2013

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

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

For the fiscal year ended December 31, 2013

Commission File Number: 001-04307

Husky Energy Inc.

(Exact name of Registrant as specified in its charter)

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

707-8^th Avenue S.W., 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

(877) 467-3525

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

of agent for service in the United States)

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

Title of Class: None

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

Title of Class: None

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

Title of Class: Common Shares

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

þ  Annual information form þ  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:

983,379,074 Common Shares outstanding as of December 31, 2013

12,000,000 Cumulative Redeemable Preferred Shares, Series 1 outstanding as of December 31, 2013

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.

þ  Yes            ¨  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. 333-191849); Form S-8 File No. (333-187135).

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, 2013 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, 2013 and December 31, 2012, 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, 2013 is included as Document C of this Annual Report on Form 40-F.

Certifications

See Exhibits 31.1, 31.2, 32.1 and 32.2, which are included as Exhibits to this Annual Report on Form 40-F.

Supplemental Reserves Information

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

Disclosure Controls and Procedures

See the section “Disclosure Controls and Procedures” in Husky’s Management’s Discussion and Analysis for the year ended December 31, 2013, 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 audited consolidated financial statements for the year ended December 31, 2013, 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, 2013, 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, 2013, which is included as Document A of this Annual Report on Form 40-F.

Code of Business Conduct and Ethics

Husky’s Code of Ethics is disclosed in its Code of Business Conduct, which is applicable to its principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions and to all of its other employees, and is posted on its website at www.huskyenergy.com. In May 2013, Husky made amendments to its Code of Business Conduct. A description of those amendments is included as Exhibit 99.2 to this Annual Report on Form 40-F. A copy of Husky’s Code of Business Conduct, as amended, is included as Exhibit 99.3 to this Annual Report on Form 40-F. In the fiscal year ended December 31, 2013, Husky has not granted a

waiver, including an implicit waiver, from a provision of its Code of Ethics. 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, 2013, 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, 2013, 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, 2013, 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.

Undertaking and Consent to Service of Process

Undertaking

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

Consent to Service of Process

A Form F-X signed by Husky and its agent for service of process has been filed with the Commission together with Form F-10 (File No. 333-191849) 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 6th day of March, 2014

	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 & Secretary

Document A

Form 40-F

Annual Information Form

For the Year Ended December 31, 2013

Husky Energy Inc.

Annual Information Form

For the Year Ended December 31, 2013

March 6, 2014

TABLE OF CONTENTS

ADVISORIES	1
ABBREVIATIONS AND GLOSSARY OF TERMS	2
EXCHANGE RATE INFORMATION	6
CORPORATE STRUCTURE	6
Husky Energy Inc.	6
Intercorporate Relationships	7
GENERAL DEVELOPMENT OF HUSKY	7
Three-year History of Husky	7
DESCRIPTION OF HUSKY’S BUSINESS	10
General	10
Social and Environmental Policy	10
Upstream Operations	13
Description of Major Properties and Facilities	13
Distribution of Oil and Gas Production	24
Disclosures of Oil and Gas Activities	25
Oil and Gas Reserves Disclosures	33
Infrastructure and Marketing	53
Downstream Operations	57
U.S. Refining and Marketing	57
Upgrading Operations	57
Canadian Refined Products	58
INDUSTRY OVERVIEW	61
RISK FACTORS	67
HUSKY EMPLOYEES	73
DIVIDENDS	73
Dividend Policy and Restrictions	73
Common Share Dividends	73
Series 1 Preferred Share Dividends	73
DESCRIPTION OF CAPITAL STRUCTURE	74
Common Shares	74
Preferred Shares	74
Liquidity Summary	74
MARKET FOR SECURITIES	76
DIRECTORS AND OFFICERS	77
Directors	77
Officers	84
Conflicts of Interest	84
Corporate Cease Trade Orders or Bankruptcies	84
Individual Penalties, Sanctions or Bankruptcies	84
AUDIT COMMITTEE	85
External Auditor Service Fees	85
LEGAL PROCEEDINGS	86
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	86
TRANSFER AGENTS AND REGISTRARS	86
INTERESTS OF EXPERTS	86
ADDITIONAL INFORMATION	87
READER ADVISORIES	88
SCHEDULES
Schedule A – Audit Committee Mandate	92
Schedule B – Reports on Reserve Data by Qualified Reserves Evaluators	96
Schedule C – Report of Management and Directors on Oil and Gas Disclosure	99
Schedule D – Independent Engineer’s Audit Opinion	101

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 2013 Page 1

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
CO2	carbon dioxide
GJ	gigajoule
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
Acronyms
AER	Alberta Energy Regulator
AIF	Annual Information Form
API	American Petroleum Institute
ARO	Asset Retirement Obligations
ASC	Alberta Securities Commission
ASP	Alkaline Surfactant Polymer
CAPP	Canadian Association of Petroleum Producers
CEPA	Canadian Energy Pipeline Association
CHOPS	Cold Heavy Oil Production with Sand
CNOOC	China National Offshore Oil Corporation
CPF	Central Processing Facility
COGEH	Canadian Oil and Gas Evaluation Handbook
CSA	Canadian Securities Administrators
CSS	Cyclic Steam Stimulation
EDGAR	Electronic Data Gathering, Analysis, and Retrieval system
EIA	Energy Information Administration
EL	Exploration licence
EOR	Enhanced Oil Recovery
EPA	Environmental Protection Agency
FASB	Financial Accounting Standards Board
FEED	Front End Engineering Design
FPSO	Floating Production, Storage and Offloading Vessel

AIF 2013 Page 2

HOIMS	Husky Operational Integrity Management System
HSB	Husky Synthetic Blend
IFRS	International Financial Reporting Standards
LARP	Lower Athabasca Regional Plan
MD&A	Management’s Discussion And Analysis
MEG	Monoethylene Glycol
NGL	Natural Gas Liquids
NIT	NOVA Inventory Transfer
NYMEX	New York Mercantile Exchange
OPEC	Organization of Petroleum Exporting Countries
PSC	Production Sharing Contract
SAGD	Steam Assisted Gravity Drainage
SEC	Securities and Exchange Commission of the United States
SEDAR	System for Electronic Document Analysis and Retrieval
WCI	Western Climate Initiative
U.S.	United States
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 a value equivalency at the wellhead.

Abandonment costs

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

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.

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.

Delineation well

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

Development well

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

Diluent

A lighter gravity liquid hydrocarbon, usually condensate or synthetic oil, added to heavy oil 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.

AIF 2013 Page 3

Enhanced oil 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

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, which is a well drilled to extend the limits of a known reservoir, or a stratigraphic test well as those items are defined herein.

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.

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.

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.

Liquefied petroleum gas

Liquefied propanes and butanes, separately or in mixtures.

Medium crude oil

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

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 sands

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

Production Sharing Contract

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

AIF 2013 Page 4

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.

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

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.

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:

Degrees API =	141.5	-131.5
	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

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

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.

Three-dimensional seismic survey

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

Turnaround

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

AIF 2013 Page 5

Two-dimensional seismic survey

A vertical section of seismic data consisting of numerous adjacent traces acquired sequentially.

Waterflood

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

Wellhead

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

Working interest

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. $)	2013		2012		2011
Year-end		1.064		0.995		1.017
Low		0.982		0.964		0.941
High		1.074		1.044		1.066
Average		1.03		0.999		0.989

⁽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 at the last day of the relevant period.

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 11, 2011 to create Cumulative Redeemable Preferred Shares, Series 1 (the “Series 1 Preferred Shares”) and Cumulative Redeemable Preferred Shares, Series 2 (the “Series 2 Preferred Shares”).

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.

AIF 2013 Page 6

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, 2013.⁽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
Husky Energy International Corporation	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

2011

On February 28, 2011, Husky announced that its shareholders voted in favour of an amendment to the Company’s Articles, which allowed Husky’s Board of Directors to declare, and 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 29, 2011, Husky completed a $1 billion public offering and a $200 million private placement to its then principal shareholders, L.F. Management and Investment S.à r.l (formerly L.F. Investments (Barbados) Limited) and Hutchison Whampoa Luxembourg Holdings S.à r.l. The Company issued approximately 37 million common shares at $27.05 per share pursuant to the public offering and approximately 7 million common shares at a price of $27.05 per share pursuant to 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. Production from the field will supply the Guangdong Province natural gas grid from an onshore gas plant at Gaolan Island, Zhuahai.

AIF 2013 Page 7

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. The amount paid to note holders was equivalent to $410 million in Canadian dollars.

On December 14, 2012, Husky 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. 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.

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 in Canada up to and including January 30, 2015. As of December 31, 2013, 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 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 production ramped up to a combined average of 17,000 bbls/day exceeding the combined 11,500 bbls/day design rates. The Company advanced construction on the 3,500 bbls/day Sandall thermal development project and commenced initial drilling. Design and initial site work continued at the 10,000 bbls/day Rush Lake commercial project. Initial planning continued for three additional commercial thermal projects.

The Overall Development Plan for the Liwan Gas Project on Block 29/26 in the South China Sea was approved by the Government of China. The development project was more than 80% complete at the end of 2012. Approximately 90 kilometers of the two 79-kilometer deep water pipelines connecting the gas field to the central platform had been laid and approximately 190 kilometers out of 261 kilometers of shallow water pipeline had 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.

Planning continued for the development of the single well Liuhua 34-2 field, which is to be tied into the Liwan 3-1 field deep water facilities. FEED for the development of the Liuhua 29-1 gas field was completed.

In December 2012, Husky signed a joint venture agreement 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 2012, with four new discoveries being made as a result of a five well exploration drilling program.

Husky and BP continued to advance the development of the Sunrise Energy Project in multiple stages. During 2012, drilling of the planned steam assisted gravity drainage (“SAGD”) horizontal well pairs for Phase I was completed and site construction and equipment installations were advanced. 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”). Development work continued on the next phase of the project, where regulatory approvals are in place for a total 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, 10 water injectors, and three gas injectors were on production. A development plan amendment was filed with the regulator in October 2012 to facilitate development of resources at the South White Rose Extension satellite. 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 online. An application to develop the deeper Hibernia formation at North

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Amethyst progressed 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.

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.

2013

During February 2013, the limit on the $1.5 billion revolving syndicated credit facility, allowing the Company to borrow in either Canadian or U.S. currency on an unsecured basis, was increased to $1.6 billion. There was no change to the maturity date of the facility. There continues to be no differences between the terms of the Company’s revolving syndicated credit facilities other than their maturity dates.

At the Liwan Gas Project, drilling and completion work continued in 2013, with all nine wells on the Liwan 3-1 gas field completed and ready for production. During May 2013, the platform topsides were completed and transported approximately 2,500 kilometers from Qingdao, China, to the South China Sea and successfully installed onto the jacket. In addition, the 261 kilometers of shallow water pipeline from the central platform to the gas plant and construction of the onshore gas plant was completed. Five major construction vessels and their support vessels were in operation during 2013, while construction continued on the deep water facilities. Despite encountering unusually difficult weather conditions during an extended typhoon season in late 2013, all piping to connect the individual wells to the manifolds and the manifolds to the connecting infield production flow lines was installed. Final testing and commissioning of the gas plant and offshore infrastructure is now underway. First production is expected in the latter part of the first quarter of 2014.

