2012

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

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

For the fiscal year ended December 31, 2012 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 Numbers (if applicable))	(I.R.S. Employer Identification Number (if applicable))

707-8^th Avenue S.W., P.O. Box 6525 Station D, Calgary, Alberta, Canada T2P 3G7

(403) 298-6111

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

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

(212) 894-8400

(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:

x  Annual information form x  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:

982,229,220 Common Shares outstanding as of December 31, 2012

12,000,000 Cumulative Redeemable Preferred Shares, Series 1 outstanding as of December 31, 2012

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  x    No  ¨

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted 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 and post such files).    Yes  ¨    No  ¨

The 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. 333-174554.

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 of Husky Energy Inc. (“Husky” or “the Company”) for the year ended December 31, 2012 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, 2012 and December 31, 2011, including the auditors’ report with respect thereto, is 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, 2012 is included as Document C of this Annual Report on Form 40-F.

Certifications

See Exhibits 23.1, 23.2, 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, 2012 which is included as Document C of this Annual Report on Form 40-F.

Management’s Annual Report on Internal Control Over Financial Reporting

The section “Management’s Annual Report on Internal Control over Financial Reporting” in Husky’s Management’s Discussion and Analysis, is included as Document C of this Annual Report on Form 40-F.

Attestation Report of the Registered Public Accounting Firm

The required disclosure is included in the “Report of Independent Registered Public Accounting Firm” that accompanies Husky’s consolidated financial statements for the year ended December 31, 2012, which is included as Document B of this Annual Report on Form 40-F.

Changes in Internal Control Over Financial Reporting

The required disclosure is included in the section “Disclosure Controls and Procedures” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2012, 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. 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 Annual Information Form for the year ended December 31, 2012, 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

Page ii 

functions and to all of its other employees, and is posted on its website at www.huskyenergy.com. In the fiscal year ended December 31, 2012, there were no amendments to Husky’s Code of Business Conduct, nor did Husky grant a waiver, including an implicit waiver from a provision of its Code of Business Conduct. 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 of such amendment or waiver 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.

Principal Accountant Fees and Services

See the section “External Auditor Service Fees” in the Annual Information Form for the year ended December 31, 2012, which is included as Document A of this Annual Report on Form 40-F.

Off-Balance Sheet Arrangements

See the section “Off-Balance Sheet Arrangements” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2012, which is included as Document C of this Annual Report on Form 40-F.

Tabular Disclosure of Contractual Obligations

See the section “Cash Requirements” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2012, which is included as Document C of this Annual Report on Form 40-F.

Identification of the Audit Committee

Husky has a separately designated standing Audit Committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. The members of the Audit Committee are: W. Shurniak, C.S. Russel, F.S.H. Ma and G.C. Magnus.

Interactive Data File

Not applicable.

Mine Safety Disclosure

Not applicable.

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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 (333 - 174554) in connection with its common shares 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 8th day of March, 2013

	Husky Energy Inc.
By:	/s/ Asim Ghosh
	Name:	Asim Ghosh
	Title:	President & Chief Executive Officer
By:	/s/ James D. Girgulis
	Name:	James D. Girgulis
	Title:	Senior Vice President, General Counsel and Secretary

Document A

Form 40-F

Annual Information Form

For the Year Ended December 31, 2012

Husky Energy Inc.

Annual Information Form

For the Year Ended December 31, 2012

March 8, 2013

AIF 2012 Page 2 

TABLE OF CONTENTS

ADVISORIES	4
ABBREVIATIONS AND GLOSSARY OF TERMS	5
EXCHANGE RATE INFORMATION	10
CORPORATE STRUCTURE	11
Husky Energy Inc.	11
Intercorporate Relationships	11
GENERAL DEVELOPMENT OF HUSKY	11
Three Year History of Husky	11
DESCRIPTION OF HUSKY’S BUSINESS	15
General	15
Social and Environmental Policy	16
Upstream Operations	18
Description of Major Properties and Facilities	18
Distribution of Oil and Gas Production	28
Disclosures of Oil and Gas Activities	29
Oil and Gas Reserves Disclosures	37
Infrastructure and Marketing	57
Downstream Operations	61
U.S. Refining and Marketing	61
Upgrading Operations	61
Canadian Refined Products	62
INDUSTRY OVERVIEW	65
RISK FACTORS	70
HUSKY EMPLOYEES	76
DIVIDENDS	76
Dividend Policy and Restrictions	76
Common Share Dividends	76
Series 1 Preferred Share Dividends	76
DESCRIPTION OF CAPITAL STRUCTURE	77
Common Shares	77
Preferred Shares	77
Liquidity Summary	78
MARKET FOR SECURITIES	80
DIRECTORS AND OFFICERS	81
Directors	81
Officers	88
Conflicts of Interest	88
Corporate Cease Trade Orders or Bankruptcies	88
Individual Penalties, Sanctions or Bankruptcies	89
AUDIT COMMITTEE	89
External Auditor Service Fees	90
LEGAL PROCEEDINGS	90
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	90
TRANSFER AGENTS AND REGISTRARS	90
INTERESTS OF EXPERTS	91
ADDITIONAL INFORMATION	91
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS	92
SCHEDULES
Schedule A – Audit Committee Mandate	95
Schedule B – Report on Reserve Data by Qualified Reserves Evaluator	99
Schedule C – Report of Management and Directors on Oil and Gas Disclosure	100
Schedule D – Independent Engineer’s Audit Opinion	102

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ADVISORIES

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 noted, 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 Canadian dollars.

AIF 2012 Page 4 

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
bopd	barrels of oil per day
bpd	barrels per day
bps	basis points
CO2	carbon dioxide
GJ	gigajoule
km	kilometers
lt	litres
lt/day	litres per day
m	meters
mbbls	thousand barrels
mbbls/day	thousand barrels per calendar day
mboe	thousand barrels of oil equivalent
mboe/day	thousand barrels of oil equivalent per 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
MW	megawatts
sq km	square kilometers
Acronyms
API	American Petroleum Institute
ASP	Alkaline Surfactant Polymer
CDOR	Certificate of Deposit Offered Rate
CHOPS	Cold Heavy Oil Production with Sand
CNOOC	China National Offshore Oil Corporation
COGEH	Canadian Oil and Gas Evaluation Handbook
CSS	Cyclic Steam Stimulation
EIA	Energy Information Administration
EL	Exploration Licence
EOR	Enhanced Oil Recovery
ERCB	Energy Resources Conservation Board
FAS	Financial Accounting Statement
FASB	Financial Accounting Standards Board
FEED	Front End Engineering Design
FPSO	Floating Production, Storage and Offloading Vessel
GAAP	Generally Accepted Accounting Principles
LIBOR	London Interbank Offered Rate
LLB	Lloydminster Blend
MD&A	Management’s Discussion And Analysis
NGL	Natural Gas Liquids

AIF 2012 Page 5 

NIT	NOVA Inventory Transfer
NWT	Northwest Territories
NYMEX	New York Mercantile Exchange
ODP	Overall Development Plan
OPEC	Organization of Petroleum Exporting Countries
PIIP	Petroleum Initially-In-Place
PSC	Production Sharing Contract
SAGD	Steam Assisted Gravity Drainage
SDL	Significant Discovery Licence
SEC	Securities and Exchange Commission of the United States
SEDAR	System for Electronic Document Analysis and Retrieval
U.S.	United States
WCSB	Western Canada Sedimentary Basin
WTI	West Texas Intermediate

The Company uses the term boe which is calculated on an energy equivalence basis whereby one barrel of crude oil is equivalent to six thousand cubic feet of natural gas. Readers are cautioned that the term boe may be misleading, particularly if used in isolation. This measure is primarily applicable at the burner tip and does not represent an equivalency at the wellhead.

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.

Barrel

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

Bitumen

Bitumen is solid or semi-solid with a viscosity greater than 10,000 centipoise at original temperature in the deposit and atmospheric pressure.

Bulk terminal

A facility used primarily for the storage and/or marketing of petroleum products.

Coal bed methane

The primary energy source of natural gas is methane. Coal bed methane is methane found and recovered from the coal bed seams. The methane is normally trapped in coal by water that is under pressure. When the water is removed the methane is released.

Cold production

A non-thermal production process for heavy oil in unconsolidated sand formations. During the cold production process, heavy oil and sand are produced simultaneously through the use of progressive cavity pumps, which produce high pressure in the reservoir.

Debottleneck

To remove restrictions thus improving flow rates and productive capacity.

Delineation well

A well in close proximity to an oil or gas well that helps determine the aerial extent of the reservoir.

Developed area

A drainage unit having a well completed thereon capable of producing oil or gas in paying quantities.

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.

AIF 2012 Page 6 

Diluent

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

Dry and abandoned well

A well found to be incapable of producing oil or gas in sufficient quantities to justify completion as a producing oil or gas well.

Enhanced recovery

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 (“EL”)

A licence with respect to the Canadian offshore or the Northwest or Yukon Territories conferring the right to explore for, and the exclusive right to drill and test for, 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.

Exploratory 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 in another reservoir. Generally, an exploratory well is any well that is not a development well, a service well, an extension well, or a stratigraphic test well as those items are defined herein.

Extension well

A well drilled to extend the limits of a known reservoir.

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.

Gathering system

Pipeline system and associated facilities used to gather natural gas or crude oil from various wells and deliver it to a central point where it can be moved from there by a single pipeline to a processing facility or sales point.

Heavy crude oil

Crude oil measured between 20 API° and 10 API° and is liquid at original temperature in the deposit and atmospheric pressure.

Horizontal drilling

Drilling horizontally rather than vertically through a reservoir, thereby exposing more of the well to the reservoir and increasing production.

Hydrogen sulphide

A poisonous gas which is colourless and heavier than air and is found in sour gas.

Infill well

A well drilled on an irregular pattern disregarding normal spacing requirements. These wells are drilled to produce from parts of a reservoir that would otherwise not be recovered through existing wells drilled in accordance with normal spacing.

Light crude oil

Crude oil measured at 30 API° or lighter.

AIF 2012 Page 7 

Liquefied petroleum gas

Liquefied propanes and butanes, separately or in mixtures.

Medium crude oil

Crude oil measured between 20 API° and 30 API°.

Metocean data

Meteorological and oceanographic data used for, among other things, the design of marine structures.

Miscible flood

An enhanced recovery method which requires that three fluids exist in the reservoir: the mobile oil to be recovered, a displacing fluid (NGL) injected to move as a bank behind the oil, and a fluid injected to propel the displacing fluid (chase gas) through the reservoir.

Multiple completion well

A well producing from two or more formations by means of separate tubing strings running inside the casing, each of which carry hydrocarbons from a separate and distinct producing formation.

Natural gas liquids

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, butanes and condensate, or a combination thereof.

Oil battery

An accessible area to accommodate separators, treaters, storage tanks and other equipment necessary to process and store crude oil and other fluids prior to transportation.

Oil sands

Sands and other rock materials which contain crude bitumen and include all other mineral substances in association therewith.

Overriding royalty interests

An interest acquired or withheld in the oil and gas produced (or the proceeds from the sale of such oil and gas), received free and clear of all costs of development, operation, or maintenance and in addition to the usual landowner’s royalty reserved to the lessor in an oil and gas lease.

Primary recovery

The oil and gas recovered by any method that may be employed to produce the oil or gas through a single well bore. The fluid enters the well bore by the action of native reservoir energy or gravity.

Production Sharing Contract (“PSC”)

A contract for the development of resources under which the contractor’s costs (investment) are recoverable each year out of the production but there is a maximum amount of production which can be applied to the cost recovery in any year. This annual allocation of production is referred to as cost oil; the remainder is referred to as profit oil and is divided in accordance with the contract between the contractor and the host government.

Raw gas

Gas as produced from a well before the separation of liquefiable hydrocarbons or other substances contained therein.

Reserve Replacement Ratio

The reserve replacement ratio represents the rate at which the Company replaces reserve volumes realized through current production for a given period. The ratio is calculated as the sum of: closing reserve volumes less opening reserve volumes plus production volumes divided by production volumes.

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.

AIF 2012 Page 8 

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. The rate at which the waves are transmitted varies with the medium through which they pass.

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 Licence (“SDL”)

A licence issued following the declaration of a significant discovery, which is indicated by the first exploration well that demonstrates by flow testing the existence of sufficient hydrocarbons in a particular geological feature to suggest potential for sustained production. A Significant Discovery Licence confers the same rights as that of an Exploration Licence.

Sour gas

Natural gas contaminated with chemical impurities, notably hydrogen sulphide or other sulphur compounds. Such compounds must be removed before the gas can be used for commercial or domestic purposes.

Specific gravity

The ratio between the weight of equal volumes of water and another liquid measured at standard temperature, the weight of water is assigned a value of one. However, the specific gravity of oil is normally expressed in degrees of API gravity as follows:

	141.5	-131.5
Degrees API =	Specific gravity @ F60 degrees

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 (“SAGD”)

A 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 to a horizontal production well beneath the steam injection well.

Step-out well

A well drilled adjacent to a proven well but located in an unproven area; a well drilled in an effort to ascertain the extent and boundaries of a producing formation.

Stratigraphic test well

A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intention of being completed for hydrocarbon production. This classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic test wells are classified as (i) “exploratory-type,” if not drilled in a proved area, or (ii) “development-type,” if drilled in a proved area.

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.

Tertiary recovery

The recovery of oil and gas by using exotic or complex recovery schemes involving steam, chemicals, gases or heat. Usually, but not necessarily, this is done after the secondary recovery phase has passed.

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Three dimensional (“3-D”) seismic survey

Three dimensional seismic imaging which uses a grid of numerous cables rather than a few lines stretched in one line.

Turnaround

Perform maintenance at a plant or facility which requires the plant or facility to be completely or partially shutdown for the duration.

Undeveloped area

An area that has not been established by drilling operations whether oil and/or gas may be found in commercial quantities.

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.

Well abandonment costs

Costs of abandoning a well, net of any salvage value, and disconnecting the well from the surface gathering system.

Wellhead

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

Working interest

An interest in the net revenues of an oil and gas property which is proportionate to the share of exploration and development costs borne until such costs have been recovered, and which entitles the holder to participate in a share of net revenue thereafter.

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.^{(1) (2)}

	Year ended December 31,
(Cdn $ per U.S. $)	2012		2011		2010
Year-end		0.995		1.017		0.995
Low		0.964		0.941		0.995
High		1.044		1.066		1.078
Average		0.999		0.989		1.030

⁽¹⁾  The year-end exchange rates were as quoted by the Bank of Canada for the noon buying rate.

⁽²⁾  The high, low and average rates were either quoted or calculated as of the last day of the relevant period.

AIF 2012 Page 10 

CORPORATE STRUCTURE

Husky Energy Inc.

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 also amended effective March 3, 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”).

Husky has its registered office and its head and principal office at 707, 8th Avenue S.W., P.O. Box 6525, Station D, Calgary, Alberta, T2P 3G7.

Intercorporate Relationships

The following table lists Husky’s significant subsidiaries and jointly controlled entities and their place of incorporation, continuance or organization, as the case may be, as at December 31, 2012. ⁽¹⁾ All of the following companies and partnerships, except as otherwise indicated, are 100% beneficially owned or controlled or directed, directly or indirectly.

Name	Jurisdiction
Subsidiary of Husky Energy Inc.
Husky Oil Operations Limited	Alberta
Subsidiaries and jointly controlled entities of Husky Oil Operations Limited
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%)	Alberta
BP-Husky Refining LLC (50%)	Delaware
Lima Refining Company	Delaware
Husky Marketing and Supply Company	Delaware

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

GENERAL DEVELOPMENT OF HUSKY

Three Year History of Husky

2010

On January 20, 2010, Husky announced that it had completed the FEED for Phase I of the Sunrise Energy Project, located 60 kilometers northeast of Fort McMurray in northern Alberta. The Company also obtained the necessary approvals from the Government of Alberta, Environment Department and the Energy Resources and Conservation Board (“ERCB”) to proceed with the project. Husky announced in November 2010 that it was moving forward with the construction of facilities for the phased development of the Sunrise Energy Project. This first phase of the project is expected to cost approximately $2.7 billion and is expected have gross production of approximately 60,000 barrels per day beginning in 2014. Further, Sunrise will use SAGD technology which limits site disturbance. In November 2010, sanction for Phase I was announced.

On February 8, 2010, Husky announced its third significant gas discovery on Block 29/26 in the South China Sea.

AIF 2012 Page 11 

On March 12, 2010, Husky issued $700 million in medium-term notes under the $1 billion shelf prospectus which was filed by the Company in December 2009 with the securities regulatory authorities in each of the provinces of Canada. The medium-term notes were issued in two tranches: $300 million at 3.75% maturing on March 12, 2015 and $400 million at 5.00% maturing on March 12, 2020.

Mr. Asim Ghosh was appointed as President and Chief Executive Officer of the Company, effective June 1, 2010. Mr. Ghosh was previously appointed to the Board of Directors in May 2009. The Company’s former President and Chief Executive Officer, Mr. John C.S. Lau, was appointed President and Chief Executive Officer, Asia Pacific, in May 2010 after stepping down as President and Chief Executive Officer of Husky after 18 years in the position. Mr. Lau’s retirement from Husky Asia Pacific was announced on July 19, 2011.

On May 31, 2010, Husky completed drilling and successful testing of the first appraisal well at the Liuhua 29-1 discovery Block 29/26 in the South China Sea with encouraging results.

On May 31, 2010, Husky also announced that oil production had been achieved from the North Amethyst field, offshore Newfoundland and Labrador. North Amethyst is the first satellite field development at Husky’s White Rose project and was brought on production less than four years after discovery. It is also the first subsea tieback project in Canada.

On September 1, 2010, Husky signed a purchase agreement to acquire natural gas properties in west central Alberta, which added 10.8 mboe/day of gross production, 32.9 mmboe of proved reserves and 10.7 mmboe of probable reserves, and extended the optimum utilization of its Ram River gas plant. The acquisition also added 160,000 acres of land to the Company’s holdings, including 122,000 undeveloped acres, doubling Husky’s land holdings in the region. This purchase closed on November 30, 2010 and had an effective date of June 1, 2010. The reserves estimates set forth above were as at December 31, 2010.

On October 27, 2010, Husky announced that it had completed the successful drilling of a second appraisal well at the Liuhua 29-1 discovery Block 29/26 in the South China Sea.

On October 28, 2010, Husky announced that it had received approval from the Government of Indonesia for a 20 year extension to the existing Madura Strait PSC, originally awarded in 1982. The Madura Strait PSC includes the Madura BD and MDA fields, as well as numerous other prospects and leads. Husky and its partner in the Madura Strait, CNOOC, also each agreed to sell a 10% equity stake in the Madura PSC to Samudra Energy Ltd., through its affiliate SMS Development Ltd. Following the completion of the sale, Husky and CNOOC each hold a 40% equity interest in Husky Oil (Madura) Limited, with the remaining 20% held by Samudra Energy Ltd. This sale closed on January 13, 2011 and Husky Oil (Madura) Ltd. subsequently changed its name to Husky-CNOOC Madura Limited.

Effective November 26, 2010, Husky filed a universal short form base shelf prospectus with applicable securities regulators in each of the provinces of Canada. The shelf prospectus enabled Husky to offer up to $3 billion of common shares, preferred shares, debt securities, subscription receipts, warrants and units in Canada until December 2012.

Husky signed an $860 million purchase and sale agreement to acquire oil and natural gas properties in Alberta and northeast British Columbia. This purchase included 16.3 mboe/day of gross natural gas production, 4.8 mbbls/day of gross oil production, and 0.8 mbbls/day of natural gas liquids (“NGL”). Husky estimated reserves included 104 mmboe of proved reserves and nine mmboe of probable reserves based on an effective date of December 1, 2010. The purchase transaction closed on February 4, 2011.

Husky also announced that it decided to retain its Asia Pacific assets citing the Company’s view that it is in the best interest of the shareholders to continue to build this material business in the resource-rich region and leverage the close proximity to major energy markets in Hong Kong and Mainland China.

On December 7, 2010, Husky issued equity by way of a public overnight-marketed common share offering and a private placement to its principal shareholders. Pursuant to the public offering, the Company issued a total of 11.9 million common shares at a price of $24.50 per share for total gross proceeds of approximately $293 million. The public offering was conducted under the Company’s previously filed Canadian shelf prospectus and accompanying prospectus supplement. The Company also issued a total of 28.9 million common shares in a private placement to its principal shareholders, L.F. Investments (Barbados) Limited and Hutchison Whampoa Luxembourg Holdings S.à.r.l., at a price of $24.50 per share for total gross proceeds of approximately $707 million.

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The Government of China approved the Original-Gas-in-Place (“OGIP”) report for the Liwan 3-1 field. On December 7, 2010, Husky announced that it had signed a Heads of Agreement with CNOOC, specifying the key principles of cooperation for funding and operation of the Liwan 3-1 deep water gas field development. Under the agreement for the Liwan 3-1 field development, Husky will operate the deep water portion of the project involving development drilling and completions, subsea equipment and controls, and subsea tie-backs to a shallow water platform. CNOOC will operate the shallow water portion of the project including a shallow water platform, approximately 270 kilometers of subsea pipeline to shore, and the onshore gas processing plant.

2011

On February 28, 2011, Husky announced that its shareholders voted in favour of an amendment to the Company’s Articles, which allows shareholders to accept dividends in cash or in common shares. The shareholders also approved an amendment to allow for the issuance of preferred shares.

On March 18, 2011, Husky issued 12 million Series 1 Preferred Shares at a price of $25.00 per share for aggregate gross proceeds of $300 million. Holders of the Series 1 Preferred Shares are entitled to receive a cumulative quarterly fixed dividend yielding 4.45% annually for the initial period ending March 31, 2016. Thereafter, the dividend rate will be reset every five years at a rate equal to the 5-year Government of Canada bond yield plus 1.73%. Holders of Series 1 Preferred Shares have the right, at their option, to convert their shares into Series 2 Preferred Shares, subject to certain conditions, on March 31, 2016 and on March 31 every five years thereafter. Holders of the Series 2 Preferred Shares are entitled to receive cumulative quarterly floating rate dividends at a rate equal to the three-month Government of Canada Treasury Bill yield plus 1.73%.

On June 13, 2011, Husky filed a universal short form base shelf prospectus with the Alberta Securities Commission and the SEC. The prospectus enabled Husky to offer up to U.S. $3 billion of common shares, preferred shares, debt securities, subscription receipts, warrants and units in the United States up to and including July 12, 2013, subject to market conditions at the time of sale. Approximately $1.5 billion remains available for issuance under this prospectus.

On June 29, 2011, Husky completed a $1 billion public offering and a $200 million private placement to its principal shareholders, L.F. Investments (Barbados) Limited and Hutchison Whampoa Luxembourg Holdings S.a.r.l. The Company issued approximately 37 million common shares at $27.05 per share in the public offering and approximately 7 million common shares at a price of $27.05 per share in the private placement. The public offering was conducted under the Company’s universal short form base shelf prospectus filed November 26, 2010 with the securities regulatory authorities in all provinces of Canada, the Company’s universal short form base shelf prospectus filed June 13, 2011 with the Alberta Securities Commission and the SEC, and the respective accompanying prospectus supplements.

On September 19, 2011, Husky announced that it had sanctioned the development of the Liwan 3-1 and Liuhua 34-2 fields, the principal fields of the Liwan Gas Project in the South China Sea. The project, which is being jointly developed by Husky and CNOOC, aims to bring at least three natural gas discoveries on Block 29/26 to market. The ODP for Liwan 3-1 was submitted to the Chinese government authorities for regulatory approval and was approved by the Government of China in 2012. A gas sales agreement for production from the field is also in place. The gas sales agreement was executed with CNOOC Gas & Power Group, Guangdong Branch for volumes from the Liwan 3-1 field. Production from the field will supply the Guangdong Province natural gas grid from an onshore gas plant at Gaolan Island, Zhuahai.

2012

On March 22, 2012, the Company issued U.S. $500 million of 3.95% senior unsecured notes due April 15, 2022 pursuant to the universal short form base shelf prospectus filed with the Alberta Securities Commission and the SEC on June 13, 2011 and an accompanying prospectus supplement. The notes are redeemable at the option of the Company at a make-whole premium and interest is payable semi-annually. The notes are unsecured and unsubordinated and rank equally with all of the Company’s other unsecured and unsubordinated indebtedness.

On June 15, 2012, Husky repaid the maturing U.S. $400 million of 6.25% notes for U.S. $413 million, including U.S. $13 million of interest.

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On December 14, 2012, Husky amended and restated both of its revolving syndicated credit facilities to allow it to borrow up to $1.5 billion and $1.6 billion in either Canadian or U.S. currency from a group of banks on an unsecured basis. The maturity date for the $1.5 billion facility was extended to December 14, 2016 and there was no change to the August 31, 2014 maturity date of the $1.6 billion facility. There continues to be no difference between the terms of these facilities, other than their maturity dates.

On December 31, 2012, Husky filed a universal short form base shelf prospectus (the “Canadian Shelf Prospectus”) with applicable securities regulators in each of the provinces of Canada, other than Quebec, that enables the Company to offer up to $3.0 billion of common shares, preferred shares, debt securities, subscription receipts, warrants and units (the “Securities”) in Canada up to and including January 30, 2015. As of December 31, 2012, the Company had not issued Securities under the Canadian Shelf Prospectus. This Canadian Shelf Prospectus replaced the universal short form base shelf prospectus filed in Canada during November 2010 which had remaining unused capacity of $1.4 billion and expired in December 2012.

During 2012, the Company continued to advance exploration and development projects on its extensive oil resource land base of approximately 800,000 net acres. Heavy oil production commenced in the second quarter of 2012 ahead of schedule at both the Pikes Peak South and Paradise Hill heavy oil thermal projects and has ramped up to a combined average of 17,000 bbls/day exceeding the combined 11,500 bbls/day design rates. Construction is approximately 40% complete at the 3,500 bbls/day Sandall thermal development project and initial drilling has commenced. First production is scheduled in 2014. Design and initial site work is continuing at the 10,000 bbls/day Rush Lake commercial project with first production anticipated in 2015. Initial planning is ongoing for three additional commercial thermal projects.

The ODP for the Liwan Gas Project development on Block 29/26 in the South China Sea was approved by the Government of China. The development project was more than 80% complete as of the end of 2012 and remains on track to achieve planned first production in late 2013/early 2014. Seven out of nine production wells are ready to commence operations and all nine production trees have been installed. At the end of 2012, approximately 90 kilometers of the two 79-kilometer deep water pipelines connecting the gas field to the central platform have been laid and approximately 190 kilometers out of 261 kilometers of shallow water pipeline have been laid from the central platform to the onshore gas plant. The completed jacket for the shallow water central platform was successfully placed onto the ocean floor on August 30, 2012. Fabrication of the platform topsides is progressing and the floatover of the topsides for the central platform is planned for mid-2013. Construction of the onshore gas plant is progressing on schedule.

Development of the single well Liuhua 34-2 field is planned to proceed in parallel with, and be tied into the development of the Liwan 3-1 field. FEED for the development of the Liuhua 29-1 gas field has now been completed, and the ODP is being prepared. Negotiations for the sale of the gas from the Liuhua 34-2 and Liuhua 29-1 fields are ongoing.

In December, Husky signed a joint venture contract with CPC Corporation, Taiwan for an exploration block in the South China Sea. The exploration block is located 100 kilometers southwest of the island of Taiwan and covers approximately 10,000 square kilometers. Husky holds a 75% working interest during exploration, while CPC Corporation has the right to participate in the development program up to a 50% interest.

The 2012 exploration drilling program on the Madura Strait Block concluded in October with four new discoveries being made as a result of a five well exploration drilling program. These discoveries are now under evaluation for commercial development. The development plan for a combined MDA and MBH development project was approved in 2013 by the industry regulator, SKK Migas. As agreed with the regulator, a re-tender process for the BD field FPSO was conducted and pre-qualification responses are being evaluated. First gas from the Madura Strait Block is anticipated in 2014/2015.

Husky and BP continue to advance the development of the Sunrise Energy Project in multiple stages. During 2012, drilling of the planned SAGD horizontal well pairs for Phase 1 was completed and site construction and equipment installations were substantially advanced. Phase 1 of the 60,000 bbls/day (30,000 bbls/day net) project remains on track for first production in 2014. Substantial cost certainty on the first phase of the Sunrise Energy Project was achieved in 2012 with the conversion to a lump sum contract for the CPF. Over 85% of the $2.7 billion costs estimate for Phase 1 are now fixed and incorporate all significant contract conversions and facility and efficiency design improvements. As of December 31, 2012, approximately 65% of the project’s total cost estimate has been spent. The CPF is approaching 50% completion with piling substantially completed and foundation work

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proceeding at the site. Construction of the field facilities is now more than 80% complete. Development work continues on the next phase of the project with the Design Basis Memorandum expected to be completed in 2013. Regulatory approvals are in place for a total of 200,000 bbls/day (100,000 bbls/day net).

Development continued at the White Rose field with the addition of an infill production well which was brought online in August 2012. As at the end of 2012, a total of 22 wells, including nine producing wells, ten water injectors, and three gas injectors were in production. Future infill wells are being evaluated. A development plan amendment was filed with the regulator in October 2012 to facilitate development of resources at the South White Rose Extension satellite. This region will be developed via subsea tieback to the SeaRose FPSO, similar to the North Amethyst satellite extension. At North Amethyst, development continued in 2012 with the addition of the fourth production well. At the end of 2012, four production and three water injection wells were on-line and the fourth water injector well is scheduled to be drilled in 2013. An application to develop the deeper Hibernia formation at North Amethyst is progressing through the regulatory review process. A water injection well to support the existing producing well for the West White Rose pilot project was completed and brought online during 2012. Evaluation of a wellhead platform to facilitate future development continued during 2012 and supporting regulatory filings were submitted for an environmental assessment of the concept. A decision on a preferred development option is expected in 2013.

Husky and Seadrill entered into a five-year contract for the use of Seadrill’s West Mira rig, a new harsh environment semi-submersible rig currently being built and expected to be completed in 2015.

Exploration activity in the Atlantic Region included drilling of the Searcher prospect in the southern Jeanne D’Arc Basin. The well did not encounter commercial hydrocarbons and was expensed in 2012. The Company plans to participate in a number of operated and non-operated exploratory wells in the Atlantic Region during the 2013/2014 timeframe. The first well in this program is a partner-operated exploration well southeast of the Mizzen discovery located in the Flemish Pass offshore Newfoundland and Labrador.

DESCRIPTION OF HUSKY’S BUSINESS

General

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.

During the first quarter of 2012, the Company completed an evaluation of activities of the Company’s former Midstream segment as a service provider to the Upstream or Downstream operations. As a result, and consistent with the Company’s strategic view of its integrated business, the previously reported Midstream segment activities are now aligned and reported within the Company’s core exploration and production, or in its upgrading and refining businesses. The Company believes this change in segment presentation allows management and third parties to more effectively assess the Company’s performance.

Upstream includes exploration for, and development and production of, crude oil, bitumen, natural gas and NGL (Exploration and Production) and marketing of the Company’s and other producers’ crude oil, natural gas, NGL, sulphur and petroleum coke, pipeline transportation and blending of crude oil and natural gas and storage of crude oil, diluent and natural gas (Infrastructure and Marketing). The Company’s Upstream operations are located primarily in Western Canada, offshore East Coast of Canada, offshore Greenland, offshore China and offshore Indonesia.

Downstream includes upgrading of heavy crude oil feedstock into synthetic crude oil (Upgrading), refining in Canada 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) and refining in the U.S. of primarily crude oil to produce and market gasoline, jet fuel and diesel fuels that meet U.S. clean fuels standards (U.S. Refining and Marketing).

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Social and Environmental Policy

Husky Operational Integrity Management System

Husky approaches social responsibility and sustainable development by seeking a balance among economic, environmental and social issues while maintaining growth. Husky strives to find solutions to these issues that do not compromise the needs of future generations. In 2008, Husky implemented the Husky Operational Integrity Management System (“HOIMS”) which is followed by all Husky businesses, with particular emphasis on projects and operations and management of the operational integrity of assets throughout its life cycle. HOIMS includes 14 fundamental elements; each element contains well defined objectives and expectations that guide Husky to continuously improve operational integrity. Resources are dedicated to the continued implementation and execution of HOIMS, and audits are conducted to help ensure that HOIMS is effectively integrated into daily operations.

The fundamental elements of HOIMS are:

1. Ensure all levels of management demonstrate leadership and commitment to operational integrity. Define and ensure appropriate accountability for HOIMS throughout the organization.

2. Prevent incidents by identifying and minimizing workplace and personal health risks. Promote and reinforce all safe behaviours.

3. Manage risks by performing comprehensive risk assessments to provide essential decision-making information. Develop and implement plans to manage significant risks and impacts to as low as reasonably practical levels.

4. Be prepared for an emergency or security threat. Identify all necessary actions to be taken to protect people, the environment, the organization’s assets and reputation in the event of an emergency or security threat.

5. Maintain operations reliability and integrity by use of clearly defined and documented operational, maintenance, inspection and corrosion programs. Seek improvements in process and equipment dependability by systematically eliminating defects and sources of loss.

6. Provide assurance that personnel possess the necessary competencies, knowledge, abilities and behaviours to perform and demonstrate designated tasks and responsibilities effectively, efficiently and safely.

7. Report and investigate all incidents. Learn from incidents and use the information to take corrective action and prevent recurrence.

8. Operate responsibly to minimize the environmental impact of operations. Leave a positive legacy behind when operations cease.

9. Ensure that risks and exposures from proposed changes are identified, evaluated and managed to remain at an acceptable level.

10. Identify, maintain and safeguard important information. Ensure personnel can readily access and retrieve information. Promote and encourage constructive dialogue within the organization to share industry recommended practices and acquired knowledge.

11. Ensure conformance with Corporate policies and compliance with all relevant government regulations. Work constructively to influence proposed laws and regulations, and debate on emerging issues.

12. Design, construct, commission, operate and decommission all assets in a healthy, safe, secure, environmentally sound, reliable and efficient manner.

13. Ensure contractors and suppliers perform in a manner that is consistent and compatible with Husky’s policies and business performance standards. Ensure contracted services and procured materials meet the requirements and expectations of Husky’s standards.

14. Confirm that HOIMS processes are implemented and assess whether they are working effectively. Measure progress and continually improve towards meeting HOIMS objectives, targets, and key performance indicators.

Health, Safety and Environment

The Health, Safety and Environment Committee of the Board of Directors is responsible for oversight of health, safety and environment policy, audit results and for monitoring compliance with the Company’s environmental policies, key performance indicators and regulatory requirements. The mandate of the Health, Safety and Environment Committee is available on the Husky website at www.huskyenergy.com.

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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, land disturbances and handling and disposal of waste materials. These laws and regulations have proliferated and become more complex over time, governing an increasingly broad aspect of the industry’s mode of operating and product characteristics. Husky continues to monitor emerging environmental laws and regulations and proactively implements programs as required for compliance.

Husky is required by the Government of Canada to report facilities that emit greater than 50,000 tonnes of carbon dioxide equivalence (“CO₂E”). The Lloydminster Upgrader, Lloydminster Refinery, Prince George Refinery, SeaRose floating, production and storage offloading vessel (“FPSO”), Sierra compressor station, Ram River gas plant, Rainbow Lake gas plant, Tucker thermal oil plant, Bolney SAGD thermal plant, Pikes Peak CSS thermal plant and the Lloydminster and Minnedosa ethanol plants are in this category. Husky has implemented an Environmental Performance Reporting System (“EPRS”) that gathers, consolidates, and calculates information, generates reports and identifies trends regarding greenhouse gas emissions.

Husky is also a member of the Integrated CO₂ Network, which is working to reduce greenhouse gas emissions. The group continues to study technologies related to the capture, transportation and storage of CO₂. A project was completed in 2012 to capture, compress and liquefy CO₂ from the Lloydminster ethanol plant for injection into heavy oil fields for Enhanced Oil Recovery. At Lloydminster and Rainbow Lake, Husky utilizes cogeneration to produce both electricity and thermal energy for use at its processing facilities. This configuration has fewer adverse effects on the environment and is cost effective. Electrical energy in excess of Husky’s requirements is sold into the grid, the provincial network of electrical transmission and distribution facilities. At Husky’s Tucker Thermal SAGD project vapour recovery systems are in use on all tanks and process vessels.

Husky has undertaken programs to minimize water consumption, particularly non-saline water. At the Tucker Thermal SAGD project, over 80% of water produced with the bitumen is recycled, and make up water is sourced from very saline, non-potable groundwater. Husky is implementing various technologies to improve water efficiency. A number of Husky fields in Alberta and Saskatchewan use alkali surfactant polymer (“ASP”) to increase water efficiency in enhanced oil recovery. In the Lloydminster area, Husky uses CO₂ to dilute and mobilize heavy oil in a pilot project.

Ongoing remediation and reclamation work is occurring at approximately 2,900 well sites and facilities. In 2012, Husky spent approximately $118 million on asset retirement obligations (“ARO”) and expects to spend approximately $130 - $150 million in 2013 on environmental site closure activities, including abandonment, decommissioning, reclamation and remediation.

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 consolidated financial statements.

At December 31, 2012, Husky had 512 retail locations in its light refined products operations, which consisted of 361 owned or leased locations (Husky controlled) and 151 independent retailer locations. Husky is continually monitoring the owned and leased locations for environmental compliance and, where required, performing remediation including routine underground tank replacements. Husky has several “legacy” (inactive facility) sites which require remediation. These inactive sites range from refinery sites to retail locations.

It is not possible to predict with certainty the amount of additional investment in new or existing facilities required to be incurred in the future for environmental protection or to address regulatory compliance requirements, such as reporting. Although these costs may be significant, Husky does not expect that they will have a material adverse effect on liquidity and financial position over the long-term.

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Upstream Operations

Upstream includes exploration for, and development and production of, crude oil, bitumen, natural gas and natural gas liquids (Exploration and Production) and marketing of the Company’s and other producers’ crude oil, natural gas, NGL, sulphur and petroleum coke, pipeline transportation and blending of crude oil and natural gas and storage of crude oil, diluent and natural gas (Infrastructure and Marketing).

Description of Major Properties and Facilities

Husky’s portfolio of Upstream assets includes properties with reserves of light crude oil (30° API and lighter), medium crude oil (between 20° and 30° API), heavy crude oil (liquid between 20° API and 10° API), bitumen (solid or semi-solid with a viscosity greater than 10,000 centipoise at original temperature in the deposit and atmospheric pressure), NGL, natural gas and sulphur.

China

Wenchang

The Wenchang field is located in the western Pearl River Mouth Basin, approximately 400 kilometers south of Hong Kong and 100 kilometers east of Hainan Island. Husky holds a 40% working interest in two oil fields, which commenced production in July 2002. The Wenchang 13-1 and 13-2 oil fields are currently producing from 32 wells in 100 meters of water into an FPSO vessel stationed between fixed platforms located in each of the two fields. The blended crude oil from the two fields averages approximately 35° API. Husky’s gross production averaged 8.3 mbbls/day during 2012.

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Block 29/26

Husky executed a PSC with CNOOC for the Contract Area 29/26 exploration block on October 1, 2004. The block is located in the Pearl River Mouth Basin of the South China Sea approximately 300 kilometers southeast of Hong Kong and 65 kilometers southeast of the Panyu gas discovery. The third Exploration Phase of the PSC has been completed and the retained area for development and production is approximately 55,100 acres (223 square kilometers).

In 2006, Husky drilled the Liwan 3-1-1 well natural gas discovery. The well was drilled in 1,500 meters of water to a total depth of 3,843 meters. During 2009, Husky discovered an additional gas field at Liuhua 34-2, approximately 23 kilometers to the northeast of the Liwan 3-1 field. In 2010, the Company made another natural gas discovery at Liuhua 29-1, approximately 43 kilometers to the northeast of the Liwan 3-1 field.

In late 2010, Husky Oil China Ltd. signed a Heads of Agreement with CNOOC which specified CNOOC’s election to participate in the development of the Block 29/26 discoveries to its maximum 51% working interest and key principles to fund, develop and operate the Liwan 3-1 deep water gas field. It was agreed that the project would be separated into deep water and shallow water development projects with Husky acting as deep water operator and CNOOC acting as shallow water operator. The deep water project would include a subsea production system connected by dual flow lines to a central shallow water platform. The shallow water project would include the shallow water platform connected to an onshore gas plant with access to the energy markets of Hong Kong and the Guangdong province on the China mainland. It was also envisaged that the Liuhua 34-2 and Liuhua 29-1 fields would be tied into and share usage of the shallow water infrastructure.

In 2011, Husky completed tendering the major deep water equipment and installation activity and CNOOC commenced the shallow water pipe laying and onshore gas plant construction. A gas sales agreement was also executed with CNOOC Gas & Power Group, Guangdong Branch for volumes from the Liwan 3-1 field.

In 2012, Husky made significant progress in the development of the Liwan 3-1 field. The ODP for the field was approved by the Chinese Government and the project was more than 80% complete at the end of 2012. Two further upper completions in the Liwan 3-1 gas field were installed and flow tested successfully at the expected production rates bringing the total of fully ready production wells to seven. All nine subsea production trees have been installed on the wells and eight associated upper completions have also been installed.

At the end of 2012, approximately 90 kilometers of the two 79-kilometer deep water pipelines connecting the gas field to the central platform have been laid and approximately 190 kilometers out of 261 kilometers of shallow water pipeline have been laid from the central platform to the onshore gas plant. Pipe laying activity is planned to resume in early 2013.

The jacket for the shallow water central platform was completed and load-out of the jacket was achieved in July 2012. The jacket was launched onto the ocean floor on August 30, 2012 after which piling to anchor the feet of the jacket to the seabed was completed. Fabrication and installation of the jacket is now fully complete and ready for the floatover of the topsides for the central platform which is planned for mid-2013.

Platform topsides fabrication progressed in 2012. The Monoethylene Glycol Recovery Unit was delivered to the Qingdao, Eastern China topsides construction site and the approximately 850 tonne unit was elevated and set into its final installation position on the upper deck. Generators and compressors have also been positioned and construction of control rooms, living quarters and other facilities are in their final stages.

Construction of the onshore gas plant progressed on schedule with site preparations and foundations largely completed including the completion of a seawall on the eastern side of the site. Nine of ten spherical liquids storage tanks are in place and the construction of pipe racks for transporting gas through the site is progressing. Construction of the control and administrative buildings as well as living areas commenced.

Development of the single well Liuhua 34-2 field is proceeding in parallel with, and will be tied into the development of the Liwan 3-1 field. FEED for the development of the Liuhua 29-1 gas field has now been completed, and the ODP is being prepared. Negotiations for the sale of the gas from the Liuhua 34-2 and Liuhua 29-1 fields are ongoing.

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The Liwan 3-1 development project is proceeding on schedule with first gas anticipated in late 2013/early 2014. The Liuhua 34-2 field is being developed on the same schedule. Production from the Liwan 3-1 field is expected to ramp up through 2014.

Taiwan

In December 2012, Husky signed a joint venture contract with CPC Corporation, Taiwan for an exploration block in the South China Sea. The exploration block is located 100 kilometers southwest of the island of Taiwan and covers approximately 10,300 square kilometers. Husky holds a 75% working interest during exploration, while CPC Corporation has the right to participate in the development program up to a 50% interest. Under the joint venture contract, Husky has an obligation to carry out two-dimensional (“2-D”) seismic surveys within the first two years, with options to carry out 3-D seismic surveys and to drill at least one exploration well in subsequent exploration periods.

Indonesia

Madura Strait

Husky has a 40% interest in approximately 621,700 acres (2,516 square kilometers) of the Madura Strait block, located offshore East Java, south of Madura Island, Indonesia. Husky’s two partners are CNOOC which is the operator and has a 40% working interest, and Samudra Energy Ltd., which holds the remaining 20% interest through its affiliate, SMS Development Ltd.

The BD gas field was granted commercial status and the Plan of Development was approved by the Indonesian state oil company in 1995. The field was to supply natural gas to a proposed independent power plant; however, construction of the power plant did not proceed due to economic issues that occurred in Indonesia at that time and as a result the BD development was deferred. Market conditions became more favourable for the BD development to supply gas to meet the demand of the East Java region and an updated development plan was approved in 2008 by the Government of Indonesia.

In October 2010, the Government of Indonesia approved an extension of the PSC that was originally awarded in 1982. The approval provided a 20-year extension to the contract which now runs until 2032. The BD field FEED was completed in the second quarter of 2010 and gas sales contracts previously signed in 2010 with three gas buyers were amended in 2011.

In 2011, CNOOC drilled an appraisal well which confirmed commercial quantities of hydrocarbons in the MDA field. An exploration well was also drilled in 2011 on the MBH field and a new gas field was discovered.

In November 2012, the functions of BP Migas, the then Indonesian oil and gas regulator, were transferred to the Energy and Mineral Resources Ministry and a new body, SKK Migas, that has been established as the new industry regulator. As discussed and agreed with the new regulator, a re-tender for the BD field FPSO was conducted and pre-qualification responses are being evaluated. Tendering for the wellhead platform and sales pipeline are also in progress. The development plan for a combined MDA and MBH development project was approved in the first quarter of 2013 by SKK Migas. First gas from the Madura Strait Block is anticipated in 2014/2015 time frame.

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North Sumbawa II

Husky executed a PSC in November 2008 with the Government of Indonesia for the North Sumbawa II contract area. Husky holds a 100% interest in the North Sumbawa II block, which is located in the East Java Basin approximately 300 kilometers east of the Madura Strait block and covers an area of 937,300 acres (3,793 square kilometers). The PSC requires the acquisition of 2-D seismic data with a commitment of U.S. $2 million, and the drilling of one exploration well with a commitment of U.S. $10 million within the first four years of the contract, including an approved one year extension. Husky satisfied its seismic work commitment by acquiring 1,020 kilometers of 2-D seismic data in December 2009. Husky has used this data to identify a potential exploration prospect and drilling is under consideration. Husky requested and received an additional one year extension to fulfill its initial drilling commitments.

Atlantic Region

Husky’s offshore East Coast Canada exploration and development program is focused on the Jeanne d’Arc Basin on the Grand Banks, which contains the Hibernia and Terra Nova fields, as well as the White Rose field and satellite extensions including the North Amethyst, West White Rose and the South White Rose extensions. Husky is the operator of the White Rose field and satellite extensions and holds ownership interests in the Terra Nova field, as well as in a number of smaller undeveloped fields. Husky also holds significant exploration acreage offshore Newfoundland and Labrador and a portfolio of exploration licences offshore Greenland.

White Rose Oil Field

The White Rose oil field is located 354 kilometers off the coast of Newfoundland and Labrador and approximately 48 kilometers east of the Hibernia oil field on the eastern section of the Jeanne d’Arc Basin. Husky is the operator of the White Rose field and satellite tiebacks, including the North Amethyst, West White Rose and South White Rose extensions. The Company has a 72.5% working interest in the core field, and a 68.9% working interest in the satellite fields.

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First oil was achieved at White Rose in November 2005. The White Rose field was the third oil field developed offshore Newfoundland and Labrador. The field currently has nine production wells, ten water injectors, and three gas injectors. Husky continues to look at means of enhancing oil recovery from the core field, and during 2012 drilled an infill production well at White Rose in the South Avalon oil pool, which was brought online in August 2012. During 2012, Husky’s gross production from the White Rose field averaged 14.3 mbbls/day.

On May 31, 2010, first oil was achieved from North Amethyst, the first satellite field extension for the White Rose field. The field is located approximately six kilometers southwest of the SeaRose FPSO vessel. Production flows from North Amethyst to the SeaRose FPSO through a series of subsea flow lines. During 2012, Husky’s gross production from North Amethyst averaged 13.1 mbbls/day. A fourth production well was completed and brought online in December 2012. As of December 31, 2012, the field had four production wells and three water injection wells. Up to 11 wells are currently planned for the main North Amethyst development.

A Development Plan Amendment (“DPA”) requesting approval to produce from a second, deeper formation at North Amethyst is moving through the regulatory review process. The DPA currently envisions drilling one production well and one water injector, utilizing existing infrastructure.

Husky continues to progress plans for a staged development of the West White Rose field through a two-well pilot project. First production was achieved in September 2011, with a supporting water injection well completed and brought online in 2012. Husky’s production from this satellite field was 3.4 mbbls/day during 2012. These wells will provide additional information on the reservoir to refine development plans for the full West White Rose field.

The Company continues to evaluate the feasibility of a concrete wellhead and drilling platform for development of future resources in the White Rose region, including the full development of West White Rose. Pre-FEED and FEED contracts to support this work were awarded in April 2012.

Production from the White Rose field and satellite extensions was impacted during 2012 by a planned maintenance off-station program which saw production from the SeaRose FPSO shut in for 102 days. Production resumed August 13, 2012, three weeks ahead of schedule.

In the third quarter of 2012, Husky excavated a new subsea drill centre to facilitate future operations at the South White Rose extension. Discovered in 2003, it is the smallest of the satellite tie-back developments. A DPA to provide for both production and gas injection wells in the region was filed in the fourth quarter of 2012. Development drilling from the new centre is scheduled to commence in early 2013.

Terra Nova Oil Field

The Terra Nova oil field is located approximately 350 kilometers southeast of St. John’s, Newfoundland and Labrador. The Terra Nova oil 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. Husky’s working interest in the field increased to 13% effective December 1, 2010.

Husky’s production in 2012 from the Terra Nova field was 3.0 mbbls/day. Production at Terra Nova was impacted by a planned maintenance off-station program which lasted 26 weeks. Production from the field resumed on December 9, 2012 and continues to ramp up more slowly than anticipated.

As at December 31, 2012, there were 14 wells in operation in the Graben area, eight production wells, three water injection wells and three gas injection wells. In the East Flank area there were 12 wells operating, including seven production wells and five water injection wells. There is one extended reach producer and an extended reach water injection well in the Far East area. Drilling operations are expected to continue in 2013 on both new and existing development wells.

Atlantic Region Exploration

Husky believes that the Atlantic Region has exploration potential, and that the Company’s position in the region will provide growth opportunities for light crude oil and natural gas development in the medium to long-term. Husky presently holds working interests ranging from 5.3% to 73.1% in 23 significant discovery areas (“SDAs”) in the Jeanne d’Arc Basin, the Flemish Pass and Labrador and Baffin Island.

AIF 2012 Page 22 

Husky participated in the Searcher C-87 exploration well during the second half of the year. The Searcher exploration well did not encounter commercial hydrocarbons. In November 2012, the Company was awarded exploration rights to a 208,899 hectare parcel of land in the Flemish Pass offshore Newfoundland. Husky holds a 40% working interest in the new licence.

As of January 16, 2013, Husky held a working interest in 17 Exploration Licences (“ELs”) offshore Newfoundland, Labrador and Greenland. Husky is the operator of 13 of these ELs and has working interests ranging from 35% to 100%.

The Company will also participate in additional operated and non-operated exploration and delineation wells during 2013, including the partner-operated Harpoon exploration well located southeast of the Mizzen discovery in the Flemish Pass. Husky holds a 35% working interest in both wells.

AIF 2012 Page 23 

Greenland

Husky is the operator of two ELs offshore the west coast of Disko Island, Greenland. Husky continues to evaluate its opportunities in the region and has received a a two-year extension on the initial phase of its exploration program. Geotechnical evaluations continued on the Greenland concessions and socio-economic study work is expected to advance during 2013.

Oil Sands

Sunrise Energy Project

On March 31, 2008, Husky and BP completed a transaction that created an integrated North American oil sands business. The business comprises 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.

FEED for Phase I of the Sunrise in-situ SAGD oil sands project, located in the Athabasca region of northern Alberta, was completed in December 2009. During 2010, the partnership reached an agreement on the movement of diluted bitumen to market and transportation of diluent to the Sunrise oil sands site. Project sanction for Phase I was announced in late 2010 and Husky awarded major engineering and construction contracts for the central processing and field facilities. Development drilling commenced in the first quarter of 2011. First production for Phase I is planned for 2014.

The Sunrise Energy Project was approved by the ERCB in December 2005. An amendment to the application was submitted in April 2007, which outlined changes and optimizations resulting from ongoing depletion planning and FEED. Amendment approvals from the ERCB were received in January 2009 and approval from Alberta Environment was received in the first quarter of 2009. A second amendment to optimize the central plant facility design was filed with the regulators in July 2009 and approval was received from both the ERCB and Alberta Environment in December 2009.

The drilling program for Phase I was completed in 2012 and the CPF is approaching 50% completion with piling substantially completed and foundation work proceeding at the site. Major equipment continues to be delivered and placed into position with approximately half of the modules fabricated and moved to site. Construction of the field facilities is now more than 80% complete with significant activity currently underway, including pipelining in the field and fabrication in the module shops.

Regulatory approvals are in place for a total of 200,000 bbls/day (100,000 bbls/day net).

Tucker Oil Sands Project

Tucker is an in-situ SAGD oil sands project located 30 kilometers northwest of Cold Lake, Alberta that commenced production at the end of 2006. Husky drilled two wells (one well pair) in 2011 to test the productivity of the Lower Grand Rapids formation. Based on the positive results, drilling of ten wells (five well pairs) commenced in 2012. Gross production at Tucker in December 2012 was 9.9 mbbls/day. Several applications to the ERCB have been approved or are proceeding for additional drilling and field development through 2015.

Undeveloped Oil Sands Assets

Husky holds in excess of 550,000 acres in undeveloped oil sands leases and has a 100% working interest in all leases except in Athabasca South in which it has a 50% working interest.

In Saleski, just north of the Hamlet of Wabasca, Alberta, Husky drilled and tested two wells and tested one standing well to high-grade acreage and select a pilot production area and confirm the availability of water source and disposal. Lab scale tests were performed to support advancing to the pilot stage; the application for the pilot is planned for 2013.

Further portfolio activity is expected to focus on accelerating and high grading the development of Husky’s other oil sands leases.

AIF 2012 Page 24 

Heavy Oil

Lloydminster Heavy Oil and Gas

Husky’s heavy oil assets are primarily concentrated in a large producing region in the Lloydminster, Alberta/Saskatchewan area. The Company maintains a land position of approximately two million gross acres within this area. Over 90% of Husky’s proved reserves in the region are contained in the heavy crude oil producing areas of Pikes Peak, Edam, Tangleflags, Celtic, Bolney, Paradise Hill, Westhazel, Big Gully, Mervin, Marwayne, Lashburn, Gully Lake, Vermilion, Swimming, Morgan, Lindbergh, Aberfeldy, Marsden, Epping, Furness and Rush Lake, and in the medium gravity crude oil producing fields of Wildmere and Wainwright. These fields contain accumulations of heavy crude oil at relatively shallow depths and are all located within 100 kilometers of the town of Lloydminster, Alberta.

Husky currently produces from oil and gas wells ranging in depth from 450 meters to 650 meters and holds a 100% working interest in the majority of these wells. Production of heavy oil from the Lloydminster area uses a variety of techniques, including primary production methods, horizontal well technology, CSS, and SAGD. Husky has increased primary production from the area through cold production techniques which utilize progressive cavity pumps capable of simultaneous production of sand and heavy oil from unconsolidated formations. Husky’s gross heavy and medium crude oil production from the area averaged 89.5 mbbls/day in 2012. Of the total gross crude oil produced, 61.1 mbbls/day was primary production of heavy crude oil, including CHOPS and horizontal technologies, 26.3 mbbls/day was from Husky’s thermal operations and 2.1 mbbls/day was from the medium gravity waterflooded fields in the Wainwright and Wildmere areas. Husky also produces natural gas from numerous small shallow pools in the Lloydminster region and recovers solution gas produced from heavy oil wells. During 2012, Husky’s gross natural gas production from the Lloydminster region averaged 25.4 mmcf/day.

