the Company must undertake successful exploration and development programs, increase the recovery factor from existing properties through applied technology and identify and execute strategic acquisitions of proved developed and undeveloped properties and unproved prospects. 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.

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. With growing oil production across North America and the limited availability of infrastructure to carry the Company’s products to the marketplace, oil and natural gas transportation capacity is expected to 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.

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 activist 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.

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.

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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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, 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.

Partner Misalignment

Joint venture partners operate 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.

Reserves Data, Future Net Revenue and Resource Estimates

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 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 percent of the future net revenue discounted at 10 percent 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. Inaccurate appraisal of large project reservoirs could result in missed production, revenue and earnings targets and could have a material adverse effect on the Company’s reputation, investor confidence and ability to deliver on its growth business strategy.

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, development or exploratory activities. As these governments continually balance competing demands from different interest groups 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.

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Environmental Regulation

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, formulation or demand of products, which may or may not be offset through market pricing.

The Company anticipates further changes in environmental legislation could occur, which may result in stricter standards and enforcement, larger fines and liabilities, increased compliance costs and approval delays for critical licences and permits. See “Industry Overview – Environmental Regulations”.

Climate Change Regulation

Climate change regulations may become more onerous over time as governments implement policies to further reduce GHG emissions. As part of long range planning, the Company assesses future compliance costs associated with regulations of GHG emissions in its operations and the evaluation of future projects, based on the Company’s outlook for carbon pricing under current and pending regulations. The impact of recently announced regulations is being evaluated as provinces and the federal government finalize carbon pricing regulations. 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. The Company continues to monitor 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 the Company operates.

The Alberta Climate Leadership Plan began to be implemented in 2017. This plan includes an economy-wide carbon levy, rising to $30 per tonne in 2018 which applies to the Lloydminster Refinery, as well as a Carbon Competitiveness Incentive Regulation (“CCIR”) that manages emissions at LFEs including the Tucker Thermal Project and Sunrise Energy Project. Under the previous Specified Gas Emitters Regulation, which expired at the end of 2017, the Tucker Thermal Project generated over 500,000 tonnes of credits due to improved emission intensity performance. These credits are eligible to offset future compliance obligations under the CCIR. See “Industry Overview – Air and Climate Change – Canadian Provincial Greenhouse Gas Regulations”. These regulations are not anticipated to have a material impact over the duration of the Company’s five-year long-range plan. The CCIR is due for review in 2020, along with the federal carbon policy. Uncertainty regarding future regulations, including carbon price and the details of implementing the oil sands emission limit, make it difficult to predict the potential future impact on the Company.

In December 2017, the Government of Saskatchewan released “Prairie Resilience”a policy paper on climate change strategy in which it outlines multiple commitments across five areas designed to make Saskatchewan more resilient to the climatic, economic and policy impacts of climate change. As part of this strategy, the government developed output-based performance standards for large industrial emitters and a Climate Resilience Measurement Framework. The large industrial emitters regulations will apply to the Company’s Lloydminster Upgrader and ethanol plant and Saskatchewan thermal projects to reduce emissions while considering the economic competitiveness of these sectors. The smaller facilities (emitting under 25,000 tonnes/year) will be exposed to the federal carbon levy. The cost impacts of this levy on the Company’s cold heavy oil production may be measurable. See “Industry Overview - Air and Climate Change - Canadian Provincial Greenhouse Gas Regulations”.

The cost of compliance with British Columbia’s $35 per tonne carbon tax (increasing to $40 on April 1, 2019) and the Renewable and Low Carbon Fuel Requirements Regulation may materially adversely affect the Company’s Prince George Refinery. Additionally, future regulations in support of British Columbia’s commitment under its Climate Leadership Plan are uncertain. See “Industry Overview – Air and Climate Change – Canadian Provincial Greenhouse Gas Regulations”.

The application of the federal carbon policy in Manitoba may significantly adversely affect the Company’s Minnedosa ethanol plant in Manitoba. See “Industry Overview – Air and Climate Change – Canadian Provincial Greenhouse Gas Regulations”.

The Newfoundland and Labrador performance-based regulation imposes a carbon price beginning at $20/tonne in 2019 and escalating to $50/tonne in 2022. The provincial Gasoline and Diesel Tax begins at $20/tonne and will be adjusted with a goal of Atlantic parity related to provincial taxation (including carbon tax) of fuel products. The carbon tax rates will only increase to match equivalent increases in carbon taxation programs in neighbouring 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 the Company’s Atlantic region operation.

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Within the mandate of the Pan-Canadian Framework on Clean Growth and Climate Change, in May 2017, the Government of Canada released a technical paper on the federal carbon policy introducing two key elements: a carbon levy applied to gas that the Company uses at its facilities as well as retail fuel ($20 per tonne starting in 2019 and increasing by $10 annually to $50 per tonne in 2022), and an output-based pricing system for industrial facilities emitting GHGs above 50,000 tonnes of CO₂e per year. In December 2018, the Government of Canada published the Regulatory Design Paper on the CFS that focuses on the liquid fuel stream regulations. Draft CFS regulations are expected to be published in mid-2019 and final regulations in 2020, with the regulations expected to come into force in 2022. The impact of the CFS is still uncertain.

The Company’s U.S. refining business may be materially adversely affected by the implementation of the EPA’s climate change rules or, by future U.S. GHG legislation that applies to the oil and gas industry or the consumption of petroleum products and by other U.S. climate change statutes at the federal or state level or by regulations imposed by other federal agencies or 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 emission 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 and results of operations.

The U.S. 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. See “Industry Overview - Air and Climate Change - U.S. Renewable Fuels Standard”. Due to regulatory uncertainty and in part due to the U.S. fuel supply reaching the “blend wall” (the 10 percent limit prescribed by most automobile warranties), the price and availability of RINs have been volatile.

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. 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.

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.

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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 debt to capital covenant. If the Company does not comply with the covenants under these credit facilities, there is a risk that repayment could be accelerated.

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.

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Climatic Conditions

Extreme climatic conditions may 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. The Company has in place a number of policies to protect people, equipment and the environment in the event of extreme weather conditions and ice melt conditions.

The Company’s Atlantic operations have a robust ice management program, which uses a range of resources including a dedicated 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 commence in February 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. The Company also maintains a series of ad-hoc relationships with contractors, allowing the quick mobilization of additional resources as required. The Company regularly assesses all aspects of its ice management program in order 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. The Company 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. The Company 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.

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.

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 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 of the Company’s Board of Directors has oversight of the Company’s risk mitigation strategies related to cybersecurity.

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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. There is a risk that the Company may have difficulty attracting and retaining personnel with the required skill levels. 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.

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 Husky 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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HUSKY EMPLOYEES

The number of Husky’s permanent employees was as follows:

	As at December 31,
	2018		2017		2016
Number of permanent employees		5,157		5,152		5,150

DIVIDENDS

Dividend Amounts

The following table shows the aggregate amount of the dividends declared payable per share in respect of its last three 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:

	2018		2017		2016
Dividends per Common Share	$	0.450	$	0.075	$	—
Dividends per Series 1 Preferred Share	$	0.60	$	0.60	$	0.73
Dividends per Series 2 Preferred Share	$	0.74	$	0.57	$	0.42
Dividends per Series 3 Preferred Share	$	1.13	$	1.13	$	1.13
Dividends per Series 5 Preferred Share	$	1.13	$	1.13	$	1.13
Dividends per Series 7 Preferred Share	$	1.15	$	1.15	$	1.15

Dividend Policy and Restrictions

The declaration and payment of dividends are at the discretion of the Board of Directors, 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 Business Corporations Act (Alberta) and other relevant factors.

Common Share Dividends

On February 28, 2018, the Board of Directors reinstated the quarterly Common Share cash dividend of $0.075 per share. On July 26, 2018, the Board of Directors increased the quarterly Common Share cash dividend to $0.125 per share.

The Board of Directors has the ability to declare dividends in common shares or in cash. Quarterly dividends are declared in an amount expressed in dollars per common share and can 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.

The Company’s dividend policy is reviewed on a regular basis and there can be no assurance that dividends will be declared or the amount of any future dividends.

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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 percent annually for the initial period ending March 31, 2016, as and when declared by the 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 percent. 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 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 who retained their shares will receive the new fixed rate quarterly dividend applicable to the Series 1 Preferred Shares of 2.404 percent 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 are 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 percent as and when declared by the Board of Directors. Effective March 31, 2016, Husky Energy 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 condition, 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 are 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 percent annually for the initial period ending December 31, 2019 as declared by the 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 percent. Holders of Series 3 Shares will have the right, at their option, to convert their shares into Series 4 Preferred Shares, subject to certain conditions, on December 31, 2019 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 percent.

Series 5 Preferred Share Dividends

Holders of the Series 5 Preferred Shares are 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 percent annually for the initial period ending March 31, 2020 as declared by the 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 3.57 percent. Holders of Series 5 Preferred Shares will have the right, at their option, to convert their shares into Series 6 Preferred Shares, subject to certain conditions, on March 31, 2020 and on March 31 every five years thereafter. Holders of the Series 6 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 3.57 percent.

Series 7 Preferred Share Dividends

Holders of the Series 7 Preferred Shares are entitled to receive a cumulative fixed dividend, payable on the last day of March, June, September and December in each year, of 4.60 percent annually for the initial period ending June 30, 2020 as declared by the 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 3.52 percent. Holders of the Series 7 Preferred Shares will have 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. Holders of the Series 8 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 3.52 percent.

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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 of Directors 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.

If the Board of Directors declares a dividend on the common shares payable in whole or in part as a stock dividend, unless otherwise determined by the Board of Directors of Husky in respect of a particular dividend, the value of the common shares for purposes of each stock dividend declared by the Board of Directors of Husky shall be deemed to be the volume weighted average trading price of the common shares on the principal stock exchange on which the common shares are traded, 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.

In the event the stock dividend is to be issued pursuant to Husky’s Stock Dividend Program, shareholders of record wishing to accept a payment of the stock dividend, and of future stock dividends declared by the Board of Directors in the form of common shares pursuant to Husky’s Stock Dividend Program, are required to complete and deliver to Husky’s transfer agent a Stock Dividend Confirmation Notice at least five business days prior to the record date of a declared dividend. The Stock Dividend Confirmation Notice permits shareholders to confirm that they will accept common shares as payment of the dividend on all or a stated number of their common shares. A Stock Dividend Confirmation Notice will remain in effect for all stock dividends on the common shares to which it relates and which are held by the shareholder unless the shareholder delivers a revocation notice to Husky’s transfer agent, in which case the Stock Dividend Confirmation Notice will not be effective for any dividends having a declaration date that is more than five business days following receipt of the revocation notice by Husky’s transfer agent. In the event a shareholder fails to deliver a Stock Dividend Confirmation Notice at least five business days prior to the record date of a declared dividend, or delivers a Stock Dividend Confirmation Notice confirming that the holder of common shares accepts the common shares as payment of the dividend on some but not all of the holder’s common shares, the dividend on common shares for which no Stock Dividend Confirmation Notice was delivered or the dividend on those of the holder’s common shares in respect of which the holder did not deliver a Stock Dividend Confirmation Notice, will be paid in cash. See “Dividends - Dividend Policy and Restrictions - Common Share Dividends”.

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 of Directors 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 are entitled to vote, except in accordance with the provisions of the Business Corporations Act (Alberta).

Husky Energy Inc. | Annual Information Form 2018 | 67

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 to certain conditions, on December 31, 2019 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, 2020 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, 2020 and on June 30 every five years thereafter.

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.

	Standard and Poor’s Rating Services (“S&P”)		Moody’s Investor Service (“Moody’s”)		Dominion Bond Rating Services                 Limited (“DBRS”)
Outlook/Trend		Stable		Stable		Stable
Senior Unsecured Debt		BBB		Baa2		A(low)
Series 1 Preferred Shares		P-3(high)				Pfd-2(low)
Series 2 Preferred Shares		P-3(high)				Pfd-2(low)
Series 3 Preferred Shares		P-3(high)				Pfd-2(low)
Series 5 Preferred Shares		P-3(high)				Pfd-2(low)
Series 7 Preferred Shares		P-3(high)				Pfd-2(low)
Commercial Paper						R-1(low)

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 pays a fee to credit rating agencies in order to receive a rating for debt or equity instruments upon issuance.

Moody’s

Moody’s long-term credit ratings are on a rating scale that ranges from Aaa (highest) to C (lowest). A rating of Baa2 by Moody’s is within the fourth highest of nine categories and is assigned to debt securities which are considered medium-grade (i.e., they are subject to moderate credit risk). Such debt securities 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 1 indicates that the issue ranks in the higher end of its generic rating category, the modifier 2 indicates a mid-range ranking and the modifier 3 indicates a ranking in the lower end of that generic rating category.

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S&P

Standard and Poor’s long-term credit ratings are on a rating scale that ranges from AAA (highest) to D (lowest). A rating of BBB by S&P is within the fourth highest of 10 categories and indicates that the obligation exhibits adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitment on the obligation. The addition of a plus (+) or minus (-) designation after a rating indicates the relative standing within the major rating categories.

S&P began rating Husky’s Series 1 Preferred Shares and Series 2 Preferred Shares, Series 3 Preferred Shares, Series 5 Preferred Shares and Series 7 Preferred Shares on its Canadian preferred share scale on March 18, 2011, December 9, 2014, March 12, 2015 and June 17, 2015, respectively. Preferred share ratings are a forward-looking opinion about the creditworthiness of an issuer with respect to a specific preferred share obligation. There is a direct correspondence between the ratings assigned on the preferred share scale and S&P’s ratings scale for long-term credit ratings. According to S&P’s ratings system, a P 3 (high) rating on the Canadian preferred share rating scale is equivalent to a BB+ rating on the long-term credit rating scale. A rating of BB by S&P is within the fifth highest of 10 categories and indicates that the obligation is less vulnerable to nonpayment than other speculative issues. However, it faces major ongoing uncertainties or exposure to adverse business, financial, or economic conditions that could lead to the obligor’s inadequate capacity to meet its financial commitments on the issue.

DBRS

Dominion Bond Rating Service’s long-term credit ratings are on a rating scale that ranges from AAA (highest) to D (lowest). A rating of A (low) by DBRS is within the third highest of 10 categories and is assigned to debt securities considered to be of good credit quality. The capacity for payment of financial obligations is substantial, but of lesser credit quality than that of higher rated securities. Entities in the A category may be vulnerable to future events, but qualifying negative factors are considered manageable. The assignment of a “(high)” or “(low)” modifier within each rating category indicates relative standing within such category.

DBRS began rating Husky’s Series 1 Preferred Shares and Series 2 Preferred Shares, Series 3 Preferred Shares, Series 5 Preferred Shares and Series 7 Preferred Shares on its Canadian preferred share scale on March 18, 2011, December 9, 2014, March 12, 2015 and June 17, 2015, respectively. Preferred share ratings are meant to give an indication of the risk that an issuer will not fulfill its full obligations in a timely manner, with respect to both dividend and principal commitments. DBRS preferred share ratings range from Pdf 1 (highest) to D (lowest). According to the DBRS’ ratings system, preferred shares rated Pfd-2 are of satisfactory credit quality where protection of dividends and principal is still substantial, but earnings, the balance sheet and coverage ratios are not as strong as Pfd-1 rated companies.

DBRS began rating Husky’s commercial paper on September 4, 2014. Credit ratings on commercial paper are on a short-term debt rating scale that ranges from R-1 (high) to D1 representing the range of such securities rated from highest to lowest qualify. A rating of R-1 (low) by DBRS is the third highest of 10 categories and is assigned to debt securities considered to be of good credit quality. The capacity for the payment of short-term financial obligations as they become due is substantial with overall strength not as favourable as higher rating categories. Entities in this category may be vulnerable to future events, but qualifying negative factors are considered manageable. The R-1 and R-2 commercial paper categories are denoted by (high), (middle) and (low) designations.

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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 are listed and posted for trading on the Toronto Stock Exchange (“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.

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, 2018:

	High		Low		Volume (000’s)
January		19.24		17.49		26,660
February		18.33		16.05		24,093
March		18.46		16.56		26,184
April		19.94		17.31		26,173
May		19.73		17.71		25,935
June		21.02		18.45		22,402
July		22.15		19.85		17,188
August		22.43		21.10		20,108
September		22.99		21.04		18,742
October		21.49		18.05		45,929
November		19.05		15.30		37,743
December		17.11		13.33		40,316

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, 2018:

	High		Low		Volume (000’s)
January		18.48		17.37		131
February		18.30		17.75		167
March		18.25		17.55		119
April		17.87		17.44		124
May		18.30		17.45		37
June		17.59		17.15		56
July		18.21		17.56		104
August		18.26		17.70		127
September		17.81		17.60		71
October		17.91		16.00		79
November		17.09		14.30		453
December		14.70		12.15		235

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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, 2018:

	High		Low		Volume (000’s)
January		19.00		17.64		26
February		18.87		18.15		18
March		18.75		18.12		12
April		18.43		17.91		8
May		18.75		18.05		12
June		18.00		17.67		10
July		18.55		17.83		1
August		18.65		18.10		9
September		18.70		18.29		17
October		18.97		17.12		39
November		18.16		15.49		22
December		15.56		12.99		48

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, 2018:

	High		Low		Volume (000’s)
January		25.63		24.44		111
February		25.19		24.69		294
March		25.22		24.66		136
April		24.81		24.29		209
May		25.05		24.41		52
June		25.00		24.55		61
July		25.27		24.96		121
August		25.23		24.88		70
September		25.00		24.69		135
October		24.97		21.88		142
November		23.87		20.02		112
December		20.50		16.40		212

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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, 2018:

	High		Low		Volume (000’s)
January		25.56		24.90		89
February		25.33		24.88		65
March		25.35		24.80		111
April		25.00		24.76		145
May		25.53		24.91		59
June		25.23		24.89		180
July		25.43		25.15		39
August		25.59		25.18		78
September		25.43		25.06		56
October		25.48		23.46		124
November		24.44		21.10		77
December		21.49		17.50		119

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, 2018:

	High		Low		Volume (000’s)
January		25.70		25.00		63
February		25.36		24.86		60
March		25.36		24.90		72
April		25.31		24.86		111
May		26.07		25.03		204
June		25.24		24.83		74
July		25.39		24.98		32
August		25.50		25.10		152
September		25.45		25.03		42
October		25.39		23.19		164
November		24.40		20.88		74
December		22.14		17.55		186

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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.

Name & Residence	Office or Position	Principal Occupation During Past Five Years
Li, Victor T. K. Hong Kong Special Administrative Region	Co-Chair of the Board Director since August 2000	Mr. Li is the Group Co-Managing Director of CK Hutchison Holdings Limited. He is also the Chairman and Managing Director of CK Asset Holdings Limited. He is also the Chairman and Executive Director of CK Infrastructure Holdings Limited and CK Life Sciences Int’l., (Holdings) Inc., a Non-Executive Director of Power Assets Holdings Limited and HK Electric Investments Manager Limited which is the trustee-manager of HK Electric Investments, and a Non-Executive Director and the Deputy Chairman of HK Electric Investments Limited. Mr. Li is also the Deputy Chairman of Li Ka Shing Foundation Limited, Li Ka Shing (Overseas) Foundation and Li Ka Shing (Canada) Foundation, and a Non-Executive Director of The Hongkong and Shanghai Banking Corporation Limited. Mr. Li serves as a member of the Standing Committee of the 12th National Committee of the Chinese People’s Political Consultative Conference of the People’s Republic of China. He is also a member of the Chief Executive’s Council of Advisors on Innovation and Strategic Development of the Hong Kong Specia Administrative Region and Vice Chairman of the Hong Kong General Chamber of Commerce. Mr. Li is the Honorary Consul of Barbados in Hong Kong. Mr. Li holds a Bachelor of Science degree in Civil Engineering and a Master of Science degree in Civil Engineering, both received from Stanford University in 1987. He obtained an honorary degree, Doctor of Laws, honoris causa (LL.D.) from The University of Western Ontario in 2009.
Fok, Canning K. N. Hong Kong Special Administrative Region	Co-Chair of the Board and Chair of the Compensation Committee Director since August 2000	Mr. Fok is an Executive Director and Group Co-Managing Director of CK Hutchison Holdings Limited. 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. 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.

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Bradley, Stephen E. Hong Kong Special Administrative Region	Member of the Audit Committee and the Corporate Governance Committee Director since July 2010	Mr. Bradley is a Director of Broadlea Group Ltd., Senior Consultant, NEX (formerly known as ICAP (Asia Pacific) Ltd.) and a Director of Swire Properties Ltd. (Hong Kong). Mr. Bradley entered the British Diplomatic Service in 1981 and served in various capacities including Director of Trade & Investment Promotions (Paris) from 1999 to 2002; Minister, Deputy Head of Mission & Consul-General (Beijing) from 2002 to 2003 and HM Consul-General (Hong Kong) from 2003 to 2008. Mr. Bradley also worked in the private sector as Marketing Director, Guinness Peat Aviation (Asia) from 1987 to 1988 and Associate Director, Lloyd George Investment Management (now part of BMO Global Asset Management) from 1993 to 1995. Mr. Bradley retired from the Diplomatic Service in 2009. Mr. Bradley obtained a Bachelor of Arts degree from Balliol College, Oxford University in 1980 and a post-graduate diploma from Fudan University, Shanghai in 1981. Mr. Bradley is a Member of the Hong Kong Securities and Investment Institute and an ICD.D with the Institute of Corporate Directors of Canada.
Ghosh, Asim London, United Kingdom	Director since May 2009	Mr. Ghosh has been on the Board of Directors of Husky Energy since May 2009 and was President & Chief Executive Officer from June 2010 until his retirement in December 2016. He is the former Managing Director and Chief Executive Officer of Vodafone Essar Limited. Under his leadership the cellular phone company grew from a virtual startup in 1998 to become one of the largest mobile companies in the world by subscribers. Mr. Ghosh started his career with Procter & Gamble in Canada and subsequently became a Senior Vice President of Carling O’Keefe. He later became founding co-Chief Executive Officer of Pepsi Food’s start up operations in India. He served in senior executive positions and as Chief Executive Officer of the AS Watson consumer packaged goods subsidiary of Hutchison Whampoa. From 1991 to 1998 he managed a group of 13 business units, and expanded the group’s operations from Hong Kong to China and Europe. Mr. Ghosh received his Master of Business Administration from Wharton School at the University of Pennsylvania, and obtained his undergraduate degree in Electrical Engineering from the Indian Institute of Technology.
Glynn, Martin J. G. British Columbia, Canada	Chair of the Corporate Governance Committee and a Member of the Compensation Committee Director since August 2000	Mr. Glynn is a Director and Chair of Public Sector Pension Investment Board (PSP Investments), and a Director of Sun Life Financial Inc. and Sun Life Assurance Company of Canada. Mr. Glynn was a Director from 2000 to 2006 and President and Chief Executive Officer of HSBC Bank USA N.A. from 2003 until his retirement in 2006. Mr. Glynn was a Director of HSBC Bank Canada from 1999 to 2006 and President and Chief Executive Officer from 1999 to 2003. Mr. Glynn obtained a Bachelor of Arts (Honours) degree from Carleton University, Canada in 1974 and a Master’s degree in Business Administration from the University of British Columbia in 1976.

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Koh, Poh Chan Hong Kong Special Administrative Region	Director since August 2000	Ms. Koh is Finance Director of Harbour Plaza Hotel Management (International) Ltd. (a hotel management company) and also a Member of the Executive Committee of CK Asset Holdings Limited. Ms. Koh is qualified as a Fellow Member (FCA) of the Institute of Chartered Accountants in England and Wales and is an Associate of the Canadian Institute of Chartered Accountants (CPA, CA) and the Chartered Institute of Taxation in the U.K. (CTA). Ms. Koh graduated from the London School of Accountancy in 1971 and was admitted to the Institute of Chartered Accountants in England and Wales in 1973, to the Chartered Institute of Taxation in the UK in 1976 as well as the Institute of Chartered Accountants of Ontario, Canada in 1980.
Kwok, Eva L. British Columbia, Canada	Member of the Compensation Committee and the Corporate Governance Committee Director since August 2000	Mrs. Kwok is Chairman, a Director and Chief Executive Officer of Amara Holdings Inc. (a private investment holding company). Mrs. Kwok is also a Director of CK Life Sciences Int’l., (Holdings) Inc. and CK Infrastucture Holdings Limited. Mrs. Kwok is also a Director of the Li Ka Shing (Canada) Foundation. 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. Mrs. Kwok obtained a Master’s degree in Science from the University of London in 1967.
Kwok, Stanley T. L. British Columbia, Canada	Chair of the Health, Safety and Environment Committee Director since August 2000	Mr. Kwok is a Director and President of Amara Holdings Inc. He is an independent Non-Executive Director of CK Hutchison Holdings Limited. Mr. Kwok is a Director of Element Lifestyle Retirement Inc. He retired as a Director of the CTBC Bank of Canada in July, 2017. Mr. Kwok obtained a Bachelor of Science degree (Architecture) from St. John’s University, Shanghai in 1949, and an A.A. Diploma from the Architectural Association School of Architecture in London, England in 1954.
Ma, Frederick S. H. Hong Kong Special Administrative Region	Member of the Audit Committee and the Health, Safety and Environment Committee Director since July 2010	Professor Ma has held senior management positions in international financial institutions and Hong Kong publicly listed companies in his career. He was also a former Principal Official with the Hong Kong Special Administrative Region Government. In addition to being a Director of Husky, he is currently the Non- Executive Chairman of MTR Corporation Limited (formerly Mass Transit Railway Corporation). In July 2002, Professor Ma joined the Government of the Hong Kong Special Administrative Region as the Secretary for Financial Services and the Treasury. He assumed the post of Secretary for Commerce and Economic Development in July 2007, but resigned from the Government in July 2008 due to medical reasons. Professor Ma was appointed as a member of the International Advisory Council of China Investment Corporation in July 2009. In January 2013, he was appointed a member of the Global Advisory Council of the Bank of America. Professor Ma was appointed as an Honorary Professor of the School of Economics and Finance at the University of Hong Kong in October 2008. In August 2013, he was appointed as an Honorary Professor of the Faculty of Business Administration at the Chinese University of Hong Kong. ProfessorMa obtained a Bachelor of Arts (Honours) degree in Economics and History from the University of Hong Kong in 1973, an Honorary Doctor of Social Sciences in October 2014 from Lingnan University and an Honorary Doctor of Social Sciences in October 2016 from City University of Hong Kong.

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Magnus, George C. Hong Kong Special Administrative Region	Member of the Audit Committee Director since July 2010	Mr. Magnus is a Non-Executive Director of CK Hutchison Holdings Limited and CK Infrastructure Holdings Limited and an independent Non-Executive Director of HK Electric Investments Manager Limited. Mr. Magnus acted as an Executive Director of Cheung Kong (Holdings) Limited from 1980 and as Deputy Chairman from 1985 until his retirement from these positions in October 2005. He served as Deputy Chairman of Hutchison Whampoa Limited from 1985 to 1993 and as Executive Director from 1993 to 2005. He also served as Chairman of Hongkong Electric Holdings Limited (now known as Power Assets Holdings Limited) from 1993 to 2005. He was a Non-Executive Director of Power Assets Holding Limited from 2005 to 2012 and then an independent Non-Executive Director until January 2014. Mr. Magnus obtained a Bachelor of Arts degree in 1959. He obtained a Master’s degree in Economics from King’s College, Cambridge University in 1963.
McGee, Neil D. Luxembourg	Member of the Health, Safety and Environment Committee Director since November 2012	Mr. McGee is the Managing Director of Hutchison Whampoa Europe Investments S.à r.l. He is an Executive Director of Power Assets Holdings Limited. Prior to his joining Hutchison Whampoa Europe Investments S.à r.l., he served as Group Finance Director of Power Assets Holdings Limited from 2006 to 2012, Chief Financial Officer of Husky Oil Limited from 1998 to 2000 and Chief Financial Officer of Husky Energy Inc. from 2000 to 2005. Prior to joining Husky Oil Limited in 1998, Mr. McGee held various financial, legal and corporate secretarial positions with the CK Hutchison Holdings Group. Mr. McGee holds a Bachelor of Arts degree and a Bachelor of Laws degree from the Australian National University.
Peabody, Robert J. Alberta, Canada	President & Chief Executive Officer Director since December 2016	Mr. Peabody became a member of the Board of Directors and President and Chief Executive Officer of Husky on December 5, 2016. Mr. Peabody was appointed Chief Operating Officer in 2006 and was responsible for leading Husky’s Upstream and Downstream segments, including Western Canada Conventional and Unconventional, Heavy Oil, Oil Sands, Atlantic Region and Exploration, as well as Refining and Upgrading operations. He was also responsible for the Safety, Engineering, Project Management and Procurement functions. Prior to joining Husky, he led four major businesses for BP plc in Europe and the United States. Mr. Peabody holds a Bachelor of Science degree in Mechanical Engineering from the University of British Columbia and a Master of Science degree in Management (Sloan Fellow) from Stanford University. Mr. Peabody is a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA) and Vice-Chairman of the Foothills Hospital Development Council.
Russel, Colin S. Gloucestershire, United Kingdom	Member of the Audit Committee and the Health, Safety and Environment Committee Director since February 2008	Mr. Russel is the founder and a director of Emerging Markets Advisory Services Ltd. (a business advisory company). Mr. Russel is a Director of CK Infrastructure Holdings Limited, CK Life Sciences Int’l., (Holdings) Inc. and ARA Asset Management Pte. Ltd. Mr. Russel was the Canadian Ambassador to Venezuela; Consul General for Canada in Hong Kong; Director for China of the Department of Foreign Affairs, Ottawa; Director for East Asian Trade in Ottawa; Senior Trade Commissioner for Canada in Hong Kong; Director for Japan Trade in Ottawa and was in the Trade Commissioner Service for Canada in Spain, Hong Kong, Morocco, the Philippines, London and India. Previously Mr. Russel was an international project manager with RCA Ltd., Canada and development engineer with AEI Ltd., UK. Mr. Russel received a degree in Electrical Engineering in 1962 and a Master’s degree in Business Administration in 1971, both from McGill University, Canada.

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Shaw, Wayne E. Ontario, Canada	Member of the Audit Committee and the Corporate Governance Committee Director since August 2000	Mr. Shaw is the President of G.E. Shaw Investments Limited. Prior to his retirement in April 2013, he was a Senior Partner with Stikeman Elliott LLP, Barristers and Solicitors. Mr. Shaw is also a Director of the Li Ka Shing (Canada) Foundation. 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 Upper Canada.
Shurniak, William Saskatchewan, Canada	Deputy Chair of the Board and Chair of the Audit Committee Director since August 2000	Mr. Shurniak was an independent Non-Executive Director of Hutchison Whampoa Limited until June 2015, when he became an independent Non-Executive Director of CK Hutchison Holdings Limited. From May 2005 to June 2011 he was a Director and Chairman of Northern Gas Networks Limited (a private distributor of natural gas in Northern England). Mr. Shurniak also held the following positions until his return to Canada in 2005: Director and Chairman of ETSA Utilities (a utility company) since 2000, Powercor Australia Limited (a utility company) since 2000, CitiPower Pty Ltd. (a utility company) since 2002, and a Director of Envestra Limited (a natural gas distributor) since 2000, CrossCity Motorways Pty Ltd. (an infrastructure and transportation company) since 2002 and Lane Cove Tunnel Company Pty Ltd. (an infrastructure and transportation company) since 2004. Mr. Shurniak obtained an Honorary Doctor of Laws degree from the University of Saskatchewan in May 1998 and from The University of Western Ontario in October 2000. On July 30, 2005, he was a recipient of the Saskatchewan Centennial Medal from the Lieutenant Governor of Saskatchewan. In 2009 he was awarded the Saskatchewan Order of Merit by the Government of the Province of Saskatchewan. In December 2012, Mr. Shurniak was a recipient of The Queen Elizabeth II Diamond Jubilee Medal from the Lieutenant Governor of Saskatchewan. On June 4, 2014, the University of Regina conferred an Honorary Doctor of Laws degree on Mr. Shurniak and on November 10, 2016 he was awarded the Meritorious Service Medal by the Governor General of Canada.
Sixt, Frank J. Hong Kong Special Administrative Region	Member of the Compensation Committee Director since August 2000	Mr. Sixt is an Executive Director, Group Finance Director and Deputy Managing Director of CK Hutchison Holdings Limited. Mr. Sixt is also the Non-Executive Chairman of TOM Group Limited, an Executive Director of CK Infrastructure Holdings Limited, a 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.

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Officers

The following are the names and residences of the officers 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.

Name and Residence	Office or Position	Principal Occupation During Past Five Years
Peabody, Robert J. Alberta, Canada	President & Chief Executive Officer	President & Chief Executive Officer of Husky since December 2016. Chief Operating Officer of Husky from April 2006 to December 2016.
Hart, Jeffrey R. Alberta, Canada	Chief Financial Officer	Chief Financial Officer of Husky since November 2018. Acting Chief Financial Officer of Husky from April 2018 to November 2018. Vice President, Controller of Husky from October 2015 to April 2018.
Symonds, Robert W. P.	Chief Operating Officer	Chief Operating Officer of Husky since March 2017. Senior Vice President,
Alberta, Canada		Western Canada Production of Husky Oil Operations Limited from April 2012 to March 2017.
Girgulis, James D. Alberta, Canada	Senior Vice President, General Counsel & Secretary	Senior Vice President, General Counsel & Secretary since April 2012. Vice President, Legal & Corporate Secretary of Husky from August 2000 to April 2012.