The single development well of the Liuhua 34-2 field is expected to be tied into the Liwan 3-1 field deep water facilities, with production expected later in the second half of 2014. Production from the Liwan Gas Project is scheduled to go off-line in the second half of 2014 for approximately six to eight weeks to tie in the Liuhua 34-2 field.

On June 5, 2013, Husky received regulatory approval for a development plan amendment for the South White Rose field, the third satellite extension at the White Rose field in the Atlantic Region. The amendment provided for gas injection, which will enhance oil production and provide additional storage for recovered gas. Installation of gas injection equipment to support the South White Rose Extension was completed at the end of 2013, with gas injection commencing in early 2014. Installation of oil production equipment is scheduled in 2014, with first oil anticipated by the end of 2014.

On October 31, 2013 and November 1, 2013, Husky filed a universal short form base shelf prospectus (the “Shelf Prospectus”) with the Alberta Securities Commission and the SEC, respectively, that enables the Company to offer up to U.S. $3.0 billion of debt securities, common shares, preferred shares, subscription receipts, warrants and units of the Company in the United States up to and including November 30, 2015. As of December 31, 2013, the Company had not issued securities under the Shelf Prospectus. This Shelf Prospectus replaced the shelf prospectus which was filed in June 2011 and expired in July 2013.

Husky and its partner made two significant discoveries in the year of a high-quality, light, sweet crude oil resource in the Flemish Pass Basin. The first discovery was made at the Harpoon O-85 well followed by a second discovery made at the Bay Du Nord prospect, both located approximately 500 kilometres offshore Newfoundland. The evaluation of well results at the Harpoon discovery is ongoing, with further appraisal drilling required to assess the potential of the prospect. The evaluation of well results at the Bay Du Nord prospect has confirmed significant quantities of hydrocarbons with best estimate contingent resources estimated by Husky at 400 million barrels on a 100% working interest basis as at December 31, 2013. The two discoveries made in the year brings the total number of significant discoveries in the region to three. The 2009 Mizzen discovery of slightly heavier oil with best estimate contingent resources estimated by Husky at 130 million barrels on a 100% working interest basis as at December 31, 2013. Husky holds a 35% working interest in all three wells.

For the West White Rose Extension Project, Husky and its joint venture partners concluded a benefits agreement with the Government of Newfoundland and Labrador for the project and a Development Application to the Canada-Newfoundland and Labrador Offshore Petroleum Board was submitted. Construction of a graving dock commenced in Argentia, Newfoundland and detailed engineering and design in advance of a final investment decision is ongoing.

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The North Amethyst G-25-9 multilateral well was completed and brought online in late November, with average gross production of 20,000 bbls/day (14,000 bbls/day net to Husky). In addition, drilling commenced on the North Amethyst Hibernia well in the fourth quarter of 2013, targeting a secondary deeper zone below the main North Amethyst field.

At the 60,000 bbls/day (30,000 bbls/day net to Husky) Sunrise Energy Project, the CPF was more than 75% complete at December 31, 2013 with major equipment installed and field tanks and buildings for Plant 1A in place. Commissioning of the first six well pads commenced in 2013, with the remaining two well pads expected to be turned over for commissioning in the first quarter of 2014. Start up for Phase I of the project is expected in the second half of 2014.

At December 31, 2013, construction was substantially complete at the 3,500 bbls/day Sandall heavy oil thermal development project, and steaming was underway with first oil achieved in the first quarter of 2014.

In 2013, construction work continued at the 10,000 bbls/day Rush Lake commercial project with first production expected in the second half of 2015.

In 2013, the liquids-rich natural gas formations at Ansell in west central Alberta continued to be a key area of focus with 25 wells (gross) drilled and 30 wells (gross) completed. At December 31, 2013, the Company had drilled and completed over 300 (gross) wells at the play, which had an average production of 13,800 boe/day in 2013.

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.

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, the 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 China, offshore Indonesia and offshore Taiwan.

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).

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 factors while maintaining growth. Husky strives to find solutions to 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. HOIMS is a systematic approach to anticipating, identifying and mitigating hazardous situations within the Company’s operations. The implementation of HOIMS has produced tangible business results, including improved performance, fewer incidents and enhanced business value. It incorporates best practices from across the industry, consistent with Husky’s commitment to excellence in operational integrity. HOIMS includes 14 fundamental elements; each element contains well defined

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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.

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 equivalent units per annum. The Lloydminster Upgrader, Lloydminster Refinery, Prince George Refinery, SeaRose FPSO, Sierra compressor station, Ram River gas plant, Rainbow Lake gas plant, Tucker thermal oil plant,

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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 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 alkaline surfactant polymer (“ASP”) to increase water efficiency in enhanced oil recovery (“EOR”). 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 3,100 well sites and facilities. In 2013, Husky spent approximately $142 million on ARO, and the Company expects to spend approximately $200 million in 2014 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 Company’s 2013 audited consolidated financial statements.

At December 31, 2013, Husky had 503 retail locations in its light refined products operations, which consisted of 348 Husky controlled, owned or leased locations and 155 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 legacy 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 NGL (Exploration and Production) and marketing of the Company’s and other producers’ crude oil, natural gas, NGL, sulphur and petroleum coke, pipeline transportation, the blending of crude oil, and natural gas, and storage of crude oil, diluent and natural gas (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

Liwan Gas Project

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

Husky executed a PSC with CNOOC for Block 29/26 on October 1, 2004. The block is located in the Pearl River Mouth Basin of the South China Sea, approximately 300 kilometers southeast of the Hong Kong Special Administrative Region.

In 2006, Husky substantially completed 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.

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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 the Hong Kong Special Administrative Region 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 and 2013, Husky completed the deep water development of the Liwan 3-1 field. During the same period, CNOOC completed the shallow water development of the Liwan 3-1 field, which comprises the central platform standing in approximately 120 meters of water. Husky was responsible for the installation of the approximately 850 tonne Monoethylene Glycol (“MEG”) Recovery Unit onto the topside of the central platform which pumps MEG to the field to suppress hydrate formation and then recovers the MEG from the production gas as it is being processed through the central platform. The CNOOC-operated shallow water development also includes 261 kilometer 30 inch diameter pipeline running from the central platform to the onshore Gaolan Gas Plant. The gas plant includes liquids separation facilities, ten spherical NGL storage tanks, an export jetty, control facilities, as well as administrative and accommodation buildings.

Also in 2013, a gas sales agreement was executed with CNOOC Gas & Power Group, Guangdong Branch, for the natural gas volumes from the Liuhua 34-2 field. Development of the single production well Liuhua 34-2 field to be tied into the deep water facilities of the Liwan 3-1 field is planned for 2014 and production is expected to commence later in the second half of 2014. FEED for the development of the Liuhua 29-1 gas field has now been completed, and the Overall Development Plan is being prepared. Negotiations for the sale of the gas from the Liuhua 29-1 field are ongoing.

Wenchang

The Wenchang field is located in the western Pearl River Mouth Basin, approximately 400 kilometers south of the Hong Kong Special Administrative Region and 100 kilometers east of Hainan Island. Husky holds a 40% working interest in two oil fields, which commenced production in July 2002, and the PSC is due to expire in 2017. The Wenchang 13-1 and 13-2 oil fields are currently producing from 32 wells in 100 meters of water into an FPSO 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 7.3 mbbls/day during 2013.

Taiwan

In December 2012, Husky signed a joint venture agreement 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 seismic surveys within the first two years, with options to carry out three-dimensional seismic surveys and to drill at least one exploration well in subsequent exploration periods.

In 2013, Husky completed approximately two-thirds of the minimum two-dimensional (“2-D”) seismic survey obligation and is processing the survey data. Completion of the remainder of the 2-D seismic survey is planned for 2014.

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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.

In 2011, CNOOC drilled an appraisal well that 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. The gas sales contracts for the BD field previously signed in 2010 with three gas buyers were amended in 2011. In November 2012, the functions of BP Migas, the then Indonesian oil and gas regulator, were temporarily transferred to the Energy and Mineral Resources Ministry and subsequently, a new body, SKK Migas, was established as the new industry regulator. As discussed and agreed with the new regulator, a re-tender for the BD field FPSO commenced.

In 2012, the exploration drilling program resulted in discoveries on the MAC, MAX, MDK and MBJ fields. The fields are being evaluated for commercial development potential.

In January 2013, the Plan of Development for a combined MDA and MBH development project was approved by SKK Migas. In July, the BD field engineering, procurement, installation and commissioning contract was awarded and engineering/construction work under the contract commenced. The evaluation of the BD field FPSO re-tender was completed by the operator and their recommendation for contract award is under final review by the Government of Indonesia. In addition, the tender plan for the combined MDA and MBH development project is under review by Indonesia’s regulatory authority for approval. The Government of Indonesia appointed a lead distributor for the major portion of the gas from the MDA and MBH fields and a Heads of Agreement has been reached. Negotiations for a gas sales contract are in progress. Exploration drilling on the block in 2013 resulted in an additional discovery named the MBF field.

First gas from the Madura Strait Block is anticipated in late 2016 - early 2017.

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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 kilometres east of the Madura Strait block and covers an area of 937,300 acres (3,793 square kilometres). 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. Husky satisfied its seismic work commitment by acquiring 1,020 kilometres of 2-D seismic data in December 2009. Husky has used this data to identify a potential exploration prospect. Husky requested and has received extensions to fulfill its commitment by November 2014.

Atlantic Region

Husky’s offshore East Coast exploration and development program is focused in the Jeanne d’Arc Basin on the Grand Banks, which contains the Hibernia and Terra Nova fields, the White Rose field and satellite extensions, which include the North Amethyst, West White Rose and the South White Rose Extensions, and the Flemish Pass Basin offshore Newfoundland, which contains the Mizzen, Bay du Nord and Harpoon discoveries. Husky is the operator of the White Rose field and satellite extensions, and holds an ownership interest in the Terra Nova field as well as in a number of smaller undeveloped fields. Husky also holds significant exploration acreage offshore Newfoundland and a portfolio of exploration licences (“ELs”) offshore Greenland.

White Rose Oil Field

The White Rose oil field is located 354 kilometers off the coast of Newfoundland 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 68.875% working interest in the satellite fields.

First oil was achieved at White Rose in November 2005. The White Rose field was the third oil field developed offshore Newfoundland and currently has nine production wells, 10 water injectors, and three gas injectors. Husky continues to look at ways for EOR from the core field, and during 2012 drilled an infill production well at White Rose. During 2013, Husky’s production from the White Rose field was 8.7 million barrels (24,000 bbls/day).