In the Lloydminster area, the Company owns and operates 21 oil treating facilities which are tied into the Husky heavy oil pipeline systems. These pipeline systems transport heavy crude oil from the field locations to the Husky Lloydminster asphalt refinery, the Husky Lloydminster Upgrader and the third-party pipeline systems at Hardisty, Alberta.

AIF 2012 Page 25 

Production commenced in the second quarter of 2012 ahead of schedule at both the Pikes Peak South and Paradise Hill heavy oil thermal projects and has ramped up to levels exceeding the combined 11,500 bbls/day design rates. Average production levels of approximately 12,000 bbls/day at Pikes Peak South and 5,000 bbls/day at Paradise Hill heavy oil thermal projects were achieved during the fourth quarter of 2012.

Construction is approximately 40% complete at the 3,500 bbls/day Sandall thermal development project and initial drilling has commenced. First production is scheduled in 2014.

Design and initial site work is continuing at the 10,000 bbls/day Rush Lake commercial project with first production anticipated in 2015. Production performance from the first single well pair pilot is in line with expectations and a second well pair pilot is planned to commence production in the second quarter of 2013. Initial planning is ongoing for three additional commercial thermal projects.

The Company advanced its horizontal drilling program in 2012 with the completion of 144 wells. Based on the positive performance of previous horizontal drilling programs, Husky is continuing this program by planning to drill approximately 140 wells in 2013. The Company also drilled 250 gross CHOPS wells during 2012. In 2013, 200 CHOPS wells are planned.

The Company is focused on increasing its heavy oil production and believes that its undeveloped land position, coupled with the development and application of improved recovery technologies, will maintain heavy crude oil production in the Lloydminster area.

Non-Thermal Enhanced Oil Recovery (“EOR”)

Husky operated four solvent EOR pilot programs in 2012 and a CO₂ capture and liquefaction plant at the Lloydminster Ethanol Plant. This liquefied CO₂ is used in the ongoing EOR piloting program.

Western Canada (excluding Heavy Oil and Oil Sands)

East Central Alberta

Husky’s East Central Alberta operations are located primarily in central Alberta, in a band extending from the Rocky Mountain foothills in the west, to east of the Alberta/Saskatchewan boundary. Husky operates 67 facilities in the area. Husky’s 2012 gross production from East Central Alberta averaged 82 mmcf/day of natural gas and 16.4 mbbls/day of oil and NGL.

Husky plans to continue its Viking resource oil drilling program which targets medium productivity reservoirs enhanced by utilizing horizontal drilling and multiple-stage fracturing treatments. Plans are in place to drill up to 58 Viking wells in 2013, primarily at the proven areas of Redwater (20 kilometers northeast of Edmonton) and Elrose (80 kilometers southwest of Saskatoon), and expand into the Alliance area (200 kilometers southeast of Edmonton). Husky currently has approximately 100 wells producing from the plays and will continue to develop infrastructure in all three areas, as required.

Preparations for the Macklin, Saskatchewan ASP flood have advanced, with petrophysical and coreflood studies completed, confirming ASP flooding potential. Optimization of the existing pattern waterflood which is necessary prior to ASP implementation is underway and well workovers are scheduled to be completed in 2013.

At Red Deer, Husky will focus on the development of additional oil resource properties from the Mississippian and Devonian formations. Development of Husky’s gas properties in the area has been deferred due to low commodity prices with the exception of some liquids-rich gas prospects in the Hussar field.

Southern Alberta and Southern Saskatchewan

Husky is the operator of a number of properties in southern Alberta and southern Saskatchewan. Husky’s gross production from properties in southern Alberta averaged 7.0 mbbls/day of crude oil and NGL and 16.8 mmcf/day of natural gas during 2012. In southern Saskatchewan, 2012 gross production averaged 15.6 mbbls/day of crude oil and NGL and 14.9 mmcf/day of natural gas.

AIF 2012 Page 26 

Husky’s ASP EOR program is used at Warner and Crowsnest in southern Alberta and at Gull Lake in southern Saskatchewan. In addition, Husky holds a 20.3% non-operating working interest in the Instow, Saskatchewan ASP flood, where oil response continues to increase in line with expectations. Husky’s gross incremental production at December 2012 for its ASP EOR program was approximately 3.9 mbbls/day (2.5 mbbs/day net). Husky’s ASP project at Fosterton, Saskatchewan commenced production in December 2012 and has continued to ramp up to targeted ASP injection rates. Husky is the operator and holds a 62.4% working interest in this project.

Development of the Bakken formation continued in southeast Saskatchewan, with 23 wells drilled and 22 wells on production. A tank treating facility, gathering system, and oil sales line were built and commissioned. Production and evaluation of the Lower Shaunavon formation in southwest Saskatchewan continued with four wells drilled and put on production. Husky’s gross production from these two plays was approximately 2.6 mbbls/day in December 2012.

Foothills Northwest Plains

The Foothills Northwest Plains area is located in western and northern Alberta and British Columbia. The area is made up of five distinct districts: Rainbow Lake, Northern Alberta, Northern Alberta & British Columbia Plains, Ansell-Galloway and Foothills. Average production from across all Foothills Northwest Plains was approximately 97.1 mboe/day in 2012.

Rainbow Lake, located approximately 700 kilometers northwest of Edmonton, Alberta, is the site of Husky’s largest light oil production operation in Western Canada. Husky’s production for 2012 from the Rainbow Lake district averaged 10.8 mbbls/day of light crude oil and NGL and 94.2 mmcf/day of natural gas. In addition to operating and continuing development of these assets, Husky has commenced exploration activities within the Muskwa resource play in which Husky holds a 100% working interest and a total of 12 horizontal wells were drilled in 2012.

The Northern Alberta district surrounds the communities of Peace River and Slave Lake northwest of Edmonton, Alberta and produces shallow gas and heavy oil. Husky’s production for 2012 from this district averaged 6.5 mbbls/day of heavy oil and 32 mmcf/day of natural gas. Husky drilled 54 wells in 2012 to expand its primary heavy oil production from the McMullen field, located 40 kilometers southwest of the Hamlet of Wabasca, Alberta and continued to evaluate an EOR pilot project through 2012.

Gross production from the Northern Alberta & British Columbia Plains district averaged approximately 5.2 mbbls/day of light crude oil and NGL and 81.9 mmcf/day of natural gas in 2012. The Company continued development of the Cardium oil resource play in the Wapiti area, in which Husky holds a 100% working interest, drilling five horizontal oil wells.

Production at the Ansell-Galloway district was approximately 2.2 mbbls/day of NGL and 56.0 mmcf/day of natural gas in 2012. A horizontal drilling program was executed in 2012 with six Cardium and five Wilrich horizontal wells drilled. In addition four vertical appraisal wells were drilled and Husky participated in three partner operated horizontal wells. Significant progress was made with securing additional offtake capacity utilizing excess third-party plant capacity in the area for 2013 volumes and beyond.

The Foothills district produced approximately 4.0 mbbls/day of light crude oil and NGL and 146.1 mmcf/day of natural gas in 2012. Production from the area is predominantly processed at the Ram River gas plant, with Husky operating and holding an average 84% interest in the Ram River sour gas plant and related processing facilities located in the Foothills district. Maintenance and operational activities continued in 2012; however, development activity was limited.

Northwest Territories (“NWT”)

In the NWT, Husky was active on two ELs acquired in June 2011. Following the construction of an ice bridge spanning the Mackenzie River and a winter access road, two vertical pilot wells were drilled: the N-09 well on EL 463 and the H-64 well on EL 462. These two wells satisfied the requirements to extend the term of both ELs to the full nine-year term. The two vertical wells were extensively cored and have provided valuable data for the characterization of the geochemical and geomechanical properties of the reservoir and the bounding units. Additionally, a 220 square kilometre multi-component proprietary 3-D seismic survey was acquired.

AIF 2012 Page 27 

Pre-disturbance, archeological, permafrost, aggregate, baseline wildlife, vegetation and surface water studies were conducted in the summer of 2012. This data, combined with the geotechnical data acquired from the two vertical wells, provided the background for Husky’s land and water use permit applications for the winter 2012/2013 program including construction, baseline groundwater, completion/testing and all season access road projects which received regulatory approval.

Columbia River Basin (Washington and Oregon State – USA)

Husky holds undeveloped land in the Columbia River Basin located in the states of Washington and Oregon. While these lands are thought to be prospective for natural gas, this play is not competitive with Husky’s many other opportunities for investment due to the relatively high risk of the play, combined with the current low gas prices. A decision has been made to allow these leases to expire.

Distribution of Oil and Gas Production

Crude Oil and NGL

Husky provides heavy crude oil feedstock to its Upgrader and its asphalt refinery, which are located at Lloydminster, Alberta/Saskatchewan. The combined dry crude feedstock requirements of the Upgrader and asphalt refinery are approximately equal to Husky’s heavy crude oil production from the Lloydminster area. Husky also purchases third party volumes. Husky markets heavy crude oil production directly to refiners located in the mid-west and eastern United States and Canada. Husky markets its light and synthetic crude oil production to third-party refiners in Canada, the United States and Asia in addition to Husky’s Lima Refinery. NGL are sold to local petrochemical end users, retail and wholesale distributors and refiners in North America.

Husky markets third-party volumes of crude oil, synthetic crude oil and NGL in addition to its own production. For a discussion of Husky’s distribution methods associated with crude oil and NGL, refer to the Commodity Marketing section of this AIF.

Natural Gas

The following table shows the distribution of Husky’s gross average daily natural gas production for the years indicated. The Company also markets third-party natural gas production in addition to its own production.

	Years ended December 31,
	2012		2011		2010
	(mmcf/day)
Sales Distribution
United States		154		163		223
Canada		242		297		164
		396		460		387
Sales to Aggregators		4		3		3
Internal Use (1)		154		144		117
		554		607		507

⁽¹⁾  Husky consumes natural gas for fuel at several of its facilities.

Fixed Price Contracts

The following table shows the future commitments to deliver natural gas from Husky reserves. Husky’s proved developed reserves of natural gas in Western Canada are more than adequate to meet future delivery commitments.

	bcf		Fixed Price $/mmbtu
2013		11.6		4.17
2014		11.6		4.25
2015		3.8		4.34

AIF 2012 Page 28 

Disclosures of Oil and Gas Activities

Production History

	Year Ended		Three Months Ended
Average Gross Daily Production	Dec 31, 2012		Dec 31, 2012		Sept 30, 2012		June 30, 2012		Mar 31, 2012
Canada – Western Canada
Light Crude Oil and NGL (mbbls/day)		30.1		31.9		29.0		29.4		30.5
Medium Crude Oil (mbbls/day)		24.1		23.2		23.9		24.1		24.9
Heavy Crude Oil (mbbls/day)		76.9		76.0		77.1		78.1		76.2
Bitumen (mbbls/day)		35.9		46.7		37.8		29.6		29.6
Natural Gas (mmcf/day)		554.0		523.7		544.9		559.5		588.3
Canada – Atlantic Region
Light Crude Oil (mbbls/day)		33.8		45.7		18.5		19.0		52.1
China
Light Crude Oil and NGL (mbbls/day)		8.4		8.5		7.9		8.4		8.6
Total Gross Production (mboe/day)		301.5		319.3		285.0		281.9		319.9
	Year Ended		Three Months Ended
Average Gross Daily Production	Dec 31, 2011		Dec 31, 2011		Sept 30, 2011		June 30, 2011		Mar 31, 2011
Canada – Western Canada
Light Crude Oil and NGL (mbbls/day)		24.8		28.8		22.9		21.7		25.9
Medium Crude Oil (mbbls/day)		24.5		24.3		24.6		24.6		24.6
Heavy Crude Oil (mbbls/day)		74.5		75.8		75.1		73.6		73.4
Bitumen (mbbls/day)		24.7		27.4		23.6		23.6		24.2
Natural Gas (mmcf/day)		607.0		597.9		614.7		631.8		583.3
Canada – Atlantic Region
Light Crude Oil (mbbls/day)		54.3		54.6		53.4		53.7		55.5
China
Light Crude Oil and NGL (mbbls/day)		8.5		8.3		7.0		9.1		9.6
Total Gross Production (mboe/day)		312.5		318.9		309.1		311.6		310.4
	Year Ended		Three Months Ended
Average Gross Daily Production	Dec 31, 2010		Dec 31, 2010		Sept 30, 2010		June 30, 2010		Mar 31, 2010
Canada – Western Canada
Light Crude Oil and NGL (mbbls/day)		23.0		23.0		23.5		22.5		23.4
Medium Crude Oil (mbbls/day)		25.4		25.3		25.7		25.1		25.3
Heavy Crude Oil (mbbls/day)		74.5		74.6		72.4		74.6		76.4
Bitumen (mbbls/day)		22.3		23.1		21.9		21.5		22.6
Natural Gas (mmcf/day)		506.8		494.2		505.5		503.9		523.7
Canada – Atlantic Region
Light Crude Oil (mbbls/day)		46.7		41.3		50.8		45.0		49.9
China
Light Crude Oil and NGL (mbbls/day)		10.7		10.8		10.1		11.2		11.0
Total Gross Production (mboe/day)		287.1		280.5		288.7		283.9		295.9

AIF 2012 Page 29 

Netback Analysis

The following tables show Husky’s netback analysis by product and area. The netback analysis has been revised to align with the change in segment presentation and prior quarters have been restated to reflect the current presentation.

	Year Ended			Three Months Ended
Average Per Unit Amounts	Dec 31, 2012			Dec 31, 2012		Sept 30, 2012			Jun 30, 2012			Mar 31, 2012
Light Crude Oil and NGL ($/bbl)
Canada – Western Canada
Price received	$	76.85		$	72.31	$	71.98		$	78.62		$	84.64
Royalties	$	12.95		$	10.49	$	14.47		$	11.76		$	15.25
Production Costs	$	20.72		$	19.68	$	19.82		$	20.26		$	21.86
Netback	$	43.18		$	42.14	$	37.70		$	46.60		$	47.53
Canada – Atlantic Canada
Price Received	$	115.78		$	108.88	$	112.78		$	110.97		$	124.74
Royalties	$	12.36		$	11.15	$	9.11		$	4.00		$	17.65
Production Costs	$	17.12		$	10.73	$	33.36		$	31.77		$	11.63
Transportation Costs (1)	$	2.14		$	1.95	$	3.34		$	4.21		$	1.12
Netback	$	84.16		$	85.05	$	66.97		$	70.99		$	94.35
Canada – Total
Price Received (1)	$	96.29		$	92.73	$	86.55		$	89.66		$	109.24
Royalties	$	12.64		$	10.88	$	12.39		$	8.72		$	16.76
Production Costs	$	18.82		$	14.40	$	25.08		$	24.78		$	15.40
Netback	$	64.83		$	67.45	$	49.08		$	56.17		$	77.07
China
Price Received	$	113.01		$	104.25	$	106.38		$	114.28		$	126.74
Royalties	$	26.88		$	22.97	$	24.31		$	29.42		$	30.73
Production Costs	$	10.08		$	12.01	$	9.10		$	11.32		$	7.85
Netback	$	76.04		$	69.28	$	72.97		$	73.54		$	88.17
Company Total
Price Received (1)	$	98.22		$	93.88	$	89.38		$	93.30		$	110.89
Royalties	$	14.28		$	12.08	$	14.09		$	11.78		$	18.08
Production Costs	$	17.81		$	14.16	$	22.80		$	22.79		$	14.69
Netback	$	66.13		$	67.63	$	52.49		$	58.74		$	78.12
Medium Crude Oil ($/bbl)
Canada – Western Canada
Price Received	$	71.51		$	67.55	$	69.59		$	69.92		$	78.63
Royalties	$	12.76		$	11.14	$	11.33		$	12.59		$	15.89
Production Costs	$	20.53		$	19.82	$	21.04		$	21.85		$	20.94
Netback	$	38.22		$	36.60	$	37.22		$	35.48		$	41.80
Heavy Crude Oil ($/bbl)
Canada – Western Canada
Price Received	$	61.91		$	57.90	$	60.58		$	60.42		$	68.93
Royalties	$	6.04		$	7.85	$	7.75		$	5.77		$	2.75
Production Costs	$	17.56		$	18.36	$	18.70		$	16.26		$	16.98
Netback	$	38.31		$	31.70	$	34.13		$	38.40		$	49.20
Bitumen ($/bbl)
Canada – Western Canada
Price Received	$	59.49		$	55.74	$	60.10		$	58.09		$	65.83
Royalties	$	3.80		$	2.69	$	2.14		$	5.92		$	5.60
Production Costs	$	13.36		$	12.74	$	13.21		$	13.17		$	14.81
Netback	$	42.32		$	40.31	$	44.75		$	39.00		$	45.43
Natural Gas ($/mcf)
Canada – Western Canada (2)
Price Received	$	2.60		$	3.25	$	2.48		$	2.05		$	2.64
Royalties	($	0.08	)	$	0.08	($	0.28	)	($	0.11	)	($	0.02	)
Production Costs	$	1.91		$	2.17	$	1.92		$	1.75		$	1.81
Netback	$	0.77		$	1.01	$	0.83		$	0.41		$	0.86

⁽¹⁾  Transportation costs are shown separately from price in Canada – Atlantic Region. This cost category is netted against price when calculating Canada Total and Company Total balances.

⁽²⁾  Includes sulphur sales and royalties.

AIF 2012 Page 30 

	Year Ended		Three Months Ended
Average Per Unit Amounts	Dec 31, 2011		Dec 31, 2011		Sept 30, 2011		Jun 30, 2011		Mar 31, 2011
Light Crude Oil and NGL ($/bbl)
Canada – Western Canada
Price Received	$	84.02	$	88.56	$	76.55	$	88.81	$	81.55
Royalties	$	17.04	$	19.98	$	14.77	$	17.20	$	15.52
Production Costs	$	21.37	$	19.66	$	20.51	$	24.03	$	21.86
Netback	$	45.61	$	48.92	$	41.27	$	47.58	$	44.18
Canada – Atlantic Canada
Price Received	$	112.21	$	114.74	$	110.59	$	115.48	$	108.04
Royalties	$	19.36	$	22.35	$	17.12	$	19.61	$	18.31
Production Costs	$	8.75	$	8.54	$	9.82	$	9.00	$	7.67
Transportation Costs (1)	$	1.50	$	1.59	$	1.62	$	0.87	$	1.91
Netback	$	82.59	$	82.26	$	82.03	$	86.00	$	80.15
Canada – Total
Price Received (1)	$	102.34	$	104.67	$	99.24	$	107.20	$	98.31
Royalties	$	18.63	$	21.53	$	16.42	$	18.92	$	17.42
Production Costs	$	12.71	$	12.38	$	13.03	$	13.32	$	12.18
Netback	$	71.00	$	70.77	$	69.79	$	74.95	$	68.70
China
Price Received	$	110.54	$	115.61	$	109.81	$	111.90	$	105.30
Royalties	$	32.75	$	36.39	$	32.34	$	37.22	$	25.54
Production Costs	$	8.17	$	9.18	$	10.41	$	7.38	$	6.34
Netback	$	69.62	$	70.04	$	67.07	$	67.30	$	73.41
Company Total
Price Received (1)	$	103.13	$	105.66	$	100.12	$	107.70	$	99.04
Royalties	$	20.00	$	22.87	$	17.76	$	20.89	$	18.28
Production Costs	$	12.27	$	12.09	$	12.81	$	12.68	$	11.57
Netback	$	70.86	$	70.70	$	69.56	$	74.13	$	69.20
Medium Crude Oil ($/bbl)
Canada – Western Canada
Price Received	$	76.59	$	85.83	$	70.81	$	81.24	$	68.41
Royalties	$	14.13	$	15.24	$	13.58	$	15.24	$	12.41
Production Costs	$	20.05	$	20.88	$	21.60	$	18.14	$	19.58
Netback	$	42.41	$	49.71	$	35.63	$	47.86	$	36.41
Heavy Crude Oil ($/bbl)
Canada – Western Canada
Price Received	$	68.13	$	76.37	$	62.35	$	72.51	$	61.02
Royalties	$	8.83	$	9.47	$	8.09	$	9.88	$	7.86
Production Costs	$	17.57	$	17.70	$	17.94	$	17.44	$	17.16
Netback	$	41.72	$	49.21	$	36.31	$	45.20	$	35.99
Bitumen ($/bbl)
Canada – Western Canada
Price Received	$	65.75	$	74.19	$	59.60	$	69.76	$	58.11
Royalties	$	8.69	$	9.75	$	6.73	$	7.91	$	10.18
Production Costs	$	17.72	$	18.47	$	17.18	$	18.19	$	16.91
Netback	$	39.34	$	45.02	$	34.79	$	42.52	$	28.33
Natural gas ($/mcf)
Canada – Western Canada (2)
Price Received	$	3.89	$	3.53	$	4.12	$	4.02	$	3.87
Royalties	$	0.18	$	0.23	$	0.17	$	0.19	$	0.13
Production Costs	$	1.75	$	1.83	$	1.85	$	1.70	$	1.62
Netback	$	1.96	$	1.47	$	2.10	$	2.13	$	2.11

⁽¹⁾  Transportation costs are shown separately from price in Canada – Atlantic Region. This cost category is netted against price when calculating Canada Total and Company Total balances.

⁽²⁾  Includes sulphur sales and royalties.

AIF 2012 Page 31 

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

Producing Wells

	Oil Wells				Natural Gas Wells				Total
	Gross		Net		Gross		Net		Gross		Net
Canada
Alberta		4,341		3,575		5,732		4,221		10,073		7,796
Saskatchewan		6,941		6,000		1,373		1,256		8,314		7,256
British Columbia		199		57		311		270		510		327
Newfoundland		30		12		—		—		30		12
		11,511		9,644		7,416		5,747		18,927		15,391
International
China		32		13		—		—		32		13
Libya		—		—		—		—		—		—
		32		13		—		—		32		13
As at December 31, 2012		11,543		9,657		7,416		5,747		18,959		15,404
Canada
Alberta		4,607		3,792		5,883		4,371		10,490		8,163
Saskatchewan		6,753		5,797		1,416		1,293		8,169		7,090
British Columbia		200		58		304		264		504		322
Newfoundland		28		11		—		—		28		11
		11,588		9,658		7,603		5,928		19,191		15,586
International
China		33		13		—		—		33		13
Libya		—		—		—		—		—		—
		33		13		—		—		33		13
As at December 31, 2011		11,621		9,671		7,603		5,928		19,224		15,599
Canada
Alberta		4,484		3,580		5,770		4,407		10,254		7,987
Saskatchewan		6,582		5,488		1,446		1,311		8,028		6,799
British Columbia		204		59		283		242		487		301
Newfoundland		25		9		—		—		25		9
		11,295		9,136		7,499		5,960		18,794		15,096
International
China		32		13		—		—		32		13
Libya		3		1		—		—		3		1
		35		14		—		—		35		14
As at December 31, 2010		11,330		9,150		7,499		5,960		18,829		15,110

Non-Producing Wells

	2012
	Oil Wells				Natural Gas Wells				Total
	Gross		Net		Gross		Net		Gross		Net
Canada		5,150		4,563		1,699		1,416		6,849		5,979

⁽¹⁾  The number of gross wells is the total number of wells in which Husky 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, 2012.

⁽²⁾  Does not include producing wells in which Husky has no working interest but does have a royalty interest. At December 31, 2012, Husky had a royalty interest in 4,333 wells of which 1,458 were oil producers and 2,875 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 2012, there were 751 gross and 725 net oil wells and 670 gross and 524 net natural gas wells which were completed in two or more formations and from which production is not commingled.

AIF 2012 Page 32 

Landholdings – Developed Acreage

(thousands of acres)	Gross		Net
As at December 31, 2012
Western Canada
Alberta		4,590		2,912
Saskatchewan		871		700
British Columbia		187		147
Manitoba		2		—
		5,650		3,759
Atlantic Region		57		20
		5,707		3,779
China		17		7
Libya		7		2
Total		5,731		3,788
As at December 31, 2011
Western Canada
Alberta		4,594		2,908
Saskatchewan		878		699
British Columbia		187		147
Manitoba		19		2
		5,678		3,756
Atlantic Region		58		20
		5,736		3,776
China		17		7
Libya		7		2
Total		5,760		3,785
As at December 31, 2010
Western Canada
Alberta		4,172		2,729
Saskatchewan		891		704
British Columbia		172		133
Manitoba		2		—
		5,237		3,566
Atlantic Region		54		18
		5,291		3,584
China		17		7
Libya		7		2
Total		5,315		3,593

AIF 2012 Page 33 

Landholdings – Undeveloped Acreage

(thousands of acres)	Gross		Net
As at December 31, 2012
Western Canada
Alberta		5,022		3,683
Saskatchewan		1,602		1,431
British Columbia		950		709
Manitoba		3		1
		7,577		5,824
Northwest Territories and Arctic		483		466
Atlantic Region		5,046		3,124
		13,106		9,414
United States		616		259
China		495		243
Indonesia		1,559		937
Greenland		8,471		5,983
Taiwan		2,545		1,909
		26,792		18,745
As at December 31, 2011
Western Canada
Alberta		5,353		3,930
Saskatchewan		1,654		1,481
British Columbia		1,037		774
Manitoba		3		1
		8,047		4,846
Northwest Territories and Arctic		1,156		633
Atlantic Region		5,548		3,339
		14,751		8,818
United States		1,076		398
China		990		484
Indonesia		1,628		1,213
Greenland		8,471		5,983
		26,916		16,896
As at December 31, 2010
Western Canada
Alberta		4,801		3,407
Saskatchewan		1,712		1,522
British Columbia		1,020		747
Manitoba		4		1
		7,537		5,677
Northwest Territories and Arctic		943		303
Atlantic Region		4,777		2,989
		13,257		8,969
United States		1,100		484
China		990		990
Indonesia		1,940		1,595
Greenland		8,471		5,983
		25,758		18,021

AIF 2012 Page 34 

Significant Factors or Uncertainties Relevant to Properties with No Attributed Reserves

The Company has a $322 million work commitment associated with its undeveloped land holdings in the Canadian Northwest Territories and Arctic. In total, the Company has $509 million in exploration work commitments to be incurred over the next five years.

Over the next 12 months, approximately 841,139 acres, or less than 5% of the Company’s net undeveloped landholdings in Canada, will be subject to expiry.

Husky holds interests in a diverse portfolio of undeveloped petroleum assets in Western Canada, the Atlantic Region and in several other areas (offshore Greenland, China, Taiwan and Indonesia, the United States and the Canadian Northwest Territories and Arctic). As part of its active portfolio management, Husky 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.

Drilling Activity

	Year ended December 31,
	2012				2011				2010
	Gross		Net		Gross		Net		Gross		Net
Canada – Western Canada
Exploration
Oil		47		30		50		40		60		51
Gas		19		12		24		24		37		31
Dry		—		—		3		3		8		8
		66		42		77		67		105		90
Development
Oil		775		715		880		765		815		722
Gas		23		17		57		42		73		53
Dry		5		4		4		4		10		9
		803		736		941		811		898		784
		869		778		1,018		878		1,003		874
Canada – Atlantic Region
Development
Oil		2		1.4		3		2.1		2		1.4
China
Development
Oil		—		—		1		0.4		1		0.4
Gas		—		—		4		2.0		2		1.0
		—		—		5		2.4		3		1.4

Service/Stratigraphic Test Wells

	2012
	Gross		Net
Canada – Western Canada		116		95.0
Canada – Atlantic Region		2		1.7
China		—		—
Indonesia		5		2.0

AIF 2012 Page 35 

Current Activities

	Exploratory				Development
Wells Drilling (1)	Gross		Net		Gross		Net
Canada – Western Canada		9		8.3		27		25.4
Canada – Atlantic Region		—		—		—		—
China		—		—		1		0.4

Service/Stratigraphic Test Wells (1)	Gross		Net
Canada		7		6.4

⁽¹⁾  Denotes wells that were being drilled at February 19, 2013.

Costs Incurred

	Total		Western Canada		Atlantic Region		Total Canada		United States		China		Indonesia		Libya
	($ millions)
Property acquisition
Unproven		15		15		—		15		—		—		—		—
Proven		6		6		—		6		—		—		—		—
Exploration		363		247		92		339		—		—		25		—
Development		4,908		3,527		547		4,074		—		833		1		—
2012		5,293		3,795		639		4,434		—		833		26		—
	Total		Western Canada		Atlantic Region		Total Canada		United States		China		Indonesia		Libya
	($ millions)
Property acquisition
Unproven		82		82		—		82		—		—		—		—
Proven		792		792		—		792		—		—		—		—
Exploration		723		342		115		457		1		233		32		—
Development		2,935		2,131		258		2,389		—		546		—		—
2011		4,532		3,347		373		3,720		1		779		32		—
	Total		Western Canada		Atlantic Region		Total Canada		United States		China		Indonesia		Libya
	($ millions)
Property acquisition
Unproven		62		62		—		62		—		—		—		—
Proven		327		327		—		327		—		—		—		—
Exploration		687		210		96		306		—		369		12		—
Development		2,048		1,589		396		1,985		—		60		—		3
2010		3,124		2,188		492		2,680		—		429		12		3

AIF 2012 Page 36 

Oil and Gas Reserves Disclosures

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 NI 51-101. Husky’s oil and gas reserves are prepared by internal reserves evaluation staff using a formalized process for determining, approving and booking reserves. This process requires all reserves evaluations to be done on a consistent basis using established definitions and guidelines. Approval of individually significant reserves changes requires review by an internal panel of qualified reserves evaluators. 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 of its reserves data and other oil and gas information.

The material differences between reserves quantities disclosed under NI 51-101 and those disclosed under the rules of the SEC and the United States Financial Accounting Standards Board (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). The following oil and gas reserves disclosure has been prepared in accordance with NI 51-101 effective December 31, 2012. Husky received approval from the CSA to also disclose its reserves using U.S. Rules as supplementary disclosure to the reserves and oil and gas activities disclosure required by NI 51-101. The reserves information prepared in accordance with 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.

Note that the numbers in each column of the tables throughout this section may not add due to rounding.

Audit of Oil and Gas Reserves

McDaniel & Associates Consultants Ltd., an independent firm of qualified oil and gas reserves evaluation engineers, was engaged to conduct an audit of Husky’s crude oil, natural gas and NGL reserves estimates. McDaniel & Associates Consultants Ltd. 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.

Disclosure of Oil and Gas Information

Unless otherwise noted in this document, all provided reserves estimates have an effective date of December 31, 2012. Gross reserves or gross production are reserves or production attributable to Husky’s 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 effect of hedging gains and losses. Unless otherwise indicated, all financial information is in accordance with accounting principles generally accepted in Canada. Husky completed a transition to IFRS in 2011 and all 2012, 2011 and 2010 financial information has been prepared using IFRS as issued by the International Accounting Standards Board.

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.

AIF 2012 Page 37 

Disclosure of Exemption Under National Instrument 51-101

Husky sought and was granted by the Canadian Securities Administrators (“CSA”) an exemption from the requirement under National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”) to involve independent qualified oil and gas reserves evaluators or auditors. Notwithstanding this exemption, the Company involves independent qualified reserves auditors as part of Husky’s corporate governance practices. Their involvement helps assure that the Company’s internal oil and gas reserves estimates are materially correct.

In Husky’s view, the reliability of Husky’s internally generated oil and gas reserves data is not materially less than would be afforded by Husky involving independent qualified reserves evaluators to evaluate and review the reserves data. The primary factors supporting the involvement of independent qualified reserves evaluators apply when (i) their knowledge of, and experience with, a reporting issuer’s reserves data are superior to that of the internal reserves evaluators and (ii) the work of the independent qualified reserves evaluators is significantly less likely to be adversely influenced by self-interest or management of the reporting issuer than the work of internal reserves evaluation staff. In Husky’s view, neither of these factors applies in Husky’s circumstances.

AIF 2012 Page 38 

Summary of Oil and Natural Gas Reserves

As at December 31, 2012

Forecast Prices and Costs

Canada

	Light Crude Oil (mmbbls)				Medium Crude Oil (mmbbls)				Heavy Crude Oil (mmbbls)				Bitumen (mmbbls)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Proved
Developed Producing		137.0		120.1		86.2		76.5		69.1		61.5		58.7		54.7
Developed Non-producing		3.3		3.3		1.8		1.6		14.6		13.5		—		0.0
Undeveloped		24.4		20.3		7.4		6.6		21.7		20.3		252.1		216.7
Total Proved		164.8		143.7		95.4		84.7		105.4		95.4		310.9		271.4
Probable		94.3		76.5		21.9		18.5		35.1		30.8		1,413.8		1,118.1
Total Proved Plus Probable		259.1		220.2		117.4		103.2		140.5		126.2		1,724.7		1,389.5
	Coal Bed Methane (bcf)				Natural Gas (bcf)				NGL (mmbbls)				Total (mmboe)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Proved
Developed Producing		22.1		20.7		1,586.3		1,396.6		63.8		49.4		682.9		598.5
Developed Non-producing		1.2		1.0		104.1		94.5		1.2		1.1		38.4		35.5
Undeveloped		—		—		359.0		351.7		11.0		9.0		376.5		331.5
Total Proved		23.3		21.8		2,049.3		1,842.8		76.0		59.6		1,097.9		965.5
Probable		5.9		5.6		468.5		431.0		23.1		18.1		1,667.3		1,334.7
Total Proved Plus Probable		29.2		27.3		2,517.8		2,273.7		99.1		77.7		2,765.2		2,300.2

China⁽¹⁾

	Light Crude Oil (mmbbls)				Medium Crude Oil (mmbbls)				Heavy Crude Oil (mmbbls)				Bitumen (mmbbls)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Proved
Developed Producing		7.8		5.9		—		—		—		—		—		—
Developed Non-producing		—		—		—		—		—		—		—		—
Undeveloped		—		—		—		—		—		—		—		—
Total Proved		7.8		5.9		—		—		—		—		—		—
Probable		1.4		1.0		—		—		—		—		—		—
Total Proved Plus Probable		9.2		7.0		—		—		—		—		—		—
	Coal Bed Methane (bcf)				Natural Gas (bcf)				NGL (mmbbls)				Total (mmboe)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Proved
Developed Producing		—		—		—		—		0.2		0.1		8.0		6.1
Developed Non-producing		—		—		—		—		—		—		—		—
Undeveloped		—		—		267.1		271.9		6.6		6.9		51.1		52.2
Total Proved		—		—		267.1		271.9		6.7		7.0		59.0		58.2
Probable		—		—		244.5		229.5		5.6		5.2		47.7		44.5
Total Proved Plus Probable		—		—		511.6		501.4		12.3		12.2		106.7		102.8

⁽¹⁾ The Block 29/26 Production Sharing Contract which governs the Liwan off-shore project in China entitles Husky to a share of production in excess of its working interest to recover certain costs that were incurred by the Company on behalf of both Husky and its partner during the exploration phase. These volumetric recoveries are included in net reserves in accordance to the COGEH guidelines and represent 4.15 mmboe of net total proved plus probable reserves.

AIF 2012 Page 39 

Indonesia

	Light Crude Oil (mmbbls)				Medium Crude Oil (mmbbls)				Heavy Crude Oil (mmbbls)				Bitumen (mmbbls)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Proved
Developed Producing		—		—		—		—		—		—		—		—
Developed Non-producing		—		—		—		—		—		—		—		—
Undeveloped		—		—		—		—		—		—		—		—
Total Proved		—		—		—		—		—		—		—		—
Probable		—		—		—		—		—		—		—		—
Total Proved Plus Probable		—		—		—		—		—		—		—		—
	Coal Bed Methane (bcf)				Natural Gas (bcf)				NGL (mmbbls)				Total (mmboe)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Proved
Developed Producing		—		—		—		—		—		—		—		—
Developed Non-producing		—		—		—		—		—		—		—		—
Undeveloped		—		—		167.2		108.8		7.2		3.6		35.0		21.7
Total Proved		—		—		167.2		108.8		7.2		3.6		35.0		21.7
Probable		—		—		39.4		21.0		1.7		0.6		8.2		4.1
Total Proved Plus Probable		—		—		206.6		129.8		8.8		4.1		43.3		25.8

Libya

	Light Crude Oil (mmbbls)				Medium Crude Oil (mmbbls)				Heavy Crude Oil (mmbbls)				Bitumen (mmbbls)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Proved
Developed Producing		—		—		—		—		—		—		—		—
Developed Non-producing		—		—		—		—		—		—		—		—
Undeveloped		—		—		—		—		—		—		—		—
Total Proved		—		—		—		—		—		—		—		—
Probable		0.1		0.1		—		—		—		—		—		—
Total Proved Plus Probable		0.1		0.1		—		—		—		—		—		—
	Coal Bed Methane (bcf)				Natural Gas (bcf)				NGL (mmbbls)				Total (mmboe)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Proved
Developed Producing		—		—		—		—		—		—		—		—
Developed Non-producing		—		—		—		—		—		—		—		—
Undeveloped		—		—		—		—		—		—		—		—
Total Proved		—		—		—		—		—		—		—		—
Probable		—		—		—		—		—		—		0.1		0.1
Total Proved Plus Probable		—		—		—		—		—		—		0.1		0.1

AIF 2012 Page 40 

Total

	Light Crude Oil (mmbbls)				Medium Crude Oil (mmbbls)				Heavy Crude Oil (mmbbls)				Bitumen (mmbbls)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Proved
Developed Producing		144.8		126.0		86.2		76.5		69.1		61.5		58.7		54.7
Developed Non-producing		3.3		3.3		1.8		1.6		14.6		13.5		—		—
Undeveloped		24.4		20.3		7.4		6.6		21.7		20.3		252.1		216.7
Total Proved		172.5		149.6		95.4		84.7		105.4		95.4		310.9		271.4
Probable		95.8		77.6		21.9		18.5		35.1		30.8		1,413.8		1,118.1
Total Proved Plus Probable		268.3		227.3		117.4		103.2		140.5		126.2		1,724.7		1,389.5
	Coal Bed Methane (bcf)				Natural Gas (bcf)				NGL (mmbbls)				Total (mmboe)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Proved
Developed Producing		22.1		20.7		1,586.3		1,396.6		64.0		49.6		690.9		604.6
Developed Non-producing		1.2		1.0		104.1		94.5		1.2		1.1		38.4		35.5
Undeveloped		—		—		793.2		732.4		24.8		19.5		462.7		405.4
Total Proved		23.3		21.8		2,483.5		2,223.5		89.9		70.2		1,192.0		1,045.5
Probable		5.9		5.6		752.4		681.5		30.3		23.9		1,723.3		1,383.4
Total Proved Plus Probable		29.2		27.3		3,236.0		2,905.0		120.3		94.0		2,915.3		2,428.9

AIF 2012 Page 41 

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

As at December 31, 2012

Forecast Prices and Costs

Canada

	Before Income Taxes and Discounted at (%/year)
($ millions)	5%		10%		15%		20%
Proved
Developed Producing		12,950		10,615		9,062		7,962
Developed Non-producing		878		700		586		505
Undeveloped		5,419		3,444		2,266		1,506
Total Proved		19,248		14,759		11,915		9,973
Probable		17,449		8,197		4,783		3,171
Total Proved Plus Probable		36,697		22,956		16,698		13,143

China

	Before Income Taxes and Discounted at (%/year)
($ millions)	5%		10%		15%		20%
Proved
Developed Producing		421		426		416		400
Developed Non-producing		—		—		—		—
Undeveloped		2,222		1,917		1,661		1,445
Total Proved		2,643		2,343		2,077		1,845
Probable		2,502		1,784		1,311		989
Total Proved Plus Probable		5,145		4,127		3,388		2,834

Indonesia

	Before Income Taxes and Discounted at (%/year)
($ millions)	5%		10%		15%		20%
Proved
Developed Producing		—		—		—		—
Developed Non-producing		—		—		—		—
Undeveloped		322		232		170		126
Total Proved		322		232		170		126
Probable		58		33		20		13
Total Proved Plus Probable		379		265		190		139

Libya

	Before Income Taxes and Discounted at (%/year)
($ millions)	5%		10%		15%		20%
Proved		—		—		—		—
Developed Producing		—		—		—		—
Developed Non-producing		—		—		—		—
Undeveloped		—		—		—		—
Total Proved		—		—		—		—
Probable		8		8		7		7
Total Proved Plus Probable		8		8		7		7

AIF 2012 Page 42 

Total

	Before Income Taxes and Discounted at (%/year)
($ millions)	5%		10%		15%		20%
Proved
Developed Producing		13,371		11,041		9,478		8,362
Developed Non-producing		878		700		586		505
Undeveloped		7,963		5,594		4,098		3,077
Total Proved		22,213		17,335		14,162		11,944
Probable		20,017		10,021		6,121		4,179
Total Proved Plus Probable		42,230		27,356		20,283		16,123

AIF 2012 Page 43 

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

As at December 31, 2012

Forecast Prices and Costs

Canada

	After Income Taxes and Discounted at (%/year)
($ millions)	5%		10%		15%		20%
Proved
Developed Producing		9,669		7,909		6,741		5,914
Developed Non-producing		646		512		426		365
Undeveloped		4,060		2,508		1,583		986
Total Proved		14,375		10,929		8,749		7,265
Probable		12,693		5,745		3,203		2,016
Total Proved Plus Probable		27,068		16,674		11,952		9,281

China

	After Income Taxes and Discounted at (%/year)
($ millions)	5%		10%		15%		20%
Proved
Developed Producing		270		277		273		263
Developed Non-producing		—		—		—		—
Undeveloped		1,852		1,590		1,369		1,182
Total Proved		2,122		1,867		1,641		1,445
Probable		2,084		1,477		1,078		808
Total Proved Plus Probable		4,206		3,344		2,720		2,253

Indonesia

	After Income Taxes and Discounted at (%/year)
($ millions)	5%		10%		15%		20%
Proved
Developed Producing		—		—		—		—
Developed Non-producing		—		—		—		—
Undeveloped		221		160		117		86
Total Proved		221		160		117		86
Probable		34		19		12		8
Total Proved Plus Probable		256		180		129		94

Libya

	After Income Taxes and Discounted at (%/year)
($ millions)	5%		10%		15%		20%
Proved
Developed Producing		—		—		—		—
Developed Non-producing		—		—		—		—
Undeveloped		—		—		—		—
Total Proved		—		—		—		—
Probable		8		8		7		7
Total Proved Plus Probable		8		8		7		7

AIF 2012 Page 44 

Total

	After Income Taxes and Discounted at (%/year)
($ millions)	5%		10%		15%		20%
Proved
Developed Producing		9,939		8,186		7,013		6,178
Developed Non-producing		646		512		426		365
Undeveloped		6,133		4,259		3,069		2,254
Total Proved		16,718		12,956		10,508		8,796
Probable		14,819		7,249		4,300		2,839
Total Proved Plus Probable		31,537		20,206		14,808		11,635

AIF 2012 Page 45 

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

As at December 31, 2012

Forecast Prices and Costs

($ millions)	Revenue		Royalties		Operating Costs		Development Costs(1)		Abandonment and Reclamation Costs(1)		Future Net Revenue Before Income Taxes		Income Taxes		Future Net Revenue After Income Taxes
Canada
Proved
Developed Producing		42,821		6,628		14,239		913		4,835		16,205		4,077		12,128
Developed Non-producing		2,179		246		575		144		—		1,215		316		899
Undeveloped		24,634		3,601		7,271		4,654		—		9,109		2,156		6,952
Total Proved		69,634		10,475		22,084		5,712		4,835		26,529		6,549		19,980
Probable		145,554		31,257		42,383		19,214		—		52,699		13,332		39,367
Total Proved Plus Probable		215,188		41,732		64,467		24,926		4,835		79,228		19,881		59,347
China
Proved
Developed Producing		753		—		122		8		244		379		145		234
Developed Non-producing		—		—		—		—		—		—		—		—
Undeveloped		4,201		—		653		964		—		2,584		421		2,163
Total Proved		4,953		—		775		972		244		2,963		566		2,397
Probable		4,035		—		397		9		—		3,629		590		3,039
Total Proved Plus Probable		8,988		—		1,171		982		244		6,592		1,156		5,435
Indonesia
Proved
Developed Producing		—		—		—		—		—		—		—		—
Developed Non-producing		—		—		—		—		—		—		—		—
Undeveloped		1,019		—		433		130		—		457		146		311
Total Proved		1,019		—		433		130		—		457		146		311
Probable		190		—		81		—		—		109		44		64
Total Proved Plus Probable		1,209		—		514		130		—		565		190		375
Libya
Proved
Developed Producing		—		—		—		—		—		—		—		—
Developed Non-producing		—		—		—		—		—		—		—		—
Undeveloped		—		—		—		—		—		—		—		—
Total Proved		—		—		—		—		—		—		—		—
Probable		14		—		3		2		—		9		—		9
Total Proved Plus Probable		14		—		3		2		—		9		—		9
Total
Proved
Developed Producing		43,574		6,628		14,360		922		5,079		16,584		4,222		12,362
Developed Non-producing		2,179		246		575		144		—		1,215		316		899
Undeveloped		29,854		3,601		8,356		5,748		—		12,149		2,723		9,426
Total Proved		75,607		10,475		23,291		6,814		5,079		29,948		7,261		22,687
Probable		149,792		31,257		42,864		19,225		—		56,446		13,967		42,479
Total Proved Plus Probable		225,399		41,732		66,155		26,039		5,079		86,393		21,227		65,166

⁽¹⁾  Abandonment and reclamation costs for undeveloped properties are included in development costs.

AIF 2012 Page 46 

Future Net Revenue by Production Group

As at December 31, 2012

Forecast Prices and Costs

	Future Net Revenue Before Income Taxes (discounted at 10%/year)
	Canada				China				Indonesia				Libya				Total
	($ millions)		($/boe)		($ millions)		($/boe)		($ millions)		($/boe)		($ millions)		($/boe)		($ millions)		($/boe)
Proved
Developed Producing
Light Crude Oil & NGL		4,137		29		426		70		—		—		—		—		4,563		30
Medium Crude Oil		1,463		19		—		—		—		—		—		—		1,463		19
Heavy Crude Oil		1,389		23		—		—		—		—		—		—		1,389		23
Natural Gas		2,130		8		—		—		—		—		—		—		2,130		8
Coal Bed Methane		21		6		—		—		—		—		—		—		21		6
Bitumen		1,474		27		—		—		—		—		—		—		1,474		27
Developed Non-producing
Light Crude Oil & NGL		64		19		—		—		—		—		—		—		64		19
Medium Crude Oil		45		29		—		—		—		—		—		—		45		29
Heavy Crude Oil		440		32		—		—		—		—		—		—		440		32
Natural Gas		150		9		—		—		—		—		—		—		150		9
Coal Bed Methane		1		5		—		—		—		—		—		—		1		5
Bitumen		—		—		—		—		—		—		—		—		—		—
Undeveloped
Light Crude Oil & NGL		516		25		—		—		—		—		—		—		516		19
Medium Crude Oil		115		17		—		—		—		—		—		—		115		17
Heavy Crude Oil		368		18		—		—		—		—		—		—		368		18
Natural Gas		486		7		1,917		43		232		11		—		—		2,636		20
Coal Bed Methane		—		—		—		—		—		—		—		—		—		—
Bitumen		1,959		9		—		—		—		—		—		—		1,959		9
Total Proved
Light Crude Oil & NGL		4,717		28		426		33		—		—		—		—		5,143		28
Medium Crude Oil		1,623		19		—		—		—		—		—		—		1,623		19
Heavy Crude Oil		2,197		23		—		—		—		—		—		—		2,197		23
Natural Gas		2,767		8		1,917		43		232		11		—		—		4,916		12
Coal Bed Methane		22		6		—		—		—		—		—		—		22		6
Bitumen		3,434		13		—		—		—		—		—		—		3,434		13
Probable
Light Crude Oil & NGL		2,484		29		90		14		—		—		8		66		2,582		28
Medium Crude Oil		515		28		—		—		—		—		—		—		515		28
Heavy Crude Oil		658		21		—		—		—		—		—		—		658		21
Natural Gas		493		6		1,694		42		33		8		—		—		2,219		18
Coal Bed Methane		2		3		—		—		—		—		—		—		2		3
Bitumen		4,044		4		—		—		—		—		—		—		4,044		4
Total Proved Plus Probable
Light Crude Oil & NGL		7,201		28		516		27		—		—		8		66		7,725		28
Medium Crude Oil		2,139		21		—		—		—		—		—		—		2,139		21
Heavy Crude Oil		2,855		23		—		—		—		—		—		—		2,855		23
Natural Gas		3,259		8		3,611		42		265		10		—		—		7,135		13
Coal Bed Methane		24		5		—		—		—		—		—		—		24		5
Bitumen		7,478		5		—		—		—		—		—		—		7,478		5

AIF 2012 Page 47 

Pricing Assumptions

The pricing assumptions disclosed in the table below were derived using the industry averages prescribed by McDaniel & Associates Consultants Ltd, Sproule Associates Limited, and GLJ Petroleum Consultants Ltd.

	Crude Oil				Natural Gas
	WTI (USD $/bbl)		Brent (USD $/ bbl)		NYMEX (USD $/ mmbtu)		NIT (Cdn $/GJ)		Inflation rates (1)		Exchange rates (2)
Historical
2008		99.65		96.99		9.04		7.70		—		0.937
2009		61.80		61.54		3.99		3.92		—		0.880
2010		79.46		79.42		4.39		3.91		—		0.971
2011		95.12		111.27		4.04		3.48		—		1.011
2012		94.21		111.54		2.79		2.28		—		1.001
Forecast
2013		90.71		106.31		3.72		3.15		1.833		1.000
2014		91.64		102.22		4.20		3.60		1.833		1.000
2015		92.30		100.49		4.61		3.98		1.833		1.000
2016		96.17		102.79		5.18		4.51		1.833		1.000
2017		97.29		102.25		5.62		4.92		1.833		1.000

⁽¹⁾  Inflation rates for forecasting prices and costs.

⁽²⁾  Exchange rate used to generate the benchmark reference prices.

AIF 2012 Page 48 

Reconciliation of Gross Proved Reserves

	Light Crude Oil & NGL (mmbbls)			Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Natural Gas (bcf)			Bitumen (mmbbls)			Total (mmboe)
Canada – Western Canada
End of 2011		169.9			89.6			112.7			2,252.6			308.5			1,056.2
Revisions – Technical		(1.7	)		8.1			3.2			14.1			1.1			13.1
Revisions – Economic		(1.2	)		—			(0.3	)		(136.8	)		—			(24.3	)
Purchases		0.1			—			0.4			—			—			0.5
Sales		—			(0.7	)		—			—			—			(0.7	)
Discoveries		1.0			0.1			—			5.6			—			2.0
Extensions		14.4			5.1			17.5			139.6			1.7			62.0
Improved Recovery		1.2			2.0			—			0.3			12.7			15.9
Production		(11.0	)		(8.8	)		(28.1	)		(202.8	)		(13.2	)		(94.9	)
End of 2012		172.7			95.4			105.4			2,072.6			310.9			1,029.9
Canada – Atlantic Region
End of 2011		76.3			—			—			—			—			76.3
Revisions – Technical		4.1			—			—			—			—			4.1
Revisions – Economic		—			—			—			—			—			—
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		—			—			—			—			—			—
Extensions		—			—			—			—			—			—
Improved Recovery		—			—			—			—			—			—
Production		(12.4	)		—			—			—			—			(12.4	)
End of 2012		68.1			—			—			—			—			68.1
China
End of 2011		4.9			—			—			—			—			4.9
Revisions – Technical		5.1			—			—			—			—			5.1
Revisions – Economic		—			—			—			—			—			—
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		6.6			—			—			267.1			—			51.1
Extensions		1.0			—			—			—			—			1.0
Improved Recovery		—			—			—			—			—			—
Production		(3.1	)		—			—			—			—			(3.1	)
End of 2012		14.5			—			—			267.1			—			59.0
Indonesia
End of 2011		7.2			—			—			167.2			—			35.0
Revisions – Technical		—			—			—			—			—			—
Revisions – Economic		—			—			—			—			—			—
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		—			—			—			—			—			—
Extensions		—			—			—			—			—			—
Improved Recovery		—			—			—			—			—			—
Production		—			—			—			—			—			—
End of 2012		7.2			—			—			167.2			—			35.0

AIF 2012 Page 49 

	Light Crude Oil & NGL (mmbbls)			Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Natural Gas (bcf)			Bitumen (mmbbls)			Total Company (mmboe)
Total
End of 2011		258.2			89.6			112.7			2,419.8			308.5			1,172.4
Revisions – Technical		7.6			8.1			3.2			14.1			1.1			22.3
Revisions – Economic		(1.2	)		—			(0.3	)		(136.8	)		—			(24.3	)
Purchases		0.1			—			0.4			—			—			0.5
Sales		—			(0.7	)		—			—			—			(0.7	)
Discoveries		7.5			0.1			—			272.7			—			53.1
Extensions		15.5			5.1			17.5			139.6			1.7			63.0
Improved Recovery		1.2			2.0			—			0.3			12.7			15.9
Production		(26.5	)		(8.8	)		(28.1	)		(202.8	)		(13.2	)		(110.4	)
End of 2012		262.5			95.4			105.4			2,506.8			310.9			1,192.0

Major additions to proved reserves in 2012 include:

• the initial booking of the Liwan 3-1 deep water project after government approval that resulted in an addition of 51 mmboe of natural gas and NGL in proved undeveloped reserves;

• the improved recovery and expansion at some heavy oil thermal projects that resulted in the booking of an additional 13 mmboe in proved reserves; and

• the extension through additional drilling locations at liquids-rich Ansell in the Alberta Deep Basin area that resulted in the booking of an additional 27 mmboe of natural gas and NGL in proved reserves.