As at February 15, 2019, the directors and officers of Husky, as a group, beneficially owned or controlled or directed, directly or indirectly, 814,498 common shares of Husky, representing less than one percent of the issued and outstanding common shares.

Conflicts of Interest

The 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 Business Corporations Act (Alberta), 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 have been within the past ten 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 ten 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, other than as follows. Mr. Glynn was director of MF Global Holdings Ltd. when it filed for Chapter 11 bankruptcy in the U.S. on October 31, 2011. Mr. Glynn is no longer a director of MF Global Holdings Ltd.

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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) have, within the past ten 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) have 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.

AUDIT COMMITTEE

Composition

The members of Husky’s Audit Committee (the “Committee”) are William Shurniak (Chair), Stephen E. Bradley, Frederick S. H. Ma, George C. Magnus, Colin S. Russel and Wayne E. Shaw. Each of the members of the Committee is independent in that each member does not have a direct or indirect material relationship with the Company. Multilateral Instrument 52-110 Audit Committees provides that a material relationship is a relationship which could, in the view of the Company’s Board of Directors, reasonably interfere with the exercise of a member’s independent judgment.

The Committee’s Mandate provides that the Committee is to be comprised of at least three members of the Board, all of whom shall be independent and meet the financial literacy requirements of applicable laws and regulations. Each member of the Committee is financially literate in that each has the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can reasonably be expected to be raised by the Company’s financial statements.

The education and experience of each Committee member that is relevant to the performance of his responsibilities as a Committee member is as follows.

William Shurniak (Chair) - Mr. Shurniak was an independent Non-Executive Director of Hutchison Whampoa Limited until June 2015, when he became an independent Non-Executive Director of CK Hutchison Holdings Limited, a newly listed company on The Stock Exchange of Hong Kong Limited. From May 2005 to June 2011 he was a Director and Chairman of Northern Gas Networks Limited (a private distributor of natural gas in Northern England).

Stephen E. Bradley - Mr. Bradley is a Director of Broadlea Group Ltd., Senior Consultant, ICAP (Asia Pacific) and a Director of Swire Properties Ltd. (Hong Kong).

Frederick S. H. Ma - Professor Ma has served in senior positions in the private sector and has held Principal Official positions (minister equivalent) with the Hong Kong Special Administrative Region Government. Professor Ma is currently a member of the International Advisory Council of China Investment Corporation, China’s Sovereign Fund, as well as an Honorary Professor of the University of Hong Kong.

George C. Magnus - Mr. Magnus is a Non-Executive Director of CK Hutchison Holdings Limited and Cheung Kong Infrastructure Holdings Limited and an independent Non-Executive Director of HK Electric Investments Manager Limited and HK Electric Investments Limited.

Colin S. Russel - Mr. Russel is the founder and Managing Director of Emerging Markets Advisory Services Ltd. Mr. Russel is a director and an audit committee member of Cheung Kong Infrastructure Holdings Limited, CK Life Sciences Int’l., (Holdings) Inc. and ARA Asset Management Pte. Ltd.

Wayne E. Shaw - Mr. Shaw is the President of G.E. Shaw Investments ULC. Prior to his retirement in April 2013, he was a Senior Partner with Stikeman Elliott LLP, Barristers and Solicitors. Mr. Shaw is also a Director of the Li Ka Shing (Canada) Foundation.

Husky’s Audit Committee Mandate is attached hereto as Appendix A.

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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 auditor, during the fiscal years indicated:

($ thousands)	2018		2017
Audit Fees		3,612		3,861
Audit-related Fees		249		256
Tax Fees		226		121
		4,087		4,238

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 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 Committee pre-approved all of the audit-related and tax services provided by KPMG LLP in 2018.

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.

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 percent 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.

TRANSFER AGENTS AND REGISTRARS

Husky’s transfer agent and registrar is Computershare Trust Company of Canada. In the United States, the transfer agent and registrar is Computershare Trust Company, Inc. The registers for transfers of the Company’s common and preferred shares are maintained by Computershare Trust Company of Canada at its principal offices in the cities of Calgary, Alberta and Toronto, Ontario. Queries should be directed to Computershare Trust Company at 1-800-564-6253 or 1-514-982-7555.

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, 2018 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 one percent 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.

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ADDITIONAL INFORMATION

Additional information, including directors’ and officers’ remuneration, principal shareholders of Husky’s common shares and a description of options to purchase common shares is contained in Husky’s Management Information Circular prepared in connection with the annual meeting of shareholders held on April 26, 2018.

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, 2018.

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.

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 general strategic plans and growth strategies; 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, 2018; the Company’s 2019 production estimates broken down by product type and location; and anticipated effects of and cost of compliance with certain future or proposed laws and regulations on the Company’s operations;

• with respect to the Company’s thermal developments: estimated production and expected timing of first production from the Dee Valley, Spruce Lake Central, Spruce Lake North, Spruce Lake East, Edam Central, Dee Valley 2 and Westhazel projects; the expected timing of regulatory approvals for the Dee Valley 2 and Westhazel projects; and the expected impact of the Alberta government-mandated production curtailment on the Tucker Thermal Project and the Sunrise Energy Project;

• with respect to the Company’s non-thermal developments, the expected impact of the Alberta government-mandated production curtailment;

• with respect to the Company’s Western Canada resource plays, strategic and drilling plans;

• with respect to the Company’s Offshore business in Asia Pacific: the expected timing of commencement of drilling of the remaining three wells at, and first gas production from, Liuhua 29-1; target production from Liuhua 29-1 when fully ramped up; timing for a second exploration well on Block 16/25; the expected timing of drilling five MDA field production wells and two MBH field production wells, and the expected timing of first gas production and sales therefrom; and the expected timing of development and tie-in of the additional MDK shallow water field;

• with respect to the Company’s Offshore business in Atlantic: development plans, expected timing of first oil and expected volume and timing of peak production at the West White Rose Project; and delineation plans at the A-24 exploration well;

• with respect to the Company’s Infrastructure and Marketing business: the processing capacity expected to be added by the Ansell Corser Gas Plant when it comes online, and the expected timing thereof; and

• with respect to the Company’s Downstream operating segment: the expected timing that operations at the Superior Refinery will resume; plans to increase asphalt modification capacity, expand asphalt sales in U.S. markets and further market residual production; plans to market and potentially sell the Prince George Refinery and the Retail and Commercial Network; and the expected timing of completion of the crude oil flexibility project at the Lima Refinery.

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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.

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, 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, thermal and non-thermal developments in the Integrated Corridor, Western Canada resource plays and Infrastructure and Marketing business: 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, 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 the Company’s Downstream operating segment: 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, 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 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, 2018; the demand for the Company’s products and prices received for crude oil and 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 the Block 29/26 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;

Husky Energy Inc. | Annual Information Form 2018 | 82

• with respect to the Company’s Offshore business in Asia Pacific and Atlantic, thermal and non-thermal developments in the Integrated Corridor, Western Canada resource plays and Infrastructure and Marketing business: 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 the Company’s Downstream operating segment: the costs to operate properties, plants and equipment in an efficient, reliable and safe manner; regulatory (environmental, license 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, 2018, which is available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov.

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 the term “operating netback”, which is a common non-GAAP metric used in the oil and gas industry and is not used to enhance the Company’s reported financial performance or position. Management believes 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 gross revenue less royalties, production and operating and transportation costs on a per unit basis.

This AIF contains the term “funds from operations”, which is a non-GAAP measure that does not have a standardized meaning prescribed by IFRS and therefore is unlikely to be comparable to similar measures presented by other issues. It is common in the reports of other companies but may differ by definition and application. Funds from operations 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 plus change in non-cash working capital. Management believes that impacts of noncash 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.

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, 2018 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.

Husky Energy Inc. | Annual Information Form 2018 | 83

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 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 incremental proved reserve additions for that period divided by the Company’s Upstream gross production for the same period. The reserves replacement ratio measures the amount of reserves added 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 percent for the company to maintain its reserves. The reserves replacement ratio only measures the amount of reserves added to a company’s reserve base during a given period. 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.

This document includes estimates of net pay thickness at White Rose A-24 and A-78, which estimates may be considered to be anticipated results under NI 51-101. The estimates were prepared internally. The risks and uncertainties associated with recovery of resources from A-24 and A-78 include, but are not limited to: that Husky may encounter unexpected drilling results; the occurrence of unexpected events in the exploration for, and the operation and development of, oil and gas; delays in anticipated timing of drilling and completion of wells; geological, technical, drilling and processing problems; and other difficulties in producing petroleum reserves.

Note to U.S. Readers

The Company reports its reserves and resources information in accordance with Canadian practices and specifically in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities, 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.

Husky Energy Inc. | Annual Information Form 2018 | 84

Appendix A

Husky Energy Inc.

Audit Committee Mandate

Purpose

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

1. the quarterly and annual financial statements and quarterly and annual MD&A, which are to be provided to shareholders and the appropriate regulatory agencies;

2. earnings press releases before the Corporation publicly discloses this information;

3. the system of internal controls that management has established;

4. the internal and external audit process;

5. the appointment of external auditors;

6. the appointment of qualified reserves evaluators or auditors;

7. the filing of statements and reports with respect to the Corporation’s oil and gas reserves; and

8. the identification, management and mitigation of major financial risk exposures of the Corporation.

In addition, the Committee provides an avenue for communication between the Board and each of the Chief Financial Officer of the Corporation and other senior financial management, internal audit, the external auditors, external qualified reserves evaluators or auditors and internal qualified reserves evaluators. It is expected that the Committee will have a clear understanding with the external auditors and the external reserve evaluators or auditors that an open and transparent relationship must be maintained with the Committee.

While the Committee has the responsibilities and powers set forth in this Mandate, the role of the Committee is oversight. The members of the Committee are not full time employees of the Corporation and may or may not be accountants or auditors by profession or experts in the fields of accounting, or auditing and, in any event, do not serve in such capacity. Consequently, it is not the duty of the Committee to plan or conduct financial audits or reserve audits or evaluations, or to determine that the Corporation’s financial statements are complete, accurate and are in accordance with applicable accounting or reserve principles. This is the responsibility of management and the external auditors and, as to reserves, the external reserve evaluators or auditors. Management and the external auditors will also have the responsibility to conduct investigations and to assure compliance with laws and regulations and the Corporation’s business conduct guidelines.

Composition

The Committee will consist of not less than three directors, all of whom will be independent and will satisfy the financial literacy requirements of securities regulatory requirements.

One of the members of the Committee will be an audit committee financial expert as defined in applicable securities regulatory requirements.

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 of the Board 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 of the Board.

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Meetings

The Committee will meet at least four times annually on dates determined by the Chair or 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 Corporation. The secretary will keep minutes of the meetings of the Committee. Minutes will be sent to all Committee members, on a timely basis.

As necessary or desirable, but in any case at least quarterly, the Committee shall meet with members of management and representatives of the external auditors and internal audit in separate executive sessions to discuss any matters that the Committee or any of these groups believes should be discussed privately.

As necessary or desirable, but in any case at least annually, the Committee will meet the management and representatives of the external reserves evaluators or auditors and internal reserves evaluators in separate executive sessions to discuss matters that the Committee or any of these groups believes should be discussed privately.

Authority

Subject to any prior specific directive by the Board, the Committee is granted the authority to investigate any matter or activity involving financial accounting and financial reporting, the internal controls of the Corporation and the reporting of the Corporation’s reserves and oil and gas activities.

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

In recognition of the fact that the external auditors are ultimately accountable to the Committee, the Committee will have the authority and responsibility to recommend to the Board the external auditors that will be proposed for nomination at the annual general meeting. The external auditors will report directly to the Committee, and the Committee will evaluate and, where appropriate, replace the external auditors. The Committee will approve the fees and terms for all audit engagements and all non-audit engagements with the external auditors. The Committee will consult with management and the internal audit group regarding the engagement of the external auditors but will not delegate these responsibilities.

The external qualified reserves evaluators or auditors will report directly to the Committee, and the Committee will evaluate and, where appropriate, replace the external qualified reserves evaluators or auditors. The Committee will approve the fees and terms for all reserves evaluators or audit engagements. The Committee will consult with management and the internal qualified reserves evaluator’s group regarding the engagement of the external qualified reserves evaluators or auditors but will not delegate these responsibilities.

Specific Duties & Responsibilities

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

Audit

1. Review and reassess the adequacy of this Mandate annually and recommend any proposed changes to the Corporate Governance Committee and the Board for approval.

2. Review with the Corporation’s management, internal audit and the external auditors and recommend to the Board for approval the Corporation’s annual financial statements and annual MD&A which is to be provided to shareholders and the appropriate regulatory agencies and any financial statement contained in a prospectus, information circular, registration statement or other similar document.

3. Review with the Corporation’s management, internal audit and the external auditors and approve the Corporation’s quarterly financial statements and quarterly MD&A which is to be provided to shareholders and the appropriate regulatory agencies.

4. Review with the Corporation’s management and approve earnings press releases before the Corporation publicly discloses this information.

5. Be responsible for the oversight of the work of the external auditors, including the resolution of disagreements between management of the Corporation and the external auditors regarding financial reporting.

Husky Energy Inc. | Annual Information Form 2018 | 86

6. Review with the Corporation’s management, internal audit and the external auditors the Corporation’s accounting and financial reporting controls and obtain annually, in writing from the external auditors their observations, if any, on material weaknesses in internal controls over financial reporting as noted during the course of their work.

7. Review with the Corporation’s management, internal audit and the external auditors significant accounting and reporting principles, practices and procedures applied by the Corporation in preparing its financial statements, and discuss with the external auditors their judgments about the quality (not just the acceptability) of the Corporation’s accounting principles used in financial reporting.

8. Review the scope of internal audit’s work plan for the year and receive a summary report of major findings by internal audit and how management is addressing the conditions reported.

9. Review the scope and general extent of the external auditors’ annual audit, such review to include an explanation from the external auditors of the factors considered in determining the audit scope, including the major risk factors, and the external auditor’s confirmation whether or not any limitations have been placed on the scope or nature of their audit procedures.

10. Inquire as to the independence of the external auditors and obtain from the external auditors, at least annually, a formal written statement delineating all relationships between the external auditors and the Corporation as contemplated by Independence Standards Board Standard No. 1, Independence Discussions with Audit Committees.

11. Arrange with the external auditors that (a) they will advise the Committee, through its Chair and management of the Corporation, of any matters identified through procedures followed for the review of interim quarterly financial statements of the Corporation, such notification is to be made prior to the related press release and (b), for written confirmation at the end of each of the first three quarters of the year, that they have nothing to report to the Committee, if that is the case, or the written enumeration of required reporting issues.

12. Review at the completion of the annual audit, with senior management, internal audit and the external auditors the following:

i. the annual financial statements and related footnotes and financial information to be included in the Corporation’s annual report to shareholders;

ii. results of the audit of the financial statements and the related report thereon and, if applicable, a report on changes during the year in accounting principles and their application;

iii. significant changes to the audit plan, if any, and any serious disputes or difficulties with management encountered during the audit;

iv. inquire about the cooperation received by the external auditors during their audit, including access to all requested records, data and information; and

v. inquire of the external auditors whether there have been any material disagreements with management, which, if not satisfactorily resolved, would have caused them to issue a non-standard report on the Corporation’s financial statements.

13. Discuss (a) with the external auditors, without management being present, (i) the quality of the Corporation’s financial and accounting personnel, and (ii) the completeness and accuracy of the Corporation’s financial statements, and (b) elicit the comments of senior management regarding the responsiveness of the external auditors to the Corporation’s needs.

14. Meet with management to discuss any relevant significant recommendations that the external auditors may have, particularly those characterized as ‘material’ or ‘serious’ (typically, such recommendations will be presented by the external auditors in the form of a Letter of Comments and Recommendations to the Committee) and review the responses of management to the Letter of Comments and Recommendations and receive follow-up reports on action taken concerning the aforementioned recommendations.

15. Review and approve disclosures required to be included in periodic reports filed with Canadian and U.S. securities regulators with respect to non-audit services performed by the external auditors.

16. Establish adequate procedures for the review of the Corporation’s disclosure of financial information extracted or derived from the Corporation’s financial statements, and periodically assess the adequacy of those procedures.

17. Establish procedures for (a) the receipt, retention and treatment of complaints received by the Corporation regarding accounting, internal accounting controls or auditing matters, and (b) the confidential, anonymous submission by employees of the Corporation of concerns regarding questionable accounting or auditing matters.

18. Review and approve the Corporation’s hiring policies regarding partners, employees and former partners and employees of the present and former external auditors.

19. Review the appointment and replacement of the senior internal audit executive.

20. Review with management, internal audit and the external auditors the methods used to establish and monitor the Corporation’s policies with respect to unethical or illegal activities by the Corporation’s employees that may have a material impact on the financial statements or other reporting of the Corporation.

21. Reviewing generally, as part of the review of the annual financial statements, a report, from the Corporation’s general counsel concerning legal, regulatory and compliance matters that may have a material impact on the financial statements or other reporting of the Corporation.

22. Review and discuss with management, on a regular basis, the identification, management and mitigation of major financial risk exposures across the Corporation. In addition, the Committee oversees the Corporation’s risk management framework and related processes.

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Reserves

23. Review, with reasonable frequency, the Corporation’s procedures relating to the disclosure of information with respect to the Corporation’s oil and gas reserves, including the Corporation’s procedures for complying with the disclosure requirements and restrictions of applicable regulatory requirements.

24. Review with management the appointment of the external qualified reserves evaluators or auditors, and in the case of any proposed change in such appointment, determine the reasons for the change and whether there have been disputes between management and the appointed external qualified reserves evaluators or auditors.

25. Review, with reasonable frequency, the Corporation’s procedures for providing information to the external qualified reserves evaluators or auditors who report on reserves and data for the purposes of compliance with applicable securities regulatory requirements.

26. Meet, before the approval and release of the Corporation’s reserves data and the report of the qualified reserve evaluators or auditors thereon, with senior management, the external qualified reserves evaluators or auditors and the internal qualified reserves evaluators to determine whether any restrictions affect their ability to report on reserves data without reservation and to review the reserves data and the report of the qualified reserves evaluators or auditors.

27. Recommend to the Board for approval of the content and filing of required statements and reports relating to the Corporation’s disclosure of reserves data as prescribed by applicable regulatory requirements.

Miscellaneous

28. Review and approve (a) any change or waiver in the Corporation’s Code of Business Conduct for the President and Chief Executive Officer and senior financial officers and (b) any public disclosure made regarding such change or waiver and, if satisfied, refer the matter to the Board for approval.

29. Act in an advisory capacity to the Board.

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

31. 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 details as is reasonably appropriate.

Effective Date: May 6, 2014

Husky Energy Inc. | Annual Information Form 2018 | 88

Appendix B

Husky Energy Inc.

Report on Reserves Data by Independent Qualified Reserves Auditor

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, 2018. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2018, 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 percent, included in the reserves data of the Company audited and reviewed for the year ended December 31, 2018, 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

Net Present Value of Future Net Revenue (Before Income Taxes, 10%

Qualified Reserves

Location of

Discount Rate)

Evaluator or

Reserves

Auditor

Effective Date

(Country)

Audited (MM$)

Evaluated (MM$)

Reviewed (MM$)

Total (MM$)

Sproule Associates Limited

December 31, 2018

Canada

16,839.4

Nil

687.1

17,526.5

China

4,438.2

Nil

—

4,438.2

Indonesia

846.5

Nil

—

846.5

22,124.1

Nil

687.1

22,811.2

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 31, 2019

/s/ Art McMullen, P. Eng.                                                                         /s/ Alec Kovaltchouk, P. Geo.

Art McMullen, P. Eng.                                                                              Alec Kovaltchouk, P. Geo.

Senior Manager, Engineering and Regional Director, Asia Pacific       VP, Geoscience

/s/ Jeff Jackson, P. Eng.                                                                             /s/ Cameron P. Six, P. Eng.

Jeff Jackson, P. Eng.                                                                                  Cameron P. Six, P. Eng.

Petroleum Engineer                                                                                    President and Chief Executive Officer

Husky Energy Inc. | Annual Information Form 2018 | 89

Appendix C

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/ Robert J. Peabody	February 25, 2019
Robert J. Peabody
President & Chief Executive Officer
/s/ Robert W. P. Symonds	February 25, 2019
Robert W. P. Symonds
Chief Operating Officer
/s/ William Shurniak	February 25, 2019
William Shurniak
Director
/s/ Stephen E. Bradley	February 25, 2019
Stephen E. Bradley
Director

Husky Energy Inc. | Annual Information Form 2018 | 90

Appendix D

Husky Energy Inc.

Independent Qualified Reserves Auditor Audit Opinion

Husky Energy Inc.

707 - 8th Avenue S.W.

Calgary, Alberta

T2P 3G7

Attention: Mr. Richard Leslie, Manager Reserves

Re: Audit of Husky Energy Inc.’s 2018 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, 2018. 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 2018 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 2018 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, 2018
	Working Interest Before Royalty Company Share of Remaining Reserves (mmboe)		Company Share of Net Present Value Before Income Tax (MM$) @ 10%
Total Proved		1,471		13,018
Total Proved Plus Probable		2,541		22,811

Sincerely,

Sproule Associates Limited

/s/ Cameron P. Six, P. Eng.

Cameron P. Six, P. Eng.

President and Chief Executive Officer

Calgary, Alberta

January 31, 2019

Husky Energy Inc. | Annual Information Form 2018 | 91

Document B

Form 40-F

Consolidated Financial Statements and

Auditors’ Report to Shareholders

For the Year Ended December 31, 2018

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders 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, 2018 and 2017, the related consolidated statements of income, comprehensive income, 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, 2018 and 2017, and the results of its financial performance and its cash flows for 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, 2018, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 25, 2019 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.

We have served as the Company’s auditor since 1951.

/s/ KPMG LLP

KPMG LLP

Chartered Professional Accountants

Calgary, Canada

February 25, 2019

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and 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, 2018, 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, 2018, 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, 2018 and 2017, the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the years then ended, and the related notes (collectively, the consolidated financial statements), and our report dated February 25, 2019 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 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

February 25, 2019

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, 2018. 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 shareholders. KPMG LLP has full and free access to the Audit Committee.

Robert J. Peabody”

Robert J. Peabody

President & Chief Executive Officer

”Jeffrey R. Hart”

Jeffrey R. Hart

Chief Financial Officer

Calgary, Canada

February 25, 2019

Husky Energy Inc. | Consolidated Financial Statements | 1

INDEPENDENT AUDITOR’S REPORT

To the Shareholders 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, 2018 and 2017, the related consolidated statements of income, comprehensive income, 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, 2018 and 2017, and the results of its financial performance and its cash flows for 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, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 25, 2019 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.

We have served as the Company’s auditor since 1951.

/s/ KPMG LLP

KPMG LLP

Chartered Professional Accountants

Calgary, Canada

February 25, 2019

Husky Energy Inc. | Consolidated Financial Statements | 2

CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Balance Sheets

(millions of Canadian dollars)	December 31, 2018		December 31, 2017
Assets
Current assets
Cash and cash equivalents (note 4)		2,866		2,513
Accounts receivable (notes 5, 24)		1,355		1,186
Income taxes receivable		112		164
Inventories (note 6)		1,232		1,513
Prepaid expenses		123		145
Restricted cash (notes 7, 16)		—		95
		5,688		5,616
Restricted cash (notes 7, 16)		128		97
Exploration and evaluation assets (note 8)		997		838
Property, plant and equipment, net (note 9)		25,800		24,078
Goodwill (note 10)		690		633
Investment in joint ventures (note 11)		1,319		1,238
Long-term income taxes receivable		243		242
Other assets (note 12)		360		185
Total Assets		35,225		32,927
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities (note 14)		3,159		3,033
Short-term debt (note 15)		200		200
Long-term debt due within one year (note 15)		1,433		—
Asset retirement obligations (note 16)		202		274
		4,994		3,507
Long-term debt (note 15)		4,114		5,240
Other long-term liabilities (note 17)		1,107		1,237
Asset retirement obligations (note 16)		2,222		2,252
Deferred tax liabilities (note 18)		3,174		2,724
Total Liabilities		15,611		14,960
Shareholders’ equity
Common shares (note 19)		7,293		7,293
Preferred shares (note 19)		874		874
Contributed surplus		2		2
Retained earnings		10,273		9,207
Accumulated other comprehensive income		1,160		580
Non-controlling interest		12		11
Total Shareholders’ Equity		19,614		17,967
Total Liabilities and Shareholders’ Equity		35,225		32,927

The accompanying notes to the consolidated financial statements are an integral part of these statements.

On behalf of the Board:
”Robert J. Peabody”	”William Shurniak”
Robert J. Peabody	William Shurniak
Director	Director

Husky Energy Inc. | Consolidated Financial Statements | 3

Consolidated Statements of Income

	Years ended December 31,
(millions of Canadian dollars, except share data)	2018			2017
Gross revenues		21,919			18,986
Royalties		(335	)		(363	)
Marketing and other		668			(40	)
Revenues, net of royalties		22,252			18,583
Expenses
Purchases of crude oil and products		14,555			11,566
Production, operating and transportation expenses (note 20)		2,803			2,679
Selling, general and administrative expenses (note 20)		654			650
Depletion, depreciation, amortization and impairment (note 9)		2,591			2,882
Exploration and evaluation expenses (note 8)		149			146
Gain on sale of assets (note 9)		(4	)		(46	)
Other – net (note 9)		(591	)		(18	)
		20,157			17,859
Earnings from operating activities		2,095			724
Share of equity investment gain (note 11)		69			61
Financial items (note 21)
Net foreign exchange gains (losses)		14			(6	)
Finance income		64			37
Finance expenses		(314	)		(392	)
		(236	)		(361	)
Earnings before income taxes		1,928			424
Provisions for (recovery of) income taxes (note 18)
Current		75			(3	)
Deferred		396			(359	)
		471			(362	)
Net earnings		1,457			786
Earnings per share (note 19)
Basic		1.41			0.75
Diluted		1.40			0.75
Weighted average number of common shares outstanding (note 19)
Basic (millions)		1,005.1			1,005.3
Diluted (millions)		1,006.1			1,005.3

The accompanying notes to the consolidated financial statements are an integral part of these statements.

Husky Energy Inc. | Consolidated Financial Statements | 4

Consolidated Statements of Comprehensive Income

	Years ended December 31,
(millions of Canadian dollars)	2018			2017
Net earnings		1,457			786
Other comprehensive income (loss)
Items that will not be reclassified into earnings, net of tax:
Remeasurements of pension plans (note 22)		46			(7	)
Items that may be reclassified into earnings, net of tax:
Derivatives designated as cash flow hedge (notes 24)		(13	)		(2	)
Equity investment – share of other comprehensive income (loss)		(2	)		3
Exchange differences on translation of foreign operations		857			(653	)
Hedge of net investment (note 24)		(262	)		243
Other comprehensive income (loss)		626			(416	)
Comprehensive income		2,083			370

The accompanying notes to the consolidated financial statements are an integral part of these statements.

Husky Energy Inc. | Consolidated Financial Statements | 5

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			Foreign Currency Translation			Hedging			Non- Controlling Interest		Total Shareholders’ Equity
Balance as at December 31, 2016		7,296			874		—		8,457			969			20			11		17,627
Net earnings		—			—		—		786			—			—			—		786
Other comprehensive income (loss)
Remeasurements of pension plans (net of tax recovery of $4 million) (notes 18, 22)		—			—		—		(7	)		—			—			—		(7	)
Derivatives designated as cash flow hedges (net of tax recovery of less than $1 million) (notes 18, 24)		—			—		—		—			—			(2	)		—		(2	)
Equity investment – share of other comprehensive income		—			—		—		—			—			3			—		3
Exchange differences on translation of foreign operations (net of tax recovery of $82 million) (note 18)		—			—		—		—			(653	)		—			—		(653	)
Hedge of net investment (net of tax expense of $38 million) (notes 18, 24)		—			—		—		—			243			—			—		243
Total comprehensive income (loss)		—			—		—		779			(410	)		1			—		370
Transactions with owners recognized directly in equity:
Dividends declared on preferred shares (note 19)		—			—		—		(34	)		—			—			—		(34	)
Share cancellation		(3	)		—		2		5			—			—			—		4
Balance as at December 31, 2017		7,293			874		2		9,207			559			21			11		17,967
Net earnings		—			—		—		1,457			—			—			—		1,457
Other comprehensive income (loss)
Remeasurements of pension plans (net of tax expense of $17 million) (notes 18, 22)		—			—		—		46			—			—			—		46
Derivatives designated as cash flow hedges (net of tax recovery of $5 million) (notes 18, 24)		—			—		—		—			—			(13	)		—		(13	)
Equity investment – share of other comprehensive loss		—			—		—		—			—			(2	)		—		(2	)
Exchange differences on translation of foreign operations (net of tax expense of $87 million) (note 18)		—			—		—		—			857			—			—		857
Hedge of net investment (net of tax recovery of $41 million) (notes 18, 24)		—			—		—		—			(262	)		—			—		(262	)
Total comprehensive income (loss)		—			—		—		1,503			595			(15	)		—		2,083
Transactions with owners recognized directly in equity:
Dividends declared on common shares (note 19)		—			—		—		(402	)		—			—			—		(402	)
Dividends declared on preferred shares (note 19)		—			—		—		(35	)		—			—			—		(35	)
Non-controlling interest in subsidiary		—			—		—		—			—			—			1		1
Balance as at December 31, 2018		7,293			874		2		10,273			1,154			6			12		19,614

⁽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 | 6

Consolidated Statements of Cash Flows

	Years ended December 31,
(millions of Canadian dollars)	2018			2017
Operating activities
Net earnings		1,457			786
Items not affecting cash:
Accretion (notes 16, 21)		97			112
Depletion, depreciation, amortization and impairment (note 9)		2,591			2,882
Inventory write-down to net realizable value (note 6)		60			—
Exploration and evaluation expenses (note 8)		29			6
Deferred income taxes (note 18)		396			(359	)
Foreign exchange		(6	)		(4	)
Stock-based compensation (notes 19, 20)		44			45
Gain on sale of assets (note 9)		(4	)		(46	)
Unrealized mark to market loss (gain) (note 24)		(150	)		56
Share of equity investment gain (note 11)		(69	)		(61	)
Gain on insurance recoveries for damage to property (note 9)		(253	)		—
Other		21			16
Settlement of asset retirement obligations (note 16)		(181	)		(136	)
Deferred revenue (note 17)		(100	)		(16	)
Distribution from joint ventures (note 11)		72			25
Change in non-cash working capital (note 23)		130			398
Cash flow – operating activities		4,134			3,704
Financing activities
Long-term debt issuance (note 15)		—			750
Long-term debt repayment (note 15)		—			(365	)
Debt issue costs (note 15)		—			(6	)
Dividends on common shares (note 19)		(402	)		—
Dividends on preferred shares (note 19)		(35	)		(34	)
Other		(8	)		18
Change in non-cash working capital (note 23)		120			—
Cash flow – financing activities		(325	)		363
Investing activities
Capital expenditures		(3,578	)		(2,220	)
Capitalized interest (note 21)		(108	)		(68	)
Corporate acquisition (note 9)		(15	)		(670	)
Proceeds from asset sales (note 9)		4			192
Contribution payable payment (note 11)		—			(142	)
Contribution to joint ventures (note 11)		(40	)		(81	)
Other		(19	)		(40	)
Change in non-cash working capital (note 23)		235			240
Cash flow – investing activities		(3,521	)		(2,789	)
Increase in cash and cash equivalents		288			1,278
Effect of exchange rates on cash and cash equivalents		65			(84	)
Cash and cash equivalents at beginning of year		2,513			1,319
Cash and cash equivalents at end of year		2,866			2,513
Supplementary cash flow information
Net interest paid		(285	)		(344	)
Net Income taxes received (paid)		(37	)		41

The accompanying notes to the consolidated financial statements are an integral part of these statements.

Husky Energy Inc. | Consolidated Financial Statements | 7

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 are 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 are 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 707, 8th Avenue S.W., PO Box 6525, Station D, Calgary, Alberta, T2P 3G7.

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 – Upstream and Downstream.

Upstream operations in the Integrated Corridor and Offshore include exploration for, and development and production of, crude oil, bitumen, natural gas and natural gas liquids (“NGL”) (“Exploration and Production”) and the marketing of the Company’s and other producers’ crude oil, natural gas, NGLs, sulphur and petroleum coke. Additionally, it includes pipeline transportation, the blending of crude oil and natural gas, and storage of crude oil, diluent and natural gas (“Infrastructure and Marketing”). Infrastructure and Marketing markets and distributes products to customers on behalf of Exploration and Production and is grouped in the Upstream business segment based on the nature of its interconnected operations. The Company’s Upstream operations are located primarily in Alberta, Saskatchewan, and British Columbia (“Western Canada”), offshore east coast of Canada (“Atlantic”) and offshore China and offshore Indonesia (“Asia Pacific”).