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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. Production flows from North Amethyst to the SeaRose FPSO through a series of subsea flow lines. During 2013, Husky’s production from North Amethyst was 8.3 million barrels (22,700 bbls/day). A multilateral production well was completed and brought online in November 2013. As of December 31, 2013, the field had five production wells and four water injection wells, which completes the base plan for the field. In October 2013, Husky received regulatory approval to develop a second, deeper formation at North Amethyst utilizing existing infrastructure, and drilling of a production well targeting the Hibernia layer formation commenced in December 2013. A supporting water injector is already in place.

Initial production from West White Rose was achieved in September 2011 through a two-well pilot project. These wells have helped provide further information on the reservoir to refine development plans for the full West White Rose field. Husky’s share of production from this satellite field was 3.3 million barrels (9,000 bbls/day) during 2013. Husky and its partners have confirmed the wellhead platform concept as the preferred option for full field development of West White Rose.

During 2013, a number of key milestones were met for the West White Rose Extension Project including the approval of a benefits agreement with the Government of Newfoundland and Labrador, the release of the environmental impact assessment for further federal and provincial approval, and the submission of the Development Application to the Canada-Newfoundland and Labrador Offshore Petroleum Board.

The White Rose Extension Project will utilize a wellhead platform consisting of a concrete gravity structure and drilling topsides. Reservoir fluids and production will continue to be handled by the SeaRose FPSO. Fabrication of a graving dock to support the project commenced in October 2013, as detailed facility engineering and design progressed in advance of a final investment decision. First production is anticipated in 2017.

Husky is developing the South White Rose Extension in two phases, with gas injection commencing in the first quarter of 2014, followed by oil production later in the year. Regulatory approval for an amended development plan was granted in June 2013. Equipment to support gas injection was installed in the summer of 2013. Oil production equipment is being fabricated for installation in the summer of 2014.

Terra Nova Oil Field

The Terra Nova oil field is located approximately 350 kilometers southeast of St. John’s, Newfoundland in 91 to 100 metres of water. 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 gross production in 2013 from the Terra Nova field was 1.79 million barrels (4,910 bbls/day). Production at Terra Nova was impacted by an extended 10-week maintenance program to facilitate repairs to the FPSO mooring chains. Production from the field resumed on December 6, 2013.

As at December 31, 2013, there were 14 development wells drilled in the Graben area, consisting of eight production wells, three water injection wells and three gas injection wells. In the East Flank area there were 13 development wells, consisting of eight 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 2014 on both new and existing development wells.

East Coast Exploration

Husky believes that the Atlantic Region has exploration potential, and that the Company’s position there 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 5.8% to 73.125% in 23 significant discovery areas in the Jeanne d’Arc Basin, Flemish Pass Basin, offshore Labrador and Baffin Island. Husky and its partner made two additional oil discoveries in the Flemish Pass Basin, at Harpoon and Bay du Nord in 2013.

The evaluation of well results at Bay du Nord have confirmed significant quantities of hydrocarbons with best estimate contingent resources estimated by Husky at 400 million barrels on a 100% working interest basis as at December 31, 2013. The Bay du Nord prospect is south of the Mizzen discovery and west of the Harpoon discovery made in 2013. In addition, the evaluation of well results at the Harpoon discovery is ongoing with further appraisal drilling required to assess the potential of the prospect. Mizzen, discovered in 2009, holds best estimate contingent resources estimated by Husky at 130 million barrels on a 100% working interest basis as at December 31, 2013. Husky holds a 35% working interest in all three wells. Husky and its partner continue to assess the recent

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discoveries at the Bay Du Nord and Harpoon prospects in the Flemish Pass Basin offshore Newfoundland, and will work to identify ways to accelerate development in the region. The companies have announced a seismic survey for spring of 2014 and an 18-month exploration and delineation drilling program. A rig has been secured and is expected to begin operations offshore Newfoundland in fall of 2014.

Husky also announced a hydrocarbon discovery at the White Rose H-70 well northwest of the main White Rose field. An analysis of the results is continuing. The well was drilled as part of Husky’s ongoing strategy of near-field delineation in the White Rose area.

Husky participated in the non-operated Federation well in the second quarter of 2013. The well did not encounter commercial hydrocarbons and has been expensed.

The Company also intends to participate in additional exploration and delineation wells during 2014, including in the southern Flemish Pass Basin and the Jeanne d’Arc Basin.

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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.

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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 is comprised of a 50/50 partnership to develop the Sunrise Energy Project, operated by Husky, and a 50/50 limited liability company for the BP-Husky Toledo Refinery, operated by BP.

The Sunrise Energy Project, which is an in-situ SAGD oil sands project located in the Athabasca region of northern Alberta, was approved by the Alberta Energy Regulator (“AER”) and formerly the Energy Resources Conservation Board) 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 AER were received in January 2009 and approval from Alberta Environment was received in the first quarter of 2009. A second amendment to optimize the CPF design was filed with the regulators in July 2009 and approval was received from both the AER and Alberta Environment in December 2009.

FEED for Phase I of the Sunrise Energy Project 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.

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Phase I of Sunrise Energy Project was approximately 85% complete as at December 31, 2013. Major equipment was installed to the CPF, and field tanks and buildings for Plant 1A are now in place. In addition, all modules have been delivered and major equipment installation has been completed for Plant 1B. Field facilities are substantially complete. The main power line to the plant is now energized and the testing of piping and the completion of remaining electrical and instrumentation work is being completed in advance of the planned systems turn over. Six of the eight well pads had been turned over for commissioning as at December 31, 2013. The remaining two well pads are targeted to be turned over in the first quarter of 2014. As of December 31, 2013, approximately 90% of the project’s total cost estimate had been spent. Start up for Phase I is planned for the second half of 2014.

Early engineering is underway for the next phase of the Sunrise Energy Project.

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 has expanded the project through the development of the overlying Lower Grand Rapids formation with an initial six well pairs. Production at Tucker in 2013 was 10.4 mbbls/day. Several applications to the AER 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 May 2013, Husky submitted an application for a 3,000 bbls/day bitumen carbonate pilot project at Saleski located north of Wabasca, Alberta. Supplemental information requests were received from the Alberta Energy Regulator and responses were submitted in December 2013. Core work, geo-modeling and simulation models were advanced.

The Company continued its analysis of several other oil sands assets during 2013. It has initiated additional delineation and resource characterization programs for McMullen, Cadotte North and Caribou.

Heavy Oil

Lloydminster Heavy Oil and Gas

The majority of Husky’s heavy oil assets are located in the Lloydminster region of Alberta and Saskatchewan, with lands consisting of approximately two million acres. This extensive land position spans most of the productive oil fields in the area, all within 100 kilometers of the City of Lloydminster. The Company operates over 4,500 wells in the area, with a 100% working interest in the majority of these wells. Husky’s operations are supported by a network of Husky owned oil treating facilities and pipelines that 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, providing full integration with the Company’s Infrastructure and Marketing and Downstream businesses.

Production of heavy oil from the Lloydminster area uses a variety of techniques, including primary production methods, horizontal well technology, CSS and SAGD. Husky’s gross heavy and medium crude oil production from the area averaged 97.9 mbbls/day in 2013. Of the total crude oil produced, 58.1 mbbls/day was primary production of heavy crude oil, using CHOPS and horizontal technologies, 37.9 mbbls/day was from Husky’s thermal operations and 1.9 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 2013, Husky’s gross natural gas production from the Lloydminster region averaged 19.6 mmcf/day.

Construction was substantially complete at the 3,500 bbls/day Sandall thermal development project at December 31, 2013. Production commenced in the first quarter of 2014.

Design and construction is continuing at the 10,000 bbls/day Rush Lake commercial project with first production expected in the second half of 2015. Production performance from the two well pair pilot is in line with expectations. Initial planning is ongoing for three additional commercial thermal projects.

AIF 2013 Page 21

Two 10,000 bbls/day thermal developments were sanctioned in the fourth quarter of 2013 at Edam East and Vawn in Saskatchewan. Construction is scheduled to begin in 2014, and these projects are expected to deliver a total of 20,000 bbls/day of production. First production is expected in 2016.

The Company advanced its horizontal drilling program in 2013 with the completion of 140 wells. Based on the positive performance of previous horizontal drilling programs, Husky is continuing this program and is planning to drill approximately 144 wells in 2014, and continuing to implement waterflooding in selected pools. The Company also drilled 228 gross CHOPS wells during 2013. In 2014, 177 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 and grow heavy crude oil production in the Lloydminster area.

Non-Thermal Enhanced Oil Recovery

Husky operated five solvent EOR pilot programs in 2013 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)

Northwest

Western Canada northwest conventional development operations are located primarily in north and central Alberta from the foothills in western Alberta to Slave Lake and Grande Prairie in northern Alberta. Husky operates 85 facilities in the area. Production for 2013 from northwest operations averaged 63 mboe/day. Production consisted of 268 mmcf/day of natural gas and 18 mbbls/day of oil and NGL.

The area is heavily weighted to natural gas production, approximately 70%, with the highest production coming from the Rocky Mountain House district totalling approximately 115 mmcf/day in 2013. Husky is pursuing liquids-rich natural gas and crude oil development opportunities within the existing asset portfolio with major oil developments at McMullen and Wapiti along with an emerging liquids-rich gas play in the Strachan area.

The conventional crude oil development primarily centers around heavy oil at McMullen which is located approximately 40 kilometers southwest of Wabasca, Alberta. The McMullen development is currently producing approximately 5 mboe/day. Development plans for 2014 include drilling 40 conventional wells to continue to increase production.

In addition to the primary development at McMullen, Husky continued with its air injection pilot in 2013 with an expansion of the pilot from one to four production wells increasing production to approximately 600 bbls/day. Three additional wells were put on production in the third quarter of 2013.

The Company continued to develop an unconventional Cardium oil play in the Wapiti area south of the city of Grand Prairie, Alberta utilizing horizontal well and multi-stage fracturing technology to unlock crude oil reserves in the Cardium zone. The 2013 drilling program was expanded to 13 wells and a 10 well drilling program is planned for 2014.

Southeast

Husky’s Western Canada southeast conventional development operations are located primarily in southern Alberta and southern Saskatchewan. Husky operates 68 crude oil and 27 gas facilities in the area. Production in 2013 from these operations averaged 69 mmcf/day of natural gas and 36 mbbls/day of crude 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 37 Viking wells in 2014, primarily at Elrose, located approximately 150 kilometers southwest of Saskatoon, Saskatchewan, and to expand into the Alliance area, located approximately 200 kilometers southeast of Edmonton, Alberta. The Company currently has approximately 100 wells producing from the plays and intends to continue to develop and optimize infrastructure in all areas.

Husky applies the ASP EOR process at Warner in southern Alberta and at Gull Lake and Fosterton in southern Saskatchewan. In addition, Husky holds a 20.3% non-operating working interest in the Instow, Saskatchewan ASP flood. Production in December 2013 for this ASP EOR program was approximately 3.9 mbbls/day.