AIF 2012 Page 50 

Reconciliation of Gross Probable Reserves

	Light Crude Oil & NGL (mmbbls)			Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Natural Gas (bcf)			Bitumen (mmbbls)			Total (mmboe)
Canada – Western Canada
End of 2011		50.6			19.2			37.9			561.1			1,400.7			1,601.9
Revisions – Technical		0.5			2.8			(2.6	)		(46.0	)		2.8			(4.2	)
Revisions – Economic		(0.1	)		—			(0.1	)		(80.4	)		—			(13.6	)
Revisions – Transfer to Proved		(3.1	)		(1.0	)		(4.9	)		(23.0	)		(3.2	)		(16.1	)
Purchases		—			—			—			—			—			—
Sales		—			(0.1	)		—			—			—			(0.1	)
Discoveries		0.9			—			—			3.3			—			1.4
Extensions		7.0			0.8			4.9			59.4			1.6			24.1
Improved Recovery		—			0.3			—			—			11.9			12.2
Production		—			—			—			—			—			—
End of 2012		55.8			21.9			35.1			474.4			1,413.8			1,605.6
Canada – Atlantic Region
End of 2011		65.0			—			—			—			—			65.0
Revisions – Technical		(0.7	)		—			—			—			—			(0.7	)
Revisions – Economic		—			—			—			—			—			—
Revisions – Transfer to Proved		(2.6	)		—			—			—			—			(2.6	)
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		—			—			—			—			—			—
Extensions		—			—			—			—			—			—
Improved Recovery		—			—			—			—			—			—
Production		—			—			—			—			—			—
End of 2012		61.7			—			—			—			—			61.7
China
End of 2011		3.2			—			—			—			—			3.2
Revisions – Technical		(0.4	)		—			—			—			—			(0.4	)
Revisions – Economic		—			—			—			—			—			—
Revisions – Transfer to Proved		(1.4	)		—			—			—			—			(1.4	)
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		5.5			—			—			244.5			—			46.3
Extensions		—			—			—			—			—			—
Improved Recovery		—			—			—			—			—			—
Production		—			—			—			—			—			—
End of 2012		6.9			—			—			244.5			—			47.7
Indonesia
End of 2011		1.7			—			—			39.4			—			8.2
Revisions – Technical		—			—			—			—			—			—
Revisions – Economic		—			—			—			—			—			—
Revisions – Transfer to Proved		—			—			—			—			—			—
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		—			—			—			—			—			—
Extension		—			—			—			—			—			—
Improved Recovery		—			—			—			—			—			—
Production		—			—			—			—			—			—
End of 2012		1.7			—			—			39.4			—			8.2

AIF 2012 Page 51 

	Light Crude Oil & NGL (mmbbls)			Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Natural Gas (bcf)			Bitumen (mmbbls)			Total (mmboe)
Libya
End of 2011		—			—			—			—			—			—
Revisions – Technical		0.1			—			—			—			—			0.1
Revisions – Economic		—			—			—			—			—			—
Revisions – Transfer to Proved		—			—			—			—			—			—
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		—			—			—			—			—			—
Extension		—			—			—			—			—			—
Improved Recovery		—			—			—			—			—			—
Production		—			—			—			—			—			—
End of 2012		0.1			—			—			—			—			0.1
	Light Crude Oil & NGL (mmbbls)			Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Natural Gas (bcf)			Bitumen (mmbbls)			Total Company (mmboe)
Total
End of 2011		120.5			19.2			37.9			600.5			1,400.7			1,678.4
Revisions – Technical		(0.5	)		2.8			(2.6	)		(46.0	)		2.8			(5.3	)
Revisions – Economic		(0.1	)		—			(0.1	)		(80.4	)		—			(13.6	)
Revisions – Transfer to Proved		(7.1	)		(1.0	)		(4.9	)		(23.0	)		(3.2	)		(20.1	)
Purchases		—			—			—			—			—			—
Sales		—			(0.1	)		—			—			—			(0.1	)
Discoveries		6.4			—			—			247.8			—			47.7
Extension		7.0			0.8			4.9			59.4			1.6			24.1
Improved Recovery		—			0.3			—			—			11.9			12.2
Production		—			—			—			—			—			—
End of 2012		126.1			21.9			35.1			758.3			1,413.8			1,723.3

Major changes to probable reserves in 2012 include:

• the initial booking of the Liwan 3-1 deep water project after government approval that resulted in an addition of 46 mmboe of natural gas and NGL in probable undeveloped reserves;

• the improved recovery and expansion at some heavy oil thermal projects that resulted in the booking of an additional 12 mmboe in probable reserves; and

• the extension through additional drilling locations at liquids-rich Ansell in the Alberta Deep Basin area that resulted in the booking of an additional 9 mmboe of natural gas and NGL in probable reserves.

AIF 2012 Page 52 

Reconciliation of Gross Proved Plus Probable Reserves

	Light Crude Oil & NGL (mmbbls)			Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Natural Gas (bcf)			Bitumen (mmbbls)			Total (mmboe)
Canada – Western Canada
End of 2011		220.5			108.8			150.6			2,813.7			1,709.3			2,658.1
Revisions – Technical		(1.1	)		10.9			0.5			(31.9	)		3.9			8.8
Revisions – Economic		(1.3	)		—			(0.4	)		(217.2	)		—			(37.9	)
Revisions – Transfer to Proved		(3.1	)		(1.0	)		(4.9	)		(23.0	)		(3.2	)		(16.1	)
Purchases		0.1			—			0.4			—			—			0.5
Sales		—			(0.8	)		—			—			—			(0.8	)
Discoveries		1.8			0.1			—			8.9			—			3.4
Extensions		21.5			5.9			22.4			198.9			3.3			86.1
Improved Recovery		1.2			2.3			—			0.3			24.6			28.1
Production		(11.0	)		(8.8	)		(28.1	)		(202.8	)		(13.2	)		(94.9	)
End of 2012		228.5			117.4			140.5			2,546.9			1,724.7			2,635.5
Canada – Atlantic Region
End of 2011		141.3			—			—			—			—			141.3
Revisions – Technical		3.4			—			—			—			—			3.4
Revisions – Economic		—			—			—			—			—			—
Revisions – Transfer to Proved		(2.6	)		—			—			—			—			(2.6	)
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		—			—			—			—			—			—
Extensions		—			—			—			—			—			—
Improved Recovery		—			—			—			—			—			—
Production		(12.4	)		—			—			—			—			(12.4	)
End of 2012		129.7			—			—			—			—			129.7
China
End of 2011		8.0			—			—			—			—			8.0
Revisions – Technical		4.7			—			—			—			—			4.7
Revisions – Economic		—			—			—			—			—			—
Revisions – Transfer to Proved		(1.4	)		—			—			—			—			(1.4	)
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		12.1			—			—			511.6			—			97.4
Extensions		1.0			—			—			—			—			1.0
Improved Recovery		—			—			—			—			—			—
Production		(3.1	)		—			—			—			—			(3.1	)
End of 2012		21.5			—			—			511.6			—			106.7
Indonesia
End of 2011		8.8			—			—			206.6			—			43.3
Revisions – Technical		—			—			—			—			—			—
Revisions – Economic		—			—			—			—			—			—
Revisions – Transfer to Proved		—			—			—			—			—			—
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		—			—			—			—			—			—
Extensions		—			—			—			—			—			—
Improved Recovery		—			—			—			—			—			—
Production		—			—			—			—			—			—
End of 2012		8.8			—			—			206.6			—			43.3

AIF 2012 Page 53 

	Light Crude Oil & NGL (mmbbls)			Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Natural Gas (bcf)			Bitumen (mmbbls)			Total (mmboe)
Libya
End of 2011		—			—			—			—			—			—
Revisions – Technical		0.1			—			—			—			—			0.1
Revisions – Economic		—			—			—			—			—			—
Revisions – Transfer to Proved		—			—			—			—			—			—
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		—			—			—			—			—			—
Extensions		—			—			—			—			—			—
Improved Recovery		—			—			—			—			—			—
Production		—			—			—			—			—			—
End of 2012		0.1			—			—			—			—			0.1
	Light Crude Oil & NGL (mmbbls)			Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Natural Gas (bcf)			Bitumen (mmbbls)			Total Company (mmboe)
Total
End of 2011		378.7			108.8			150.6			3,020.3			1,709.3			2,850.8
Revisions – Technical		7.1			10.9			0.5			(31.9	)		3.9			17.1
Revisions – Economic		(1.3	)		—			(0.4	)		(217.2	)		—			(37.9	)
Revisions – Transfer to Proved		(7.1	)		(1.0	)		(4.9	)		(23.0	)		(3.2	)		(20.1	)
Purchases		0.1			—			0.4			—			—			0.5
Sales		—			(0.8	)		—			—			—			(0.8	)
Discoveries		13.9			0.1			—			520.5			—			100.8
Extensions		22.5			5.9			22.4			198.9			3.3			87.1
Improved Recovery		1.2			2.3			—			0.3			24.6			28.1
Production		(26.5	)		(8.8	)		(28.1	)		(202.8	)		(13.2	)		(110.4	)
End of 2012		388.6			117.4			140.5			3,265.1			1,724.7			2,915.3

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.

Husky funds capital programs by cash generated from operating activities, cash on hand, equity issuances, and short-term and long-term debt. Decisions to develop proved undeveloped and probable undeveloped reserves are based on various factors including economic conditions, technical performance and size of the development program. Approximately 39% of Husky’s gross proved undeveloped reserves are assigned to the Sunrise Energy Project. This project is under development with first production expected in 2014. Approximately 12% of Husky’s gross proved undeveloped reserves are assigned to the natural gas liquids-rich Ansell area. This project has ongoing drilling with the recent acquisition of gas plant capacity. Approximately 11% of Husky’s gross proved undeveloped reserves are assigned to the first booking of the Liwan 3-1 deep water project. This project is under development with first production expected in late 2013/early 2014.

As at December 31, 2012, there were no material proved undeveloped reserves that have remained undeveloped for greater than five years.

AIF 2012 Page 54 

Proved Undeveloped Reserves

First attributed	Light Crude Oil & NGL (mmbbls)		Medium Crude Oil (mmbbls)		Heavy Crude Oil (mmbbls)		Bitumen (mmbbls)		Natural Gas (bcf)		Total Oil & NGL (mmbbls)
Year
Prior		55.0		9.6		47.7		137.8		526.0		250.1
2010		17.1		4.7		7.5		65.6		294.1		94.8
2011		7.0		6.0		10.1		68.8		33.8		91.9
2012		16.6		3.7		8.1		12.3		399.4		40.7

Probable Undeveloped Reserves

First attributed	Light Crude Oil & NGL (mmbbls)		Medium Crude Oil (mmbbls)		Heavy Crude Oil (mmbbls)		Bitumen (mmbbls)		Natural Gas (bcf)		Total Oil & NGL (mmbbls)
Year
Prior		132.2		7.9		41.0		1,795.1		262.7		1,976.2
2010		7.1		3.8		8.7		2.8		47.0		22.4
2011		6.3		1.9		12.5		362.2		21.2		382.9
2012		11.5		0.7		5.9		12.3		299.0		30.4

Future Development Costs

Forecast Prices and Costs

The Company expects to fund its future development costs by cash generated from operating activities, cash on hand, and short-term and long-term debt. The Company also has access to available amounts through credit facilities on which it can draw funds and the ability to issue 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.

	Canada				China				Indonesia				Libya
Year	Proved Reserves ($  millions)		Proved Plus Probable Reserves ($ millions)		Proved Reserves ($  millions)		Proved Plus Probable Reserves ($ millions)		Proved Reserves ($  millions)		Proved Plus Probable Reserves ($ millions)		Proved Reserves ($  millions)		Proved Plus Probable Reserves ($ millions)
2013		1,722		2,341		819		828		74		74				1
2014		1,099		1,661		—		—		56		56		—		1
2015		796		1,530		—		—		—		—		—		1
2016		358		1,297		15		15		—		—		—		—
2017		509		1,678		222		222		—		—		—		—
Remaining		6,063		21,253		160		160		—		—		—		—
Total		10,547		29,761		1,216		1,225		130		130		—		2

	Total ($ millions)
Year	Proved Reserves		Proved Plus Probable Reserves
2013		2,615		3,243
2014		1,155		1,718
2015		796		1,531
2016		373		1,313
2017		732		1,901
Remaining		6,223		21,413
Total		11,893		31,118

AIF 2012 Page 55 

Additional Information Concerning Abandonment and Reclamation Costs

The Company estimates the costs associated with abandonment and reclamation costs for surface leases, wells, facilities, and pipelines through its previous experience, where available, or by estimating such costs. With respect to abandonment and reclamation costs for surface leases, wells, facilities, and pipelines, the Company expects to incur these costs on approximately 29,750 net wells for a total undiscounted amount of $5.1 billion. Discounted at 10% per year, the total abandonment costs, net of estimated salvage value, for wells is $1.2 billion. This amount was deducted in estimating the future net revenue. Of the undiscounted portion of the total abandonment and reclamation costs, $187 million is expected to be paid in the next three years.

Production Estimates

Yearly Production Estimates for 2013

	Light Crude Oil (mmbbls)		Medium Crude Oil (mmbbls)		Heavy Crude Oil (mmbbls)		Bitumen (mmbbls)		Natural Gas (bcf)
Canada
Total Gross Proved		24.2		9.1		25.2		12.7		171.7
Total Gross Probable		5.5		0.4		2.0		0.3		9.7
Total Gross Proved plus Probable		29.7		9.4		27.2		12.9		181.4
International
Total Gross Proved		2.8		—		—		—		4.9
Total Gross Probable		0.2		—		—		—		—
Total Gross Proved plus Probable		3.0		—		—		—		4.9
Total
Total Gross Proved		27.0		9.1		25.2		12.7		176.6
Total Gross Probable		5.7		0.4		2.0		0.3		9.7
Total Gross Proved plus Probable		32.7		9.4		27.2		12.9		186.3

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

AIF 2012 Page 56 

Infrastructure and Marketing

During the first quarter of 2012, the Company completed an evaluation of activities of the Company’s former Midstream segment as a service provider to the Upstream or Downstream operations. As a result, and consistent with the Company’s strategic view of its integrated business, the previously reported Midstream segment activities are now aligned and reported within the Company’s core exploration and production, Upstream Infrastructure and Marketing, or in its upgrading and refining businesses. The Company believes this change in segment presentation allows management and third parties to more effectively assess the Company’s performance.

The Infrastructure and Marketing business is comprised of the marketing of the Company’s and other producers’ crude oil, natural gas, NGL, sulphur and petroleum coke, pipeline transportation and blending of crude oil and natural gas and storage of crude oil, diluent and natural gas.

Infrastructure

Husky has been involved in the gathering, transporting and storage of heavy crude oil in the Lloydminster area since the early 1960s. Husky’s crude oil pipeline systems include more than 2,000 kilometers of pipeline and are capable of transporting up to 710 mbbls/day of blended heavy crude oil, diluent and synthetic crude oil, assuming the systems are fully powered. 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 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: Enbridge Pipeline multi-line system, Kinder Morgan Express Pipeline, TransCanada’s Keystone Pipeline and the smaller IPF Pipeline. The blended crude oil is transported to eastern and southern markets on these pipelines. Husky’s crude oil pipeline systems also have feeder pipeline interconnections with the IPF Pipeline at Cold Lake, the Echo Pipeline at Hardisty, the Gibsons Hardisty Terminal, the Enbridge Hardisty Caverns and Merchant Terminal, the Enbridge Athabasca Pipeline and the Talisman Chauvin Pipeline.

The following table shows the average daily pipeline throughput for the periods indicated:

	Years ended December 31,
(mbbls/day)	2012		2011		2010
Combined Pipeline Throughput		581		559		512

⁽¹⁾  Throughput includes the Husky internal and third- party volumes

In recent years Husky has incurred a number of expansions on its pipeline system and Hardisty terminal facilities to capitalize on anticipated increases in heavy oil production from the Lloydminster and Cold Lake areas and to service the new incremental take-away capacity from the Keystone Pipeline. In May 2012, a new 300,000 barrel tank at the Hardisty terminal was placed in service which facilitates moving crude oil volumes to the U.S. Petroleum Administration for Defense Districts (“PADD”) II and PADD III markets.

Husky’s heavy crude oil processing facilities are located throughout the Lloydminster area and are connected to Husky’s pipeline system. These facilities process Husky’s and other producers’ raw heavy crude oil from the field production by removing sand, water and other impurities to produce clean dry heavy crude oil. There are also third-party processing facilities connected to Husky’s pipeline. The heavy crude oil is blended with a diluent to reduce both viscosity and density in order to meet pipeline specifications for transportation.

AIF 2012 Page 57 

In 2010, Husky 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 corporate initiative, agreed upon in 2006, to expand the market for Husky’s crude oil into the midwest United States. This initiative was further supported through the acquisition of the Lima Refinery in 2007, which now enables Husky’s Canadian synthetic crude oil production (along with additional third-party purchases) to be processed at the refinery.

Due to Husky’s ongoing Keystone pipeline commitment, the Lima Refinery now has the option, depending on the economics, to access a significant amount of Canadian crude oil as part of its crude feedstock requirements.

Keystone Pipeline has also enabled Husky to sell heavy crude supply on the Gulf Coast, through interconnecting pipeline systems. This provides the benefits of diversifying Husky’s commodity markets and improving the Company’s Upstream production netback.

The Canadian pipeline system in 2012 was subject to significant apportionment, affecting both Canadian export volumes and the crude prices in Western Canada. Through the reliability of Husky’s proprietary pipeline system, the capability of the Hardisty terminal and Husky’s commitment on the Keystone pipeline, Husky was able to avoid any production shut ins, ensure sufficient storage for any apportioned volumes and access the US market through our committed flow on the Keystone pipeline.

AIF 2012 Page 58 

Results from Husky’s third party pipeline and infrastructure businesses are included in Upstream Infrastructure and Marketing and results associated with Husky internal production volumes are included in Upstream Exploration and Production.

Cogeneration

The Company holds a 50% interest in a 90 MW natural gas fired cogeneration facility adjacent to Husky’s Rainbow Lake processing plant. The cogeneration facility produces electricity for the Power Pool of Alberta and thermal energy (steam) for the Rainbow Lake processing plant. It provides power directly to the Power Pool of Alberta under an agreement with the Alberta Electric System Operator to provide additional electricity generating capacity and system stability for northwestern Alberta. The power plant has the capability of being expanded to approximately 110 MW in total. ATCO Power is the operator of the facility and a hands-on operator of the Rainbow #5 electricity generator. Husky contract-operates the Rainbow #4 electricity generator, the Once-Through Steam Generator and the Water Treatment Plant. All of this equipment constitutes part of the cogeneration facility. Results from this joint venture are included in Upstream Exploration and Production.

Effective January 1, 2011, Husky sold its 50% interest in a 215 MW natural gas fired cogeneration facility at the site of the Lloydminster Upgrader.

Natural Gas Storage Facilities

Husky has been operating a natural gas storage facility at Hussar, Alberta since April 2000. Husky also operates and has a 50% interest in a natural gas storage facility at East Cantuar near Swift Current, Saskatchewan. Husky also contracts additional natural gas storage under long-term arrangements. At December 31, 2012, Husky managed a total natural gas storage capacity of approximately 45.5 bcf. The Company is continuing to evaluate additional storage opportunities within Western Canada. Results from Husky’s natural gas storage business are included in Upstream Infrastructure and Marketing.

Commodity Marketing

Husky 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 Lloydminster Upgrader.

AIF 2012 Page 59 

Husky supplies feedstock to its Lloydminster Upgrader and asphalt refinery from its own and third-party heavy oil production sourced from the Lloydminster and Cold Lake areas. The Company also sells blended heavy crude oil directly to refiners based in the United States and Canada. Husky’s extensive infrastructure in the Lloydminster area supports its heavy crude oil refining and marketing operations.

Husky markets light and medium crude oil and NGL sourced from Husky’s own production and third-party production. Light crude oil is acquired for processing by third-party refiners at Edmonton, Alberta and by Husky’s refinery at Prince George, British Columbia. Husky markets the synthetic crude oil produced at its Upgrader in Lloydminster to refiners in Canada and the United States.

Husky 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 forecast to be deliverable from Husky’s reserves. The natural gas sales contracted are primarily at market prices. At December 31, 2012, Husky’s long-term fixed price natural gas sales contracts totaled 26.6 bcf over three years deliverable at the rate of 43% in 2013, 43% in 2014 and 14% in 2015. Husky has acquired rights to firm pipeline capacity to transport the natural gas to most of these contracted markets. The Company manages and trades natural gas in conjunction with Husky owned and operated natural gas storage facilities.

Husky has developed its commodity marketing operations to include the acquisition of third-party volumes in order to increase volumes and enhance the value of its midstream assets. The Company plans to expand its marketing operations by continuing to increase marketing activities. The Company believes that this increase will generate synergies with the marketing of its own production volumes and the optimization of its assets. Results from Husky’s commodity marketing business are included in Upstream Infrastructure and Marketing.

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Downstream Operations

U.S. Refining and Marketing

Lima, Ohio Refinery

The Lima Refinery, located in Ohio between Toledo and Dayton, has an atmospheric crude throughput capacity of 160 mbbls per stream day. The refinery currently processes both light sweet crude oil feedstock sourced from the United States and Africa and since 2010, with the commissioning of the Keystone Pipeline system, Canadian synthetic crudes, including Husky Synthetic Blend (“HSB”) produced by the Lloydminster Upgrader. The refinery produces gasoline, gasoline blend stocks, diesel, jet fuel, petrochemical feedstock and other by-products. The feedstock is received via the Mid-Valley and Marathon Pipelines and the refined products are transported via the Buckeye and Inland pipeline systems and by rail car to primary markets in Ohio, Illinois, Indiana and southern Michigan.

During 2012, crude oil feedstock throughput at the Lima Refinery averaged 150 mbbls/day. Production of gasoline averaged 77 mbbls/day, total distillates averaged 56 mbbls/day and total butanes averaged 17 mbbls/day.

In 2012, ordering of equipment and site construction commenced on a 20 mbbls/day kerosene hydrotreater which is planned to increase jet fuel production. The kerosene hydrotreater is approximately 80% complete and is expected to be operational in the first quarter of 2013.

The Lima Refinery is scheduled to complete a major turnaround in 2014 on 70% of its operating units and is expected to be shut down for 45 days during this turnaround. The remaining 30% of operating units are scheduled to be addressed in a major turnaround currently planned for 2015. Husky continues to implement short-term reliability and profitability improvement projects.

BP-Husky Toledo, Ohio Refinery

The BP-Husky Toledo Refinery, in which Husky holds a 50% interest, has an atmospheric crude throughput capacity of 160 mbbls per stream day. Products include low sulphur gasoline, ultra low sulphur diesel, aviation fuels, propane, kerosene and asphalt. The refinery is located in one of the highest energy consumption regions in the United States.

Husky, together with its partner BP, plan to expand the refinery’s bitumen processing capacity to align with the first two 60 mbbls/day phases of the Sunrise Energy Project SAGD development. BP currently markets 100% of the refinery’s output; however, once Sunrise Phase I reaches design production rates, Husky will have the right to market its own share of the refined products.

In 2010, Husky and BP announced the sanction of the Continuous Catalyst Regeneration Reformer Project at the BP-Husky Toledo Refinery. This project is expected to improve the efficiency and competitiveness of the refinery by reducing energy consumption and lowering operating costs with the replacement of two naphtha reformers and one hydrogen plant with a 42,000 bbls/day continuous catalyst regeneration reformer system plant. Project construction formally commenced in August 2010. Mechanical completion was achieved in the fourth quarter of 2012 with startup expected in the first quarter of 2013.

During the year ended December 31, 2012, crude oil feedstock throughput averaged 61 mbbls/day (Husky’s share). Production of gasoline averaged 38 mbbls/day, middle distillates averaged 17 mbbls/day and other fuel and feedstock averaged 9 mbbls/day.

Upgrading Operations

Husky owns and operates the Husky Lloydminster Upgrader, a heavy oil upgrading facility located in Lloydminster, Saskatchewan. The Upgrader is designed to process blended heavy crude oil feedstock into high quality, low sulphur synthetic crude oil. Synthetic crude oil is used as refinery feedstock for the production of premium transportation fuels in Canada and the United States. In addition, the Upgrader recovers the diluent, which is blended with the heavy crude oil prior to pipeline transportation to reduce viscosity and facilitate its movement, and returns it to the field to be reused.

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The Upgrader was commissioned in 1992 with an original design capacity of 46 mbbls/day of synthetic crude oil. Current production is considerably higher than the original design rate capacity as a result of throughput modifications and improved reliability. In 2007, the Upgrader commenced production of off-road diesel for locomotive and other uses. The Upgrader’s current rated production capacity is 82 mbbls/day of synthetic crude oil, diluents, low sulphur diesel and ultra low sulphur diesel.

Production at the Upgrader averaged 61 mbbls/day of synthetic crude oil, 13 mbbls/day of diluent and 4 mbbls/day of low sulphur diesel in 2012. In addition, the Upgrader also produced, as by-products of its upgrading operations, approximately 361 lt/day of sulphur and 1,023 lt/day of petroleum coke during 2012. These products are sold in Canadian and international markets.

Canadian Refined Products

Husky’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 acquisition by purchase and exchange of refined petroleum products. Husky’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 Husky refinery at Prince George, British Columbia and are also acquired from third-party refiners and marketed through Husky and Mohawk branded retail and commercial petroleum outlets and through direct marketing to third-party dealers and end users. Asphalt and residual products are produced at Husky’s asphalt refinery at Lloydminster, Alberta and are marketed directly or through Husky’s eight emulsion plants, five of which are also asphalt terminals located throughout Western Canada.

Prince George Refinery

Husky’s light oil refinery in Prince George, British Columbia, meets the refined products marketing needs of Husky and third-party retail outlets in the central and northern regions of the province. Feedstock is delivered to the refinery by pipeline from northeastern British Columbia. Prince George Refinery production is equal to approximately 18% of Husky’s total refined product supply requirements.

The refinery produces all grades of unleaded gasoline, seasonal diesel fuels, mixed propane and butane, and heavy fuel oil. It markets road asphalt, shipped by rail from Husky’s Lloydminster, Alberta, asphalt refinery. In 2012, refinery throughput averaged 11.1 mbbls/day.

The refinery uses two types of desulphurization technologies. For clean gasoline (low sulphur gasoline), the refinery uses Prime G+ hydrodesulphurization technology. For clean diesel (ultra low sulphur diesel), the refinery increased the capacity of its existing unifier and reformer units, and increased the hydrogen supply through installation of a new steam methane reformer.

Lloydminster Asphalt Refinery

Husky’s Lloydminster Asphalt Refinery processes heavy crude oil into asphalt products used in road construction and maintenance and industrial asphalt products. The refinery has a throughput capacity of 29 mbbls/day of heavy crude oil. The refinery also produces straight run gasoline, bulk distillates and residuals. The straight run gasoline stream is removed and re-circulated into the heavy oil pipeline network as pipeline diluent and the distillate stream is used by the Upgrader to make low sulphur diesel. The bulk distillates are hydrogen deficient and are transferred directly to the Upgrader and then treated for blending into the HSB stream. Residuals are a blend of medium and light distillate and gas oil streams, which are sold directly to customers typically as drilling and well fracturing fluids or used in asphalt cutbacks and emulsions.

Refinery throughput averaged 28.3 mbbls/day of blended heavy crude oil feedstock during 2012. In 2012, daily sales volumes of asphalt averaged 15.7 mbbls/day and daily sales volumes of residual and other products averaged 10.5 mbbls/day. Due to the seasonal demand for asphalt products, most Canadian asphalt refineries typically operate at full capacity only during the normal paving season in Canada and the northern United States. Husky has implemented various plans to increase refinery throughput during the other months of the year, such as increasing storage capacity and developing U.S. markets for asphalt products. This is intended to allow Husky to run at or near full capacity year round.

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Asphalt Distribution Network

Husky’s Pounder Emulsions division has a significant market share in Western Canada for road application emulsion products. Additional non-asphalt based road maintenance products are also marketed and distributed through Pounder Emulsions. The Company’s sales to the U.S. and eastern Canada accounted for 60% of asphalt sales in 2012. Exported asphalt products are shipped as far as Texas and New York in the U.S. and Quebec, Canada. Husky typically sells in excess of 5.5 mmbbls of asphalt cement each year. All of Husky’s asphalt requirements are supplied by Husky’s asphalt refinery.

Husky’s asphalt distribution network consists of emulsion plants and asphalt terminals located at Kamloops, British Columbia, Edmonton and Lethbridge, Alberta, Yorkton, Saskatchewan and Winnipeg, Manitoba and three emulsion plants located at Watson Lake, Yukon and Lloydminster and Saskatoon, Saskatchewan. Husky also terminals asphalt at its Prince George Refinery and uses an independently operated terminal at Langley, British Columbia. In 2012, the sales volume of asphalt products was 26.2 mbbls/day.

In 2013, Husky plans to direct its efforts to increasing terminal capacity at the Yorkton and Edmonton facilities, develop retail capacity in U.S. markets, expand sales of road stabilization, preservation and recycling products, increase sales of drilling and completion products, implement safety and reliability improvements and develop new products, markets and specifications.

Ethanol Plants

In September 2006, Husky commissioned an ethanol plant in Lloydminster, Saskatchewan. This 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; the plant is operating above that capacity. In 2012, ethanol production averaged 721,200 litres/day.

Husky’s ethanol production supports its ethanol-blended gasoline marketing program. When added to gasoline, ethanol promotes more complete fuel combustion, prevents fuel line freezing and reduces carbon monoxide emissions, ozone precursors and net emissions of greenhouse gases. Environment Canada has designated ethanol blended gasoline as an “Environmental Choice” product. Husky sells a large portion of its production to other major oil companies for their ethanol blending requirements in Western Canada.

During 2012, the Lloydminster plant commissioned a CO₂ capture facility. The plant is currently capturing CO₂ for use in Husky’s heavy oil reservoir enhancement project.

Husky continued to position its refined products business segment as the leader in ethanol blended fuels in Western Canada.

Other Supply Arrangements

In addition to the refined petroleum products supplied by the Prince George Refinery of 2.7 mbbls/day and by the Husky Lloydminster Upgrader of 3.9 mbbls/day, Husky has rack-based pricing purchase agreements for refined products with all major Canadian refiners. During 2012, Husky purchased approximately 40.0 mbbls/day of refined petroleum products from refiners and acquired approximately 8.7 mbbls/day of refined petroleum products pursuant to exchange agreements with third-party refiners.

Branded Petroleum Product Outlets and Commercial Distribution

As of December 31, 2012, there were 512 independently operated Husky and Mohawk branded petroleum product outlets. These petroleum product outlets include travel centres, convenience stores, cardlock operations and bulk distribution facilities located from the Ontario/Quebec border to the West Coast. The travel centre network is strategically located on major highways and serves the retail market and commercial transporters with quality products and full-service Husky House restaurants. At most locations, the travel centre network also features the proprietary “Route Commander” cardlock system that enables commercial users to purchase products using a card system that electronically processes transactions and provides detailed billing, sales tax and other information. A variety of full and self-serve retail locations under the Husky and Mohawk brand names serve urban and rural markets, while Husky and Mohawk bulk distributors offer direct sales to commercial and farm markets in Western Canada.

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Independent retailers or agents operate all Husky and Mohawk branded petroleum product outlets. Retail outlets feature varying services such as convenience stores, service bays, 24-hour service, car washes, Husky House full-service, family-style restaurants, proprietary and co-branded quick serve restaurants and bank machines. In addition to ethanol-blended gasoline, Husky offers additive-enhanced DieselMax and propane services together with Chevron lubricants. Husky 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. Husky’s brands are promoted through Husky’s sponsorship of Alpine Canada, the Western Hockey League and various university athletics, as well as advertising designed to reach both national and regional audiences.

The following table shows the number of Husky and Mohawk branded petroleum outlets by province as of December 31, 2012:

	British Columbia & Yukon		Alberta		Sask.		Manitoba		Ontario		2012 Total		2011 Total
Branded Petroleum Outlets
Retail Owned Outlets		54		67		13		16		77		227		247
Leased		37		43		5		11		38		134		149
Independent Retailers		51		68		13		6		13		151		153
Total		142		178		31		33		128		512		549
Cardlocks (1)		23		31		5		6		19		84		88
Convenience Stores (1)		86		98		17		25		115		341		140
Restaurants		10		12		4		2		14		42		47

⁽¹⁾  Located at branded petroleum outlets.

Husky also markets refined petroleum products directly to various commercial markets, including independent dealers, national rail companies and major industrial and commercial customers in Western Canada and the northwestern United States. In 2012, daily sales volumes of gasoline, diesel fuel and liquefied petroleum gas were 26.2 mbbls/day, 27.2 mbbls/day, and 0.8 mbbls/day, respectively.

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

	Years ended December 31,
(mbbls/day)	2012		2011		2010
Gasoline		26.2		27.7		24.9
Diesel fuel		27.2		26.0		25.7
Liquefied Petroleum Gas		0.8		0.6		0.7
		54.2		54.3		51.3

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INDUSTRY OVERVIEW

The operations of the oil and gas industry are governed by a considerable 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 have the most significant impact on the short and long-term operations of the oil and gas industry.

Crude Oil and Natural Gas Production

Production from oil sands projects is expected to continue to accelerate as the dominant source of crude oil product in the decades to come. Production of bitumen from both mining and in-situ operations is forecast to increase by 15% in 2013 compared with 2012. Of the remaining established crude oil and bitumen reserves in Alberta, 135 billion barrels or 80% is considered recoverable by in-situ methods and 34 billion barrels is suited to surface mining. The majority of in-situ production is not upgraded prior to reaching markets.¹

In its June 2012 forecast, the Canadian Association of Petroleum Producers (“CAPP”) projected total Canadian production to increase by approximately 94% to 6.2 mmbbls/day by 2030, of which 5.0 mmbbls/day would be from oil sands. Production above 2.5 mmbbls/day would be sourced from new oil sands projects that were not under construction at the forecast date. In addition, conventional crude oil production has reversed its long-standing declining trend. Production is ramping up based on the successful application of horizontal drilling and multi-stage hydraulic fracturing techniques to tight oil reservoirs. Current estimate of the ultimate potential reserves recoverable may still be conservative as these technologies are in their early stages. As a result, conventional production is forecast to decline again after 2016.²

Natural gas production is forecast to increase by 1% in 2013 compared with 2012. Natural gas production in Canada has declined 15% since 2008 while production in the U.S. increased by an estimated 18% during the same period. Consumption of natural gas in the U.S. has increased by 9.4% in the same period. Ample natural gas supply and high storage levels have resulted in continued low prices. Although the natural gas rig count has declined, natural gas markets are expected to remain well supplied in the near-term as a backlog of shale gas wells near markets in the U.S. Gulf Coast, mid-continent and eastern states continue to be completed and tied-in. As a result, investment in Canadian natural gas exploration and development is expected to be focused on tight and shale resource plays that utilize new technology and are in NGL prone areas.³

The Energy Information Administration (“EIA”) Short-Term Energy Outlook was published on February 13, 2013 and provides insights to the near-term energy environment. World energy demand is expected to continue to increase in 2013 and 2014, mostly in countries outside of the Organization for Economic Cooperation and Development (“OECD”). World liquid fuels consumption grew by 1.4% to reach 89.2 mmbbls/day in 2012 and is expected to grow by on average of 1.4% per year in 2013 and 2014. OPEC’s surplus capacity is expected to rise from 2.7 mmbbls/day in January 2013 to an average of 2.9 mmbbls/day for 2013 and 3.4 mmbbls/day for 2014.²

Commodity Pricing

Crude oil and natural gas producers are entitled to 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 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.

The trend of volatile commodity prices is expected to continue. The EIA projects that the spot price of Brent, an imported light sweet benchmark crude oil produced in the North Sea, will fall from an average of U.S. $112/bbl in 2012 to annual averages of U.S. $109/bbl and U.S. $101/bbl in 2013 and 2014, respectively. This forecasted

¹  “Crude Oil Forecast, Markets and Pipelines”, June 2012, Canadian Association of Petroleum Producers.

²  “Short-Term Energy Outlook,” February 12, 2013, Energy Information Administration U.S. Department of Energy.

³  “Canadian Energy Overview 2011”, July 2012, National Energy Board.

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decrease reflects the increasing supply of liquid fuels from non-OPEC countries. Averaging U.S. $94/bbl in 2012, the projected West Texas Intermediate (“WTI”) price is U.S. $93/bbl in 2013 and U.S. $92/bbl in 2014. WTI futures for May 2013 delivery during the five-day period ending February 7, 2013 averaged U.S. $97.55/bbl.⁴

Market Access

Transportation and market access in North America for crude oil emerged as a major issue in 2012, contributing to regional price volatility. Western Canada’s crude has very limited access to world markets. Higher than expected production from Alberta and Saskatchewan conventional oil developments, the growth of Bakken production in North Dakota, and new U.S. shale oil production have added to the challenges the Canadian industry is facing in accessing markets.

Crude oil with access to waterborne transportation receives a higher Brent based price due to its increased mobility compared to onshore North American crude which is valued based on WTI. Most western Canadian onshore crude is transported to Cushing, Oklahoma where the price for WTI is set. As a result of limited capacity to transport crude oil from Cushing to the Gulf Coast refining centres and from an increase of onshore production from emerging resource plays like the North Dakota Bakken and Canadian oil sands, the price differential between Brent crude and WTI crude averaged U.S. $18/bbl in 2012.

In addition to the price differential between Brent crude and WTI crude and pipeline constraints, the increased supply in the U.S. has resulted in volatility in Canadian crude prices. In 2012, Western Canadian Synthetic crude oil prices traded at a discount to WTI averaging U.S. $2/bbl compared to a premium averaging U.S. $7/bbl in 2011.

Current pipeline capacity exiting western Canada totals 3.5 mmbbls/day, 300 mbbls/day of which runs to the west coast. A number of pipeline proposals have been announced that would increase market access between 2014 and 2017. The proposed pipeline projects are the Keystone XL to the U.S. Gulf Coast, the Alberta Clipper expansion to Superior, Wisconsin, and the Trans Mountain Expansion and Enbridge Northern Gateway to the west coast. The proposed pipelines, if completed, would add approximately 2 mmbbls/day of pipeline capacity. However, considerable uncertainty exists around when and if each of these will be in service.¹

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 pertaining to Husky operations in Western Canada averaged 10% in 2012 compared with 14% in 2011 due to lower natural gas prices and royalty credit adjustments. In the Company’s Atlantic Region, the average royalty rate was 11% in 2012 compared with 17% in 2011 due to higher eligible costs associated with the SeaRose offstation and lower Terra Nova production which is subject to higher royalty rates.

The Canadian federal corporate income tax rate was 15% in 2012, a decrease from 16.5% in 2011 and 18% in 2010. Provincial rates ranged between 10 and 14% in 2012.

Other Jurisdictions

Royalty rates in the Company’s Asia Pacific Region averaged 24% in 2012 compared with 30% in 2011 mainly due to reductions in windfall profit taxes that became effective in November of 2011.

⁴  “Short-Term Energy Outlook,” February 12, 2013, Energy Information Administration U.S. Department of Energy.

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Operations in the U.S are subject to the U.S. federal tax rate of 34% and various state-level taxes. Operations in China are subject to the Chinese tax rate of 25%. Operations in Indonesia are subject to tax at a rate of 40% as governed by each project’s PSC.

The Company’s consolidated effective tax rate was 29% for both 2012 and 2011. Royalty rates averaged 11% of gross revenue in 2012 compared with 16% in 2011.

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, significant discovery and production licenses, 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 licenses, and production sharing agreements. 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.

Environmental Regulations

All phases of the oil and natural gas business are subject to environmental regulation pursuant to a variety of federal, provincial, state and local laws and regulations, as well as international conventions (collectively, “environmental legislation”).

Environmental legislation imposes, 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. Environmental legislation also requires that wells, facilities and other properties associated with Husky’s operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. 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.

The scope of recent environmental regulation and initiatives has had an impact on many areas important to industry operations which include but are not limited to, climate change, pipeline integrity, reclamation, hydraulic fracturing and land use.

Climate Change

International Climate Change Regulations

A significant breakthrough resulting from the 15th Conference of the Parties held in 2009 was the Copenhagen Accord, which endorsed the need to reduce global emissions. The Accord includes commitments from all the major emitters including the U.S., China, India, and Brazil, and provides for international review of both developed and developing countries’ targets and actions. In 2010, Canada committed to reducing its greenhouse gas emissions by 17% below 2005 levels by 2020, which is aligned with the U.S. target.

Canadian Federal Greenhouse Gas Regulations

The Canadian federal government has began addressing emissions of specific sectors of the economy, including working closely with the U.S. government to establish common North American vehicle emissions standards, as well as performance standards for thermal electricity generation. Also in line with the U.S., Canada has adopted renewable fuels regulations, requiring fuel producers and importers to have at least 5% of their gasoline supply come from renewable sources such as ethanol and at least 2% of their diesel supply from bio-diesel.

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Canadian Provincial Greenhouse Gas Regulations

In the absence of a federal policy, Ontario, British Columbia (“B.C.”) and Québec have committed to moving forward with a cap-and-trade system designed under the Western Climate Initiative (“WCI”). The WCI initiative was designed to reduce greenhouse gas emissions at the regional level from 15% below 2005 levels by 2020. The reduction would be a result of capping emissions on large industrial facilities within these provinces.

U.S. Greenhouse Gas Regulations

The U.S. also does not have a federal policy for the reduction of greenhouse gas emissions. The United States Environmental Protection Agency (“EPA”) has begun implementing greenhouse gas regulations. In particular, the so-called ‘Tailoring Rule’ now requires sources emitting greater than 100,000 tons per year of greenhouse gas to obtain a permit for those emissions, even if they are not otherwise required to obtain a new or modified permit. The Tailoring Rule may also require the installation and operation of pollution control technology as a part of any project that results in a significant greenhouse gas emissions increase. The EPA has promulgated regulations requiring greenhouse gas emissions reporting from certain U.S. operations. The EPA also issued greenhouse gas emission guidelines for existing refineries and new source performance standards for new refineries and modifications to existing refineries. Although proposed rules have not been issued, they are expected by 2013. These and other EPA regulations regarding greenhouse gas emissions are subject to legislative and judicial challenges, including current congressional proposals to block or delay the EPA’s authority to regulate greenhouse gas emissions.

Pipeline Integrity

Recent high-profile oil spill events have led to a review by industry regulators. In 2012, the Alberta Energy Resources Conservation Board (“ERCB”) hired Group 10, a third-party consultant, to review the industry’s pipeline integrity, spill response and emergency response. Husky participated in the interview process and the final report is expected by the end of the first quarter of 2013.

The British Columbia Oil and Gas Commission is conducting a review of all pipeline segments and the B.C. Ministry of Environment has recently issued a land based spill preparedness and response policy intentions paper for comment on the Government of B.C. website.

The Canadian Energy Pipeline Association (“CEPA”) announced CEPA Integrity First, an industry-wide initiative to improve pipeline safety and environmental and social performance. The program is based on sharing best practices and applying advanced technology, and highlights pipeline incident prevention, emergency response, reclamation and education. The prevention section focuses on programs and processes related to pipeline integrity, the emergency response section concentrates on programs CEPA members have in place, the reclamation section addresses the quality of post-incident activities, and the education section provides additional information about pipelines in Canada. CEPA is taking the lead with CAPP, providing support and context around pipelines owned and operated by producing companies, as well as emphasis on the importance of reliable and safe energy infrastructure to the oil and gas industry and all Albertans.

Reclamation

The ERCB maintains the regulatory process for the abandonment of a well. Over the years, the ERCB has made several adjustments to ensure effective well abandonment in Alberta. These adjustments include the introduction of new directives and additions to current regulations. In 1991, the ERCB first introduced Directive 020: Well Abandonment, which sets strict requirements for environmental protection and public safety in areas around abandoned wells. In June 2010, the requirements for abandoned wells were enhanced. These enhancements included required notification to the ERCB prior to any abandonment operation, additional abandonment criteria for critical sour wells, and a specialized cap on vented wells to prevent gas pressure build up in the well.

In 2012, the Alberta Department of Energy and the ERCB identified a large number of historically abandoned wellbores within urban areas and on residential properties. Amendments to Alberta Municipal Affairs subdivision regulations are forthcoming to ensure that all future developments will a have a five-meter setback, future wells to be abandoned must be identified and the location confirmed by the developer, and the integrity must be verified by the licensee prior to development approval.

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Hydraulic Fracturing

Hydraulic fracturing is a method of increasing well production by injecting fluid under high pressure down a well, which causes the surrounding rock to crack or fracture. The fluid typically consists of water, sand, chemicals and other additives and flows into the cracks where the sand remains to keep the cracks open and allow natural gas or liquids to be recovered. Fracturing fluids are produced back to the surface through the wellbore and are stored for reuse or future disposal in accordance with regional regulations, which may include injection into underground wells. The design of the well bores protects 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 ERCB requires that all fracturing operations submit reports regarding the quantity of fluids and additives. In the U.S., the process is regulated by state and local governments. However, the EPA is considering undertaking a broad study as it pertains to the national Clean Water Act which may or may not result in future federal regulations.

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. The LARP was developed to manage cumulative effects within the region using three formal management frameworks; Air Quality, Surface Water Quality and Groundwater Quality. The use of each framework establishes approaches to ensure trends are identified and assessed, regional limits are not exceeded and that air and water remain healthy for the region’s residents and ecosystems during oil sands development.

Industry Collaboration Initiatives

Husky is working with industry on several regulatory initiatives, most recently on increasing transparency around hydraulic fracturing procedures.

In early 2012, Husky joined the International Petroleum Industry Environmental, Conservation Association (“IPIECA”), the global oil and gas industry association for environmental and social issues and is participating in its Water Task Force. Husky also participates in industry reporting through CAPP; the Company’s water use numbers are included in the CAPP Responsible Canadian Energy Reporting. As a member of several CAPP Water Groups and Committees, Husky is committed to adhering to the Guiding Principles for Hydraulic Fracturing and Hydraulic Fracturing Operating Practices for shale and tight gas development.

Husky pursues memberships in sustainability focused groups including Oil Spill Response (OSRL), China Offshore Oil Operation Safety Office (COOSO), IPEICA, Wood Buffalo Environmental Association (WBEA), Parkland Air Management Zone (PAMZ), Calgary Regional Airshed Zone (CRAZ), Lakeland Industry and Community Association (LICA), Southeast Saskatchewan Airshed Association (SESAA), Regional Aquatics Monitoring Program (RAMP). Alberta Biodiversity Monitoring Institute (ABMI), Carbon Disclosure Project, Integrated CO₂ Network (ICO₂N), Orphan Well Association, Cumulative Effects Management Association (CEMA), Canadian Land Reclamation Association (CLRA), Environmental Services Association of Alberta (ESAA), North Saskatchewan, Watershed Alliance, Beaver River Watershed Alliance, Clearwater Mutual Aid CO-OP, Western Canadian Spill Services, One Ocean, Eastern Canada Response Corporation (ECRC), Ottawa River Coalition (ORC), Ohio Chemistry Trade Council (OCTC) and the Environmental Citizens Action Committee.

Husky’s Sustainability Commitment

Husky’s sustainability is a key pillar of the financial well being of the Company. At the end of 2010, the Company presented its business strategy and set out a five-year plan with clearly defined financial goals and performance targets. Almost two years into that plan, the Company is meeting or exceeding its key performance indicators. While sustainability begins with a strong financial foundation, success is directly linked to how the Company conducts its business, whether it is by improving safety, enhancing environmental performance through innovative ways to protect the environment, or in delivering lasting benefits to the communities. For further information, please see the Company’s 2012 Sustainability Report at www.huskyenergy.com.

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RISK FACTORS

The following provides a list of the most significant risks relating to Husky and its operations that 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.

Operational, Environmental and Safety Incidents

Husky’s businesses are subject to inherent operational risks and hazards in respect of safety and the environment that require continuous vigilance. The Company seeks to minimize these operational risks and hazards by carefully designing and building its facilities and conducting its operations in a safe and reliable manner. However, failure to manage these operational risks and hazards effectively could result in unexpected incidents, including the release of restricted substances, fires, explosions, well blow-outs, marine catastrophe or mechanical failures and pipeline failures. The consequences of such events include personal injuries, loss of life, environmental damage, property damage, loss of revenues, fines, penalties, legal liabilities, disruption to operations, asset repair costs, remediation and reclamation costs, monitoring post-cleanup and/or reputational impacts which may affect the Company’s license to operate. Remediation may be complicated by a number of factors including shortages of specialized equipment or personnel, extreme operating environments and the absence of appropriate or proven countermeasures to effectively remedy such consequences. Emergency preparedness, business continuity and security policies and programs are in place for all operating areas, and are routinely exercised. The Company, in accordance with industry practice, maintains insurance coverage against losses from certain of these risks and hazards. Nonetheless, insurance proceeds may not be sufficient to cover all losses, and insurance coverage may not be available for all types of operational risks and hazards.

Commodity Price Volatility

Husky’s results of operations and financial condition are dependent on the prices received for its crude oil and natural gas production. Lower prices for crude oil and natural gas could adversely affect the value and quantity of Husky’s oil and gas reserves. Husky’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 is limited and planned increases of North American heavy crude oil production may create the need for additional heavy oil refining and transportation capacity. As a result, wider price differentials could have adverse effects on Husky’s financial performance and condition, reduce the value and quantities of Husky’s heavier crude oil reserves and delay or cancel projects that involve the development of heavier crude oil resources. There is no guarantee that planned pipeline development projects will provide sufficient transportation capacity and access to refining capacity to accommodate expected increases in North American heavy crude oil production.

Prices for 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, prevailing weather patterns and the availability of alternate sources of energy.

Husky’s natural gas production is currently located entirely in Western Canada and is, therefore, 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 well head or from storage facilities, prevailing weather patterns, the price of crude oil, the U.S. and Canadian economies, the occurrence of natural disasters and pipeline restrictions.

In certain instances, the Company uses derivative commodity instruments to manage exposure to price volatility on a portion of its oil and gas production and firm commitments for the purchase or sale of crude oil and natural gas.

The fluctuations in crude oil and natural gas prices are beyond Husky’s control and accordingly, could have a material adverse effect on the Company’s business, financial condition and cash flow. For information on 2012 commodity price sensitivities, refer to Section 3.0 of the 2012 Annual MD&A.

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Reservoir Performance Risk

Lower than projected reservoir performance on the Company’s key growth projects could have a material impact on the Company’s financial position, medium to long-term business strategy and cash flow. 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 natural gas liquids 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. In order 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 developable projects depends on, among other things, obtaining and renewing rights to explore, develop and produce oil and natural gas, drilling success, completing long-lead time capital intensive projects on budget and on schedule and the application of successful exploitation techniques on mature properties.

Restricted Market Access

Husky’s results depend upon the Company’s ability to deliver products to the most attractive markets. The Company’s results could be impacted 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. With growing conventional and oil sands production across North America and 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 impact on the Company’s financial position, medium to long-term business strategy, cash flow and corporate reputation.

Security and Terrorist Threats

A security threat or terrorist attack on a facility owned or operated by the Company could result in the interruption or cessation of key elements of its operations, which could have a material impact on the Company’s financial position, business strategy and cash flow.

International Operations

International operations can expose the Company to uncertain political, economic and other risks. The Company’s operations in certain jurisdictions may be 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, imposition of onerous regulation, changes in laws governing existing operations, financial constraints, including currency and exchange rate fluctuations, and unreasonable taxation. This could adversely affect the Company’s interest in its foreign operations and future profitability.

Gas Offtake

The potential inability to deliver an effective gas storage solution as inventories grow over the life of the White Rose field may potentially result in prolonged shutdown of these operations, which may have a material impact on the Company’s financial position, medium to long-term business strategy and cash flow.

Skills and Human Resource Shortage

The Company recognizes that a robust, productive, and healthy workforce drives efficiency, effectiveness, and financial performance. Attracting and retaining qualified and skilled labour is critical to the successful execution of Husky’s current and future business strategies. However, a tight labour market, an insufficient number of qualified candidates, and an aging workforce are factors that precipitate a human resource risk for the Company. Failure to retain current employees and attract new skilled employees could materially affect the Company’s ability to conduct its business.

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Major Project Execution

The Company manages a variety of major projects relating to oil and gas exploration, development and production. Risks associated with the execution of Husky’s major projects, as well as the commissioning and integration of new assets into its existing infrastructure, may result in cost overruns, project or production delays, and missed financial targets, thereby eroding project economics. Typical project execution risks include: the availability and cost of capital, inability to find mutually agreeable parameters with key project partners for large growth projects, availability of manufacturing and processing capacity, faulty construction and design errors, labour disruptions, bankruptcies, productivity issues affecting Husky directly or indirectly, unexpected changes in the scope of a project, health and safety incidents, need for government approvals or permits, unexpected cost increases, availability of qualified and skilled labour, availability of critical equipment, severe weather, and availability and proximity of pipeline capacity.

Partner Misalignment

Joint venture partners operate a portion of Husky’s assets in which the Company has an ownership interest. Husky 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 Husky project may be delayed and the Company may be partially or totally liable for its partner’s share of the project.

Reserves Data, Future Net Revenue and Resource Estimates

The reserves data 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 resource plays. In general, estimates of economically recoverable crude oil and 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 assumed effects of regulation by governmental agencies, including with respect to royalty payments, all of which may vary considerably from actual results. All such estimates are to some degree uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For those reasons, estimates of the economically recoverable oil and gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. 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 and efficacy 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. Inaccurate appraisal of large project reservoirs could result in missed production, revenue and earnings targets, and could negatively affect the Company’s reputation, investor confidence, and the Company’s ability to deliver on its growth strategy.

Government Regulation

Given the scope and complexity of Husky’s operations, the Company may be subject to regulation and intervention by governments at the federal, provincial, state and municipal levels in the countries in which it conducts its operations 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 regulation could impact the Company’s existing and planned projects as well as impose costs of compliance, increase capital expenditures and operating expenses, and expose the Company to other risks including environmental and safety risks. Examples of the Company’s regulatory risks include, but are not limited to, uncertain or negative interactions with governments, uncertain energy policies, environmental and safety controls related to the reduction of greenhouse gasses and other emissions, penalties, taxes, royalties, government fees, reserves access, limitations or increase in costs relating to the exportation of commodities, 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 licenses to operate.

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Environmental Regulation

Husky anticipates that changes in environmental legislation may require reductions in emissions from its operations and result in increased capital expenditures. Further changes in environmental legislation could occur, which may result in stricter standards and enforcement, larger fines and liabilities, and increased capital expenditures and operating costs, which could have a material adverse effect on Husky’s financial condition and results of operations.

The 2010 Deepwater Horizon oil spill in the Gulf of Mexico has led to numerous public and governmental expressions of concern about the safety and potential environmental impact of offshore oil and gas operations. Stricter regulation of offshore oil and gas operations has already been implemented by the U.S. with respect to operations in the Outer Continental Shelf, including in the Gulf of Mexico. Further regulation, increased financial assurance requirements and increased caps on liability are likely to be applied to offshore oil and gas operations in these areas. In the event that similar changes in environmental regulation occur with respect to Husky’s operations in the Atlantic or Asia Pacific Regions, such changes could increase the cost of complying with environmental regulation in connection with these operations and have a material adverse impact on Husky’s operations.

Climate Change Regulation

Husky continues to monitor international efforts to address climate change, including developments on the Kyoto Protocol and the Copenhagen Accord. Canada has withdrawn from participation in the Kyoto Protocol. The effect of these initiatives on the Company’s operations cannot be determined with any certainty at this time. The Alberta and BC governments have regulations in place with the Saskatchewan government anticipated to soon follow with similar regulation. These regulations include limiting the intensity limits for large emitters of greenhouse gases in Alberta emitting 100,000 tonnes or more of greenhouse gas in any year. Under the regulations, 12-15% intensity reduction will be applied to the average of that facility’s 2003-2005 baseline emissions intensity for established facilities. New facilities are required to reduce emissions starting with the fourth year of commercial operation by 2%, and then by 2% every year after, until the 12-15% reduction target has been achieved. These regulations impact all of Husky’s Upstream operations in B.C., the Prince George Refinery, the Ram River gas plant and the Tucker thermal oil facility. In addition, the Federal Government of Canada has announced pending regulations in respect of greenhouse gases and other pollutants. Although the impact of these regulations is uncertain, they may adversely affect the Company’s operations and increase costs. These regulations may become more onerous over time as public and political pressures increase to implement initiatives that further reduce the emission of greenhouse gases.

While the U.S. EPA regulations are currently in effect, they have not yet had a material impact on Husky. However, the Company’s operations may be materially impacted by future application of these rules or by future U.S. greenhouse gas legislation applying to the oil and gas industry or the consumption of petroleum products or by these or any further restrictive regulations issued by the EPA. Such legislation or regulation could require Husky’s U.S. refining operations to significantly reduce emissions and/or purchase allowances, which may increase capital and operating expenditures.

Financial Risks

Husky’s financial risks are largely related to commodity price risk, foreign currency risk, interest rate risk, credit risk, and liquidity risk. From time to time, Husky uses derivative financial instruments to manage its exposure to these risks. These derivative financial instruments are not intended for trading or speculative purposes. For further details on the Company’s derivative financial instruments, including assumptions made in the calculation of fair value and additional discussion of exposure to risks and mitigation activities see Note 22 Financial Instrument and Risk Management within the Company’s 2012 audited consolidated financial statements and Section 7.0 of the Company’s 2012 Annual MD&A, which are incorporated herein by reference. For a discussion on commodity price risk, refer to the Commodity Price Volatility section above.