Downstream operations in the Integrated Corridor include upgrading of heavy crude oil feedstock into synthetic crude oil in Canada (“Upgrading”), refining crude oil in Canada, marketing of refined petroleum products including gasoline, diesel, ethanol blended fuels, asphalt and ancillary products, and production of ethanol (“Canadian Refined Products”). It also includes refining in the U.S. of primarily crude oil to produce and market asphalt, gasoline, jet fuel and diesel fuels that meet U.S. clean fuels standards (“U.S. Refining and Marketing”). Upgrading, Canadian Refined Products and U.S. Refining and Marketing all process and refine natural resources into marketable products and are grouped together as the Downstream business segment due to the similar nature of their products and services.

Husky Energy Inc. | Consolidated Financial Statements | 8

Segmented Financial Information

	Upstream
	Exploration and Production(1)						Infrastructure and Marketing(2)						Total
($ millions)
Year ended December 31,	2018			2017			2018			2017			2018			2017
Gross revenues		4,330			4,978			2,211			1,976			6,541			6,954
Royalties		(335	)		(363	)		—			—			(335	)		(363	)
Marketing and other		—			—			668			(40	)		668			(40	)
Revenues, net of royalties		3,995			4,615			2,879			1,936			6,874			6,551
Expenses
Purchases of crude oil and products		—			—			2,087			1,855			2,087			1,855
Production, operating and transportation expenses		1,527			1,650			23			13			1,550			1,663
Selling, general and administrative expenses		296			265			5			4			301			269
Depletion, depreciation, amortization and impairment		1,811			2,237			—			2			1,811			2,239
Exploration and evaluation expenses		149			146			—			—			149			146
Loss (gain) on sale of assets		(2	)		(42	)		—			1			(2	)		(41	)
Other – net		(120	)		6			2			(8	)		(118	)		(2	)
		3,661			4,262			2,117			1,867			5,778			6,129
Earnings (loss) from operating activities		334			353			762			69			1,096			422
Share of equity investment gain		51			12			18			49			69			61
Financial items
Net foreign exchange gain (loss)		—			—			—			—			—			—
Finance income		12			5			—			—			12			5
Finance expenses		(109	)		(131	)		—			—			(109	)		(131	)
		(97	)		(126	)		—			—			(97	)		(126	)
Earnings (loss) before income taxes		288			239			780			118			1,068			357
Provisions for (recovery of) income taxes
Current		(484	)		(34	)		354			—			(130	)		(34	)
Deferred		549			99			(141	)		32			408			131
		65			65			213			32			278			97
Net earnings (loss)		223			174			567			86			790			260
Intersegment revenues		1,155			1,250			—			—			1,155			1,250

⁽¹⁾  Includes allocated depletion, depreciation, amortization and impairment related to assets in Infrastructure and Marketing, as these assets provide a service to Exploration and Production.

⁽²⁾  Includes $172 million of revenue (2017 - $280 million) and $142 million of associated costs (2017 - $234 million) for construction contracts, inclusive of $172 million of revenue (2017 - $259 million) and $142 million of costs (2017 - $236 million) for contracts in progress accounted for under the percentage of completion method.

⁽³⁾ 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.

Husky Energy Inc. | Consolidated Financial Statements | 9

Segmented Financial Information Con’t

Downstream																								Corporate and Eliminations(3)						Total
Upgrading						Canadian Refined Products						U.S. Refining and Marketing						Total
2018			2017			2018			2017			2018			2017			2018			2017			2018			2017			2018			2017
	1,750			1,440			3,412			2,787			11,770			9,355			16,932			13,582			(1,554	)		(1,550	)		21,919			18,986
	—			—			—			—			—			—			—			—			—			—			(335	)		(363	)
	—			—			—			—			—			—			—			—			—			—			668			(40	)
	1,750			1,440			3,412			2,787			11,770			9,355			16,932			13,582			(1,554	)		(1,550	)		22,252			18,583
	928			983			2,760			2,219			10,334			8,059			14,022			11,261			(1,554	)		(1,550	)		14,555			11,566
	195			197			265			256			795			563			1,255			1,016			(2	)		—			2,803			2,679
	7			9			47			53			22			15			76			77			277			304			654			650
	123			99			115			111			450			354			688			564			92			79			2,591			2,882
	—			—			—			—			—			—			—			—			—			—			149			146
	—			—			(2	)		(5	)		—			—			(2	)		(5	)		—			—			(4	)		(46	)
	—			—			(1	)		(1	)		(464	)		(21	)		(465	)		(22	)		(8	)		6			(591	)		(18	)
	1,253			1,288			3,184			2,633			11,137			8,970			15,574			12,891			(1,195	)		(1,161	)		20,157			17,859
	497			152			228			154			633			385			1,358			691			(359	)		(389	)		2,095			724
	—			—			—			—			—			—			—			—			—			—			69			61
	—			—			—			—			—			—			—			—			14			(6	)		14			(6	)
	—			—			—			—			—			—			—			—			52			32			64			37
	(1	)		(1	)		(12	)		(12	)		(14	)		(14	)		(27	)		(27	)		(178	)		(234	)		(314	)		(392	)
	(1	)		(1	)		(12	)		(12	)		(14	)		(14	)		(27	)		(27	)		(112	)		(208	)		(236	)		(361	)
	496			151			216			142			619			371			1,331			664			(471	)		(597	)		1,928			424
	168			63			100			45			9			2			277			110			(72	)		(79	)		75			(3	)
	(33	)		(22	)		(42	)		(7	)		129			135			54			106			(66	)		(596	)		396			(359	)
	135			41			58			38			138			137			331			216			(138	)		(675	)		471			(362	)
	361			110			158			104			481			234			1,000			448			(333	)		78			1,457			786
	290			192			109			108			—			—			399			300			—			—			1,554			1,550

Husky Energy Inc. | Consolidated Financial Statements | 10

Segmented Financial Information

	Upstream
($ millions)	Exploration and Production(1)						Infrastructure and Marketing						Total
Year ended December 31,	2018			2017			2018			2017			2018			2017
Expenditures on exploration and evaluation assets(2)		242			148			—			—			242			148
Expenditures on property, plant and equipment(2)		2,414			1,328			—			—			2,414			1,328
As at December 31,
Exploration and evaluation assets		997			838			—			—			997			838
Developing and producing assets at cost		44,196			41,804			—			—			44,196			41,804
Accumulated depletion, depreciation, amortization and impairment		(27,379	)		(26,014	)		—			—			(27,379	)		(26,014	)
Other property, plant and equipment at cost		—			—			101			89			101			89
Accumulated depletion, depreciation and amortization		—			—			(50	)		(50	)		(50	)		(50	)
Total exploration and evaluation assets and property, plant and equipment, net		17,814			16,628			51			39			17,865			16,667
Total assets		19,175			17,920			1,301			1,364			20,476			19,284

⁽¹⁾  Includes allocated depletion, depreciation, amortization and impairment related to assets in Infrastructure and Marketing, as these assets provide a service to Exploration and Production.

⁽²⁾ Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the year. Includes Exploration and Production assets acquired through acquisition, but excludes assets acquired through corporate acquisition.

Geographical Financial Information

($ millions)	Canada						United States
Year ended December 31,	2018			2017			2018		2017
Gross revenues(1)		9,000			8,599			11,770		9,355
Royalties		(269	)		(303	)		—		—
Marketing and other		668			(40	)		—		—
Revenue, net of royalties		9,399			8,256			11,770		9,355
As at December 31,
Restricted cash – non-current		—			—			—		—
Exploration and evaluation assets		935			831			—		—
Property, plant and equipment, net		16,433			15,478			6,336		5,595
Goodwill		—			—			690		633
Investment in joint ventures		669			685			—		—
Long-term income tax receivable		243			242			—		—
Other assets(2)		58			64			276		21
Total non-current assets		18,338			17,300			7,302		6,249

⁽¹⁾ Sales to external customers are based on the location of the seller.

⁽²⁾ Includes insurance proceeds of $253 million (2017 - nil), related to the Superior Refinery incident.

Husky Energy Inc. | Consolidated Financial Statements | 11

Segmented Financial Information Con’t

Downstream																								Corporate and Eliminations						Total
Upgrading						Canadian Refined Products						U.S. Refining and Marketing						Total
2018			2017			2018			2017			2018			2017			2018			2017			2018			2017			2018			2017
	—			—			—			—			—			—			—			—			—			—			242			148
	62			230			74			87			665			313			801			630			121			114			3,336			2,072
	—			—			—			—			—			—			—			—			—			—			997			838
	—			—			—			—			—			—			—			—			—			—			44,196			41,804
	—			—			—			—			—			—			—			—			—			—			(27,379	)		(26,014	)
	2,659			2,600			2,789			2,704			9,746			8,300			15,194			13,604			1,251			1,124			16,546			14,817
	(1,585	)		(1,463	)		(1,581	)		(1,466	)		(3,410	)		(2,705	)		(6,576	)		(5,634	)		(937	)		(845	)		(7,563	)		(6,529	)
	1,074			1,137			1,208			1,238			6,336			5,595			8,618			7,970			314			279			26,797			24,916
	1,149			1,263			1,431			1,548			8,566			7,580			11,146			10,391			3,603			3,252			35,225			32,927

Geographical Financial Information Con’t

China						Other International				Total
2018			2017			2018		2017		2018			2017
	1,149			1,032			—		—		21,919			18,986
	(66	)		(60	)		—		—		(335	)		(363	)
	—			—			—		—		668			(40	)
	1,083			972			—		—		22,252			18,583
	128			97			—		—		128			97
	57			3			5		4		997			838
	3,030			3,005			1		—		25,800			24,078
	—			—			—		—		690			633
	—			—			650		553		1,319			1,238
	—			—			—		—		243			242
	—			78			26		22		360			185
	3,215			3,183			682		579		29,537			27,311

Husky Energy Inc. | Consolidated Financial Statements | 12

Disaggregation of Revenue

	Upstream
($ millions)	Exploration and Production(1)				Infrastructure and Marketing				Total
Year ended December 31,	2018		2017		2018		2017		2018		2017
Primary Geographical Markets
Canada		3,181		3,946		2,211		1,976		5,392		5,922
United States		—		—		—		—		—		—
China		1,149		1,032		—		—		1,149		1,032
Total revenue		4,330		4,978		2,211		1,976		6,541		6,954
Major Product Lines
Light & medium crude oil		948		1,273		—		—		948		1,273
Heavy crude oil		527		703		—		—		527		703
Bitumen		1,367		1,662		—		—		1,367		1,662
Total crude oil		2,842		3,638		—		—		2,842		3,638
NGL		381		276		—		—		381		276
Natural gas		1,107		1,064		—		—		1,107		1,064
Total exploration and production		4,330		4,978		—		—		4,330		4,978
Total infrastructure and marketing		—		—		2,211		1,976		2,211		1,976
Synthetic crude		—		—		—		—		—		—
Gasoline		—		—		—		—		—		—
Diesel & distillates		—		—		—		—		—		—
Asphalt		—		—		—		—		—		—
Other		—		—		—		—		—		—
Total refined products		—		—		—		—		—		—
Total revenue		4,330		4,978		2,211		1,976		6,541		6,954

Husky Energy Inc. | Consolidated Financial Statements | 13

Disaggregation of Revenue Con’t

Downstream																Corporate and Eliminations						Total
				Canadian Refined				U.S. Refining
Upgrading				Products				and Marketing				Total
2018		2017		2018		2017		2018		2017		2018		2017		2018			2017			2018		2017
	1,750		1,440		3,412		2,787		—		—		5,162		4,227		(1,554	)		(1,550	)		9,000		8,599
	—		—		—		—		11,770		9,355		11,770		9,355		—			—			11,770		9,355
	—		—		—		—		—		—		—		—		—			—			1,149		1,032
	1,750		1,440		3,412		2,787		11,770		9,355		16,932		13,582		(1,554	)		(1,550	)		21,919		18,986
	—		—		—		—		—		—		—		—		—			—			948		1,273
	—		—		—		—		—		—		—		—		—			—			527		703
	—		—		—		—		—		—		—		—		—			—			1,367		1,662
	—		—		—		—		—		—		—		—		—			—			2,842		3,638
	—		—		—		—		—		—		—		—		—			—			381		276
	—		—		—		—		—		—		—		—		—			—			1,107		1,064
	—		—		—		—		—		—		—		—		—			—			4,330		4,978
	—		—		—		—		—		—		—		—		—			—			2,211		1,976
	1,445		1,235		—		—		—		—		1,445		1,235		—			—			1,445		1,235
	—		—		1,070		925		6,157		5,198		7,227		6,123		—			—			7,227		6,123
	278		196		1,303		917		4,297		3,435		5,878		4,548		—			—			5,878		4,548
	—		—		454		362		165		31		619		393		—			—			619		393
	27		9		585		583		1,151		691		1,763		1,283		—			—			1,763		1,283
	1,750		1,440		3,412		2,787		11,770		9,355		16,932		13,582		—			—			16,932		13,582
	1,750		1,440		3,412		2,787		11,770		9,355		16,932		13,582		(1,554	)		(1,550	)		21,919		18,986

Husky Energy Inc. | Consolidated Financial Statements | 14

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 and signed by the Chair of the Audit Committee and the Chief Executive Officer on February 25, 2019 having been duly authorized to do so by the Board of Directors.

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 11), 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.

Significant estimates, judgments and assumptions made by management in the preparation of these consolidated financial statements are outlined in detail in Note 3.

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.

Husky Energy Inc. | Consolidated Financial Statements | 15

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 (m). Any changes in commodity trading inventory fair value are included as gains or losses in Marketing and Other in the consolidated statements of income, 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 earnings. 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.

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 | 16

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 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 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, 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 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, less any estimated residual value. The useful lives of assets are estimated based upon the period the asset is expected to be available for use by the Company. Residual values are based upon the estimated amount that would be obtained on disposal, net of any costs associated with the disposal. Other property, plant and equipment held under finance leases are depreciated over the shorter of the lease term and the estimated useful life of the asset.

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.

Husky Energy Inc. | Consolidated Financial Statements | 17

vi) Finance Leases

Finance leases, which transfer substantially all of the risks and rewards incidental to ownership of the leased item to the Company, are capitalized at the commencement of the lease term at the fair value of the lease property or, if lower, at the present value of the minimum lease payments. Capitalized leased assets are depreciated over the shorter of the estimated useful life of the asset or the lease term.

All other leases are accounted for as operating leases and the lease costs are expensed as incurred.

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) Investments in Associates

An associate is an entity for which the Company has significant influence and thereby has the power to participate in the financial and operational decisions but does not control or jointly control the investee. Investments in associates are accounted for using the equity method of accounting and are recognized at cost and adjusted thereafter for the post-acquisition change in the Company’s share of the investee’s net assets. The Company’s consolidated financial statements include its share of the investee’s profit or loss and OCI until the date that significant influence ceases.

g) 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 earnings. Acquisition costs incurred are expensed and included in selling, general and administrative expenses in the consolidated statements of income.

h) 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 earnings 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.

Husky Energy Inc. | Consolidated Financial Statements | 18

i) 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, 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, 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.

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 income.

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.

j) 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.

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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 earnings. 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.

k) 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 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 earnings. The Company continually monitors known and potential contingent matters and makes appropriate disclosure and provisions when warranted by the circumstances present.

l) 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.

m) 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 income, 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 profit or 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.

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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.

n) 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 income 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 earnings.

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 earnings 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 earnings over the remaining maturity of the hedged item.

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 earnings. 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 earnings in the period of discontinuation.

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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.

o) Comprehensive Income

Comprehensive income consists of net earnings 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.

p) 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 earnings. 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.

q) Pensions and Other Post-employment Benefits

In Canada, the Company provides a defined contribution pension plan and other post-retirement benefits to qualified employees. The Company also maintains a defined benefit pension plan for a small number of employees who did not choose to join the defined contribution pension plan in 1991. In the United States, the Company provides two defined contribution pension plans (401(k)) and one other post-retirement benefits plan. The Company also maintains a small defined benefit pension plan for the employees of the Superior Refinery.

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.

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.

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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 country 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.

r) Income Taxes

Current income tax is recognized in net earnings 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. Any interest and penalties on income taxes are recognized in interest expense and interest payable. 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 earnings 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 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.

s) 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 income in the period they occur.

t) 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 obligations for returns, refunds, warranties or similar obligations.

i) Nature of Goods or Services

The following is a description of the principal activities, by operating segment, from which the Company generates revenue.

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a) Upstream

The Upstream segment includes Exploration and Production, and Infrastructure and Marketing.

i) Exploration and Production

Exploration and Production principally generates revenue from the sale of crude oil, bitumen, natural gas, and NGLs, as well as crude oil and natural gas processing services. Performance obligations associated with sales of these products are satisfied at the point in time when the products are delivered to and title passes to the customer. Performance obligations associated with the sale of processing services are satisfied at the point in time when the services are provided. Royalties are recognized as a reduction to gross revenues. Sales, services and royalties are billed and paid on a monthly basis.

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 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 product can no longer be taken. 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, performance obligation is satisfied, and revenue is recognized when the take-or-pay penalty is triggered.

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.

ii) Infrastructure and Marketing

Infrastructure and Marketing principally generates revenue from marketing the Company’s and other producers’ crude oil, natural gas, NGL, sulphur and petroleum coke, pipeline transportation, the blending of crude oil and natural gas, and storage of crude oil, diluent and natural gas. Performance obligations associated with sales of these products are satisfied at the point in time when the products are delivered to and title passes to the customer. Performance obligations associated with transportation, blending and storage are satisfied at the point in time when the services are provided. Sales, services and royalties are billed and paid on a monthly basis. Infrastructure and Marketing also includes revenue from construction services provided to Husky Midstream Limited Partnership (“HMLP”), of which the Company owns 35 percent. The Company acts as the general contractor for HMLP projects for fixed price and cost plus contracts. Revenue from fixed price contracts is recognized using the percentage of completion method based on costs incurred. Revenue from cost plus contracts are recognized as services are performed. Construction services are billed and paid on a monthly basis, with unbilled percentage of completion payments billed on completion of the project.

b) Downstream

The Downstream segment includes Upgrading, Canadian Refined Products, and U.S. Refining and Marketing.

i) Upgrading

Upgrading principally generates revenue from the sale of synthetic crude oil in Canada, upgraded from heavy oil feedstock. Performance obligations associated with sales of these products are satisfied at the point in time when the products are delivered to and title passes to the customer. Sales are billed and paid on a monthly basis.

ii) Canadian Refined Products

Canadian Refined Products principally generates revenue from refining of crude oil and marketing of refined petroleum products, including gasoline, diesel, ethanol blended fuels, asphalt and ancillary products, and production of ethanol. Canadian Refined Products also includes, the Company’s retail gasoline and diesel distribution and sales network. Performance obligations associated with sales of these products are satisfied at the point in time when the products are delivered to and title passes to the customer. Performance obligations associated with marketing services are satisfied when the services are performed. Sales for retail gasoline, diesel and ancillary products are billed and paid upon delivery. All other sales and services are billed and paid on a weekly or monthly basis.

iii) U.S. Refining and Marketing

U.S. Refining and Marketing primarily generates revenue from refining crude oil to produce and market gasoline, jet fuel and diesel fuels. Performance obligations associated with sale of these products are satisfied at the point in time when the products are delivered to and title passes to the customer. All sales are billed and paid on a weekly or monthly basis.

Performance obligations associated with the sale of crude oil, natural gas, natural gas liquids, synthetic crude oil, purchased commodities and refined petroleum products are satisfied at the point in time when the products are delivered to and title passes to the customer. Performance obligations associated with the sale of transportation, processing and natural gas storage services are satisfied at the point in time when the services are provided. All amounts are due upon delivery of goods or when services are provided.

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c) Corporate and Eliminations

Corporate and Eliminations primarily generates revenue from finance income. Finance income is recognized as the interest accrues using the effective interest rate, which is the rate that discounts estimated future cash receipts through the expected life of the financial instrument to the net carrying amount of the financial asset. Corporate and Eliminations also includes the elimination of sales of crude oil, bitumen, natural gas and NGLs between segments.

u) 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 earnings. 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.

v) 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 earnings 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 earnings. 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 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 earnings is adjusted for the difference 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.

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w) Earnings 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 earnings per common share is based on net earnings 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 earnings per share is based on net earnings 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 earnings 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 earnings. As a result, net earnings 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 earnings per share calculation.

x) 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 earnings in equal amounts over the expected useful life of the related asset through lower depletion, depreciation and amortization.

y) 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. These transactions are on terms equivalent to those that prevail in arm’s length transactions, unless otherwise noted. 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.

Revenue from fixed price construction contracts are recognized using the percentage of completion method based on costs incurred, which requires estimating the expected costs to complete a project. Changes in these assumptions may result in a material difference in the construction revenue recognized. See Note 25.

z) Recent Accounting Standards

The Company has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective.

i) Leases

In January 2016, the IASB issued IFRS 16 Leases, which replaces the current IFRS guidance on leases. Under the current guidance, lessees are required to determine if the lease is a finance or operating lease, based on specified criteria. Finance leases are recognized on the balance sheet while operating leases are recognized in the consolidated statements of income when the expense is incurred. Under IFRS 16, lessees must recognize a lease liability and a right-of-use asset for virtually all lease contracts. The recognition of the present value of minimum lease payments for certain contracts currently classified as operating leases will result in increases to assets, liabilities, depletion, depreciation and amortization, and finance expense, and a decrease to production, operating and transportation expense upon implementation. Optional exemptions to not recognize certain short-term leases or leases of low value can be applied by lessees. For lessors, the accounting remains essentially unchanged.

The Company will adopt IFRS 16 on the effective date of January 1, 2019 and has selected the modified retrospective transition approach. The optional exemptions to not recognize certain short-term and low value leases will be applied.

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For leases implemented January 1, 2019, the Company will recognize a right-of-use asset of $1.1 billion equal to the lease liability at the present value of the remaining lease payments discounted using the Company’s incremental borrowing rate. The implementation of IFRS 16 does not have a material impact on the consolidated statements of income. Due to a change in classification of operating lease expenses, cash flow from operating activities will increase and cash flow from financing activities will decrease, with no overall impact to the cash position for the Company.

aa) Change in Accounting Policy

i) Revenue from Contracts with Customers

In September 2015, the IASB published an amendment to IFRS 15 Revenue from Contracts with Customers, deferring the effective date to annual periods beginning on or after January 1, 2018. IFRS 15 replaces existing revenue recognition guidance with a single comprehensive accounting model. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive when control is transferred to the purchaser. The Company retrospectively adopted the standard on January 1, 2018. The adoption of IFRS 15 did not require any material adjustments to the amounts recorded in the consolidated financial statements; however, additional disclosures are presented in the consolidated financial statements.

Revenue is recognized when the performance obligations are satisfied and revenue can be reliably measured. Revenue is measured at the consideration specified in the contracts and represents amounts receivable for goods or services provided in the normal course of business, net of discounts, customs duties and sales taxes. Natural gas sales in Asia Pacific are under long-term, fixed price contracts. Substantially all other revenue is based on floating prices. Performance obligations associated with the sale of crude oil, crude oil equivalents, and refined products are satisfied at the point in time when the products are delivered to and title passes to the customer. Performance obligations associated with processing services, transportation, blending and storage, and marketing services are satisfied at the point in time when the services are provided.

ii) Financial Instruments

In July 2014, the IASB issued IFRS 9 Financial Instruments to replace IAS 39, which provides a single model for classification and measurement based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial instruments. For financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in other comprehensive income rather than net earnings, unless this creates an accounting mismatch. IFRS 9 includes a new, forward-looking ‘expected loss’ impairment model that will result in a more timely recognition of expected credit losses. In addition, IFRS 9 provides a substantially-reformed approach to hedge accounting. The standard was effective for annual periods beginning on January 1, 2018. The Company retrospectively adopted the standard on January 1, 2018. The adoption of IFRS 9 did not require any material adjustments to the consolidated financial statements.

Financial assets previously classified as loans and receivables (cash and cash equivalents, accounts receivable, restricted cash, and long-term receivables), as well as financial liabilities previously classified as other financial liabilities (accounts payable and accrued liabilities, short-term debt, and long-term debt) have been reclassified to amortized cost. The carrying value and measurement of all financial instruments remains unchanged. The Company’s current process for assessing short-term receivables lifetime expected credit losses collectively in groups that share similar credit risk characteristics is unadjusted with the adoption of the new impairment model and resulted in no additional impairment allowance. Additionally, long-term receivables were assessed individually under the expected credit loss model and no impairment was concluded.

iii) Amendments to IFRS 2 Share-based payment

In June 2016, the IASB issued amendments to IFRS 2 to be applied prospectively for annual periods beginning on or after January 1, 2018. The amendments clarify how to account for certain types of share-based payment arrangements. The adoption of the amendments did not have a material impact on the Company’s consolidated financial statements.

Husky Energy Inc. | Consolidated Financial Statements | 27

Note 4 Cash and Cash Equivalents

Cash and cash equivalents at December 31, 2018 included $187 million of cash (December 31, 2017 – $280 million) and $2,679 million of short-term investments with original maturities less than three months at the time of purchase (December 31, 2017 – $2,233 million).

Note 5 Accounts Receivable

Accounts Receivable

($ millions)	December 31, 2018			December 31, 2017
Trade receivables		1,146			1,170
Provision for expected credit losses		(39	)		(34	)
Derivatives due within one year		43			17
Other(1)		205			33
End of year		1,355			1,186

⁽¹⁾  Includes insurance proceeds of $143 million (2017—nil), related to the Superior Refinery incident.

Note 6 Inventories

Inventories

($ millions)	December 31, 2018		December 31, 2017
Crude oil, natural gas and NGL		445		539
Refined petroleum products		435		548
Trading inventories measured at fair value less costs to sell		200		237
Materials, supplies and other		152		189
End of year		1,232		1,513

Impairment of inventory to net realizable value for the year ended December 31, 2018 was $60 million (December 31, 2017 – nil), 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. Refer to Note 24.

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, 2018, the Company had deposited funds of $128 million which have been classified as non-current (2017 – $97 million). As at December 31, 2017, the Company deposited funds of $192 million, of which $95 million related to the Wenchang field and was classified as current. The Company’s participation in the Wenchang field expired in November 2017, and the amount of the decommissioning and disposal expenses was finalized in January 2018.

Husky Energy Inc. | Consolidated Financial Statements | 28

Note 8 Exploration and Evaluation Costs

Exploration and Evaluation Assets

($ millions)	2018			2017
Beginning of year		838			1,066
Additions		287			224
Disposals		(23	)		—
Transfers to oil and gas properties (note 9)		(79	)		(377	)
Expensed exploration expenditures previously capitalized		(29	)		(6	)
Exchange adjustments		3			(69	)
End of year		997			838

The following exploration and evaluation expenses for the years ended December 31, 2018 and 2017 relate to activities associated with the exploration for and evaluation of crude oil and natural gas resources and were recorded in the Upstream Exploration and Production business.

Exploration and Evaluation Expense Summary

($ millions)	2018		2017
Seismic, geological and geophysical		102		113
Expensed drilling		41		22
Expensed land		6		11
		149		146

Husky Energy Inc. | Consolidated Financial Statements | 29

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, 2016		44,801			137			2,367			8,645			2,755			58,705
Additions(1)		1,371			11			230			561			140			2,313
Acquisitions		29			—			—			577			—			606
Transfers from exploration and evaluation (note 8)		377			—			—			—			—			377
Intersegment transfers		48			(61	)		—			—			13			—
Changes in asset retirement obligations (note 16)		150			—			2			13			23			188
Disposals and derecognition		(4,702	)		—			—			(39	)		—			(4,741	)
Exchange adjustments		(259	)		(1	)		—			(566	)		(1	)		(827	)
December 31, 2017		41,815			86			2,599			9,191			2,930			56,621
Additions		2,465			12			62			744			151			3,434
Acquisitions		64			—			—			3			—			67
Transfers from exploration and evaluation (note 8)		79			—			—			—			—			79
Intersegment transfers		—			—			—			(5	)		5			—
Changes in asset retirement obligations (note 16)		43			2			(2	)		(5	)		7			45
Disposals and derecognition		(632	)		—			—			(10	)		(1	)		(643	)
Exchange adjustments		362			1			—			773			3			1,139
December 31, 2018		44,196			101			2,659			10,691			3,095			60,742
Accumulated depletion, depreciation, amortization and impairment
December 31, 2016		(27,986	)		(96	)		(1,363	)		(2,975	)		(1,692	)		(34,112	)
Depletion, depreciation, amortization and impairment		(2,238	)		(2	)		(99	)		(406	)		(137	)		(2,882	)
Intersegment transfers		(37	)		50			—			—			(13	)		—
Disposals and derecognition		4,124			—			—			16			—			4,140
Exchange adjustments		121			1			—			189			—			311
December 31, 2017		(26,016	)		(47	)		(1,462	)		(3,176	)		(1,842	)		(32,543	)
Depletion, depreciation, amortization and impairment		(1,811	)		(2	)		(123	)		(503	)		(152	)		(2,591	)
Disposals and derecognition		586			—			—			10			—			596
Exchange adjustments		(138	)		(1	)		—			(264	)		(1	)		(404	)
December 31, 2018		(27,379	)		(50	)		(1,585	)		(3,933	)		(1,995	)		(34,942	)
Net book value
December 31, 2017		15,799			39			1,137			6,015			1,088			24,078
December 31, 2018		16,817			51			1,074			6,758			1,100			25,800

⁽¹⁾ Additions include assets under finance lease.

Depletion, depreciation, amortization and impairment for the year ended December 31, 2018 included a $56 million derecognition of the carrying value reflected in the second and third quarter of 2018 for damage caused by an incident at the Superior Refinery in the Company’s U.S Refining and Marketing segment (December 31, 2017—a pre-tax impairment expense of $173 million in the Upstream Exploration and Production segment).

In addition, the Company accrued pre-tax recoveries for property damage, rebuild costs, business interruption and clean-up costs associated with the Superior Refinery incident of $468 million for the year ended December 31, 2018, which is included in other-net in the consolidated statements of income.

The provisions for derecognition and insurance recoveries are based on management’s best estimates as at December 31, 2018, with measurement uncertainty around the provision for property damage, and business interruption insurance recoveries. As the assessment of damage is ongoing, the provisions may be subject to changes.

Costs of property, plant and equipment, including major development projects, not subject to depletion, depreciation and amortization as at December 31, 2018 were $5.2 billion (December 31, 2017 – $2.8 billion) including undeveloped land assets of $117 million as at December 31, 2018 (December 31, 2017 – $57 million).

Husky Energy Inc. | Consolidated Financial Statements | 30

The net book values of assets held under finance lease within property, plant and equipment are as follows:

Assets Under Finance Lease

($ millions)	Refining		Oil and Gas Properties		Total
December 31, 2017		152		335		487
December 31, 2018		141		323		464

Assets Dispositions

During 2017, the Company completed the sale of select assets in Western Canada to third parties for gross proceeds of approximately $185 million, resulting in a pre-tax gain of $46 million and an after-tax gain of $36 million. The assets and related liabilities were recorded in the Upstream Exploration and Production segment.

Assets Acquisitions

On November 8, 2017, the Company completed the purchase of the Superior Refinery, a 50,000 bbls/day permitted capacity facility located in Superior, Wisconsin, U.S., from Calumet Specialty Products Partners, L.P. (“Calumet”) for $670 million (US$527 million).

The acquisition has been accounted for as a business combination using the acquisition method.

Purchase Price Allocation

($ millions)	USD			CAD
Working capital		85			108
Property, plant and equipment		454			577
Asset retirement obligation		(7	)		(9	)
Other long-term liabilities		(5	)		(6	)
Net assets acquired		527			670

The fair values of accounts receivable and accounts payable approximate their carrying values due to their short-term nature. The fair value of inventory was determined using quoted prices. The fair values of property, plant and equipment were determined based on a cost and future cash flow approach. For the cost approach, key assumptions included the cost to construct the assets and the remaining useful life. For the cash flow approach, key assumptions were the discount rate and future commodity prices. The decommissioning provision was based on the fair value of estimated future reclamation costs. Key assumptions included discount rates, cost estimates and timeline to abandon and reclaim the refinery.

The acquisition of Superior Refinery contributed $163 million to gross revenues and a loss of $13 million to consolidated net earnings from the acquisition date to December 31, 2017.

Had the acquisition occurred on January 1, 2017, the Superior Refinery would have contributed $1.1 billion to gross revenues and $93 million to consolidated net earnings, which would have resulted in gross revenues of $19.9 billion and consolidated net earnings of $892 million for the year ended December 31, 2017.

Husky Energy Inc. | Consolidated Financial Statements | 31

Note 10 Goodwill

Goodwill

($ millions)	December 31, 2018		December 31, 2017
Beginning of year		633		679
Exchange adjustments		57		(46	)
End of year		690		633

As at December 31, 2018, the Company’s goodwill balance related entirely to the Lima Refinery. For impairment testing purposes, the recoverable amount of the Lima Refinery CGU was estimated using the higher of FVLCS and VIU methodology based on cash flows expected over a 50-year period and discounted using an after-tax discount rate of 8 percent.