AIF 2013 Page 22

Development of the Bakken and Torquay formations continued in southeast Saskatchewan with 14 wells drilled and 13 wells put on production. The tank treating facility capacity was upgraded to handle solution gas. Production and evaluation of the Lower Shaunavon formation in southwest Saskatchewan continued with nine wells drilled and seven wells put on production and the two remaining wells are undergoing completion and tie-in. Production from these two plays was 2.4 mbbls/day in December 2013.

Conventional oil development in southern Alberta will focus on the Lithic Glauconitic and Ellerslie channel sands and several locations in the Taber/Hussar area. A plan is in place to drill approximately 25 vertical delineation wells and 16 horizontal multi-stage fracturing wells.

Rainbow Development

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 2013 from the Rainbow Lake district averaged 10.1 mbbls/day of light crude oil and NGL and 89.5 mmcf/day of natural gas. In addition to operating and continuing development of these assets, Husky has continued exploration activities within the Muskwa resource play in which Husky holds a 100% working interest and a total of 10 horizontal wells were drilled in 2013.

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, or steam, for the Rainbow Lake processing plant. Results from this joint venture are included in Upstream Exploration and Production.

AIF 2013 Page 23

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 is 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, see “Commodity Marketing”.

Natural Gas

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

	Years Ended December 31,
	2013		2012			2011
				(mmcf/day	)
Sales Distribution
United States		141		154			163
Canada		198		242			297
		339		396			460
Sales to Aggregators		2		4			3
Internal Use (1)		172		154			144
		513		554			607

⁽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
2014		11.6		4.25
2015		3.8		4.34
2016		—		—

AIF 2013 Page 24

Disclosures of Oil and Gas Activities

Production History

	Year Ended		Three Months Ended
Average Gross Daily Production	Dec 31, 2013		Dec 31, 2013		Sept 30, 2013		June 30, 2013		Mar 31, 2013
Canada—Western Canada
Light Crude Oil and NGL (mbbls/day)		29.7		30.2		29.2		28.6		30.7
Medium Crude Oil (mbbls/day)		23.2		23.4		23.2		22.9		23.0
Heavy Crude Oil (mbbls/day)		74.5		75.9		75.3		72.3		74.4
Bitumen (mbbls/day)		47.7		46.7		48.0		48.3		47.9
Natural Gas (mmcf/day)		512.7		503.8		505.5		504.7		537.3
Canada—Atlantic Region
Light Crude Oil (mbbls/day)		44.1		40.8		41.7		46.1		47.9
China
Light Crude Oil and NGL (mbbls/day)		7.3		7.3		6.8		7.6		7.8
Total Gross Production (mboe/day)		312.0		308.3		308.5		309.9		321.3
	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

AIF 2013 Page 25

Netback Analysis

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

	Year Ended			Three Months Ended
Average Per Unit Amounts	Dec 31, 2013			Dec 31, 2013			Sept 30, 2013			June 30, 2013		Mar 31, 2013
Light Crude Oil and NGL ($/bbl)
Canada—Western Canada
Price Received	$	82.73		$	78.42		$	91.80		$	80.54	$	80.33
Royalties	$	12.87		$	12.57		$	10.94		$	13.96	$	14.00
Production Costs	$	23.63		$	21.59		$	26.84		$	23.87	$	22.54
Netback	$	46.23		$	44.26		$	54.02		$	42.71	$	43.79
Canada—Atlantic Canada
Price Received	$	114.60		$	117.87		$	117.84		$	106.28	$	116.93
Royalties	$	14.65		$	15.98		$	14.23		$	12.92	$	15.50
Production Costs	$	12.47		$	15.19		$	13.31		$	12.16	$	9.98
Transportation Costs (1)	$	2.62		$	2.80		$	3.16		$	2.54	$	2.08
Netback	$	84.86		$	83.90		$	87.14		$	78.66	$	89.37
Canada—Total
Price Received (1)	$	100.22		$	99.50		$	105.26		$	94.86	$	101.40
Royalties	$	13.93		$	14.54		$	12.88		$	13.33	$	14.93
Production Costs	$	16.96		$	17.91		$	18.88		$	16.64	$	15.03
Netback	$	69.33		$	67.05		$	73.50		$	64.89	$	71.44
China
Price Received	$	107.95		$	110.17		$	115.30		$	94.26	$	112.95
Royalties	$	26.23		$	26.19		$	27.98		$	21.46	$	29.52
Production Costs	$	11.39		$	13.63		$	12.72		$	10.28	$	9.97
Netback	$	70.33		$	70.35		$	74.60		$	62.52	$	73.46
Company Total
Price Received (1)	$	100.87		$	100.49		$	106.13		$	94.80	$	102.43
Royalties	$	15.00		$	15.62		$	14.19		$	14.08	$	16.22
Production Costs	$	16.45		$	17.51		$	18.34		$	16.05	$	14.44
Netback	$	69.42		$	67.36		$	73.60		$	64.67	$	71.77
Medium Crude Oil ($/bbl)
Canada—Western Canada
Price Received	$	76.31		$	67.86		$	93.67		$	73.62	$	61.74
Royalties	$	14.25		$	11.06		$	16.23		$	10.80	$	10.78
Production Costs	$	20.53		$	20.23		$	23.45		$	24.09	$	22.19
Netback	$	41.53		$	36.57		$	53.99		$	38.73	$	28.77
Heavy Crude Oil ($/bbl)
Canada—Western Canada
Price Received	$	63.44		$	56.51		$	84.45		$	66.77	$	45.67
Royalties	$	8.20		$	7.69		$	10.93		$	8.06	$	6.03
Production Costs	$	20.63		$	20.16		$	21.82		$	20.73	$	20.15
Netback	$	34.61		$	28.66		$	51.70		$	37.98	$	19.49
Bitumen ($/bbl)
Canada—Western Canada
Price Received	$	61.68		$	54.08		$	83.17		$	65.71	$	43.12
Royalties	$	5.37		$	6.63		$	6.64		$	4.94	$	3.25
Production Costs	$	12.39		$	12.80		$	11.83		$	13.61	$	11.61
Netback	$	43.92		$	34.65		$	64.70		$	47.16	$	28.26
Natural Gas ($/mcf)
Canada—Western Canada (2)
Price Received	$	3.19		$	3.30		$	2.66		$	3.72	$	3.08
Royalties	($	0.01	)	($	0.08	)	($	0.09	)	$	0.11	$	0.02
Production Costs	$	2.14		$	2.09		$	2.25		$	2.30	$	2.02
Netback	$	1.06		$	1.29		$	0.50		$	1.31	$	1.04

⁽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 2013 Page 26

	Year Ended			Three Months Ended
Average Per Unit Amounts	Dec 31, 2012			Dec 31, 2012		Sept 30, 2012			June 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		$	7.83
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 2013 Page 27

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

Producing Wells

	Oil Wells				Natural Gas Wells				Total
	Gross		Net		Gross		Net		Gross		Net
Canada
Alberta		4,236		3,475		5,445		3,968		9,681		7,443
Saskatchewan		6,683		5,744		1,374		1,249		8,057		6,993
British Columbia		198		56		304		266		502		322
Newfoundland		21		6		—		—		21		6
		11,138		9,281		7,123		5,483		18,261		14,764
International
China		29		11		—		—		29		11
Libya		3		1		—		—		3		1
		32		12		—		—		32		12
As at December 31, 2013		11,170		9,293		7,123		5,483		18,293		14,776
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

Non-Producing Wells

	2013
	Oil Wells				Natural Gas Wells				Total
	Gross		Net		Gross		Net		Gross		Net
Canada		5,886		5,252		1,878		1551		7,764		6,803

⁽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, 2013.

⁽²⁾ The above table does not include producing wells in which Husky has no working interest but does have a royalty interest. At December 31, 2013, Husky had a royalty interest in 4,152 wells, of which 1,422 were oil producers and 2,730 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 2013, there were 1,339 gross and 1,199 net oil wells and 670 gross and 524 net natural gas wells that were completed in two or more formations and from which production is not commingled.

AIF 2013 Page 28

Landholdings—Developed Acreage

(thousands of acres)	Gross		Net
As at December 31, 2013
Western Canada
Alberta		4,554		2,917
Saskatchewan		818		648
British Columbia		187		146
Manitoba		3		—
		5,562		3,711
Atlantic Region		57		20
		5,619		3,731
China		17		7
Libya		7		2
Total		5,643		3,740
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

AIF 2013 Page 29

Landholdings—Undeveloped Acreage

(thousands of acres)	Gross		Net
As at December 31, 2013
Western Canada
Alberta		4,694		3,422
Saskatchewan		1,567		1,403
British Columbia		826		634
Manitoba		3		1
		7,090		5,460
Northwest Territories and Arctic		483		466
Atlantic Region		5,500		3,269
		13,073		9,195
United States		110		74
China		56		27
Indonesia		1,559		937
Greenland		8,471		5,983
Taiwan		2,545		1,909
Total		25,814		18,125
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
Total		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		6,186
Northwest Territories and Arctic		1,156		633
Atlantic Region		5,548		3,339
		14,751		10,158
United States		1,076		398
China		990		484
Indonesia		1,628		1,213
Greenland		8,471		5,983
Total		26,916		18,236

AIF 2013 Page 30

Significant Factors or Uncertainties Relevant to Properties with No Attributed Reserves

The Company does not have any material work commitments associated with its undeveloped land.

Approximately 431,419 acres, or less than 3% of the Company’s net undeveloped landholdings in Canada, will be subject to expiry in 2014.

Husky holds interests in a diverse portfolio of undeveloped petroleum assets in Western Canada, the Atlantic Region, offshore Greenland, China, Taiwan and Indonesia, the United States, the Canadian Northwest Territories and the 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—Number of Wells Drilled

	Year Ended December 31,
	2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net
Canada—Western Canada
Exploration
Oil		39		24		47		30		50		40
Gas		19		14		19		12		24		24
Dry		—		—		—		—		3		3
		58		38		66		42		77		67
Development
Oil		768		709		775		715		880		765
Gas		68		41		23		17		57		42
Dry		1		—		5		4		4		4
		837		750		803		736		941		811
		895		788		869		778		1,018		878
Canada—Atlantic Region
Development
Oil		2		1.1		2		1.4		3		2.1
China
Development
Oil		3		1.2		—		—		1		0.4
Gas		—		—		—		—		4		2.0
		3		1.2		—		—		5		2.4

Service/Stratigraphic Test Wells

	2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net
Canada - Western Canada		130		106		116		95		211		189
Canada - Atlantic Region		8		3.9		2		1.7		2		0.9
China		—		—		—		—		1		6.8
Indonesia		2		0.9		5		2		—		—

AIF 2013 Page 31

Current Activities

	Exploratory				Development
Wells Drilling (1)	Gross		Net		Gross		Net
Canada – Western Canada		5		5		33		32.1
Canada—Atlantic Region		—		—		1		0.7
China		—		—		—		—

Service/Stratigraphic Test Wells (1)	Gross		Net
Canada		4		4

⁽¹⁾ Denotes wells that were being drilled at February 18, 2014.