Foreign Currency Risk

Husky’s results are affected by the exchange rates between various currencies including the Canadian and U.S. dollar. The majority of Husky’s expenditures are in Canadian dollars while the majority 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

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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 Husky’s U.S. dollar denominated debt and related interest expense, as expressed in Canadian dollars. The fluctuations in exchange rates are beyond Husky’s control and accordingly, could have a material adverse effect on the Company’s business, financial condition and cash flow.

The Company enters into short-dated foreign exchange contracts to fix the exchange rate for conversion of U.S. revenue dollars to hedge against these potential fluctuations. Husky also designates a portion of its U.S debt as a hedge of the Company’s net investment in the U.S. refining operations which are considered as a foreign functional currency. At December 31, 2012, the amount that the Company designated was U.S. $2.8 billion (December 31, 2011 – U.S. $1.3 billion).

Interest Rate Risk

Interest rate risk is the impact of fluctuating interest rates on earnings, cash flows and valuations. In order to manage interest rate risk and the resulting interest expense, Husky 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. Husky may also enter into interest rate swaps from time to time as an additional means of managing current and future interest rate risk.

Credit Risk

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. Husky actively manages this exposure to credit and contract execution risk from both a customer and a supplier perspective. Internal credit policies govern Husky’s credit portfolio and limit transactions according to a counterparty’s and a supplier’s credit quality. Counterparties for all financial derivatives transacted by Husky are major financial institutions or counterparties with investment grade credit ratings.

Liquidity Risk

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 the availability to raise capital from various debt capital markets, including under its shelf prospectuses. The availability of capital under its shelf prospectuses is dependent on market conditions.

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 gain access to markets. Husky 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. Husky’s ability to successfully complete development projects could be 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. Husky’s competitors comprise all types of energy companies, some of which have greater resources.

Internal Credit Risk

Credit ratings affect Husky’s ability to obtain short-term and long-term financing and the cost of such financing. Additionally, the ability of Husky to engage in ordinary course derivative or hedging transactions and maintain ordinary course contracts with customers and suppliers on acceptable terms 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. 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

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the rating agencies are not recommendations to purchase, hold or sell the securities inasmuch 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, liquidity 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 adversely affects 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 land and offshore drilling rigs, land and offshore geological and geophysical services, engineering and construction services and construction materials. These materials and services may not be available when required at reasonable prices.

Climatic Conditions

Extreme climatic conditions may have significant adverse effects on operations. 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 or disruptions to the operations of major customers or suppliers can be affected by extreme weather, which may result in cessation or diminishment of production, delay of exploration and development activities or delay of plant construction. All of these could potentially cause financial losses.

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HUSKY EMPLOYEES

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

As at December 31,
2012		2011		2010
	5,178		4,726		4,380

DIVIDENDS

The following table shows the aggregate amount of the dividends per common share and Series 1 Preferred Shares of the Company declared payable in respect of its last three years ended December 31:

	2012		2011		2010
Dividends per Common Share	$	1.20	$	1.20	$	1.20
Dividends per Series 1 Preferred Share	$	1.11	$	0.87	$	—

Dividend Policy and Restrictions

Common Share Dividends

The Board of Directors has established a dividend policy that pays quarterly dividends of $0.30 ($1.20 annually) per common share. The declaration and payment of dividends are at the discretion of the Board of Directors, which will consider earnings, 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.

In February 2011, Husky’s shareholders approved amendments to the common share terms to provide the shareholders with the ability to receive dividends in common shares or in cash. Quarterly dividends may be declared in an amount expressed in dollars per common share and 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.

Husky’s dividend policy will continue to be reviewed and there can be no assurance that further dividends will be declared or the amount of any future dividend.

Series 1 Preferred Share Dividends

Holders of Series 1 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, yielding 4.45% 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 5-year Government of Canada bond yield plus 1.73%. Holders of Series 1 Preferred Shares will have the right, at their option, to convert their shares into Series 2 Preferred Shares, subject to certain conditions, on March 31, 2016 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 at a rate equal to the three-month Government of Canada Treasury Bill yield plus 1.73% as and when declared by the Board of Directors.

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DESCRIPTION OF CAPITAL STRUCTURE

Common Shares

Husky is authorized to issue an unlimited number of no par value common shares. 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. See “Dividend Policy and Restrictions.”

If the Board of Directors declares a dividend on the common shares payable in whole or in part as a stock dividend, shareholders of record wishing to accept a payment of future stock dividends declared by the Board of Directors in the form of common shares 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.

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. See “Dividend Policy and Restrictions – Series 1 Preferred Share Dividends.”

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Liquidity Summary

The following information relating to Husky’s 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 ability of Husky 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, and (ii) into and maintaining ordinary course contracts with customers and suppliers on acceptable terms.

	Outlook		Rating
Moody’s
Senior Unsecured Debt		Stable		Baa2
Standard and Poor’s
Senior Unsecured Debt		Stable		BBB+
Series 1 Preferred Shares		Stable		P-2 (low)
Dominion Bond Rating Service
Senior Unsecured Debt		Stable		A (low)
Series 1 Preferred Shares		Stable		Pfd-2 (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 inasmuch 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.

Moody’s

Moody’s credit rating system ranges from Aaa (highest) to C (lowest). Debt securities rated within the Baa category are considered medium grade debts; they are neither highly protected nor poorly secured. Interest payments and principal security appear to be adequate at the time of the rating; however, they are subject to potential adverse circumstances over time. As a result, these debt securities possess some speculative characteristics. The addition of a 1, 2 or 3 modifier indicates an additional relative standing within the general rating classification. The addition of the modifier 1 indicates the debt is positioned in the top one third of the general rating classification, 2 indicates the mid one third and 3 indicates the bottom one third.

Standard and Poor’s

Standard and Poor’s credit rating system for debt ranges from AAA (highest) to D (lowest). Debt securities rated within the BBB category are considered to possess adequate protection parameters. However, they could potentially change subject to adverse economic conditions or other circumstances that may result in reduced capacity of the debtor to continue to meet principal and interest payments. As a result, these debt securities possess some speculative characteristics. The addition of the modifier + or - indicates the debt is positioned above (+) or below (-) the mid range of the general category.

Standard and Poor’s began rating Husky’s Series 1 Preferred Shares on its Canadian preferred share scale on March 11, 2011. Preferred share ratings have a direct correlation to the degree of credit worthiness provided by the debt ratings system except that ratings on preferred shares refer to the entity’s ability to fulfill the obligations specific to the preferred shares. A P-2 (low) rating on the Canadian preferred share rating scale is equivalent to a BBB- rating on the debt rating scale.

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Dominion Bond Rating Service

Dominion Bond Rating Service’s credit rating system for debt ranges from AAA (highest) to D (lowest). Debt securities rated within the A category are considered to be of satisfactory credit quality. Protection of interest and principal is considered acceptable, but the debtor is susceptible to adverse changes in financial and economic conditions, or there may be other adverse conditions present which reduce the strength of the debtor and its rated debt. The addition of the high or low modifier denotes that the rating is either above or below the mid range of the general rating category.

Dominion Bond Rating Service began rating Husky’s Series 1 Preferred Shares on its Canadian preferred share scale on March 10, 2011. Preferred share ratings have a direct correlation to the degree of credit worthiness provided by the debt ratings system except that ratings on preferred shares refers to the entity’s ability to fulfill the obligations specific to the preferred shares. A Pfd-2(low) rating on the Canadian preferred share rating scale is equivalent to an A category rating on the debt rating scale.

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MARKET FOR SECURITIES

Husky’s common shares and Series 1 Preferred Shares are listed and posted for trading on the Toronto Stock Exchange under the respective trading symbols “HSE” and “HSE.PR.A”. The Series 1 Preferred Shares began trading on the Toronto Stock Exchange on March 18, 2011.

The following table discloses the trading price range and volume of Husky’s common shares traded on the Toronto Stock Exchange during Husky’s financial year ended December 31, 2012:

	High		Low		Volume (000’s)
January		24.98		23.78		21,934
February		26.99		24.43		16,848
March		26.99		24.84		23,509
April		25.84		23.70		16,899
May		25.86		22.76		22,716
June		25.72		22.04		22,753
July		26.25		24.52		15,010
August		27.14		24.58		18,850
September		27.18		25.89		19,604
October		28.33		26.41		19,168
November		28.20		26.08		18,523
December		29.50		27.78		24,228

The following table discloses the trading price range and volume of the Series 1 Preferred Shares traded on the Toronto Stock Exchange during Husky’s financial year ended December 31, 2012:

	High		Low		Volume (000’s)
January		26.25		25.70		933
February		26.18		25.75		243
March		26.20		25.47		365
April		26.17		25.76		529
May		26.30		25.39		152
June		25.94		25.30		454
July		26.33		25.60		172
August		26.36		25.75		92
September		26.25		25.71		243
October		26.09		25.68		184
November		25.77		25.32		330
December		26.15		25.54		149

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DIRECTORS AND OFFICERS

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

Directors

Name & Residence	Office or Position	Principal Occupation During Past 5 Years
Li, Victor T.K. Hong Kong	Co-Chair Director of Husky since August 2000	Mr. Li is Managing Director and Deputy Chairman of Cheung Kong (Holdings) Limited (a public investment holding and project management company).
		Mr. Li is also Deputy Chairman and Executive Director of Hutchison Whampoa Limited (an investment holding company); Chairman and Executive Director of Cheung Kong Infrastructure Holdings Limited (an infrastructure company) and of CK Life Sciences Int’l, (Holdings) Inc. (a biotechnology company); Executive Director of Power Assets Holdings Limited (a holding company); and a non-executive Director of The Hongkong and Shanghai Banking Corporation Limited. Mr. Li is also the Deputy Chairman of each of the Li Ka Shing Foundation, the Li Ka Shing (Overseas) Foundation and the Li Ka Shing Canada Foundation.
		Mr. Li is a member of the Standing Committee of the 11th National Committee of the Chinese People’s Political Consultative Conference of the People’s Republic of China and he is also a member of the Council for Sustainable Development of the Hong Kong Special Administrative Region and Vice Chairman of the Hong Kong General Chamber of Commerce and was previously a member of the Commission on Strategic Development of the Hong Kong Special Administrative Region. Mr. Li is also the Honorary Consul of Barbados in Hong Kong.
		Mr. Li holds a Bachelor of Science degree in Civil Engineering and a Masters of Science degree in Structural 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	Co-Chair and Chair of the Compensation Committee Director of Husky since August 2000	Mr. Fok is Group Managing Director and Executive Director of Hutchison Whampoa Limited.

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		Mr. Fok is Chairman and a Director of Hutchison Harbour Ring Limited, Hutchison Telecommunications Hong Kong Holdings Limited, Hutchison Telecommunications (Australia) Limited, Power Assets Holdings Limited and Hutchison Port Holdings Management Pte. Limited as the trustee-manager of Hutchison Port Holdings Trust. Mr. Fok is the Deputy Chairman and a Director of Cheung Kong Infrastructure Holdings Limited, a Director of Cheung Kong (Holdings) Limited and an Alternate Director to a Director of Hutchison Telecommunications Hong Kong Holdings Limited. Mr. Fok was also Chairman and a Director of Partner Communications Company Ltd. from 1998 to 2009 and Chairman and non-executive Director of Hutchison Telecommunications International Limited from 2004 to 2010.
		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 since 1979.
Bradley, Stephen E. Hong Kong	Member of Corporate Governance Committee Director of Husky since July 2010	Mr. Bradley is a director of Broadlea Group Ltd., Senior Representative (China), Grosvenor Ltd., Vice Chairman, ICAP (Asia Pacific) 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 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.
Ghosh, Asim Alberta, Canada	President & Chief Executive Officer Director of Husky since May 2009	Mr. Ghosh was appointed the President and Chief Executive Officer of Husky on June 1, 2010. Prior thereto Mr. Ghosh was the Managing Director and Chief Executive Officer of Vodafone India Limited (formerly Vodafone Essar Limited) (a telecommunications company) until March 2009.

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		Mr. Ghosh began his career with Procter & Gamble in Canada in 1971 and subsequently worked with Rothmans International in what was then its Carling O’Keefe subsidiary from 1980 to 1988, his last position being Senior Vice President of the brewery operations. In 1989, Mr. Ghosh moved to India as the Chief Executive Officer of the Pepsi Foods (Frito Lay) start up in India. From 1991 to 1998 he held senior executive positions and then the position of Chief Executive Officer of the A S Watson Industries subsidiary (a manufacturer of consumer goods) of Hutchison Whampoa Limited. In August 1998, he became Managing Director and Chief Executive Officer of the company that would become Vodafone India Limited.
		Mr. Ghosh was Chairman of the Cellular Operators Association of India and of the National Telecom Committee of the Confederation of Indian Industries. He is an independent director of Kotak Mahindra Bank Limited, a listed bank in India, and was on the Board of Directors of Vodafone India Limited until February 2010. Mr. Ghosh is also a director of the Li Ka Shing (Canada) Foundation and a member of the Board of Directors of the Canadian Council of Chief Executives.
		Mr. Ghosh obtained an undergraduate degree in Electrical Engineering from the Indian Institute of Technology in 1969 and received a Master’s degree in Business Administration from the Wharton School, University of Pennsylvania in 1971.
Glynn, Martin J.G. British Columbia, Canada	Chair of the Corporate Governance Committee and a Member of the Compensation Committee Director of Husky since August 2000	Mr. Glynn is a director of VinaCapital Vietnam Opportunity Fund Limited (an investment fund), Sun Life Financial Inc., Sun Life Assurance Company of Canada and UBC Investment Management Trust Inc.
		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 University of British Columbia in 1976.

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Koh, Poh Chan Hong Kong	Director of Husky since August 2000	Ms. Koh is Finance Director of Harbour Plaza Hotel Management (International) Ltd. (a hotel management company).
		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 become a member of the Institute of Chartered Accountants in England and Wales in 1973.
Kwok, Eva L. British Columbia, Canada	Member of the Compensation Committee and the Corporate Governance Committee Director of Husky 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 Cheung Kong Infrastructure 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 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 of Husky since August 2000	Mr. Kwok is a director and President of Stanley Kwok Consultants (a planning and development company). Mr. Kwok is also a director and President of Amara Holdings Inc. and a director of Cheung Kong (Holdings) Limited and CTC Bank of Canada.
		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. GBS, JP Hong Kong	Member of the Audit Committee and the Health, Safety and Environment Committee Director of Husky since July 2010	Mr. 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 (SAR) Government.

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		He is a non-executive director of China Resources Land Limited, a Hong Kong listed company; a non-executive director and Chairman of the Audit Committee of Agricultural Bank of China, which is listed in Hong Kong and Shanghai; a non-executive director of COFCO Corporation and a non-executive director of Hutchison Port Holdings Management Pte. Limited, as the trustee-manager of Hutchison Port Holdings Trust.
		In July 2002, Mr. Ma joined the Government of the Hong Kong SAR 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. In October 2008, he was appointed an Honorary Professor of the School of Economics and Finance at the University of Hong Kong. In July 2009, he was appointed as a Member of the International Advisory Council of China Investment Corporation.
		Mr. Ma obtained a Bachelor of Arts (Honours) degree in Economics and History from the University of Hong Kong in 1973.
Magnus, George C. Hong Kong	Member of the Audit Committee Director of Husky since July 2010	Mr. Magnus has been a non-executive Director of Cheung Kong (Holdings) Limited since November 2005. He has also been a non-executive Director of Hutchison Whampoa Limited, Cheung Kong Infrastructure Holdings Limited and Power Assets Holdings Limited (formerly Hongkong Electric Holdings Limited) since 2005.
		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.
		Mr. Magnus obtained a Master’s degree in Economics from King’s College, Cambridge University in 1959.

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McGee, Neil D. Luxembourg	Member of the Health, Safety and Environment Committee Director of Husky since November 2012	Mr. McGee is the Managing Director of Hutchison Whampoa Luxembourg Holdings S.à r.l. Prior to his joining Hutchison Whampoa Luxembourg, 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 Husky Energy Inc. from 2000 to 2005.
		Prior to joining Husky, Mr. McGee held various financial, legal and corporate secretarial positions within the Hutchison Whampoa Group. Mr. McGee holds a Bachelor of Arts degree and a Bachelor of Laws degree from the Australian National University.
Russel, Colin S. Gloucestershire, United Kingdom	Member of the Audit Committee and the Health, Safety and Environment Committee	Mr. Russel is the founder and Managing Director of Emerging Markets Advisory Services Ltd. (a business advisory company).
	Director of Husky since February
	2008	Mr. Russel is a director of Cheung Kong 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.
		Mr. Russel is a Professional Engineer and Qualified Commercial Mediator. He received his degree in Electrical Engineering in 1962 and a Master’s degree in Business Administration in 1971 both from McGill University, Canada.
Shaw, Wayne E. Ontario, Canada	Member of the Corporate Governance Committee and the Health, Safety and Environment Committee	Mr. Shaw is a Senior Partner with Stikeman Elliott LLP, Barristers and Solicitors. Mr. Shaw is also a director of the Li Ka Shing (Canada) Foundation.
	Director of Husky since August
	2000	Mr. Shaw obtained a Bachelor of Arts degree and a Bachelor of Laws degree both from University of Alberta (1967). He is a member of the Law Society of Ontario.
Shurniak, William Saskatchewan, Canada	Deputy Chair and Chair of the Audit Committee Director of Husky since August 2000	Mr. Shurniak is an independent non-executive director of Hutchison Whampoa Limited and 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).

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		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. 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.
Sixt, Frank J. Hong Kong	Member of the Compensation Committee Director of Husky since August 2000	Mr. Sixt is Group Finance Director and Executive Director of Hutchison Whampoa Limited.
		Mr. Sixt is also Chairman and a non-executive Director of TOM Group Limited (an investment holding company); an Executive Director of Cheung Kong Infrastructure Holdings Limited and Power Assets Holdings Limited; a non-executive Director of Cheung Kong (Holdings) Limited, Hutchison Telecommunications Hong Kong Holdings Limited and Hutchison Port Holdings Management Pte. Limited as the trustee-manager of Hutchison Port Holdings Trust and a Director of Hutchison Telecommunications (Australia) Limited. Mr. Sixt is also a Director of the Li Ka Shing (Canada) Foundation. He was previously a Director of Partner Communications Ltd. from 1998 to 2009 and a non-executive Director of Hutchison Telecommunications International Limited from 2004 to 2011.
		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

Name and Residence	Office or Position	Principal Occupation During Past 5 Years
Cowan, Alister Alberta, Canada	Chief Financial Officer	Chief Financial Officer of Husky since July 2008. He was previously Executive Vice President and Chief Financial Officer, British Columbia Hydro & Power Authority from 2004 to 2008, Vice President, Direct Energy Marketing Limited from 2003 to 2004 and Vice President and Comptroller, TransAlta Corporation from 2000 to 2003.
Peabody, Robert J. Alberta, Canada	Chief Operating Officer	Chief Operating Officer of Husky since January 2006.
Girgulis, James D. Alberta, Canada	Senior Vice President, General Counsel and Secretary	Vice President, Legal and Corporate Secretary of Husky since August 2000. Senior Vice President, General Counsel and Secretary since April 2012.

As at February 27, 2013, the directors and officers of Husky, as a group, beneficially owned or controlled or directed, directly or indirectly, 661,875 common shares of Husky representing less than 1% 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 which 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 manger or trustee appointed to hold its assets, other than as follows. Eva L. Kwok was a director of Air Canada in 2003 at the time it became subject to creditor protection under the Companies Creditors Arrangement Act (Canada). Victor T. K. Li was a director of Star River Investment Limited, a Hong Kong company, until June 4, 2005, which commenced creditors voluntary wind up on September 28, 2004. Star River Investments Limited was owned as to 50% by Cheung Kong (Holdings) Limited and a wholly owned subsidiary of Cheung Kong (Holdings) Limited was the petitioning creditor. The company was subsequently dissolved on June 4, 2005. Mr. Glynn was director of MF Global Holdings Ltd. when it filed for Chapter 11 bankruptcy in the United States 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

The members of Husky’s Audit Committee (the “Committee”) are William Shurniak (Chair), Colin S. Russel, Frederick S.H. Ma and George C. Magnus. Each of the members of the Committee are 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 (3) 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 Audit Committee member that is relevant to the performance of his responsibilities as an Audit Committee member is as follows.

William Shurniak (Chair) – Mr. Shurniak is an independent, non-executive director and member of the audit committee of Hutchison Whampoa Limited and from May 2005 to June 2011, a director and Chairman of Northern Gas Networks Limited, a private company in the U.K.. He has broad banking experience and prior to his moving back to Canada in 2005, he spent five years in Australia where he was a director of a public company engaged in the distribution of natural gas. He was also a director and member of the audit committees of five other private companies, three of which are regulated electricity distribution companies.

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.

Frederick S.H. Ma – Mr. Ma has served in senior positions in the private sector and has held Principal Official positions (minister equivalent) with the Hong Kong SAR Government. Mr. 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 has been a non-executive Director of Cheung Kong (Holdings) Limited since November 2005. He is also a non-executive Director of Hutchison Whampoa Limited, Cheung Kong Infrastructure Holdings Limited and Power Assets Holdings Limited (formerly Hongkong Electric Holdings Limited).

Husky’s Audit Committee Mandate is attached hereto as Schedule “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)	2012		2011
Audit Fees		3,822		2,113
Audit-related Fees		152		977
Tax Fees		230		160
All Other Fees		—		—
		4,204		3,250

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 and services with respect to acquisitions and dispositions. Tax fees included fees for tax planning and various taxation matters.

The Company’s Audit Committee has the sole authority to review in advance, and grant any appropriate pre-approvals, of all non-audit services to be provided by the independent auditors and to approve fees, in connection therewith. The Audit Committee pre-approved all of the audit-related and tax services provided by KPMG LLP in 2012.

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 amount which it may be required to pay by reason thereof would have a material adverse impact on its financial position, 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% 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 1-888-564-6253 or 1-514-982-7555.

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INTERESTS OF EXPERTS

Certain information relating to the Company’s reserves included in this AIF has been calculated by the Company and audited and opined upon as of December 31, 2012 by McDaniel & Associates Consultants Ltd. (“McDaniel”), independent petroleum engineering consultants retained by Husky, and has been so included in reliance on the opinion and analysis of McDaniel, given upon the authority of said firm as experts in reserves engineering. The partners of McDaniel as a group beneficially own, directly or indirectly, less than 1% of the Company’s securities of any class.

KPMG LLP are the auditors of the Company and have confirmed that they are independent with respect to the Company within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta and within the meaning of the U.S. Securities Act of 1933 and the applicable rules and regulations thereunder adopted by the SEC and the Public Company Accounting Oversight Board (United States).

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 will be contained in Husky’s Management Information Circular prepared in connection with the annual meeting of shareholders to be held on May 7, 2013.

Additional financial information is provided in Husky’s audited consolidated financial statements and Management’s Discussion and Analysis for the most recently completed fiscal year ended December 31, 2012.

Additional information relating to Husky Energy Inc. is available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov.

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements in this AIF are forward looking statements within the meaning of 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, and forward-looking information within the meaning of applicable Canadian securities legislation (collectively “forward-looking statements”). The Company hereby provides cautionary statements identifying important factors that could cause actual results to differ materially from those projected in these forward-looking statements. Any 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,” “are expected to,” “will continue,” “is anticipated,” “is targeting,” “estimated,” “intend,” “plan,” “projection,” “could,” “aim,” “vision,” “goals,” “objective,” “target,” “schedules” and “outlook”) are not historical facts, are forward-looking and may involve estimates and assumptions and are subject to risks, uncertainties and other factors some of which are beyond the Company’s control and difficult to predict. Accordingly, these factors could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements.

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;

• with respect to the Company’s Asia Pacific Region: anticipated timing of first gas production and ramping up of production at the Company’s Liwan 3-1 Gas Project; scheduled timing of topside platform completions and floatover for the Liwan Gas Project; anticipated timing of first gas at the Madura Strait Block; and development plans for the single well Liuhua 34-2 field;

• with respect to the Company’s Atlantic Region: scheduled timing of completion of construction of the new build rig West Mira; drilling plans, including anticipated timing of drilling, at the North Amethyst field; development plans at the West White Rose field, including expected timing of a decision on a preferred development option; anticipated timing of development drilling at the South White Rose extension field; 2013 drilling plans at the Terra Nova field; exploration and drilling plans at the Mizzen field; and anticipated timing of socio-economic study work in respect of the Company’s Greenland concessions;

• with respect to the Company’s Oil Sands properties: planned timing of first production at the Company’s Sunrise Oil Sands project; expected timing of completion of the Design Basis Memorandum for the next phase of the Company’s Sunrise Oil Sands project; expected timing of production from the Company’s Tucker Oil Sands project; additional drilling and field development plans at the Company’s Tucker Oil Sands project through 2015; and planned timing of a pilot application for the Company’s Saleski oil sands project;

• with respect to the Company’s Heavy Oil properties: anticipated timing of first production at the Company’s Sandall thermal development project; anticipated timing of first production at the Company’s Rush Lake thermal development project; and ability of the Company’s undeveloped land position and the development and application of improved recovery technologies to maintain heavy crude oil production in the Lloydminster area;

• with respect to the Company’s Western Canadian oil and gas resource plays: 2013 drilling and development plans at the Company’s Redwater Red Deer and Alliance plays; and 2013 well workover plans at the Company’s Macklin Saskatchewan ASP flood project; and

• with respect to the Company’s Downstream operating segment: anticipated timing and duration of scheduled turnarounds at the Lima Refinery; anticipated timing of operations of the kerosene hydrotreater at the Lima Refinery; expansion plans for bitumen processing capacity at the BP-Husky Toledo Refinery; expected timing of startup of the Continuous Catalyst Regeneration Reformer project at the BP-Husky Toledo Refinery.

In addition, statements relating to “reserves” and “resources” are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves or resources described can be profitably produced in the future.

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

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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, regulators and other sources. 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 Asia Pacific Region, Atlantic Region, Oil Sands properties, Heavy Oil properties and Western Canadian oil and gas resource plays: the accuracy of future production rates and reserve and resource 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 of the procurement, development, construction or commissioning of our 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 increase in the cost of major growth projects; and

• with respect to the Company’s Downstream operating segment: the absence of significant delays of the development, construction or commissioning of our 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 our Management’s Discussion and Analysis for the year ended December 31, 2012; 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 ability to replace reserves of oil and gas, whether sourced from exploration, improved recovery or acquisitions; potential actions of governments, regulatory authorities and other stakeholders that may impose operating costs or restrictions in the jurisdictions where the Company has operations; changes to royalty regimes; changes to government fiscal, monetary and other financial policies; changes in workforce demographics; and the cost and availability of capital, including access to capital markets at acceptable rates;

• with respect to the Company’s Asia Pacific Region, Atlantic Region, Oil Sands properties, Heavy Oil properties and Western Canadian oil and gas resource plays: the availability of prospective drilling rights; the costs to

AIF 2012 Page 93 

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; 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; 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 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 Management’s Discussion and Analysis for the year ended December 31, 2012 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.

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. 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 its assessment of the future considering all information then available.

AIF 2012 Page 94 

Schedule 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 it 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.

AIF 2012 Page 95 

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 evaluators 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.

AIF 2012 Page 96 

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.

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 auditors 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.

AIF 2012 Page 97 

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.

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: November 20, 2010

AIF 2012 Page 98 

Schedule B

Husky Energy Inc.

Report on Reserves Data by Qualified Reserves Evaluator

To the Board of Directors of Husky Energy Inc. (“Husky”):

1. Our staff has evaluated Husky’s reserves data as at December 31, 2012. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2012, estimated using forecast prices and costs.

2. The reserves data are the responsibility of Husky’s management. As the Internal Qualified Reserves Evaluator our responsibility is to certify that the reserves data has been properly calculated in accordance with generally accepted procedures for the estimation of reserves data.

We carried out our evaluation in accordance with generally accepted procedures for the estimation of oil and gas reserves data and standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society). Our internal reserves evaluators are not independent of Husky, within the meaning of the term “independent” under those standards.

3. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with the principles and definitions presented in the COGE Handbook.

4. The following table sets forth the evaluated estimated future net revenue (before deducting 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 Husky evaluated for the year ended December 31, 2012 and reported to the Audit Committee of the Board of Directors:

Location of Reserves (Country or Foreign Geographic Area)	Proved Plus Probable Net Present Value of Future Net Revenue (Before Income Taxes, 10% Discount Rate) ($ millions)
Canada	$	22,956
China	$	4,127
Indonesia	$	265
Libya	$	8
	$	27,356

5. In our opinion, the reserves data evaluated by us have, in all material respects, been determined in accordance with the principles and definitions presented in the COGE Handbook.

6. We have no responsibility to update our evaluation for events and circumstances occurring after the date of this report.

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

/s/ Frederick Au-Yeung

Frederick Au-Yeung, P. Eng

Manager, Reserves

Calgary, Alberta

January 28, 2013

AIF 2012 Page 99 

Schedule C

Husky Energy Inc.

Report of Management and Directors on Oil and Gas Disclosure

Management of Husky Energy Inc. (“Husky”) 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 which are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2012, estimated using forecast prices and costs.

Husky’s oil and gas reserves evaluation process involves applying generally accepted procedures for the estimation of oil and gas reserves data for the purposes of complying with the legal requirements of NI 51-101. Husky’s internal qualified reserves evaluator is the Manager of Reservoir Engineering, who is an employee of Husky and has evaluated Husky’s oil and gas reserves data and certified that Husky’s reserves data process has been followed. The Report on Reserves Data by Husky’s internal qualified reserves evaluator accompanies this report and will be filed with securities regulatory authorities concurrently with this report.

The Audit Committee of the Board of Directors has:

(a) reviewed Husky’s procedures for providing information to the internal qualified reserves evaluator and the independent qualified reserves auditors;

(b) met with the internal qualified reserves evaluator and external reserves auditors to determine whether any restrictions placed by management affected the ability of the internal qualified reserves evaluator and the independent qualified auditors to report without reservation; and

(c) reviewed the reserves data with management, the internal qualified reserves evaluator and the independent qualified reserves auditors.

The Audit Committee of the Board of Directors has reviewed Husky’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 approved, on the recommendation of the Audit Committee:

(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 on Reserves Data of Husky’s internal qualified reserves evaluator; and

(c) the content and filing of this report.

Husky sought and was granted by the Canadian Securities Administrators an exemption from the requirement under National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” to involve independent qualified oil and gas reserves evaluators or auditors. Notwithstanding this exemption, we involve independent qualified reserves auditors as part of Husky’s corporate governance practices. Their involvement helps assure that our internal oil and gas reserves estimates are materially correct.

In Husky’s view, the reliability of Husky’s internally generated oil and gas reserves data is not materially less than would be afforded by Husky involving independent qualified reserves evaluators or independent qualified reserves auditors to evaluate or audit and review the reserves data. The primary factors supporting the involvement of independent qualified reserves evaluators or independent qualified reserves auditors apply when (i) their knowledge of, and experience with, a reporting issuer’s reserves data are superior to that of the internal reserves evaluators and (ii) the work of the independent qualified reserves evaluator or independent qualified reserves auditors is significantly less likely to be adversely influenced by self-interest or management of the reporting issuer than the work of internal reserves evaluation staff. In Husky’s view, neither of these factors applies in Husky’s circumstances.

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

AIF 2012 Page 100 

/s/ Asim Ghosh	March 8, 2013
Asim Ghosh
President & Chief Executive Officer
/s/ Rob Peabody	March 8, 2013
Rob Peabody
Chief Operating Officer
/s/ William Shurniak	March 8, 2013
William Shurniak
Director
/s/ Colin S. Russel	March 8, 2013
Colin S. Russel
Director

AIF 2012 Page 101 

Schedule D

Husky Energy Inc.

Independent Engineer’s Audit Opinion

Husky Energy Inc.

707 – 8th Avenue S.W.

Calgary, Alberta

T2P 3G7

To Whom It May Concern:

Pursuant to Husky’s request we have conducted an audit of the reserves estimates and the respective net present value of these reserves of Husky Energy Inc., as at December 31, 2012. The Company’s detailed reserves information were provided to us for this audit. Our responsibility is to express an independent opinion on the reserves and the respective present worth value estimates, in the aggregate, based on our audit tests and procedures.

We conducted our audit in accordance with generally accepted audit standards as recommended by the Society of Petroleum Engineers and as recommended in the Canadian Oil and Gas Evaluation Handbook (COGEH) Volume 1 Section 12. Those standards require that we review and assess the policies, procedures, documentation and guidelines of the Company with respect to the estimation, review and approval of Husky’s reserves information. An audit includes examining, on a test basis, to confirm that there is adherence on the part of Husky’s internal reserves evaluators and other employees to the reserves management and administration policies and procedures established by the Company. An audit also includes conducting reserves evaluation on a sufficient number of the Company’s properties as considered necessary in order to express an opinion.

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 Canadian Oil and Gas Evaluation 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 in the attached table.

Sincerely,

McDaniel & Associates Consultants Ltd.

/s/ B. J. Wurster, P. Eng.

B. J. Wurster, P. Eng.

Vice President

Calgary, Alberta

January 21, 2013

AIF 2012 Page 102 

Total Company Reserve and Net Present Value

Forecast Prices and Costs as at December 31, 2012

	Company Share of  Remaining Reserves (mmbbls, bcf, mmboe)				Company share of Net Present Value Before Income Tax (MM$)
	Gross		Net		0%		5%		10%		15%		20%
Proved
Developed Producing
Light Crude Oil		145		126		7,769		5,608		4,563		3,902		3,434
Medium Crude Oil		86		77		1,817		1,790		1,463		1,221		1,046
Heavy Crude Oil		69		62		1,094		1,407		1,389		1,330		1,265
Natural Gas		1,586		1,397		3,913		2,854		2,130		1,687		1,397
Coal Bed Methane		22		21		33		26		21		18		15
Bitumen		59		55		1,957		1,686		1,474		1,321		1,204
Natural Gas Liquids(1)		64		50		—		—		—		—		—
Total		691		605		16,584		13,371		11,041		9,478		8,362
Developed Non-Producing
Light Crude Oil		3		3		201		102		64		47		37
Medium Crude Oil		2		2		77		56		45		37		32
Heavy Crude Oil		15		14		633		517		440		381		336
Natural Gas		104		95		302		201		150		120		99
Coal Bed Methane		1		1		2		1		1		1		1
Bitumen		—		—		—		—		—		—		—
Natural Gas Liquids(1)		1		1		—		—		—		—		—
Total		38		35		1215		878		700		586		505
Undeveloped
Light Crude Oil		24		20		885		655		516		422		356
Medium Crude Oil		7		7		262		170		115		80		56
Heavy Crude Oil		22		20		656		485		368		283		219
Natural Gas		793		732		4,509		3,345		2,636		2,144		1,778
Coal Bed Methane		—		—		—		—		—		—		—
Bitumen		252		217		5,838		3,309		1,959		1,168		669
Natural Gas Liquids(1)		25		19		—		—		—		—		—
Total		463		405		12,149		7,963		5,594		4,098		3,077
Total Proved
Light Crude Oil		173		150		8,855		6,365		5,143		4,371		3,827
Medium Crude Oil		95		85		2,156		2,016		1,623		1,338		1,134
Heavy Crude Oil		105		95		2,383		2,410		2,197		1,994		1,820
Natural Gas		2,484		2,223		8,723		6,400		4,916		3,951		3,274
Coal Bed Methane		23		22		35		27		22		18		16
Bitumen		311		271		7,795		4,995		3,434		2,489		1,873
Natural Gas Liquids(1)		90		70		—		—		—		—		—
Total		1,192		1,045		29,948		22,213		17,335		14162		11,944
Probable
Developed Producing
Light Crude Oil		96		78		5,916		3,503		2,582		2,069		1,727
Medium Crude Oil		22		19		1,246		751		515		380		294
Heavy Crude Oil		35		31		1,223		875		658		510		403
Natural Gas		752		681		5,695		3,355		2,219		1,553		1,129
Coal Bed Methane		6		6		5		4		2		1		1
Bitumen		1,414		1,118		42,361		11,530		4,044		1,607		625
Natural Gas Liquids(1)		30		24		—		—		—		—		—
Total		1,723		1,383		56,446		20,017		10,021		6,121		4,179
Total Proved Plus Probable
Light Crude Oil		268		227		14,771		9,868		7,725		6,440		5,553
Medium Crude Oil		117		103		3,402		2,767		2,139		1,718		1,428
Heavy Crude Oil		140		126		3,606		3,285		2,855		2,504		2,223
Natural Gas		3,236		2,905		14,418		9,754		7,135		5,505		4,403
Coal Bed Methane		29		27		41		31		24		20		17
Bitumen		1,725		1,390		50,155		16,525		7,478		4,096		2,498
Natural Gas Liquids(1)		120		94		—		—		—		—		—
Total		2,915		2,429		86,393		42,230		27,356		20,283		16,123

⁽¹⁾  Natural Gas Liquid volumes are identified separately but the value is included with the Natural Gas.

AIF 2012 Page 103 

Document B

Form 40-F

Consolidated Financial Statements and

Auditors’ Report to Shareholders

For the Year Ended December 31, 2012

INDEPENDENT AUDITORS’ REPORT OF

REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of Husky Energy Inc.

We have audited the accompanying consolidated financial statements of Husky Energy Inc., which comprise the consolidated balance sheets as at December 31, 2012 and December 31, 2011, the consolidated statements of income, comprehensive income, changes in shareholders’ equity and cash flows for the years then ended, and notes, comprising a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Husky Energy Inc. as at December 31, 2012 and December 31, 2011, and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Other Matter

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Husky Energy Inc.’s internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 27, 2013 expressed an unmodified (unqualified) opinion on the effectiveness of Husky Energy Inc.’s internal control over financial reporting.

/s/ KPMG LLP

KPMG LLP

Chartered Accountants

February 27, 2013

Calgary, Canada

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of Husky Energy Inc.

We have audited Husky Energy Inc.’s (“the Company”) internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). 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 Report. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 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.

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.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2012 and December 31, 2011, and the related consolidated statements of income, comprehensive income, changes in shareholders’ equity and cash flows for each of the years in the two-year period ended December 31, 2012, and our report dated February 27, 2013 expressed an unmodified (unqualified) opinion on those consolidated financial statements.

/s/ KPMG LLP

KPMG LLP

Chartered Accountants

February 27, 2013

Calgary, Canada

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, 2012. 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 Canadian Auditing Standards and 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.

Asim Ghosh

President and Chief Executive Officer

Alister Cowan

Chief Financial Officer

Calgary, Canada

February 27, 2013

Consolidated Financial Statements

1

INDEPENDENT AUDITORS’ REPORT

To the Shareholders and Board of Directors of Husky Energy Inc.

We have audited the accompanying consolidated financial statements of Husky Energy Inc., which comprise the consolidated balance sheets as at December 31, 2012 and December 31, 2011, the consolidated statements of income, comprehensive income, changes in shareholders’ equity and cash flows for the years then ended, and notes, comprising a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Husky Energy Inc. as at December 31, 2012 and December 31, 2011, and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

KPMG LLP

Chartered Accountants

Calgary, Canada

February 27, 2013

Consolidated Financial Statements

2

CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Balance Sheets

(millions of Canadian dollars)	December 31, 2012			December 31, 2011
Assets
Current assets
Cash and cash equivalents (note 9)		2,025			1,841
Accounts receivable (note 4)		1,349			1,235
Income taxes receivable		323			273
Inventories (note 5)		1,736			2,059
Prepaid expenses		64			36
		5,497			5,444
Exploration and evaluation assets (note 6)		810			746
Property, plant and equipment, net (note 7)		27,399			24,279
Goodwill (note 10)		663			674
Contribution receivable (note 8)		607			1,147
Other assets		164			136
Total Assets		35,140			32,426
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities (note 12)		2,986			2,867
Asset retirement obligations (note 16)		107			116
Long-term debt due within one year (note 13)		—			407
		3,093			3,390
Long-term debt (note 13)		3,918			3,504
Other long-term liabilities (note 15)		331			342
Contribution payable (note 8, 22)		1,336			1,437
Deferred tax liabilities (note 17)		4,615			4,329
Asset retirement obligations (note 16)		2,686			1,651
Commitments and contingencies (note 20)
Total Liabilities		15,979			14,653
Shareholders’ equity
Common shares (note 18)		6,939			6,327
Preferred shares (note 18)		291			291
Retained earnings		11,950			11,097
Other reserves		(19	)		58
Total Shareholders’ Equity		19,161			17,773
Total Liabilities and Shareholders’ Equity		35,140			32,426

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

On behalf of the Board:

Asim Ghosh	William Shurniak
Director	Director

Consolidated Financial Statements

3

Consolidated Statements of Income

(millions of Canadian dollars, except share data)	Year ended December 31,
	2012			2011
Gross revenues (note 3)		22,741			22,992
Royalties		(693	)		(1,125	)
Marketing and other (note 3)		387			90
Revenues, net of royalties		22,435			21,957
Expenses
Purchases of crude oil and products (note 3)		13,596			12,903
Production and operating expenses		2,612			2,476
Selling, general and administrative expenses		451			428
Depletion, depreciation, amortization and impairment (note 7)		2,580			2,519
Exploration and evaluation expenses (note 6)		350			470
Other – net (note 3)		(123	)		(193	)
		19,466			18,603
Earnings from operating activities		2,969			3,354
Financial items (note 14)
Net foreign exchange gains		14			10
Finance income		93			86
Finance expenses		(240	)		(310	)
		(133	)		(214	)
Earnings before income taxes		2,836			3,140
Provisions for income taxes (note 17)
Current		536			354
Deferred		278			562
		814			916
Net earnings		2,022			2,224
Earnings per share (note 18)
Basic		2.06			2.40
Diluted		2.06			2.34
Weighted average number of common shares outstanding (note 18)
Basic (millions)		975.8			923.8
Diluted (millions)		975.9			932.0

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

Consolidated Financial Statements

4

Consolidated Statements of Comprehensive Income

	Year ended December 31,
(millions of Canadian dollars)	2012			2011
Net earnings		2,022			2,224
Other comprehensive income (loss)
Items that will not be reclassified into earnings, net of tax:
Actuarial gains (losses) on pension plans (note 19)		15			(20	)
Items that may be reclassified into earnings, net of tax:
Derivatives designated as cash flow hedges (note 22)		3			—
Exchange differences on translation of foreign operations		(95	)		88
Hedge of net investment (note 22)		15			(18	)
Other comprehensive income (loss)		(62	)		50
Comprehensive income		1,960			2,274

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

Consolidated Financial Statements

5

Consolidated Statements of Changes in Shareholders’ Equity

	Attributable to Equity Holders
										Other Reserves
(millions of Canadian dollars)	Common Shares (note 18)			Preferred Shares (note  18)			Retained Earnings			Foreign Currency Translation			Hedging (note 22)			Total Shareholders’ Equity
Balance as at December 31, 2010		4,574			—			10,012			(10	)		(2	)		14,574
Net earnings		—			—			2,224			—			—			2,224
Other comprehensive income
Actuarial losses on pension plans (net of tax of $8 million)		—			—			(20	)		—			—			(20	)
Exchange differences on translation of foreign operations (net of tax of $14 million)		—			—			—			88			—			88
Hedge of net investment (net of tax of $3 million) (note 22)		—			—			—			(18	)		—			(18	)
Total comprehensive income		—			—			2,204			70			—			2,274
Transactions with owners recognized directly in equity:
Issue of common shares		1,200			—			—			—			—			1,200
Share issue costs		(27	)		—			—			—			—			(27	)
Issue of preferred shares		—			300			—			—			—			300
Share issue costs		—			(9	)		—			—			—			(9	)
Stock dividends paid		580			—			—			—			—			580
Dividends declared on common shares (note 18)		—			—			(1,109	)		—			—			(1,109	)
Dividends declared on preferred shares (note 18)		—			—			(10	)		—			—			(10	)
Balance as at December 31, 2011		6,327			291			11,097			60			(2	)		17,773
Net earnings		—			—			2,022			—			—			2,022
Other comprehensive income (loss)
Actuarial gains on pension plans (net of tax of $5 million)		—			—			15			—			—			15
Derivatives designated as cash flow hedges (net of tax of $1 million)		—			—			—			—			3			3
Exchange differences on translation of foreign operations (net of tax of $12 million)		—			—			—			(95	)		—			(95	)
Hedge of net investment (net of tax of $2 million) (note 22)		—			—			—			15			—			15
Total comprehensive income (loss)		—			—			2,037			(80	)		3			1,960
Transactions with owners recognized directly in equity:
Stock dividends paid		607			—			—			—			—			607
Stock options exercised		5			—			—			—			—			5
Dividends declared on common shares (note 18)		—			—			(1,171	)		—			—			(1,171	)
Dividends declared on preferred shares (note 18)		—			—			(13	)		—			—			(13	)
Balance as at December 31, 2012		6,939			291			11,950			(20	)		1			19,161

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

Consolidated Financial Statements

6

Consolidated Statements of Cash Flows

	Year ended December 31,
(millions of Canadian dollars)	2012			2011
Operating activities
Net earnings		2,022			2,224
Items not affecting cash:
Accretion (note 14)		97			79
Depletion, depreciation, amortization and impairment (note 7)		2,580			2,519
Exploration and evaluation expenses		60			68
Deferred income taxes (note 17)		278			562
Foreign exchange		(20	)		14
Stock-based compensation (note 18)		54			(1	)
Loss (gain) on sale of assets		1			(261	)
Other		(62	)		(6	)
Settlement of asset retirement obligations (note 16)		(123	)		(105	)
Income taxes paid		(575	)		(282	)
Interest received		34			12
Change in non-cash working capital (note 9)		843			269
Cash flow – operating activities		5,189			5,092
Financing activities
Long-term debt issuance (note 13)		500			5,054
Long-term debt repayment (note 13)		(410	)		(5,434	)
Settlement of cross currency swaps		(89	)		—
Debt issue costs		(9	)		(5	)
Proceeds from common share issuance, net of share issue costs (note 18)		—			1,173
Proceeds from preferred share issuance, net of share issue costs (note 18)		—			291
Proceeds from exercise of stock options (note 18)		5			—
Dividends on common shares (note 18)		(557	)		(495	)
Dividends on preferred shares (note 18)		(17	)		(7	)
Interest paid		(252	)		(229	)
Contribution receivable payment (note 8)		563			234
Other		25			90
Change in non-cash working capital (note 9)		79			238
Cash flow – financing activities		(162	)		910
Investing activities
Capital expenditures		(4,701	)		(4,800	)
Proceeds from asset sales		24			179
Contribution payable payment (note 8)		(152	)		(103	)
Other		(57	)		(12	)
Change in non-cash working capital (note 9)		56			316
Cash flow – investing activities		(4,830	)		(4,420	)
Increase in cash and cash equivalents		197			1,582
Effect of exchange rates on cash and cash equivalents		(13	)		7
Cash and cash equivalents at beginning of year		1,841			252
Cash and cash equivalents at end of year		2,025			1,841

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

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 and preferred shares are listed on the Toronto Stock Exchange (“TSX”) under the symbol “HSE” and “HSE.PR.A”, 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.

During the first quarter of 2012, the Company completed an evaluation of activities of the Company’s former Midstream segment as a service provider to the Upstream or Downstream operations. As a result, and consistent with the Company’s strategic view of its integrated business, the previously reported Midstream segment activities are now aligned and reported within the Company’s core exploration and production, or in its upgrading and refining businesses. The Company believes this change in segment presentation allows management and third parties to more effectively assess the Company’s performance.

Upstream includes exploration for, and development and production of, crude oil, bitumen, natural gas and natural gas liquids (Exploration and Production) and marketing of the Company’s and other producers’ crude oil, natural gas, natural gas liquids, sulphur and petroleum coke, pipeline transportation and blending of crude oil and natural gas and storage of crude oil, diluent and natural gas (Infrastructure and Marketing). The Company’s Upstream operations are located primarily in Western Canada, offshore East Coast of Canada, offshore Greenland, offshore China and offshore Indonesia.

Downstream includes upgrading of heavy crude oil feedstock into synthetic crude oil (Upgrading), refining in Canada 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) and refining in the U.S. of primarily crude oil to produce and market gasoline, jet fuel and diesel fuels that meet U.S. clean fuels standards (U.S. Refining and Marketing).

Comparative periods have been reclassified to conform to the revised segment presentation.

Consolidated Financial Statements

8

Segmented Financial Information

	Upstream
($ millions)	Exploration and Production(1)						Infrastructure and Marketing						Total
Year ended December 31,	2012			2011			2012			2011			2012			2011
Gross revenues		6,547			7,519			2,420			1,987			8,967			9,506
Royalties		(693	)		(1,125	)		—			—			(693	)		(1,125	)
Marketing and other		—			—			387			90			387			90
Revenues, net of royalties		5,854			6,394			2,807			2,077			8,661			8,471
Expenses
Purchases of crude oil and products		73			99			2,258			1,818			2,331			1,917
Production and operating expenses		1,840			1,714			49			43			1,889			1,757
Selling, general and administrative expenses		178			153			21			17			199			170
Depletion, depreciation, amortization and impairment		2,121			2,018			22			24			2,143			2,042
Exploration and evaluation expenses		350			470			—			—			350			470
Other – net		(105	)		(261	)		—			1			(105	)		(260	)
Earnings (loss) from operating activities		1,397			2,201			457			174			1,854			2,375
Financial items
Net foreign exchange gains		—			—			—			—			—			—
Finance income		5			4			—			—			5			4
Finance expenses		(78	)		(68	)		—			—			(78	)		(68	)
Earnings (loss) before income taxes		1,324			2,137			457			174			1,781			2,311
Provisions for (recovery of) income taxes
Current		134			41			171			64			305			105
Deferred		211			515			(55	)		(20	)		156			495
Total income tax provision (recovery)		345			556			116			44			461			600
Net earnings (loss)		979			1,581			341			130			1,320			1,711
Intersegment revenues		2,003			2,072			—			—			2,003			2,072
Other material non-cash items
Gain (loss) on sale of assets		1			261			—			—			1			261

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

⁽²⁾  Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices.

⁽³⁾  Certain hydrogen feedstock costs from production and operating expenses have been reclassified to purchases of crude oil and products in 2012. Prior periods have been reclassified to conform with current period presentation.

Consolidated Financial Statements

9

Downstream																								Corporate and Eliminations(2)						Total
Upgrading(3)						Canadian Refined Products						U.S. Refining and Marketing						Total
2012			2011			2012			2011			2012			2011			2012			2011			2012			2011			2012			2011
	2,191			2,217			3,848			3,877			10,038			9,752			16,077			15,846			(2,303	)		(2,360	)		22,741			22,992
	—			—			—			—			—			—			—			—			—			—			(693	)		(1,125	)
	—			—			—			—			—			—			—			—			—			—			387			90
	2,191			2,217			3,848			3,877			10,038			9,752			16,077			15,846			(2,303	)		(2,360	)		22,435			21,957
	1,636			1,628			3,208			3,265			8,724			8,453			13,568			13,346			(2,303	)		(2,360	)		13,596			12,903
	150			146			184			182			385			391			719			719			4			—			2,612			2,476
	3			3			58			49			13			12			74			64			178			194			451			428
	102			164			83			80			212			195			397			439			40			38			2,580			2,519
	—			—			—			—			—			—			—			—			—			—			350			470
	(17	)		67			(2	)		—			4			—			(15	)		67			(3	)		—			(123	)		(193	)
	317			209			317			301			700			701			1,334			1,211			(219	)		(232	)		2,969			3,354
	—			—			—			—			—			—			—			—			14			10			14			10
	—			—			—			—			—			—			—			—			88			82			93			86
	(11	)		(7	)		(6	)		(6	)		(5	)		(4	)		(22	)		(17	)		(140	)		(225	)		(240	)		(310	)
	306			202			311			295			695			697			1,312			1,194			(257	)		(365	)		2,836			3,140
	31			(2	)		89			25			(1	)		76			119			99			112			150			536			354
	49			54			(9)			50			258			178			298			282			(176)			(215)			278			562
	80			52			80			75			257			254			417			381			(64	)		(65	)		814			916
	226			150			231			220			438			443			895			813			(193	)		(300	)		2,022			2,224
	134			120			166			168			—			—			300			288			—			—			2,303			2,360
	—			—			(2	)		—			—			—			(2	)		—			—			—			(1	)		261

Consolidated Financial Statements

10

Segmented Financial Information

	Upstream
($ millions)	Exploration and Production(1)						Infrastructure and Marketing						Total
Year ended December 31,	2012			2011			2012			2011			2012			2011
Expenditures on exploration and evaluation assets(3)		273			403			—			—			273			403
Expenditures on property, plant and equipment(3)		3,833			3,728			54			43			3,887			3,771
As at December 31,
Exploration and evaluation assets		810			746			—			—			810			746
Developing and producing assets at cost		38,826			33,640			—			—			38,826			33,640
Accumulated depletion, depreciation, amortization and impairment		(17,947	)		(15,900	)		—			—			(17,947	)		(15,900	)
Other property, plant and equipment at cost		47			48			934			882			981			930
Accumulated depletion, depreciation and amortization		(29	)		(27	)		(414	)		(380	)		(443	)		(407	)
Total exploration and evaluation assets and property, plant and equipment, net		21,707			18,507			520			502			22,227			19,009
Total assets		22,753			20,141			1,506			1,509			24,259			21,650

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

⁽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 assets acquired through acquisitions.

Geographical Financial Information

($ millions)	Canada
Year ended December 31,	2012			2011
Gross revenues		11,365			11,481
Royalties		(611	)		(1,024	)
Marketing and other		386			89
Revenue, net of royalties(1)		11,140			10,546
As at December 31,
Exploration and evaluation assets		496			421
Property, plant and equipment, net		21,718			19,481
Goodwill		160			160
Total non-current assets		23,090			21,315

⁽¹⁾  Based on the geographical location of legal entities.

Consolidated Financial Statements

11

Downstream																								Corporate and Eliminations(2)						Total
Upgrading						Canadian Refined Products						U.S. Refining and Marketing						Total
2012			2011			2012			2011			2012			2011			2012			2011			2012			2011			2012			2011
	—			—			—			—			—			—			—			—			—			—			273			403
	47			55			97			94			313			224			457			373			84			71			4,428			4,215
	—			—			—			—			—			—			—			—			—			—			810			746
	—			—			—			—			—			—			—			—			—			—			38,826			33,640
	—			—			—			—			—			—			—			—			—			—			(17,947	)		(15,900	)
	2,006			1,972			2,189			2,208			4,487			4,325			8,682			8,505			643			557			10,306			9,992
	(950	)		(848	)		(967	)		(1,007	)		(951	)		(759	)		(2,868	)		(2,614	)		(475	)		(432	)		(3,786	)		(3,453	)
	1,056			1,124			1,222			1,201			3,536			3,566			5,814			5,891			168			125			28,209			25,025
	1,242			1,316			1,646			1,632			5,326			5,476			8,214			8,424			2,667			2,352			35,140			32,426

United States				Other International						Total
2012		2011		2012			2011			2012			2011
	11,004		11,201		372			310			22,741			22,992
	—		—		(82	)		(101	)		(693	)		(1,125	)
	1		1		—			—			387			90
	11,005		11,202		290			209			22,435			21,957
	—		—		314			325			810			746
	3,535		3,572		2,146			1,226			27,399			24,279
	503		514		—			—			663			674
	4,055		4,103		2,498			1,564			29,643			26,982

Consolidated Financial Statements

12

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 Chief Executive Officer on February 27, 2013, having been duly authorized to do so by the Board of Directors.