Management used the higher of FVLCS and VIU calculations for the Lima Refinery CGU, which are sensitive to changes in discount rate, forecasted crack spreads and growth rate. The discount rate is derived from the post-tax weighted average cost of capital, of a group of relevant peers, considered to represent the rate of return that would be required by a typical market participant for similar assets, with appropriate adjustments made to reflect the risks specific to the refinery. Forecasted crack spreads are based on WTI and prices for gasoline and diesel, and are consistent with crack spreads used in the Company’s long range plan.

Cash flow projections for the initial 10-year period are based on long range plan future cash flows and inflated by long-term growth rates of 1 percent and 2 percent, 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 percent and adjusted for throughput capacity constraints (2017 – 2 percent). As at December 31, 2018, the recoverable value of the CGU exceeded the carrying amount and no impairment was identified.

The Company used comparative market multipliers to corroborate discounted cash flow results.

Note 11 Joint Arrangements

Joint Operations

BP-Husky Refining LLC

The Company holds a 50 percent ownership interest in BP-Husky Refining LLC, which owns and operates the BP-Husky Toledo Refinery in Ohio. On March 31, 2008, the Company completed a transaction with BP whereby BP contributed the BP-Husky Toledo Refinery plus inventories and other related net assets and the Company contributed US$250 million in cash and a contribution payable of US $2.6 billion.

The Company amended the terms of payment of the Company’s contribution payable with BP-Husky Refining LLC in the first quarter of 2015. In accordance with the amendment, US$1 billion of the net contribution payable was paid on February 2, 2015. Subsequent to the payment, BP-Husky Refining LLC distributed US$1 billion to each of the joint arrangement partners, which resulted in the creation of a deferred tax asset and deferred tax recovery of $203 million. As a result of the prepayment, the accretion rate was reduced from 6 percent to 2.5 percent for the future term of the agreement and the remaining maturity date was extended to December 31, 2017. The remaining net contribution payable amount of approximately US$110 million (CDN $142 million) was repaid in 2017.

Sunrise Oil Sands Partnership

The Company holds a 50 percent 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 | 32

Joint Venture

Husky-CNOOC Madura Ltd.

The Company currently holds 40 percent 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 income in Exploration and Production in the Upstream 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)	2018			2017
Revenues		441			97
Expenses		(273	)		(80	)
Net earnings		168			17
Share of equity investment (percent)		40	%		40	%
Proportionate share of equity investment		51			12

Balance Sheets

($ millions, except share of equity investment)	December 31, 2018			December 31, 2017
Current assets(1)		373			152
Non-current assets		2,072			1,993
Current liabilities		(123	)		(106	)
Non-current liabilities(2)		(1,917	)		(1,813	)
Net assets		405			226
Share of net assets (percent)		40	%		40	%
Carrying amount in balance sheet		650			553

⁽¹⁾ Includes cash and cash equivalents of $203 million (2017 – $26 million).

⁽²⁾ Includes deferred revenue of $2 million (2017 - 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 percent 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

On July 15, 2016, the Company completed the sale of its ownership interest in select midstream assets in the Lloydminster region of Alberta and Saskatchewan. The assets are held by a newly-formed limited partnership, HMLP, of which Husky owns 35 percent, Power Assets Holdings Ltd. (“PAH”) owns 48.75 percent and CK Infrastructure Holdings Ltd. (“CKI”) owns 16.25 percent. Results of the joint venture are included in the consolidated statements of income in Infrastructure and Marketing in the Upstream segment.

Summarized below is the financial information for HMLP accounted for using the equity method:

Results of Operations

($ millions, except share of equity investment)	2018			2017
Revenues		296			294
Expenses		(177	)		(107	)
Net earnings		119			187
Share of equity investment (percent)		35	%		35	%
Proportionate share of equity investment		18			49

Husky Energy Inc. | Consolidated Financial Statements | 33

Balance Sheet

($ millions, except share of net assets)	December 31, 2018			December 31, 2017
Current assets(1)		115			152
Non-current assets		2,849			2,617
Current liabilities		(153	)		(75	)
Non-current liabilities		(825	)		(690	)
Net assets		1,986			2,004
Share of net assets (percent)		35	%		35	%
Carrying amount in balance sheet		669			685

⁽¹⁾ Current assets include cash and cash equivalents of $16 million (2017 – $28 million).

The Company’s share of equity investment and carrying amount of share of net assets does not equal the 35 percent joint control of the net income and net assets of HMLP due to the potential fluctuation in the partnership profit structure.

Note 12 Other Assets

Other Assets

($ millions)	December 31, 2018		December 31, 2017
Long-term receivables(1)		319		144
Leasehold incentives		—		2
Precious metals		23		21
Other		18		18
End of year		360		185

⁽¹⁾ Includes insurance proceeds of $253 million (2017—nil), related to the Superior Refinery incident.

Note 13 Bank Operating Loans

At December 31, 2018, the Company had unsecured short-term borrowing lines of credit with banks totalling $900 million(1) (December 31, 2017 – $850 million) and letters of credit under these lines of credit totalling $439 million (December 31, 2017 – $422 million). As at December 31, 2018, bank operating loans were nil (December 31, 2017 – 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, 2017 – $10 million) available for general purposes. The Company’s proportionate share of the liability for any drawings under this credit facility is $5 million (December 31, 2017 – $5 million). As at December 31, 2018, there was no balance outstanding under this credit facility (December 31, 2017 – no balance).

⁽¹⁾ Includes $125 million demand facilities available specifically for letters of credit only.

Note 14 Accounts Payable and Accrued Liabilities

Accounts Payable and Accrued Liabilities

($ millions)	December 31, 2018		December 31, 2017
Trade payables		1,121		950
Accrued liabilities		1,712		1,791
Dividend payable (note 19)		126		9
Stock-based compensation		32		30
Derivatives due within one year		39		115
Other		129		138
End of year		3,159		3,033

Husky Energy Inc. | Consolidated Financial Statements | 34

Note 15 Debt and Credit Facilities

Short-term Debt

($ millions)	December 31, 2018		December 31, 2017
Commercial paper(1)		200		200

⁽¹⁾  The commercial paper is supported by the Company’s syndicated credit facilities and the Company is authorized to issue commercial paper up to a maximum of $1.0 billion having a term not to exceed 365 days. The weighted average interest rate as at December 31, 2018 was 2.20 percent per annum (December 31, 2017 – 1.40 percent).

Long-term Debt

			Canadian $ Amount						U.S. $ Denominated
($ millions)	Maturity		December 31, 2018			December 31, 2017			December 31, 2018		December 31, 2017
Long-term debt
6.15% notes(1)(3)		2019		—			376			—		300
7.25% notes(1)(4)		2019		—			939			—		750
5.00% notes(5)		2020		400			400			—		—
3.95% notes(1)(4)		2022		682			626			500		500
4.00% notes(1)(4)		2024		1,023			939			750		750
3.55% notes(5)		2025		750			750			—		—
3.60% notes(5)		2027		750			750			—		—
6.80% notes(1)(4)		2037		528			484			387		387
Debt issue costs(2)				(19	)		(24	)		—		—
Long-term debt				4,114			5,240			1,637		2,687
Long-term debt due within one year
6.15% notes(1)(3)		2019		410			—			300		—
7.25% notes(1)(4)		2019		1,023			—			750		—
Long-term debt due within one year				1,433			—			1,050		—

⁽¹⁾  All of the Company’s 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 24 for Foreign Currency Risk Management.

⁽²⁾  Calculated using the effective interest rate method.

⁽³⁾ The 6.15% notes represent unsecured securities under a trust indenture dated June 14, 2002.

⁽⁴⁾ The 7.25%, the 3.95%, the 4.00% and the 6.80% notes represent unsecured securities under a trust indenture dated September 11, 2007.

⁽⁵⁾ The 5.00%, the 3.55% and the 3.60% notes represent unsecured securities under a trust indenture dated December 21, 2009.

Credit Facilities

On November 30, 2017, the maturity date for one of the Company’s $2.0 billion revolving syndicated credit facilities, previously set to expire on June 19, 2018, was extended to June 19, 2022.

As at December 31, 2018 the covenant under the Company’s syndicated credit facilities was a debt to capital covenant, 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 agreement divided by total debt, shareholders’ equity and certain adjusting items specified in the agreement. This covenant is used to assess the Company’s financial strength. If the Company does not comply with the covenants under the syndicated credit facilities, there is the risk that repayment could be accelerated. The Company was in compliance with the syndicated credit facility covenants at December 31, 2018, and assessed the risk of non-compliance to be low. As at December 31, 2018, the Company had no borrowings under its $2.0 billion facility expiring March 9, 2020 (December 31, 2017 – no borrowings) and no borrowings under its $2.0 billion facility expiring June 19, 2022 (December 31, 2017 – no borrowings).

There continues to be no difference between the terms of these facilities, other than their maturity dates. 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’s rated senior unsecured debt.

Husky Energy Inc. | Consolidated Financial Statements | 35

Notes

On March 10, 2017, the Company issued $750 million of 3.60 percent notes due March 10, 2027. This was completed by way of a prospectus supplement dated March 7, 2017, to the Company’s universal short form base shelf prospectus dated February 23, 2015. The notes are redeemable at the option of the Company at any time, subject to a make-whole premium unless the notes are redeemed in the three month period prior to maturity. Interest is payable semi-annually on March 10 and September 10 of each year, beginning September 10, 2017. The notes are unsecured and unsubordinated and rank equally with all of the Company’s other unsecured and unsubordinated indebtedness.

On March 30, 2017, the Company filed a universal short form base shelf prospectus (the “2017 Canadian Shelf Prospectus”) with applicable securities regulators in each of the provinces of Canada that enables the Company to offer up to $3.0 billion of common shares, preferred shares, debt securities, subscription receipts, warrants and other units in Canada up to and including April 30, 2019.

On September 15, 2017, the Company repaid the maturing 6.20 percent notes issued under a trust indenture dated September 11, 2007. The amount paid to note holders was $365 million, including $11 million of interest.

On January 29, 2018, the Company filed a universal short form base shelf prospectus (the “2018 U.S. Shelf Prospectus”) with the Alberta Securities Commission. On January 30, 2018, the Company’s related U.S. registration statement with the SEC containing the 2018 U.S. Shelf Prospectus became effective which enables 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. up to and including February 29, 2020.

On December 4, 2018, the Company entered into cash flow hedges using forward interest rate swaps to fix the underlying U.S. $500 million 10-year note fixed rate to December 15, 2019. Refer to Note 24.

At December 31, 2018, the Company had unused capacity of $3.0 billion under its 2017 Canadian Shelf Prospectus and US$3.0 billion under its 2018 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.

Reconciliation of Changes of Liabilities to Cash Flows from Financing Activities

	Liabilities
			Long-term debt					Other long-term
($ millions)	Short-term debt		due within one year		Long-term debt			liabilities
December 31, 2017		200		—		5,240			1,237
Changes from financing cash flows
Long-term debt issuance		—		—		—			—
Long-term debt repayment		—		—		—			—
Short-term debt issuance		—		—		—			—
Short-term debt repayment		—		—		—			—
Debt issue costs		—		—		—			—
Total change from financing cash flows		—		—		—			—
Other changes – liability-related
Reclassification to short-term		—		1,399		(1,399	)		—
Foreign exchange		—		—		—			32
Fair value changes		—		—		—			(67	)
Addition of finance lease obligations		—		—		—			—
Payment of finance lease obligations		—		—		—			(15	)
Deferred revenue		—		—		—			(100	)
Amortization of debt issuance costs		—		—		4			—
Foreign exchange recognized in OCI		—		34		269			—
Other		—		—		—			20
Total other changes – liability related		—		1,433		(1,126	)		(130	)
December 31, 2018		200		1,433		4,114			1,107

Husky Energy Inc. | Consolidated Financial Statements | 36

Note 16 Asset Retirement Obligations

At December 31, 2018, the estimated total undiscounted inflation-adjusted amount required to settle the Company’s ARO was $9.2 billion (December 31, 2017 – $9.7 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, 2017 – 42 years) into the future. This amount has been discounted using credit-adjusted risk-free rates of 3.8 percent to 5.0 percent (December 31, 2017 – 2.9 percent to 4.8 percent) and an inflation rate of 2 percent (December 31, 2017 – 2 percent). Obligations related to future environmental remediation and cleanup of oil and gas assets are included in the estimated ARO.

The change in the provision in 2018 is primarily related to increased decommissioning and restoration activities and increase in the average discount rate, partially offset by an increase in the estimated cost of decommissioning activities.

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, 2018 and 2017 is set out below:

Asset Retirement Obligations

($ millions)	2018			2017
Beginning of year		2,526			2,791
Additions		40			47
Liabilities settled		(270	)		(136	)
Liabilities disposed		(11	)		(420	)
Change in discount rate		(68	)		143
Change in estimates		93			(2	)
Exchange adjustment		17			(9	)
Accretion (note 21)		97			112
End of year		2,424			2,526
Expected to be incurred within 1 year		202			274
Expected to be incurred beyond 1 year		2,222			2,252

At December 31, 2018, the Company had deposited funds of $128 million into the restricted accounts for funding of future asset retirement obligations in offshore China. These amounts have been classified as non-current and included in restricted cash. At December 31, 2017, the Company had deposited funds of $192 million, of which $95 million related to the Wenchang field and was classified as current, the remaining balance of $97 million was classified as non-current. The Company’s participation in the Wenchang field expired in November 2017, and the amount of the decommissioning and disposal expenses was finalized in January 2018.

Note 17 Other Long-term Liabilities

Other Long-term Liabilities

($ millions)	December 31, 2018		December 31, 2017
Employee future benefits (note 22)		205		248
Finance lease obligations		467		498
Stock-based compensation		42		32
Deferred revenue		205		284
Leasehold incentives		96		101
Other		92		74
End of year		1,107		1,237

Husky Energy Inc. | Consolidated Financial Statements | 37

Finance lease obligations

The future minimum lease payments under existing finance leases are payable as follows:

	Within 1 year				After 1 year but no more than 5 years				More than 5 years				Total
($ millions)	2018		2017		2018		2017		2018		2017		2018		2017
Future minimum lease payments		69		69		242		258		1,014		993		1,325		1,320
Interest		48		48		175		174		613		594		836		816
Present value of minimum lease payments		66		66		180		194		243		244		489		504

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, 2018			December 31, 2017
Beginning of year		284			321
Take-or-pay payments received		—			12
Revenue recognized		(100	)		(28	)
Exchange adjustment		21			(21	)
End of year		205			284

Note 18 Income Taxes

The major components of income tax expense for the years ended December 31, 2018 and 2017 were as follows:

Income Tax Expense (Recovery)

($ millions)	2018			2017
Current income tax
Current income tax charge		86			28
Adjustments to current income tax estimates		(11	)		(31	)
		75			(3	)
Deferred income tax
Relating to origination and reversal of temporary differences		378			83
Adjustments to deferred income tax estimates		18			(442	)
		396			(359	)

Deferred Tax Items in OCI

($ millions)	2018			2017
Deferred tax items expensed (recovered) directly in OCI
Derivatives designated as cash flow hedges		(5	)		—
Remeasurement of pension plans		17			(4	)
Exchange differences on translation of foreign operations		87			(82	)
Hedge of net investment		(41	)		38
		58			(48	)

Husky Energy Inc. | Consolidated Financial Statements | 38

The provision for income taxes in the consolidated statements of income reflects an effective tax rate which differs from the expected statutory tax rate. Differences for the years ended December 31, 2018 and 2017 were accounted for as follows:

Reconciliation of Effective Tax Rate

($ millions, except tax rate)	2018			2017
Earnings before income taxes
Canada		734			(440	)
United States		493			301
Other foreign jurisdictions		701			563
		1,928			424
Statutory Canadian income tax rate (percent)		27.2	%		27.1	%
Expected income tax		525			115
Effect on income tax resulting from:
Foreign jurisdictions		(36	)		20
Non-taxable items		(13	)		(1	)
Adjustments with respect to previous year		7			(473	)
Revaluation of foreign tax pools		(4	)		(8	)
Other – net		(8	)		(15	)
Income tax expense (recovery)		471			(362	)

The statutory tax rate is 27.2 percent in 2018 (2017 – 27.1 percent). The 2018 and 2017 tax rates were similar due to no significant changes to tax rates.

Effective January 1, 2018, the U.S. Federal corporate tax rate was reduced from 35 percent to 21 percent. Included in income tax expense for the year ended December 31, 2017 was a $436 million deferred income tax recovery related to the revaluation of the U.S. deferred tax liabilities.

The following reconciles the movements in the deferred income tax liabilities and assets:

Deferred Tax Liabilities and Assets

($ millions)	January 1, 2018			Recognized in Earnings			Recognized in OCI			Other		December 31, 2018
Deferred tax liabilities
Exploration and evaluation assets and property, plant and equipment		(3,727	)		(260	)		(106	)		4		(4,089	)
Foreign exchange gains taxable on realization		(177	)		(43	)		46			—		(174	)
Debt issue costs		(3	)		(1	)		—			—		(4	)
Other temporary differences		(90	)		62			—			—		(28	)
Deferred tax assets
Pension plans		40			(15	)		(17	)		—		8
Asset retirement obligations		679			(29	)		4			—		654
Loss carry-forwards		523			(70	)		15			—		468
Financial assets at fair value		31			(40	)		—			—		(9	)
		(2,724	)		(396	)		(58	)		4		(3,174	)

Husky Energy Inc. | Consolidated Financial Statements | 39

Deferred Tax Liabilities and Assets

($ millions)	January 1, 2017			Recognized in Earnings			Recognized in OCI			Other			December 31, 2017
Deferred tax liabilities
Exploration and evaluation assets and property, plant and equipment		(3,998	)		187			104			(20	)		(3,727	)
Foreign exchange gains taxable on realization		(224	)		85			(38	)		—			(177	)
Debt issue costs		(2	)		(1	)		—			—			(3	)
Other temporary differences		(21	)		(69	)		—			—			(90	)
Deferred tax assets
Pension plans		32			4			4			—			40
Asset retirement obligations		693			(8	)		(6	)		—			679
Loss carry-forwards		389			150			(16	)		—			523
Financial assets at fair value		20			11			—			—			31
		(3,111	)		359			48			(20	)		(2,724	)

The Company has temporary differences associated with its investments in its foreign subsidiaries, branches, and interests in joint ventures. At December 31, 2018, the Company had nil deferred tax liabilities in respect to these investments (December 31, 2017 – nil).

At December 31, 2018, the Company had $1,806 million (December 31, 2017 – $2,031 million) of tax losses that will expire between 2030 and 2037. The Company has recorded deferred tax assets in respect of these losses, as there are sufficient taxable temporary differences in the various jurisdictions to utilize these losses.

Note 19 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, 2016		1,005,451,854			7,296
Share cancellation		(331,842	)		(3	)
December 31, 2017		1,005,120,012			7,293
Options exercised (1)		1,726			—
December 31, 2018		1,005,121,738			7,293

⁽¹⁾  Stock options exercised was less than $1 million.

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.

On February 28, 2018, the Board of Directors reinstated the quarterly common share dividends.

Common Share Dividends

	2018				2017
($ millions)	Declared		Paid		Declared		Paid
		402		276		—		—

At December 31, 2018, Common Share dividends payable were $126 million (December 31, 2017 – nil).

Husky Energy Inc. | Consolidated Financial Statements | 40

Preferred Shares

The Company is authorized to issue an unlimited number of no par value preferred shares.

Cumulative Redeemable Preferred Shares	Number of Shares		Amount ($ millions)
December 31, 2016		36,000,000		874
December 31, 2017		36,000,000		874
December 31, 2018		36,000,000		874

Cumulative Redeemable Preferred Shares Dividends

	2018				2017
($ millions)	Declared		Paid		Declared		Paid
Series 1 Preferred Shares		6		8		6		6
Series 2 Preferred Shares		1		1		1		1
Series 3 Preferred Shares		12		14		11		11
Series 5 Preferred Shares		9		11		9		9
Series 7 Preferred Shares		7		9		7		7
		35		43		34		34

At December 31, 2018, Preferred Share dividends payable were nil (December 31, 2017 - $9 million).

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 percent 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 percent. 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, 2018 but excluding December 31, 2018, was 3.239 percent based on the sum of the Government of Canada 90 day Treasury bill rate on August 21, 2018 plus 1.73 percent. 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 4.50 percent annually for the initial period ending December 31, 2019 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 percent. 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, 2019 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 percent.

Holders of the Cumulative Redeemable Preferred Shares, Series 5 (the “Series 5 Preferred Shares”) are entitled to receive a cumulative quarterly fixed dividend yielding 4.50 percent annually for the initial period ending March 31, 2020 as declared by the Board of Directors. Thereafter, the dividend rate will be reset every 5 years at the rate equal to the five-year Government of Canada bond yield plus 3.57 percent. Holders of Series 5 Preferred Shares will have the right, at their option, to convert their shares into Cumulative Redeemable Preferred Shares, Series 6 (the “Series 6 Preferred Shares”), subject to certain conditions, on March 31, 2020 and on March 31 every five years thereafter. Holders of the Series 6 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 3.57 percent.

Holders of the Cumulative Redeemable Preferred Shares, Series 7 (the “Series 7 Preferred Shares”) are entitled to receive a cumulative fixed dividend yielding 4.60 percent annually for the initial period ending June 30, 2020 as declared by the Board of Directors. Thereafter, the dividend rate will be reset every 5 years at the rate equal to the five-year Government of Canada bond yield plus 3.52 percent. Holders of the Series 7 Preferred Shares will have the right, at their option, to convert their shares into Cumulative Redeemable Preferred Shares, Series 8 (the “Series 8 Preferred Shares”), subject to certain conditions, on June 30, 2020 and on June 30 every 5 years thereafter. Holders of the Series 8 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 3.52 percent.

Husky Energy Inc. | Consolidated Financial Statements | 41

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 he or she wishes to surrender his or her 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, 2018 was $11 million (December 31, 2017 – $21 million) representing the estimated fair value of options outstanding. The total expense recovery recognized in selling, general and administrative expenses in the consolidated statements of income for the Option Plan for the year ended December 31, 2018 was $3 million (December 31, 2017 – expense of $13 million). At December 31, 2018, the intrinsic value of stock options exercisable for cash was nil (December 31, 2017 – $12 million).

The following options to purchase common shares have been awarded to officers and certain other employees:

Outstanding and Exercisable Options

	2018					2017
	Number of Options (thousands)			Weighted Average Exercise Prices ($)		Number of Options (thousands)			Weighted Average Exercise Prices ($)
Outstanding, beginning of year		22,645			23.96		25,459			26.26
Granted(1)		5,610			17.21		5,544			16.13
Exercised for common shares		(2	)		15.67		—			—
Surrendered for cash		(1,772	)		15.82		—			—
Expired or forfeited		(6,514	)		27.69		(8,358	)		25.62
Outstanding, end of year		19,967			21.48		22,645			23.96
Exercisable, end of year		10,461			25.87		12,946			28.91

⁽¹⁾ Options granted during the year ended December 31, 2018 were attributed a fair value of $2.90 per option (2017 – $2.01) at grant date.

Outstanding and Exercisable Options

	Outstanding Options						Exercisable Options
Range of Exercise Price	Number of Options (thousands)		Weighted Average Exercise Prices ($)		Weighted Average Contractual Life (years)		Number of Options (thousands)		Weighted Average Exercise Prices ($)
$ 14.20 – $ 29.99		16,061		18.55		2.90		6,555		21.30
$ 30.00 – $ 36.20		3,906		33.52		0.17		3,906		33.51
December 31, 2018		19,967		21.48		2.37		10,461		25.87

Husky Energy Inc. | Consolidated Financial Statements | 42

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, 2018		December 31, 2017
	Tandem Options		Tandem Options
Dividend per option		0.56		0.72
Range of expected volatilities used (percent)		16.8 - 44.4		16.7 - 32.9
Range of risk-free interest rates used (percent)		1.6 - 1.9		0.9 - 1.9
Expected life of share options from vesting date (years)		1.95		1.95
Expected forfeiture rate (percent)		8.9		9.0
Weighted average exercise price		22.46		25.46
Weighted average fair value		0.65		1.15

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

In February 2010, the Compensation Committee of the Board of Directors of the Company established the 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 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 earnings 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, 2018, the carrying amount of the liability relating to PSUs was $63 million (December 31, 2017 – $41 million). The total expense recognized in selling, general and administrative expenses in the consolidated statements of income for the PSUs for the year ended December 31, 2018 was $47 million (2017 – $32 million). The Company paid out $24 million (2017 – $15 million) for performance share units which vested in the year. The weighted average contractual life of the PSUs at December 31, 2018 was two years (December 31, 2017 – two years).

The number of PSUs outstanding was as follows:

Performance Share Units	2018			2017
Beginning of year		8,361,918			4,863,690
Granted		6,108,430			5,667,970
Exercised		(1,354,316	)		(966,932	)
Forfeited		(1,509,388	)		(1,202,810	)
Outstanding, end of year		11,606,644			8,361,918
Vested, end of year		4,487,585			2,262,954

Husky Energy Inc. | Consolidated Financial Statements | 43

Earnings per Share

Earnings per Share

($ millions)	2018			2017
Net earnings		1,457			786
Effect of dividends declared on preferred shares in the year		(35	)		(34	)
Net earnings – basic		1,422			752
Dilutive effect of accounting for stock options(1)		(13	)		4
Net earnings – diluted		1,409			756
(millions)
Weighted average common shares outstanding – basic		1,005.1			1,005.3
Effect of stock dividends declared in the year		1.0			—
Weighted average common shares outstanding – diluted		1,006.1			1,005.3
Earnings per share – basic ($/share)		1.41			0.75
Earnings per share – diluted ($/share)		1.40			0.75

⁽¹⁾  For the year ended December 31, 2018, equity-settlement of stock options was used to calculate diluted earnings per share as it was considered more dilutive than cash-settlement (December 31, 2017—cash settlement method was used). Stock-based compensation recovery was $3 million based on equity-settlement for the year ended December 31, 2018 (2017 – expense of $9 million). Stock-based compensation expense would have been $10 million based on cash-settlement for the year ended December 31, 2018 (2017 – $13 million).

For the year ended December 31, 2018, 13 million tandem options (2017 – 23 million) were excluded from the calculation of diluted earnings per share as these options were anti-dilutive.

Note 20 Production, Operating and Transportation and Selling, General and Administrative Expenses

The following table summarizes production, operating and transportation expenses in the consolidated statements of income for the years ended December 31, 2018 and 2017:

Production, Operating and Transportation Expenses

($ millions)	2018		2017
Services and support costs		1,039		930
Salaries and benefits		762		664
Materials, equipment rentals and leases		243		248
Energy and utility		405		453
Licensing fees		191		200
Transportation		24		26
Other		139		158
Total production, operating and transportation expenses		2,803		2,679

The following table summarizes selling, general and administrative expenses in the consolidated statements of income for the years ended December 31, 2018 and 2017:

Selling, General and Administrative Expenses

($ millions)	2018		2017
Employee costs(1)		332		395
Stock-based compensation expense(2)		44		45
Contract services		104		100
Equipment rentals and leases		39		37
Maintenance and other		135		73
Total selling, general and administrative expenses		654		650

⁽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.

Husky Energy Inc. | Consolidated Financial Statements | 44

Note 21 Financial Items

Financial Items

($ millions)	2018			2017
Foreign exchange
Non-cash working capital gains		(3	)		(3	)
Other foreign exchange gains (losses)		17			(3	)
Net foreign exchange gains (losses)		14			(6	)
Finance income		64			37
Finance expenses
Long-term debt		(320	)		(342	)
Contribution payable (note 11)		—			(2	)
Other		(5	)		(4	)
		(325	)		(348	)
Interest capitalized(1)		108			68
		(217	)		(280	)
Accretion of asset retirement obligations (note 16)		(97	)		(112	)
Finance expenses		(314	)		(392	)
Total Financial Items		(236	)		(361	)

⁽¹⁾  Interest capitalized on project costs is calculated using the Company’s annualized effective interest rate of 5 percent (2017 – 5 percent).

Note 22 Pensions and Other Post-employment Benefits

The Company currently provides defined contribution pension plans for all qualified employees and two 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 two defined benefit pension plans, which are closed to new entrants. The defined benefit pension plans provide pension benefits to certain employees based on years of service and final average earnings. The amount and timing of funding of these plans 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, 2018. 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, 2016 for the Canadian defined benefit plan and December 31, 2018 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, 2018, the Company recognized a $54 million expense (2017 – $46 million) for the defined contribution plan and the two U.S. 401(k) plans in net earnings.

Husky Energy Inc. | Consolidated Financial Statements | 45

Defined Benefit Pension Plans (“DB Pension Plan”) and Other Post-employment Benefit Plans (“OPEB Plans”)

Defined Benefit Obligations

	DB Pension Plans						OPEB Plans
($ millions)	2018			2017			2018			2017
Beginning of year		76			178			244			213
Current service cost		1			1			11			15
Interest cost		3			4			8			8
Benefits paid		(2	)		(9	)		(4	)		(4	)
Settlements		—			(140	)		—			—
Increase due to business combinations(1)		—			34			—			—
Remeasurements
Actuarial (gain) loss – experience		2			3			(13	)		—
Actuarial loss – financial assumptions		(4	)		5			(45	)		12
Effect of changes in foreign exchange rates		3			—			(2	)		—
End of year		79			76			199			244

⁽¹⁾ The Superior Refinery DB pension plan was transferred from Calumet GP.LLC to Husky Energy Inc. effective November 2017.

Fair Value of Plan Assets

	DB Pension Plans						OPEB Plans
($ millions)	2018			2017			2018			2017
Beginning of year		67			183			—			—
Contributions by employer		1			6			2			—
Benefits paid		(2	)		(9	)		(2	)		—
Interest income		2			4			—			—
Return on plan assets greater than discount rate		—			4			—			—
Settlements		—			(148	)		—			—
Increase due to business combinations(1)		—			27			—			—
Effect of changes in foreign exchange rates		3			—			—			—
End of year		71			67			—			—

⁽¹⁾ The Superior Refinery DB pension plan was transferred from Calumet GP.LLC to Husky Energy Inc. effective November 2017. Please refer to Note 9 for business combination.

Funded status

	DB Pension Plans						OPEB Plans
($ millions)	2018			2017			2018			2017
Net asset (liability)		(8	)		(9	)		(199	)		(244	)

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 27, 2017, the Company completed a series of transactions related to the Canadian DB Pension Plan. The most recent actuarial valuation at the transaction date was at December 31, 2016. Defined benefit assets and accrued obligations were remeasured immediately prior to the transactions. DB Pension Plan assets of $148 million, including a one-time cash contribution by the Company of $5 million, were used to settle $140 million of the defined benefit obligation related to the inactive plan members. This resulted in the Company recognizing a $8 million loss on settlement in Other – net expense.

Furthermore, as part of a risk management strategy the Company also purchased a $48 million annuity, on July 27, 2017, to offset the related $42 million defined benefit obligation for the active plan members. This resulted in a $3 million actuarial loss (net of tax of $1 million) on plan assets recorded in other comprehensive income in 2017.

The Company continued to accrue service costs for the active plan members and the contribution to the plan for 2018.

In November 2017, the Company also acquired a small defined benefit pension plan for the employees of the Superior Refinery which is closed to new entrants.

Husky Energy Inc. | Consolidated Financial Statements | 46

The composition of the DB Pension Plan assets at December 31, 2018 and 2017 was as follows:

DB Pension Plan Assets

(percent)	Target allocation range		2018		2017
Money market type funds		—		5.0		0.2
Equity securities		—		—		—
Debt securities		100		95.0		99.8

The following table summarizes amounts recognized in net earnings and OCI for the DB Pension Plans and the OPEB Plans for the years ended December 31, 2018 and 2017:

	DB Pension Plan						OPEB Plans
($ millions)	2018			2017			2018			2017
Amounts recognized in net earnings
Current service cost		1			1			11			15
Past service cost		—			1			—			—
Net Interest cost		1			—			8			8
Settlement loss		—			8			—			—
Benefit cost		2			10			19			23
Remeasurements
Actuarial loss (gain) due to liability experience		2			3			(13	)		—
Actuarial loss (gain) due to liability assumption changes		(4	)		5			(45	)		12
Gain on plan assets		—			(4	)		—			—
Remeasurement effects recognized in OCI		(2	)		4			(58	)		12

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 Plan				OPEB Plans
(percent)	2018		2017		2018		2017
Discount rate for benefit expense and obligation		3.4-3.6		3.4-3.5		3.4-3.7		3.4-3.9
Rate of compensation expense		N/A		3.5		N/A		N/A

The average health care cost trend rate used for the benefit expense for the Canadian OPEB Plan was 6.5 percent for 2018, grading 0.5 percent per year for 3 years to 5.0 percent in 2021 and thereafter. The average health care cost trend rate used for the obligation related to the Canadian OPEB Plan was 6.0 percent for 2018, 2019 and 2020, grading 0.5 percent per year for 3 years to 5.0 percent in 2022 and thereafter.                