Costs Incurred

	Total		Western Canada		Atlantic Region		Total Canada		United States		China		Indonesia		Libya
	($ millions)
Property acquisition
Unproven		1		1		—		1		—		—		—		—
Proven		37		37		—		37		—		—		—		—
Exploration		601		357		223		580		—		5		16		—
Development		3,722		2,655		402		3,057		—		665		—		—
2013		4,361		3,050		625		3,675		—		670		16		—
	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		—

AIF 2013 Page 32

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 National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”). Sproule Unconventional Limited (“Sproule”), an independent firm of oil and gas reserves evaluation engineers, was engaged to conduct a full evaluation of Husky’s crude oil, natural gas and natural gas products reserves for the Company’s Heavy Oil and Gas business unit, excluding the Tucker property. The remainder of 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 following oil and gas reserves disclosure has been prepared in accordance with NI 51-101 effective December 31, 2013. Husky received approval from the Canadian Securities Administrators (“CSA”) to also disclose its reserves using the rules of the the United States Financial Accounting Standards Board (“FASB”) and the SEC (the “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. The material differences between reserves quantities disclosed under NI 51-101 and those disclosed under the U.S. Rules is that NI 51-101 requires the determination of reserves quantities to be based on forecast pricing assumptions whereas the U.S. Rules require the determination of reserves quantities to be based on constant price assumptions calculated using a 12 month average price for the year (sum of the benchmark price on the first calendar day of each month in the year divided by 12).

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

Independent Audit or Evaluation 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 internally evaluated crude oil, natural gas, NGL and the Tucker property reserves estimates, other than for the Company’s Heavy Oil and Gas business unit. 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.

Sproule Unconventional Limited, an independent firm of oil and gas reserves evaluation engineers, was engaged to conduct a full evaluation of Husky’s crude oil, natural gas and natural gas products reserves for the Company’s Heavy Oil and Gas business unit, excluding the Tucker property.

Disclosure of Oil and Gas Information

Unless otherwise noted in this document, all provided reserves estimates have an effective date of December 31, 2013 and are Husky’s total reserves including those prepared by internal reserves revaluation staff and those evaluated by Sproule for the Company’s Heavy Oil and Gas business unit, excluding the Tucker property. 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 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 2013 Page 33

Disclosure of Exemption Under National Instrument 51-101

Husky sought and was granted by the CSA an exemption from the requirement under 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 addition, Husky engaged Sproule Unconventional Limited to evaluate Husky’s reserves for its Heavy Oil and Gas business unit, excluding the Tucker property.

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 2013 Page 34

Summary of Oil and Natural Gas Reserves

As at December 31, 2013

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		133.4		107.0		81.8		72.3		80.7		72.8		57.4		53.3
Developed Non-producing		4.9		4.3		3.2		2.8		10.8		10.1		8.5		8.2
Undeveloped		23.6		19.2		5.7		4.9		21.9		19.8		293.2		250.0
Total Proved		162.0		130.5		90.7		80.0		113.5		102.7		359.1		311.5
Probable		80.7		58.4		20.9		17.5		62.5		55.6		1,511.4		1,206.1
Total Proved Plus Probable		242.6		189.0		111.6		97.5		176.0		158.3		1,870.4		1,517.6
	Coal Bed Methane (bcf)				Natural Gas (bcf)				NGL (mmbbls)				Total (mmboe)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Proved
Developed Producing		24.3		22.8		1,580.1		1,374.2		66.6		50.6		687.4		588.8
Developed Non-producing		—		—		98.0		89.0		1.6		1.2		45.4		41.4
Undeveloped		—		—		472.4		463.7		10.2		8.6		433.3		379.7
Total Proved		24.3		22.8		2,150.6		1,926.8		78.4		60.4		1,166.2		1,010.0
Probable		2.2		2.1		491.8		453.5		26.7		20.7		1,784.5		1,434.3
Total Proved Plus Probable		26.6		25.0		2,642.4		2,380.3		105.2		81.1		2,950.7		2,444.3
China
	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		7.1		5.5		—		—		—		—		—		—
Developed Non-producing		—		—		—		—		—		—		—		—
Undeveloped		—		—		—		—		—		—		—		—
Total Proved		7.1		5.5		—		—		—		—		—		—
Probable		1.0		0.7		—		—		—		—		—		—
Total Proved Plus Probable		8.0		6.2		—		—		—		—		—		—
	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		7.2		5.6
Developed Non-producing		—		—		266.9		274.0		7.7		7.9		52.2		53.6
Undeveloped		—		—		17.8		20.5		1.0		1.3		4.0		4.7
Total Proved		—		—		284.7		294.5		8.9		9.3		63.4		63.9
Probable		—		—		254.7		240.3		7.1		6.6		50.5		47.4
Total Proved Plus Probable		—		—		539.4		534.8		16.0		16.0		113.9		111.3

AIF 2013 Page 35

Indonesia⁽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

—

—

—

—

—

—

—

—

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		—		—		152.0		104.1		1.7		0.6		27.0		17.9
Total Proved Plus Probable		—		—		319.2		212.9		8.8		4.1		62.1		39.6

⁽¹⁾ Husky’s beneficial interest in the Madura Strait block is held by way of a 40% interest in Husky—CNOOC Madura Limited (HCML”), an entity that is party to a PSC with the Government of Indonesia. Husky has entered into a unanimous shareholder agreement dated April 8, 2008 with the other shareholders of HCML that provides for joint control of HCML. International Financial Reporting Standard 11, “Joint Arrangements” (“IFRS 11”), requires Husky to follow the equity method of accounting for its investment in the Madura Strait block. IFRS 11 focuses on the legal form of the corporate structure in which Husky’s Madura assets are held. Husky holds its interest in the Madura Strait block through HCML and accordingly is required to use the equity method to account for this interest. As a consequence, Husky sought and was granted by the Canadian Securities Administrators an exemption from the provisions in NI 51-101 which would have otherwise required Husky to exclude the reserves allocated to the Madura Strait block from the total disclosed reserves and future net revenue of Husky and to only disclose those reserves separately because the Madura Strait block is accounted for by the equity method of accounting.

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		0.1		0.1		—		—		—		—		—		—
Developed Non-producing		—		—		—		—		—		—		—		—
Undeveloped		—		—		—		—		—		—		—		—
Total Proved		0.1		0.1		—		—		—		—		—		—
Probable		—		—		—		—		—		—		—		—
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		—		—		—		—		—		—		0.1		0.1
Developed Non-producing		—		—		—		—		—		—		—		—
Undeveloped		—		—		—		—		—		—		—		—
Total Proved		—		—		—		—		—		—		0.1		0.1
Probable		—		—		—		—		—		—		—		—
Total Proved Plus Probable		—		—		—		—		—		—		0.1		0.1

AIF 2013 Page 36

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		140.6		112.6		81.8		72.3		80.7		72.8		57.4		53.3
Developed Non-producing		4.9		4.3		3.2		2.8		10.8		10.1		8.5		8.2
Undeveloped		23.6		19.2		5.7		4.9		21.9		19.8		293.2		250.0
Total Proved		169.1		136.1		90.7		80.0		113.5		102.7		359.1		311.5
Probable		81.6		59.2		20.9		17.5		62.5		55.6		1,511.4		1,206.1
Total Proved Plus Probable		250.8		195.2		111.6		97.5		176.0		158.3		1,870.4		1,517.6

	Coal Bed Methane (bcf)				Natural Gas (bcf)				NGL (mmbbls)				Total (mmboe)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Proved
Developed Producing		24.3		22.8		1,580.1		1,374.2		66.8		50.7		694.7		594.5
Developed Non-producing		—		—		365.0		363.0		9.3		9.2		97.6		95.0
Undeveloped		—		—		657.4		593.0		18.4		13.4		472.4		406.1
Total Proved		24.3		22.8		2,602.5		2,330.1		94.5		73.3		1,264.7		1,095.6
Probable		2.2		2.1		898.6		797.9		35.5		27.9		1,862.0		1,499.7
Total Proved Plus Probable		26.6		25.0		3,501.1		3,128.0		130.0		101.2		3,126.7		2,595.3

AIF 2013 Page 37

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

As at December 31, 2013

Forecast Prices and Costs

Canada

	Before Income Taxes and Discounted at (%/year)
($ millions)	5%		10%		15%		20%
Proved
Developed Producing		11,403		9,960		8,845		7,978
Developed Non-producing		1,123		930		803		712
Undeveloped		6,451		4,101		2,739		1,872
Total Proved		18,978		14,991		12,387		10,562
Probable		23,088		12,007		7,496		5,182
Total Proved Plus Probable		42,065		26,999		19,883		15,744
China
	Before Income Taxes and Discounted at (%/year)
($ millions)	5%		10%		15%		20%
Proved
Developed Producing		244		267		271		265
Developed Non-producing		3,061		2,817		2,604		2,418
Undeveloped		288		264		243		226
Total Proved		3,593		3,348		3,118		2,909
Probable		2,520		1,874		1,434		1,125
Total Proved Plus Probable		6,113		5,222		4,552		4,034
Indonesia
	Before Income Taxes and Discounted at (%/year)
($ millions)	5%		10%		15%		20%
Proved
Developed Producing		—		—		—		—
Developed Non-producing		—		—		—		—
Undeveloped		262		169		108		67
Total Proved		262		169		108		67
Probable		159		78		30		—
Total Proved Plus Probable		421		247		137		66
Libya
	Before Income Taxes and Discounted at (%/year)
($ millions)	5%		10%		15%		20%
Proved
Developed Producing		4		4		4		4
Developed Non-producing		—		—		—		—
Undeveloped		—		—		—		—
Total Proved		4		4		4		4
Probable		—		—		—		—
Total Proved Plus Probable		5		5		4		4

AIF 2013 Page 38

Total

	Before Income Taxes and Discounted at (%/year)
($ millions)	5%		10%		15%		20%
Proved
Developed Producing		11,652		10,232		9,119		8,248
Developed Non-producing		4,184		3,747		3,407		3,129
Undeveloped		7,001		4,534		3,090		2,164
Total Proved		22,837		18,512		15,617		13,541
Probable		25,767		13,960		8,960		6,307
Total Proved Plus Probable		48,604		32,472		24,577		19,848