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. Substantially all of the Company’s Upstream activities are conducted jointly with third parties and accordingly the accounts reflect the Company’s proportionate share of the assets, liabilities, revenues, expenses and cash flows from these activities. Intercompany balances, net earnings and unrealized gains and losses arising from intercompany transactions are eliminated in preparing the consolidated financial statements.

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, impairment, asset retirement obligations, assets and liabilities measured at fair value, employee future benefits, income taxes, 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 successful efforts and impairment assessments, the determination of cash generating units (“CGUs”) and the designation of the Company’s functional currency.

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 composition of revenue and costs in the locations in which it operates.

Consolidated Financial Statements

13

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.

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 and transportation. Commodity inventories held for trading purposes are carried at fair value. Any changes in commodity 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. 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 property, plant and equipment 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 which 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.

The appropriate accounting treatment of costs incurred for oil and natural gas exploration and 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 both judgment 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.

ii) Exploration and Evaluation Costs

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

Consolidated Financial Statements

14

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. Technical feasibility and commercial viability are met when management determines that an exploration and evaluation asset will be developed, as evidenced by the classification of proved or probable reserves and the appropriate internal and external approvals. 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 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, including unsuccessful development or delineation 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 next scheduled 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 recoverable reserves is applied. Rights and concessions are depleted on a unit-of-production basis over the total proved reserves of the relevant area. The unit-of-production rate for the depletion of oil and gas properties related to total proved 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 reserves 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 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.

Consolidated Financial Statements

15

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.

Any gain or loss arising on disposal of exploration and evaluation assets or property, plant and equipment is included in other – net in the consolidated statements of income in the period of disposal.

e) Joint Arrangements

Joint arrangements represent activities where the Company has joint control established by a contractual agreement. The consolidated financial statements include the Company’s proportionate share of the assets, liabilities, revenues, expenses and cash flows of the arrangement with items of a similar nature on a line-by-line basis, from the date that joint control commences until the date that joint control ceases.

f) Business Combinations

Business combinations are accounted for using the acquisition method. Determining whether an acquisition meets the definition of a business combination or represents an asset purchase requires judgment on a case by case basis. If the acquisition meets the definition of a business combination, the assets and liabilities are recognized based on the contractual terms, economic conditions, the Company’s operating and accounting policies, and other factors that exist on the acquisition date, which is the date on which control is transferred to the Company. The identifiable assets and liabilities are measured at their fair values on the acquisition date. 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 other – net in the consolidated statements of income.

g) Goodwill

Goodwill is the excess of the purchase price paid over the recognized amount of net assets acquired, 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.

h) Impairment of 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 any indication of impairment. If such indication exists, the recoverable amount is estimated.

Determining whether there are any indications of impairment requires significant judgment of external factors, such as an extended decrease in prices or margins for oil and gas commodities or products, a significant decline in an asset’s market value, a significant downward revision of estimated volumes, an upward revision of future development costs, a decline in the entity’s market capitalization, or significant changes in the technological, market, economic or

Consolidated Financial Statements

16

legal environment that would have an adverse impact on the entity. If any indication of impairment exists, 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 the continued use of the 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 which would be applied by a market participant to arrive at a net present value of the CGU.

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, marketing supply and demand, product margins 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, probable and unproved volumes, which are risk-weighted utilizing geological, production, recovery 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 for other assets in prior years are assessed at the end of each reporting period for any indications that the impairment condition has decreased or no longer exists. An impairment loss is reversed only to the extent that the carrying amount of the asset or CGU does not exceed the carrying amount that would have been determined, net of depletion, depreciation and amortization, if no impairment loss had been recognized.

i) Asset Retirement Obligations (“ARO”)

A liability is recognized for future legal or constructive retirement obligations associated with the Company’s assets. The Company has significant obligations to remove tangible assets and restore land after operations cease and the Company retires or relinquishes the asset. The retirement of Upstream and Downstream assets consists primarily of plugging and abandoning wells, removing and disposing of 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

Consolidated Financial Statements

17

recognized in finance expenses. The costs capitalized to the related assets are amortized in a manner consistent with the depletion, depreciation and amortization of the underlying assets. Actual retirement expenditures are charged against the accumulated liability as incurred.

Liabilities for ARO are adjusted every reporting period for changes in estimates. These adjustments are accounted for as a change in the corresponding capitalized cost, except where a reduction in the provision is greater than the undepreciated capitalized cost of the related assets, in which case the capitalized cost is reduced to nil and the remaining adjustment is recognized in net earnings. In the case of closed sites, changes to estimated costs are recognized immediately in net earnings. Changes to the amount of capitalized costs will result in an adjustment to future depletion, depreciation and amortization, and finance expenses.

Estimating the ARO requires significant judgment as restoration technologies and costs are constantly changing, as are regulatory, political, environmental and safety considerations. Inherent in the calculation of the ARO are numerous assumptions including the ultimate settlement amounts, future third-party pricing, inflation factors, risk free discount rates, credit risk, timing of settlement and changes in the legal, regulatory, environmental and political environments. Future revisions to these assumptions may result in material changes to the ARO liability. Adjustments to the estimated amounts and timing of future ARO cash flows are a regular occurrence in light of the significant judgments and estimates involved.

j) Legal and Other Contingent Matters

Provisions and liabilities for legal and other contingent matters are recognized in the period when the circumstance becomes probable that a future cash outflow resulting from past operations or events will occur and the amount of the cash outflow can be reasonably estimated. The timing of recognition and measurement of the provision requires the application of judgment to existing facts and circumstances, which can be subject to change, and the carrying amounts of provisions and liabilities are 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 provisions when warranted by the circumstances present.

k) Share Capital

Preferred shares are classified as equity since they are cancellable and redeemable only at the Company’s option and dividends are discretionary and payable only if declared by the Board of Directors. Incremental costs directly attributable to the issuance of shares and stock options are recognized as a deduction from equity, net of tax. Common share dividends are paid out in common shares or in cash, and preferred share dividends are paid in cash. Both common and preferred share dividends are recognized as distributions within equity.

l) Financial Instruments

Financial instruments are any contracts that give rise to a financial asset of one entity and a financial liability or equity instrument of another entity. Financial instruments are initially recognized at fair value, and subsequently measured based on classification in one of the following categories: loans and receivables, held to maturity investments, other financial liabilities, fair value through profit or loss (“FVTPL”) or available-for-sale (“AFS”) financial assets.

Financial instruments classified as FVTPL or AFS are measured at fair value at each reporting date; any transaction costs associated with these types of instruments are expensed as incurred. Unrealized gains and losses on AFS financial assets are recognized in other comprehensive income (“OCI”) and transferred to net earnings when the asset is derecognized. 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.

Consolidated Financial Statements

18

Financial instruments classified as loans or receivables, held to maturity investments and other financial liabilities are initially measured at fair value and subsequently carried at amortized cost using the effective interest rate method. Transaction costs that are directly attributable to the acquisition or issue of a financial instrument measured at amortized cost are added to the fair value initially recognized.

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.

m) Derivative Instruments and Hedging Activities

Derivatives are financial instruments for which the fair value changes in response to market risks, require little or no initial investment and are settled at a future date. Derivative instruments are utilized by the Company to manage various market risks including volatility in commodity prices, foreign exchange rates and interest rate exposures. The Company’s policy is not to utilize derivative instruments for speculative purposes. The Company may enter into swap and other derivative transactions to hedge or mitigate the Company’s commercial risk, including derivatives that reduce risks that arise in the ordinary course of the Company’s business. The Company may choose to apply hedge accounting to derivative instruments.

The fair values of derivatives are determined using valuation models which require assumptions concerning the amount and timing of future cash flows and discount rates. These estimates are also subject to change with fluctuations in commodity prices, interest rates, foreign currency exchange rates and estimates of non-performance. The actual settlement of a derivative instrument could differ materially from the fair value recorded and could impact future results.

i) Derivative Instruments

All derivative instruments, other than those designated as effective hedging instruments, are classified as FVTPL – held for trading and are recorded on the balance sheet 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 to offset fixed or floating price contracts entered into with customers and suppliers to retain market prices while meeting customer or supplier pricing requirements. The estimation of the fair value of commodity derivatives and the related inventory incorporates forward prices and adjustments for quality or location. Gains and losses from these 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 and are recorded on the balance sheet as set forth below under “Hedging Activities.”

ii) Embedded Derivatives

Derivatives embedded in a host contract 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 other 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, the Company formally documents the designation of the hedge, the risk management objectives, the hedging relationships between the hedged items and the hedging items, and the method for testing the effectiveness of the hedge, which must be reasonably assured over the term of the derivative transaction. This process includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions.

Consolidated Financial Statements

19

The Company formally assesses, both at the inception of the hedge and at each reporting date, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of the hedged items. For fair value hedges, the gains or losses arising from adjusting the derivative to its fair value are recognized immediately in net earnings along with the offsetting gain or loss on the hedged item. For cash flow hedges, the effective portion of the gains and losses is recorded in OCI until the hedged transaction is recognized in net earnings. Any hedge ineffectiveness is immediately recognized in net earnings. When the hedged transaction is recognized in net earnings, the fair value of the associated cash flow hedging item is reclassified from other reserves into net earnings. Hedge accounting is discontinued on a prospective basis when the hedging relationship no longer qualifies for hedge accounting.

When a fair value hedging relationship is discontinued as a result of discontinuing the hedging instrument, any gain or loss on the hedging instrument is deferred and amortized to net earnings over the remaining maturity of the hedged item. Any gain or loss on the hedging instrument resulting from the discontinuation of a cash flow hedging relationship 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.

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.

The Company may enter into interest rate swap agreements to hedge its fixed and floating interest rate mix on long-term debt. The estimated fair value of interest rate hedges is determined primarily through forward market prices and compared with quotes from financial institutions. Gains and losses from these contracts are recognized as an adjustment to finance expense on the hedged debt instrument.

The Company may also enter into interest rate swap agreements to fix interest rates on a highly probable forecasted issuance of long-term debt. The estimated fair value of forward starting swaps is determined primarily using forward market prices. The effective portion of gains and losses on these instruments is recorded in OCI and is adjusted for changes in the fair value of the instrument until the forecasted transaction occurs.

The Company may enter into foreign exchange contracts to hedge its foreign currency exposures on U.S. dollar denominated long-term debt. The estimated fair value of forward purchases of U.S. dollars is determined primarily using forward market prices. Gains and losses on these instruments related to foreign exchange are recorded in foreign exchange gains or losses in the period to which they relate, offsetting the respective foreign exchange gains and losses recognized on the underlying foreign currency long-term debt. The remaining portion of the gain or loss is recorded in OCI and is adjusted for changes in the fair value of the instrument over the life of the debt.

The Company may enter into foreign exchange forwards and foreign exchange collars to hedge anticipated U.S. dollar denominated crude oil and natural gas sales. The estimate of fair value for foreign currency hedges is determined primarily through forward market prices and compared with quotes from financial institutions. Gains and losses on these instruments are recognized in Upstream oil and gas revenues when the sale is recorded.

n) 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 unrealized gains and losses on AFS financial assets, the exchange gains and losses arising from the translation of foreign operations 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.

Consolidated Financial Statements

20

o) Impairment of Financial Assets

A financial asset is assessed at the end of each reporting period to determine whether it is impaired based on objective evidence indicating that one or more events have had a negative effect on the estimated future cash flows of that asset. Objective evidence used by the Company to assess impairment of financial assets includes quoted market prices for similar financial assets and historical collection rates for loans and receivables.

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. An impairment loss with respect to an AFS financial asset is calculated by reference to its fair value and any amounts in OCI are transferred to net earnings.

Significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed 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 requires the use of estimates and assumptions, including forecasts of commodity prices, marketing supply and demand, product margins and expected production volumes, it is possible that the assumptions may change, which may require a material adjustment to the carrying value of financial assets.

p) Pensions and Other Post-employment Benefits

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 defined contribution pension plans (401(k)), a defined benefit pension plan and other post-retirement benefits.

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.

Past service costs are recognized in the benefit cost on a straight-line basis over the average period until the benefits become vested. The past service costs are recognized as an expense immediately following the introduction of, or changes to, the pension plans.

The defined benefit asset or liability is comprised of the present value of the defined benefit obligation, less past service costs and the fair value of plan assets from which the obligations are to be settled. 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.

Consolidated Financial Statements

21

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 plans.

The determination of the cost of the defined benefit pension plans 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 who is 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.

Mortality rates are based on the latest available standard mortality tables for the individual countries concerned. The assumptions for each country are reviewed each year and are adjusted where necessary to reflect changes in fund experience and actuarial recommendations. The rate of return on pension plan assets is based on a projection of real long-term bond yields and an equity risk premium, which are combined with local inflation assumptions and applied to the actual asset mix of each plan. The amount of the expected return on plan assets is calculated using the expected rate of return for the year and the fair value of assets at the beginning of the year. Future salary increases are based on expected future inflation rates for the individual countries.

q) Income Taxes

Current income taxes are recognized in net earnings except when they relate to equity, which includes OCI, and are recognized directly in equity. Management periodically evaluates positions taken in the Company’s tax returns with respect to situations in which applicable tax regulations are subject to interpretation and reassessment and establishes provisions where appropriate.

Deferred tax is measured using the liability method on temporary differences at the reporting date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes.

Deferred tax assets and liabilities are recognized at expected tax rates in effect in the year when the asset is expected to be realized or the liability settled, based on tax rates and tax laws that have been enacted or substantively enacted at the reporting date. Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net 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. Significant estimations are also made with respect to the timing of temporary difference reversals, the realizability of tax assets and in circumstances where transaction and calculations for which the ultimate tax determination are uncertain. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management.

r) Asset Exchange Transactions

Asset exchange transactions are measured at cost if the transaction lacks commercial substance or the fair value of neither the asset received nor the asset given up is reliably measurable. Otherwise, asset exchange transactions are measured at the fair value of the asset given up, unless the fair value of the asset received is more clearly evident. If the acquired item is not measured at fair value, its cost is measured at the carrying amount of the asset given up. Gains and losses are recorded in other – net in the consolidated statements of income in the period they occur.

Consolidated Financial Statements

22

s) Revenue Recognition

Revenue from the sale of goods is recognized when the significant risks and rewards of ownership have passed to the buyer and it can be reliably measured. Revenues associated with the sale of crude oil, natural gas, natural gas liquids, synthetic crude oil, purchased commodities and refined petroleum products are recognized when the title passes to the customer. Revenues associated with the sale of transportation, processing and natural gas storage services are recognized when the services are provided.

Revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for goods provided in the normal course of business, net of discounts, customs duties and sales taxes. Crude oil and natural gas sold below or above the Company’s working interest share of production results in production underlifts or overlifts. Underlifts are recorded as a receivable at cost with a corresponding decrease to production and operating expense while overlifts are recorded as a payable at fair value with a corresponding increase to production and operating expense.

Physical exchanges of inventory 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.

Finance income is recognized as the interest accrues using the effective interest rate, which is the rate that exactly discounts estimated future cash receipts through the expected life of the financial instrument to the net carrying amount of the financial asset.

t) Foreign Currency

Functional currency is the currency of the primary economic environment in which the Company and its subsidiaries operate and is normally the currency in which the entity primarily generates and expends cash. The financial statements of Husky’s subsidiaries are translated into Canadian dollars, which is the presentation and functional currency of the Company. The assets and liabilities of subsidiaries whose functional currencies are other than Canadian dollars are translated into Canadian dollars at the foreign exchange rate at the balance sheet date, while revenues and expenses of such subsidiaries are translated using average monthly foreign exchange rates, which approximate the foreign exchange rates on the dates of the transactions. Foreign exchange differences arising on translation are included in OCI.

The Company’s transactions in foreign currencies are translated to the appropriate functional currency at the foreign exchange rate on the date of the transaction. 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 date of the transactions.

u) Share-based Payments

In accordance with the Company’s stock option plan, stock options to acquire common shares may be granted to officers and certain other employees. The Company records compensation expense over the vesting period based on the fair value of options granted. Compensation expense is recorded in net 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 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.

Consolidated Financial Statements

23

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 is contingent on the Company’s total shareholder return relative to a peer group of companies. A liability for expected cash payments is accrued over the vesting period of the PSUs and is revalued at each reporting date based on the market price of the Company’s common shares and the expected vesting percentage. Upon vesting, a cash payment is made to the participants and the outstanding liability is reduced by the payment amount.

v) 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 receivable. 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 dilutive potential common shares, which are comprised of share 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.

w) Government Grants

Government grants are recognized when there is reasonable assurance that the grant will be received and all attached conditions will be complied with. If a grant is received but reasonable assurance and compliance with conditions is not achieved, the grant is recognized as a deferred liability until such conditions are fulfilled. When the grant relates to an expense item, it is recognized as income in the period in which the costs are incurred. Where the grant relates to an asset, it is recognized as a reduction to the net book value of the related asset and recognized in net earnings in equal amounts over the expected useful life of the related asset through lower depletion, depreciation and amortization.

Consolidated Financial Statements

24

x) Recent Accounting Standards

i) Consolidated Financial Statements

In May 2011, the IASB published IFRS 10, “Consolidated Financial Statements,” which provides a single model to be applied in the assessment of control for all entities in which the Company has an investment including special purpose entities currently in the scope of Standing Interpretations Committee (“SIC”) 12. Under the new control model, the Company has control over an investment if the Company has the ability to direct the activities of the investment, is exposed to the variability of returns from the investment and there is a link between the ability to direct activities and the variability of returns. IFRS 10 is effective for the Company on January 1, 2013 with required retrospective application and early adoption permitted. The Company intends to retrospectively adopt IFRS 10 on January 1, 2013. The adoption of the standard is not expected to have a material impact on the Company’s financial statements.

ii) Joint Arrangements

In May 2011, the IASB published IFRS 11, “Joint Arrangements,” whereby joint arrangements are classified as either joint operations or joint ventures. Parties to a joint operation retain the rights and obligations to individual assets and liabilities of the operation, while parties to a joint venture have rights to the net assets of the venture. Joint operations shall be accounted for in a manner consistent with jointly controlled assets and operations whereby the Company’s contractual share of the arrangement’s assets, liabilities, revenues and expenses is included in the consolidated financial statements. Any arrangement structured through a separate vehicle that does effectively result in separation between the Company and the arrangement shall be classified as a joint venture and accounted for using the equity method of accounting. Under the existing IFRS standard, the Company has the option to account for any interests it has in joint arrangements using proportionate consolidation or equity accounting. IFRS 11 is effective for the Company on January 1, 2013 with required retrospective application and early adoption permitted. The Company intends to retrospectively adopt IFRS 11 on January 1, 2013. The adoption of the standard is not expected to have a material impact on the Company’s financial statements.

iii) Disclosure of Interests in Other Entities

In May 2011, the IASB published IFRS 12, “Disclosure of Interests in Other Entities,” which contains new disclosure requirements for interests the Company has in subsidiaries, joint arrangements, associates and unconsolidated structured entities. Required disclosures aim to provide readers of the financial statements with information to evaluate the nature of and risks associated with the Company’s interests in other entities and the effects of those interests on the Company’s financial statements. IFRS 12 is effective for the Company on January 1, 2013 with required retrospective application and early adoption permitted. The Company intends to retrospectively adopt IFRS 12 on January 1, 2013. The adoption of the standard is not expected to have a material impact on the Company’s financial statements.

iv) Investments in Associates and Joint Ventures

In May 2011, the IASB issued amendments to IAS 28, “Investments in Associates and Joint Ventures,” which provides additional guidance applicable to accounting for interests in joint ventures or associates when a portion of an interest is classified as held for sale or when the Company ceases to have joint control or significant influence over an associate or joint venture. When joint control or significant influence over an associate or joint venture ceases, the Company will no longer be required to remeasure the investment at that date. When a portion of an interest in a joint venture or associate is classified as held for sale, the portion not classified as held for sale shall be accounted for using the equity method of accounting until the sale is completed at which time the interest is reassessed for prospective accounting treatment. Amendments to IAS 28 are effective for the Company on January 1, 2013 with required retrospective application and early adoption permitted. The Company intends to retrospectively adopt these amendments on January 1, 2013. The Company does not expect the amendments to IAS 28 to have a material impact on the Company’s financial statements.

Consolidated Financial Statements

25

i) Fair Value Measurement

In May 2011, the IASB published IFRS 13, “Fair Value Measurement,” which provides a single source of fair value measurement guidance and replaces fair value measurement guidance contained in individual IFRSs. The standard provides a framework for measuring fair value and establishes new disclosure requirements to enable readers to assess the methods and inputs used to develop fair value measurements, for recurring valuations that are subject to measurement uncertainty, and for the effect of those measurements on the financial statements. IFRS 13 is effective for the Company on January 1, 2013 with required prospective application and early adoption permitted. The Company intends to adopt IFRS 13 on January 1, 2013. The adoption of the standard is not expected to have a material impact on the Company’s financial statements.

vi) Employee Benefits

In June 2011, the IASB issued amendments to IAS 19, “Employee Benefits” to eliminate the corridor method that permits the deferral of actuarial gains and losses, to revise the presentation requirements for changes in defined benefit plan assets and liabilities and to enhance the required disclosures for defined benefit plans. Amendments to IAS 19 are effective for the Company on January 1, 2013 with required retrospective application and early adoption permitted. The Company intends to retrospectively adopt these amendments on January 1, 2013. The adoption of the amended standard is not expected to have a material impact on the Company’s financial statements.

vii) Offsetting Financial Assets and Financial Liabilities

In December 2011, the IASB issued amendments to IFRS 7, “Financial Instruments: Disclosures” and IAS 32, “Financial Instruments: Presentation” to clarify the current offsetting model and develop common disclosure requirements to enhance the understanding of the potential effects of offsetting arrangements. Amendments to IFRS 7 are effective for the Company on January 1, 2013 with required retrospective application and early adoption permitted. Amendments to IAS 32 are effective for the Company on January 1, 2014 with required retrospective application and early adoption permitted. The Company intends to retrospectively adopt the IFRS 7 amendments on January 1, 2013 and the IAS 32 amendments on January 1, 2014. The adoption of these amended standards is not expected to have a material impact on the Company’s financial statements.

viii) Financial Instruments

In November 2009, the IASB published IFRS 9, “Financial Instruments,” which covers the classification and measurement of financial assets as part of its project to replace IAS 39, “Financial Instruments: Recognition and Measurement.” In October 2010, the requirements for classifying and measuring financial liabilities were added to IFRS 9. Under this guidance, entities have the option to recognize financial liabilities at fair value through profit or loss. If this option is elected, entities would be required to reverse the portion of the fair value change due to their own credit risk out of net earnings and recognize the change in OCI. IFRS 9 is effective for the Company on January 1, 2015 with required retrospective application and early adoption permitted. The Company intends to retrospectively adopt the amendments on January 1, 2015. The adoption of the standard is not expected to have a material impact on the Company’s financial statements.

y) Change in Presentation of Trading Activities

During the first quarter of 2012, the Company completed a review of the trading activities within its Infrastructure and Marketing segment and determined that the realized and the unrealized gains and losses previously presented on a gross basis in gross revenues, purchases of crude oil and products and other – net, would be more appropriately presented on a net basis to reflect the nature of trading activities. As a result, these realized and unrealized gains and losses, and the underlying settlement of these contracts, have been recognized and recorded on a net basis in marketing and other in the consolidated statements of income.

Consolidated Financial Statements

26

Prior periods have been reclassified to reflect this change in presentation and there was no impact on net earnings:

Earnings Impact ($ millions)	2011
Gross revenues		(1,497	)
Marketing and other		90
Purchases of crude oil and products		1,399
Other – net		8
Net earnings		—

z) Change in Accounting Policy

In June 2011, the International Accounting Standards Board (“IASB”) issued IAS 1, “Presentation of Items of OCI: Amendments to IAS 1 Presentation of Financial Statements.” The amendments stipulate the presentation of net earnings and OCI and also require the Company to group items within OCI based on whether the items may be subsequently reclassified to profit or loss. Amendments to IAS 1 were effective for the Company on January 1, 2012 with required retrospective application and early adoption permitted. The Company retrospectively adopted the amendments on January 1, 2012. The adoption of the amendments to this standard did not have a material impact on the Company’s financial statements.

Note 4 Accounts Receivable

Accounts Receivable ($ millions)	December 31, 2012			December 31, 2011
Trade receivables		1,291			1,071
Allowance for doubtful accounts		(23	)		(23	)
Derivatives due within one year		14			66
Other		67			121
		1,349			1,235

Note 5 Inventories

Inventories ($ millions)	December 31, 2012		December 31, 2011
Crude oil, natural gas and sulphur		1,113		1,476
Refined petroleum products		157		176
Trading inventories measured at fair value		328		284
Materials, supplies and other		138		123
		1,736		2,059

Impairment of inventory to net realizable value as at December 31, 2012 was $1 million (December 31, 2011 – $3 million) primarily due to a reduction in market prices for asphalt and ethanol products.

Consolidated Financial Statements

27

Note 6 Exploration and Evaluation Costs

Exploration and Evaluation Assets ($ millions)	2012			2011
Beginning of year		746			472
Additions		291			331
Acquisitions		16			116
Transfers to oil and gas properties (note 7)		(198	)		(92	)
Expensed exploration expenditures previously capitalized		(42	)		(68	)
Disposals		—			(19	)
Exchange adjustments		(3	)		6
End of year		810			746

The following exploration and evaluation expenses for the years ended December 31, 2012 and 2011 relate to activities associated with the exploration for and evaluation of oil and natural gas resources and are recorded in Exploration and Production in the Upstream segment:

Exploration and Evaluation Expense Summary ($ millions)	2012		2011
Seismic, geological and geophysical		146		170
Expensed drilling		188		245
Expensed land		16		55
		350		470

Consolidated Financial Statements

28

Note 7 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, 2010		29,144			1,069			1,974			4,545			2,028			38,760
Additions		3,028			43			58			269			119			3,517
Acquisitions		848			—			—			—			—			848
Transfers from exploration and evaluation (note 6)		92			—			—			—			—			92
Intersegment transfers		84			(84	)		—			—			—			—
Changes in asset retirement obligations		542			5			3			30			27			607
Disposals and derecognition		(113	)		(103	)		(63	)		(22	)		2			(299	)
Exchange adjustments		15			—			—			94			—			109
December 31, 2011		33,640			930			1,972			4,916			2,176			43,634
Additions		3,971			53			47			349			146			4,566
Acquisitions		16			—			—			—			—			16
Transfers from exploration and evaluation (note 6)		198			—			—			—			—			198
Changes in asset retirement obligations		1,097			(2	)		(13	)		(71	)		29			1,040
Disposals and derecognition		(76	)		—			—			(7	)		(127	)		(210	)
Exchange adjustments		(20	)		—			—			(93	)		1			(112	)
December 31, 2012		38,826			981			2,006			5,094			2,225			49,132
Accumulated depletion, depreciation, amortization and impairment
December 31, 2010		(13,919	)		(449	)		(742	)		(818	)		(1,062	)		(16,990	)
Depletion, depreciation, amortization and impairment(1)		(1,990	)		(48	)		(169	)		(220	)		(92	)		(2,519	)
Intersegment transfers		(46	)		46			—			—			—			—
Disposals and derecognition		58			44			63			3			—			168
Exchange adjustments		(3	)		—			—			(11	)		—			(14	)
December 31, 2011		(15,900	)		(407	)		(848	)		(1,046	)		(1,154	)		(19,355	)
Depletion, depreciation and amortization(1)		(2,101	)		(36	)		(102	)		(241	)		(103	)		(2,583	)
Disposals and derecognition		49			—			—			3			124			176
Exchange adjustments		5			—			—			24			—			29
December 31, 2012		(17,947	)		(443	)		(950	)		(1,260	)		(1,133	)		(21,733	)
Net book value
December 31, 2011		17,740			523			1,124			3,870			1,022			24,279
December 31, 2012		20,879			538			1,056			3,834			1,092			27,399

⁽¹⁾  Depletion, depreciation and amortization for the year ended December 31, 2012 does not include amortization of research and development assets of $5 million (2011 – $10 million), offset by exchange adjustments of $8 million (2011 – $10 million).

Costs of property, plant and equipment, including major development projects, excluded from costs subject to depletion, depreciation and amortization as at December 31, 2012 were $6.1 billion (December 31, 2011 – $5.3 billion).

The net book values of assets under construction included within costs not subject to depletion, depreciation and amortization are as follows:

Assets Under Construction ($ millions)
December 31, 2011	1,913
December 31, 2012	3,051

Consolidated Financial Statements

29

The net book values of development assets included within costs not subject to depletion, depreciation and amortization are as follows:

Development Assets ($ millions)
December 31, 2011	2,200
December 31, 2012	1,796

The net book values of assets held under finance lease included in the “Refining” class within property, plant and equipment are as follows:

Assets Under Finance Lease ($ millions)
December 31, 2011	32
December 31, 2012	30

In 2012, as a result of declines in future natural gas prices, an impairment test was performed on two heavily gas-weighted CGUs located in East Central Alberta. No impairment indicators were identified for Husky’s remaining CGUs. The Company estimated the recoverable amount based on a VIU methodology using estimated cash flows based on both proved plus probable reserves and near-term development plans, discounted using an average pre-tax discount rate of 8% (2011 – 8%). At December 31, 2012, no impairment has been recognized in relation to these CGUs (December 31, 2011 – $70 million); however, the VIU calculation continues to be sensitive to factors such as development plans and, in particular, future natural gas prices, as a U.S. $0.10/mmbtu decrease represents an approximate effect on an annual undiscounted pre-tax earnings of $12 million.

Note 8 Joint Ventures

BP-Husky Refining LLC

The Company holds a 50% ownership interest in BP-Husky Refining LLC, which owns and operates the BP-Husky Toledo Refinery in Ohio. 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 U.S. $250 million in cash and a contribution payable of U.S. $2.6 billion.

The Company’s proportionate share of the contribution payable included in the consolidated balance sheets is as follows:

Contribution Payable ($ millions)	2012			2011
Beginning of year		1,437			1,427
Accretion		81			83
Paid		(152	)		(103	)
Foreign exchange		(30	)		30
End of year		1,336			1,437

The contribution payable accretes at a rate of 6% and is payable between December 31, 2012 and December 31, 2015 with the final balance due by December 31, 2015. The timing of payments during this period will be determined by the capital expenditures made at the refinery during this same period. The entity is included as part of U.S. Refining and Marketing in the Downstream segment.

Consolidated Financial Statements

30

Summarized below is the Company’s proportionate share of operating results and financial position that have been included in the consolidated statements of income and the consolidated balance sheets in U.S. Refining and Marketing in the Downstream segment:

Results of Operations ($ millions)	2012			2011
Revenues		2,574			2,632
Expenses		(2,319	)		(2,389	)
Proportionate share of net earnings		255			243
Balance Sheets ($ millions)	December 31, 2012			December 31, 2011
Current assets		416			487
Non-current assets		1,864			1,859
Current liabilities		(210	)		(223	)
Non-current liabilities		(492	)		(534	)
Proportionate share of net assets		1,578			1,589

Other Joint Ventures

The Company holds a 50% interest in the Sunrise Oil Sands Partnership, which is engaged in developing an oil sands project in Northern Alberta. On March 31, 2008, the Company completed a transaction with BP whereby the Company contributed Sunrise oil sands assets with a fair value of U.S. $2.5 billion and BP contributed U.S. $250 million in cash and a contribution receivable of U.S. $2.25 billion. The contribution receivable accretes at a rate of 6% and is payable between December 31, 2012 and December 31, 2015 with the final balance due by December 31, 2015. The contribution receivable is reflected as a long-term asset as amounts to be received within twelve months of the reporting date are reflected as additions to property, plant and equipment.

The Company’s proportionate share of the contribution receivable from BP included in the consolidated balance sheets is as follows:

Contribution Receivable ($ millions)	2012			2011
Beginning of year		1,147			1,284
Accretion		53			71
Received		(563	)		(234	)
Foreign exchange		(30	)		26
End of year		607			1,147

Consolidated Financial Statements

31

The Company also holds a 40% interest in Husky-CNOOC Madura Limited, which is engaged in exploring for oil and gas resources in Indonesia. Results of the Husky-CNOOC Madura Limited and Sunrise Oil Sands Partnership joint ventures are included in Exploration and Production in the Upstream segment.

Summarized below is the Company’s proportionate share of operating results and financial position in the Sunrise Oil Sands Partnership and Husky-CNOOC Madura Limited that have been included in the consolidated statements of income and the consolidated balance sheets:

Results of Operations ($ millions)	2012			2011
Revenues		—			—
Expenses		(13	)		(9	)
Financial items		30			97
Proportionate share of net earnings		17			88
Balance Sheets ($ millions)	December 31, 2012			December 31, 2011
Current assets		17			8
Non-current assets		1,960			1,778
Current liabilities		(117	)		(38	)
Non-current liabilities		(51	)		(21	)
Proportionate share of net assets		1,809			1,727

Note 9 Cash Flows – Change in Non-cash Working Capital

Non-cash Working Capital ($ millions)	2012			2011
Decrease (increase) in non-cash working capital
Accounts receivable		314			553
Inventories		329			(77	)
Prepaid expenses		(29	)		(8	)
Accounts payable and accrued liabilities		364			355
Change in non-cash working capital		978			823
Relating to:
Operating activities		843			269
Financing activities		79			238
Investing activities		56			316

Cash and cash equivalents at December 31, 2012 included $127 million of cash (December 31, 2011 – $2 million) and $1,898 million of short-term investments with original maturities less than three months at the time of purchase (December 31, 2011 – $1,839 million).

Consolidated Financial Statements

32

Note 10 Goodwill

Goodwill ($ millions)	2012			2011
Beginning of year		674			663
Exchange adjustments		(11	)		11
End of year		663			674

As at December 31, 2012, goodwill related primarily to the Lima Refinery CGU included in the Downstream segment with the remaining balance allocated to various Upstream CGUs located in Western Canada. For impairment testing purposes, the recoverable amount of the Lima Refinery CGU was estimated using value-in-use methodology based on cash flows expected over a 40-year period and discounted using a pre-tax discount rate of 10% (2011 – 10%). The discount rate was determined in relation to the Company’s incremental borrowing rate adjusted for risks specific to the refinery. Cash flow projections for the initial five-year period are based on budgeted future cash flows and inflated by a 2% long-term growth rate for the remaining 35-year period. The inflation rate was based upon an average expected inflation rate for the U.S. of 2% (2011 – 2%). At December 31, 2012, the recoverable amount exceeded the carrying amount of the relevant CGUs. The value-in-use calculation for the Lima Refinery CGU is particularly sensitive to changes in discount rates, forecasted crack spreads and refining margins.

Note 11 Bank Operating Loans

At December 31, 2012, the Company had unsecured short-term borrowing lines of credit with banks totalling $515 million (December 31, 2011– $465 million) and letters of credit under these lines of credit totalling $235 million (December 31, 2011 – $250 million). As at December 31, 2012, bank operating loans were nil (December 31, 2011 – nil). Interest payable is based on Bankers’ Acceptance, U.S. LIBOR or prime rates. During 2012, the Company’s weighted average interest rate on short-term borrowings was approximately 1.2% (2011 – 1.2%).

Husky Energy (HK) Limited and Husky Oil China Ltd., subsidiaries of the Company, each have an uncommitted demand revolving facility of U.S. $10 million available for general purposes. As at December 31, 2012, there was no balance outstanding under these facilities (December 31, 2011 – nil). The 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. As at December 31, 2012, there was no balance outstanding under this credit facility (December 31, 2011 – nil).

Note 12 Accounts Payable and Accrued Liabilities

Accounts Payable and Accrued Liabilities ($ millions)	December 31, 2012		December 31, 2011
Trade payables		152		74
Accrued liabilities		2,292		2,178
Dividend payable (note 18)		295		291
Stock-based compensation		47		9
Derivatives due within one year		5		138
Contingent consideration		27		17
Other		168		160
		2,986		2,867

Consolidated Financial Statements

33

Note 13 Long-term Debt

Long-term Debt ($ millions)			Canadian $ Amount						U.S. $ Denominated
	Maturity		December 31, 2012			December 31, 2011			December 31, 2012		December 31, 2011
Long-term debt
5.90% notes(1)(2)		2014		746			763			750		750
3.75% medium-term notes(1)		2015		300			300			—		—
7.55% debentures(1)		2016		199			203			200		200
6.20% notes(1)(2)		2017		298			305			300		300
6.15% notes(2)		2019		298			305			300		300
7.25% notes(2)		2019		746			763			750		750
5.00% medium-term notes		2020		400			400			—		—
3.95% notes(2)		2022		498			—			500		—
6.80% notes(2)		2037		385			393			387		387
Debt issue costs(3)				(24	)		(21	)		—		—
Unwound interest rate swaps				72			93			—		—
Long-term debt				3,918			3,504			3,187		2,687
Long-term debt due within one year
6.25% notes(4)				—			407			—		400

⁽¹⁾  A portion of the Company’s debt was designated in a fair value hedging relationship for interest rate risk management and the gains or losses arising from adjusting the derivative to its fair value were recognized immediately in net earnings along with the offsetting gain or loss on the hedged item recorded at fair value until discontinuation of the hedging relationship in 2011. Refer to Note 22.

⁽²⁾  A portion of the Company’s U.S. denominated debt is designated as a hedge of the Company’s net investment in its U.S. refining operations. Refer to Note 22.

⁽³⁾  Calculated using the effective interest rate method.

⁽⁴⁾  A portion of the Company’s debt was designated in a cash flow hedging relationship for foreign currency risk management, with the use of cross currency swaps, until expiration of the hedging relationship in the second quarter of 2012 with the repayment of the related U.S. $400 million of 6.25% notes which matured on June 15, 2012 and the settlement of the cross currency swaps on the same day. Refer to Note 22.

Credit Facilities

The Company’s revolving syndicated credit facility, which was entered into on November 15, 2011 and amended and restated on December 14, 2012, allows the Company to borrow up to $1.5 billion in either Canadian or U.S. currency from a group of banks on an unsecured basis. The facility is structured as a four-year committed revolving credit facility with a maturity date of December 14, 2016.

The Company also has a second revolving syndicated credit facility, which was entered into on August 31, 2010 and amended and restated on December 14, 2012. The facility allows the Company to borrow up to $1.6 billion in either Canadian or U.S. currency from a group of banks on an unsecured basis. The facility is structured as a four-year committed revolving credit with a maturity date of August 31, 2014.

These facilities, except for their maturity dates, have the same terms. Interest rates vary based on Canadian prime, Bankers’ Acceptance, U.S. LIBOR or U.S. base rate, depending on the borrowing option selected and credit ratings assigned by certain credit rating agencies to the Company’s rated senior unsecured debt.

As at December 31, 2012, the Company had no borrowings under either revolving syndicated credit facility (December 31, 2011 – no borrowings under the prior $1.6 billion revolving syndicated credit facility, the prior $1.7 billion revolving syndicated credit facility or the $100 million bilaterial credit facility which was cancelled effective February 3, 2012).

Consolidated Financial Statements

34

Notes and Debentures

The 7.55% debentures represent unsecured securities under a trust indenture dated October 31, 1996.

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

The 5.90%, the 6.20%, the 7.25%, the 3.95% and the 6.80% notes represent unsecured securities under a trust indenture dated September 11, 2007.

The 3.75% and the 5.00% medium-term notes represent unsecured securities under a trust indenture dated December 21, 2009.

On June 15, 2012, the Company repaid the maturing 6.25% notes issued under a trust indenture dated June 14, 2002. The amount paid to note holders was U.S. $413 million, including U.S. $13 million of interest.

At December 31, 2012, the Company had entered into a cash flow hedge using forward starting interest rate swap arrangements whereby the Company fixed the underlying U.S. 10-year Treasury Bond rate on U.S. $500 million to June 16, 2014, which is the Company’s forecasted debt issuance on the same date. Refer to Note 22.

On June 13, 2011, the Company filed a universal short form base shelf prospectus (the “U.S. Base Prospectus”) with the Alberta Securities Commission and the U.S. Securities and Exchange Commission that enables the Company to offer up to U.S. $3.0 billion of common shares, preferred shares, debt securities, subscription receipts, warrants and units in the United States up to and including July 12, 2013. At December 31, 2012, approximately $1.5 billion remains available for issuance under the U.S. Base Prospectus.

On December 31, 2012, the Company filed a universal short form base shelf prospectus (the “Canadian Base Prospectus”) with applicable securities regulators in each of the provinces of Canada, other than Quebec, that enables the Company to offer up to $3.0 billion of common shares, preferred shares, debt securities, subscription receipts, warrants and units (the “Securities”) in Canada up to and including January 30, 2015. As of December 31, 2012, the Company had not issued Securities under the Canadian Base Prospectus. This Canadian Base Prospectus replaced the universal short form base shelf prospectus filed in Canada during November 2010 which had remaining unused capacity of $1.4 billion and expired in December 2012.

The ability of the Company to raise capital utilizing the U.S. Base Prospectus or the Canadian Base Prospectus is dependent on market conditions at the time of sale.

The notes and debentures disclosed above are redeemable (unless otherwise stated) at the option of the Company, at any time, at a redemption price equal to the greater of the par value of the securities and the sum of the present values of the remaining scheduled payments discounted at a rate calculated using a comparable U.S. Treasury Bond rate (for U.S. dollar denominated securities) or Government of Canada Bond rate (for Canadian dollar denominated securities) plus an applicable spread. Interest on the notes and debentures disclosed above is payable semi-annually.

The Company’s notes, debentures, credit facilities and short-term lines of credit rank equally.

The unamortized portion of the gain on previously unwound interest rate swaps that were designated as a fair value hedge is included in the carrying value of long-term debt. Refer to Note 22.

Consolidated Financial Statements

35

Note 14 Financial Items

Financial Items ($ millions)	2012			2011
Foreign exchange
Gains (losses) on translation of U.S. dollar denominated long-term debt		43			(47	)
Gains on cross currency swaps		2			7
Gains (losses) on contribution receivable		(7	)		34
Other foreign exchange gains (losses)		(24	)		16
Net foreign exchange gains		14			10
Finance income
Contribution receivable		53			71
Interest income		34			—
Other		6			15
Finance income		93			86
Finance expenses
Long-term debt		(232	)		(226	)
Contribution payable		(81	)		(82	)
Short-term debt		(3	)		(9	)
		(316	)		(317	)
Interest capitalized(1)		173			86
		(143	)		(231	)
Accretion of asset retirement obligations (note 16)		(87	)		(73	)
Accretion of other long-term liabilities		(10	)		(6	)
Finance expenses		(240	)		(310	)
		(133	)		(214	)

⁽¹⁾  Interest capitalized on project costs in 2012 is calculated using the Company’s annualized effective interest rate of 6% (2011 – 6%).

Other foreign exchange gains and losses primarily include realized and unrealized foreign exchange gains and losses on property, plant and equipment, and working capital.

Note 15 Other Long-term Liabilities

Other Long-term Liabilities ($ millions)	December 31, 2012		December 31, 2011
Employee future benefits (note 19)		147		166
Finance lease obligations		31		33
Stock-based compensation		21		8
Contingent consideration (note 22)		78		112
Other		54		23
		331		342

Consolidated Financial Statements

36

Note 16 Asset Retirement Obligations

At December 31, 2012, the estimated total undiscounted inflation adjusted amount required to settle the Company’s ARO was $10.3 billion (December 31, 2011 – $8.5 billion). These obligations will be settled based on the useful lives of the underlying assets, which currently extend an average of 45 years into the future. This amount has been discounted using credit-adjusted risk-free rates of 3% to 5% (December 31, 2011 – 3% to 5%). Obligations related to environmental remediation and cleanup of oil and gas producing assets are included in the estimated ARO.

The change in estimates in 2012 primarily related to increased cost estimates for the retirement of assets in the Asia Pacific Region, the Atlantic Region and in Western Canada, and a revision of the timing of future ARO cash flows for Western Canadian and Downstream assets.

Asset Retirement Obligations ($ millions)	2012			2011
Beginning of year		1,767			1,198
Additions		154			188
Liabilities settled		(123	)		(105	)
Liabilities disposed		(1	)		(6	)
Change in discount rate		174			387
Change in estimates		737			32
Exchange adjustment		(2	)		—
Accretion(1)		87			73
End of year		2,793			1,767
Expected to be incurred within 1 year		107			116
Expected to be incurred beyond 1 year		2,686			1,651

⁽¹⁾  Accretion is included in finance expenses. Refer to Note 14.

Consolidated Financial Statements

37

Note 17 Income Taxes

The major components of income tax expense for the years ended December 31, 2012 and 2011 were as follows:

Income Tax Expense ($ millions)	2012			2011
Current income tax
Current income tax charge		529			334
Adjustments in respect of current income tax of previous years		7			20
		536			354
Deferred income tax
Relating to origination and reversal of temporary differences		221			511
Adjustments in respect of deferred income tax of previous years		57			51
		278			562
Deferred Tax Items in OCI ($ millions)	2012			2011
Deferred tax items expensed (recovered) directly in OCI
Derivatives designated as cash flow hedges		1			—
Actuarial gains (losses) on pension plans		5			(8	)
Exchange differences on translation of foreign operations		(12	)		14
Hedge of net investment		2			(3	)
		(4	)		3
Deferred Tax Items in Equity ($ millions)	2012			2011
Deferred tax items expensed (recovered) directly in equity
Share issue costs		—			(9	)

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, 2012 and 2011 were accounted for as follows:

Reconciliation of Effective Tax Rate ($ millions)	2012			2011
Earnings before income taxes
Canada		2,097			2,556
United States		575			508
Other foreign jurisdictions		164			76
		2,836			3,140
Statutory income tax rate (percent)		25.8			27.3
Expected income tax		732			857
Effect on income tax resulting from:
Rate benefit on partnership earnings		—			(56	)
Capital gains and losses		(10	)		2
Foreign jurisdictions		37			46
Non-taxable items		12			(5	)
Adjustments in respect of previous years		64			71
Other – net		(21	)		1
Income tax expense		814			916

The statutory tax rate was 25.8% in 2012 (2011 – 27.3%). The decrease from 2011 to 2012 is due to a reduction in the 2012 Canadian corporate tax rates as part of a series of corporate tax rate reductions previously enacted by the Canadian federal government.

Consolidated Financial Statements

39

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

Deferred Tax Liabilities and Assets ($ millions)	January 1, 2012			Recognized in Earnings			Recognized in OCI			Other			December 31, 2012
Deferred tax liabilities
Exploration and evaluation assets and property, plant and equipment		(4,914	)		(487	)		13			(12	)		(5,400	)
Foreign exchange gains taxable on realization		(84	)		23			(3	)		—			(64	)
Financial assets at fair value		6			(13	)		—			—			(7	)
Deferred tax assets
Pension plans		46			(2	)		(5	)		—			39
Asset retirement obligations		489			290			(1	)		—			778
Loss carry-forwards		121			(91	)		—			—			30
Debt issue costs		10			(4	)		—			—			6
Other temporary differences		(3	)		6			—			—			3
		(4,329	)		(278	)		4			(12	)		(4,615	)
Deferred Tax Liabilities and Assets ($ millions)	January 1, 2011			Recognized in Earnings			Recognized in OCI			Other			December 31, 2011
Deferred tax liabilities
Exploration and evaluation assets and property, plant and equipment		(4,371	)		(519	)		(18	)		(6	)		(4,914	)
Foreign exchange gains taxable on realization		(74	)		(13	)		3			—			(84	)
Other temporary differences		22			(34	)		—			9			(3	)
Deferred tax assets
Pension plans		38			—			8			—			46
Asset retirement obligations		308			180			1			—			489
Financial assets at fair value		3			3			—			—			6
Loss carry-forwards		310			(192	)		3			—			121
Debt issue costs		(3	)		13			—			—			10
		(3,767	)		(562	)		(3	)		3			(4,329	)

The Company has temporary differences associated with its investments in its foreign subsidiaries, branches, and interests in joint ventures. At December 31, 2012, the Company has no deferred tax liabilities in respect of these temporary differences (December 31, 2011 – nil).

At December 31, 2012, the Company had $86 million (December 31, 2011 – $443 million) of U.S. tax losses that will expire after 2030. The Company has recorded deferred tax assets in respect of these losses, as there are sufficient taxable temporary differences in the U.S. jurisdiction to utilize these losses.

Consolidated Financial Statements

40

Note 18 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, 2010		890,708,795		4,574
Common shares issued, net of share issue costs		44,362,214		1,173
Stock dividends		22,461,089		580
Options exercised		5,000		—
December 31, 2011		957,537,098		6,327
Stock dividends		24,514,797		607
Options exercised		177,325		5
December 31, 2012		982,229,220		6,939

On June 29, 2011, the Company issued approximately 37 million common shares at a price of $27.05 per share for total gross proceeds of approximately $1.0 billion through a public offering, and a total of approximately 7.4 million common shares at a price of $27.05 per share for total gross proceeds of $200 million through a private placement to L.F. Investments (Barbados) Limited and Hutchison Whampoa Luxembourg Holdings S.à.r.l. The public offering was conducted under the Company’s universal base shelf prospectus filed November 26, 2010 with the securities regulatory authorities in all provinces of Canada, the Company’s universal base shelf prospectus filed June 13, 2011 with the Alberta Securities Commission and the U.S. Securities and Exchange Commission and the respective accompanying prospectus supplements.

Shareholders have the option to receive dividends in common shares or in cash. Quarterly dividends may be declared in an amount expressed in dollars per common share and 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.

During the year ended December 31, 2012, the Company declared dividends payable of $1.20 per common share (2011 – $1.20 per common share), resulting in dividends of $1.2 billion (2011 – $1.1 billion). An aggregate of $557 million was paid in cash during 2012 (2011 – $495 million). At December 31, 2012, $295 million, including $293 million in cash and $2 million in common shares, was payable to shareholders on account of dividends declared on November 1, 2012 (December 31, 2011 – $287 million, including $87 million in cash and $200 million in common shares).

Preferred Shares

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

Preferred Shares	Number of Shares		Amount ($ millions)
December 31, 2010		—		—
Cumulative Redeemable Preferred Shares, Series 1 issued, net of share issue costs		12,000,000		291
December 31, 2011		12,000,000		291
Cumulative Redeemable Preferred Shares, Series 1 issued, net of share issue costs		—		—
December 31, 2012		12,000,000		291

Consolidated Financial Statements

41

On March 18, 2011, the Company issued 12 million Cumulative Redeemable Preferred Shares, Series 1 (the “Series 1 Preferred Shares”) at a price of $25.00 per share for aggregate gross proceeds of $300 million. Net proceeds after share issue costs were $291 million. The Series 1 Preferred Shares were offered by way of a prospectus supplement under the short form base shelf prospectus filed November 26, 2010 with the securities regulatory authorities in all provinces of Canada.

Holders of the Series 1 Preferred Shares are entitled to receive a cumulative quarterly fixed dividend yielding 4.45% annually for the initial period ending March 31, 2016, 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 5-year Government of Canada bond yield plus 1.73%. Holders of Series 1 Preferred Shares have the right, at their option, to convert their shares into Cumulative Redeemable Preferred Shares, Series 2 (the “Series 2 Preferred Shares”), subject to certain conditions, on March 31, 2016 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 at a rate equal to the three-month Government of Canada Treasury Bill yield plus 1.73%, as and when declared by the Company’s Board of Directors.

In the event of liquidation, dissolution or winding-up of the Company, the holders of the Series 1 Preferred Shares will be entitled to receive $25 per share. All accrued unpaid dividends will be paid before any amounts are paid or any assets of the Company are distributed to the holders of any other shares ranking junior to the Series 1 Preferred Shares. The holders of the Series 1 Preferred Shares will not be entitled to share in any further distribution of the assets of the Company.

During the year ended December 31, 2012, the Company declared dividends payable of $13 million on the Series 1 Preferred Shares (2011 – $10 million) representing approximately $1.11 per Series 1 Preferred Share (2011 – $0.87 per Series 1 Preferred Share). At December 31, 2012, there were no amounts payable as dividends on the Series 1 Preferred Shares (December 31, 2011 – $3 million). A total of $17 million was paid during 2012 (2011 – $7 million), representing approximately $0.28 per Series 1 Preferred Share (2011 – $0.28 per Series 1 Preferred Share).

Stock Option Plan

Pursuant to the Incentive Stock Option Plan (the “Option Plan”), the Company may grant from time to time to officers and employees of the Company options to purchase common shares of the Company. The term of each option is five years and it 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. For options granted up to 2009, when the option is surrendered for cash, the cash payment is the difference between the weighted average trading price of the Company’s common shares on the trading day prior to the surrender date and the exercise price of the option. For options granted after 2009, when the option is surrendered for cash, the cash payment is the difference between the weighted average trading price of the Company’s common shares for the five trading days following the surrender date and the exercise price of the option.

Certain options granted under the Option Plan and henceforth referred to as performance options vest only if certain shareholder return targets are met. The ultimate number of performance options that vest will depend upon the Company’s performance measured over three calendar years. If the Company’s performance is below the specified level compared with its industry peer group, the performance options awarded will be forfeited. If the Company’s performance is at or above the specified level compared with its industry peer group, the number of performance options exercisable shall be determined by the Company’s relative ranking. Stock compensation expense related to the performance options is accrued based on the price of the common shares at the end of the period and the anticipated performance factor. The term of each performance option is five years and the compensation expense is recognized over the three-year vesting period of the performance options. Performance options are no longer granted and the last grant was on August 7, 2009.

Included in accounts payable and accrued liabilities and other long-term liabilities in the consolidated balance sheets at December 31, 2012 was $57 million (December 31, 2011 – $16 million) representing the estimated fair value of options outstanding. The total expense recognized in selling, general and administrative expenses in the consolidated statements of income for the Option Plan for the year ended December 31, 2012 was $42 million (2011 – recovery of $2 million). At December 31, 2012, stock options exercisable for cash had an intrinsic value of $31 million (December 31, 2011 – nil).

Consolidated Financial Statements

42

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

Outstanding and Exercisable Options	2012					2011
	Number of Options (thousands)			Weighted Average Exercise Prices		Number of Options (thousands)			Weighted Average Exercise Prices
Outstanding, beginning of year		33,337			34.62		29,541			37.04
Granted(1)		11,137			25.61		9,618			28.80
Exercised for common shares		(177	)		27.61		(5	)		28.19
Expired or forfeited		(15,276	)		39.09		(5,817	)		37.30
Outstanding, end of year		29,021			28.85		33,337			34.62
Exercisable, end of year		10,796			32.19		18,486			39.50

⁽¹⁾  Options granted during the year ended December 31, 2012 were attributed a fair value of $3.94 per option (2011 – $4.41) 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
$24.96 – $29.99		25,765		27.32		3		7,540		28.40
$30.00 – $34.99		661		31.24		1		661		31.24
$35.00 – $39.99		201		39.97		—		201		39.97
$40.00 – $42.99		748		40.91		—		748		40.91
$43.00 – $45.02		1,646		45.02		1		1,646		45.02
December 31, 2012		29,021		28.85		3		10,796		32.19

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 two plans:

Black-Scholes Assumptions	December 31, 2012				December 31, 2011
	Tandem Options		Tandem Performance Options		Tandem Options		Tandem Performance Options
Dividend per option		1.31		1.31		1.33		1.33
Range of expected volatilities used (percent)		13.5 – 33.2		13.5 – 24.8		21.3 – 35.9		21.3 – 32.0
Range of risk-free interest rates used (percent)		0.9 – 1.4		0.9 – 1.1		0.7 – 1.3		0.7 – 1.0
Expected life of share options from vesting date (years)		1.82		1.82		1.75		1.75
Expected forfeiture rate (percent)		11.0		11.0		11.5		11.5
Weighted average exercise price		29.16		41.36		34.59		41.51
Weighted average fair value		2.84		0.28		0.82		0.03

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

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43

three years and the PSU vests on the second and third anniversary dates of the grant date in percentages determined by the Board of Directors based on the Company reaching certain shareholder return targets. 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, 2012, the carrying amount of the liability relating to PSUs was $11 million (December 31, 2011 – $1 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, 2012 was $12 million (2011 – expense of $1 million). The weighted average contractual life of the PSUs at December 31, 2012 was 2 years.