The average health care cost trend rate used for the benefit expense for the U.S. OPEB Plan was 6.0 percent for 2018, grading 0.25 percent per year for 5 years to 5.0 percent per year in 2022 and thereafter. The average health care cost trend rate used for the obligation related to the U.S. OPEB Plan was 6.5 percent for 2018, grading 0.25 percent per year for 6 years to 5.0 percent 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 Plan					OPEB Plans
($ millions)	1% increase			1% decrease		1% increase			1% decrease
Discount rate		(9	)		11		(33	)		43
Health care cost trend rate		N/A			N/A		32			(25	)

Husky Energy Inc. | Consolidated Financial Statements | 47

Note 23 Cash Flows – Change in Non-cash Working Capital

Non-cash Working Capital

($ millions)	2018			2017
Decrease (increase) in non-cash working capital
Accounts receivable		127			(329	)
Inventories		393			(264	)
Prepaid expenses		30			(38	)
Accounts payable and accrued liabilities		(65	)		1,269
Change in non-cash working capital		485			638
Relating to:
Operating activities		130			398
Financing activities		120			—
Investing activities		235			240

Note 24 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 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, 2018			December 31, 2017
Commodity contracts – fair value through profit or loss (”FVTPL”)
Natural gas(1)		(9	)		(13	)
Crude oil(2)		89			(57	)
Foreign currency contracts – FVTPL
Foreign currency forwards		(1	)		1
Other assets – FVTPL		1			1
Derivatives designated as a cash flow hedge - forward starting swaps		(14	)		—
Hedge of net investment(3)(4)		(846	)		(584	)
End of year		(780	)		(652	)

⁽¹⁾  Natural gas contracts includes a $10 million decrease at December 31, 2018 (December 31, 2017 – $3 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 $15 million at December 31, 2018 (December 31, 2017 – $5 million).

⁽²⁾  Crude oil contracts includes a $67 million increase at December 31, 2018 (December 31, 2017 – $5 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 $185 million at December 31, 2018 (December 31, 2017 – $232 million).

⁽³⁾ Hedging instruments are presented net of tax.

⁽⁴⁾  Represents the translation of the Company’s U.S. dollar denominated long-term debt designated as a hedge of the Company’s net investment in selected foreign operations with a U.S. dollar functional currency.

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, 2018, the carrying value of the Company’s long-term debt was $5.5 billion and the estimated fair value was $5.7 billion (December 31, 2017 – carrying value of $5.2 billion, estimated fair value of $5.6 billion).

All financial assets and liabilities are classified as Level 2 fair value measurements. During the year ended December 31, 2018, 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.

Husky Energy Inc. | Consolidated Financial Statements | 48

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. 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.

Responsibility for 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 from time to time 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, 2018, 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, 2018, the net unrealized gain recognized on the derivative contracts was $150 million (2017—net unrealized loss of $56 million).

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, 2018, the Company had designated US$2.7 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, 2017 – US$2.7 billion). For the year ended December 31, 2018, the unrealized loss arising from the translation of the debt was $262 million (December 31, 2017 – unrealized gain of $243 million), net of tax recovery of $41 million (December 31, 2017 – expense of $38 million), which was recorded in hedge of net investment within OCI.

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 commercial paper 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.

On December 4, 2018, the Company entered into cash flow hedges using forward interest rate swaps to fix the underlying U.S. $500 million 10-year note fixed rate to December 15, 2019. There was no ineffective portion as at December 31, 2018. For the year ended December 31, 2018, the unrealized loss arising from the recognition of the swaps was $11 million (December 31, 2017—nil), net of tax recovery of $3 million, which was recorded in OCI.

Husky Energy Inc. | Consolidated Financial Statements | 49

The forward starting swaps have the following terms and fair value as at December 31, 2018.

Forward Starting Swaps

	As at December 31, 2018
($ millions)	Swap Rate (1)			Notional Amount (U.S. $ millions)		Fair Value ($ million)
Swap Maturity
December 15, 2029		2.999	%		250		(7	)
December 15, 2029		3.000	%		250		(7	)

⁽¹⁾  Weighted average rate.

At December 31, 2018, the balance in other reserves related to the accrued gain from unwound forward starting interest rate swaps designated as a cash flow hedge was $13 million (December 31, 2017 – $15 million), net of tax of $4 million (December 31, 2017 – net of tax of $5 million). The amortization of the accrued gain upon settling the interest rate swaps resulted in an offset to finance expense of $2 million for the year ended December 31, 2018 (December 31, 2017 – $2 million).

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, 2018
($ millions)	Gross Amount			Amount Offset			Net Amount
Financial Assets
Financial derivatives		188			(120	)		68
Normal purchase and sale agreements		625			(335	)		290
End of year		813			(455	)		358
Financial Liabilities
Financial derivatives		(107	)		62			(45	)
Normal purchase and sale agreements		(756	)		307			(449	)
End of year		(863	)		369			(494	)

Offsetting Financial Assets and Liabilities

	As at December 31, 2017
($ millions)	Gross Amount			Amount Offset			Net Amount
Financial Assets
Financial derivatives		150			(111	)		40
Normal purchase and sale agreements		639			(280	)		359
End of year		789			(391	)		399
Financial Liabilities
Financial derivatives		(246	)		122			(123	)
Normal purchase and sale agreements		(933	)		353			(581	)
End of year		(1,179	)		475			(704	)

Husky Energy Inc. | Consolidated Financial Statements | 50

Market Risk Sensitivity Analysis

A sensitivity analysis for commodities, foreign currency exchange and interest rate risks has been calculated by increasing or decreasing commodity prices, foreign currency exchange rates or interest rates, as appropriate. These sensitivities represent the increase or decrease in earnings 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		26			(26	)
Natural gas price		(9	)		9

Foreign Exchange Rate⁽²⁾

	Canadian dollar		Canadian dollar
($ millions)	$0.01 increase		$0.01 decrease
U.S. dollar per Canadian dollar		1		(1	)

Interest Rate⁽³⁾

	100 basis point		100 basis point
($ millions)	increase		decrease
LIBOR		61		(61	)

⁽¹⁾  Based on average crude oil and natural gas market prices as at December 31, 2018.

⁽²⁾  Based on the U.S./Canadian dollar exchange rate as at December 31, 2018.

⁽³⁾  Based on the U.S. LIBOR as at December 31, 2018.

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 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. The Company’s Upstream capital programs are 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, 2018:

Credit Facilities

($ millions)	Available		Unused
Operating facilities(1) (note 13)		900		461
Syndicated bank facilities(2) (note 15)		4,000		3,800
End of year		4,900		4,261

⁽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 $3.0 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.

Husky Energy Inc. | Consolidated Financial Statements | 51

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 had one external customer that constituted more than 10 percent of gross revenues during the years ended December 31, 2018 and December 31, 2017. Sales to this customer were approximately $4.2 billion for the year ended December 31, 2018 (December 31, 2017 – $3.3 billion).

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, 2018:

Accounts Receivable Aging

($ millions)	December 31, 2018
Current		1,140
Past due (1 – 30 days)		139
Past due (31 – 60 days)		42
Past due (61 – 90 days)		16
Past due (more than 90 days)		57
Provision for expected credit losses		(39	)
		1,355

The Company recognizes a valuation provision when collection of accounts receivable is in doubt. Accounts receivable are impaired directly when collection of accounts receivable is no longer expected. For the year ended December 31, 2018, the Company wrote off $3 million (December 31, 2017 – $1 million) of uncollectible receivables.

Note 25 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, 2018. All of the entities listed below, except as otherwise indicated, are 100 percent 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 Terra Nova Partnership		100		Alberta
Husky Downstream General 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 | 52

Each of the related party transactions described below was made on terms equivalent to those that prevail in arm’s length transactions.

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 are related party transactions, as the Company has a 35 percent 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. For the year ended December 31, 2018, the Company charged HMLP $448 million (December 31, 2017 – $412 million) related to construction costs and management services. For the year ended December 31, 2018, the Company had purchases from HMLP of $200 million (December 31, 2017 – $203 million) related to the use of the pipeline for the Company’s blending activities, transportation and storage activities, received distributions of $139 million (December 31, 2017 – $25 million) and paid capital contributions of $40 million (December 31, 2017 – $17 million). At December 31, 2018, the Company had $140 million due from HMLP, of which nil relates to unbilled revenue from construction contracts on the percentage of completion method (December 31, 2017 – $67 million and $23 million, respectively).

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)	2018		2017
Short-term employee benefits(1)		17		16
Stock-based compensation(2)		33		31
		50		47

⁽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 26 Commitments and Contingencies

At December 31, 2018, 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 leases(1)		233		504		1,186		1,923
Firm transportation agreements(1)		497		2,066		4,013		6,576
Unconditional purchase obligations(2)		1,620		3,656		4,822		10,098
Lease rentals and exploration work agreements		49		246		930		1,225
Obligations to fund equity investee(3)		53		293		395		741
		2,452		6,765		11,346		20,563

⁽¹⁾ Included in operating leases and firm transportation agreements are blending and storage agreements and transportation commitments of $1.1 billion and $1.9 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.

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.

Husky Energy Inc. | Consolidated Financial Statements | 53

Note 27 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 $25.4 billion as at December 31, 2018 (December 31, 2017 – $23.4 billion). To maintain or adjust the capital structure, the Company may, from time to time, issue shares, raise debt and/or adjust its capital spending to manage its current and projected debt levels.

The Company monitors its capital structure and financing requirements 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 plus change in non-cash working capital.

The Company’s objective is to maintain a debt to capital employed target of less than 25 percent and a debt to funds from operations ratio of less than 2.0 times. At December 31, 2018, debt to capital employed was 22.7 percent (December 31, 2017 – 23.2 percent) and debt to funds from operations was 1.4 times (December 31, 2017 – 1.6 times), within the Company’s targets. To facilitate the management of these ratios, the Company prepares annual budgets, which are updated depending on varying factors such as general market conditions and successful capital deployment. The annual budget is approved by the Board of Directors.

The Company’s share capital is not subject to external restrictions; however, the syndicated credit facilities include a debt to capital covenant, 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 agreement divided by total debt, shareholders’ equity and certain adjusting items specified in the agreement. This covenant is used to assess the Company’s financial strength. If the Company does not comply with the covenants under the syndicated credit facilities, there is the risk that repayment could be accelerated. The Company was in compliance with the syndicated credit facility covenants at December 31, 2018, and assessed the risk of non-compliance to be low.

There were no changes in the Company’s approach to capital management from the previous year.

Note 28 Subsequent Event

On January 8, 2019, the Company announced its intention to market and potentially sell its Prince George Refinery and Retail and Commercial Network. An estimate of the financial impact cannot be made at this time.

On January 16, 2019, the Company announced that its offer to acquire all of the outstanding common shares of MEG Energy Corp. expired, as the minimum tender threshold was not satisfied, and the Company decided not to extend its offer.

Husky Energy Inc. | Consolidated Financial Statements | 54

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)	2018			2017		2016
Gross revenues and Marketing and other		22,587			18,946		13,224
Net earnings (loss) by business segment
Upstream		790			260		1,091
Downstream		1,000			448		342
Corporate		(333	)		78		(511	)
Net earnings		1,457			786		922
Net earnings per share – basic		1.41			0.75		0.88
Net earnings per share – diluted		1.40			0.75		0.88
Cash flow – operating activities		4,134			3,704		1,971
Funds from operations(1)		4,004			3,306		2,198
Ordinary dividends per common share		0.450			0.075		—
Dividends per cumulative redeemable preferred share, series 1		0.60			0.60		0.73
Dividends per cumulative redeemable preferred share, series 2		0.74			0.57		0.42
Dividends per cumulative redeemable preferred share, series 3		1.13			1.13		1.13
Dividends per cumulative redeemable preferred share, series 5		1.13			1.13		1.13
Dividends per cumulative redeemable preferred share, series 7		1.15			1.15		1.15
Total assets		35,225			32,927		32,260
Total debt(2)		5,747			5,440		5,339
Net debt(2)		2,881			2,927		4,020

⁽¹⁾  Funds from operations is a non-GAAP measure. The calculation of funds from operations changed in the second quarter of 2017. Prior periods have been revised to conform with the current period presentation. Refer to Section 9.3 for a reconciliation to the corresponding GAAP measure.

⁽²⁾  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 2018 | 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 are 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 are 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 Upstream and Downstream business segments.

2.1 Corporate Strategy

The Company’s business strategy is to focus on returns from investment in a deep portfolio of opportunities that can generate increased cash flow from operating activities and funds from operations.

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”) (Atlantic and Asia Pacific collectively, “Offshore”).

Integrated Corridor

The Company’s business in the Integrated Corridor includes crude oil, bitumen, natural gas and natural gas liquids (“NGL”) production from Western Canada, the Lloydminster upgrading and asphalt refining complex, Husky Midstream Limited Partnership (35 percent working interest and operatorship), and the Lima, Toledo (50 percent working interest) and Superior refineries in the U.S. midwest. Natural gas production from the Western Canada portfolio is closely aligned with the Company’s energy requirements for refining and thermal bitumen production and acts as a natural hedge.

Offshore

The Company’s Offshore business includes operations, development and exploration in Atlantic and Asia Pacific. Each area generates high-netback production, with near and long-term investment potential.

2.2 Operations Overview and 2018 Highlights

Upstream Operations

Upstream operations in the Integrated Corridor and Offshore include exploration for, and development and production of, crude oil, bitumen, natural gas and NGL (“Exploration and Production”) and the marketing of the Company’s and other producers’ crude oil, natural gas, NGL, sulphur and petroleum coke. Additionally, Upstream operations include pipeline transportation, the blending of crude oil and natural gas and storage of crude oil, diluent and natural gas (“Infrastructure and Marketing”). Infrastructure and Marketing markets and distributes products to customers on behalf of Exploration and Production and is grouped in the Upstream business segment based on the nature of its interconnected operations. The Company’s Upstream operations are located primarily in Western Canada, Atlantic and Asia Pacific.

On January 16, 2019, the Company announced that its offer to acquire all of the outstanding common shares of MEG Energy Corp. expired, as the minimum tender threshold was not satisfied, and the Company decided not to extend its offer.

Exploration and Production

Thermal Developments

The Company continued to advance its inventory of thermal projects in 2018. These long-life developments are being built with modular, repeatable designs and require low sustaining capital once brought online.

Total bitumen production, including Lloyd thermal projects, the Tucker Thermal Project and the Sunrise Energy Project, averaged 124,200 bbls/day in 2018.

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Lloyd Thermal Projects

The Company is phasing execution of its long-life thermal projects to optimize capital efficiency and project execution. In 2018, the Company completed two land deals to create two Thermal hubs, one at Spruce Lake, and one at Dee Valley. This has resulted in the expectation that the Edam Central project will be completed in 2022, rather than the previously disclosed timeframe of late 2021, and in Westhazel being reprioritized.

The following table shows major projects and their status as at December 31, 2018:

Project Name	Estimated Production (bbls/day)		Expected Project Production Date	Project Status
Rush Lake 2		10,000	First quarter of 2019	Completed ahead of schedule with first production achieved in October 2018 and nameplate capacity of 10,000 bbls/day reached in November 2018.
Dee Valley		10,000	Fourth quarter of 2019	Work continued, with drilling of the second well pad completed and construction of the Central Processing Facility (“CPF”) continuing ahead of schedule. As of the end of 2018, the CPF was 80 percent complete.
Spruce Lake Central		10,000	2020	Construction of the CPF commenced in 2018.
Spruce Lake North		10,000	Around the end of 2020	Site clearing was completed in 2018.
Spruce Lake East		10,000	Around the end of 2021	Sanctioned in November 2018, with regulatory approval received in 2019.
				Prioritized ahead of Westhazel.
Edam Central		10,000	2022	Regulatory permit was received in early January 2019.
Dee Valley 2		10,000	2023	Regulatory applications were submitted in 2018, with approval expected in 2019.
Westhazel		10,000	Reprioritized	Regulatory applications were submitted in 2018, with approval expected in 2019.
				Reprioritized in order to optimize thermal sequence.

In February 2019, the Pike’s Peak thermal bitumen plant was closed down as it reached the end of its useful life. The plant achieved first production in September 1981 and produced 78 mmbbls over its useful life.

Tucker Thermal Project

Work to debottleneck the CPF and Tucker field was completed in the third quarter of 2018. Subsequently, production ramped up and nameplate capacity of 30,000 bbls/day was achieved in October 2018, with a daily production record of 31,700 bbls/day achieved in late November. Production for 2018 and December 2018 averaged 22,400 bbls/day and 27,500 bbls/day, respectively.

Production in 2019 is expected to be impacted by government-mandated production curtailment in Alberta. While specific volume reductions are uncertain, production in the first quarter of 2019 could be impacted by as much as 5,000 bbls/day.

Sunrise Energy Project

Total annual production in 2018 averaged 50,000 bbls/day (25,000 bbls/day Husky working interest). During the fourth quarter of 2018, maintenance activities were completed and the project reached its nameplate capacity of 60,000 bbls/day. Record production of 62,600 bbls/day was achieved in late December. December production averaged 59,000 bbls/day (29,500 bbls/day Husky working interest).

Production in 2019 is expected to be impacted by government-mandated production curtailment in Alberta. While specific volume reductions are uncertain, production in the first quarter of 2019 could be impacted by as much as 15,000 bbls/day (7,500 bbls/day Husky working interest).

Non-Thermal Developments

The Company is managing the natural decline in Cold Heavy Oil Production with Sand (“CHOPS”) operations with an active optimization program as well as using waterflooding and polymer injection technology.

Production in 2019 is expected to be impacted by government-mandated production curtailment in Alberta.

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Cold and Enhanced Oil Recovery

In 2018, the Company sanctioned a full field polymer injection project at Aberfeldy and has opportunities to expand to other areas.

During the year, the Company operated five carbon dioxide (“CO₂”) injection enhanced oil recovery (“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 several types of CO₂ capture technology at its Lashburn facility in Saskatchewan.

Western Canada

The Company continues to execute its resource play strategy in Western Canada to advance developments in the Spirit River (predominantly Wilrich) and Montney formations.

Oil and Natural Gas Resource Plays

A drilling program targeting the Spirit River Formation, in the Ansell and Kakwa areas, continued with 21 wells drilled in 2018, and 25 completed.

A drilling program targeting the oil and liquids-rich gas Montney Formation in the Wembley and Karr areas is continuing with seven wells drilled in 2018, and six completed.

Asia Pacific

The Company’s Asia Pacific business produces natural gas and NGL in the South China Sea and the Madura Strait offshore Indonesia. Natural gas is sold into the South China and East Java markets under long-term contracts with set prices that include escalation factors. NGL in both regions are sold at market prices.

The Company’s interests include the Liwan 3-1, Liuhua 34-2 and Liuhua 29-1 fields on Block 29/26, and Blocks 15/33, 16/25, 22/11 and 23/07 located in the South China Sea. The Madura Strait consists of the operating BD field, the MDA, MBH, MDK and MAC developments and three additional discoveries. The Company has rights to additional exploration blocks offshore Taiwan and Indonesia, and has signed a Strategic Cooperation Agreement with China National Offshore Oil Corporation Limited (“CNOOC”) on two offshore areas in the northern part of the South China Sea for additional exploration opportunities in the future.

The Company continues to develop its contracted price natural gas business in China and Indonesia, further protecting the Company from commodity price instability.

China

Block 29/26

Total production from Liwan 3-1 and Liuhua 34-2 averaged 79,900 boe/day (39,200 boe/day Husky working interest) in 2018. Production consisted of natural gas production of 377 mmcf/day and NGL production of 17,100 bbls/day.

Construction continues at Liuhua 29-1, the third deepwater gas field of the Liwan Gas Project. All of the major contracts have been executed and detailed design work is underway. The Environment Impact Assessment was approved by the Ministry of Ecology and Environment in January 2019. Drilling of the remaining three wells is expected to commence in the first quarter of 2019, which will add to the four previously drilled wells. First gas production from this seven-well development is expected around the end of 2020, with target production of 45 mmcf/day of natural gas (Husky working interest) and 1,800 bbls/day of NGL (Husky working interest) when fully ramped up. The Company holds a working interest of 75 percent in this field development.

Blocks 15/33 and 16/25

The Company is progressing commercial development plans following the successful drilling and testing of an exploration well on Block 15/33.

During the third quarter of 2018, the Company drilled one exploration well at the nearby exploration Block 16/25 which encountered non-commercial hydrocarbons. Additional evaluation work is being conducted and a second exploration well may be drilled in the 2020 timeframe.

The Company is the operator of both blocks with a working interest of 100 percent during the exploration phase. In the event of a commercial discovery, CNOOC may assume a participating partnership interest of up to 51 percent in either or both blocks for the development and production phases.

Blocks 22/11 and 23/07

The Company and CNOOC signed two Production Sharing Contracts (“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 percent during the exploration phase. In the event of a commercial discovery, CNOOC may assume a participating partnership interest of up to 51 percent in either or both blocks for the development and production phases.

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Block DW-1

During 2017, on Block DW-1 offshore Taiwan, the Company completed the acquisition of three-dimensional seismic survey data. Analysis of the data is ongoing to identify potential drilling prospects on the block.

Indonesia

Madura Strait

The BD Project achieved its total daily sales target of 100 mmcf/day of natural gas (40 mmcf/day Husky working interest) and 6,000 bbls/day of associated NGL (2,400 bbls/day Husky working interest) in the third quarter of 2018. Total natural gas production averaged 78 mmcf/day (31 mmcf/day Husky working interest) and NGL production averaged 6,200 bbls/day (2,500 bbls/day Husky working interest) in 2018.

At the MDA and MBH fields, the two shallow water platforms have been fully installed and preparations are underway to drill the five MDA and two MBH field production wells in 2019. Gas production and sales are expected to commence in the 2020 timeframe, following completion of the Floating Production Unit (“FPU”) which will be used to process and compress the gas. Subsequently, an additional shallow water field, named MDK, is scheduled to be developed and tied into the FPU. 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 with set prices that include escalation factors.

Pre-engineering activities and approvals progressed at the MAC field, where an approved Plan of Development is in place. Additional discoveries in the region are being evaluated for potential development.

Anugerah

During 2015, the Company acquired two-dimensional and three-dimensional seismic survey data on the contract area, which was required during the first three years of the PSC. An analysis of that data and offset block information indicates that drilling is not economic and the block will be relinquished.

Atlantic

The Company’s Atlantic portfolio has short and long-term opportunities that provide for high return production growth off the coast of Newfoundland and Labrador.

White Rose Field and Satellite Extensions

Project activity continues to ramp-up on the West White Rose Project. Construction of the concrete gravity structure began in the first half of 2018 at the purpose-built graving dock in Argentia, Newfoundland and Labrador. The structure’s base slab was completed in mid-September and the structure was poured to a height of 46 metres during the 2018 construction season. First production is expected in 2022.

The Company continues to progress a subsea program to offset natural reservoir declines through infill drilling and workover operations at the White Rose field and satellite extensions. During the third quarter of 2018, two well workovers were completed. Two additional infill wells are being completed and are expected to be brought online before mid-year 2019, instead of the previously stated timeframe of the fourth quarter of 2018.

In late January 2019, the Company began a staged ramp-up of production at the White Rose field. The field had been shut-in since mid-November, after a flowline connector failed near the South White Rose Extension, causing a spill of approximately 250 cubic metres of oil. The Company and its certifying authority have completed inspections of the SeaRose floating production, storage and offloading (“FPSO”) vessel as well as subsea infrastructure. Regulatory approval has been received for plans to recover the damaged flowline connector. An investigation into the cause of the incident is underway.

Atlantic Exploration

The Company continued to evaluate the results of a recent discovery at the A-24 exploration well north of the White Rose field and further delineation in the area is planned. The Company has a 68.875 percent ownership interest, with partners Suncor Energy and Nalcor Energy Oil and Gas holding 26.125 percent and five percent, respectively.

Infrastructure and Marketing

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 Husky’s Upgrader and Asphalt Refinery. The Hardisty Terminal acts as the exclusive blending hub for Western Canada Select (“WCS”). HMLP is in the process of diversifying its operations beyond the Lloydminster and Hardisty area and has commenced construction of the Ansell Corser Gas Plant.

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LLB Direct – Cold Lake Gathering System to Hardisty

LLB Direct Pipeline and an associated 300,000-barrel operational tank at Hardisty came online in the fourth quarter of 2018, fulfilling an important component of HMLP’s growth strategy in the Lloydminster region. The 20-inch line, with an initial 100,000 bbl/day capacity, provides the Company and third-party customers on the Cold Lake Gathering System with direct access to Hardisty, while simultaneously relieving congestion on the mainline system between Lloydminster and Hardisty.

Saskatchewan Gathering System Expansion

A multi-year expansion program is underway and will provide transportation of diluent and heavy oil blend for several additional thermal plants.

Ansell Corser Gas Plant

The new gas processing plant is now under construction and is expected to add 120 mmcf/day of processing capacity when it is scheduled to come online in the fourth quarter of 2019.

Commodity Marketing

The Company has developed its commodity marketing operations to include the acquisition of third-party volumes to enhance the value of its midstream assets. The Company also markets both its own and third-party production of crude oil, synthetic crude oil, NGL, natural gas and sulphur. Additionally, the Company markets petroleum coke, a by-product from the Lloydminster Upgrader, and its Ohio and Wisconsin refineries.

Downstream Operations

Downstream operations in the Integrated Corridor in Canada include upgrading of heavy crude oil feedstock into synthetic crude oil (“Upgrading”), refining crude oil, marketing of refined petroleum products including gasoline, diesel, ethanol blended fuels, asphalt and ancillary products, and production of ethanol (“Canadian Refined Products”). It also includes refining of crude oil in the U.S. to produce and market diesel fuels, gasoline, jet fuel and asphalt (“U.S. Refining and Marketing”). Upgrading, Canadian Refined Products and U.S. Refining and Marketing all process and refine natural resources into marketable products and are grouped together as the Downstream business segment due to the similar nature of their products and services.

The Company’s Downstream operations target three primary objectives: increasing feedstock flexibility to bring the best-priced crude to the Company’s refineries; improving flexibility in the range of its products to capitalize on opportunities; and enhancing market access to achieve the best returns. The Company’s focused integration strategy helps to capture the margin on refined product pricing for its Western Canada heavy oil, bitumen and light oil production and assists in mitigating market volatility.

Upgrading

The heavy oil upgrading facility, located in Lloydminster, Saskatchewan, has a throughput capacity of 82,000 bbls/day. The Lloydminster 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 Lloydminster 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.

Canadian Refined Products

Lloydminster Asphalt Refinery

The Lloydminster Asphalt Refinery in Lloydminster, Alberta, has a throughput capacity of 29,000 bbls/day and is integrated with the local heavy 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 combined capacity of 260 million litres per year.

Prince George Refinery

The Prince George Refinery in British Columbia has a throughput capacity of 12,000 bbls/day and produces low sulphur gasoline and ultra-low sulphur diesel.

On January 8, 2019, the Company announced its intention to market and potentially sell the Prince George Refinery.

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Retail and Commercial Network

The Company is a major regional motor fuel marketer with an average of 557 retail marketing locations in 2018, including bulk plants and travel centres, with strategic land positions in western Canada and Ontario.

On January 8, 2019, the Company announced its intention to market and potentially sell its Retail and Commercial Network.

U.S. Refining and Marketing

Lima Refinery

The Lima Refinery in Ohio has a crude oil throughput capacity, depending on the crude slate, of up to 175,000 bbls/day and produces low sulphur gasoline, gasoline blend stocks, ultra-low sulphur diesel, jet fuel, petrochemical feedstock and other by-products.

In 2016, the Company completed the first stage of the crude oil flexibility project and the refinery is now able to process up to 10,000 bbls/day of heavy crude oil feedstock. The project is designed to allow for the processing of up to 40,000 bbls/day of heavy crude oil feedstock from western Canada when completed, providing the ability to swing between light and heavy crude oil feedstock.

The timing of completion for the crude oil flexibility project is expected to be late 2019. This schedule coordinates project work with normal maintenance to provide higher levels of sustained production.

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 percent by the Company and 50 percent by BP Corporation North America Inc. (“BP”), and is operated by BP. The Company and BP completed a feedstock optimization project in 2016, allowing the refinery to process up to 70,000 bbls/day of high content naphthenic acids (“high-TAN”) crude oil to support production from the Sunrise Energy Project. The refinery’s nameplate capacity remained unchanged.

Superior Refinery

The Superior Refinery has a permitted throughput capacity of 50,000 bbls/day and an operating capacity of 45,000 bbls/day as configured. The refinery produces motor fuel products and asphalt from light and heavy crude oil originating from North Dakota and western Canada.

2.3 Superior Refinery Incident

On April 26, 2018, the Superior Refinery experienced an incident while preparing for a major turnaround. Operations at the refinery remain suspended. An engineering contractor has been appointed to oversee design work and rebuild of the refinery. The rebuild will commence once design work is complete and permits are obtained. Operations are expected to resume in 2020.

As at December 31, 2018, the Company derecognized $56 million of assets damaged in the incident in the U.S. Refining and Marketing segment. In addition, the Company accrued pre-tax insurance recoveries for property damage, rebuild costs, business interruption and clean-up costs associated with the incident of $468 million.

2.4 Financial Strategic Plan

The Company is committed to ensuring it has sufficient liquidity, financial flexibility and access to long-term capital to fund its growth. The Company maintains undrawn committed term credit facilities with a portfolio of creditworthy financial institutions and other sources of liquidity to provide timely access to funding to supplement cash flow.

The Company intends to maintain a healthy balance sheet to provide financial flexibility. The Company’s objective is to maintain a debt to capital employed target of less than 25 percent and a debt to funds from operations ratio of less than 2.0 times. Debt to funds from operations and debt to capital employed are both non-GAAP measures (refer to Sections 6.4 and 9.3). The Company is committed to retaining its investment grade credit ratings to support access to debt capital markets. The Company has taken measures to maintain its strong financial position through commodity cycles. Past measures included, but were not limited to, a reduction of budgeted capital spending, temporary suspension of the quarterly common share dividend, the sale of non-core assets in Western Canada and the continued transition to higher margin production. Refer to Section 6.0 for additional information on the Company’s liquidity and capital resources.

On February 28, 2018, the Board of Directors reinstated the quarterly common share cash dividend of $0.075 per share. On July 26, 2018, the quarterly common share cash dividend was increased to $0.125 per share.

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3.0 The 2018 Business Environment

The Company’s operations were significantly influenced by domestic and international factors in 2018, including, but not limited to, the following:

• Global crude oil benchmarks strengthened in the first half of 2018 due to market rebalancing, but weakened towards the end of the year due to record levels of oil production from the world’s largest producers leading to increased global inventories, combined with uncertainties regarding future global demand.

• North American natural gas benchmarks continued to be weak in 2018 due to infrastructure constraints combined with lower demand for Canadian natural gas in the U.S. as a result of increased U.S. shale oil production.

• A continued emphasis on the environment, the impacts of climate change, health and safety, enterprise risk management, resource sustainability and corporate social responsibility concerns.

• Transportation constraints on crude oil produced in western Canada. The oil and gas industry continues to work with stakeholders to develop a strong network of transportation infrastructure including pipelines, rail, marine and trucks. The development of a strong infrastructure network continues to be an important challenge for the industry to obtain market access for the growing supply of crude oil from the western Canadian oil sands.

• On December 2, 2018, the Government of Alberta set province-wide mandatory oil production cuts in an attempt to rebalance the market. This curtailment was effective as of January 1, 2019, and is expected to continue through 2019.

• Alternative and improved extraction methods have rapidly evolved in North American and international onshore and offshore activity.

Major business factors are considered in the formulation of the Company’s short and long-term business strategy.

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, 2018.

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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.

Average Benchmarks Summary			2018		2017
West Texas Intermediate (“WTI”) crude oil(1)	(US$/bbl	)		64.77		50.95
Brent crude oil(2)	(US$/bbl	)		70.97		54.28
Light sweet at Edmonton	($/bbl	)		69.31		62.91
WCS at Hardisty(3)	(US$/bbl	)		38.46		38.98
Lloyd heavy crude oil at Lloydminster	($/bbl	)		39.33		44.36
WTI/Lloyd crude blend differential	(US$/bbl	)		26.09		11.76
Condensate at Edmonton	(US$/bbl	)		60.95		51.57
NYMEX natural gas(4)	(US$/mmbtu	)		3.09		3.11
Nova Inventory Transfer (“NIT”) natural gas	($/GJ	)		1.45		2.30
Chicago Regular Unleaded Gasoline	(US$/bbl	)		78.07		66.22
Chicago Ultra-low Sulphur Diesel	(US$/bbl	)		87.08		69.05
Chicago 3:2:1 crack spread	(US$/bbl	)		15.94		16.31
U.S./Canadian dollar exchange rate	(US$	)		0.772		0.771
Canadian $ Equivalents(5)
WTI crude oil	($/bbl	)		83.90		66.08
Brent crude oil	($/bbl	)		91.93		70.40
WCS at Hardisty	($/bbl	)		49.82		50.56
WTI/Lloyd crude blend differential	($/bbl	)		33.80		15.25
NYMEX natural gas	($/mmbtu	)		4.00		4.03

⁽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 which terminals at Hardisty, Alberta. Quoted prices are indicative of the Index for WCS at Hardisty, Alberta, set in the month prior to delivery.

⁽⁴⁾  Prices quoted are average settlement prices during the period.