AIF 2013 Page 39

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

As at December 31, 2013

Forecast Prices and Costs

Canada

	After Income Taxes and Discounted at (%/year)
($ millions)	5%		10%		15%		20%
Proved
Developed Producing		8,375		7,299		6,471		5,829
Developed Non-producing		824		678		583		514
Undeveloped		4,777		2,942		1,877		1,199
Total Proved		13,975		10,919		8,930		7,542
Probable		16,730		8,441		5,096		3,399
Total Proved Plus Probable		30,706		19,360		14,026		10,941
China
	After Income Taxes and Discounted at (%/year)
($ millions)	5%		10%		15%		20%
Proved
Developed Producing		127		148		154		153
Developed Non-producing		2,665		2,457		2,273		2,112
Undeveloped		244		224		206		192
Total Proved		3,037		2,828		2,633		2,456
Probable		2,111		1,562		1,188		926
Total Proved Plus Probable		5,148		4,390		3,821		3,382
Indonesia
	After Income Taxes and Discounted at (%/year)
($ millions)	5%		10%		15%		20%
Proved
Developed Producing		—		—		—		—
Developed Non-producing		—		—		—		—
Undeveloped		185		118		73		42
Total Proved		185		118		73		42
Probable		106		45		8		(16	)
Total Proved Plus Probable		292		163		80		26
Libya
	After Income Taxes and Discounted at (%/year)
($ millions)	5%		10%		15%		20%
Proved
Developed Producing		4		4		4		4
Developed Non-producing		—		—		—		—
Undeveloped		—		—		—		—
Total Proved		4		4		4		4
Probable		—		—		—		—
Total Proved Plus Probable		5		5		4		4

AIF 2013 Page 40

Total

	After Income Taxes and Discounted at (%/year)
($ millions)	5%		10%		15%		20%
Proved
Developed Producing		8,507		7,452		6,629		5,985
Developed Non-producing		3,489		3,135		2,856		2,626
Undeveloped		5,206		3,283		2,156		1,433
Total Proved		17,202		13,870		11,640		10,044
Probable		18,948		10,048		6,292		4,310
Total Proved Plus Probable		36,150		23,917		17,932		14,354

AIF 2013 Page 41

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

As at December 31, 2013

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		43,896		6,982		16,068		960		6,975		12,910		3,408		9,502
Developed Non-producing		2,813		354		830		156		—		1,473		386		1,088
Undeveloped		28,735		4,353		7,454		5,876		—		11,052		2,688		8,364
Total Proved		75,444		11,690		24,352		6,992		6,975		25,435		6,481		18,954
Probable		153,728		32,829		38,922		20,824		—		61,153		15,705		45,448
Total Proved Plus Probable		229,171		44,519		63,274		27,816		6,975		86,588		22,187		64,402
China
Proved
Developed Producing		708		—		118		122		289		179		104		75
Developed Non-producing		4,286		—		790		159		—		3,337		439		2,899
Undeveloped		357		—		29		11		—		317		48		269
Total Proved		5,352		—		936		293		289		3,834		591		3,243
Probable		3,811		—		304		9		—		3,499		553		2,946
Total Proved Plus Probable		9,163		—		1,240		302		289		7,332		1,144		6,189
Indonesia
Proved
Developed Producing		—		—		—		—		—		—		—		—
Developed Non-producing		—		—		—		—		—		—		—		—
Undeveloped		1,021		—		476		134		—		411		121		290
Total Proved		1,021		—		476		134		—		411		121		290
Probable		858		—		409		147		—		302		90		213
Total Proved Plus Probable		1,880		—		885		281		—		713		210		503
Libya
Proved
Developed Producing		8		—		2		1		—		5		—		5
Developed Non-producing		—		—		—		—		—		—		—		—
Undeveloped		—		—		—		—		—		—		—		—
Total Proved		8		—		2		1		—		5		—		5
Probable		1		—		—		—		—		—		—		—
Total Proved Plus Probable		8		—		2		1		—		5		—		5
Total
Proved
Developed Producing		44,612		6,982		16,188		1,083		7,264		13,094		3,512		9,582
Developed Non-producing		7,100		354		1,619		315		—		4,811		825		3,986
Undeveloped		30,113		4,353		7,959		6,021		—		11,780		2,856		8,924
Total Proved		81,825		11,690		25,766		7,420		7,264		29,685		7,193		22,492
Probable		158,398		32,829		39,635		20,980		—		64,954		16,348		48,606
Total Proved Plus Probable		240,223		44,519		65,401		28,400		7,264		94,639		23,540		71,099

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

AIF 2013 Page 42

Future Net Revenue by Production Group

As at December 31, 2013

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		3,936		30		267		48		—		—		4		62		4,207		30
Medium Crude Oil		1,867		26		—		—		—		—		—		—		1,867		26
Heavy Crude Oil		1,461		20		—		—		—		—		—		—		1,461		20
Natural Gas		1,474		6		—		—		—		—		—		—		1,474		6
Coal Bed Methane		24		6		—		—		—		—		—		—		24		6
Bitumen		1,198		22		—		—		—		—		—		—		1,198		22
Developed Non-producing
Light Crude Oil & NGL		135		31		—		—		—		—		—		—		135		11
Medium Crude Oil		83		30		—		—		—		—		—		—		83		30
Heavy Crude Oil		272		27		—		—		—		—		—		—		272		27
Natural Gas		148		9		2,817		54		—		—		—		—		2,965		43
Coal Bed Methane		—		—		—		—		—		—		—		—		—		—
Bitumen		292		36		—		—		—		—		—		—		292		36
Undeveloped
Light Crude Oil & NGL		389		20		—		—		—		—		—		—		389		19
Medium Crude Oil		94		19		—		—		—		—		—		—		94		19
Heavy Crude Oil		359		18		—		—		—		—		—		—		359		18
Natural Gas		324		4		264		66		169		8		—		—		757		7
Coal Bed Methane		—		—		—		—		—		—		—		—		—		—
Bitumen		2,936		12		—		—		—		—		—		—		2,936		12
Total Proved
Light Crude Oil & NGL		4,460		29		267		18		—		—		4		62		4,731		28
Medium Crude Oil		2,043		26		—		—		—		—		—		—		2,043		26
Heavy Crude Oil		2,092		20		—		—		—		—		—		—		2,092		20
Natural Gas		1,946		5		3,081		55		169		8		—		—		5,196		14
Coal Bed Methane		24		6		—		—		—		—		—		—		24		6
Bitumen		4,425		14		—		—		—		—		—		—		4,425		14
Probable
Light Crude Oil & NGL		2,731		40		67		9		—		—		—		—		2,798		37
Medium Crude Oil		405		23		—		—		—		—		—		—		405		23
Heavy Crude Oil		1,209		22		—		—		—		—		—		—		1,209		22
Natural Gas		596		7		1,807		43		78		4		—		—		2,482		17
Coal Bed Methane		2		6		—		—		—		—		—		—		2		6
Bitumen		7,065		6		—		—		—		—		—		—		7,065		6
Total Proved Plus Probable
Light Crude Oil & NGL		7,191		32		334		15		—		—		4		57		7,529		31
Medium Crude Oil		2,448		25		—		—		—		—		—		—		2,448		25
Heavy Crude Oil		3,300		21		—		—		—		—		—		—		3,300		21
Natural Gas		2,542		6		4,888		50		247		6		—		—		7,677		15
Coal Bed Methane		26		6		—		—		—		—		—		—		26		6
Bitumen		11,490		8		—		—		—		—		—		—		11,490		8

AIF 2013 Page 43

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
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
2013		97.97		107.91		3.65		3.00		—		0.971
Forecast
2014		95.72		106.85		4.22		4.01		1.833		0.947
2015		93.62		104.24		4.35		4.17		1.833		0.947
2016		92.25		100.87		4.50		4.35		1.833		0.947
2017		96.01		102.11		4.92		4.81		1.833		0.947
2018		96.59		102.74		5.07		4.99		1.833		0.947

(1) Inflation rates for forecasting prices and costs.

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

AIF 2013 Page 44

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 2012		172.7			95.4			105.4			2,072.6			310.9			1,029.9
Revisions—Technical		(10.6	)		(3.2	)		7.1			79.8			24.2			30.8
Revisions—Economic		0.1			0.2			0.3			(20.5	)		—			(2.9	)
Purchases		—			—			0.1			1.0			1.2			1.4
Sales		(0.1	)		—			—			(2.8	)		—			(0.6	)
Discoveries		2.7			—			—			15.5			—			5.3
Extensions		11.5			6.7			22.0			216.5			39.5			115.8
Improved Recovery		0.5			—			5.8			—			0.8			7.1
Production		(10.8	)		(8.5	)		(27.2	)		(187.2	)		(17.4	)		(95.1	)
End of 2013		166.0			90.7			113.5			2,174.9			359.1			1,091.7
Canada—Atlantic Region
End of 2012		68.1			—			—			—			—			68.1
Revisions—Technical		13.1			—			—			—			—			13.1
Revisions—Economic		—			—			—			—			—			—
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		—			—			—			—			—			—
Extensions		9.4			—			—			—			—			9.4
Improved Recovery		—			—			—			—			—			—
Production		(16.1	)		—			—			—			—			(16.1	)
End of 2013		74.5			—			—			—			—			74.5
China
End of 2012		14.5			—			—			267.1			—			59.0
Revisions—Technical		3.1			—			—			(0.1	)		—			3.0
Revisions—Economic		—			—			—			—			—			—
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		1.0			—			—			17.8			—			4.0
Extensions		—			—			—			—			—			—
Improved Recovery		—			—			—			—			—			—
Production		(2.7	)		—			—			—			—			(2.7	)
End of 2013		16.0			—			—			284.7			—			63.4
Indonesia
End of 2012		7.2			—			—			167.2			—			35.0
Revisions—Technical		—			—			—			—			—			—
Revisions—Economic		—			—			—			—			—			—
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		—			—			—			—			—			—
Extensions		—			—			—			—			—			—
Improved Recovery		—			—			—			—			—			—
Production		—			—			—			—			—			—
End of 2013		7.2			—			—			167.2			—			35.0

AIF 2013 Page 45

	Light Crude Oil & NGL (mmbbls)			Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Natural Gas (bcf)			Bitumen (mmbbls)			Total Company (mmboe)
Total
End of 2012		262.5			95.4			105.4			2,506.8			310.9			1,192.0
Revisions—Technical		5.6			(3.2	)		7.1			79.7			24.2			47.0
Revisions—Economic		0.1			0.2			0.3			(20.5	)		—			(2.9	)
Purchases		—			—			0.1			1.0			1.2			1.4
Sales		(0.1	)		—			—			(2.8	)		—			(0.6	)
Discoveries		3.7			—			—			33.3			—			9.3
Extensions		20.9			6.7			22.0			216.5			39.5			125.2
Improved Recovery		0.5			—			5.8			—			0.8			7.1
Production		(29.6	)		(8.5	)		(27.2	)		(187.2	)		(17.4	)		(113.9	)
End of 2013		263.6			90.7			113.5			2,626.8			359.2			1,264.7

Major additions to proved reserves in 2013 include:

• the extension through additional drilling locations at Sunrise in the Oil Sands that resulted in the booking of an additional 39 mmbbls of bitumen in proved undeveloped reserves;

• the project sanction at the South White Rose Extension in the Atlantic Region that resulted in the booking of an additional 7 mmbbls of light oil in proved undeveloped reserves; and

• the extension through additional drilling locations at the Ansell liquids-rich natural gas resource play in the Alberta Deep Basin that resulted in the booking of an additional 32 mmboe of natural gas and NGL in proved undeveloped reserves.