The number of PSUs outstanding was as follows:

Performance Share Units	2012			2011
Beginning of year		500,000			220,000
Granted		539,500			295,000
Exercised		(82,000	)		—
Forfeited		(93,000	)		(15,000	)
Outstanding, end of year		864,500			500,000
Vested, end of year		429,835			121,190

Earnings per Share

Earnings per share ($ millions)	2012			2011
Net earnings		2,022			2,224
Effect of dividends declared on preferred shares in the year		(13	)		(10	)
Net earnings – basic		2,009			2,214
Dilutive effect of accounting for share options as equity-settled(1)		—			(30	)
Net earnings – diluted		2,009			2,184
(millions)
Weighted average common shares outstanding – basic		975.8			923.8
Effect of stock dividends declared in the year		0.1			8.2
Weighted average common shares outstanding – diluted		975.9			932.0
Earnings per share – basic ($/share)		2.06			2.40
Earnings per share – diluted ($/share)		2.06			2.34

⁽¹⁾  Stock-based compensation expense was $42 million based on cash-settlement for the year ended December 31, 2012 (2011 – recovery of $2 million). Stock-based compensation expense was $33 million based on equity-settlement for the year ended December 31, 2012 (2011 – expense of $28 million). For the year ended December 31, 2012, cash-settlement of share options was considered more dilutive than the equity-settlement of share options and as such, was used to calculate earnings per share – diluted.

For the year ended December 31, 2012, 29 million tandem options and 1 million tandem performance options (2011 – 26 million tandem options and 7 million tandem performance options) were excluded from the calculation of diluted earnings per share as these options were anti-dilutive.

Note 19 Pensions and Other Post-employment Benefits

The Company currently provides a defined contribution pension plan for all qualified employees and an other post-employment benefit plan to its retirees. The Company also maintains a defined benefit pension plan, which is closed to new entrants. The measurement date of all plan assets and the accrued benefit obligations was December 31, 2012. The most recent actuarial valuation of the plans was December 31, 2011 for the Canadian defined benefit plan and the other post-employment benefit plan. The most recent actuarial valuation of the U.S. plans was January 1, 2012.

Defined Contribution Pension Plan

During the year ended December 31, 2012, the Company recognized a $33 million expense (2011 – $28 million) for the defined contribution plan and the U.S. 401(k) plan in net earnings.

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44

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

The Company has accrued the total net liability for the DB Pension Plan and the OPEB Plan in the consolidated balance sheets in other long-term liabilities as follows:

DB Pension Plan ($ millions)	December 31, 2012			December 31, 2011			December 31, 2010
Fair value of plan assets		156			147			142
Defined benefit obligation		(189	)		(183	)		(170	)
Funded status		(33	)		(36	)		(28	)
Unrecognized past service costs		—			—			—
Net Liability		(33	)		(36	)		(28	)
Non-current liability		(33	)		(36	)		(28	)

OPEB Plan ($ millions)	December 31, 2012			December 31, 2011			December 31, 2010
Fair value of plan assets		—			—			—
Defined benefit obligation		(105	)		(120	)		(100	)
Funded status		(105	)		(120	)		(100	)
Unrecognized past service costs		(9	)		(10	)		(12	)
Net Liability		(114	)		(130	)		(112	)
Non-current liability		(114	)		(130	)		(112	)

The following tables summarize the experience adjustments arising on the DB Pension and the OPEB Plan liabilities:

DB Pension Plan ($ millions)	2012			2011			2010
Experience adjustments arising on plan liabilities		(0.5	)		0.2			1.8
OPEB Plan ($ millions)	2012			2011			2010
Experience adjustments arising on plan liabilities		1.6			(1.2	)		(0.6	)

The following table summarizes the experience adjustments arising on the DP Pension Plan assets:

DB Pension Plan ($ millions)	2012			2011		2010
Experience adjustments arising on plan assets		(2.2	)		5.3		(4.0	)

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45

The following tables summarize changes to the net balance sheet position and amounts recognized in net earnings and OCI for the DB Pension Plan and the OPEB Plan for the years ended December 31, 2012 and 2011:

DB Pension Plan and OPEB Plan Net Asset (Liability) ($ millions)	DB Pension Plan						OPEB Plan
	2012			2011			2012			2011
Beginning of year		(36	)		(28	)		(130	)		(112	)
Employer contributions		8			10			1			1
Benefit cost		—			—			(10	)		(9	)
Actuarial loss (gain)		(5	)		(18	)		25			(10	)
End of year		(33	)		(36	)		(114	)		(130	)
DB Pension Plan and OPEB Plan ($ millions)	DB Pension Plan						OPEB Plan
	2012			2011			2012			2011
Amounts recognized in net earnings
Current service cost		2			3			7			6
Interest cost		7			8			4			5
Expected return on plan assets		(9	)		(10	)		—			—
Past service cost (credit)		—			—			(2	)		(2	)
Curtailment gain		—			(1	)		—			—
Benefit cost		—			—			9			9
Amounts recognized in retained earnings
Actuarial loss (gain) recognized		5			18			(25	)		10
Cumulative actuarial loss (gain), end of year		32			27			(4	)		21

The following tables summarize changes to the defined benefit obligation for the DB Pension Plan and the OPEB Plan:

Defined Benefit Obligation ($ millions)	DB Pension Plan						OPEB Plan
	2012			2011			2012			2011
Beginning of year		183			170			120			100
Current service cost		2			3			7			6
Interest cost		7			8			4			5
Benefits paid		(10	)		(10	)		(1	)		(1	)
Actuarial loss (gain)		7			13			(25	)		10
Curtailment gain		—			(1	)		—			—
End of year		189			183			105			120

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46

The following table summarizes changes to the DB Pension Plan assets during the year:

Fair Value of Plan Assets ($ millions)	2012			2011
Beginning of year		147			142
Contributions by employer		8			10
Benefits paid		(10	)		(10	)
Expected return on plan assets		9			10
Actuarial gain (loss)		2			(5	)
End of year		156			147

The following long term assumptions were used to estimate the value of the defined benefit obligations, the plan assets, and the OPEB Plan:

DB Pension Plan Long-term Assumptions (percent)	Canada – DB Pension Plan				U.S. – DB Pension Plan
	2012		2011		2012		2011
Discount rate for benefit expense		4.1		5.0		3.9		4.7
Discount rate for benefit obligation		3.8		4.1		3.2		3.9
Rate of compensation expense		3.5		4.0		4.5		4.5
Expected rate of return on plan assets		6.5		6.5		5.3		6.0

OPEB Plan Long-term Assumptions (percent)	OPEB Plan
	2012		2011
Discount rate for benefit expense		4.1 – 4.3		4.9 – 5.2
Discount rate for benefit obligation		3.3 – 4.0		4.1 – 4.3
Dental care escalation rate		4.0		4.0
Provincial health care premium		2.5		2.5

The average health care cost trend rate used for the benefit expense for the Canadian OPEB Plan was 7.0% for 2012, 2013 and 2014, grading 0.5% per year for four years to 5.0% in 2018 and thereafter. The average health care cost trend rate used for the obligation related to the Canadian OPEB Plan was 7.0% for 2012, 2013 and 2014, grading 0.5% per year for four years to 5.0% in 2018 and thereafter.

The average health care cost trend rate used for the benefit expense for the U.S. OPEB Plan was 8.0% for 2012 and 2013, and 7.0% for 2014, grading 0.5% per year for four years to 5.0% per year in 2018 and thereafter. The average health care cost trend rate used for the obligation related to the U.S. OPEB Plan was 8.0% for 2012 and 2013, and 7.0% for 2014, grading 0.5% per year for four years to 5.0% in 2018 and thereafter.

The medical cost trend rate assumption has a significant effect on amounts reported for the OPEB plan. A one percent increase or decrease in the estimated trend rate would have the following effects:

Medical Cost Trend Rate Sensitivity Analysis ($ millions)	1% increase		1% decrease
Effect on benefit cost recognized in net earnings		2		(2	)
Effect on defined benefit obligation		18		(15	)

The expected rate of return on the plan assets was determined based on management’s best estimate and the historical rates of return, adjusted periodically by asset category. The actual rate of return on plan assets for 2012 was 8% and 6% (2011 – 3% and 1%) for the Canadian and U.S. DB Pension Plans, respectively.

During 2012, the Company contributed $8 million (2011 – $10 million) to the defined benefit pension plan assets and is expecting to contribute $8 million in 2013. Benefits of $12 million are expected to be paid in 2013.

The Company adheres to a Statement of Investment Policies and Procedures (the “Policy”). Plan assets are allocated in accordance with the long-term nature of the obligation and comprise a balanced investment based on interest rate and inflation sensitivities. The Policy explicitly prescribes diversification parameters for all classes of investment.

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47

The composition of the DB Pension Plan assets at December 31, 2012 and 2011 was as follows:

DB Pension Plan Assets (percent)	Target allocation range		2012		2011
Money market type funds		0 – 7		—		6.8
Equity securities		50 – 80		59.8		56.1
Debt securities		30 – 50		39.6		36.7
Real estate		0 – 5		—		—
Other		0 – 15		0.6		0.4

Note 20 Commitments and Contingencies

At December 31, 2012, the Company had commitments that require the following minimum future payments which are not accrued for in the consolidated balance sheet:

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		130		806		556		1,492
Firm transportation agreements		217		1,037		2,652		3,906
Unconditional purchase obligations		3,089		4,449		78		7,616
Lease rentals and exploration work agreements		85		386		571		1,042
		3,521		6,678		3,857		14,056

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 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.

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Note 21 Related Party Transactions

Significant subsidiaries and jointly controlled entities at December 31, 2012 and the Company’s percentage equity interest (to the nearest whole number) are set out below.

Significant Subsidiaries and Joint Operations	%		Jurisdiction
Subsidiary of Husky Energy Inc.
Husky Oil Operations Limited		100		Alberta
Subsidiaries and jointly controlled entities of Husky Oil Operations Limited
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
Lima Refining Company		100		Delaware
Husky Marketing and Supply Company		100		Delaware

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49

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

On May 11, 2009, the Company issued 5-year and 10-year senior notes of U.S. $251 million and U.S. $107 million, respectively, to certain management, shareholders, affiliates and directors. The coupon rates offered were 5.90% and 7.25% for the 5-year and 10-year tranches, respectively. Subsequent to this offering, U.S. $122 million of the 5-year senior notes and U.S. $75 million of the 10-year senior notes issued to related parties were sold to third parties. These transactions were measured at fair market value at the date of the transaction and have been carried out on the same terms as would have applied with unrelated parties. At December 31, 2012, the senior notes are included in long-term debt in the Company’s consolidated balance sheet.

In April 2011, the Company sold its 50% interest in the Meridian cogeneration facility (“Meridian”) at Lloydminster to a related party. The consideration for the Company’s share of Meridian was $61 million, resulting in no net gain or loss on the transaction.

The Company sells natural gas to, and purchases steam from, Meridian and other cogeneration facilities owned by a related party. These natural gas sales and steam purchases are related party transactions and have been measured at fair value. For the year ended December 31, 2012, the amount of natural gas sales to Meridian and other cogeneration facilities owned by the related party totalled $74 million (2011 – $108 million). For the year ended December 31, 2012, the amount of steam purchases by the Company from Meridian totalled $13 million (2011 – $19 million). In addition, the Company provides cogeneration and facility support services to Meridian, measured on a cost recovery basis. For the year ended December 31, 2012, the total cost recovery for these services was $19 million (2011 – $16 million).

On June 29, 2011, the Company issued 7.4 million common shares at a price of $27.05 per share for total gross proceeds of $200 million via private placement to its principal shareholders, L.F. Investments (Barbados) Limited and Hutchison Whampoa Luxembourg Holdings S.à.r.l.

The total compensation expense recognized in purchases of crude oil and products and selling, general and administrative expenses in the consolidated statements of income for the year ended December 31, 2012 was $673 million (2011 – $588 million) as follows:

Compensation of Employees ($ millions)	2012			2011
Short-term employee benefits		661			615
Post-employment benefits		42			37
Stock-based compensation		54			(1	)
		757			651
Less: capitalized portion		(84	)		(63	)
		673			588

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50

The amounts disclosed in the table below are the amounts recognized as an expense during the reporting period related to key management personnel. The Company defines its key management as the officers and executives within the executive department of the Company.

Compensation of Key Management Personnel ($ millions)	2012		2011
Short-term employee benefits		11		11
Post-employment benefits		—		—
Stock-based compensation		4		(2	)
		15		9

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 in the consolidated statements of income.

Post-employment benefits represent the estimated cost to the Company to provide either a defined benefit pension plan or a defined contribution pension plan, and other post-retirement benefits for the current year of service (refer to Note 19).

Stock-based compensation expense represents the cost to the Company for participation in share-based payment plans (refer to Note 18).

Note 22 Financial Instruments and Risk Management

Financial Instruments

The Company’s financial instruments include cash and cash equivalents, accounts receivable, contribution receivable, accounts payable and accrued liabilities, long-term debt, contribution payable, and portions of other assets and other long-term liabilities.

The following table summarizes by measurement classification, derivatives, contingent consideration and hedging instruments that are carried at fair value in the consolidated balance sheets:

Financial Instruments at Fair Value ($ millions)	December 31, 2012			December 31, 2011
Derivatives – FVTPL (held-for-trading)
Accounts receivable		13			65
Accounts payable and accrued liabilities		(5	)		(45	)
Other assets, including derivatives		1			2
Other – FVTPL (held-for-trading)(1)
Accounts payable and accrued liabilities		(27	)		(17	)
Other long-term liabilities		(78	)		(112	)
Hedging instruments
Other assets, including derivatives		1			—
Accounts payable and accrued liabilities		—			(93	)
Long-term debt(2)		25			(13	)
		(70	)		(213	)
Net gains (losses) for the year related to financial instruments held at fair value		122			(73	)
Included in net earnings		104			(55	)
Included in OCI		18			(18	)

⁽¹⁾  Non-derivative items related to contingent consideration recognized as part of a business acquisition.

⁽²⁾  Represents the foreign exchange adjustment related to translation of U. S. denominated long-term debt designated as a hedge of the Company’s net investment in its U.S. refining operations.

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51

The Company’s other financial instruments that are not related to derivatives, contingent consideration or hedging activities are included in cash and cash equivalents, accounts receivable, contribution receivable, accounts payable and accrued liabilities, long-term debt, other long-term liabilities and contribution payable. These financial instruments are classified as loans and receivables or other financial liabilities and are carried at amortized cost. Excluding long-term debt, the carrying values of these financial instruments and cash and cash equivalents approximate their fair values.

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. The estimated fair value of long-term debt at December 31, 2012 was $4.6 billion (December 31, 2011 – $4.4 billion).

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52

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 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 following table summarizes the Company’s assets and liabilities recorded at fair value on a recurring basis:

Fair Value Hierarchy ($ millions)	December 31, 2012			December 31, 2011
Financial assets
Level 2		15			67
Financial liabilities
Level 2		20			(151	)
Level 3		(105	)		(129	)
		(70	)		(213	)

Contingent consideration payments, based on the average differential between heavy and synthetic crude oil prices until 2014, are classified as Level 3 fair value measurements and included in accounts payable and accrued liabilities and other long-term liabilities. The fair value of the contingent consideration is determined through forecasts of synthetic crude oil volumes, crude oil prices, and forward price differentials deemed specific to the Company’s Upgrader. A reconciliation of changes in fair value of financial liabilities classified in Level 3 is provided below:

Level 3 Valuations ($ millions)	2012			2011
Beginning of year		129			53
Accretion		11			6
Upside interest payment		(17	)		—
Increase (decrease) on revaluation(1)		(18	)		70
End of year		105			129
Expected to be incurred within 1 year		27			17
Expected to be incurred beyond 1 year		78			112

⁽¹⁾  Revaluation of the contingent consideration liability is recorded in other – net in the consolidated statements of income.

Risk Management Overview

The Company is exposed to market risks related to the volatility of commodity prices, foreign exchange and interest rates. It is also exposed to financial risks related to liquidity and credit and contract risks. In certain instances, the Company uses derivative instruments to manage the Company’s exposure to these risks. The Company employs risk management strategies and policies to ensure that any exposures to risk are in compliance with the Company’s business objectives and risk tolerance levels.

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

In certain instances, the Company uses derivative commodity instruments to manage exposure to price volatility on a portion of its oil and gas production and firm commitments for the purchase or sale of crude oil and natural gas.

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The Company’s results will also be impacted by a decrease in the price of crude oil inventory. The Company has crude oil inventories that are feedstock, held at terminals, or part of the in-process inventories at its refineries and at offshore sites. These inventories are subject to a lower of cost or net realizable value test on a monthly basis.

ii) Foreign Exchange Risk Management

The Company’s results are affected by the exchange rates between various currencies, including the Canadian and U.S. dollar. The majority of the Company’s revenues are received in U.S. dollars or 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. The majority of the Company’s expenditures are in Canadian dollars. The Company enters into short-dated foreign exchange contracts to fix the exchange rate for conversion of U.S. revenue dollars to hedge against these fluctuations and to mitigate its exposure to foreign exchange risk.

A change in the value of the Canadian dollar against the U.S. dollar will also result in an increase or decrease in the Company’s U.S. dollar denominated debt, as expressed in Canadian dollars, as well as the related finance expense. In order to mitigate the Company’s exposure to long-term debt affected by the U.S./Canadian dollar exchange rate, the Company may enter into cash flow hedges using cross currency debt swap arrangements. In addition, a portion of the Company’s U.S. dollar denominated debt has been designated as a hedge of a net investment in a foreign operation which has a U.S. dollar functional currency. The unrealized foreign exchange gain related to this hedge is recorded in OCI.

At December 31, 2012, the Company had designated U.S. $2.8 billion of its U.S. denominated debt as a hedge of the Company’s net investment in its U.S. refining operations (December 31, 2011 – U.S. $1.3 billion). Of this amount, U.S. $700 million was designated in the first quarter of 2012 and included the U.S. $500 million of the 3.95% senior unsecured notes issued on March 22, 2012. During the third quarter of 2012, U.S. $800 million was designated, including U.S. $50 million of the 7.25% notes and U.S. $750 million of the 5.90% notes issued in 2009. For the year ended December 31, 2012, the unrealized loss arising from the translation of the debt was $15 million (2011 – loss of $18 million), net of tax of $2 million (2011 – $3 million), which was recorded in OCI. At December 31, 2012, the fair value of the hedge was $97 million recorded in long-term debt in the consolidated balance sheets (December 31, 2011 - $80 million).

iii) Interest Rate Risk Management

Interest rate risk is the impact of fluctuating interest rates on earnings, cash flows and valuations. To mitigate risk related to interest rates, the Company may enter into fair value hedges using interest rate swaps. At December 31, 2012, the balance in long-term debt related to deferred gains resulting from unwound interest rate swaps that were designated as a fair value hedge was $72 million (December 31, 2011 – $93 million). The amortization of the accrued gain upon terminating the interest rate swaps resulted in an offset to finance expenses of $21 million for the year ended December 31, 2012 (2011 – offset of $9 million).

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54

Cash flow hedges may also be used to mitigate risk related to interest rates. At December 31, 2012, the Company had entered into a cash flow hedge using forward starting interest rate swap arrangements whereby the Company fixed the underlying U.S. 10-year Treasury Bond rate on U.S. $500 million to June 16, 2014, which is the Company’s forecasted debt issuance on the same date. The effective portion of these contracts has been recorded at fair value in other assets; there was no ineffective portion at December 31, 2012. The forward starting swaps have the following terms and fair value as at December 31, 2012:

				December 31, 2012
Forward Starting Swaps ($ millions)	Swap Rate(1)			Notional Amount (U.S. $  millions)		Fair Value
Swap Maturity
June 15, 2024		2.24	%		105		—
June 16, 2024		2.25	%		310		1
June 17, 2024		2.24	%		85		—
					500		1

⁽¹⁾  Weighted average rate.

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iv) Financial Position of Market Risk Management Contracts

The Company has the following risk management contracts and related inventory recognized at fair value in the consolidated balance sheets at December 31, 2012 and 2011:

Financial Position	December 31, 2012								December 31, 2011
($ millions)	Asset		Liability			Net			Asset			Liability			Net
Commodity Price
Natural gas contracts		3		(2	)		1			2			(2	)		—
Natural gas storage contracts		10		—			10			32			(8	)		24
Natural gas storage inventory(1)		6		—			6			(9	)		—			(9	)
Crude oil contracts(2)		—		—			—			—			(8	)		(8	)
Crude oil inventory(3)		—		—			—			2			—			2
Crude oil contracts		—		(3	)		(3	)		—			(4	)		(4	)
Crude oil inventory(4)		53		—			53			6			—			6
Foreign Currency
Cross currency swaps(5)		—		—			—			—			(2	)		(2	)
Foreign currency forwards		—		—			—			1			—			1
Interest Rates
Forward starting swaps		1		—			1			—			—			—
		73		(5	)		68			34			(24	)		10

⁽¹⁾  Represents the fair value adjustment to 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 $107 million at December 31, 2012 (December 31, 2011 – $121 million).

⁽²⁾  Certain crude oil physical purchase contracts were designated as a fair value hedge against changes in the fair value of the related inventory held in storage. During 2012, the fair value hedging relationship was discontinued and only fair value changes related to the derivative contracts continued to be recorded in the consolidated balance sheets.

⁽³⁾  Represents the fair value adjustment to inventory recognized in the consolidated balance sheets related to the crude oil physical purchase contracts designated as a fair value hedge. During 2012, the fair value hedging relationship was discontinued and the total fair value adjustment of the related crude oil inventory was nil at December 31, 2012 (December 31, 2011 – $16 million).

⁽⁴⁾  Represents the fair value adjustment to inventory recognized in the consolidated balance sheets related to third-party crude oil physical purchase and sale contracts. Total fair value adjustment of the related crude oil inventory was $221 million at December 31, 2012 (December 31, 2011 – $147 million).

⁽⁵⁾  Represents the fair value adjustment to cross currency swaps related to a portion of the Company’s U.S. denominated debt designated in a cash flow hedging relationship for foreign currency risk management. The hedging relationship expired in the second quarter of 2012 with the repayment of the related U.S. $400 million of 6.25% notes which matured on June 15, 2012 and the settlement of the cross currency swaps on the same day. Refer to Note 13.

Consolidated Financial Statements

56

v) Earnings Impact of Market Risk Management Contracts

The gains (losses) recognized on risk management positions for the years ended December 31, 2012 and 2011 are set out below. All gains (losses) are unrealized, unless otherwise noted.

	2012
Earnings Impact ($ millions)	Marketing and Other			Purchases of Crude Oil and Products			Other – Net			Net Foreign Exchange Gains (Losses)			OCI
Commodity Price
Natural gas		2			—			—			—			—
Crude oil(1)		48			(2	)		—			—			—
		50			(2	)		—			—			—
Foreign Currency
Cross currency swaps(2)		—			—			(2	)		2			2
Foreign currency forwards(3)		—			—			(1	)		(5	)		—
		—			—			(3	)		(3	)		2
Interest Rates
Forward starting swaps		—			—			—			—			1
		50			(2	)		(3	)		(3	)		3
	2011
Earnings Impact ($ millions)	Marketing and Other			Purchases of Crude Oil and Products			Other – Net			Net Foreign Exchange Gains (Losses)			Finance Expenses
Commodity Price
Natural gas		(11	)		—			—			—			—
Crude oil(1)		4			(6	)		—			—			—
		(7	)		(6	)		—			—			—
Foreign Currency
Cross currency swaps		—			—			2			7			—
Foreign currency forwards(3)		—			—			1			(5	)		—
		—			—			3			2			—
Interest Rates
Interest rate swaps(4)		—			—			—			—			13
		(7	)		(6	)		3			2			13

⁽¹⁾  Certain crude oil physical purchase contracts were designated as a fair value hedge with fair value changes recognized in purchases of crude oil and products in the consolidated statements of income. During 2012, the fair value hedging relationship was discontinued and only fair value changes related to the derivative contracts continued to be recorded in purchases of crude oil and products.

⁽²⁾  A portion of the Company’s U.S. denominated debt was designated in a cash flow hedging relationship for foreign currency risk management, with the use of cross currency swaps, until expiration of the hedging relationship in the second quarter of 2012 with the repayment of the related U.S. $400 million of 6.25% notes which matured on June 15, 2012 and the settlement of the cross currency swaps on the same day. Refer to Note 13. The balance of $2 million included in other reserves was reclassified into net earnings upon the repayment of the debt and concurrent settlement of the cross currency swaps.

⁽³⁾  Unrealized gains or losses from short-dated foreign currency forwards are included in other – net, while realized gains or losses are included in net foreign exchange gains in the consolidated statements of income.

⁽⁴⁾  A portion of the Company’s debt was designated in a fair value hedging relationship for interest rate risk management and recorded at fair value until discontinuation of the hedging relationship in 2011. Amortization of the accrued gain recognized upon termination of the interest rate swaps is not included in this table and is discussed in the Interest Rate Swaps section below.

Consolidated Financial Statements

57

vi) 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 and related inventories 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		36		(36	)
Natural gas price		—		—
Foreign Exchange Rate(2) ($ millions)	Canadian dollar $0.01 increase		Canadian dollar $0.01 decrease
U.S. dollar per Canadian dollar		1		(1	)
Interest Rate(3) ($ millions)	100 basis point increase		100 basis points decrease
LIBOR		44		(50	)

⁽¹⁾  Based on average crude oil and natural gas market prices as at December 31, 2012.

⁽²⁾  Based on the U.S./Canadian dollar exchange rate as at December 31, 2012.

⁽³⁾  Based on U.S. LIBOR as at December 31, 2012.

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 availability to raise capital from various debt 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, repay maturing debt and pay dividends. 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.

Consolidated Financial Statements

58

The Company had the following available credit facilities as at December 31, 2012:

Credit Facilities ($ millions)	Available		Unused
Operating facilities(1)		515		280
Syndicated bank facilities		3,100		3,100
		3,615		3,380

⁽¹⁾  Consists of demand credit facilities.

In addition to the credit facilities listed above, the Company had unused capacity under the universal short form base shelf prospectus filed in Canada of $3.0 billion and unused capacity under the universal short form base shelf prospectus filed in the United States of U.S. $1.5 billion. The unused capacity of two Canadian shelf prospectuses expired in 2012. The unused capacity of $300 million under the debt shelf prospectus filed in Canada in December 2009 expired in January 2012 and the unused capacity of $1.4 billion under the debt shelf prospectus filed in Canada in November 2010 expired in December 2012. The ability of the Company to raise additional capital utilizing these 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.

The following are the contractual maturities of the Company’s financial liabilities as at December 31, 2012:

Contractual Maturities of Financial Liabilities ($ millions)	2013		2014		2015		2016		2017		Thereafter
Accounts payable and accrued liabilities		2,986		—		—		—		—		—
Other long-term liabilities		3		52		38		3		3		29
Long-term debt		227		951		477		371		455		3,125

The Company’s contribution payable pursuant to the joint arrangement with BP is payable between December 31, 2012 and December 31, 2015, with the final balance due and payable by December 31, 2015. Refer to Note 8 and Note 20 for additional contractual obligations.

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 did not have any external customers that constituted more than 10% of gross revenues during the years ended December 31, 2012 and December 31, 2011, with the exception of the Company’s joint venture partner BP, relating to revenues from the BP-Husky Toledo Refinery.

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 contribution receivable represent the Company’s maximum credit exposure.

Consolidated Financial Statements

59

The Company’s accounts receivable was aged as follows at December 31, 2012:

Accounts Receivable Aging ($ millions)	December 31, 2012
Current		1,245
Past due (1 – 30 days)		95
Past due (31 – 60 days)		10
Past due (61 – 90 days)		6
Past due (more than 90 days)		16
Allowance for doubtful accounts		(23	)
		1,349

The Company recognizes a valuation allowance 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, 2012, the Company impaired $4 million (2011 – $3 million) of uncollectible receivables.

Consolidated Financial Statements

60

Note 23 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 at December 31, 2012 was $23.1 billion (December 31, 2011 – $21.7 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 capital based on the current and projected ratios of debt to cash flow (defined as total debt divided by cash flow – operating activities plus non-cash charges before settlement of asset retirement obligations, income taxes paid, interest received and changes in non-cash working capital) and debt to capital employed (defined as total debt divided by total debt and shareholders’ equity). The Company’s objective is to maintain a debt to capital employed target of less than 25% and a debt to cash flow ratio of less than 1.5 times. At December 31, 2012, debt to capital employed was 17% (December 31, 2011 – 18%) which was below the long-term range, providing the financial flexibility to fund the Company’s capital program and profitable growth opportunities. At December 31, 2012, debt to cash flow was 0.8 times (December 31, 2011 – 0.8 times). The ratio may increase at certain times as a result of capital spending. To facilitate the management of this ratio, 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 cash flow covenant. The Company was fully compliant with these covenants at December 31, 2012.

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

Note 24 Government Grants

The Company has government assistance programs in place where it receives funding based on ethanol production and sales from the Lloydminster and Minnedosa ethanol plants from the Department of Natural Resources and the Government of Manitoba. The programs expire in 2015 and applications for funding are submitted quarterly. During 2012, the Company received $40 million (2011 – $38 million) under these programs. The grants accrued for operational purposes have been recorded as revenues in the consolidated statements of income.

Consolidated Financial Statements

61

Document C

Form 40-F

Management’s Discussion and Analysis

March 8, 2013

MANAGEMENT’S DISCUSSION AND ANALYSIS

1.0 Financial Summary

1.1 Financial Position

1.2 Financial Performance

⁽¹⁾  Debt to capital employed, debt to cash flow, return on equity, return on capital employed and return on capital in use constitute non-GAAP measures. (Refer to Section 11.3)

1.3 Total Shareholder Returns

The following graph shows the total shareholder returns compared with the Standard and Poor’s (“S&P”) and the Toronto Stock Exchange (“TSX”) energy and composite indices.

Management’s Discussion and Analysis 2012

1

1.4 Selected Annual Information

($ millions, except where indicated)	2012			2011			2010
Gross revenues		23,128			23,082			18,085
Net earnings by segment(1)
Upstream		1,320			1,711			861
Midstream		—			—			160
Downstream		895			813			160
Corporate		(193	)		(300	)		(187	)
Eliminations		—			—			(47	)
Net earnings		2,022			2,224			947
Net earnings per share – basic		2.06			2.40			1.11
Net earnings per share – diluted		2.06			2.34			1.05
Ordinary dividends per common share		1.20			1.20			1.20
Dividends per cumulative redeemable preferred share, series 1		1.11			0.87			—
Cash flow from operations(2)		5,010			5,198			3,072
Total assets		35,140			32,426			28,050
Other long-term financial liabilities		331			342			102
Long-term debt including current portion		3,918			3,911			4,187
Total non-current financial liabilities		12,886			11,263			10,907
Cash and cash equivalents		2,025			1,841			252
Return on equity (percent)(2)(3)		10.9			13.8			6.7
Return on capital in use (percent)(2)(4)		12.7			15.6			8.4
Return on capital employed (percent)(2)(5)		9.5			11.8			6.4

⁽¹⁾  During the first quarter of 2012, the Company completed an evaluation of the activities of the former Midstream segment as a service provider to the Upstream and Downstream operations. As a result, the segmented financial information for activities within the previously reported Midstream segment are presented under Upstream or Downstream segments to align with how the Company’s results are assessed by management. Prior period information relating to 2011 has been restated to conform with current year presentation. The 2010 information has not been restated.

⁽²⁾  Cash flow from operations and financial ratios constitute non-GAAP measures. (Refer to Section 11.3)

⁽³⁾  Return on equity equals net earnings divided by the two-year average shareholder’s equity. (Refer to Section 11.3)

⁽⁴⁾  Return on capital in use equals net earnings plus after tax interest expense divided by the two-year average of capital employed less any capital invested in assets that are not generating cash flows.(Refer to Section 11.3)

⁽⁵⁾  Return on capital employed equals net earnings plus after-tax finance expense divided by the two-year average of long-term debt including long-term debt due within one year plus total shareholders’ equity.(Refer to Section 11.3)

2.0 Husky Business Overview

Husky Energy Inc. (“Husky” or the “Company”) is one of Canada’s largest integrated energy companies. It is based in Calgary, Alberta, and is publicly traded on the TSX under the symbols HSE and HSE.PR.A. The Company operates in Western Canada, the United States, the Asia Pacific Region and the Atlantic Region with Upstream and Downstream business segments. Husky’s balanced growth strategy focuses on consistent execution, disciplined financial management and safe and reliable operations.

During 2012, the Company completed an evaluation of activities of the Company’s former Midstream segment as a service provider to the Upstream or Downstream operations. As a result, and consistent with the Company’s strategic view of its integrated business, the previously reported Midstream segment activities are aligned and reported within the Company’s core exploration and production, or within upgrading and refining businesses. The Company believes this change in segment presentation allows management and third parties to more effectively assess the Company’s performance. The current period and 2011 year results have been revised to conform to the new segment presentation.

Management’s Discussion and Analysis 2012

2

2.1 Upstream

Profile and highlights of the Upstream segment include:

• Large base of crude oil producing properties in Western Canada that continue to produce with existing technology and have responded well to the application of increasingly sophisticated techniques such as horizontal drilling. Enhanced oil recovery (“EOR”) techniques including thermal in-situ recovery methods have been extensively used in the mature Western Canada Sedimentary Basin to increase recovery rates and to stabilize decline rates of light and heavy crude oil. EOR techniques such as Alkaline Surfactant Polymer (“ASP”) are being field tested and advanced, while techniques that have been in practice for several decades continue to be optimized;

• A large position in Western Canada gas resource plays with approximately 1,000,000 net acres associated with both liquids-rich and dry gas positions;

• Active oil resource play portfolio of approximately 800,000 net acres focusing in the Bakken, Viking, Cardium, Rainbow Muskwa and Canol shale formations;

• Expertise and experience exploring and developing the natural gas potential in the Alberta Deep Basin, Foothills, and northwest plains of Alberta and British Columbia;

• Husky and BP have advanced the development of the Sunrise Energy Project, which is a multiple stage, in-situ oil sands development with first production expected in 2014. Phase 1 is approximately 65% complete and is expected to produce approximately 60,000 bbls/day (30,000 bbls/day net Husky share). Sunrise will use proven steam-assisted gravity drainage (“SAGD”) technology, keeping site disturbance to a minimum. Regulatory approval is in place to expand the project to 200,000 bbls/day (100,000 bbls/day net Husky share) and planning has advanced for the next phase of the project;

• In addition to Sunrise, Husky has an extensive portfolio of undeveloped oil sands leases, encompassing in excess of 550,000 acres in northern Alberta;

• Offshore China includes a production interest in the Wenchang oil field and significant natural gas discoveries at the Liwan 3-1, Liuhua 34-2 and Liuhua 29-1 fields within Block 29/26;

• The Liwan Gas Project development on Block 29/26 in the South China Sea has been approved by the Chinese Government and is now more than 80% complete and on track to achieve planned first production in late 2013/early 2014;

• Husky has a 40% interest in the Madura Strait Block covering approximately 622,000 acres, offshore East Java, south of Madura Island, Indonesia, and is focused on the development of the BD, MDA and MBH natural gas and natural gas liquids fields;

• In 2012, Husky signed a joint venture contract with CPC Corporation, Taiwan for an exploration block in the South China Sea covering approximately 10,000 square kilometers located 100 kilometers southwest of the island of Taiwan. Husky holds a 75% working interest during exploration while CPC Corporation has the right to participate in the development program up to a 50% interest;

• Husky is the operator of the White Rose field with a 72.5% working interest in the core field and a 68.9% working interest in satellite tiebacks, including the North Amethyst, West White Rose and South White Rose extensions. Development continues at White Rose and its three satellite extensions. Husky has a 13% non-operated interest in the Terra Nova oil field;

• Husky holds ownership interests in the producing oil fields at Terra Nova, White Rose and its satellites and North Amethyst. Husky also has a large portfolio of significant discovery and exploration licences offshore Newfoundland and Labrador and offshore Greenland (collectively referred to as the “Atlantic Region”). The offshore exploration and development program is focused in the Jeanne d’Arc Basin and the Flemish Pass.

• Integrated heavy oil pipeline systems in the Lloydminster producing region;

• The Infrastructure and Marketing business managed third-party commodity trading volumes of approximately 180 mboe/day in 2012 and managed access to capacity on third-party pipelines and storage facilities in both Canada and the United States and natural gas storage in excess of 45 bcf, owned and leased.

Management’s Discussion and Analysis 2012

3

2.2 Downstream

Profile and highlights of the Downstream segment include:

• Heavy oil upgrading facility located in the Lloydminster, Saskatchewan heavy oil producing region with a throughput capacity of 82 mbbls/day;

• Refinery at Lima, Ohio and a 50% interest in the BP-Husky Refinery in Toledo, Ohio, each with a gross crude oil throughput capacity of 160 mbbls/day;

• Refinery at Prince George, British Columbia with throughput capacity of 12 mbbls/day producing low sulphur gasoline and ultra low sulphur diesel;

• Largest marketer of paving asphalt in Western Canada with a 29 mbbls/day capacity asphalt refinery located at Lloydminster, Alberta integrated with the local heavy oil production, transportation and upgrading infrastructure;

• Largest producer of ethanol in Western Canada with a combined 260 million litre per year capacity at plants located in Lloydminster, Saskatchewan and Minnedosa, Manitoba; and

• Major regional motor fuel marketer with 512 retail marketing locations as at December 31, 2012 including bulk plants and travel centres with strategic land positions in Western Canada and Ontario.

3.0 The 2012 Business Environment

Husky’s operations are significantly influenced by domestic and international business environment factors. The global crude oil and liquid fuel industry is impacted by various factors, including those encountered during 2012, that are anticipated to continue to impact the industry to varying degrees into 2013 and beyond. Business factors impacting Husky’s industry during 2012 include but are not limited to the following:

• The proliferation of shale oil plays in the Bakken, the Permian and the Eagle Ford have outpaced EIA production forecasts for the U.S.;

• Key takeaway capacity constraints still exist for Western Canadian crudes in North America causing a widening of differentials of these crudes relative to key benchmarks such as West Texas Intermediate (“WTI”);

• Pricing benchmarks for crude oil and natural gas and underlying market supply and demand drivers;

• Political unrest in the Middle East have caused continued unplanned production outages having an impact on crude oil benchmark pricing;

• Expected continued production growth in both U.S. shale oil formations and from the Western Canadian oil sands with approximately 260 bitumen projects in progress at various stages from research to exploration, development and completion;

• Industry advancement in alternate and improved extraction methods have rapidly evolved North American and international on-shore and offshore activity;

• All-time high U.S. natural gas inventories with increased production from shale gas and liquids-rich gas plays have resulted in downward pressure on North American natural gas pricing;

• Economic conditions remain uncertain as national indebtedness among countries continues to impact global GDP growth;

• Continued global economic uncertainty has led to a tightening of investment, creating greater competition among companies within capital markets;

• Increasing globalization, larger projects with major partners, and economies of scale;

• Strong demand for natural gas in Asian markets has led to robust gas pricing in the region;

• Domestic and international political, regulatory and tax system changes; and

• A continuing emphasis on environmental, health and safety, enterprise risk management, resource sustainability and corporate social responsibility.

Major business factors are considered in the formulation of Husky’s short and longer term business strategy.

The Company is exposed to a number of risks inherent to the exploration, development, production, marketing, transportation, storage and sale of crude oil, liquids-rich gas and natural gas and related products. For a discussion on Risks and Risk Management see Section 7.0 and the 2012 Annual Information Form.

Management’s Discussion and Analysis 2012

4

Commodity prices, foreign exchange rates and refining crack spreads are some of the most significant factors that affect the results of Husky’s operations.

Average Benchmarks		2012		2011
WTI crude oil	(U.S. $/bbl)		94.21		95.12
Brent crude oil	(U.S. $/bbl)		111.54		111.27
Canadian light crude 0.3% sulphur	($/bbl)		86.57		95.32
Western Canada Select @ Hardisty	(U.S. $/bbl)		73.18		77.97
Lloyd heavy crude oil @ Lloydminster	($/bbl)		62.89		67.61
NYMEX natural gas	(U.S. $/mmbtu)		2.79		4.04
NIT natural gas	($/GJ)		2.28		3.48
WTI/Lloyd crude blend differential	(U.S. $/bbl)		21.46		17.44
New York Harbor 3:2:1 crack spread	(U.S. $/bbl)		31.36		25.26
Chicago 3:2:1 crack spread	(U.S. $/bbl)		27.63		24.65
U.S./Canadian dollar exchange rate	(U.S. $)		1.001		1.011
Canadian Equivalents
WTI crude oil	($/bbl)		94.12		94.09
Brent crude oil	($/bbl)		111.43		110.06
WTI/Lloyd crude blend differential	($/bbl)		21.44		17.25
NYMEX natural gas	($/mmbtu)		2.79		4.00

As an integrated producer, Husky’s profitability is largely determined by realized prices for crude oil and natural gas, marketing margins on committed pipeline capacity and refinery processing margins, including the effect of changes in the U.S./Canadian dollar exchange rate. All of Husky’s crude oil production and the majority of its natural gas production receive the prevailing market price. The market price for crude oil is determined largely by North American and global factors and is beyond the Company’s control. The price for natural gas is determined more by North American fundamentals since virtually all natural gas production in North America is consumed by North American customers, predominantly in the United States. Weather conditions also exert a significant effect on short-term supply and demand.

The Downstream segment is heavily impacted by the price of crude oil and natural gas. The largest cost factor in the Downstream segment is crude oil feedstock, a portion of which is heavy crude oil. In the upgrading business segment, heavy crude oil feedstock is processed into light synthetic crude oil. Husky’s U.S. refining operations process a mix of different types of crude oil from various sources but are primarily light sweet crude oil at the Lima Refinery and approximately 50% heavy crude oil feedstock at the BP-Husky Toledo Refinery. The Company’s refined products business in Canada relies primarily on purchased refined products for resale in the retail distribution network. Refined products are acquired from other Canadian refiners at rack prices or exchanged with production from the Husky Prince George Refinery.

Management’s Discussion and Analysis 2012

5

Crude Oil

The price Husky receives for production from Western Canada is primarily driven by changes in the price of WTI and discounts or premiums to Western Canadian crude prices while the majority of the Company’s production in the Atlantic Region and the Asia Pacific Region is referenced to the price of Brent, an imported light sweet benchmark crude oil produced in the North Sea. The price of WTI ended 2012 at U.S. $94.19/bbl compared to U.S. $98.83/bbl on December 31, 2011, and averaged U.S. $94.21/bbl in 2012 compared with U.S. $95.12/bbl in 2011. The price of Canadian light crude ended 2012 at $74.32/bbl compared to $98.19/bbl on December 31, 2011 and averaged $86.57/bbl in 2012 compared with $95.32/bbl in 2011. The price of Brent ended 2012 at U.S. $111.66/bbl, compared to U.S. $106.51/bbl on December 31, 2011, and averaged U.S. $111.54/bbl in 2012 compared with U.S. $111.27/bbl in 2011.

A portion of Husky’s crude oil production is classified as either heavy crude oil or bitumen, which trades at a discount to light crude oil. In 2012, 54% of Husky’s crude oil production was heavy crude oil or bitumen compared with 47% in 2011. The increase in the 2012 heavy oil to total crude oil production weighting was due to lower light crude oil production from the Atlantic Region where two planned offstation turnarounds for the SeaRose and Terra Nova floating, production, storage and offloading vessels (“FPSO”) were completed combined with increased production from new heavy oil thermal projects. The light/heavy crude oil differential averaged U.S. $21.46/bbl or 23% of WTI in 2012 compared to U.S. $17.44/bbl or 18% of WTI in 2011.

Management’s Discussion and Analysis 2012

6

Natural Gas

In 2012, 31% of Husky’s total oil and gas production was natural gas compared with 32% in 2011. The near-month natural gas price quoted on the NYMEX ended 2012 at U.S. $3.35/mmbtu compared with U.S. $2.99/mmbtu at December 31, 2011. During 2012, the NYMEX near-month contract price of natural gas averaged U.S. $2.79/mmbtu compared with U.S. $4.04/mmbtu in 2011.

Foreign Exchange

The majority of the Company’s revenues from the sale of oil and gas commodities receive prices determined by reference to U.S. benchmark prices. The majority of the Company’s expenditures are in Canadian dollars. A decrease in the value of the Canadian dollar relative to the U.S. dollar increases the revenues received from the sale of oil and gas commodities. Correspondingly, an increase in the value of the Canadian dollar relative to the U.S. dollar decreases the revenues received from the sale of oil and gas commodities. The majority of the Company’s long-term debt is denominated in U.S. dollars. A decrease in the value of the Canadian dollar relative to the U.S. dollar increases the principal amount owing on long-term debt at maturity and the associated interest payments. In addition, changes in foreign exchange rates impact the translation of the foreign operations of the U.S. Downstream segment and the Asia Pacific Region.

The Canadian dollar ended 2011 at U.S. $0.983 and closed at U.S. $1.005 on December 31, 2012. In 2012, the Canadian dollar averaged U.S. $1.001 weakening by 1% compared with U.S. $1.011 during 2011. In 2012, the price of WTI in U.S. dollars decreased by 1% and nil in Canadian dollars when compared to 2011 with the weakening of the Canadian dollar versus the U.S. dollar offsetting the movement in crude oil prices.

Management’s Discussion and Analysis 2012

7

Refining Crack Spreads

The 3:2:1 refining crack spread is the key indicator for refining margins as refinery gasoline output is approximately twice the distillate output. This crack spread is equal to the price of two-thirds of a barrel of gasoline plus one-third of a barrel of fuel oil (distillate) 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 necessarily reflect the actual crude oil purchase costs or product configuration of a specific refinery. Each refinery has a unique crack spread depending on several variables. Realized refining margins are affected by the product configuration of each refinery, crude oil feedstock, product slates, transportation costs to benchmark hubs and by the time lag between the purchase and delivery of crude oil, which is accounted for on a first in first out (“FIFO”) basis in accordance with International Financial Reporting Standards (“IFRS”).

The New York Harbor 3:2:1 refining crack spread benchmark is calculated as the difference between the price of a barrel of WTI crude oil and the sum of the price of two-thirds of a barrel of reformulated gasoline and the price of one-third of a barrel of heating oil. The Chicago 3:2:1 refining crack spread benchmark is calculated based on WTI, regular unleaded gasoline and ultra low sulphur diesel.

During 2012, the New York Harbor 3:2:1 refining crack spread averaged U.S. $31.36/bbl compared with U.S. $25.26/bbl in 2011 and the Chicago 3:2:1 crack spread averaged U.S. $27.63/bbl in 2012 compared with U.S. $24.65/bbl in 2011.

The following table is indicative of the relative annualized effect on pre-tax earnings and net earnings from changes in certain key variables in 2012. The table below shows what the effect would have been on 2012 financial results had the indicated variable increased by the notional amount. The analysis is based on business conditions and production volumes during 2012. Each separate item in the sensitivity analysis shows the effect of an increase in that variable only; all other variables are held constant. While these sensitivities are applicable 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 greater magnitudes of change.

Management’s Discussion and Analysis 2012

8

Sensitivity Analysis	2012 Average		Increase	Effect on Pre-tax Earnings(1)						Effect on Net Earnings(1)
				($ millions)			($/share)(2)			($ millions)			($/share)(2)
WTI benchmark crude oil price(3)(4)		94.21	U.S. $1.00/bbl		66			0.07			49			0.05
NYMEX benchmark natural gas price(5)		2.79	U.S. $0.20/mmbtu		24			0.02			18			0.02
WTI/Lloyd crude blend differential(6)		62.89	U.S. $1.00/bbl		(16	)		(0.02	)		(12	)		(0.01	)
Canadian light oil margins		0.044	Cdn $0.005/litre		16			0.02			12			0.01
Asphalt margins		22.90	Cdn $1.00/bbl		9			0.01			7			0.01
New York Harbor 3:2:1 crack spread(7)		31.36	U.S. $1.00/bbl		53			0.05			34			0.03
Exchange rate (U.S. $ per Cdn $)(3)(8)		1.001	U.S. $0.01		(55	)		(0.06	)		(41	)		(0.04	)

⁽¹⁾  Excludes mark to market accounting impacts.

⁽²⁾  Based on 982.2 million common shares outstanding as of December 31, 2012.

⁽³⁾  Does not include gains or losses on inventory.

⁽⁴⁾  Includes impacts related to Brent-based production.

⁽⁵⁾  Includes impact of natural gas consumption.

⁽⁶⁾  Excludes impact on asphalt operations.

⁽⁷⁾  Relates to U.S. Refining & Marketing.

⁽⁸⁾  Assumes no foreign exchange gains or losses on U.S. dollar denominated long-term debt and other monetary items, including cash balances.

4.0 Strategic Plan

Husky’s strategy is to maintain and enhance production in its Heavy Oil and Western Canada foundation as it repositions these areas toward thermal developments and resource plays, while advancing its three major growth pillars in the Asia Pacific Region, Oil Sands and in the Atlantic Region. The Company’s Downstream assets provide specialized support to its Upstream operations to enhance efficiency and extract additional value from production.

Husky’s strategic direction by business segment is summarized as follows:

4.1 Upstream

Husky has a substantial portfolio of assets in Western Canada. New technologies are making it possible to economically access new pools and recover more production from existing reservoirs. The Company is active in the exploration and production of heavy oil, light crude oil, natural gas and natural gas liquids. The Western Canada strategy is comprised of maintaining production while refocusing by growing oil resource plays, directing capital into liquids-rich natural gas plays and expanding thermal and horizontal drilling in heavy oil. Approximately two-thirds of Upstream production is oil-weighted. Husky is advancing its oil resource play position with activities in the Bakken, Viking, Cardium, Lower Shaunavon, Muskwa and Canol formations, with approximately 800,000 net acres of oil resource play inventory. Husky also has a large position in Western Canada gas resource plays, with approximately 1,000,000 net acres associated with both liquids-rich and dry gas positions.

Husky has an extensive portfolio of oil sands leases, encompassing 2,500 square kilometers in northern Alberta. Husky has advanced the development of the Sunrise Energy Project, which is a multiple stage, in-situ oil sands development with first phase construction and drilling having commenced in 2011. The first phase, which represents a $2.7 billion investment, is expected to produce approximately 60,000 barrels per day with anticipated first production beginning in 2014. Husky’s working interest is 50%. Sunrise will use proven steam-assisted gravity drainage (“SAGD”) technology, keeping site disturbance to a minimum.

The Asia Pacific Region consists of the Wenchang oil field, the Liwan Gas Project (“Block 29/26”) located offshore China and the Madura Strait block BD, MDA and MBH development fields offshore Indonesia. The Liwan 3-1 field in Block 29/26, located approximately 300 kilometers southeast of Hong Kong, is an important component of the Company’s near term production growth strategy and a key step in accessing the burgeoning energy markets in Hong Kong and Mainland China. Husky has partnered with China National Offshore Oil Corporation (“CNOOC”) on the development, with first gas production anticipated in late 2013/early 2014. In addition to the producing Wenchang oil field, the natural gas discoveries on Block 29/26 and growth opportunities in Indonesia, including the BD, MDA and MBH developments in the Madura Strait Production Sharing Contract (“PSC”), represent growth areas for Husky in the Asia Pacific Region.

Management’s Discussion and Analysis 2012

9

The Atlantic Region continues to be a focus area with current production of approximately 48,000 bbls/day of crude oil. The Company holds interests in eight Production Licences, 17 Exploration Licences and 23 Significant Discovery Areas. Development activity at the White Rose core field and its satellites, including North Amethyst and the West and South White Rose extensions continues to advance. Husky also holds significant exploration acreage in the Atlantic Region. Work is progressing to identify innovative ways to further develop the significant resources in the region.

The Infrastructure and Marketing business unit supports Upstream production while providing integration with the Company’s Downstream assets through optimization of market access for Husky’s upstream production.

4.2 Downstream

Downstream supports heavy oil and oil sands production and makes prudent reinvestments in respect of feedstock, product and market access feasibility. Husky plans to continue to pursue projects to optimize, integrate and reconfigure the Lima, Ohio Refinery for additional crude oil feedstock and product flexibility and reconfigure and increase capacity at the BP-Husky Toledo Refinery to accommodate Sunrise production as its primary feedstock. The Company also plans to expand terminal pipeline access and product storage opportunities to enhance market access.

4.3 Financial

Husky is committed to ensuring sufficient liquidity, financial flexibility and access to long-term capital to fund the Company’s growth and support dividend payments. Husky 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.

Husky intends to continue to maintain a strong balance sheet to provide financial flexibility. The Company’s target is to maintain a debt to cash flow ratio of under 1.5 times and a debt to capital employed ratio of under 25%, which are both non-GAAP measures (refer to Section 11.3). Husky is committed to retaining its investment grade credit ratings to support access to debt capital markets.

The significant asset base in the Company’s foundational businesses in Western Canada provides a steady source of cash flow to reinvest in its growth projects, including the Asia Pacific Region, the Oil Sands and the Atlantic Region of Canada. As these significant growth projects are developed, the Company expects that they will provide steady sources of cash for the Company.

5.0 Key Growth Highlights

The 2012 Capital Program supported the repositioning of the Heavy Oil and Western Canada foundation by accelerating near-term production growth and advancing Husky’s three major growth pillars in the Asia Pacific Region, the Oil Sands and the Atlantic Region.

5.1 Upstream

Western Canada (excluding Heavy Oil and Oil Sands)

Husky continued to progress crude oil and liquids-rich gas resource plays as a core element of its Western Canada foundation. Total production from these resource plays at the end of 2012 was approximately 20,000 bbls/day, representing a 70% increase compared to 2011.

Management’s Discussion and Analysis 2012

10

Oil Resource Plays

During 2012, the Company continued to advance exploration and development projects on its extensive oil resource land base of approximately 800,000 net acres. A total of 93 horizontal wells and two vertical wells were drilled and 78 horizontal wells were completed in 2012. It is anticipated that up to 88 wells will be drilled during the 2013 oil resource drilling program.

The following table summarizes the oil resource play drilling and completion activity for the year ended December 31, 2012:

Oil Resource Plays(1)		Year ended December 31, 2012
Project	Location	Gross Wells Drilled		Gross Wells Completed
Oungre Bakken	S.E. Saskatchewan		22		21
Lower Shaunavon	S.W. Saskatchewan		4		4
Viking (2)	Alberta and S.W. Saskatchewan		50		45
N.Cardium	Wapiti, Alberta		5		5
Rainbow Muskwa	Northern Alberta		12		3
Slater River	Northwest Territories		2		—
Total Gross			95		78
Total Net			89		74

⁽¹⁾  Excludes service/stratigraphic test wells for evaluation purposes. All activity was horizontal except Slater River N.W.T. , vertical wells.

⁽²⁾  Viking is comprised of project activity at Redwater in central Alberta, Alliance in Southeastern Alberta and drilling in Southwestern Saskatchewan.

At the Rainbow Muskwa play, the first horizontal shale oil well was placed on production to a single well battery and is being monitored.

At the Slater River Project in the Northwest Territories, the Company drilled two vertical wells and a 220 square kilometre three-dimensional (“3-D”) seismic survey was completed.