⁽⁵⁾  Prices quoted are calculated using U.S. dollar benchmark commodity prices and U.S./Canadian dollar exchange rates.

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 price. 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 is determined by fixed long-term sales contracts.

The Downstream segment is heavily impacted by the price of crude oil and natural gas, as the largest cost factor in the Downstream segment is crude oil feedstock, a portion of which is heavy crude oil and bitumen. In the Upgrading business, heavy crude oil feedstock is processed into light synthetic crude oil. The Company’s U.S. Refining and Marketing business 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 62 percent heavy crude oil and bitumen feedstock at the BP-Husky Toledo Refinery. The Company’s Retail and Commercial Network relies primarily on supply contracts to purchase refined products for resale in the retail distribution network, as well as production from the Prince George Refinery and diesel from the Lloydminster Upgrader.

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Crude Oil Benchmarks

Global crude oil benchmarks strengthened in the first half of 2018 due to market rebalancing, but weakened towards the end of the year due to record levels of oil production from the world’s largest producers leading to increased global inventories, combined with uncertainties regarding future global demand. Furthermore, the WCS benchmark weakened towards the end of 2018 primarily due to an oversupply of Canadian crude oil resulting from continued transportation constraints. Consequently the WCS benchmark traded at a greater discount compared to other North American benchmarks. WTI averaged US$64.77/bbl in 2018 compared to US$50.95/ bbl in 2017. Brent averaged US$70.97/bbl in 2018 compared to US$54.28/bbl in 2017. WCS averaged US$38.46/bbl in 2018 compared to US$38.98/bbl in 2017.

The price received by the Company for crude oil production from Western Canada is primarily driven by the price of WTI, adjusted to Western Canada. 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 portion of the Company’s crude oil production from Western Canada is classified as either heavy crude oil or bitumen, which trades at a discount to light crude oil. The Company’s crude oil and NGL production was 75 percent heavy crude oil and bitumen in 2018 compared to 70 percent in 2017.

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 increased in 2018 compared to 2017, primarily due to the increase in crude oil benchmark pricing.

Natural Gas Benchmarks

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The price received by the Company for natural gas production from Western Canada is primarily driven by the NIT near-month contract price of natural gas, while the price received by the Company for production from Asia Pacific is determined by long-term contracts that include escalation factors.

The NIT natural gas price benchmark decreased in 2018 compared to 2017, primarily due to the continued oversupply of natural gas in North America.

North American natural gas is consumed internally by the Company’s Upstream and Downstream operations, helping to mitigate the impact of weak natural gas benchmark prices on results.

Refining Benchmarks

The Chicago 3:2:1 crack spread is a key indicator for U.S. 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 based on last in first out (“LIFO”) accounting, which is a non-GAAP measure (refer to Section 9.3).

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, BP-Husky Toledo and Superior refineries contain between 13 and 38 percent 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”).

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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. 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, changes in foreign exchange rates impact the translation of U.S. Downstream and Asia Pacific operations and U.S. dollar denominated debt. The Canadian dollar averaged US$0.772 in 2018 compared to US$0.771 in 2017.

A portion of the Company’s long-term sales contracts in Asia Pacific are priced in Chinese Yuan (“RMB”). An increase in the value of RMB relative to the Canadian dollar will increase the revenues received in Canadian dollars from the sale of natural gas commodities in the region. The Canadian dollar averaged RMB 5.104 in 2018 compared to RMB 5.208 in 2017.

Sensitivity Analysis

The following table is indicative of the impact of changes in certain key variables in 2018 on earnings before income taxes and net earnings. The table below reflects what the expected effect would have been on the financial results for 2018 had the indicated variable increased by the notional amount. The analysis is based on business conditions and production volumes during 2018. 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.

Sensitivity Analysis	2018 Average		Increase	Effect on Earnings before Income Taxes(1)						Effect on Net Earnings(1)
				($ millions)			($/share)(2)			($ millions)			($/share)(2)
WTI benchmark crude oil price(3)(4)		64.77	US$1.00/bbl		96			0.10			70			0.07
NYMEX benchmark natural gas price(5)		3.09	US$0.20/mmbtu		—			—			—			—
WTI/Lloyd crude blend differential(6)		26.09	US$1.00/bbl		(7	)		(0.01	)		(5	)		(0.01	)
Canadian asphalt margins		27.82	Cdn $1.00/bbl		10			0.01			8			0.01
Canadian light oil margins		0.042	Cdn $0.005/litre		14			0.01			10			0.01
Chicago 3:2:1 crack spread		15.94	US$1.00/bbl		112			0.11			87			0.09
Exchange rate (US $ per Cdn $)(3)(7)		0.772	US$0.01		(59	)		(0.06	)		(44	)		(0.04	)

⁽¹⁾  Excludes mark to market accounting impacts.

⁽²⁾  Based on 1,005.1 million common shares outstanding as of December 31, 2018.

⁽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⁾  Excludes impact on Canadian asphalt operations.

⁽⁷⁾  Assumes no foreign exchange gains or losses on U.S. dollar denominated long-term debt and other monetary items, including cash balances.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 12

4.0 Results of Operations

4.1 Segment Earnings

Segmented Earnings	Earnings (Loss) before Income Taxes						Net Earnings (Loss)					Capital Expenditures(1)
($ millions)	2018			2017			2018			2017		2018		2017
Upstream
Exploration and Production		288			239			223			174		2,656		1,476
Infrastructure and Marketing		780			118			567			86		—		—
Downstream
Upgrading		496			151			361			110		62		230
Canadian Refined Products		216			142			158			104		74		87
U.S. Refining and Marketing		619			371			481			234		665		313
Corporate		(471	)		(597	)		(333	)		78		121		114
Total		1,928			424			1,457			786		3,578		2,220

⁽¹⁾  Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the year. Includes Exploration and Production assets acquired through acquisition, but excludes assets acquired through corporate acquisition.

4.2 Upstream

Exploration and Production

Exploration and Production Earnings Summary ($ millions)	2018			2017
Gross revenues		4,330			4,978
Royalties		(335	)		(363	)
Net revenues		3,995			4,615
Production, operating and transportation expenses		1,527			1,650
Selling, general and administrative expenses		296			265
Depletion, depreciation, amortization and impairment (“DD&A”)		1,811			2,237
Exploration and evaluation expenses		149			146
Gain on sale of assets		(2	)		(42	)
Other – net		(120	)		6
Share of equity investment gain		(51	)		(12	)
Financial items		97			126
Provisions for income taxes		65			65
Net earnings		223			174

Exploration and Production net revenues decreased by $620 million in 2018 compared to 2017, primarily due to lower average realized sales prices combined with lower production, both of which are described in more detail below.

Selling, general and administrative expenses increased by $31 million in 2018 compared to 2017, primarily due to higher employee costs.

Gain on sale of assets decreased by $40 million in 2018 compared to 2017, primarily due to the disposition of select legacy assets in Western Canada in 2017.

Other – net for Exploration and Production increased by $126 million in 2018 compared to 2017, primarily due to profit or loss elimination between segments.

Share of equity investment gain increased by $39 million in 2018 compared to 2017, primarily due to the investment in the Husky-CNOOC Madura Ltd. joint venture, which is accounted for under the equity method. The BD Project reached first production in the third quarter of 2017.

Financial items decreased by $29 million in 2018 compared to 2017, primarily due to higher capitalized interest expense due to thermal projects and West White Rose project.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 13

Average Sales Prices Realized

Average Sales Prices Realized	2018		2017
Crude oil and NGL ($/bbl)
Light & Medium crude oil		83.71		67.36
NGL(1)		55.72		44.18
Heavy crude oil		39.26		43.38
Bitumen		30.17		38.20
Total crude oil and NGL average		42.16		46.09
Natural gas average ($/mcf) (1)		6.64		5.52
Total average ($/boe)		41.50		42.47

⁽¹⁾  Reported average NGL and natural gas prices include Husky’s working interest production from the BD Project (40 percent). Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for consolidated financial statement purposes.

The average sales prices realized by the Company for crude oil and NGL production decreased by nine percent in 2018 compared to 2017, primarily due to widening of the Canadian light/heavy oil differential.

The average sales prices realized by the Company for natural gas increased by 20 percent in 2018 compared to 2017. The increase was primarily due to a higher percentage of fixed priced natural gas production from both the Liwan Gas Project and BD Project relative to total natural gas production.

Daily Gross Production

Daily Gross Production	2018		2017
Crude oil and NGL (mbbls/day)
Western Canada
Light and Medium crude oil		9.4		12.1
NGL		12.0		10.5
Heavy crude oil		36.8		44.4
Bitumen(1)		124.2		119.1
		182.4		186.1
Atlantic
White Rose and Satellite Fields – light crude oil		17.4		30.0
Terra Nova – light crude oil		4.0		4.0
		21.4		34.0
Asia Pacific
Wenchang – light crude oil		—		5.3
Liwan and Wenchang – NGL(2)		8.4		7.0
Madura – NGL(3)		2.5		0.6
		10.9		12.9
		214.7		233.0
Natural gas (mmcf/day)
Western Canada		291.0		378.2
Asia Pacific
Liwan(2)		184.8		152.9
Madura(3)		31.2		8.0
		216.0		160.9
		507.0		539.1
Total (mboe/day)		299.2		322.9

⁽¹⁾  Bitumen consists of production from thermal developments in Lloydminster, the Tucker Thermal Project located near Cold Lake, Alberta and the Sunrise Energy Project.

⁽²⁾  Reported production volumes include Husky’s working interest production from the Liwan Gas Project (49 percent).

⁽³⁾  Reported production volumes include Husky’s working interest production from the BD Project (40 percent). 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 2018 | 14

Crude Oil and NGL Production

Crude oil and NGL production decreased by 18.3 mbbls/day, or eight percent, in 2018 compared to 2017. The decrease was primarily due to lower production in Atlantic due to the suspension of operations on the SeaRose FPSO vessel in January and November 2018, a high water cut well at North Amethyst combined with natural well declines, a reduction of heavy crude oil production due to natural declines and reduced optimization activities in the Company’s non-thermal developments, lower crude oil production in Asia Pacific due to the expiry of the Company’s participation in the Wenchang oilfield PSC in late 2017, and lower production in Western Canada as a result of the disposition of select legacy assets in 2017. The decreases were partially offset by increased bitumen production from the Company’s thermal projects, combined with increased NGL production in Asia Pacific and Western Canada.

Natural Gas Production

Natural gas production decreased by 32.1 mmcf/day, or six percent, in 2018 compared to 2017. In Western Canada, natural gas production decreased by 87.2 mmcf/day, primarily due to the disposition of select legacy assets in 2017. In Asia Pacific, natural gas production increased by 55.1 mmcf/day, primarily due to increased gas demand at the Liwan Gas Project and higher production from the BD Project.

Exploration and Production Revenue Mix (Percentage of Upstream Net Revenues)	2018		2017
Crude oil and NGL
Light & Medium crude oil		22		25
NGL(1)		10		6
Heavy crude oil		11		14
Bitumen		29		33
Crude oil and NGL		72		78
Natural gas(1)		28		22
Total		100		100

⁽¹⁾  Reported average NGL and natural gas revenue include Husky’s working interest production from the BD Project (40 percent). Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for consolidated financial statement purposes.

2019 Production Guidance and 2018 Actual

			Year ended
	Guidance		December 31		Guidance
Gross Production	2019		2018		2018
Canada
Light & Medium crude oil (mbbls/day)		29 - 31		31		35 - 36
NGL (mbbls/day)		12 - 13		12		10 - 11
Heavy crude oil & bitumen (mbbls/day)		155 - 163		161		162 - 164
Natural gas (mmcf/day)		297 - 307		291		285 - 290
Canada total (mboe/day)		246 - 258		252		255 - 259
Asia Pacific
Light crude oil (mbbls/day)		3 - 3		—		0 - 0
NGL (mbbls/day)(1)		6 - 7		11		10 - 11
Natural gas (mmcf/day)(1)		210 - 220		216		210 - 215
Asia Pacific total (mboe/day)		44 - 47		47		45 - 46
Total (mboe/day)		290 - 305		299		300 - 305

⁽¹⁾  Includes Husky’s working interest production from the BD Project (40 percent). Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for consolidated financial statement purposes.

Total production for the year ended December 31, 2018 was marginally under the production guidance, primarily due to the factors that impacted crude oil and NGL production discussed above. The expected total production volumes in 2019 will remain comparable to 2018 after factoring in the reductions associated with Government of Alberta curtailment and partial suspension of operations at the White Rose field in Atlantic. The 2019 production guidance reflects curtailment affecting production at the Tucker Thermal Project, the Sunrise Energy Project and the conventional heavy oil business.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 15

Factors that could potentially impact the Company’s production performance in 2019 include, but are not limited to:

• eventual outcome and impact of the government-mandated production curtailment in Alberta.

• changes in crude oil and natural gas prices such as increases in commodity pricing, which may result in the decision to accelerate near-term growth projects, or decreases in commodity pricing, which may result in the decision to temporarily shut-in production or delay capital expenditures.

• performance of recently commissioned facilities, new wells brought onto production and unanticipated reservoir response from existing fields.

• unplanned or extended maintenance and turnarounds at any of the Company’s operated or non-operated facilities, upgrading, refining, pipeline or offshore assets.

• business interruptions due to unexpected events such as severe weather, fires, blowouts, freeze-ups, equipment failures, unplanned and extended pipeline shutdowns and other similar events.

• defaults by contracting parties whose services, goods or facilities are necessary for the Company’s production.

• operations and assets which are subject to a number of political, economic and socio-economic risks.

Royalties

Royalties (Percent)	2018		2017
Western Canada		9		7
Atlantic		8		9
Asia Pacific(1)		7		6
Total		8		7

⁽¹⁾  Reported royalties include Husky’s working interest from the BD Project (40 percent). Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for interim financial statement purposes.

Royalty rates for Western Canada increased by two percent in 2018 compared to 2017, primarily due to higher WTI prices for the majority of 2018. Royalty rates for Atlantic decreased by one percent in 2018 compared to 2017, primarily due to lower production combined with higher eligible costs. Royalty rates for Asia Pacific increased by one percent in 2018 compared to 2017, primarily due to higher production from the BD Project which has higher royalty rates than the Liwan Gas Project.

Operating Costs

Operating Costs ($ millions)	2018		2017
Western Canada		1,218		1,331
Atlantic		213		213
Asia Pacific		95		94
Total		1,526		1,638
Per unit operating costs ($/boe)		14.00		13.93

Total Exploration and Production operating costs were $1,526 million in 2018 compared to $1,638 million in 2017. Total per unit operating costs averaged $14.00/boe in 2018 compared to $13.93/boe in 2017. The increase in per unit operating costs was primarily due to the factors discussed below.

Per unit operating costs in Atlantic averaged $27.21/bbl in 2018 compared to $17.12/bbl in 2017. The increase in per unit operating costs was primarily due to lower production.

Per unit operating costs in Western Canada averaged $14.48/boe in 2018 compared to $14.67/boe in 2017. The decrease in per unit operating costs was primarily due to lower energy costs and the continued ramp-up at the Sunrise Energy Project.

Per unit operating costs in Asia Pacific averaged $5.53/boe in 2018 compared to $6.47/boe in 2017. The decrease in per unit operating costs was primarily due to higher production at the Liwan Gas and BD projects.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 16

Exploration and Evaluation Expenses

Exploration and Evaluation Expenses ($ millions)	2018		2017
Seismic, geological and geophysical		102		113
Expensed drilling		41		22
Expensed land		6		11
Total		149		146

Exploration and Evaluation expenses were $149 million in 2018 compared to $146 million in 2017.

Depletion, Depreciation, Amortization and Impairment

DD&A expense decreased by $426 million in 2018 compared to 2017, primarily due to lower production in 2018, the recognition of a pre-tax impairment charge of $173 million in 2017, and additional heavy oil and bitumen reserves bookings in the fourth quarter of 2017. In 2018, total DD&A excluding impairment averaged $16.99/boe compared to $17.61/boe in 2017.

Exploration and Production Capital Expenditures

Exploration and Production capital expenditures were higher in 2018 compared to 2017, reflecting increased spending across the portfolio. Exploration and Production capital expenditures were as follows:

Exploration and Production Capital Expenditures(1) ($ millions)	2018		2017
Exploration
Western Canada		99		63
Thermal developments		7		8
Atlantic		73		67
Asia Pacific(2)		52		10
		231		148
Development
Western Canada		332		196
Thermal developments		874		534
Non-thermal developments		110		106
Atlantic		916		417
Asia Pacific(2)		148		2
		2,380		1,255
Acquisitions
Western Canada		4		25
Thermal developments		41		48
		45		73
Total		2,656		1,476

⁽¹⁾  Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the period.

⁽²⁾  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.

Western Canada

During 2018, $435 million (16 percent) was invested in Western Canada compared to $284 million (19 percent) in 2017. Capital expenditures in 2018 related primarily to resource play development targeting the Spirit River Formation in the Ansell and Kakwa areas and the Montney Formation in the Wembley and Karr areas.

Thermal Developments

During 2018, $922 million (35 percent) was invested in thermal developments compared to $590 million (40 percent) in 2017. Capital expenditures in 2018 related primarily to the development of the Rush Lake 2 Thermal Project, and construction work at the Dee Valley and Spruce Lake Central thermal projects.

Non-Thermal Developments

During 2018, $110 million (four percent) was invested in non-thermal developments compared to $106 million (seven percent) in 2017. Capital expenditures in 2018 related primarily to sustainment activities.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 17

Atlantic

During 2018, $989 million (37 percent) was invested in Atlantic compared to $484 million (33 percent) in 2017. Capital expenditures in 2018 related primarily to the development of the West White Rose Project and sustainment and development activities at the White Rose field and satellite extensions.

Asia Pacific

During 2018, $200 million (eight percent) was invested in Asia Pacific compared to $12 million (one percent) in 2017. Capital expenditures in 2018 related primarily to the continued development of Liuhua 29-1, and the exploration of Blocks 15/33 and 16/25.

Exploration and Production Wells Drilled

Onshore Drilling Activity

The following table discloses the number of wells drilled during 2018 and 2017:

	2018				2017
Wells Drilled (wells)(1)	Gross		Net		Gross		Net
Thermal developments		150		140		64		64
Non-thermal developments		31		26		29		27
Western Canada		46		45		36		33
Total		227		211		129		124

⁽¹⁾  Excludes service/stratigraphic test wells for evaluation purposes.

Thermal developments consisted of drilling and completion activity related to the Sunrise Energy Project and the Dee Valley and Spruce Lake Central thermal projects. Western Canada drilling and completion activity increased primarily due to a drilling program targeting the Spirit River Formation in the Ansell and Kakwa areas, as well as a drilling program targeting the Montney Formation in the Wembley and Karr areas.

Offshore Drilling Activity

The following table discloses the Company’s Offshore drilling activity during 2018:

Region	Well	Working Interest	Well Type
Atlantic	North Amethyst G-25 11	68.875 percent	Development
Atlantic	White Rose A-24	68.875 percent	Exploration
Asia Pacific	Block 15/33 XJ 34-3-2	100 percent	Exploration
Asia Pacific	Block 15/33 PY 3-6-1	100 percent	Exploration
Asia Pacific	Block 16/25 HZ 25-7-4	100 percent	Exploration

2019 Upstream Capital Expenditures Program

2019 Upstream Capital Expenditures Program ($ millions)
Thermal developments	670 - 700
Non-thermal developments	100 - 110
Western Canada	150 - 160
Atlantic	1,120 - 1,190
Asia Pacific(1)	440 - 460
Total Upstream capital expenditures	2,480 - 2,620

⁽¹⁾  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.

The 2019 Upstream capital expenditures program reflects a focus on near-term and medium-cycle projects in the Integrated Corridor business, including further growing the Lloydminister thermal bitumen portfolio as well as the Ansell resource play in Western Canada. In the Offshore business, the capital expenditures program will support the continuation of construction at the Liuhua 29-1 field offshore China and the West White Rose Project in Atlantic.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 18

The Company has budgeted $730 - $760 million in thermal developments for 2019, primarily for the development of the Dee Valley, Spruce Lake North and Spruce Lake Central thermal bitumen projects. Capital expenditures will also take place in support of environmental and regulatory work on Spruce Lake East which was sanctioned in the fourth quarter of 2018. The Company is making progress in its strategy to transition a greater percentage of production to long-life thermal bitumen production and the 2019 Upstream capital expenditures program will continue to build on this momentum.

The Company has budgeted $100 - $110 million in non-thermal developments for 2019, primarily for sustainment activities.

The Company has budgeted $180 - $190 million in Western Canada for 2019, primarily for the planned drilling activities in the Spirit River Formation in the Ansell and Kakwa areas as well as in the Montney Formation, and sustainment and maintenance activities.

The Company has budgeted $1,120 - $1,190 million in Atlantic for 2019, primarily for the construction of the West White Rose Project.

The Company has budgeted $350 - $370 million in Asia Pacific in 2019, primarily for the continued development of the third field of the Liwan Gas Project, Liuhua 29-1.

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, 2018 with a preparation date of January 31, 2019.

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, 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 or on the Company’s website at www.huskyenergy.com.

Sproule Associates Ltd. (“Sproule”), an independent firm of qualified oil and gas reserves evaluation engineers, was engaged to conduct an audit and review of the Company’s crude oil, natural gas and NGL reserves estimates. Sproule issued an audit opinion on January 31, 2019 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.

At December 31, 2018, the Company’s proved oil and gas reserves were 1,471 mmboe, up from 1,301 mmboe at the end of 2017. The Company’s 2018 reserves replacement ratio, defined as net additions divided by total production during the period, was 260 percent excluding economic revisions (255 percent including economic revisions).

Major changes to proved reserves in 2018 included:

• Discoveries, Extensions and Improved Recovery additions of 266 mmboe including 102 mmbbls at the Sunrise Energy Project from new locations as part of a full field optimized development plan, 63 mmbbls for two new Lloydminster thermal bitumen steam-assisted gravity drainage projects, first booking of Liuhua 29-1 of 31 mmboe, 43 mmboe in Ansell, Kakwa, North Blackstone, Wapiti and Wembley from new locations, and 8 mmbbls for additional reserves associated with the West White Rose Project.

• Technical revisions of 15 mmboe included 31 mmbbls added for the Lloydminster thermal bitumen projects and 9 mmboe added in China due to higher performance than last year’s forecast. These were offset by a reduction of 23 mmbbls at the Sunrise Energy Project as a result of applying a more conservative estimate of the recovery factor early in the 50-year life of the field.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 19

Proved Plus Probable Reserves and Production at December 31, 2018:

Reconciliation of Proved Reserves ⁽¹⁾

	Canada															International						Total
	Western Canada												Atlantic
	Light/ Medium Crude Oil & NGL (mmbbls)			Heavy Crude Oil (mmbbls) (2)			Bitumen (mmbbls)(2)			Natural Gas (bcf)			Light Crude Oil (mmbbls)			Light Crude Oil & NGL (mmbbls)			Natural Gas (bcf)			Crude Oil, Bitumen & NGL (mmbbls)			Natural Gas (bcf)			Equivalent Units (mmboe)
(forecast prices and costs
before royalties)
Proved reserves
December 31, 2017		66			64			747			1,174			97			21			662			995			1,836			1,301
Technical revisions		(2	)		2			8			4			(3	)		2			47			7			51			15
Acquisitions		—			—			2			8			—			—			—			2			8			4
Dispositions		—			(1	)		—			(2	)		—			—			—			(1	)		(2	)		(1	)
Discoveries, extensions and improved recovery		9			5			178			220			7			5			153			204			373			266
Economic factors		—			(3	)		—			(10	)		—			—			—			(3	)		(10	)		(5	)
Production		(8	)		(13	)		(45	)		(106	)		(8	)		(4	)		(79	)		(78	)		(185	)		(109	)
Proved reserves December 31, 2018		65			54			890			1,288			93			24			783			1,126			2,071			1,471
Proved and probable reserves December 31, 2018		80			76			1,722			1,751			177			30			984			2,085			2,735			2,541
December 31, 2017		80			86			1,609			1,597			196			31			1,014			2,002			2,611			2,437

⁽¹⁾ Numbers in the above table may not align with other disclosures due to rounding.

⁽²⁾  Lloydminster thermal property reserves are classified as bitumen.

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)			Natural Gas (bcf)			Light Crude Oil (mmbbls)			Light Crude Oil & NGL (mmbbls)			Natural Gas (bcf)			Crude Oil, Bitumen & NGL (mmbbls)			Natural Gas (bcf)			Equivalent Units (mmboe)
Proved developed reserves
December 31, 2017		62			64			162			823			37			21			561			346			1,384			575
Technical revisions		(2	)		2			2			2			(5	)		3			46			—			48			9
Transfer from proved undeveloped		1			—			21			24			—			—			—			22			24			26
Acquisitions		—			—			—			8			—			—			—			—			8			2
Dispositions		(1	)		—			—			(2	)		—			—			—			(1	)		(2	)		(1	)
Discoveries, extensions and improved recovery		4			4			2			63			—			—			—			10			63			20
Economic factors		—			(4	)		—			(8	)		—			—			—			(4	)		(8	)		(5	)
Production		(8	)		(13	)		(45	)		(106	)		(8	)		(4	)		(79	)		(78	)		(185	)		(109	)
December 31, 2018		56			53			142			804			24			20			528			295			1,332			517

⁽¹⁾  Number 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 2018 | 20

Infrastructure and Marketing

Infrastructure and Marketing Earnings Summary ($ millions)	2018			2017
Gross revenues		2,211			1,976
Marketing and other		668			(40	)
Expenses
Purchases of crude oil and products		2,087			1,855
Production, operating and transportation expenses		23			13
Selling, general and administrative expenses		5			4
Depletion, depreciation, amortization and impairment		—			2
Loss on sale of assets		—			1
Other – net		2			(8	)
Share of equity investment gain		(18	)		(49	)
Provisions for income taxes		213			32
Net earnings		567			86

Infrastructure and Marketing gross revenues and purchases of crude oil and products increased by $235 million and $232 million, respectively, in 2018 compared to 2017, primarily due to increased volumes and prices.

Marketing and other increased by $708 million in 2018 compared to 2017, primarily due to crude oil marketing gains from widening location price differentials between Canada and the U.S., which the Company is able to capture due to its committed capacity on the Keystone pipeline.

Share of equity investment gain decreased by $31 million in 2018 compared to 2017, primarily due to higher maintenance expense and higher depreciation from HMLP in 2018.

Provisions for income taxes increased by $181 million in 2018 compared to 2017, primarily due to higher earnings before income taxes in 2018.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 21

4.3 Downstream

Upgrading

Upgrading Earnings Summary ($ millions, except where indicated)	2018		2017
Gross revenues		1,750		1,440
Expenses
Purchases of crude oil and products		928		983
Production, operating and transportation expenses		195		197
Selling, general and administrative expenses		7		9
Depletion, depreciation, amortization and impairment		123		99
Financial items		1		1
Provisions for income taxes		135		41
Net earnings		361		110
Upgrading throughput (mbbls/day)(1)		75.6		68.5
Total sales (mbbls/day)		74.7		68.5
Synthetic crude oil sales (mbbls/day)		52.9		49.8
Upgrading differential ($/bbl)		29.05		18.66
Unit margin ($/bbl)		30.15		18.28
Unit operating cost ($/bbl)(2)		7.07		7.88

⁽¹⁾  Throughput includes diluent returned to the field.

⁽²⁾  Based on throughput.

Upgrading operations add value by processing heavy crude oil into high value synthetic crude oil and low sulphur distillates. Upgrading profitability is primarily dependent on the differential between the cost of heavy crude oil feedstock and the sales price of synthetic crude oil.

Upgrading gross revenues increased by $310 million in 2018 compared to 2017, primarily due to higher realized prices for synthetic crude oil and higher sales volumes as the Lloydminster Upgrader was in a major planned turnaround in the second quarter of 2017. The price of Husky Synthetic Blend averaged $75.55/bbl in 2018 compared to $67.05/bbl in 2017.

Upgrading feedstock purchases decreased by $55 million in 2018 compared to 2017, primarily due to the decrease in the average cost of heavy crude oil feedstock.

Upgrading DD&A increased by $24 million in 2018 compared to 2017, primarily due to a higher depletable base in 2018 resulting from the capitalization of turnaround costs in 2017.

Provisions for income taxes increased by $94 million in 2018 compared to 2017, primarily due to higher earnings before income taxes in 2018.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 22

Canadian Refined Products

Canadian Refined Products Earnings Summary ($ millions, except where indicated)	2018			2017
Gross revenues		3,412			2,787
Expenses
Purchases of crude oil and products		2,760			2,219
Production, operating and transportation expenses		265			256
Selling, general and administrative expenses		47			53
Depletion, depreciation, amortization and impairment		115			111
Gain on sale of assets		(2	)		(5	)
Other – net		(1	)		(1	)
Financial items		12			12
Provisions for income taxes		58			38
Net earnings		158			104
Number of fuel outlets(1)		557			518
Fuel sales volume, including wholesale
Fuel sales (millions of litres/day)		7.7			7.3
Fuel sales per retail outlet (thousands of litres/day)		12.3			12.1
Refinery throughput
Prince George Refinery (mbbls/day)(2)		10.7			11.2
Lloydminster Refinery (mbbls/day)(2)		27.1			26.8
Ethanol production (thousands of litres/day)		819.4			804.8

⁽¹⁾  Average number of fuel outlets for period indicated.

⁽²⁾ Includes all crude oil, feedstock, intermediate feedstock and blend-stocks used in producing sales volumes from the refinery.

Canadian Refined Products gross revenues increased by $625 million in 2018 compared to 2017, primarily due to higher product prices.

Canadian Refined Products purchases of crude oil and products increased by $541 million in 2018 compared to 2017, primarily due to higher commodity prices.

Provisions for income taxes increased by $20 million in 2018 compared to 2017, primarily due to higher earnings before income taxes in 2018.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 23

U.S. Refining and Marketing

U.S. Refining and Marketing Earnings Summary ($ millions, except where indicated)	2018			2017
Gross revenues		11,770			9,355
Expenses
Purchases of crude oil and products		10,334			8,059
Production, operating and transportation expenses		795			563
Selling, general and administrative expenses		22			15
Depletion, depreciation, amortization and impairment		450			354
Other – net		(464	)		(21	)
Financial items		14			14
Provisions for income taxes		138			137
Net earnings		481			234
Selected operating data:
Lima Refinery throughput (mbbls/day)(1)		151.1			172.2
BP-Husky Toledo Refinery throughput (mbbls/day)(1)(2)		71.1			76.6
Superior Refinery throughput (mbbls/day)(1)		11.7			5.5
Refining and marketing margin (US$/bbl crude throughput)(3)		13.03			11.44
Refinery inventory (mmbbls)(4)		6.9			9.2

⁽¹⁾  Includes all crude oil, feedstock, intermediate feedstock and blend-stocks used in producing sales volumes from the refinery.

⁽²⁾  Reported throughput volumes include Husky’s working interest from the BP-Husky Toledo Refinery (50 percent).

⁽³⁾  Prior period has been restated to include impact of U.S. product marketing margin.

⁽⁴⁾  Feedstock and refined products are included in refinery inventory.

U.S. Refining and Marketing gross revenues increased by $2,415 million in 2018 compared to 2017, primarily due to higher refined product prices partially offset by lower sales volumes as the Lima Refinery completed a major planned turnaround in late 2018.

U.S. Refining and Marketing purchases of crude oil and products increased by $2,275 million in 2018 compared to 2017, primarily due to higher commodity prices partially offset by lower throughput volumes as the Lima Refinery completed a major planned turnaround in late 2018.

Production, operating and transportation expenses increased by $232 million in 2018 compared to 2017, primarily due to the acquisition of the Superior Refinery in late 2017 and the incident at the refinery in April 2018.

DD&A expense increased by $96 million in 2018 compared to 2017, primarily due to the derecognition of assets damaged during the incident at the Superior Refinery.

Other – net increased by $443 million in 2018 compared to 2017, primarily due to pre-tax insurance recoveries for property damage, rebuild costs, business interruption and clean-up costs associated with the incident at the Superior Refinery.

Downstream Capital Expenditures

In 2018, Downstream capital expenditures totalled $801 million compared to $630 million in 2017. In Canada, capital expenditures of $136 million related primarily to the scheduled partial turnaround at the Lloydminster Upgrader in the second quarter of 2018, and various reliability and environmental activities at the Lloydminster and Prince George refineries. In the U.S., capital expenditures of $665 million related primarily to the turnaround and crude oil flexibility project at the Lima Refinery, the turnaround at the Superior Refinery, and various reliability and environmental initiatives at the Lima and BP-Husky Toledo refineries.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 24

4.4 Corporate

Corporate Summary ($ millions) income (expense)	2018			2017
Production, operating and transportation expenses		2			—
Selling, general and administrative expenses		(277	)		(304	)
Depletion, depreciation, amortization and impairment		(92	)		(79	)
Other – net		8			(6	)
Net foreign exchange gain (loss)		14			(6	)
Finance income		52			32
Finance expense		(178	)		(234	)
Recovery of income taxes		138			675
Net earnings (loss)		(333	)		78

The Corporate segment reported a net loss of $333 million in 2018 compared to net earnings of $78 million in 2017. The change was primarily due to the recognition of a $436 million deferred tax recovery in 2017, related to the reduction of the U.S. Federal corporate tax rate that took effect at the beginning of 2018.