AIF 2013 Page 46

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 2012		55.8			21.9			35.1			474.4			1,413.8			1,605.6
Revisions—Technical		(11.4	)		(4.5	)		8.0			(73.9	)		14.9			(5.4	)
Revisions—Economic		—			0.1			—			(5.5	)		(4.1	)		(5.0	)
Revisions—Transfer to Proved		(1.0	)		(0.5	)		(4.5	)		(2.9	)		(48.0	)		(54.5	)
Purchases		—			—			—			0.2			2.3			2.4
Sales		(0.1	)		—			—			(2.6	)		—			(0.5	)
Discoveries		1.0			—			—			6.0			—			2.0
Extensions		9.7			3.9			19.2			96.9			24.6			73.6
Improved Recovery		3.3			—			4.7			1.5			107.8			116.1
Production		—			—			—			—			—			—
End of 2013		57.2			20.9			62.5			494.1			1,511.4			1,734.4
Canada—Atlantic Region
End of 2012		61.7			—			—			—			—			61.7
Revisions—Technical		6.4			—			—			—			—			6.4
Revisions—Economic		—			—			—			—			—			—
Revisions—Transfer to Proved		(17.9	)		—			—			—			—			(17.9	)
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		—			—			—			—			—			—
Extensions		—			—			—			—			—			—
Improved Recovery		—			—			—			—			—			—
Production		—			—			—			—			—			—
End of 2013		50.2			—			—			—			—			50.2
China
End of 2012		6.9			—			—			244.5			—			47.7
Revisions—Technical		0.5			—			—			(0.1	)		—			0.5
Revisions—Economic		—			—			—			—			—			—
Revisions—Transfer to Proved		—			—			—			—			—			—
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		0.6			—			—			10.3			—			2.3
Extensions		—			—			—			—			—			—
Improved Recovery		—			—			—			—			—			—
Production		—			—			—			—			—			—
End of 2013		8.0			—			—			254.7			—			50.5
Indonesia
End of 2012		1.7			—			—			39.4			—			8.2
Revisions—Technical		—			—			—			—			—			—
Revisions—Economic		—			—			—			—			—			—
Revisions—Transfer to Proved		—			—			—			—			—			—
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		—			—			—			112.6			—			18.8
Extension		—			—			—			—			—			—
Improved Recovery		—			—			—			—			—			—
Production		—			—			—			—			—			—
End of 2013		1.7			—			—			152.0			—			27.0

AIF 2013 Page 47

	Light Crude Oil & NGL (mmbbls)			Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Natural Gas (bcf)			Bitumen (mmbbls)			Total (mmboe)
Libya
End of 2012		0.1			—			—			—			—			0.1
Revisions—Technical		—			—			—			—			—			—
Revisions—Economic		—			—			—			—			—			—
Revisions—Transfer to Proved		(0.1	)		—			—			—			—			(0.1	)
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		—			—			—			—			—			—
Extension		—			—			—			—			—			—
Improved Recovery		—			—			—			—			—			—
Production		—			—			—			—			—			—
End of 2013		—			—			—			—			—			—
	Light Crude Oil & NGL (mmbbls)			Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Natural Gas (bcf)			Bitumen (mmbbls)			Total Company (mmboe)
Total
End of 2012		126.1			21.9			35.1			758.3			1,413.8			1,723.3
Revisions—Technical		(4.5	)		(4.5	)		8.0			(74.0	)		14.9			1.5
Revisions—Economic		—			0.1			—			(5.5	)		(4.1	)		(5.0	)
Revisions—Transfer to Proved		(19.0	)		(0.5	)		(4.5	)		(2.9	)		(48.0	)		(72.5	)
Purchases		—			—			—			0.2			2.3			2.4
Sales		(0.1	)		—			—			(2.6	)		—			(0.5	)
Discoveries		1.6			—			—			129.0			—			23.1
Extension		9.7			3.9			19.2			96.9			24.6			73.6
Improved Recovery		3.3			—			4.7			1.5			107.8			116.0
Production		—			—			—			—			—			—
End of 2013		117.1			20.9			62.5			900.8			1,511.4			1,862.0

Major changes to probable reserves in 2013 include:

• the approval of the development plan for the Madura MDA and MBH fields that resulted in an addition of 19 mmboe of natural gas in probable undeveloped reserves;

• improved recovery and new heavy oil thermal projects that resulted in the booking of an additional 127 mmbbls in probable reserves; and

• the extension through additional drilling locations mainly in the S. Kaybob Duverney liquids-rich natural gas resource play in the Alberta Deep Basin that resulted in the booking of an additional 11 mmboe of natural gas and NGL in probable undeveloped reserves.

AIF 2013 Page 48

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 2012		228.5			117.4			140.5			2,546.9			1,724.7			2,635.5
Revisions—Technical		(22.0	)		(7.6	)		15.0			5.9			39.1			25.4
Revisions—Economic		0.1			0.2			0.3			(26.0	)		(4.1	)		(7.8	)
Revisions—Transfer to Proved		(1.0	)		(0.5	)		(4.5	)		(2.9	)		(48.0	)		(54.5	)
Purchases		—			—			0.1			1.2			3.5			3.8
Sales		(0.2	)		—			—			(5.4	)		—			(1.1	)
Discoveries		3.7			—			—			21.5			—			7.3
Extensions		21.2			10.6			41.2			313.3			64.1			189.4
Improved Recovery		3.8			—			10.5			1.5			108.6			123.1
Production		(10.8	)		(8.5	)		(27.2	)		(187.2	)		(17.4	)		(95.1	)
End of 2013		223.2			111.6			176.0			2,669.0			1,870.4			2,826.1
Canada—Atlantic Region
End of 2012		129.7			—			—			—			—			129.7
Revisions—Technical		19.5			—			—			—			—			19.5
Revisions—Economic		—			—			—			—			—			—
Revisions—Transfer to Proved		(17.9	)		—			—			—			—			(17.9	)
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		—			—			—			—			—			—
Extensions		9.4			—			—			—			—			9.4
Improved Recovery		—			—			—			—			—			—
Production		(16.1	)		—			—			—			—			(16.1	)
End of 2013		124.6			—			—			—			—			124.6
China
End of 2012		21.5			—			—			511.6			—			106.7
Revisions—Technical		3.6			—			—			(0.2	)		—			3.6
Revisions—Economic		—			—			—			—			—			—
Revisions—Transfer to Proved		—			—			—			—			—			—
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		1.6			—			—			28.0			—			6.3
Extensions		—			—			—			—			—			—
Improved Recovery		—			—			—			—			—			—
Production		(2.7	)		—			—			—			—			(2.7	)
End of 2013		24.0			—			—			539.4			—			113.9
Indonesia
End of 2012		8.8			—			—			206.6			—			43.3
Revisions—Technical		—			—			—			—			—			—
Revisions—Economic		—			—			—			—			—			—
Revisions—Transfer to Proved		—			—			—			—			—			—
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		—			—			—			112.6			—			18.8
Extensions		—			—			—			—			—			—
Improved Recovery		—			—			—			—			—			—
Production		—			—			—			—			—			—
End of 2013		8.8			—			—			319.2			—			62.1

AIF 2013 Page 49

	Light Crude Oil & NGL (mmbbls)			Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls)			Natural Gas (bcf)			Bitumen (mmbbls)			Total (mmboe)
Libya
End of 2012		0.1			—			—			—			—			0.1
Revisions—Technical		—			—			—			—			—			—
Revisions—Economic		—			—			—			—			—			—
Revisions—Transfer to Proved		(0.1	)		—			—			—			—			(0.1	)
Purchases		—			—			—			—			—			—
Sales		—			—			—			—			—			—
Discoveries		—			—			—			—			—			—
Extensions		—			—			—			—			—			—
Improved Recovery		—			—			—			—			—			—
Production		—			—			—			—			—			—
End of 2013		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 2012		388.6			117.4			140.5			3,265.1			1,724.7			2,915.3
Revisions—Technical		1.1			(7.6	)		15.0			5.7			39.1			48.6
Revisions—Economic		0.1			0.2			0.3			(26.0	)		(4.1	)		(7.8	)
Revisions—Transfer to Proved		(19.0	)		(0.5	)		(4.5	)		(2.9	)		(48.0	)		(72.5	)
Purchases		—			—			0.1			1.2			3.5			3.8
Sales		(0.2	)		—			—			(5.4	)		—			(1.1	)
Discoveries		5.3			—			—			345.4			—			62.9
Extensions		30.6			10.6			41.2			130.1			64.1			168.3
Improved Recovery		3.8			—			10.5			1.5			108.6			123.1
Production		(29.6	)		(8.5	)		(27.2	)		(187.2	)		(17.4	)		(113.9	)
End of 2013		380.7			111.6			176.0			3,527.6			1,870.4			3,126.7

Undeveloped Reserves

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

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 47% of Husky’s gross proved undeveloped reserves are assigned to the Sunrise Energy Project. Development of the first phase of the project is over 85% complete with start up expected in the second half of 2014. Approximately 16% of Husky’s gross proved undeveloped reserves are assigned to the liquids-rich Ansell area. This project has ongoing drilling with the recent acquisition of gas plant capacity. Approximately 7% of Husky’s gross proved undeveloped reserves are assigned to the Madura BD project.

As at December 31, 2013, there were no material proved undeveloped reserves that have remained undeveloped for greater than five years.

AIF 2013 Page 50

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		72.1		14.3		55.2		203.4		820.1		344.9
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
2013		16.2		1.7		13.0		41.3		216.5		72.3

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		139.3		11.7		49.7		1,797.9		309.7		1,998.6
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
2013		11.6		3.1		18.1		134.8		216.3		167.5

Future Development Costs

The Company expects to fund its future development costs by cash generated from operating activities, cash on hand, and short and long-term debt. In addition, the Company has access to additional funding through credit facilities and the issuance of equity through shelf prospectuses, subject to market conditions. The cost associated with this funding would not affect reserves and would not be material in comparison with future net revenues.

The following tables include estimates of the forecasted costs of developing the Company’s proved and proved plus probable reserves as at December 31, 2013:

	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)
2014		2,095		2,766		91		100		18		54		1		1
2015		1,300		2,223		17		17		88		157		1		1
2016		948		1,842		33		33		28		66		—		—
2017		634		1,591		152		152		—		3		—		—
2018		556		1,196		112		112		—		—		—		—
Remaining		8,434		25,173		178		178		—		—		—		—
Total		13,967		34,791		582		591		134		281		1		1

	Total ($ millions)
Year	Proved Reserves		Proved Plus Probable Reserves
2014		2,205		2,920
2015		1,405		2,398
2016		1,009		1,941
2017		786		1,747
2018		668		1,307
Remaining		8,612		25,350
Total		14,684		35,664

AIF 2013 Page 51

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, net of estimated salvage value, the Company expects to incur these costs on approximately 30,590 net wells for a total undiscounted amount of $7.3 billion. Discounted at 10% per year, the total abandonment costs, net of estimated salvage value, for wells is $2.1 billion. This amount was deducted in estimating the future net revenue. Of the undiscounted portion of the total abandonment and reclamation costs, $352 million is expected to be paid in the next three years.