Liquids-Rich Gas Resource Plays

The following table summarizes the liquids-rich gas drilling and completion activity for the year ended December 31, 2012:

Liquids-Rich Gas Resource Plays(1)		Year ended December 31, 2012
Project	Location	Gross Wells Drilled		Gross Wells Completed
Ansell	West Central Alberta		18		53
Duvernay	West Central Alberta		4		3
Montney	West Central Alberta		1		2
Total Gross			23		58
Total Net			21		56

⁽¹⁾  Excludes service/stratigraphic test wells for evaluation purposes. Liquids-rich gas drilling activity in 2012 was mainly horizontal wells. Completion activity includes legacy vertical wells. Types of drilling include Wilrich and Cardium horizontals and vertical single and multi-zone wells.

Management’s Discussion and Analysis 2012

11

The liquids-rich gas formations at Ansell in west central Alberta continue to be a key area of focus with 55 Cardium and three Wilrich wells on production at the end of 2012.

At the Duvernay play in Kaybob, Alberta, a third horizontal well was completed in 2012 and commenced production in January 2013. In December 2012, the first well on a four well pad of horizontal wells was spud and drilling continues in 2013. A previously completed well is expected to be tied-in during the first quarter of 2013.

Alkaline Surfactant Polymer Floods

Construction was completed on the Fosterton, Saskatchewan Alkaline Surfactant Polymer (“ASP”) facility in 2012. Husky is the operator and holds a 62% working interest in this project. Chemical injection has commenced with initial production response expected in the second half of 2013.

Heavy Oil

Production commenced in the second quarter of 2012 ahead of schedule at both the Pikes Peak South and Paradise Hill heavy oil thermal projects and has ramped up to levels exceeding the combined 11,500 bbls/day design rate capacity. Average production levels of approximately 12,000 bbls/day at Pikes Peak South and 5,000 bbls/day at Paradise Hill heavy oil thermal projects were achieved during the fourth quarter of 2012.

Construction is approximately 40% complete at the 3,500 bbls/day Sandall thermal development project and initial drilling has commenced. First production is scheduled in 2014.

Design and initial site work is continuing at the 10,000 bbls/day Rush Lake commercial project with first production anticipated in 2015. Production performance from the first single well pair pilot is in line with expectations and a second well pair pilot is planned to commence production in the second quarter of 2013. Initial planning is ongoing for three additional commercial thermal projects.

The Company advanced its horizontal drilling program in 2012 with the completion of 144 wells. Based on the positive performance of previous horizontal drilling programs, Husky is continuing this program by planning to drill approximately 140 wells in 2013. The Company also drilled 250 gross cold heavy oil production with sand (“CHOPS”) wells during 2012. In 2013, 200 CHOPS wells are planned.

A carbon dioxide (“CO₂”) capture and liquefaction plant at the Lloydminster Ethanol Plant was commissioned and started producing liquid CO₂ in March 2012. The liquefied CO₂ from this facility is used in the ongoing solvent EOR piloting program.

Asia Pacific Region

China

The Overall Development Plan (“ODP”) for the Liwan Gas Project development on Block 29/26 in the South China Sea has been approved by the Chinese Government. The development project is now more than 80% complete and remains on track to achieve planned first production in late 2013/early 2014.

Two further upper completions in the Liwan 3-1 gas field were installed and flow tested successfully at the expected production rates bringing the total of fully ready production wells to seven. All nine subsea production trees have been installed on the wells and eight associated upper completions have also been installed.

At the end of 2012, approximately 90 kilometers of the two 79-kilometer deep water pipelines connecting the gas field to the central platform have been laid and approximately 190 kilometers out of 261 kilometers of shallow water pipeline have been laid from the central platform to the onshore gas plant. Pipe laying activity is planned to resume in 2013.

The completed jacket for the shallow water central platform was transported from the Qingdao construction yard in Eastern China to its final offshore location in the South China Sea and was successfully launched from the transport barge onto the ocean floor on August 30, 2012. Piling to anchor the feet of the jacket to the seabed has also been completed. Fabrication of the platform topsides is progressing and the floatover of the topsides for the central platform is planned for mid-2013.

Management’s Discussion and Analysis 2012

12

The 850-tonne Monoethylene Glycol Recovery Unit has been delivered to the Qingdao, Eastern China topsides construction site and the approximately 850 tonne unit has been elevated and set into its final installation position on the upper deck. Generators and compressors have also been positioned on the deck. Construction of control rooms, living areas and other facilities are in their final stages.

The contract for the use of the West Hercules deepwater drilling rig expired in July 2012. The deepwater semi-submersible drilling rig, Hai Yang Shi You 981, has been contracted to continue the deepwater development project.

Construction of the onshore gas plant is also progressing on schedule. Site preparations and foundations are largely complete including the completion of a seawall on the eastern side of the site. Nine of ten spherical liquids storage tanks are in place and the construction of pipe racks for transporting gas through the site is progressing. Construction of control and administrative buildings as well as living areas has commenced.

Development of the single well Liuhua 34-2 field is planned to proceed in parallel with, and be tied into the development of, the Liwan 3-1 field. Front end engineering design (“FEED”) for the development of the Liuhua 29-1 gas field has now been completed, and the ODP is being prepared. Negotiations for the sale of the gas from the Liuhua 34-2 and Liuhua 29-1 fields are ongoing.

On Block 63/05 in the Qiongdongnan Basin, Husky and CNOOC have agreed to the termination of the contract after completion of the first phase of the exploration period. Accordingly, the Company has no further obligation with respect to this block.

Taiwan

In December, Husky signed a joint venture contract with CPC Corporation, Taiwan for an exploration block in the South China Sea. The exploration block is located 100 kilometers southwest of the island of Taiwan and covers approximately 10,000 square kilometers. Husky holds a 75% working interest during exploration, while CPC Corporation has the right to participate in the development program up to a 50% interest. Under the joint venture contract, Husky has an obligation to carry out 2-D seismic surveys within the first two years, with options to carry out 3-D seismic surveys and to drill at least one exploration well in subsequent exploration periods.

Indonesia

The 2012 exploration drilling program on the Madura Strait Block concluded in October with four new discoveries made as a result of a five well exploration drilling program. These discoveries are now under evaluation for commercial development.

The development plan for a combined MDA and MBH development project was approved in 2013 by SKK Migas, the industry regulator. As agreed with the regulator, a re-tender process for the BD field FPSO was conducted and pre-qualification responses are being evaluated. First gas from the Madura Strait Block is anticipated in the 2015 time frame.

Oil Sands

Sunrise Energy Project

Husky and BP continue to advance the development of the Sunrise Energy Project in multiple stages. During 2012, drilling of the planned SAGD horizontal well pairs for Phase 1 was completed and site construction and equipment installations were substantially advanced. Phase 1 of the 60,000 bbls/day (30,000 bbls/day net) project remains on track for first production in 2014.

Substantial cost certainty on the first phase of the Sunrise Energy Project was achieved in 2012 with the conversion to a lump sum contract for the Central Processing Facility (“CPF”). Over 85% of the costs for Phase 1 are now fixed and incorporate all significant contract conversions and facility and efficiency design improvements. To date, approximately 65% of the project’s total cost estimate has been spent.

Management’s Discussion and Analysis 2012

13

The CPF is approaching 50% completion with piling substantially completed and foundation work proceeding at the site. Major equipment continues to be delivered and placed into position with approximately half of the modules fabricated and moved to the site. Construction for the field facilities is now more than 80% complete with significant activity currently underway, including pipelining in the field and fabrication in the module shops.

Development work continues on the next phase of the project with the Design Basis Memorandum expected to be completed in 2013. Regulatory approvals are in place for a total of 200,000 bbls/day (100,000 bbls/day net).

Tucker

Production rates at Husky’s Tucker Oil Sands Project have remained stable at approximately 10,000 bbls/day in 2012. Production from the Grand Rapids pilot well pair commenced in the first quarter of 2012. Based on positive performance from the pilot, Husky initiated drilling of an additional five Grand Rapids well pairs in November 2012 with production expected in 2013.

Saleski

A regulatory application for the bitumen carbonates pilot is anticipated to be filed in 2013.

McMullen

During 2012, seven evaluation wells were drilled and 32 slant wells were drilled, equipped and placed on production in the cold production development project. At the end of 2012, production from McMullen was 4,600 bbls/day and development activity is continuing.

Atlantic Region

White Rose Field and Satellite Extensions

Development continued at the White Rose field with the addition of an infill production well which was brought online in August 2012. As at the end of 2012, a total of 22 wells, including nine producing wells, ten water injectors, and three gas injectors were in operation. Future infill wells are being evaluated.

The Husky-operated SeaRose FPSO completed its planned maintenance dry-docking in Belfast, Northern Ireland with zero lost-time incidents and ahead of schedule with production resuming on August 13, 2012 approximately three weeks ahead of plan. Production from the White Rose field and satellite extensions returned to expected levels by the end of the third quarter of 2012.

A development plan amendment was filed with the regulator in October 2012 to facilitate development of resources at the South White Rose Extension. This region will be developed via subsea tieback to the SeaRose FPSO, similar to the North Amethyst satellite extension. A new drill centre to support the development was excavated during the third quarter of 2012 and drilling of a gas injection well is scheduled to commence in 2013.

At North Amethyst, development continued in 2012 with the addition of the fourth production well. At the end of 2012, four production and three water injection wells were on-line. An additional water injector well is scheduled to be drilled in 2013. An application to develop the deeper Hibernia formation at North Amethyst is progressing through the regulatory review process.

A water injection well to support the existing producing well for the West White Rose pilot project was completed and brought online during 2012. Evaluation of a wellhead platform to facilitate future development continued during 2012 and supporting regulatory filings were submitted for an environmental assessment of the concept. A decision on a preferred development option is expected in 2013.

Drilling of the Searcher prospect in the southern Jeanne D’Arc Basin did not encounter commercial hydrocarbons and the well was expensed in 2012.

Husky and Seadrill entered into a five-year contract for the use of Seadrill’s West Mira rig, a new harsh environment semi-submersible rig currently being built and expected to be completed in 2015.

Management’s Discussion and Analysis 2012

14

Atlantic Exploration

The Company was awarded exploration rights to a 208,899 hectare parcel of land offshore Newfoundland during the November 2012 licencing round. The licence is located in the Flemish Pass and is east of and adjacent to existing land holdings in the Jeanne d’Arc Basin. Husky has a 40% working interest and future exploration is currently being evaluated.

The Company plans to participate in a number of operated and non-operated exploratory wells in the Atlantic Region during the 2013/2014 timeframe. The first well in this program is a partner-operated exploration well southeast of the Mizzen discovery located in the Flemish Pass.

Offshore Greenland

A two-year extension was received on the initial phase of the exploration program for two Husky-operated exploration licenses offshore Greenland. Geological and geophysical evaluations continued in 2012 and socio-economic study work is continuing.

Infrastructure and Marketing

Through the Company’s continued development of both proprietary infrastructure and contracted pipeline commitments, it is able to access higher priced crude oil markets, partially offset Western Canadian differentials, and provide crude feedstock flexibility for the Lima Refinery, enabling the optimization of the crude slate in terms of quality, location and price.

A new 300,000 barrel tank at the Hardisty terminal was placed in service May 2012. The tank facilitates moving crude oil volumes to U.S. Petroleum Administration for Defense Districts (“PADD”) II and III markets.

5.2 Downstream

Lima Refinery

The Lima Refinery continues to progress reliability and profitability improvement projects. Construction of the 20 mbbls/day kerosene hydrotreater, which will increase on-road diesel and jet fuel production volumes, is approximately 80% complete and is expected to be operational in the first quarter of 2013.

BP-Husky Toledo Refinery

The Continuous Catalyst Regeneration Reformer Project at the BP-Husky Toledo Refinery is progressing as planned. Mechanical completion was achieved in the fourth quarter of 2012 and start up is expected in the first quarter of 2013. The refinery continues to advance a multi-year program to improve operational integrity and plant performance while reducing operating costs and environmental impacts.

Management’s Discussion and Analysis 2012

15

6.0 Results of Operations

6.1 Segment Earnings

	Earnings (Loss) before Income Taxes						Net Earnings (Loss)						Capital Expenditures(1)
($ millions)	2012			2011			2012			2011			2012		2011
Upstream(2)
Exploration and Production		1,324			2,137			979			1,581			4,106		4,131
Infrastructure and Marketing		457			174			341			130			54		43
Downstream(2)
Upgrading		306			202			226			150			47		55
Canadian Refined Products		311			295			231			220			97		94
U.S. Refining and Marketing		695			697			438			443			313		224
Corporate		(257	)		(365	)		(193	)		(300	)		84		71
Total		2,836			3,140			2,022			2,224			4,701		4,618

⁽¹⁾  Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the period.

⁽²⁾  During the first quarter of 2012, the Company completed an evaluation of the activities of the former Midstream segment as a service provider to the Upstream and Downstream operations. As a result, the segmented financial information for activities within the previously reported Midstream segment are presented under Upstream or Downstream segments to align with how the Company’s results are assessed by management. Prior period disclosures have been restated to conform with current year presentation.

6.2 Summary of Quarterly Results

Management’s Discussion and Analysis 2012

16

⁽¹⁾  Cash flow from operations is a non-GAAP measure. (Refer to Section 11.3)

6.3 Upstream

2012 Total Upstream Earnings $1,320 million

Exploration and Production Earnings Summary ($ millions)	2012			2011
Gross revenues		6,547			7,519
Royalties		(693	)		(1,125	)
Net revenues		5,854			6,394
Purchases, operating, transportation and administration expenses		2,091			1,966
Depletion, depreciation, amortization and impairment		2,121			2,018
Exploration and evaluation expense		350			470
Other expenses (income)		(32	)		(197	)
Income taxes		345			556
Net earnings		979			1,581

Exploration and Production net earnings were $602 million lower in 2012 compared with 2011 primarily due to lower realized crude oil and natural gas prices and lower production in the Atlantic Region as a result of the planned maintenance of the SeaRose and Terra Nova FPSOs, partially offset by increased production in Western Canada from the new heavy oil thermal development projects at Paradise Hill and Pikes Peak South and lower exploration and evaluation expense. In addition, Husky realized after-tax gains on the sale of non-core assets and an asset swap of $198 million in 2011.

Management’s Discussion and Analysis 2012

17

Average Sales Prices Realized	2012		2011
Crude oil ($/bbl)
Light crude oil & NGL		99.22		104.06
Medium crude oil		71.51		76.59
Heavy crude oil		61.91		68.13
Bitumen		59.49		65.75
Total average		75.50		83.73
Natural gas average ($/mcf)		2.60		3.89
Total average ($/boe)		57.16		64.17

During 2012, the average realized price decreased 10% to $75.50/bbl for crude oil, NGL and bitumen compared with $83.73/bbl during 2011 primarily due to lower Brent-based production from the Atlantic Region and wider Western Canada crude oil price differentials to WTI. Realized natural gas prices averaged $2.60/mcf during 2012 compared with $3.89/mcf in 2011, a decline of 33%.

Management’s Discussion and Analysis 2012

18

Daily Gross Production	2012			2011
Crude oil (mbbls/day)
Western Canada
Light crude oil & NGL		30.1			24.8
Medium crude oil		24.1			24.5
Heavy crude oil		76.9			74.5
Bitumen		35.9			24.7
		167.0			148.5
Atlantic Region
White Rose and Satellite Fields – light crude oil		30.8			48.7
Terra Nova – light crude oil		3.0			5.6
		33.8			54.3
China
Wenchang – light crude oil & NGL		8.4			8.5
Crude oil (mbbls/day)		209.2			211.3
Natural gas (mmcf/day)		554.0			607.0
Total (mboe/day)		301.5			312.5
Upstream Revenue Mix (Percentage of Upstream Net Revenues)	2012			2011
Crude oil
Light crude oil & NGL		43	%		44	%
Medium crude oil		10	%		9	%
Heavy crude oil		28	%		26	%
Bitumen		12	%		8	%
Crude oil		93	%		87	%
Natural gas		7	%		13	%
Total		100	%		100	%

During 2012, crude oil, bitumen and NGL production decreased by 2.1 boe/day or 1% compared with 2011, primarily due to lower production in the Atlantic Region as a result of the planned maintenance of the SeaRose and Terra Nova FPSOs, largely offset by increased production in Western Canada from the new heavy oil thermal development projects at Paradise Hill and Pikes Peak South.

Production from natural gas decreased by 53.0 mmcf/day or 9% in 2012 compared with 2011 due to natural reservoir declines in mature properties as capital investment is being directed to higher return oil and liquids-rich developments.

Management’s Discussion and Analysis 2012

19

2013 Production Guidance and 2012 Actual

Gross Production	Guidance 2013		Year ended December 31, 2012		Guidance 2012
Crude oil & NGL (mbbls/day)
Light crude oil & NGL		85 – 90		72		70 – 75
Medium crude oil		25 – 30		24		25 – 30
Heavy crude oil & bitumen		110 – 120		113		100 – 110
Crude oil & NGL (mbbls/day)		220 – 240		209		195 – 215
Natural gas (mmcf/day)		540 – 580		554		560 – 610
Total (mboe/day)		310 – 330		302		290 – 315

The Company’s total production for the year ended December 31, 2012 was within production guidance set by the Company in 2011. Husky expects that production levels in 2013 will be higher compared to 2012 due to a full year of production from the Atlantic Region where the Company and its partners executed two major maintenance turnarounds of the SeaRose and Terra Nova FPSOs. In 2010, the Company set a compound annual production growth target of 3% to 5% through the plan period 2010-2015 and is on track to achieve that goal. In 2012, a new target was set for the plan period of 2012 to 2017 at an increased compound annual production growth rate of 5% to 8%.

Factors that could potentially impact Husky’s production performance for 2013 include, but are not limited to:

• performance on 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;

• significant declines in crude oil and natural gas commodity prices which may result in the decision to temporarily shut-in production; and

• foreign operations and related assets which are subject to a number of political, economic and socio-economic risks.

Royalties

Royalty rates averaged 11% of gross revenues in 2012 compared with 16% in 2011. Royalty rates in Western Canada averaged 10% in 2012 compared with 14% in 2011 due to lower natural gas prices and royalty credit adjustments. In the Atlantic Region, the average rate was 11% in 2012 compared with 17% in 2011 due to higher eligible costs associated with the SeaRose FPSO offstation and lower Terra Nova production which is subject to higher royalty rates. Royalty rates in the Asia Pacific Region averaged 24% in 2012 compared with 30% in 2011 mainly due to reductions in windfall profit taxes that became effective in November of 2011.

Operating Costs

($ millions)	2012		2011
Western Canada		1,571		1,485
Atlantic Region		212		174
Asia Pacific		31		25
Total		1,814		1,684
Unit operating costs ($/boe)		15.49		14.01

Total operating costs increased to $1,814 million in 2012 from $1,684 million in 2011. Total Upstream unit operating costs in 2012 averaged $15.49/boe compared with $14.01/boe in 2011.

Operating costs in Western Canada increased to $15.45/boe in 2012 compared with $15.35/boe in 2011 primarily due to higher fuel and labour costs offset by higher heavy oil production, lower treating costs and decreased maintenance costs.

Management’s Discussion and Analysis 2012

20

Operating costs in the Atlantic Region averaged $17.12/boe in 2012 compared with $8.75/boe in 2011. The increase was mainly due to higher maintenance costs and lower production as a result of the planned maintenance of the SeaRose and Terra Nova FPSOs.

Operating costs in the Asia Pacific Region averaged $10.08/boe in 2012 compared with $8.08/boe in 2011 due to higher maintenance, fuel, workover and helicopter costs.

Exploration and Evaluation Expenses

($ millions)	2012		2011
Seismic, geological and geophysical		146		170
Expensed drilling		188		245
Expensed land		16		55
Total		350		470

Total exploration and evaluation expenses decreased in 2012 to $350 million from $470 million in 2011. The decrease in seismic, geological and geophysical expense was primarily due to a shift in focus in 2012 to more development activities in Western Canada compared with 2011. Expensed drilling in 2012 primarily consisted of drilling in the Northwest Territories to gain a general understanding of geological formations, and costs related to the Searcher well in the Atlantic Region and the MAQ-1 well in the Madura Strait of Indonesia, neither of which encountered economic quantities of hydrocarbons. Expensed drilling and land costs in 2011 included acquisition and drilling costs expensed for properties in the Columbia River Basin located in the states of Washington and Oregon.

Depletion, Depreciation, Amortization (“DD&A”) and Impairment

During 2012, total unit DD&A was $19.20/boe compared with $17.69/boe during 2011. The higher DD&A rate in 2012 was primarily due to a shift in focus by the Company to higher capital investments in oil and liquids-rich natural gas properties with higher netbacks than natural gas developments.

At December 31, 2012, capital costs in respect of unproved properties and major development projects were $6.1 billion compared with $5.3 billion at the end of 2011. These costs are excluded from the Company’s DD&A calculation until the unproved properties are evaluated and developed, proved reserves are attributed to the project or the project is deemed to be impaired.

⁽¹⁾  Operating netback is a non-GAAP measure and constitues Husky’s average price less royalties and operating costs on a per unit basis. Refer to Section 11.3.

Management’s Discussion and Analysis 2012

21

Upstream Capital Expenditures

In 2012, Upstream Exploration and Production capital expenditures were $4,106 million. Capital expenditures were $2,288 million (56%) in Western Canada, $658 million (16%) in Oil Sands, $413 million (10%) in the Atlantic Region and $747 million (18%) in the Asia Pacific Region. Husky’s major projects remain on budget and on schedule.

Upstream Capital Expenditures(1) ($ millions)	2012		2011
Exploration
Western Canada		238		233
Atlantic Region		13		2
Asia Pacific		22		168
		273		403
Development
Western Canada		2,029		1,787
Oil Sands		658		263
Atlantic Region		400		258
Asia Pacific		725		546
		3,812		2,854
Acquisitions
Western Canada		21		874
		4,106		4,131

⁽¹⁾  Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the period.

Management’s Discussion and Analysis 2012

22

Western Canada, Heavy Oil & Oil Sands

The following table discloses the number of gross and net exploration and development wells Husky completed in Western Canada, Heavy Oil and Oil Sands during the periods indicated:

	2012				2011
Wells Drilled (wells)	Gross		Net		Gross		Net
Exploration
Oil		47		30		50		40
Gas		19		12		24		24
Dry		—		—		3		3
		66		42		77		67
Development
Oil		775		715		880		765
Gas		23		17		57		42
Dry		5		4		4		4
		803		736		941		811
Total		869		778		1,018		878

The Company drilled 778 net wells in the Western Canada, Heavy Oil and Oil Sands business units in 2012 resulting in 745 net oil wells and 29 net natural gas wells compared with 878 net wells resulting in 805 net oil wells and 66 net natural gas wells in 2011.

Capital expenditures for wells drilled in Western Canada increased substantially in 2012 compared with 2011 due to the increased focus on resource play development drilling in areas such as the liquids-rich gas resource play in Ansell, a larger number of horizontal wells drilled and more multi-stage fracture completions performed.

During 2012, Husky invested $2,288 million on exploration, development and acquisitions, including heavy oil, throughout the Western Canada Sedimentary Basin compared with $2,894 million in 2011. Property acquisitions totalling $21 million were completed in 2012 compared with $874 million in 2011. Investment in oil related exploration and development was $538 million and $500 million was invested in natural gas resource plays during 2012 compared with $591 million for oil and $359 million in natural gas in 2011.

In addition, $245 million was spent on production optimization and cost reduction initiatives in 2012. Capital expenditures on facilities, land acquisition and retention and environmental protection totalled $398 million.

Capital expenditures on heavy oil thermal projects, CHOPS drilling and horizontal drilling, were $586 million during 2012 compared to $587 million in 2011.

Oil Sands

During 2012, capital expenditures on Oil Sands projects increased to $658 million compared to $263 million in the same period in 2011 as Sunrise Phase 1 progressed and activity at the central processing facility and field facilities accelerated. In addition, the Company drilled 29 gross (15 net) evaluation wells for Phase 2 at the Sunrise Energy Project during 2012.

Atlantic Region

The following table discloses Husky’s offshore Atlantic Region drilling activity during 2012:

Atlantic Region Offshore Drilling Activity

White Rose E-18-11	WI 68.875%	Development	Service/injector
North Amethyst G-25 7	WI 68.875%	Development	Production
White Rose B-07 11	WI 72.5%	Development	Production
Searcher C-87	WI 100%	Exploration	Stratigraphic

During 2012, $413 million was invested in Atlantic Region projects primarily on the continued development of the White Rose Extension Project including the West White Rose and North Amethyst satellite fields. A drill center was excavated at the South White Rose Extension and a temporary guide base was installed in 2012. In addition, one infill oil well was drilled in the White Rose field during 2012.

Management’s Discussion and Analysis 2012

23

Asia Pacific Region

The following table discloses Husky’s offshore China and Indonesia drilling activity completed during 2012:

Asia Pacific Region Offshore Drilling Activity

MBJ-1, Madura Strait Block	WI 40%	Exploration	Stratigraphic test
MDK-1, Madura Strait Block	WI 40%	Exploration	Stratigraphic test
MAC-1, Madura Strait Block	WI 40%	Exploration	Stratigraphic test
MAX-1, Madura Strait Block	WI 40%	Exploration	Stratigraphic test
MAQ-1, Madura Strait Block	WI 40%	Exploration	Stratigraphic test

Total capital expenditures of $747 million were invested in the Asia Pacific Region in 2012 primarily for development of the Liwan Gas Project. Five exploration wells were drilled at the Madura Strait in Indonesia during 2012, resulting in four discoveries under evaluation for commercial development.

2013 Upstream Capital Program

($ millions)
Western Canada	2,100
Oil sands	500
Atlantic Region	600
Asia Pacific Region	800
Total Upstream capital expenditures(1)	4,000

⁽¹⁾  Capital program excludes capitalized administration costs, capitalized interest and asset retirement obligations incurred.

The 2013 Capital Program will enable Husky to build on the momentum achieved over the past two years and will support the acceleration of near-term production and the continued execution of the Company’s mid and long-term growth initiatives.

The Company has budgeted $800 million for the Asia Pacific Region in 2013, mainly for the Liwan Gas Project to complete the construction of the shallow water pipeline installations, the onshore gas plant and the topsides portion of the platform with planned first production in late 2013/early 2014. Oil Sands capital for 2013 will primarily be for the continued development of Phase 1 of the Sunrise Energy Project as well as planning, design and engineering for the next phase of the project. Investment in the Atlantic Region of $600 million is for continued development of the White Rose fields and extensions and evaluation of the feasibility of a concrete wellhead and drilling platform for the development of future resources, including the full development of West White Rose.

In addition to advancing mid and long-term growth pillars, the 2013 Capital Program provides support to the Company’s efforts to continue to reinvigorate and transform its foundation in Western Canada. A substantial oil and liquids-rich natural gas resource play portfolio has been acquired and further drilling is scheduled to take place across the portfolio in 2013. The Company is making progress in its strategy to transition a greater percentage of its heavy oil production to long-life thermal. The Company will continue its development of the 3,500 bbls/day Sandall thermal project with expected first production in 2014 and the 10,000 bbls/day Rush Lake thermal project with expected first production in 2015.

Upstream Turnarounds

The Husky-operated SeaRose FPSO completed its planned maintenance dry-docking in Belfast, Northern Ireland with zero lost-time incidents and ahead of schedule with production resuming on August 13, 2012, approximately three weeks ahead of plan. Production from the White Rose field and satellite extensions returned to expected levels by the end of the third quarter of 2012.

Management’s Discussion and Analysis 2012

24

The non-operated Terra Nova FPSO resumed production in December following a planned 26-week turnaround shutdown and continues to ramp up more slowly than anticipated.

In third quarter of 2013, a one week turnaround is scheduled for the SeaRose FPSO. The Terra Nova FPSO turnaround plans for 2013 are being evaluated.

Oil and Gas Reserves

The following oil and gas reserves disclosure has been 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, 2012. Husky received approval from the Canadian Securities Administrators to also disclose its reserves using U.S. disclosure requirements as supplementary disclosure to the reserves and oil and gas activities disclosure required by NI 51-101. The reserves information prepared in accordance with the U.S. disclosure requirements 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 Company’s complete Oil and Gas Reserves Disclosure prepared in accordance with NI 51-101 is contained in Husky’s Annual Information Form, which is available at www.sedar.com, or Husky’s Form 40-F, which is available at www.sec.gov or on the Company’s website at www.huskyenergy.com.

McDaniel & Associates Consultants Ltd., an independent firm of oil and gas reserves evaluation engineers, was engaged to conduct an audit of Husky’s crude oil, natural gas and natural gas products reserves. McDaniel & Associates Consultants Ltd. issued an audit opinion stating that Husky’s internally generated proved and probable reserves and net present values 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, 2012, Husky’s proved oil and gas reserves were 1,192 mmboe, up from 1,172 mmboe at the end of 2011. Addition to proved reserves, including acquisitions and divestitures, represents 140% (118% after economic revisions) of 2012 production. Major additions to proved reserves in 2012 included:

• the initial booking of reserves in the Liwan 3-1 deepwater project that resulted in the addition of 51 mmboe of natural gas and natural gas liquids in proved undeveloped reserves;

• the improved recovery and expansion of heavy oil thermal projects that resulted in the booking of an additional 13 mmboe in proved reserves; and

• the extension through additional drilling locations at the liquids-rich Ansell project that resulted in the booking of an additional 27 mmboe of natural gas and natural gas liquids in proved reserves.

Management’s Discussion and Analysis 2012

25

Note: Reserves reported represent proved plus probable reserves.

Reconciliation of Proved Reserves
(forecast prices and costs before royalties)	Canada																		International					Total
	Western Canada															Atlantic Region
	Light Crude Oil & NG (mmbbls)			Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Bitumen (mmbbls)			Natural Gas (bcf)			Light Crude Oil (mmbbls)			Light Crude Oil & NGL (mmbbls)			Natural Gas (bcf)		Crude Oil & NGL (mmbbls)			Natural Gas (bcf)			Equivalent Units (mmboe)
Proved reserves
December 31, 2011		169			90			113			309			2,253			76			12			167		769			2,420			1,172
Revision of previous estimate		—			8			2			1			14			4			5			—		20			14			22
Purchase of reserves in place		1			—			—			—			—			—			—			—		1			—			1
Sale of reserves in place		—			(1	)		—			—			—			—			—			—		(1	)		—			(1	)
Discoveries, extensions and improved recovery		16			7			18			14			146			—			8			267		63			413			132
Economic revision		(1	)		—			—			—			(137	)		—			—			—		(1	)		(137	)		(24	)
Production		(12	)		(9	)		(28	)		(13	)		(203	)		(12	)		(3	)		—		(77	)		(203	)		(110	)
Proved reserves December 31, 2012		173			95			105			311			2,073			68			22			434		774			2,507			1,192
Proved and probable reserves December 31, 2012		229			117			140			1,725			2,547			130			30			718		2,371			3,265			2,915
December 31, 2011		220			109			151			1,709			2,813			141			17			207		2,347			3,020			2,851

Management’s Discussion and Analysis 2012

26

Reconciliation of Proved Developed Reserves
	Canada																		International					Total
	Western Canada															Atlantic Region
(forecast prices and costs before royalties)	Light Crude Oil & NGL (mmbbls)			Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Bitumen (mmbbls)			Natural Gas (bcf)			Light Crude Oil (mmbbls)			Light Crude Oil & NGL (mmbbls)			Natural Gas (bcf)		Crude Oil & NGL (mmbbls)			Natural Gas (bcf)			Equivalent Units (mmboe)
Proved developed reserves
December 31, 2011		148			77			86			56			1,916			65			5			—		437			1,916			757
Revision of previous estimate		6			18			16			14			85			3			5			—		62			85			74
Purchase of reserves in place		1			—			—			—			—			—			—			—		1			—			1
Sale of reserves in place		—			(1	)		—			—			—			—			—			—		(1	)		—			(1	)
Discoveries, extensions and improved recovery		7			3			10			2			13			—			1			—		23			13			25
Economic revision		(1	)		—			—			—			(97	)		—			—			—		(1	)		(97	)		(17	)
Production		(12	)		(9	)		(28	)		(13	)		(203	)		(12	)		(3	)		—		(77	)		(203	)		(110	)
Proved developed reserves December 31, 2012		149			88			84			59			1,714			56			8			—		444			1,714			729

Infrastructure and Marketing

Infrastructure and Marketing Earnings Summary ($ millions, except where indicated)	2012		2011
Infrastructure gross margin		162		169
Marketing and other gross margin		387		90
Gross margin		549		259
Operating and administrative expenses		70		60
Depletion, depreciation and amortization		22		24
Other expenses		—		1
Income taxes		116		44
Net earnings		341		130
Commodity trading volumes managed (mboe/day)		180.1		181.0

Infrastructure and Marketing net earnings increased by $211 million compared with the same period in 2011 as a result of marketing activities utilizing the Company’s access to infrastructure to move crude oil from Canada to the United States to mitigate the impact of wider Western Canadian crude oil differentials on the Exploration and Production business by capturing widening Canadian crude discounts through integration.

Infrastructure and Marketing capital expenditures totalled $54 million in 2012 compared to $43 million in 2011. The majority of Infrastructure and Marketing capital expenditures during the year related to the completion of the 300,000 barrel tank at the Hardisty terminal and pipeline maintenance and integrity projects.

Management’s Discussion and Analysis 2012

27

6.4 Downstream

2012 Total Downstream Earnings $895 million

Upgrader

Upgrader Earnings Summary ($ millions, except where indicated)	2012			2011
Gross revenues		2,191			2,217
Gross margin (1)		555			589
Operating and administration expenses(1)		153			149
Depreciation and amortization		102			164
Other expenses (income)		(6	)		74
Income taxes		80			52
Net earnings		226			150
Upgrader throughput(2)(mbbls/day)		77.4			69.6
Synthetic crude oil sales (mbbls/day)		60.4			55.3
Upgrading differential ($/bbl)		22.34			27.34
Unit margin(1)($/bbl)		25.17			29.18
Unit operating cost(3)($/bbl)		5.42			5.87

⁽¹⁾ The Company reclassified certain hydrogen feedstock costs from operating and administrative expenses to cost of sales in the third quarter of 2012. Prior periods have been reclassified to conform with current period presentation.

⁽²⁾ Throughput includes diluent returned to the field.

⁽³⁾  Based on throughput.

The Upgrading operations add value by processing heavy sour crude oil into high value synthetic crude oil and low sulphur distillates. The Upgrader profitability is primarily dependent on the differential between the cost of heavy crude oil feedstock and the sales price of synthetic crude oil.

Upgrading earnings in 2012 were impacted by lower upgrading differentials resulting from lower synthetic crude oil prices offsetting lower heavy oil feedstock costs. Lower margins were offset by a decrease in the fair value of the remaining upside interest payment obligations included in other income and a decrease in depreciation and amortization as intangible costs were derecognized in the second quarter of 2011.

During 2012, the price of Husky’s synthetic crude oil averaged $91.90/bbl compared with the average cost of blended heavy crude oil from the Lloydminster area of $69.56/bbl. During 2011, the price of Husky’s synthetic crude oil averaged $101.68/bbl compared with an average cost of blended heavy crude oil from the Lloydminster area of $74.34/bbl. This resulted in an average synthetic/heavy crude differential of $22.34/bbl in 2012 compared to $27.34/bbl in 2011 and a gross unit margin of $25.17/bbl in 2012 compared to $29.18/bbl in 2011. The cost of upgrading averaged $5.42/bbl in 2012 compared to $5.87/bbl in 2011, which resulted in a net margin for upgrading heavy crude of $19.75/bbl, down 15% compared with $23.31/bbl in 2011. The decrease in Upgrading differentials, unit margins and net margins in 2012 compared to 2011 was primarily due to Western Canadian synthetic crude oil prices which traded at a discount to WTI in 2012 compared to a premium to WTI in 2011. This new trend is mainly due to export pipeline constraints in Western Canada and new supply in the U.S. which has resulted in a decrease in demand for Western Canadian crude oil.

Management’s Discussion and Analysis 2012

28

Canadian Refined Products

Canadian Refined Products Earnings Summary ($ millions, except where indicated)	2012		2011
Gross revenues		3,848		3,877
Gross margin (1)
Fuel		153		153
Refining		180		171
Asphalt		257		239
Ancillary		50		49
		640		612
Operating and administration expenses		242		231
Depreciation and amortization		83		80
Other expense		4		6
Income taxes		80		75
Net earnings		231		220
Number of fuel outlets (2)		531		547
Refined products sales volume
Light oil products (million of litres/day) (3)		9.5		9.5
Light oil products per outlet (thousand of litres/day) (3)		17.8		17.3
Asphalt products (mbbls/day)		26.2		25.3
Refinery throughput
Prince George refinery (mbbls/day)		11.1		10.6
Lloydminster refinery (mbbls/day)		28.3		28.1
Ethanol production (thousand of litres/day)		721.2		711.3

⁽¹⁾  Gross margin and operating and administrative expenses have been recast for reclassification of certain purchases and operating expenses. Prior periods have been recast to reflect this classification.

⁽²⁾  Average number of fuel outlets for period indicated.

⁽³⁾  Light oil products have been redefined to include ethanol sales. Prior periods have been recast to reflect this change in definition.

Refining gross margins increased in 2012 primarily due to higher refining market crack spreads and higher throughput and ethanol production compared to 2011. Included in ethanol gross margins in 2012 was $37 million related to government assistance grants compared with $46 million in 2011.

Asphalt gross margins increased compared to the same period in 2011 primarily due to higher realized market prices and increased sales volumes for residuals as a result of strong demand for drilling fluids.

Higher operating and administration expenses were primarily due to increased maintenance activity in 2012 compared to 2011.

Management’s Discussion and Analysis 2012

29

U.S. Refining and Marketing

U.S. Refining and Marketing Earnings Summary ($ millions, except where indicated)	2012		2011
Gross revenues		10,038		9,752
Gross refining margin		1,314		1,299
Operating and administration expenses		398		403
Depreciation and amortization		212		195
Other expenses		9		4
Income taxes		257		254
Net earnings		438		443
Selected operating data:
Lima Refinery throughput (mbbls/day)		150.0		144.3
BP-Husky Toledo Refinery throughput (mbbls/day)		60.6		63.9
Refining margin (U.S. $/bbl crude throughput)		17.51		17.60
Refinery inventory (feedstocks and refined products) (mmbbls)		11.3		11.8

U.S. Refining and Marketing net earnings in 2012 were comparable to 2011. Stronger throughput at Lima and higher market crack spreads in 2012 compared to 2011 were offset by the impacts of FIFO accounting on realized margins, lower throughput at the BP-Husky Toledo Refinery due to turnaround activity and higher depreciation and amortization.

The Chicago crack spread market benchmark is based on last in first out (“LIFO”) accounting, which assumes that crude oil feedstock costs are based on the current month price of WTI, while crude oil feedstock costs included in realized margins are based on FIFO accounting which reflects purchases made earlier in the previous year when crude oil prices were higher. The estimated FIFO impact was a reduction in net earnings of approximately $28 million in 2012 compared to an increase in net earnings of $122 million in 2011.

In addition, the product slates produced at the Lima and Toledo refineries contain approximately 10% to 15% of other products that are sold at discounted market prices compared with gasoline and distillate, which are the standard products included in the Chicago 3:2:1 market crack spread benchmark.

Downstream Capital Expenditures

Downstream capital expenditures totalled $457 million for 2012 compared to $373 million in 2011. In Canada, capital expenditures were $144 million related to upgrades at the Prince George Refinery, the Upgrader and at retail stations. In the United States, capital expenditures totalled $313 million. At the Lima Refinery, $150 million was spent on various debottleneck projects, optimizations and environmental initiatives. At the BP-Husky Toledo Refinery, capital expenditures totalled $163 million (Husky’s 50% share) primarily for engineering work and procurement on the Continuous Catalyst Regeneration Reformer Project, facility upgrades and environmental protection initiatives.

Management’s Discussion and Analysis 2012

30

Downstream Planned Turnarounds

The Lloydminster Refinery has a turnaround scheduled in the spring of 2013. The refinery is expected to be shut down for 30 days for inspections and equipment repair.

The Lima Refinery is scheduled to complete a turnaround in 2014 on 70% of the operating units. The refinery is expected to be shut down for 45 days. The remaining 30% of the operating units are scheduled to be addressed in a turnaround currently planned for 2015.

The Upgrader has a turnaround scheduled in the fall of 2013 and is expected to be shut down for 45 days.

6.5 Corporate

2012 Loss $193 million

Corporate Summary ($ millions) income (expense)	2012			2011
Administration expenses		(128	)		(195	)
Stock-based compensation		(54	)		1
Depreciation and amortization		(40	)		(38	)
Other income		3			—
Foreign exchange gains		14			10
Interest - net		(52	)		(143	)
Income taxes		64			65
Net loss		(193	)		(300	)

The Corporate segment reported a loss in 2012 of $193 million compared with a loss of $300 million in 2011. Administration expenses were lower in 2012 compared to 2011 in which the Company incurred costs related to financing projects and other initiatives. Stock-based compensation expense increased by $55 million in 2012 due to a higher share price at the end of 2012 compared to 2011. Interest - net decreased by $91 million in 2012 compared to 2011 due to increases in amounts of capitalized interest related to projects in the Asia Pacific Region and the Sunrise Energy Project.

Foreign Exchange Summary ($ millions, except exchange rate amounts)	2012			2011
Gains (losses) on translation of U.S. dollar denominated long-term debt		43			(47	)
Gains (losses) on cross currency swaps		2			7
Gains (losses) on contribution receivable		(7	)		34
Other foreign exchange gains (losses)		(24	)		16
Foreign exchange gains (losses)		14			10
U.S./Canadian dollar exchange rates:
At beginning of year	U.S. $	0.983		U.S. $	1.005
At end of year	U.S. $	1.005		U.S. $	0.983

Consolidated Income Taxes

Consolidated income taxes decreased in 2012 to $814 million from $916 million in 2011 resulting in an effective tax rate of 29% for both 2012 and 2011.

($ millions)	2012			2011
Income taxes as reported		814			916
Cash taxes paid		(575	)		(282	)

Taxable income from Canadian operations is primarily generated through partnerships. This structure previously allowed a deferral of taxable income and related taxes to a future period. Starting in 2012, the Canadian government has removed this deferral, and any income taxes related to previously deferred taxable income will now be payable over a 5-year period commencing in 2013.

Management’s Discussion and Analysis 2012

31

Corporate Capital Expenditures

Corporate capital expenditures of $84 million in 2012 were primarily related to computer hardware and software and system upgrades.

7.0 Risk and Risk Management

7.1 Enterprise Risk Management

Husky’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. 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 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 Husky and its operations.

7.2 Significant Risk Factors

Operational, Environmental and Safety Incidents

Husky’s businesses are subject to inherent operational risks and hazards in respect of safety and the environment that require continuous vigilance. The Company seeks to minimize these operational risks and hazards by carefully designing and building its facilities and conducting its operations in a safe and reliable manner. However, failure to manage these operational risks and hazards effectively could result in unexpected incidents, including the release of restricted substances, fires, explosions, well blow-outs, marine catastrophe or mechanical failures and pipeline failures. The consequences of such events include personal injuries, loss of life, environmental damage, property damage, loss of revenues, fines, penalties, legal liabilities, disruption to operations, asset repair costs, remediation and reclamation costs, monitoring post-cleanup and/or reputational impacts which may affect the Company’s license to operate. Remediation may be complicated by a number of factors including shortages of specialized equipment or personnel, extreme operating environments and the absence of appropriate or proven countermeasures to effectively remedy such consequences. Emergency preparedness, business continuity and security policies and programs are in place for all operating areas, and are routinely exercised. The Company, in accordance with industry practice, maintains insurance coverage against losses from certain of these risks and hazards. Nonetheless, insurance proceeds may not be sufficient to cover all losses and insurance coverage may not be available for all types of operational risks and hazards.

Commodity Price Volatility

Husky’s results of operations and financial condition are dependent on the prices received for its crude oil and natural gas production. Lower prices for crude oil and natural gas could adversely affect the value and quantity of Husky’s oil and gas reserves. Husky’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 is limited and planned increases of North American heavy crude oil production may create the need for additional heavy oil refining and transportation capacity. As a result, wider price differentials could have adverse effects on Husky’s financial performance and condition, reduce the value and quantities of Husky’s heavier crude oil reserves and delay or cancel projects that involve the development of heavier crude oil resources. There is no guarantee that planned pipeline development projects will provide sufficient transportation capacity and access to refining capacity to accommodate expected increases in North American heavy crude oil production.

Management’s Discussion and Analysis 2012

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Prices for 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, prevailing weather patterns and the availability of alternate sources of energy.

Husky’s natural gas production is currently located entirely in Western Canada and is, therefore, 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 well head or from storage facilities, prevailing weather patterns, the price of crude oil, the U.S. and Canadian economies, the occurrence of natural disasters and pipeline restrictions.

In certain instances, the Company uses derivative commodity instruments to manage exposure to price volatility on a portion of its oil and gas production and firm commitments for the purchase or sale of crude oil and natural gas.

The fluctuations in crude oil and natural gas prices are beyond Husky’s control and accordingly, could have a material adverse effect on the Company’s business, financial condition and cash flow. For information on 2012 commodity price sensitivities, refer to Section 3.0 within this Management’s Discussion and Analysis.

Reservoir Performance Risk

Lower than projected reservoir performance on the Company’s key growth projects could have a material impact on the Company’s financial position, medium to long-term business strategy and cash flow. 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 natural gas liquids 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. In order 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 developable projects depends on, among other things, obtaining and renewing rights to explore, develop and produce oil and natural gas, drilling success, completing long-lead time capital intensive projects on budget and on schedule and the application of successful exploitation techniques on mature properties.

Restricted Market Access

Husky’s results depend upon the Company’s ability to deliver products to the most attractive markets. The Company’s results could be impacted 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. With growing conventional and oil sands production across North America and 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 impact on the Company’s financial position, medium to long-term business strategy, cash flow and corporate reputation.

Security and Terrorist Threats

A security threat or terrorist attack on a facility owned or operated by the Company could result in the interruption or cessation of key elements of its operations, which could have a material impact on the Company’s financial position, business strategy and cash flow.

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International Operations

International operations can expose the Company to uncertain political, economic and other risks. The Company’s operations in certain jurisdictions may be 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 PSCs, imposition of onerous regulation, changes in laws governing existing operations, financial constraints, including currency and exchange rate fluctuations, and unreasonable taxation. This could adversely affect the Company’s interest in its foreign operations and future profitability.

Gas Offtake

The potential inability to deliver an effective gas storage solution as inventories grow over the life of the White Rose field may potentially result in prolonged shutdown of these operations, which may have a material impact on the Company’s financial position, business strategy and cash flow.

Skills and Human Resource Shortage

The Company recognizes that a robust, productive, and healthy workforce drives efficiency, effectiveness, and financial performance. Attracting and retaining qualified and skilled labour is critical to the successful execution of Husky’s current and future business strategies. However, a tight labour market, an insufficient number of qualified candidates, and an aging workforce are factors that precipitate a human resource risk for the Company. Failure to retain current employees and attract new skilled employees could materially affect the Company’s ability to conduct its business.

Major Project Execution

The Company manages a variety of major projects relating to oil and gas exploration, development and production. Risks associated with the execution of Husky’s major projects, as well as the commissioning and integration of new assets into its existing infrastructure, may result in cost overruns, project or production delays, and missed financial targets, thereby eroding project economics. Typical project execution risks include: the availability and cost of capital, inability to find mutually agreeable parameters with key project partners for large growth projects, availability of manufacturing and processing capacity, faulty construction and design errors, labour disruptions, bankruptcies, productivity issues affecting Husky directly or indirectly, unexpected changes in the scope of a project, health and safety incidents, need for government approvals or permits, unexpected cost increases, availability of qualified and skilled labour, availability of critical equipment, severe weather, and availability and proximity of pipeline capacity.

Partner Misalignment

Joint venture partners operate a portion of Husky’s assets in which the Company has an ownership interest. Husky 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 Husky project may be delayed and the Company may be partially or totally liable for its partner’s share of the project.

Reserves Data, Future Net Revenue and Resource Estimates

The reserves data in this Management’s Discussion and Analysis 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 resource plays. In general, estimates of economically recoverable crude oil and 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 assumed effects of regulation by governmental agencies, including with respect to royalty payments, all of which may vary considerably from actual results. All such estimates are to some degree uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For those reasons, estimates of the economically recoverable oil and gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. 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 and efficacy of these techniques, there remains the potential for human or systemic error in recording and

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reporting the magnitude of the Company’s oil and gas reserves. Inaccurate appraisal of large project reservoirs could result in missed production, revenue and earnings targets, and could negatively affect the Company’s reputation, investor confidence, and the Company’s ability to deliver on its growth strategy.

Government Regulation

Given the scope and complexity of Husky’s operations, the Company may be subject to regulation and intervention by governments at the federal, provincial, state and municipal levels in the countries in which it conducts its operations 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 regulation could impact the Company’s existing and planned projects as well as impose costs of compliance, increase capital expenditures and operating expenses, and expose the Company to other risks including environmental and safety risks. Examples of the Company’s regulatory risks include, but are not limited to, uncertain or negative interactions with governments, uncertain energy policies, environmental and safety controls related to the reduction of greenhouse gasses and other emissions, penalties, taxes, royalties, government fees, reserves access, limitations or increase in costs relating to the exportation of commodities, restrictions on the acquisition of exploration and production rights and land tenure, expropriation or cancellation of PSCs and/or contract rights, limitations on control over the development and abandonment of fields, and loss of licenses to operate.

Environmental Regulation

Husky anticipates that changes in environmental legislation may require reductions in emissions from its operations and result in increased capital expenditures. Further changes in environmental legislation could occur, which may result in stricter standards and enforcement, larger fines and liabilities, and increased capital expenditures and operating costs, which could have a material adverse effect on Husky’s financial condition and results of operations.

The 2010 Deepwater Horizon oil spill in the Gulf of Mexico has led to numerous public and governmental expressions of concern about the safety and potential environmental impact of offshore oil and gas operations. Stricter regulation of offshore oil and gas operations has already been implemented by the U.S. with respect to operations in the Outer Continental Shelf, including in the Gulf of Mexico. Further regulation, increased financial assurance requirements and increased caps on liability are likely to be applied to offshore oil and gas operations in these areas. In the event that similar changes in environmental regulation occur with respect to Husky’s operations in the Atlantic or Asia Pacific Regions, such changes could increase the cost of complying with environmental regulation in connection with these operations and have a material adverse impact on Husky’s operations.

Climate Change Regulation

Husky continues to monitor international efforts to address climate change, including developments on the Kyoto Protocol and the Copenhagen Accord. Canada has withdrawn from participation in the Kyoto Protocol. The effect of these initiatives on the Company’s operations cannot be determined with any certainty at this time. The Alberta and BC governments have regulations in place with the Saskatchewan government anticipated to soon follow with similar regulation. These regulations include limiting the intensity limits for large emitters of greenhouse gases in Alberta emitting 100,000 tonnes or more of greenhouse gas in any year. Under the regulations, a 12-15% intensity reduction will be applied to the average of that facility’s 2003-2005 baseline emissions intensity for established facilities. New facilities are required to reduce emissions starting with the fourth year of commercial operation by 2%, and then by 2% every year after, until the 12-15% reduction target has been achieved. These regulations impact all of Husky’s Upstream operations in BC, the Prince George Refinery, the Ram River gas plant and the Tucker thermal oil facility. In addition, the Federal Government of Canada has announced pending regulations in respect of greenhouse gases and other pollutants. Although the impact of these regulations is uncertain, they may adversely affect the Company’s operations and increase costs. These regulations may become more onerous over time as public and political pressures increase to implement initiatives that further reduce the emission of greenhouse gases.

While the U.S. EPA regulations are currently in effect, they have not yet had a material impact on Husky. However, the Company’s operations may be materially impacted by future application of these rules or by future U.S. greenhouse gas legislation applying to the oil and gas industry or the consumption of petroleum products or by these or any further restrictive regulations issued by the EPA. Such legislation or regulation could require Husky’s U.S. refining operations to significantly reduce emissions and/or purchase allowances, which may increase capital and operating expenditures.

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Competition

The energy industry is highly competitive with respect to gaining access to the resources required to increase oil and gas reserves and production and gain access to markets. Husky 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. Husky’s ability to successfully complete development projects could be 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. Husky’s competitors comprise all types of energy companies, some of which have greater resources.

Internal Credit Risk

Credit ratings affect Husky’s ability to obtain short-term and long-term financing and the cost of such financing. Additionally, the ability of Husky to engage in ordinary course derivative or hedging transactions, maintain ordinary course contracts with customers and suppliers on acceptable terms and enter into 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. 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 inasmuch 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, liquidity 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 adversely affects 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 land and offshore drilling rigs, land and offshore geological and geophysical services, engineering and construction services and construction materials. These materials and services may not be available when required at reasonable prices.

Climatic Conditions

Extreme climatic conditions may have significant adverse effects on operations. 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 or disruptions to the operations of major customers or suppliers can be affected by extreme weather, which may result in cessation or diminishment of production, delay of exploration and development activities or delay of plant construction. All of these could potentially cause financial losses.

7.3 Financial Risks

Husky’s financial risks are largely related to commodity price risk, foreign currency risk, interest rate risk, credit risk, and liquidity risk. From time to time, Husky uses derivative financial instruments to manage its exposure to these risks. These derivative financial instruments are not intended for trading or speculative purposes. For further details on the Company’s derivative financial instruments, including assumptions made in the calculation of fair value and additional discussion of exposure to risks and mitigation activities see Note 22 Financial Instrument and Risk Management within the Company’s 2012 audited Consolidated Financial Statements and Section 3.0 of this Management’s Discussion and Analysis. For a discussion on commodity price risk, refer to the Commodity Price Volatility section above.

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Foreign Currency Risk

Husky’s results are affected by the exchange rates between various currencies including the Canadian and U.S. dollar. The majority of Husky’s expenditures are in Canadian dollars while the majority 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 Husky’s U.S. dollar denominated debt and related interest expense, as expressed in Canadian dollars. The fluctuations in exchange rates are beyond Husky’s control and accordingly, could have a material adverse effect on the Company’s business, financial condition and cash flow.

The Company enters into short-dated foreign exchange contracts to fix the exchange rate for conversion of U.S. revenue dollars to hedge against these potential fluctuations. Husky also designates a portion of its U.S debt as a hedge of the Company’s net investment in the U.S. refining operations which are considered as a foreign functional currency. At December 31, 2012, the amount that the Company designated was U.S. $2.8 billion (December 31, 2011 - U.S. $1.3 billion). For the year ended December 31, 2012, the unrealized loss arising from the translation of the debt was $15 million (2011 - loss of $18 million), net of tax of $2 million (2011 - $3 million), which was recorded in OCI. At December 31, 2012, the fair value of the hedge was $97 million recorded in long-term debt in the consolidated balance sheets (December 31, 2011 - $80 million).

Interest Rate Risk

Interest rate risk is the impact of fluctuating interest rates on earnings, cash flows and valuations. In order to manage interest rate risk and the resulting interest expense, Husky 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. Husky may also enter into interest rate swaps from time to time as an additional means of managing current and future interest rate risk.

Credit Risk

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. Husky actively manages this exposure to credit and contract execution risk from both a customer and a supplier perspective. Internal credit policies govern Husky’s credit portfolio and limit transactions according to a counterparty’s and a supplier’s credit quality. Counterparties for all financial derivatives transacted by Husky are major financial institutions or counterparties with investment grade credit ratings.

Liquidity Risk

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 the availability to raise capital from various debt capital markets, including under its shelf prospectuses. The availability of capital under its shelf prospectuses is dependent on market conditions.