Finance income increased by $20 million in 2018 compared to 2017, primarily due to interest on short-term investments.

Finance expense decreased by $56 million in 2018 compared to 2017, primarily due to lower interest expense in 2018 from the repayment of long term debt in late 2017.

Net foreign exchange gain increased by $20 million due to the items noted below.

Foreign Exchange Summary ($ millions, except where indicated)	2018			2017
Non-cash working capital loss		(3	)		(3	)
Other foreign exchange gain (loss)		17			(3	)
Net foreign exchange gain (loss)		14			(6	)
U.S./Canadian dollar exchange rates:
At beginning of year	US$	0.799		US$	0.745
At end of year	US$	0.733		US$	0.799

Included in the other foreign exchange gain (loss) 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)	2018		2017
Provisions for (recovery of) income taxes		471		(362	)
Cash income taxes paid (recovered)		37		(41	)

Consolidated income taxes were a provision of $471 million in 2018 compared to a recovery of $362 million in 2017. The increase in consolidated income taxes was primarily due to the recognition of a $436 million deferred tax recovery related to the U.S. tax reform changes enacted in December 2017, combined with higher earnings before income taxes in 2018.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 25

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, Environmental and Safety Incidents

The Company’s businesses are subject to inherent operational risks with respect to safety and the environment that require continuous vigilance. The Company seeks to minimize these operational risks by designing and building its facilities and conducting its operations in a safe and reliable manner using the Husky Operational Integrity Management System, an integrated management system that considers environmental requirements as well as process and occupational safety. Failure to manage the risks effectively could result in potential fatalities, serious injury, interruptions to activities or use of assets, damage to assets, environmental impact or loss of licence to operate. Enterprise risk management, emergency preparedness, business continuity and security policies and programs are in place for all operating areas and are adhered to on an ongoing basis. 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 natural gas production. Lower prices for crude oil, NGL and 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 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 heavy crude oil and bitumen is limited and planned increases of North American heavy crude oil and bitumen production may create the need for additional heavy oil and bitumen 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 a number of factors including, but not limited to, actions taken by the Organization of the Petroleum Exporting Countries (”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 natural gas production is currently located in Western Canada and Asia Pacific. Western Canada’s natural gas production is subject to North American market forces. North American natural gas supply and demand is affected by a number of factors including, but not limited to, the amount of 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.

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 natural gas.

The fluctuations in refined products, crude oil and 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.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 26

Reservoir Performance 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, investor confidence and the Company’s ability to deliver on its growth strategy.

In order to maintain the Company’s future production of crude oil, 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. To mitigate the effects of this, the Company must undertake successful exploration and development programs, increase the recovery factor from existing properties through applied technology and identify and execute strategic acquisitions of proved developed and undeveloped properties and unproved prospects. 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.

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. With growing oil production across North America and the limited availability of infrastructure to carry the Company’s products to the marketplace, oil and natural gas transportation capacity is expected to 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.

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 activist 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.

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.

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.

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, 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.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 27

Partner Misalignment

Joint venture partners operate 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.

Reserves Data, Future Net Revenue and Resource Estimates

The reserves data contained or referenced in the 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 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 percent of the future net revenue discounted at 10 percent 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. Inaccurate appraisal of large project reservoirs could result in missed production, revenue and earnings targets and could have a material adverse effect on the Company’s reputation, investor confidence and ability to deliver on its growth business strategy.

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, development or exploratory activities. As these governments continually balance competing demands from different interest groups 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 Regulation

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, formulation or demand of products, which may or may not be offset through market pricing.

The Company anticipates further changes in environmental legislation could occur, which may result in stricter standards and enforcement, larger fines and liabilities, increased compliance costs and approval delays for critical licences and permits.

Climate Change Regulation

Climate change regulations may become more onerous over time as governments implement policies to further reduce greenhouse gases (“GHG”) emissions. As part of long range planning, the Company assesses future compliance costs associated with regulations of GHG emissions in its operations and the evaluation of future projects, based on the Company’s outlook for carbon pricing under current and pending regulations. The impact of recently announced regulations is being evaluated as provinces and the federal government finalize carbon pricing regulations. 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. The Company continues to monitor 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 the Company operates.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 28

The Alberta Climate Leadership Plan began to be implemented in 2017. This plan includes an economy-wide carbon levy, rising to $30 per tonne in 2018 which applies to the Lloydminster Refinery, as well as a Carbon Competitiveness Incentive Regulation (“CCIR”) that manages emissions at large final emitting facilities (”LFEs”) including the Tucker Thermal Project and Sunrise Energy Project. Under the previous Specified Gas Emitters Regulation, which expired at the end of 2017, the Tucker Thermal Project generated over 500,000 tonnes of credits due to improved emission intensity performance. These credits are eligible to offset future compliance obligations under the CCIR. These regulations are not anticipated to have a material impact over the duration of the Company’s five-year long-range plan. The CCIR is due for review in 2020, along with the federal carbon policy. Uncertainty regarding future regulations, including carbon price and the details of implementing the oil sands emission limit, make it difficult to predict the potential future impact on the Company.

In December 2017, the Government of Saskatchewan released “Prairie Resilience”a policy paper on climate change strategy in which it outlines multiple commitments across five areas designed to make Saskatchewan more resilient to the climatic, economic and policy impacts of climate change. As part of this strategy, the government developed output-based performance standards for large industrial emitters and a Climate Resilience Measurement Framework. The large industrial emitters regulations will apply to the Company’s Lloydminster Upgrader and ethanol plant and Saskatchewan thermal projects to reduce emissions while considering the economic competitiveness of these sectors. The smaller facilities (emitting under 25,000 tonnes/year) will be exposed to the federal carbon levy. The cost impacts of this levy on the Company’s cold heavy oil production may be measurable.

The cost of compliance with British Columbia’s $35 per tonne carbon tax (increasing to $40 on April 1, 2019) and the Renewable and Low Carbon Fuel Requirements Regulation may materially adversely affect the Company’s Prince George Refinery. Additionally, future regulations in support of British Columbia’s commitment under its Climate Leadership Plan are uncertain.

The application of the federal carbon policy in Manitoba may significantly adversely affect the Company’s Minnedosa ethanol plant in Manitoba.

The Newfoundland and Labrador performance-based regulation imposes a carbon price beginning at $20/tonne in 2019 and escalating to $50/tonne in 2022. The provincial Gasoline and Diesel Tax begins at $20/tonne and will be adjusted with a goal of Atlantic parity related to provincial taxation (including carbon tax) of fuel products. The carbon tax rates will only increase to match equivalent increases in carbon taxation programs in neighbouring 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 the Company’s Atlantic region operation.

Within the mandate of the Pan-Canadian Framework on Clean Growth and Climate Change, in May 2017, the Government of Canada released a technical paper on the federal carbon policy introducing two key elements: a carbon levy applied to gas that the Company uses at its facilities as well as retail fuel ($20 per tonne starting in 2019 and increasing by $10 annually to $50 per tonne in 2022), and an output-based pricing system for industrial facilities emitting GHGs above 50,000 tonnes of CO₂e per year. 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. Draft CFS regulations are expected to be published in mid-2019 and final regulations in 2020, with the regulations expected to come into force in 2022. The impact of the CFS is still uncertain.

The Company’s U.S. refining business may be materially adversely affected by the implementation of the Environmental Protection Agency’s (”EPA”) climate change rules or, by future U.S. GHG legislation that applies to the oil and gas industry or the consumption of petroleum products and by other U.S. climate change statutes at the federal or state level or by regulations imposed by other federal agencies or 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 emission 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 and results of operations.

The U.S. Renewable Fuel Standard (”RFS”) program, through the EPA-specified renewable volume obligation (”RVO”), requires refiners to add annually increasing amounts of renewable fuels to their petroleum products or to purchase RINs in lieu of such blending. Due to regulatory uncertainty and in part due to the U.S. fuel supply reaching the “blend wall” (the 10 percent limit prescribed by most automobile warranties), the price and availability of RINs have been volatile.

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. 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.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 29

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.

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.

Climatic Conditions

Extreme climatic conditions may 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 Newfoundland and Labrador. 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 Newfoundland and Labrador may threaten Atlantic oil production facilities, cause damage to equipment and possible production disruptions, spills, other asset damage and human impacts. The Company has in place a number of policies to protect people, equipment and the environment in the event of extreme weather conditions and ice melt conditions.

The Company’s Atlantic operations have a robust ice management program, which uses a range of resources including a dedicated 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 commence in February 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. The Company also maintains a series of ad-hoc relationships with contractors, allowing the quick mobilization of additional resources as required. The Company regularly assesses all aspects of its ice management program in order 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. The Company 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. The Company 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.

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.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 30

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 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 of the Company’s Board of Directors has oversight of the Company’s risk mitigation strategies related to cybersecurity.

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. There is a risk that the Company may have difficulty attracting and retaining personnel with the required skill levels. 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.

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 Husky 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.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 31

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.

On December 4, 2018, the Company entered into cash flow hedges using forward interest rate swaps to fix the underlying U.S. $500 million 10-year note fixed rate to December 15, 2019.

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.

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.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 32

The Company is committed to retaining investment grade credit ratings to support access to capital markets and currently has 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	Stable	Stable	Stable
Senior Unsecured Debt	BBB	Baa2	A(low)
Series 1 Preferred Shares	P-3(high)		Pfd-2(low)
Series 2 Preferred Shares	P-3(high)		Pfd-2(low)
Series 3 Preferred Shares	P-3(high)		Pfd-2(low)
Series 5 Preferred Shares	P-3(high)		Pfd-2(low)
Series 7 Preferred Shares	P-3(high)		Pfd-2(low)
Commercial Paper			R-1(low)

Debt Covenants

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

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 33

6.0 Liquidity and Capital Resources

6.1 Summary of Cash Flow

Cash Flow Summary ($ millions)	2018			2017
Cash flow
Operating activities		4,134			3,704
Financing activities		(325	)		363
Investing activities		(3,521	)		(2,789	)

Cash Flow from Operating Activities

Cash flow generated from operating activities increased by $430 million in 2018 compared to 2017. The increase was primarily due to an increase from the Company’s Infrastructure and Marketing segment, higher realized prices for synthetic crude oil combined with decreased average cost of crude oil feedstock in the Company’s upgrading operations, and increased production from the Company’s Asia Pacific operations.

Cash Flow from (used for) Financing Activities

Cash flow used for financing activities increased by $688 million in 2018 compared to 2017. Financing activities in 2018 related primarily to the reinstatement of the quarterly cash dividend in 2018. Financing activities in 2017 related primarily to the net issuance of long-term debt.

Cash Flow used for Investing Activities

Cash flow used for investing activities increased by $732 million in 2018 compared to 2017. The increase was primarily due to increased capital expenditures in 2018.

6.2 Working Capital Components

Working capital is the amount by which current assets exceed current liabilities. At December 31, 2018, the Company’s working capital was $694 million compared to $2,109 million at December 31, 2017. A reconciliation of the Company’s working capital is as follows:

Working Capital ($ millions)	December 31, 2018			December 31, 2017			Change
Cash and cash equivalents		2,866			2,513			353
Accounts receivable		1,355			1,186			169
Income taxes receivable		112			164			(52	)
Inventories		1,232			1,513			(281	)
Prepaid expenses		123			145			(22	)
Restricted cash		—			95			(95	)
Accounts payable and accrued liabilities		(3,159	)		(3,033	)		(126	)
Short-term debt		(200	)		(200	)		—
Long-term debt due within one year		(1,433	)		—			(1,433	)
Asset retirement obligations		(202	)		(274	)		72
Net working capital		694			2,109			(1,415	)

The increase in cash and cash equivalents was primarily due to the higher global commodity prices for the majority of 2018. Fluctuations in accounts receivable and accounts payable were due to the timing of settlements in 2018 compared to 2017. The decrease in income taxes receivable was primarily due to the timing of expected tax refunds. The decrease in inventories was primarily driven by decreased market values in the fourth quarter of 2018. The decrease in restricted cash was primarily due to the expiry of the Company’s participation in the Wenchang oilfield PSC in late 2017. The increase in long-term debt due within one year was due to the timing of debt maturities.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 34

6.3 Sources of Liquidity

Liquidity describes a company’s ability to access cash. Sources of liquidity include funds from operations, proceeds from the issuance of equity, 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 equity, the issuance of debt, borrowings under committed and uncommitted credit facilities and cash proceeds from asset sales. The Company is continually examining its options with respect to sources of long and short-term capital resources to ensure it retains financial flexibility.

At December 31, 2018, the Company had the following available credit facilities:

Credit Facilities ($ millions)	Available		Unused
Operating facilities(1)		900		461
Syndicated credit facilities(2)		4,000		3,800
		4,900		4,261

⁽¹⁾  Consists of demand credit facilities.

⁽²⁾ Commercial paper outstanding is supported by the Company’s syndicated credit facilities.

At December 31, 2018, the Company had $4,261 million of unused credit facilities of which $3,800 million are long-term committed credit facilities and $461 million are short-term uncommitted credit facilities. A total of $439 million short-term uncommitted borrowing credit facilities was used in support of outstanding letters of credit and $200 million of long-term committed borrowing credit facilities was used in support of commercial paper. At December 31, 2018, the Company had no direct borrowing against committed credit facilities. The maturity dates for the Company’s revolving syndicated credit facilities are March 9, 2020 and June 19, 2022. The Company’s ability to renew existing bank credit facilities and raise new debt is 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.

The Company’s share capital is not subject to external restrictions. The Company’s leverage covenant under both of its revolving syndicated credit facilities is debt to capital 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 agreement divided by total debt, shareholders’ equity and certain adjusting items specified in the agreement. This covenant is used to assess the Company’s financial strength. If the Company does not comply with the covenants under the syndicated credit facilities, there is the risk that repayment could be accelerated. The Company was in compliance with the syndicated credit facility covenants at December 31, 2018, 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, 2018.

On March 10, 2017, the Company issued $750 million of 3.60 percent notes due March 10, 2027. The notes are redeemable at the option of the Company at any time, subject to a make-whole premium unless the notes are redeemed in the three month period prior to maturity. Interest is payable semi-annually on March 10 and September 10 of each year, beginning September 10, 2017. The notes are unsecured and unsubordinated and rank equally with all of the Company’s other unsecured and unsubordinated indebtedness.

On March 30, 2017, the Company filed a universal short form base shelf prospectus (the “2017 Canadian Shelf Prospectus”) with applicable securities regulators in each of the provinces of Canada that enables the Company to offer up to $3.0 billion of common shares, preferred shares, debt securities, subscription receipts, warrants and other units in Canada up to and including April 30, 2019. The 2017 Canadian Shelf Prospectus replaced the Company’s Canadian universal short form base shelf prospectus which expired on March 23, 2017. During the 25-month period that the 2017 Canadian Shelf Prospectus is in effect, securities may be offered in amounts, at prices and on terms set forth in a prospectus supplement.

On September 15, 2017, the Company repaid the maturing 6.20 percent notes issued under a trust indenture dated September 11, 2007. The amount paid to note holders was $365 million, including $11 million of interest.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 35

On January 29, 2018, the Company filed a universal short form base shelf prospectus (“the 2018 U.S. Shelf Prospectus”) with the Alberta Securities Commission. On January 30, 2018, the Company’s related U.S. registration statement filed with the Securities and Exchange Commission (”SEC”) containing the 2018 U.S. Shelf Prospectus became effective which enables 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. up to and including February 29, 2020. The 2018 U.S. Shelf Prospectus replaced the Company’s U.S. universal short form base shelf prospectus which expired on January 22, 2018. During the 25-month period that the 2018 U.S. Shelf Prospectus and the related U.S. registration statement are effective, securities may be offered in amounts, at prices and on terms set forth in a prospectus supplement.

As at December 31, 2018, the Company has $3.0 billion in unused capacity under the 2017 Canadian Shelf Prospectus and US$3.0 billion in unused capacity under the 2018 U.S. Shelf Prospectus and related U.S. registration statement. The ability of the Company to utilize the capacity under the 2017 Canadian Shelf Prospectus and 2018 U.S. Shelf Prospectus and related U.S. registration statement is subject to market conditions at the time of sale.

Net Debt

Net debt, a non-GAAP measure (see Section 9.3), is calculated as total debt less cash and cash equivalents. The Company had total debt of $5,747 million and cash and cash equivalents of $2,866 million at December 31, 2018, compared to total debt of $5,440 million and cash and cash equivalents of $2,513 million at December 31, 2017. The Company’s net debt at December 31, 2018 decreased by $46 million when compared to December 31, 2017:

Net Debt(1) ($ millions)	December 31, 2018			December 31, 2017
Net debt at beginning of period		(2,927	)		(4,020	)
Change in net debt due to:
Funds from operations(1)		4,004			3,306
Capital expenditures		(3,578	)		(2,220	)
Capitalized interest		(108	)		(68	)
Corporate acquisition		(15	)		(670	)
Dividends on preferred shares		(35	)		(34	)
Dividends on common shares		(402	)		—
Change in non-cash working capital		485			638
Proceeds from asset sales		4			192
Effect of exchange rates on cash and cash equivalents		65			(84	)
Effect of exchange rates on long-term debt		(307	)		284
Contribution payable payment		—			(142	)
Contributions to joint ventures		(40	)		(81	)
Other		(27	)		(28	)
		46			1,093
Net debt at end of period		(2,881	)		(2,927	)

⁽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 years ended December 31, 2018 and 2017, the Company’s capital expenditures were funded by funds from operations. 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.

On February 28, 2018, the Board of Directors reinstated the quarterly common share cash dividend of $0.075 per share. On July 26, 2018, the quarterly common share cash dividend was increased to $0.125 per share.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 36

6.4 Capital Structure

Capital Structure ($ millions)	December 31, 2018 Outstanding
Total debt(1)		5,747
Shareholders’ equity		19,614

⁽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 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 $25.4 billion at December 31, 2018 (December 31, 2017 – $23.4 billion). To maintain or adjust the capital structure, the Company may, from time to time, issue shares, raise debt and/or adjust its capital spending to manage its current and projected debt levels.

The Company monitors its capital structure and financing requirements 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). The Company’s objective is to maintain a debt to capital employed target of less than 25 percent and a debt to funds from operations ratio of less than 2.0 times. At December 31, 2018, debt to capital employed was 22.7 percent (December 31, 2017 – 23.2 percent) and debt to funds from operations was 1.4 times (December 31, 2017 – 1.6 times), within the Company’s targets.

To facilitate the management of these ratios, the Company prepares annual budgets, which are updated depending on varying factors such as general market conditions and successful capital deployment. The annual budget is approved by the Board of Directors.

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)	2019		2020-2021		2022-2023		Thereafter		Total
Long-term debt and interest on fixed rate debt		1,697		724		956		3,709		7,086
Operating leases(1)		233		245		259		1,186		1,923
Firm transportation agreements(1)		497		1,036		1,030		4,013		6,576
Unconditional purchase obligations(2)		1,620		2,447		1,209		4,822		10,098
Lease rentals and exploration work agreements		49		123		123		930		1,225
Obligations to fund equity investee(3)		53		147		146		395		741
Finance lease obligations(4)		69		138		104		1,014		1,325
Asset retirement obligations(5)		202		293		287		8,541		9,323
	4,420		5,153		4,114		24,610		38,297

⁽¹⁾ Included in the total of operating leases and firm transportation agreements are blending and storage agreements and transportation commitments of $1.1 billion and $1.9 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⁾ Refer to Note 17 in the 2018 consolidated financial statements.

⁽⁵⁾ Asset retirement obligation amounts represent the undiscounted future payments for the estimated cost of abandonment, removal and remediation associated with retiring the Company’s assets. The amounts are inclusive of $128 million of cash deposited into restricted accounts for funding of future asset retirement obligations in Asia Pacific and obligations related to Husky’s working interest from the BD Project (40 percent). Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for interim financial statement purposes.

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.

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.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 37

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, 2018, the Company has deposited funds of $128 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 are related party transactions, as the Company has a 35 percent ownership interest in HMLP and the remaining ownership interests in HMLP belong to Power Assets Holdings Limited and CK Infrastructure Holdings Limited, which are affiliates of one of the Company’s principal shareholders. For the year ended December 31, 2018, the Company charged HMLP $448 million related to construction costs and management services. For the year ended December 31, 2018, the Company had purchases from HMLP of $200 million related to the use of the pipeline for the Company’s blending, transportation and storage activities. As at December 31, 2018, the Company had $140 million due from HMLP.

6.7 Outstanding Share Data

Authorized:

• unlimited number of common shares

• unlimited number of preferred shares

Issued and outstanding: February 21, 2019

• 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	19,934,692
• stock options exercisable	10,443,916

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 38

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 2018 consolidated financial statements. Certain 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.

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.

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.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 39

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 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 result.

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.

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.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 40

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 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.

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. These transactions are on terms equivalent to those that prevail in arm’s-length transactions. 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.

Leases

In January 2016, the IASB issued IFRS 16 Leases, which replaces the current IFRS guidance on leases. Under the current guidance, lessees are required to determine if the lease is a finance or operating lease, based on specified criteria. Finance leases are recognized on the balance sheet while operating leases are recognized in the consolidated statements of income when the expense is incurred. Under IFRS 16, lessees must recognize a lease liability and a right-of-use asset for virtually all lease contracts. The recognition of the present value of minimum lease payments for certain contracts currently classified as operating leases will result in increases to assets, liabilities, depletion, depreciation and amortization, and finance expense, and a decrease to production, operating and transportation expense upon implementation. Optional exemptions to not recognize certain short-term leases or leases of low value can be applied by lessees. For lessors, the accounting remains essentially unchanged.

The Company will adopt IFRS 16 on the effective date of January 1, 2019 and has selected the modified retrospective transition approach. The optional exemptions to not recognize certain short-term and low value leases will be applied.

For leases implemented January 1, 2019, the Company will recognize a right-of-use asset of $1.1 billion equal to the lease liability at the present value of the remaining lease payments discounted using the Company’s incremental borrowing rate. The implementation of IFRS 16 does not have a material impact on the consolidated statements of income. Due to a change in classification of operating lease expenses, cash flow from operating activities will increase and cash flow from financing activities will decrease, with no overall impact to the cash position for the Company.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 41

Change in Accounting Policy

Revenue from Contracts with Customers

In September 2015, the IASB published an amendment to IFRS 15 Revenue from Contracts with Customers, deferring the effective date to annual periods beginning on or after January 1, 2018. IFRS 15 replaces existing revenue recognition guidance with a single comprehensive accounting model. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive when control is transferred to the purchaser. The Company retrospectively adopted the standard on January 1, 2018. The adoption of IFRS 15 did not require any material adjustments to the amounts recorded in the consolidated financial statements; however, additional disclosures are presented in the consolidated financial statements.

Revenue is recognized when the performance obligations are satisfied and revenue can be reliably measured. Revenue is measured at the consideration specified in the contracts and represents amounts receivable for goods or services provided in the normal course of business, net of discounts, customs duties and sales taxes. Natural gas sales in Asia Pacific are under long-term, fixed price contracts. Substantially all other revenue is based on floating prices. Performance obligations associated with the sale of crude oil, crude oil equivalents, and refined products are satisfied at the point in time when the products are delivered to and title passes to the customer. Performance obligations associated with processing services, transportation, blending and storage, and marketing services are satisfied at the point in time when the services are provided.

Financial Instruments

In July 2014, the IASB issued IFRS 9 Financial Instruments to replace IAS 39, which provides a single model for classification and measurement based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial instruments. For financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in other comprehensive income rather than net earnings, unless this creates an accounting mismatch. IFRS 9 includes a new, forward-looking ‘expected loss’ impairment model that will result in a more timely recognition of expected credit losses. In addition, IFRS 9 provides a substantially-reformed approach to hedge accounting. The standard was effective for annual periods beginning on January 1, 2018. The Company retrospectively adopted the standard on January 1, 2018. The adoption of IFRS 9 did not require any material adjustments to the consolidated financial statements.

Financial assets previously classified as loans and receivables (cash and cash equivalents, accounts receivable, restricted cash, and long-term receivables), as well as financial liabilities previously classified as other financial liabilities (accounts payable and accrued liabilities, short-term debt, and long-term debt) have been reclassified to amortized cost. The carrying value and measurement of all financial instruments remains unchanged. The Company’s current process for assessing short-term receivables lifetime expected credit losses collectively in groups that share similar credit risk characteristics is unadjusted with the adoption of the new impairment model and resulted in no additional impairment allowance. Additionally, long-term receivables were assessed individually under the expected credit loss model and no impairment was concluded.

Amendments to IFRS 2 Share-based Payment

In June 2016, the IASB issued amendments to IFRS 2 to be applied prospectively for annual periods beginning on or after January 1, 2018. The amendments clarify how to account for certain types of share-based payment arrangements. The adoption of the amendments did not have a material impact on the Company’s consolidated financial statements.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 42

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”, “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: the Company’s general strategic plans and growth strategies; the Company’s 2019 production guidance, including guidance for specified areas and product types; the Company’s objective of maintaining stated debt to funds from operations and debt to capital employed ratio targets; and the Company’s 2019 Upstream capital expenditure program;

• with respect to the Company’s thermal developments: estimated production and expected timing of first production from the Dee Valley, Spruce Lake Central, Spruce Lake North, Spruce Lake East, Edam Central, Dee Valley 2 and Westhazel projects; the expected timing of regulatory approvals for the Dee Valley 2 and Westhazel projects; and the expected impact of the Alberta government-mandated production curtailment on the Tucker Thermal Project and the Sunrise Energy Project;

• with respect to the Company’s non-thermal developments, the expected impact of the Alberta government-mandated production curtailment;

• with respect to the Company’s Western Canada resource plays, strategic and drilling plans;

• with respect to the Company’s Offshore business in Asia Pacific: the expected timing of commencement of drilling of the remaining three wells at, and first gas production from, Liuhua 29-1; target production from Liuhua 29-1 when fully ramped up; the expected timing of drilling five MDA field production wells and two MBH field production wells, and the expected timing of first gas production and sales therefrom; timing for a second exploration well on Block 16/25; and the expected timing of development and tie-in of the additional MDK shallow water field;

• with respect to the Company’s Offshore business in the Atlantic: the expected timing of first production from the West White Rose Project; the expected timing that two additional infill wells will be completed and come online at the White Rose field; and delineation plans at the A-24 exploration well;

• with respect to the Company’s Infrastructure and Marketing business, the processing capacity expected to be added by the Ansell Corser Gas Plant when it comes online, and the expected timing thereof; and

• with respect to the Company’s Downstream operating segment: plans to market and potentially sell the Prince George Refinery and the Retail and Commercial Network; the expected timing of completion of the crude oil flexibility project at the Lima Refinery; and the expected timing that operations at the Superior Refinery will resume.

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.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 43

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, 2018 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 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, 2018 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, 2018.

The Company uses the term barrels of oil equivalent (”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 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 but 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 incremental proved reserves additions for that period divided by the Company’s Upstream gross production for the same period. The reserves replacement ratio measures the amount of reserves added 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 percent for the company to maintain its reserves. The reserves replacement ratio only measures the amount of reserves added to a company’s reserve base during a given period. Reserves replacement ratios that exclude economic factors will exclude the impacts that changing oil and gas prices have.

This document includes an estimate of net pay thickness at White Rose A-24, which estimate may be considered to be anticipated results under NI 51-101. The estimate was prepared internally. The risks and uncertainties associated with recovery of resources from A-24 include, but are not limited to: that Husky may encounter unexpected drilling results; the occurrence of unexpected events in the exploration for, and the operation and development of, oil and gas; delays in anticipated timing of drilling and completion of wells; geological, technical, drilling and processing problems; and other difficulties in producing petroleum reserves.

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 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 2018 | 44

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: funds from operations, free cash flow, total debt, net debt, operating netback, debt to capital employed, debt to funds from operations and LIFO. None of these measures is used to enhance the Company’s reported financial performance or position. There are no comparable measures in accordance with IFRS for operating netback, 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 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 plus 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, 2018, 2017 and 2016:

Debt to Funds from Operations ($ millions)	December 31, 2018		December 31, 2017		December 31, 2016
Total debt		5,747		5,440		5,339
Funds from operations		4,004		3,306		2,198
Debt to funds from operations		1.4		1.6		2.4

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 plus 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.

Funds from operations was restated in the second quarter of 2017 in order to be more comparable to similar non-GAAP measures presented by other companies. Changes from prior period presentation include the removal of adjustments for settlement of asset retirement obligations and deferred revenue. Prior periods have been restated to conform to current presentation.

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.

Free cash flow has been restated in the fourth quarter of 2018 in order to be more comparable to similar non-GAAP measures presented by other companies. Changes from prior period presentation include the removal of investment in joint ventures. Prior periods have been restated to conform to current presentation.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 45

The following table shows the reconciliation of net earnings to funds from operations and free cash flow, and related per share amounts for the three months and years ended December 31:

Reconciliation of Cash Flow	Three months ended						Year ended
($ millions)	Dec. 31			Dec. 31			Dec. 31			Dec. 31			Dec. 31
	2018			2017			2018			2017			2016
Net earnings		216			672			1,457			786			922
Items not affecting cash:
Accretion		25			28			97			112			126
Depletion, depreciation, amortization and impairment		662			647			2,591			2,882			2,462
Inventory write-down to net realizable value		60			—			60			—			9
Exploration and evaluation expenses		22			—			29			6			86
Deferred income taxes (recoveries)		25			(360	)		396			(359	)		29
Foreign exchange loss (gain)		1			1			(6	)		(4	)		(4	)
Stock-based compensation		(50	)		25			44			45			33
Gain on sale of assets		—			(13	)		(4	)		(46	)		(1,634	)
Unrealized market to market loss (gain)		(16	)		57			(150	)		56			38
Share of equity investment gain		(16	)		(1	)		(69	)		(61	)		(15	)
Gain on insurance recoveries for damage to property		(253	)		—			(253	)		—			—
Other		2			8			21			16			24
Settlement of asset retirement obligations		(65	)		(45	)		(181	)		(136	)		(87	)
Deferred revenue		(30	)		(5	)		(100	)		(16	)		209
Distribution from joint ventures		—			—			72			25			—
Change in non-cash working capital		730			337			130			398			(227	)
Cash flow – operating activities		1,313			1,351			4,134			3,704			1,971
Change in non-cash working capital		(730)			(337)			(130)			(398)			227
Funds from operations		583			1,014			4,004			3,306			2,198
Capital expenditures		(1,265)			(745)			(3,578)			(2,220)			(1,705)
Free Cash Flow		(682	)		269			426			1,086			493
Funds from operations – basic		0.58			1.01			3.98			3.29			2.19
Funds from operations – diluted		0.58			1.01			3.98			3.29			2.19

LIFO

The Chicago 3:2:1 market crack spread benchmark is based on LIFO inventory costing, a non-GAAP measure, which assumes that crude oil feedstock costs are based on the current month price of WTI, while on a FIFO basis, the comparable GAAP measure, crude oil feedstock costs included in realized margins reflect purchases made in previous months. Management believes that comparisons between LIFO and FIFO inventory costing assist management and investors in assessing differences in the Company’s realized refining margins compared to the Chicago 3:2:1 market crack spread benchmark, which is commonly used by the Company’s U.S. refining peers.

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, 2018, 2017 and 2016:

Net Debt ($ millions)	December 31, 2018			December 31, 2017			December 31, 2016
Total debt		5,747			5,440			5,339
Cash and cash equivalents		(2,866	)		(2,513	)		(1,319	)
Net debt		2,881			2,927			4,020

Operating Netback

Operating netback is a common non-GAAP metric used in the oil and gas industry. Management believes this measurement assists management and investors to evaluate the specific operating performance by product at the oil and gas lease level. Operating netback is calculated as gross revenue less royalties, production and operating and transportation costs on a per unit basis.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 46

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, 2018, 2017 and 2016:

Total Debt ($ millions)	December 31, 2018		December 31, 2017		December 31, 2016
Short-term debt		200		200		200
Long-term debt due within one year		1,433		—		403
Long-term debt		4,114		5,240		4,736
Total debt		5,747		5,440		5,339

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.

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 25, 2019. 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 February 25, 2019, should be read in conjunction with the 2018 consolidated financial statements and related notes. Readers are also encouraged to refer to the Company’s interim reports filed for 2018, which contain Management’s Discussion and Analysis and consolidated financial statements, and the Company’s Annual Information Form for the year ended December 31, 2018, 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. Husky’s Management’s Discussion and Analysis for the interim period ended December 31, 2018 is incorporated herein by reference.

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, 2018 and 2017 and the Company’s financial position at December 31, 2018 and 2017.

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.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 47

Terms
Asia Pacific	Includes Upstream oil and gas exploration and production activities located offshore China and Indonesia
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 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 plus 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
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 1 are referred to as high-TAN crudes
Last in first out (“LIFO”)	Last in first out accounting assumes that crude oil feedstock costs are based on the current month price of WTI
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
Operating netback	Gross revenue less royalties, operating costs and transportation costs on a per unit basis
Plan of Development	As it relates to the Company’s operations in Indonesia, a Plan of Development represents development planning on one or more oil and gas fields in an integrated and optimal plan for the production of hydrocarbon reserves considering technical, economical and environmental aspects. An initial Plan of Development in a development area needs both SKK Migas and the Minister of Energy and Mineral Resources approvals. Subsequent Plans of Development in the same development area only need SKK Migas approval
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 2018 | 48

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
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
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 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 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
Western Canada	Includes Upstream oil and gas exploration and development activities located in Alberta, Saskatchewan and British Columbia

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 2018 | 49

9.5 Disclosure Controls and Procedures

Disclosure Controls and Procedures

Husky’s management, under supervision of the Chief Executive Officer and the 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, 2018, 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 Chief Executive Officer and 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, 2018, management, under the supervision of the Chief Executive Officer and 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, 2018, 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 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, 2018, 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 2018 | 50

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 2018			Dec. 31 2017
Gross revenues and Marketing and other
Upstream
Exploration and Production		643			1,355
Infrastructure and Marketing		678			633
Downstream
Upgrading		307			452
Canadian Refined Products		821			815
U.S. Refining and Marketing		2,766			2,755
Corporate and Eliminations		(173	)		(476	)
Total gross revenues and marketing and other		5,042			5,534
Net earnings (loss)
Upstream
Exploration and Production		(206	)		170
Infrastructure and Marketing		126			(27	)
Downstream
Upgrading		80			48
Canadian Refined Products		55			39
U.S. Refining and Marketing		213			129
Corporate and Eliminations		(52	)		313
Net earnings		216			672
Per share – Basic		0.21			0.66
Per share – Diluted		0.16			0.66
Cash flow – operating activities		1,313			1,351
Funds from operations(1)		583			1,014
Per share – Basic		0.58			1.01
Per share – Diluted		0.58			1.01
Upstream
Daily gross production
Crude oil and NGL production (mbbls/day)(2)		214.7			231.2
Natural gas production (mmcf/day)(2)		537.6			534.9
Total production (mboe/day)		304.3			320.4
Average sales prices realized ($/boe)
Crude oil and NGL ($/bbl)(2)		18.93			51.06
Natural gas ($/mcf) (2)		6.86			5.89
Total average sales prices realized ($/boe)		25.47			46.69
Downstream
Refinery throughput
Lloydminster Upgrader (mbbls/day)		71.8			78.2
Lloydminster Refinery (mbbls/day)		25.3			30.1
Prince George Refinery (mbbls/day)		10.7			11.3
Lima Refinery (mbbls/day)		105.9			164.5
BP-Husky Toledo Refinery (mbbls/day)		73.2			81.0
Superior Refinery (mbbls/day)		—			22.0
Total throughput (mbbls/day)		286.9			387.1

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 51

	Three months ended
Fourth Quarter Results Summary (continued) ($ millions, except where indicated)	Dec. 31 2018		Dec. 31 2017
Upgrading unit margin ($/bbl)		29.13		20.65
Upgrading synthetic crude oil sales (mbbls/day)		53.8		56.5
Upgrading total sales (mbbls/day)		73.5		77.9
Retail fuel sales (million of litres/day)		8.0		8.0
Canadian light oil margins ($/litre)		0.037		0.052
Lloydminster Refinery asphalt margin ($/bbl)		41.50		15.79
U.S. Refining and Marketing margin (US$/bbl crude throughput)(3)		9.12		14.89
U.S./Canadian dollar exchange rate (US$)		0.757		0.786

⁽¹⁾  Funds from operations is a non-GAAP measure. Refer to Section 9.3 for a reconciliation to the corresponding GAAP measure.

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

⁽³⁾  Prior period has been restated to include impact of U.S. product marketing margin.

Gross Revenue and Marketing and Other

The Company’s consolidated gross revenues and marketing and other decreased by $492 million in the fourth quarter of 2018 compared to the fourth quarter of 2017.

In the Upstream business segment, Exploration and Production gross revenues decreased primarily due to lower average realized sales prices combined with lower production. Infrastructure and Marketing gross revenues and marketing and other increased primarily due to crude oil marketing gains from widening location price differentials between Canada and the U.S., which the Company is able to capture due to its committed capacity on the Keystone pipeline.

In the Downstream business segment, gross revenues decreased primarily due to lower realized prices for synthetic crude oil in the Upgrading business segment.

Net Earnings (Loss)

The Company’s consolidated net earnings decreased by $456 million in the fourth quarter of 2018 compared to the fourth quarter of 2017.

In the Upstream business segment, Exploration and Production net loss increased primarily due to the same factors which impacted gross revenue and marketing and other.

In the Downstream business segment, Upgrading net earnings increased primarily due to the widening of the light/heavy oil differentials. Canadian Refined Products and U.S. Refining and Marketing net earnings increased primarily due to lower average cost of crude oil feedstock and pre-tax insurance recoveries for property damage, rebuild costs and business interruption associated with the incident at the Superior Refinery in the fourth quarter of 2018 compared to the fourth quarter of 2017.

In the Corporate business segment, net loss increased primarily due to the recognition of a $436 million deferred tax recovery in 2017, related to the reduction of the U.S. Federal corporate tax rate that took effect at the beginning of 2018.

Cash Flow – Operating Activities and Funds from Operations

Cash flow – operating activities and funds from operations decreased by $38 million and $431 million, respectively, in the fourth quarter of 2018 compared to the fourth quarter of 2017, primarily due to the same factors which impacted the Upstream and Downstream business segment net earnings, excluding the pre-tax insurance recoveries for rebuild costs associated with the incident at the Superior Refinery. Funds from operations is a non-GAAP measure; refer to Section 9.3.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 52

Daily Gross Production

Production decreased by 16.1 mbbls/day during the fourth quarter of 2018 compared to the fourth quarter of 2017 as a result of:

• Decreased crude oil production in Atlantic due to the suspension of operations on the SeaRose FPSO vessel;

• Decreased heavy crude oil production due to natural declines and reduced optimization activities in the Company’s non-thermal developments;

• Decreased crude oil production in Asia Pacific due to the expiry of the Company’s participation in the Wenchang oilfield PSC in late 2017; and

• Decreased crude oil and natural gas production in Western Canada as a result of the disposition of select legacy assets in 2017.

Partially offset by:

• Increased bitumen production from the Company’s thermal projects;

• Increased natural gas and NGL production from the Liwan Gas and BD projects; and

• Increased NGL production in Western Canada.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 53

Segmented Operational Information

Segmented Operational Information	2018												2017
($ millions, except where indicated)	Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
Gross revenues and Marketing and other
Upstream
Exploration and Production		643			1,319			1,284			1,084			1,355			1,157			1,215			1,251
Infrastructure and Marketing		678			769			821			611			633			509			425			369
Downstream
Upgrading		307			534			444			465			452			377			227			384
Canadian Refined Products		821			1,001			869			721			815			802			602			568
U.S. Refining and Marketing(1)		2,766			3,198			3,035			2,771			2,755			2,292			2,135			2,173
Corporate and Eliminations		(173	)		(521	)		(470	)		(390	)		(476	)		(424	)		(253	)		(397	)
Total gross revenues and marketing and other		5,042			6,300			5,983			5,262			5,534			4,713			4,351			4,348
Net earnings (loss)
Upstream
Exploration and Production		(206	)		214			158			57			170			28			(67	)		43
Infrastructure and Marketing		126			149			154			138			(27	)		10			33			70
Downstream
Upgrading		80			88			84			109			48			9			5			48
Canadian Refined Products		55			43			32			28			39			38			12			15
U.S. Refining and Marketing		213			158			115			(5	)		129			114			12			(21	)
Corporate and Eliminations		(52	)		(107	)		(95	)		(79	)		313			(63	)		(88	)		(84	)
Net earnings (loss)		216			545			448			248			672			136			(93	)		71
Per share – Basic		0.21			0.53			0.44			0.24			0.66			0.13			(0.10	)		0.06
Per share – Diluted		0.16			0.53			0.44			0.24			0.66			0.13			(0.10	)		0.06
Cash flow – operating activities		1,313			1,283			1,009			529			1,351			894			813			646
Funds from operations(2)		583			1,318			1,208			895			1,014			891			715			686
Per share – Basic		0.58			1.31			1.20			0.89			1.01			0.89			0.71			0.68
Per share – Diluted		0.58			1.31			1.20			0.89			1.01			0.89			0.71			0.68
U.S./Canadian dollar exchange rate (US$)		0.757			0.765			0.775			0.791			0.786			0.799			0.744			0.756
Exploration and Production
Daily production, before royalties
Crude oil & NGL production (mbbls/day)
Light & Medium crude oil		22.6			33.7			29.7			37.5			46.6			42.7			56.0			60.7
NGL(3)		24.8			24.5			21.8			20.5			21.4			19.3			17.2			14.2
Heavy crude oil		34.4			34.6			38.5			39.7			42.3			44.1			43.1			48.0
Bitumen		132.9			117.3			123.2			123.2			120.9			117.7			117.4			120.6
Total crude oil & NGL production (mbbls/day)		214.7			210.1			213.2			220.9			231.2			223.8			233.7			243.5
Natural gas (mmcf/day)(3)		537.6			519.5			494.0			477.0			534.9			563.4			514.8			543.1
Total production (mboe/day)		304.3			296.7			295.5			300.4			320.4			317.7			319.5			334.0
Average sales prices
Light & Medium crude oil ($/bbl)		60.19			93.84			92.23			82.08			77.05			63.13			63.27			66.70
NGL ($/bbl)(3)		53.36			60.08			54.13			55.03			51.19			37.83			38.00			49.64
Heavy crude oil ($/bbl)		18.71			50.09			54.22			32.80			48.64			41.89			42.06			41.28
Bitumen ($/bbl)		5.42			46.00			44.41			27.77			41.88			38.14			37.46			35.20
Natural gas ($/mcf) (3)		6.86			6.15			6.53			7.03			5.89			5.25			5.59			5.35
Operating costs ($/boe)		13.75			14.68			14.22			13.33			13.20			14.12			14.65			13.75
Operating netbacks(3)(4)
Lloydminster Thermal ($/bbl)(5)		(0.05	)		35.83			36.16			19.77			33.98			27.38			24.14			24.88
Lloydminster Non-Thermal ($/boe)(5)		(11.80	)		13.28			20.83			4.13			19.36			12.46			12.70			14.80
Tucker Thermal ($/bbl)(5)		(5.08	)		29.53			31.67			16.16			31.79			28.35			24.09			23.53
Sunrise Energy Project ($/bbl)(5)		(25.60	)		15.79			12.59			(5.62	)		16.50			16.05			11.67			2.24
Western Canada – Crude Oil ($/bbl)(5)		(1.70	)		23.81			29.37			17.88			12.99			3.64			12.03			19.18
Western Canada – NGL & natural gas ($/mcf) (6)		1.13			0.29			0.39			1.33			0.15			0.12			1.01			1.05
Atlantic – Light Oil ($/bbl)(5)		23.19			68.20			57.79			65.23			59.00			35.86			42.08			44.39
Asia Pacific – Light Oil, NGL & natural gas ($/boe)(3)(5)		67.42			65.45			68.44			70.31			65.31			61.81			61.90			64.43
Total ($/boe)(5)		9.42			31.30			31.31			24.37			30.00			23.25			23.53			24.17

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 54

	2018								2017
Segmented Operational Information (continued)	Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
Upgrading
Synthetic crude oil sales (mbbls/day)		53.8		54.9		47.1		56.0		56.5		58.2		30.3		54.1
Total sales (mbbls/day)		73.5		76.7		69.1		79.4		77.9		79.4		40.3		76.2
Upgrading differential ($/bbl)		27.89		29.46		26.67		32.31		21.46		13.60		18.70		20.88
Canadian Refined Products
Fuel sales (millions of litres/day)		8.0		7.7		7.5		7.4		8.0		8.1		6.5		6.4
Refinery throughput(7)
Lloydminster Refinery (mbbls/day)		25.3		27.8		26.8		28.7		30.1		30.0		19.5		28.0
Prince George Refinery (mbbls/day)		10.7		11.5		8.8		12.0		11.3		11.9		9.7		11.8
U.S. Refining and Marketing
Refinery throughput(7)
Lima Refinery (mbbls/day)		105.9		163.3		171.2		164.4		164.5		178.3		174.1		172.0
BP-Husky Toledo Refinery (mbbls/day)(8)		73.2		70.8		65.5		75.0		81.0		77.3		71.1		77.0
Superior Refinery (mbbls/day)(9)		—		—		10.1		37.0		22.0		—		—		—

⁽¹⁾  During the third quarter of 2017, the Company corrected certain intrasegment sales eliminations. Gross revenues and purchases of crude oil and products have been recast for the first two quarters of 2017. There was no impact on net earnings.

⁽²⁾  Funds from operations is a non-GAAP measure. Refer to Section 9.3 for a reconciliation to the corresponding GAAP measure.

⁽³⁾  Reported production volumes and associated per unit values include Husky’s working interest production from the BD Project (40 percent). Revenues and expenses related to the Husky-CNOOC Madura Ltd. joint venture are accounted for under the equity method for financial statement purposes.

⁽⁴⁾  Operating netback is a non-GAAP measure. Refer to Section 9.3.

⁽⁵⁾  Includes associated co-products converted to boe.

⁽⁶⁾  Includes associated co-products converted to mcfge.

⁽⁷⁾  Includes all crude oil, feedstock, intermediate feedstock and blend-stocks used in producing sales volumes from the refinery.

⁽⁸⁾ Reported throughput volumes include Husky’s working interest from the BP-Husky Toledo Refinery (50 percent).

⁽⁹⁾  The Superior Refinery was acquired on November 8, 2017.

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. Stronger crude oil prices realized by the Company for the majority of 2018, and increased Asia Pacific production throughout the year, resulted in an increase to 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:

2018

Q4:

• At the Rush Lake 2 Thermal Project, first production and nameplate capacity of 10,000 bbls/day were achieved.

• At the Spruce Lake North Thermal Project, site clearing was completed.

• At the Tucker Thermal Project, nameplate capacity of 30,000 bbls/day was achieved.

• At the Sunrise Energy Project, nameplate capacity of 60,000 bbls/day was achieved. Additionally, the 10 infill wells previously drilled came online.

• At the Ansell and Kakwa areas, a drilling program targeting the Spirit River Formation continued with six more wells drilled and 12 more were completed.

• At the Karr and Wembley areas, in the Montney Formation, three more wells were drilled and completed.

• On November 16, 2018, a flowline connector separated near the South White Rose Extension Drill Centre, causing a spill of approximately 250 cubic metres of oil. Production at the SeaRose FPSO was shut-in. Operations resumed in the first quarter of 2019.

• The Company is a non-operating partner in two exploration licences awarded in the November 2018 C-NLOPB land sale. The licences are adjacent to Terra Nova and White Rose in the Jeanne d’Arc Basin and will bring the Company’s total licence holdings in the region to nine.

• The Company completed its 2018 planned scope of work on the crude oil flexibility project.

• The Company accrued pre-tax insurance recoveries for property damage, rebuild costs and business interruption associated with the incident at the Superior Refinery of $331 million.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 55

Q3:

• At the Rush Lake 2 Thermal Project, construction of the CPF was completed and first steam was achieved.

• At the Dee Valley Thermal Project, drilling of the second well pad was completed and construction of the CPF continued.

• At the Spruce Lake Central Thermal Project, drilling of the first well pad was completed and construction of the CPF commenced.

• At the Tucker Thermal Project, a planned turnaround was completed in support of reaching its 30,000 bbls/day design capacity.

• At the Ansell and Kakwa areas, an accelerated drilling program from an 18-well program to a 25-well development program continued with eight more wells drilled and nine more were completed.

• At the Karr and Wembley areas, in the Montney Formation, two more wells were drilled and three completed.

• An exploration well was drilled on Block 16/25 which encountered hydrocarbons. Additional evaluation works is being conducted.

• At the Madura Strait, the BD Project achieved its gross daily sales targets of 100 mmcf/day of natural gas (40 mmcf/day Husky working interest) and 6,000 bbls/day of associated NGL (2,400 bbls/day Husky working interest).

• The Company accrued pre-tax insurance recoveries for property damage and clean-up costs associated with the incident at the Superior Refinery of $110 million.

Q2:

• At the Dee Valley Thermal Project, drilling of the first well pad was completed and construction of the CPF commenced.

• At the Spruce Lake Central Thermal Project, site clearing was completed.

• At the Tucker Thermal Project, production from the remaining five wells of the 15-well D West pad commenced.

• At the Sunrise Energy Project, two infill wells commenced production, and the remaining three of 10 infill wells were drilled.

• At the Karr and Wembley areas, in the Montney Formation, two wells were drilled.

• Construction to develop Liuhua 29-1 commenced.

• Two exploration wells were drilled on Block 15/33 in the South China Sea. The first well was a success and the second well, which was drilled on a separate structure, did not encounter commercial hydrocarbons and was written off.

• The Company and CNOOC signed two PSCs for Blocks 22/11 and 23/07 in the Beibu Gulf area of the South China Sea.

• At the West White Rose Project, construction of the concrete gravity structure commenced at the purpose-built graving dock in Argentia, Newfoundland and Labrador.

• An exploration well was drilled north of the main White Rose field. The well encountered a net pay thickness of more than 85 metres of oil-bearing sandstone. The discovery continues to be evaluated and further delineation of the area is planned.

• On April 26, 2018, a fire occurred at the Superior Refinery and operations were suspended. The Company has insurance to cover business interruption, third-party liability and property damage. The Company accrued pre-tax insurance recoveries for property damage associated with the incident of $27 million.

Q1:

• At the Rush Lake 2 Thermal Project, drilling of the 12 SAGD injector-producer well pairs was completed and construction of the CPF continued.

• At the Dee Valley Thermal Project, drilling of the first well pad commenced.

• At the Spruce Lake North and Central thermal projects, site clearing commenced.

• At the Tucker Thermal Project, production from the first 10 wells of the new D West pad commenced.

• At the Sunrise Energy Project, production commenced at the last well pair of the 14 previously drilled well pairs. Two infill wells commenced steaming, and seven out of 10 infill wells were drilled.

• At the Ansell and Kakwa areas, production commenced at the remaining six wells of the 16-well 2017 drilling program. Additionally, an 18-well development program is underway with seven wells drilled and four completed.

• Production operations on the SeaRose FPSO vessel were suspended for nine days due to a regulatory suspension.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 56

2017

Q4:

• On November 8, 2017, the Company completed the purchase of the Superior Refinery, a 50,000 bbls/day permitted capacity facility located in Superior, Wisconsin, U.S., from Calumet Specialty Products Partners, L.P. for $670 million (US$527 million) in cash, which includes $108 million (US$85 million) of working capital.

• At the Tucker Thermal Project, drilling of the new 15-well pad was completed in the second quarter and steaming commenced in the fourth quarter of 2017.

• At the Sunrise Energy Project production continued to ramp-up and the 14 previously drilled well pairs were tied in, with 13 well pairs producing.

• Production from 10 wells of the 16-well program in the Ansell and Kakwa areas was achieved. Due to improved operating efficiencies, drilling times were reduced by 30 percent during 2017, contributing to a 22 percent reduction in per-well drilling costs.

• At Karr in the Montney Formation, two wells were drilled in the third quarter and production was achieved in the fourth quarter.

• Production continued to ramp-up at the BD Project. The first lifting of NGL occurred mid-October.

• An additional infill well was completed at the main White Rose field, which was tied back to the SeaRose FPSO, providing for improved capital efficiencies.

• The sale of select assets in Western Canada to third parties was completed, representing approximately 17,600 boe/day for gross proceeds of approximately $65 million resulting in an after-tax gain of $9 million.

• The recognition of $436 million in deferred tax recovery related to the reduction in the U.S. Federal corporate tax rate that will take effect in 2018.

Q3:

• First production was achieved at the BD Project in the Madura Strait. NGL were produced and stored on the FPSO.

• Nine wells of a 16-well program in the Ansell and Kakwa areas were completed by the third quarter.

• Production from one well at Wembley in the Montney Formation commenced.

• At South White Rose, an oil production well and a supporting water injection well were completed.

• The consolidation of a single expanded truck transport network of approximately 160 sites was completed during the quarter.

Q2:

• The Company recognized an after-tax impairment expense of $123 million related to crude oil and natural gas assets located in Western Canada in the Upstream Exploration and Production segment. The impairment charges were the result of changes in the development plans and reinforced by market transactions.

• Lloydminster Upgrader and Lloydminster Asphalt Refinery throughput and sales volumes were lower due to major planned turnarounds at the Lloydminster Upgrader and Lloydminster Asphalt Refinery.

• The sale of select assets in Western Canada to third parties was completed, representing approximately 2,600 boe/day for gross proceeds of approximately $123 million, resulting in an after-tax gain of $23 million.

Q1:

• First oil was achieved at the Tucker Thermal Project’s new eight-well pad.

• First oil was achieved from a North Amethyst infill well.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 57

Segmented Financial Information

	Upstream																								Downstream
	Exploration and Production(1)												Infrastructure and Marketing												Upgrading
2018 ($ millions)	Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
Gross revenues		643			1,319			1,284			1,084			530			601			634			446			307			534			444			465
Royalties		(50	)		(106	)		(99	)		(80	)		—			—			—			—			—			—			—			—
Marketing and other		—			—			—			—			148			168			187			165			—			—			—			—
Revenues, net of royalties		593			1,213			1,185			1,004			678			769			821			611			307			534			444			465
Expenses
Purchases of crude oil and products		(1	)		—			1			—			497			567			602			421			110			328			251			239
Production, operating and transportation expenses		388			398			384			357			4			2			15			2			51			52			46			46
Selling, general and administrative expenses		72			71			77			76			2			1			1			1			1			2			2			2
Depletion, depreciation, amortization and impairment		469			461			434			447			(1	)		—			1			—			36			30			29			28
Exploration and evaluation expenses		53			26			40			30			—			—			—			—			—			—			—			—
Loss (gain) on sale of assets		—			2			—			(4	)		—			—			—			—			—			—			—			—
Other – net		(109	)		(42	)		27			4			1			(1	)		—			2			—			—			—			—
	872			916			963			910			503			569			619			426			198			412			328			315
Earnings (loss) from operating activities		(279	)		297			222			94			175			200			202			185			109			122			116			150
Share of equity investment income (loss)		18			12			17			4			(2	)		6			9			5			—			—			—			—
Financial items
Net foreign exchange gains
(losses)		—			—			—			—			—			—			—			—			—			—			—			—
Finance income		—			2			1			9			—			—			—			—			—			—			—			—
Finance expenses		(29	)		(29	)		(22	)		(29	)		—			—			—			—			—			(1	)		—			—
		(29	)		(27	)		(21	)		(20	)		—			—			—			—			—			(1	)		—			—
Earnings (loss) before income tax		(290	)		282			218			78			173			206			211			190			109			121			116			150
Provisions for (recovery of) income taxes
Current		(233	)		(46	)		(106	)		(99	)		193			14			84			63			40			47			36			45
Deferred		149			114			166			120			(146	)		43			(27	)		(11	)		(11	)		(14	)		(4	)		(4	)
		(84	)		68			60			21			47			57			57			52			29			33			32			41
Net earnings (loss)		(206	)		214			158			57			126			149			154			138			80			88			84			109
Capital expenditures(3)		898			715			524			519			—			—			(15	)		15			9			9			33			11
Total assets		19,175			18,410			18,263			18,070			1,301			1,529			1,519			1,417			1,149			1,308			1,275			1,270

⁽¹⁾  Includes allocated depletion, depreciation, amortization and impairment related to assets in Infrastructure and Marketing, as these assets provide a service to Exploration and Production.

⁽²⁾  Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices.

⁽³⁾  Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the period. Includes Exploration and Production assets acquired through acquisition, and excludes assets acquired through corporate acquisition.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 58

Downstream (continued)																								Corporate and Eliminations(2)												Total
Canadian Refined Products												U.S. Refining and Marketing
Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
	821			1,001			869			721			2,766			3,198			3,035			2,771			(173	)		(521	)		(470	)		(390	)		4,894			6,132			5,796			5,097
	—			—			—			—			—			—			—			—			—			—			—			—			(50	)		(106	)		(99	)		(80	)
	—			—			—			—			—			—			—			—			—			—			—			—			148			168			187			165
	821			1,001			869			721			2,766			3,198			3,035			2,771			(173	)		(521	)		(470	)		(390	)		4,992			6,194			5,884			5,182
	637			834			711			578			2,523			2,741			2,565			2,505			(173	)		(521	)		(470	)		(390	)		3,593			3,949			3,660			3,353
	67			66			72			60			193			222			217			163			(2	)		—			—			—			701			740			734			628
	11			12			11			13			5			5			7			5			21			96			88			72			112			187			186			169
	29			29			28			29			102			129			125			94			27			23			22			20			662			672			639			618
	—			—			—			—			—			—			—			—			—			—			—			—			53			26			40			30
	—			(2	)		—			—			—			—			—			—			—			—			—			—			—			—			—			(4	)
	(1	)		—			—			—			(334	)		(107	)		(29	)		6			1			—			(9	)		—			(442	)		(150	)		(11	)		12
	743			939			822			680			2,489			2,990			2,885			2,773			(126	)		(402	)		(369	)		(298	)		4,679			5,424			5,248			4,806
	78			62			47			41			277			208			150			(2	)		(47	)		(119	)		(101	)		(92	)		313			770			636			376
	—			—			—			—			—			—			—			—			—			—			—			—			16			18			26			9
	—			—			—			—			—			—			—			—			(2	)		(9	)		3			22			(2	)		(9	)		3			22
	—			—			—			—			—			—			—			—			16			13			12			11			16			15			13			20
	(3	)		(3	)		(3	)		(3	)		(3	)		(4	)		(3	)		(4	)		(41	)		(43	)		(46	)		(48	)		(76	)		(80	)		(74	)		(84	)
	(3	)		(3	)		(3	)		(3	)		(3	)		(4	)		(3	)		(4	)		(27	)		(39	)		(31	)		(15	)		(62	)		(74	)		(58	)		(42	)
	75			59			44			38			274			204			147			(6	)		(74	)		(158	)		(132	)		(107	)		267			714			604			343
	41			15			19			25			3			2			2			2			(18	)		(19	)		(17	)		(18	)		26			13			18			18
	(21	)		1			(7	)		(15	)		58			44			30			(3	)		(4	)		(32	)		(20	)		(10	)		25			156			138			77
	20			16			12			10			61			46			32			(1	)		(22	)		(51	)		(37	)		(28	)		51			169			156			95
	55			43			32			28			213			158			115			(5	)		(52	)		(107	)		(95	)		(79	)		216			545			448			248
	22			23			18			11			296			196			118			55			40			25			30			26			1,265			968			708			637
	1,431			1,578			1,578			1,547			8,566			8,209			8,003			7,926			3,603			3,641			3,354			3,057			35,225			34,675			33,992			33,287

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 59

	Upstream																								Downstream
	Exploration and Production(1)												Infrastructure and Marketing												Upgrading
2017 ($ millions)	Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
Gross revenues		1,355			1,157			1,215			1,251			704			513			426			333			452			377			227			384
Royalties		(97	)		(71	)		(91	)		(104	)		—			—			—			—			—			—			—			—
Marketing and other		—			—			—			—			(71	)		(4	)		(1	)		36			—			—			—			—
Revenues, net of royalties		1,258			1,086			1,124			1,147			633			509			425			369			452			377			227			384
Expenses
Purchases of crude oil and products		(1	)		—			1			—			657			495			408			295			304			287			144			248
Production, operating and transportation expenses		390			413			430			417			7			1			2			3			49			45			54			49
Selling, general and administrative expenses		84			63			61			57			1			1			1			1			3			1			3			2
Depletion, depreciation, amortization and impairment		471			514			705			547			—			1			1			—			30			31			19			19
Exploration and evaluation expenses		38			31			56			21			—			—			—			—			—			—			—			—
Loss (gain) on sale of assets		(13	)		3			(33	)		1			—			—			—			1			—			—			—			—
Other – net		37			(7	)		(39	)		15			(6	)		10			(9	)		(3	)		—			—			—			—
		1,006			1,017			1,181			1,058			659			508			403			297			386			364			220			318
Earnings (loss) from operating activities		252			69			(57	)		89			(26	)		1			22			72			66			13			7			66
Share of equity investment income (loss)		13			(1	)		(1	)		1			(12	)		13			24			24			—			—			—			—
Financial items
Net foreign exchange gains (losses)		—			—			—			—			—			—			—			—			—			—			—			—
Finance income		1			2			1			1			—			—			—			—			—			—			—			—
Finance expenses		(33	)		(31	)		(35	)		(32	)		—			—			—			—			—			(1	)		—			—
		(32	)		(29	)		(34	)		(31	)		—			—			—			—			—			(1	)		—			—
Earnings (loss) before income tax		233			39			(92	)		59			(38	)		14			46			96			66			12			7			66
Provisions for (recovery of) income taxes
Current		(8	)		(25	)		12			(13	)		—			—			—			—			24			12			4			23
Deferred		71			36			(37	)		29			(11	)		4			13			26			(6	)		(9	)		(2	)		(5	)
		63			11			(25	)		16			(11	)		4			13			26			18			3			2			18
Net earnings (loss)		170			28			(67	)		43			(27	)		10			33			70			48			9			5			48
Capital expenditures(4)		525			355			307			289			—			—			—			—			14			27			168			21
Total assets		17,920			18,021			18,275			18,802			1,364			1,447			1,338			1,422			1,263			1,261			1,179			1,129

⁽¹⁾  Includes allocated depletion, depreciation, amortization and impairment related to assets in Infrastructure and Marketing, as these assets provide a service to Exploration and Production.

⁽²⁾  Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices.

⁽³⁾  During the third quarter of 2017, the Company corrected certain intrasegment sales eliminations. Gross revenues and purchases of crude oil and products have been recast for the first two quarters of 2017. There was no impact on net earnings.

⁽⁴⁾  Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the period. Includes Exploration and Production assets acquired through acquisition, and excludes assets acquired through corporate acquisition.

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 60

Downstream (continued)																								Corporate and Eliminations(2)												Total
Canadian Refined Products												U.S. Refining and Marketing(3)
Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
	815			802			602			568			2,755			2,292			2,135			2,173			(476	)		(424	)		(253	)		(397	)		5,605			4,717			4,352			4,312
	—			—			—			—			—			—			—			—			—			—			—			—			(97	)		(71	)		(91	)		(104	)
	—			—			—			—			—			—			—			—			—			—			—			—			(71	)		(4	)		(1	)		36
	815			802			602			568			2,755			2,292			2,135			2,173			(476	)		(424	)		(253	)		(397	)		5,437			4,642			4,260			4,244
	647			650			477			445			2,316			1,876			1,894			1,973			(476	)		(424	)		(253	)		(397	)		3,447			2,884			2,671			2,564
	66			63			67			60			151			135			137			140			—			—			—			—			663			657			690			669
	19			12			11			11			4			4			3			4			121			61			63			59			232			142			142			134
	28			27			27			29			90			82			93			89			28			18			17			16			647			673			862			700
	—			—			—			—			—			—			—			—			—			—			—			—			38			31			56			21
	—			(5	)		—			—			—			—			—			—			—			—			—			—			(13	)		(2	)		(33	)		2
	(1	)		—			—			—			(14	)		10			(14	)		(3	)		(3	)		12			(3	)		—			13			25			(65	)		9
	759			747			582			545			2,547			2,107			2,113			2,203			(330	)		(333	)		(176	)		(322	)		5,027			4,410			4,323			4,099
	56			55			20			23			208			185			22			(30	)		(146	)		(91	)		(77	)		(75	)		410			232			(63	)		145
	—			—			—			—			—			—			—			—			—			—			—			—			1			12			23			25
	—			—			—			—			—			—			—			—			5			2			(11	)		(2	)		5			2			(11	)		(2	)
	—			—			—			—			—			—			—			—			10			9			8			5			11			11			9			6
	(3	)		(3	)		(3	)		(3	)		(4	)		(4	)		(3	)		(3	)		(59	)		(58	)		(62	)		(55	)		(99	)		(97	)		(103	)		(93	)
	(3	)		(3	)		(3	)		(3	)		(4	)		(4	)		(3	)		(3	)		(44	)		(47	)		(65	)		(52	)		(83	)		(84	)		(105	)		(89	)
	53			52			17			20			204			181			19			(33	)		(190	)		(138	)		(142	)		(127	)		328			160			(145	)		81
	18			11			6			10			(4	)		5			1			—			(14	)		(31	)		(18	)		(16	)		16			(28	)		5			4
	(4	)		3			(1	)		(5	)		79			62			6			(12	)		(489	)		(44	)		(36	)		(27	)		(360	)		52			(57	)		6
	14			14			5			5			75			67			7			(12	)		(503	)		(75	)		(54	)		(43	)		(344	)		24			(52	)		10
	39			38			12			15			129			114			12			(21	)		313			(63	)		(88	)		(84	)		672			136			(93	)		71
	25			14			37			11			122			88			52			51			59			27			16			12			745			511			580			384
	1,548			1,533			1,516			1,503			7,580			6,676			6,769			7,035			3,252			3,219			3,295			3,003			32,927			32,157			32,372			32,894

Husky Energy Inc. | Management’s Discussion and Analysis 2018 | 61

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