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Husky is committed to retaining investment grade credit ratings to support access to debt capital markets and currently has the following credit ratings:

	Outlook	Rating
Moody’s:
Senior Unsecured Debt	Stable	Baa2
Standard and Poor’s:
Senior Unsecured Debt	Stable	BBB+
Series 1 Preferred Shares	Stable	P-2 (low)
Dominion Bond Rating Service:
Senior Unsecured Debt	Stable	A (low)
Series 1 Preferred Shares	Stable	Pfd-2 (low)

Fair Value of Financial Instruments

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 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 Company’s financial instruments include cash and cash equivalents, accounts receivable, contribution receivable, accounts payable and accrued liabilities, long-term debt, contribution payable, and portions of other assets and other long-term liabilities.

The following table summarizes by measurement classification, derivatives, contingent consideration and hedging instruments that are carried at fair value through profit or loss (“FVTPL”) in the consolidated balance sheets:

Financial Instruments at Fair Value ($ millions)	December 31, 2012			December 31, 2011
Derivatives – FVTPL (held-for-trading)
Accounts receivable		13			65
Accounts payable and accrued liabilities		(5	)		(45	)
Other assets, including derivatives		1			2
Other – FVTPL (held-for-trading)(1)
Accounts payable and accrued liabilities		(27	)		(17	)
Other long-term liabilities		(78	)		(112	)
Hedging instruments
Other assets, including derivatives		1			—
Accounts payable and accrued liabilities		—			(93	)
Long-term debt(2)		25			(13	)
		(70	)		(213	)
Net gains (losses) for the year related to financial instruments held at fair value		122			(73	)
Included in net earnings		104			(55	)
Included in OCI		18			(18	)

⁽¹⁾  Non-derivative items related to contingent consideration recognized as part of a business acquisition.

⁽²⁾  Represents the foreign exchange adjustment related to translation of U. S. denominated long-term debt designated as a hedge of the Company’s net investment in its U.S. refining operations.

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8.0 Liquidity and Capital Resources

8.1 Summary of Cash Flow

In 2012, Husky funded its capital programs and dividend payments through cash generated from operating activities and cash on hand. At December 31, 2012, Husky had total debt of $3,918 million partially offset by cash on hand of $2,025 million for $1,893 million of net debt compared to $2,070 million of net debt as at December 31, 2011. At December 31, 2012, the Company had $3.1 billion in unused committed credit facilities, $280 million in unused short-term uncommitted credit facilities, $3.0 billion in unused capacity under its Canadian universal short form base shelf prospectus filed December 31, 2012 and U.S. $1.5 billion in unused capacity under its U.S universal short form base shelf prospectus filed June 13, 2011. The ability of the Company to utilize the capacity under its shelf prospectuses is subject to market conditions. Refer to Section 8.2.

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	2012			2011
Cash flow
Operating activities ($ millions)		5,189			5,092
Financing activities ($ millions)		(162	)		910
Investing activities ($ millions)		(4,830	)		(4,420	)
Financial Ratios(1)
Debt to capital employed (percent)(2)		17			18
Debt to cash flow (times)(3)(4)		0.8			0.8
Corporate reinvestment ratio (percent)(3)(5)		106			98
Interest coverage on long-term debt only(3)(6)
Earnings		12.5			14.5
Cash flow		24.9			24.7
Interest coverage on total debt(3)(7)
Earnings		12.3			14.1
Cash flow		24.6			23.9

⁽¹⁾  Financial ratios constitute non-GAAP measures. (Refer to Section 11.3)

⁽²⁾  Debt to capital employed is equal to long-term debt and long-term debt due within one year divided by capital employed. (Refer to Section 11.3)

⁽³⁾  Calculated for the 12 months ended for the dates shown.

⁽⁴⁾  Debt to cash flow (times) is equal to long-term debt and long-term debt due within one year divided by cash flow from operations. (Refer to Section 11.3)

⁽⁵⁾  Corporate reinvestment ratio is equal to capital expenditures plus exploration and evaluation expenses, capitalized interest and settlements of asset retirement obligations less proceeds from asset disposals divided by cash flow from operations. (Refer to Section 11.3)

⁽⁶⁾  Interest coverage on long-term debt on a net earnings basis is equal to net earnings before finance expense on long-term debt and income taxes divided by finance expense on long-term debt and capitalized interest. Interest coverage on long-term debt on a cash flow basis is equal to cash flow – operating activities before finance expense on long-term debt and current income taxes divided by finance expense on long-term debt and capitalized interest. Long-term debt includes the current portion of long-term debt.

⁽⁷⁾  Interest coverage on total debt on a net earnings basis is equal to net earnings before finance expense on total debt and income taxes divided by finance expense on total debt and capitalized interest. Interest coverage on total debt on a cash flow basis is equal to cash flow – operating activities before finance expense on total debt and current income taxes divided by finance expense on total debt and capitalized interest. Total debt includes short and long-term debt.

Cash Flow from Operating Activities

Cash generated from operating activities was $5,189 million in 2012 compared with $5,092 million in 2011. Slightly higher cash flows from operations were mainly due to changes in non-cash working capital, partially offset by higher taxes paid and lower net earnings when compared to 2011.

Cash Flow from Financing Activities

Cash used for financing activities was $162 million in 2012 compared with cash flow from financing activities of $910 million in 2011. Cash flow from financing activities was lower in 2012 compared to 2011 due to a preferred share issuance of $300 million and a common share issuance of $1.2 billion in 2011.

Cash Flow used for Investing Activities

Cash used in investing activities for 2012 was $4,830 million compared with $4,420 million in 2011. Cash invested in both periods was primarily for acquisitions and capital expenditures.

8.2 Working Capital Components

Working capital is the amount by which current assets exceed current liabilities. At December 31, 2012, Husky’s working capital was $2,404 million compared with $2,054 million at December 31, 2011.

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Movement in Working Capital

($ millions)	December 31, 2012			December 31, 2011			Increase/ (Decrease)
Cash and cash equivalents		2,025			1,841			184
Accounts receivable		1,349			1,235			114
Income taxes receivable		323			273			50
Inventories		1,736			2,059			(323	)
Prepaid expenses		64			36			28
Accounts payable and accrued liabilities		(2,986	)		(2,867	)		(119	)
Asset retirement obligations		(107	)		(116	)		9
Long-term debt due within one year		—			(407	)		407
Net working capital		2,404			2,054			350

The increase in cash was primarily due to strong cash flow from operations in the year which was in excess of cash flow used for financing and investing activities. Cash flow used for financing and investing activities in 2012 primarily consisted of dividends paid on common and preferred shares, interest paid on long-term debt and Upstream capital expenditures. Increases in accounts receivable and accounts payable were due to the timing of settlements compared to 2011. Inventory levels held at December 31, 2012 decreased from levels held at December 31, 2011 due to comparable production combined with higher throughput in Downstream in the fourth quarter of 2012 compared to the same period in 2011 and the timing of lifts and sales of upstream offshore production. The decrease in long-term debt due within one year was due to the repayment of debt which matured in 2012 compared to no long-term debt maturities in 2013.

Sources and Uses of Cash

Liquidity describes a company’s ability to access cash. Companies operating in the upstream oil and gas industry require sufficient cash in order to fund capital programs necessary to maintain and increase production and develop reserves, to acquire strategic oil and gas assets, and to repay maturing debt and pay dividends. Husky is currently able to fund its capital programs principally by cash generated from operating activities, cash on hand, issuances of equity, issuances of long-term debt and borrowings under committed and uncommitted credit facilities. During times of low oil and gas prices, a portion of a capital program can generally be deferred. However, due to the long cycle times and the importance to future cash flow in maintaining 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, Husky frequently evaluates the options with respect to sources of short and long-term capital resources. Occasionally, the Company will hedge a portion of its production to protect cash flow in the event of commodity price declines. At December 31, 2012, no production was hedged.

At December 31, 2012 Husky had the following available credit facilities:

Credit Facilities ($ millions)	Available		Unused
Operating facilities(1)		515		280
Syndicated bank facilities		3,100		3,100
		3,615		3,380

⁽¹⁾  Consists of demand credit facilities.

Cash and cash equivalents at December 31, 2012 totalled $2,025 million compared with $1,841 million at the beginning of the year.

At December 31, 2012, Husky had unused short and long-term borrowing credit facilities totalling $3,380 million. A total of $235 million of the Company’s short-term borrowing credit facilities was used in support of outstanding letters of credit.

Husky Energy (HK) Limited and Husky Oil China Ltd., subsidiaries of Husky, each have an uncommitted demand revolving facility of U.S. $10 million available for general purposes.

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The 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.

At the special meeting of shareholders held on February 28, 2011, the Company’s shareholders approved amendments to the common share terms, which provide shareholders with the ability to receive dividends in common shares or in cash. Under the amended terms, quarterly dividends may be declared in an amount expressed in dollars per common share and 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. A shareholder must 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 confirming they will accept the dividend in common shares. Failure to do so will result in such shareholder receiving the dividend paid in cash. During the year ended December 31, 2012, the Company declared dividends payable of $1.20 per common share, resulting in dividends of $1.2 billion. An aggregate of $557 million was paid in cash during 2012. At December 31, 2012, $295 million, including $293 million in cash and $2 million in common shares, was payable to shareholders on account of dividends declared on November 1, 2012.

On March 18, 2011, Husky issued 12 million Cumulative Redeemable Preferred Shares, Series 1 (the “Series 1 Preferred Shares”) at a price of $25.00 per share for aggregate gross proceeds of $300 million under a Canadian universal short form base shelf prospectus (the “Prior Canadian Shelf Prospectus”). Holders of the Series 1 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 yielding 4.45% annually for the initial period ending March 31, 2016 as and when declared by Husky’s Board of Directors. Thereafter, the dividend rate will be reset every five years at a rate equal to the 5-year Government of Canada bond yield plus 1.73%. Holders of Series 1 Preferred Shares will 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, 2016 and on March 31 every five years thereafter. Holders of the Series 2 Preferred Shares will be entitled to receive cumulative quarterly floating dividends at a rate equal to the three-month Government of Canada Treasury Bill yield plus 1.73%.

On June 13, 2011, the Company filed a universal short form base shelf prospectus (the “U.S. Shelf Prospectus”) with the Alberta Securities Commission and the U.S. Securities and Exchange Commission that enables the Company to offer up to U.S. $3.0 billion of common shares, preferred shares, debt securities, subscription receipts, warrants and units in the United States up to and including July 12, 2013. At December 31, 2012, approximately $1.5 billion remains available for issuance under the U.S. Shelf Prospectus.

On June 29, 2011, Husky issued 37 million common shares at a price of $27.05 per share for total gross proceeds of approximately $1.0 billion through a public offering, and a total of 7.4 million common shares at a price of $27.05 per share for total gross proceeds of $200 million through a private placement to L.F. Investments (Barbados) Limited and Hutchison Whampoa Luxembourg Holdings S.à.r.l. The Company received total gross proceeds of $1.2 billion from this issuance. The public offering was completed under the U.S. Shelf Prospectus and accompanying prospectus supplement in the United States and under the Prior Canadian Shelf Prospectus and accompanying prospectus supplement in Canada.

On March 22, 2012, the Company issued U.S. $500 million of 3.95% senior unsecured notes due April 15, 2022 pursuant to the U.S. Shelf Prospectus and an accompanying prospectus supplement. The notes are redeemable at the option of the Company at a make-whole premium and interest is payable semi-annually. The notes are unsecured and unsubordinated and rank equally with all of the Company’s other unsecured and unsubordinated indebtedness.

On June 15, 2012, the Company repaid the maturing 6.25% notes issued under a trust indenture dated June 14, 2002. The amount paid to note holders was U.S. $413 million, including U.S. $13 million of interest.

On December 14, 2012, the Company amended and restated both of its revolving syndicated credit facilities to allow the Company to borrow up to $1.5 billion and $1.6 billion in either Canadian or U.S. currency from a group of banks on an unsecured basis.

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On December 31, 2012, the Company filed a universal short form base shelf prospectus (the “Canadian Shelf Prospectus”) with applicable securities regulators in each of the provinces of Canada, other than Quebec, that enables the Company to offer up to $3.0 billion of common shares, preferred shares, debt securities, subscription receipts, warrants and units (the “Securities”) in Canada up to and including January 30, 2015. As of December 31, 2012, the Company had not issued Securities under the Canadian Shelf Prospectus. This Canadian Shelf Prospectus replaced the Prior Canadian Shelf Prospectus filed in Canada during November 2010 which had remaining unused capacity of $1.4 billion and expired in December 2012. The ability of the Company to raise capital utilizing the U.S. Shelf Prospectus and Canadian Shelf Prospectus is dependent on market conditions at the time of sale.

Capital Structure ($ millions)	December 31, 2012
	Outstanding		Available(1)
Total long-term debt		3,918		3,380
Common shares, retained earnings and other reserves		19,161

⁽¹⁾  Available long-term debt includes committed and uncommitted credit facilities.

8.3 Cash Requirements

Contractual Obligations and Other Commercial Commitments

In the normal course of business, Husky is obligated to make future payments. These obligations represent contracts and other commitments that are known and non-cancellable.

Contractual Obligations Payments due by period ($ millions)	2013		2014-2015		2016-2017		Thereafter		Total
Long-term debt and interest on fixed rate debt		227		1,428		826		3,125		5,606
Operating leases		130		370		436		556		1,492
Firm transportation agreements		217		561		476		2,652		3,906
Unconditional purchase obligations(1)		3,089		4,347		102		78		7,616
Lease rentals and exploration work agreements		85		174		212		571		1,042
Asset retirement obligations(2)		107		198		211		9,812		10,328
		3,855		7,078		2,263		16,794		29,990

⁽¹⁾  Includes purchase of refined petroleum products, processing services, distribution services, insurance premiums, drilling services and natural gas purchases.

⁽²⁾  Asset retirement obligation (ARO) amounts represent the undiscounted future payments for the estimated cost of abandonment, removal and remediation associated with retiring the Company’s assets.

The following additions during the year are included in total non-cancellable contracts and other commercial commitments:

• The Company executed an operating lease agreement with Seadrill for the semi-submersible rig, West Mira. The non-cancellable minimum future payments are approximately $129 million per year commencing 2015 for five years with an option to extend the contract to 2022.

• The Company executed contracts to purchase refined petroleum products in Canada over the next three years totalling approximately $4.5 billion.

• The Company updated its estimates for Asset Retirement Obligations (“ARO”) as outlined in Note 16 of the 2012 audited Consolidated Financial Statements. On an undiscounted basis, the ARO increased from $8.5 billion as at December 31, 2011 to $10.3 billion as at December 31, 2012 due to increased cost estimates and asset growth in the Upstream and Downstream segments.

Based on Husky’s 2013 commodity price forecast, the Company believes that its non-cancellable contractual obligations, including commercial commitments and the 2013 Capital Program, will be funded by cash flow from operating activities and, to the extent required, by available committed credit facilities and the issuance of long-term debt. In the event of significantly lower cash flow, Husky would be able to defer certain projected capital expenditures without penalty.

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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 the outcome of adverse 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 and management believes that it has adequately provided for current and deferred income taxes.

Husky provides a defined contribution plan and a post-retirement health and dental plan for all qualified employees in Canada. The Company also provides a defined benefit pension plan for approximately 96 active employees, 110 participants with deferred benefits and 535 participants or joint survivors receiving benefits in Canada. This plan was closed to new entrants in 1991 after the majority of employees transferred to the defined contribution pension plan. Husky provides a defined benefit pension plan for approximately 237 active union represented employees in the United States. A defined benefit pension plan for 207 active non-represented employees in the United States was curtailed effective April 1, 2011. Approximately 10 participants in both U.S. plans have deferred benefits and no participants were receiving benefits at year end. These pension plans were established effective July 1, 2007 in conjunction with the acquisition of the Lima Refinery. Husky also assumed a post-retirement welfare plan covering all qualified employees at the Lima Refinery and contributes to a 401(k) plan (Refer to Note 19 to the 2012 audited Consolidated Financial Statements).

Husky has an obligation to fund capital expenditures of the BP-Husky Toledo Refinery LLC (Refer to Note 8 to the 2012 audited Consolidated Financial Statements) which is payable between December 31, 2011 and December 31, 2015 with the final balance due and payable by December 31, 2015. The timing of payments during this period will be determined by the capital expenditures made at the refinery during this same period. At December 31, 2012, Husky’s share of this obligation was U.S. $1.3 billion including accrued interest.

Husky is also subject to various contingent obligations that become payable only if certain events or rulings were to 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 and have not been reflected in the Company’s financial statements beyond the associated ARO. These contingent environmental liabilities are primarily related to the migration of contamination at fuel outlets and certain legacy sites where Husky 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.

8.4 Off-Balance Sheet Arrangements

Husky does not believe that it has any off-balance sheet arrangements that have, or are reasonably likely to have, a current or future material effect on the company’s financial condition or financial performance.

Standby Letters of Credit

On occasion, Husky issues letters of credit in connection with transactions in which the counterparty requires such security.

8.5 Transactions with Related Parties

The Company continues to sell natural gas to and purchase steam from the Meridian cogeneration facility owned by a related party of Husky. These natural gas sales and steam purchases are related party transactions and have been measured at fair value. For the year ended December 31, 2012, the total value of natural gas sales to the Meridian

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cogeneration facility owned by the related party was $74 million. For the year ended December 31, 2012, the total value of obligated steam purchases from the Meridian cogeneration facility owned by the related party was $13 million. In addition, the Company provides cogeneration and facility support services to Meridian, measured on a cost recovery basis. For the year ended December 31, 2012, the total cost recovery for these services was $19 million.

8.6 Outstanding Share Data

Authorized
unlimited number of common shares
unlimited number of preferred shares
Issued and outstanding: February 27, 2013
common shares	982,541,821
cumulative redeemable preferred shares, series 1	12,000,000
stock options	28,389,305
stock options exercisable	10,224,925

9.0 Critical Accounting Estimates and Key Judgments

Husky’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 2012 audited Consolidated Financial Statements. Certain of the Company’s accounting policies require subjective judgment and estimation about uncertain circumstances.

9.1 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, impairment, asset retirement obligations, assets and liabilities measured at fair value, employee future benefits, income taxes, and contingencies are based on estimates.

Depletion, Depreciation and Amortization

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.

Asset Retirement Obligations

Estimating ARO requires that Husky 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 ARO 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 ARO.

Fair Value of Financial Instruments

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 instruments could differ materially from the fair value recorded and could impact future results.

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Employee Future Benefits

The determination of the cost of the post-retirement health and dental care plan and the defined benefit pension plan 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 and 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. Significant estimations are made with respect to the timing of temporary difference reversals, the realizability of tax assets and in circumstances where 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

Husky is required to both determine whether a loss is probable based on judgment and interpretation of laws and regulations and determine whether the loss can be reasonably estimated. When a loss is determined it is charged to net earnings. Husky must continually monitor known and potential contingent matters and make appropriate provisions by charges to net earnings when warranted by circumstances.

9.2 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 successful efforts and impairment assessments, the determination of cash generating units (“CGUs”) and the designation of the Company’s functional currency.

Successful Efforts Assessments

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. Successful efforts assessments require significant judgment and may change as new information becomes available.

Impairment of Non-Financial Assets and Financial Assets

The carrying amounts of the Company’s non-financial assets are reviewed at each reporting date to determine whether there is any indication of impairment. Determining whether there are indications of impairment requires significant judgment of internal and external indicators. If impairment is indicated, the amount by which the carrying value exceeds the estimated fair value of the long-lived asset is charged to net earnings. The determination of the recoverable amount for impairment purposes involves the use of numerous assumptions and estimates including future net cash flows from oil and gas reserves, future third-party pricing, inflation factors, discount rates and other uncertainties. Future revisions to these assumptions impact the recoverable amount.

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 for loans and receivables. The calculations for

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the net present value of estimated future cash flows related to derivative financial assets requires 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.

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 judgement based on the composition of revenues and costs in the locations in which it operated.

10.0 Recent Accounting Standards

Consolidated Financial Statements

In May 2011, the IASB published IFRS 10, “Consolidated Financial Statements,” which provides a single model to be applied in the assessment of control for all entities in which the Company has an investment including special purpose entities currently in the scope of Standing Interpretations Committee (“SIC”) 12. Under the new control model, the Company has control over an investment if the Company has the ability to direct the activities of the investment, is exposed to the variability of returns from the investment and there is a link between the ability to direct activities and the variability of returns. IFRS 10 is effective for the Company on January 1, 2013 with required retrospective application and early adoption permitted. The Company intends to retrospectively adopt IFRS 10 on January 1, 2013. The adoption of the standard is not expected to have a material impact on the Company’s financial statements.

Joint Arrangements

In May 2011, the IASB published IFRS 11, “Joint Arrangements,” whereby joint arrangements are classified as either joint operations or joint ventures. Parties to a joint operation retain the rights and obligations to individual assets and liabilities of the operation, while parties to a joint venture have rights to the net assets of the venture. Joint operations shall be accounted for in a manner consistent with jointly controlled assets and operations whereby the Company’s contractual share of the arrangement’s assets, liabilities, revenues and expenses is included in the consolidated financial statements. Any arrangement structured through a separate vehicle that does effectively result in separation between the Company and the arrangement shall be classified as a joint venture and accounted for using the equity method of accounting. Under the existing IFRS standard, the Company has the option to account for any interests it has in joint arrangements using proportionate consolidation or equity accounting. IFRS 11 is effective for the Company on January 1, 2013 with required retrospective application and early adoption permitted. The Company intends to retrospectively adopt IFRS 11 on January 1, 2013. The adoption of the standard is not expected to have a material impact on the Company’s financial statements.

Disclosure of Interests in Other Entities

In May 2011, the IASB published IFRS 12, “Disclosure of Interests in Other Entities,” which contains new disclosure requirements for interests the Company has in subsidiaries, joint arrangements, associates and unconsolidated structured entities. Required disclosures aim to provide readers of the financial statements with information to evaluate the nature of and risks associated with the Company’s interests in other entities and the effects of those interests on the Company’s financial statements. IFRS 12 is effective for the Company on January 1, 2013 with required retrospective application and early adoption permitted. The Company intends to retrospectively adopt IFRS 12 on January 1, 2013. The adoption of the standard is not expected to have a material impact on the Company’s financial statements.

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Investments in Associates and Joint Ventures

In May 2011, the IASB issued amendments to IAS 28, “Investments in Associates and Joint Ventures,” which provides additional guidance applicable to accounting for interests in joint ventures or associates when a portion of an interest is classified as held for sale or when the Company ceases to have joint control or significant influence over an associate or joint venture. When joint control or significant influence over an associate or joint venture ceases, the Company will no longer be required to remeasure the investment at that date. When a portion of an interest in a joint venture or associate is classified as held for sale, the portion not classified as held for sale shall be accounted for using the equity method of accounting until the sale is completed at which time the interest is reassessed for prospective accounting treatment. Amendments to IAS 28 are effective for the Company on January 1, 2013 with required retrospective application and early adoption permitted. The Company intends to retrospectively adopt these amendments on January 1, 2013. The Company does not expect the amendments to IAS 28 to have a material impact on the Company’s financial statements.

Fair Value Measurement

In May 2011, the IASB published IFRS 13, “Fair Value Measurement,” which provides a single source of fair value measurement guidance and replaces fair value measurement guidance contained in individual IFRSs. The standard provides a framework for measuring fair value and establishes new disclosure requirements to enable readers to assess the methods and inputs used to develop fair value measurements, for recurring valuations that are subject to measurement uncertainty, and for the effect of those measurements on the financial statements. IFRS 13 is effective for the Company on January 1, 2013 with required prospective application and early adoption permitted. The Company intends to adopt IFRS 13 on January 1, 2013. The adoption of the standard is not expected to have a material impact on the Company’s financial statements.

Employee Benefits

In June 2011, the IASB issued amendments to IAS 19 “Employee Benefits” to eliminate the corridor method that permits the deferral of actuarial gains and losses, to revise the presentation requirements for changes in defined benefit plan assets and liabilities and to enhance the required disclosures for defined benefit plans. The amendments to IAS 19 are effective for the Company on January 1, 2013 with required retrospective application and early adoption permitted. The Company intends to retrospectively adopt these amendments on January 1, 2013. The adoption of the amended standard is not expected to have a material impact on the Company’s financial statements.

Offsetting Financial Assets and Financial Liabilities

In December 2011, the IASB issued amendments to IFRS 7, “Financial Instruments: Disclosures” and IAS 32, “Financial Instruments: Presentation” to clarify the current offsetting model and develop common disclosure requirements to enhance the understanding of the potential effects of offsetting arrangements. Amendments to IFRS 7 are effective for the Company on January 1, 2013 with required retrospective application and early adoption permitted. Amendments to IAS 32 are effective for the Company on January 1, 2014 with required retrospective application and early adoption permitted. The Company intends to retrospectively adopt the IFRS 7 amendments on January 1, 2013 and the IAS 32 amendments on January 1, 2014. The adoption of these amended standards is not expected to have a material impact on the Company’s financial statements.

Financial Instruments

In November 2009, the IASB published IFRS 9, “Financial Instruments,” which covers the classification and measurement of financial assets as part of its project to replace IAS 39, “Financial Instruments: Recognition and Measurement.” In October 2010, the requirements for classifying and measuring financial liabilities were added to IFRS 9. Under this guidance, entities have the option to recognize financial liabilities at fair value through profit or loss. If this option is elected, entities would be required to reverse the portion of the fair value change due to their own credit risk out of net earnings and recognize the change in OCI. IFRS 9 is effective for the Company on January 1, 2015 with required retrospective application and early adoption permitted. The Company intends to retrospectively adopt the amendments on January 1, 2015. The adoption of the standard is not expected to have a material impact on the Company’s financial statements.

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11.0 Reader Advisories

11.1 Forward-looking Statements

Certain statements in this document are forward looking statements within the meaning of 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, and forward-looking information within the meaning of applicable Canadian securities legislation (collectively “forward-looking statements”). The Company hereby provides cautionary statements identifying important factors that could cause actual results to differ materially from those projected in these forward-looking statements. Any 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,” “are expected to,” “will continue,” “is anticipated,” “is targeting,” “estimated,” “intend,” “plan,” “projection,” “could,” “aim,” “vision,” “goals,” “objective,” “target,” “schedules” and “outlook”) are not historical facts, are forward-looking and may involve estimates and assumptions and are subject to risks, uncertainties and other factors some of which are beyond the Company’s control and difficult to predict. Accordingly, these factors could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements.

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 general financial plans and goals; target weighting of production among product types; target debt to cash flow ratio and target debt to capital employed ratio; expected sources of cash from the Company’s growth projects; the Company’s 2013 production guidance; target compound annual production growth for the periods 2010-2015 and 2012-2017, and the Company’s ability to achieve such targets; the Company’s 2013 capital program; and the funding sources for the Company’s non-cancellable contractual obligations and other commercial commitments;

• with respect to the Company’s Asia Pacific Region: anticipated timing of first production from the Company’s Liwan Gas Project; planned timing of resumption of pipe laying activity at the Company’s Liwan Gas Project; planned timing of floatover of the topsides for the central platform at the Company’s Liwan Gas Project; planned timing of development of the single well Liuhua 34-2 field; and anticipated timing of first gas from the Company’s Madura Strait Block;

• with respect to the Company’s Atlantic Region: development and drilling plans for the South White Rose extension project; development and drilling plans for the North Amethyst field; expected timing of a decision on a preferred development option for the West White Rose project; expected timing of completion of the West Mira rig; planned participation in operated and non-operated exploratory wells in the region during 2013 and 2014; and 2013 turnaround plans at the SeaRose and Terra Nova FPSOs;

• with respect to the Company’s Oil Sands properties: anticipated timing and volume of production from the Company’s Sunrise Energy Project; expected timing of completion of the Design Basis Memorandum for the next phase of the Company’s Sunrise Energy Project; expected timing of production from the Company’s Tucker Oil Sands Project; and anticipated timing of filing a regulatory application for the bitumen carbonates pilot at the Company’s Saleski Oil Sands project;

• with respect to the Company’s Heavy Oil properties: scheduled timing of first production from the Company’s Sandall thermal development project; anticipated timing of first commercial production at the Company’s Rush Lake Project; anticipated timing of production from the second well pair pilot at the Company’s Rush Lake project; and the Company’s horizontal and CHOPS drilling programs for 2013;

• with respect to the Company’s Western Canadian oil and gas resource plays: 2013 drilling plans in the Company’s oil and gas resource play portfolio; tie-in plans at the Company’s Kaybob property; and expected timing of production response from the Company’s Fosterton Alkaline Surfactant Polymer facility;

• with respect to the Company’s Infrastructure and Marketing business unit: intended focus of spending with the unit; and

• with respect to the Company’s Downstream operating segment: project and expansion plans within the segment for 2013 and beyond; expected timing of operation of a kerosene hydrotreater at the Lima Refinery; expected timing of start up of the Continuous Catalyst Regeneration Reformer Project at the BP-Husky Toledo Refinery; and scheduled timing and anticipated duration of turnarounds at the Lloydminster Refinery, the Lima Refinery and the Lloydminster Upgrader.

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In addition, statements relating to “reserves” and “resources” are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves or resources described can be profitably produced in the future.

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 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, regulators and other sources.

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.

Sections 7.2 and 7.3 of this Management’s Discussion and Analysis and the Company’s Annual Information Form for the year ended December 31, 2012 and other documents filed with securities regulatory authorities (accessible through the SEDAR website www.sedar.com and the EDGAR website www.sec.gov) describe the risks, material assumptions and other factors that could influence actual results and are incorporated herein by reference.

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. 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 its assessment of the future considering all information then available.

11.2 Oil and Gas Reserves Reporting

Disclosure of Oil and Gas Reserves and Other Oil and Gas Information

Unless otherwise noted in this document, all reserves estimates given have an effective date of December 31, 2012.

The Company uses the terms barrels of oil equivalent (“boe”), which is calculated on an energy equivalence basis whereby one barrel of crude oil is equivalent to six thousand cubic feet of natural gas. Readers are cautioned that the term boe may be misleading, particularly if used in isolation. This measure is primarily applicable at the burner tip and does not represent value equivalence at the wellhead.

11.3 Non-GAAP Measures

Disclosure of non-GAAP Measurements

Husky uses measurements primarily based on IFRS as issued by the International Accounting Standards Board and also certain secondary non-GAAP measurements. The non-GAAP measurements included in this Management’s Discussion and Analysis are cash flow from operations, operating netback, debt to capital employed, debt to cash flow, corporate reinvestment ratio, interest coverage on long-term debt, interest coverage on total debt, return on capital employed and return on capital in use. None of these measurements are used to enhance the Company’s reported financial performance or position. With the exception of cash flow from operations, there are no comparable measures to these non-GAAP measures in accordance with IFRS. These non-GAAP measurements are

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considered to be useful as complementary measurements in assessing Husky’s financial performance, efficiency and liquidity. The non-GAAP measurements do not have a standardized meaning prescribed by IFRS and therefore are unlikely to be comparable by definition to similar measures presented by other companies. Except as described below, the definitions of these measurements are found in Section 11.4, “Additional Reader Advisories.”

Disclosure of Cash Flow from Operations

Husky uses the term “cash flow from operations,” 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. Cash flow from operations is presented in the Company’s financial reports to assist management and investors in analyzing operating performance by business in the stated period. Husky’s determination of cash flow from operations may not be comparable to that reported by other companies. Cash flow from operations equals net earnings plus items not affecting cash which include accretion, depletion, depreciation and amortization, future income taxes, foreign exchange and other non-cash items.

The following table shows the reconciliation of cash flow – operating activities to cash flow from operations and related per share amounts for the years ended December 31:

($ millions)	2012			2011
GAAP Cash flow – operating activities		5,189			5,092
Settlement of asset retirement obligations		123			105
Income taxes paid		575			282
Interest received		(34	)		(12	)
Change in non-cash working capital		(843	)		(269	)
Non-GAAP Cash flow from operations		5,010			5,198
Cash flow from operations – basic		5.13			5.63
Cash flow from operations – diluted		5.13			5.58

Disclosure of Operating Netback

Operating netback is a common non-GAAP metric used in the oil and gas industry. This measurement assists management and investors to evaluate the specific operating performance by product at the oil and gas lease level. The netback was determined by taking upstream netback (gross revenues less operating costs less royalties) divided by upstream gross production.

11.4 Additional Reader Advisories

Intention of Management’s Discussion and Analysis (“MD&A”)

This MD&A 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 financial statements.

Review by the Audit Committee

This MD&A was reviewed by the Audit Committee and approved by Husky’s Board of Directors on February 27, 2013. Any events subsequent to that date could conceivably materially alter the veracity and usefulness of the information contained in this document.

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Additional Husky Documents Filed with Securities Commissions

This MD&A should be read in conjunction with the Consolidated Financial Statements and related notes. The readers are also encouraged to refer to Husky’s interim reports filed in 2012, which contain MD&A and Consolidated Financial Statements, and Husky’s Annual Information Form filed separately with Canadian regulatory agencies and Form 40-F filed with the SEC, the U.S. regulatory agency. These documents are available at www.sedar.com, at www.sec.gov and www.huskyenergy.com.

Use of Pronouns and Other Terms

“Husky” and “the Company” refer to Husky Energy Inc. on a consolidated basis.

Standard Comparisons in this Document

Unless otherwise indicated, comparisons of results are for the years ended December 31, 2012 and 2011 and Husky’s financial position as at December 31, 2012 and at December 31, 2011.

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 their decision to buy, sell or hold the securities of Husky.

Additional Reader Guidance

Unless otherwise indicated:

• Financial information is presented in accordance with IFRS as issued by the International Accounting Standards Board.

• Currency is presented in millions of Canadian dollars (“$ millions”).

• Gross production and reserves are Husky’s working interest prior to deduction of royalty volume.

• Prices are presented before the effect of hedging.

• Light crude oil is 30^º API and above.

• Medium crude oil is 21^º API and above but below 30^º API.

• Heavy crude oil is above 10^º API but below 21^º API.

• Bitumen is solid or semi-solid with a viscosity greater than 10,000 centipoise at original temperature in the deposit and atmospheric pressure.

Terms

Bitumen	Bitumen is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulphur, metals and other non-hydrocarbons
Brent Crude Oil	Prices which are dated less than 15 days prior to loading for delivery
Capital Employed	Short and long-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
Cash Flow from Operations	Earnings from operations plus non-cash charges before settlement of asset retirement obligations, income taxes paid, interest received and changes in non-cash working capital
Coal Bed Methane	Methane (CH4), the principal component of natural gas, is adsorbed in the pores of coal seams
Corporate Reinvestment Ratio	Corporate reinvestment ratio is equal to capital expenditures plus exploration and evaluation expenses, capitalized interest and settlements of asset retirement obligations less proceeds from asset disposals divided by cash flow from operations
Debt to Capital Employed	Long-term debt and long-term debt due within one year divided by capital employed
Debt to Cash Flow	Long-term debt and long-term debt due within one year divided by cash flow from operations
Design Rate Capacity	Maximum continuous rated output of a plant based on its design
Embedded Derivative	Implicit or explicit term(s) in a contract that affects some or all of the cash flows or the value of other exchanges required by the contract
Feedstock	Raw materials which are processed into petroleum products
Front End Engineering Design	Preliminary engineering and design planning, which among other things, identifies project objectives, scope, alternatives, specifications, risks, costs, schedule and economics

Management’s Discussion and Analysis 2012

52

Gross/Net Acres/Wells	Gross refers to the total number of acres/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
Interest Coverage Ratio	A calculation of a company’s ability to meet its interest payment obligation. It is equal to net earnings or cash flow – operating activities before finance expense divided by finance expense and capitalized interest
NOVA Inventory Transfer	Exchange or transfer of title of gas that has been received into the NOVA pipeline system but not yet delivered to a connecting pipeline
Polymer	A substance which has a molecular structure built up mainly or entirely of many similar units bonded together
Return on Capital Employed	Non-GAAP measure used to assist in analyzing shareholder value and return on average capital.Net earnings plus after tax interest expense divided by the two-year average capital employed
Return on Capital in Use	Non-GAAP measure used to assist in analyzing shareholder value and return on capital. Net earnings plus after tax interest expense divided by; the two-year average capital employed, less any capital invested in assets that are not generating cash flows
Return on Equity	Non-GAAP measure used to assist in analyzing shareholder value. Net earnings divided by the two-year average shareholder’s equity.
Seismic	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	Shares, retained earnings and other reserves
Total Debt	Long-term debt including current portion and bank operating loans
Turnaround	Scheduled performance of plant or facility maintenance

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

“Proved developed reserves” are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g., when compared to the cost of drilling a well) to put the reserves on production.

“Proved Undeveloped” are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g. when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned. In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator’s assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

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

Abbreviations

bbls	barrels	CNOOC	China National Offshore Oil Corporation
bpd	barrels per day	EOR	enhanced oil recovery
bps	basis points	FEED	Front end engineering design
mbbls	thousand barrels	FPSO	Floating production, storage and offloading vessel
mbbls/day	thousand barrels per day	GAAP	Generally Accepted Accounting Principles
mmbbls	million barrels	GJ	gigajoule
mcf	thousand cubic feet	LIBOR	London Interbank Offered Rate
mmcf	million cubic feet	MD&A	Management’s Discussion and Analysis
mmcf/day	million cubic feet per day	MW	megawatt
bcf	billion cubic feet	NGL	natural gas liquids
tcf	trillion cubic feet	NIT	NOVA Inventory Transfer
boe	barrels of oil equivalent	NYMEX	New York Mercantile Exchange

Management’s Discussion and Analysis 2012

53

mboe	thousand barrels of oil equivalent	OPEC	Organization of Petroleum Exporting Countries
mboe/day	thousand barrels of oil equivalent per day	PSC	production sharing contract
mmboe	million barrels of oil equivalent	PIIP	Petroleum initially-in-place
mcfge	thousand cubic feet of gas equivalent	SAGD	Steam assisted gravity drainage
mmbtu	million British Thermal Units	SEDAR	System for Electronic Document Analysis and Retrieval
mmlt	million long tons	WI	working interest
tcfe	trillion cubic feet equivalent	WTI	West Texas Intermediate
tgal	thousand gallons	C-NLOPB	Canada-Newfoundland and Labrador Offshore
ASP	alkali surfactant polymer		Petroleum Board
CHOPS	cold heavy oil production with sand	IFRS	International Financial Reporting Standards

11.5 Disclosure Controls and Procedures

Disclosure Controls and Procedures

Husky’s management, with the participation 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, 2012, and have concluded that such disclosure controls and procedures are effective to ensure that information required to be disclosed by Husky in reports that it files or submits under the Securities Exchange Act of 1934 and Canadian securities laws is (i) recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and Canadian securities laws and (ii) accumulated and communicated to Husky’s management, including its principal executive officer and principal financial officer, to allow for timely decisions regarding required disclosure.

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 is responsible for 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 (“COSO”) framework to evaluate the effectiveness of Husky’s internal control over financial reporting.

3) As at December 31, 2012, management assessed 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, 2012, 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) which attests to management’s assessment of 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, 2012, that have materially affected or are reasonably likely to materially affect its internal control over financial reporting.

Management’s Discussion and Analysis 2012

54

12.0 Selected Quarterly Financial & Operating Information

Segmented Operational Information

	2012								2011
	Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
Upstream
Daily production, before royalties
Light crude oil & NGL (mbbls/day)		86.1		55.4		56.8		91.2		91.7		83.3		84.5		91.0
Medium crude oil (mbbls/day)		23.2		23.9		24.1		24.9		24.3		24.6		24.6		24.6
Heavy crude oil (mbbls/day)		76.0		77.1		78.1		76.2		75.8		75.1		73.6		73.4
Bitumen (mbbls/day)		46.7		37.8		29.6		29.6		27.4		23.6		23.6		24.2
Total crude oil production (mboe/day)		232.0		194.2		188.6		221.9		219.2		206.6		206.3		213.2
Natural gas (mmcf/day)		523.7		544.9		559.5		588.3		597.9		614.7		631.8		583.3
Total production (mboe/day)		319.3		285.0		281.9		319.9		318.9		309.1		311.6		310.4
Average sales prices
Light crude oil & NGL ($/bbl)		94.91		90.5		94.71		111.53		106.61		101.16		108.26		100.21
Medium crude oil ($/bbl)		67.55		69.59		69.92		78.63		85.83		70.81		81.24		68.41
Heavy crude oil ($/bbl)		57.9		60.58		60.42		68.93		76.37		62.35		72.51		61.02
Bitumen ($/bbl)		55.74		60.1		58.09		65.83		74.19		59.60		69.76		58.11
Natural gas ($/mcf)		3.25		2.48		2.05		2.64		3.53		4.12		4.02		3.87
Operating costs ($/boe)		15.05		16.69		15.83		14.56		14.17		14.62		13.83		13.40
Operating netbacks(1)
Lloydminster – Thermal Oil ($/boe)(2)		45.47		48.42		43.42		50.25		49.90		39.20		45.61		33.34
Lloydminster – Non-Thermal Oil ($/boe)(2)		30.09		33.35		37.07		47.94		47.47		35.75		43.70		35.33
Oil Sands – Bitumen ($/boe)(2)		19.49		33.91		30.05		35.88		38.45		27.43		38.66		24.32
Western Canada – Crude Oil ($/boe)(2)		38.31		37.12		38.52		43.67		48.12		35.40		45.67		36.81
Western Canada – Natural gas ($/mcf)(3)		1.49		1.16		1.11		1.52		2.03		2.51		2.62		2.56
Atlantic – Light Oil ($/boe)(2)		85.05		66.97		70.99		94.34		82.26		82.03		86.00		80.15
Asia Pacific – Light Oil & NGL ($/boe)(2)		69.28		72.97		73.54		88.16		70.04		67.07		67.30		73.42
Total ($/boe)(2)		35.99		30.08		30.43		43.00		42.65		37.22		42.16		38.04
Net wells drilled(4)
Exploration Oil		8		1		3		18		19		8		4		9
Gas		—		2		—		10		11		3		1		9
Dry		—		—		—		—		—		—		—		3
		8		3		3		28		30		11		5		21
Development Oil		217		245		56		197		196		286		93		190
Gas		6		1		2		8		4		8		3		27
Dry		3		—		—		1		1		2		1		—
		226		246		58		206		201		296		97		217
		234		249		61		234		231		307		102		238
Success ratio (percent)		99		100		100		100		100		99		99		99
Upgrader
Synthetic crude oil sales (mbbls/day)		63.4		64.1		53.1		61.1		58.2		60.7		61.0		41.0
Upgrading differential ($/bbl)		24.27		22.04		22.64		20.38		22.32		29.87		33.09		24.00
Canadian Refined Products
Refined products sales volumes
Light oil products (million litres/day)		9.6		9.9		8.4		9.1		9.4		9.9		8.3		8.4
Asphalt products (mbbls/day)		24.1		34		26.2		20.4		20.1		36.4		20.2		19.9
Refinery throughput
Lloydminster refinery (mbbls/day)		28.3		28.7		29.1		27.2		29.0		28.5		26.2		28.9
Prince George refinery (mbbls/day)		11.4		11.3		10.4		11.1		11.1		7.9		9.1		11.0
Refinery utilization (percent)		97		97		96		93		97		88		85		96
U.S. Refining and Marketing
Refinery throughput
Lima refinery (mbbls/day)		155.9		153.9		150.7		139.4		142.9		136.8		148.6		148.9
BP-Husky Toledo refinery (mbbls/day)		58.1		52.7		64.9		67.3		64.4		60.8		62.6		67.9

⁽¹⁾  Operating netbacks are Husky’s average prices less royalties and operating costs on a per unit basis.

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

⁽³⁾  Includes associated co-products converted to mcfge.

⁽⁴⁾  Includes Western Canada, Heavy Oil and Oil Sands.

Management’s Discussion and Analysis 2012

55

Segmented Capital Expenditures⁽¹⁾

	2012									2011
($ millions)	Q4			Q3		Q2		Q1		Q4		Q3		Q2		Q1
Upstream
Exploration
Western Canada		79			43		29		87		87		19		5		122
Asia Pacific		(28	)		17		—		—		37		79		—		—
Atlantic Region		5			35		6		—		—		2		—		—
		56			95		35		87		124		100		5		122
Development
Western Canada		662			497		293		577		653		472		254		404
Oil Sands		220			152		132		154		81		69		82		35
Asia Pacific		91			175		203		134		226		150		175		47
Atlantic Region		213			150		101		58		61		62		73		62
		1,186			974		729		923		1,021		753		584		548
Acquisitions
Western Canada		—			16		—		5		14		0		18		842
Total Exploration and Production		1,242			1,085		764		1,015		1,159		853		607		1,512
Infrastructure and Marketing		19			14		11		10		14		13		10		6
Total Upstream		1,261			1,099		775		1,025		1,173		866		617		1,518
Downstream
Upgrader		17			13		9		8		20		19		6		10
Canadian Refined Products		33			32		19		13		33		28		18		15
U.S. Refining and Marketing		113			92		65		43		72		68		62		22
		163			137		93		64		125		115		86		47
Corporate		49			16		14		5		34		22		12		3
		1,473			1,252		882		1,094		1,332		1,003		715		1,568

⁽¹⁾  Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the period.

Management’s Discussion and Analysis 2012

56

Segmented Financial Information

	Upstream																								Downstream
	Exploration and Production(1)												Infrastructure and Marketing												Upgrading
2012 ($ millions)	Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
Gross revenues		1,764			1,430			1,382			1,971			796			377			633			614			562			576			472			581
Royalties		(189	)		(145	)		(140	)		(219	)		—			—			—						—			—			—			—
Marketing and other		—			—			—			—			76			120			120			71			—			—			—			—
Revenues, net of royalties		1,575			1,285			1,242			1,752			872			497			753			685			562			576			472			581
Expenses
Purchases of crude oil and products(2)		20			15			13			25			741			335			591			591			417			423			339			447
Production and operating expenses		508			446			431			455			7			16			14			12			40			33			47			40
Selling, general and administrative expenses		21			55			66			36			6			5			6			4			1			—			1			1
Depletion, depreciation, amortization and impairment		614			515			463			529			6			5			6			5			27			25			25			25
Exploration and evaluation expenses		163			59			53			75			—			—			—			—			—			—			—			—
Other – net		(72	)		28			(60	)		(1	)		—			—			1			(1	)		(17	)		—			—			—
Earnings from operating activities		321			167			276			633			112			136			135			74			94			95			60			68
Net foreign exchange gains (losses)		—			—			—			—			—			—			—			—			—			—			—			—
Finance income		—			5			—			—			—			—			—			—			—			—			—			—
Finance expenses		(19	)		(21	)		(19	)		(19	)		—			—			—			—			(2	)		(3	)		(3	)		(3	)
		(19	)		(16	)		(19	)		(19	)		—			—			—			—			(2	)		(3	)		(3	)		(3	)
Earnings (loss) before income taxes		302			151			257			614			112			136			135			74			92			92			57			65
Provisions for (recovery of) income taxes
Current		16			(44	)		(47	)		209			50			54			62			5			(1	)		24			(11	)		19
Deferred		62			85			114			(50	)		(22	)		(19	)		(27	)		13			25			—			26			(2	)
		78			41			67			159			28			35			35			18			24			24			15			17
Net earnings (loss)		224			110			190			455			84			101			100			56			68			68			42			48
Capital expenditures(3)		1,242			1,085			764			1,015			19			14			11			10			17			13			9			8
Total assets		22,753			21,175			20,819			20,548			1,506			1,400			1,143			1,434			1,242			1,271			1,295			1,252

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

⁽²⁾  Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices.

⁽³⁾  Certain hydrogen feedstock costs from production and operating expenses have been reclassified to purchases of crude oil and products in 2012. Prior periods have been reclassified to conform with current period presentation.

Management’s Discussion and Analysis 2012

57

Downstream (continued)																								Corporate and Eliminations(1)												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
	933			1,067			968			880			2,412			2,477			2,657			2,492			(598	)		(596	)		(484	)		(625	)		5,869			5,331			5,628			5,913
	—			—			—			—			—			—			—			—			—			—			—			—			(189	)		(145	)		(140	)		(219	)
	—			—			—			—			—			—			—			—			—			—			—			—			76			120			120			71
	933			1,067			968			880			2,412			2,477			2,657			2,492			(598	)		(596	)		(484	)		(625	)		5,756			5,306			5,608			5,765
	794			849			802			763			2,102			2,021			2,368			2,233			(598	)		(596	)		(484	)		(625	)		3,476			3,047			3,629			3,434
	49			45			50			40			102			91			100			92			(1	)		1			1			3			705			632			643			642
	15			14			15			14			3			4			3			3			63			34			40			41			109			112			131			99
	21			21			21			20			57			52			52			51			13			11			9			7			738			629			576			637
	—			—			—			—			—			—			—			—			—			—			—			—			163			59			53			75
	—			(2	)		—			—			4			—			—			—			(19	)		4			7			5			(104	)		30			(52	)		3
	54			140			80			43			144			309			134			113			(56	)		(50	)		(57	)		(56	)		669			797			628			875
	—			—			—			—			—			—			—			—			(1	)		16			—			(1	)		(1	)		16			—			(1	)
	—			—			—			—			—			—			—			—			21			17			23			27			21			22			23			27
	(1	)		(2	)		(2	)		(1	)		(1	)		(1	)		(2	)		(1	)		(22	)		(28	)		(43	)		(47	)		(45	)		(55	)		(69	)		(71	)
	(1	)		(2	)		(2	)		(1	)		(1	)		(1	)		(2	)		(1	)		(2	)		5			(20	)		(21	)		(25	)		(17	)		(46	)		(45	)
	53			138			78			42			143			308			132			112			(58	)		(45	)		(77	)		(77	)		644			780			582			830
	16			32			23			18			(49	)		48			—			—			29			35			16			32			61			149			43			283
	(2	)		3			(3	)		(7	)		104			65			48			41			(58	)		(29	)		(50	)		(39	)		109			105			108			(44	)
	14			35			20			11			55			113			48			41			(29	)		6			(34	)		(7	)		170			254			151			239
	39			103			58			31			88			195			84			71			(29	)		(51	)		(43	)		(70	)		474			526			431			591
	33			32			19			13			113			92			65			43			49			16			14			5			1,473			1,252			882			1,094
	1,646			1,658			1,656			1,625			5,326			5,160			5,260			5,334			2,667			2,802			2,669			3,093			35,140			33,466			32,842			33,286

Management’s Discussion and Analysis 2012

58

	Upstream																							Downstream
	Exploration and Production												Infrastructure and Marketing											Upgrading
2011 ($ millions)	Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1		Q4			Q3			Q2			Q1
Gross revenues(2)		2,051			1,797			1,920			1,751			619			537			336			495		615			586			648			368
Royalties		(331	)		(247	)		(289	)		(258	)		—			—			—			—		—			—			—			—
Marketing and other		—			—			—			—			32			21			2			35		—			—			—			—
Revenues, net of royalties		1,720			1,550			1,631			1,493			651			558			338			530		615			586			648			368
Expenses
Purchases of crude oil and products(2)		60			11			(12	)		40			579			506			285			448		462			400			474			269
Production and operating expenses		477			429			408			400			3			2			21			17		29			36			46			58
Selling, general and administrative expenses		25			34			51			43			4			4			5			4		7			(1	)		(3	)		—
Depletion, depreciation, amortization and impairment		601			498			483			436			5			7			6			6		25			26			88			25
Exploration and evaluation expenses		194			95			88			93			—			—			—			—		—			—			—			—
Other – net		2			(1	)		(73	)		(189	)		1			—			—			—		24			18			15			10
Earnings from operating activities		361			484			686			670			59			39			21			55		68			107			28			6
Net foreign exchange gains (losses)		—			—			—			—			—			—			—			—		—			—			—			—
Finance income		1			1			1			1			—			—			—			—		—			—			—			—
Finance expenses		(19	)		(16	)		(18	)		(15	)		—			—			—			—		(2	)		(2	)		(1	)		(2	)
		(18	)		(15	)		(17	)		(14	)		—			—			—			—		(2	)		(2	)		(1	)		(2	)
Earnings (loss) before income taxes		343			469			669			656			59			39			21			55		66			105			27			4
Provisions for (recovery of) income taxes
Current		(25	)		9			32			25			18			22			13			11		2			(2	)		(3	)		1
Deferred		115			96			150			154			(3	)		(13	)		(7	)		3		15			29			10			—
		90			105			182			179			15			9			6			14		17			27			7			1
Net earnings (loss)		253			364			487			477			44			30			15			41		49			78			20			3
Capital expenditures(3)		1,159			853			607			1,512			14			13			10			6		20			19			6			10
Total assets		20,141			19,669			18,916			18,708			1,509			1,206			1,353			1,628		1,316			1,266			1,302			1,335

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

⁽²⁾  Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices.

⁽³⁾  Certain hydrogen feedstock costs from production and operating expenses have been reclassified to purchases of crude oil and products in 2012. Prior periods have been reclassified to conform with current period presentation.

Management’s Discussion and Analysis 2012

59

Downstream (continued)																								Corporate and Eliminations(1)												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
	928			1,177			945			827			2,381			2,527			2,600			2,244			(738	)		(566	)		(408	)		(648	)		5,856			6,058			6,041			5,037
	—			—			—			—			—			—			—			—			—			—			—			—			(331	)		(247	)		(289	)		(258	)
	—			—			—			—			—			—			—			—			—			—			—			—			32			21			2			35
	928			1,177			945			827			2,381			2,527			2,600			2,244			(738	)		(566	)		(408	)		(648	)		5,557			5,832			5,754			4,814
	786			974			798			707			2,097			2,239			2,202			1,915			(738	)		(566	)		(408	)		(648	)		3,246			3,564			3,339			2,731
	44			47			49			42			101			108			90			92			—			—			—			—			654			622			614			609
	13			11			12			13			4			2			3			3			55			46			70			23			108			96			138			86
	20			23			19			18			52			48			45			50			13			9			9			7			716			611			650			542
	—			—			—			—			—			—			—			—			—			—			—			—			194			95			88			93
	—			—			—			—			—			—			—			—			(5	)		6			1			(2	)		22			23			(57	)		(181	)
	65			122			67			47			127			130			260			184			(63	)		(61	)		(80	)		(28	)		617			821			982			934
	—			—			—			—			—			—			—			—			(15	)		6			17			2			(15	)		6			17			2
	—			—			—			—			—			—			—			—			25			20			17			20			26			21			18			21
	(2	)		(1	)		(2	)		(1	)		(1	)		(1	)		(1	)		(1	)		(47	)		(50	)		(62	)		(66	)		(71	)		(70	)		(84	)		(85	)
	(2	)		(1	)		(2	)		(1	)		(1	)		(1	)		(1	)		(1	)		(37	)		(24	)		(28	)		(44	)		(60	)		(43	)		(49	)		(62	)
	63			121			65			46			126			129			259			183			(100	)		(85	)		(108	)		(72	)		557			778			933			872
	14			3			4			4			21			55			—			—			123			(28	)		26			29			153			59			72			70
	2			28			12			8			25			(8	)		94			67			(158	)		66			(67	)		(56	)		(4	)		198			192			176
	16			31			16			12			46			47			94			67			(35	)		38			(41	)		(27	)		149			257			264			246
	47			90			49			34			80			82			165			116			(65	)		(123	)		(67	)		(45	)		408			521			669			626
	33			28			18			15			72			68			62			22			34			22			12			3			1,332			1,003			715			1,568
	1,632			1,630			1,625			1,581			5,476			5,459			5,043			5,034			2,352			2,456			1,852			507			32,426			31,686			30,091			28,793

Management’s Discussion and Analysis 2012

60

Exhibit No.	Description
23.1	Consent of KPMG LLP, independent registered public accounting firm.
23.2	Consent of McDaniel and Associates Consultants Ltd., independent engineers.
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.