Production Estimates

Yearly Production Estimates for 2014

	Light Crude Oil (mmbbls)		Medium Crude Oil (mmbbls)		Heavy Crude Oil (mmbbls)		Bitumen (mmbbls)		Natural Gas (bcf)
Canada
Total Gross Proved		27.8		9.1		25.7		17.1		169.6
Total Gross Probable		3.9		0.6		2.5		2.4		6.8
Total Gross Proved Plus Probable		31.7		9.7		28.2		19.5		176.5
International
Total Gross Proved		3.1		—		—		—		37.4
Total Gross Probable		0.4		—		—		—		0.9
Total Gross Proved Plus Probable		3.5		—		—		—		38.3
Total
Total Gross Proved		30.9		9.1		25.7		17.1		207.0
Total Gross Probable		4.3		0.6		2.5		2.4		7.7
Total Gross Proved Plus Probable		35.2		9.7		28.2		19.5		214.7

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

AIF 2013 Page 52

Infrastructure and Marketing

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, the blending of crude oil and natural gas, and the 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 capable of transporting up to 710 mbbls/day of blended heavy crude oil, diluent and synthetic crude oil when 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, Spectra Express Pipeline, TransCanada’s Keystone pipeline and the smaller Inter 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 Inter Pipeline at Cold Lake, the Echo Pipeline at Hardisty, the Gibsons Hardisty Terminal, the Enbridge Hardisty Caverns and Merchant Terminal and the Talisman Chauvin Pipeline.

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

	Years Ended December 31,
(mbbls/day)	2013		2012		2011
Combined Pipeline Throughput (1)		557		581		559

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

In recent years, Husky has completed 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. Two additional 300,000-barrel tanks are currently under construction and are expected to be in service during the first quarter of 2015.

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 2013 Page 53

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 strategy, commenced in 2006, to expand the market for Husky’s crude oil into the midwest United States. This strategy 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 has the option, depending on the economics, to access a significant amount of Canadian crude oil as part of its crude feedstock requirements. The Keystone pipeline has also enabled Husky to sell heavy crude oil through interconnecting pipeline systems to the Lima, Ohio Refinery and into Cushing, Oklahoma.

AIF 2013 Page 54

In 2012 and 2013, the Canadian pipeline system was subject to significant apportionment, affecting both Canadian export volumes and crude oil prices in Western Canada. Husky has to a large extent been insulated from these effects through the reliability of its proprietary pipeline system, its firm capacity on Keystone and through Husky’s demand for Canadian crude feedstocks to its upgrading and refining assets. To date, Husky has been able to avoid any production shut ins. As a seller and buyer of crude oils, Husky has a relatively balanced exposure to many location and grade differentials.

Husky has been carefully monitoring opportunities to participate in growing crude oil markets accessed by rail, which have developed due to refiners’ desire for inland crude oil, priced at significant discounts to ocean imports. Husky has made opportunistic crude oil deliveries to rail loading facilities via trucks where netbacks can be increased relative to pipeline alternatives. While Husky’s primary focus is on low cost pipeline transportation options, it intends to develop a flexible crude delivery strategy to use rail transport to a variety of crude oil markets.

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

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 and contracts additional natural gas storage under long-term arrangements. At December 31, 2013, Husky managed a total natural gas storage capacity of approximately 28 bcf. 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 2013 Page 55

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, including the Lima Refinery and other refineries in the midwest of 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 the 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, 2013, Husky’s long-term fixed price natural gas sales contracts totaled approximately 15 bcf over two years deliverable at the rate of 75% in 2014 and 25% in 2015. Husky has acquired rights to firm pipeline capacity to transport natural gas to contracted markets. The Company trades natural gas to generate revenue from assets managed, including transportation and natural gas storage facilities.

Husky has developed its commodity marketing operations to include the acquisition of third-party volumes 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.

AIF 2013 Page 56

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/day. The Lima 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 HSB produced by the Lloydminster Upgrader. The Lima 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 2013, crude oil feedstock throughput at the Lima Refinery averaged 144 mbbls/day. Production of gasoline averaged 75 mbbls/day, total distillates averaged 58 mbbls/day and total other products averaged 18 mbbls/day.

The Lima Refinery continues to progress reliability and profitability improvement projects. Construction of the 20- mbbls/day kerosene hydrotreater, which increased on-road diesel and jet fuel production volumes, was completed and brought on-line in early 2013. In addition, FEED commenced in the second half of 2013 to revamp existing refinery process units and add new equipment to allow the refinery to process up to 40,000 bbls/day of Western Canadian heavy crude oil while maintaining the capability and flexibility to refine existing light crude oil, regulatory approval for which was granted by the U.S. Environmental Protection Agency. The capability to refine heavy crude oil at the Lima Refinery is anticipated by 2017.

BP-Husky Toledo, Ohio Refinery

The BP-Husky Toledo Refinery, in which Husky holds a 50% interest, has a name plate capacity of 160 mbbls/day and an operating capacity of 135 to 145 mbbls/day on its current crude slate. Products include low sulphur gasoline, ultra low sulphur diesel, aviation fuels, propane, kerosene and asphalt. The BP-Husky Toledo 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 BP-Husky Toledo Refinery’s bitumen processing capacity to align with the first two 60 mbbls/day phases of the Sunrise Energy Project 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. Project construction formally commenced in August 2010 and was completed in the fourth quarter of 2012. This project improved the efficiency and competitiveness of the refinery by reducing energy consumption, lowering operating costs and safety concerns with the replacement of two naphtha reformers and one hydrogen plant with a 42,000 bbls/day continuous catalyst regeneration reformer system plant.

The Company and its partner initiated the Hydrotreater Recycle Gas Compressor Project in 2013, which is scheduled to be completed in 2014. The installation of a new recycle gas compressor in the existing hydrotreater is intended to improve operational integrity and plant performance.

During the year ended December 31, 2013, Husky’s share of crude oil feedstock throughput averaged 65 mbbls/day, production of gasoline averaged 43 mbbls/day, middle distillates averaged 18 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.

The Upgrader was commissioned in 1992 with an original design capacity of 46 mbbls/day of synthetic crude oil.

AIF 2013 Page 57

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 transportation grade diesel. The Upgrader’s current rated production capacity is 82 mbbls/day of synthetic crude oil, diluents, and ultra low sulphur diesel.

Production at the Upgrader averaged 51 mbbls/day of synthetic crude oil, 11 mbbls/day of diluent and 4 mbbls/day of ultra low sulphur diesel in 2013. In addition, the Upgrader also produced, as by-products of its upgrading operations, approximately 311 lt/day of sulphur and 793 lt/day of petroleum coke during 2013. 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, provides refined products to 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. In 2013, refinery throughput averaged 10.3 mbbls/day.

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 ultra low sulphur diesel fuel. 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 26.4 mbbls/day of blended heavy crude oil feedstock during 2013. In 2013, daily sales volumes of asphalt averaged 14.2 mbbls/day and daily sales volumes of residual and other products averaged 12.1 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.

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 United States and eastern Canada accounted for 50% of its total asphalt sales in 2013. Exported asphalt products are shipped as far as Texas and New York in the United States and Quebec in Canada. Husky typically sells in excess of 5.4 mmbbls of asphalt cement each year. All of Husky’s asphalt requirements are supplied by Husky’s asphalt refinery.

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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 2014, 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 2013, ethanol production averaged 742,403 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 continues 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 3.0 mbbls/day and by the Husky Lloydminster Upgrader of 3.8 mbbls/day in 2013, Husky has rack-based pricing purchase agreements for refined products with all major Canadian refiners. During 2013, Husky purchased approximately 36.5 mbbls/day of refined petroleum products from refiners and acquired approximately 9.9 mbbls/day of refined petroleum products pursuant to exchange agreements with third-party refiners.

Branded Petroleum Product Outlets and Commercial Distribution

As at December 31, 2013, there were 503 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.

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. The following table shows the number of Husky and Mohawk branded petroleum outlets by province as of December 31, 2013:

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	British Columbia & Yukon		Alberta		Saskatchewan		Manitoba		Ontario		2013 Total		2012 Total
Branded Petroleum Outlets
Retail Owned Outlets		53		63		13		16		77		222		227
Leased		37		37		5		11		36		126		134
Independent Retailers		48		72		13		6		16		155		151
Total		138		172		31		33		129		503		512
Cardlocks (1)		22		28		5		7		19		81		84
Convenience Stores (1)		84		95		18		25		112		334		341
Restaurants		10		12		4		2		13		41		42

⁽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 2013, daily sales volumes of gasoline, diesel fuel and liquefied petroleum gas were 25.0 mbbls/day, 25.5 mbbls/day, and 0.4 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)	2013		2012		2011
Gasoline		25.0		26.2		27.7
Diesel fuel		25.5		27.2		26.0
Liquefied Petroleum Gas		0.4		0.8		0.6
		50.9		54.2		54.3

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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 United States 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 8.7% in 2014 compared with 2013. Of the remaining established crude oil and bitumen reserves in Alberta, 135 billion barrels or 80% is considered recoverable by in-situ methods and 33 billion barrels is suited to surface mining. The majority of in-situ production is not upgraded prior to reaching markets.¹

In its June 2013 forecast, the Canadian Association of Petroleum Producers (“CAPP”) projected total Canadian production to increase by approximately 95% to 6.7 mmbbls/day by 2030, of which 5.2 mmbbls/day would be from oil sands. Oil sands production at 5.2 mmbbls/day represents a 166% increase from current production levels. Conventional crude oil production, representing approximately 43% of current Canadian production, is forecast to remain stable and to represent 23% of total Canadian production by 2030 due to the sharp increase in oil sands production¹. The EIA Short-Term Energy Outlook was published in January 2014 and estimates that total U.S. crude production will reach 9.3 mmbbls/day in 2015, which represents a 24% increase over 2013 production volumes.²

Total Canadian natural gas production decreased by 3.3% in 2013 compared with 2012.³ The decrease follows a trend resulting from lower natural gas prices across North America as technological advances continue to unlock recoverable reserves. CAPP estimates that total production in Canada will remain relatively flat through 2020 assuming longer-term prices remain below $4/GJ.⁵ Total U.S. natural gas production increased by 1.4% in 2013 compared with 2012 and is forecast to increase by an additional 3.4% through 2015. Total U.S. consumption of natural gas increased by 2.5% in 2013 compared with 2012 and is expected to remain relatively flat through 2015. Total U.S. production of natural gas is expected to exceed consumption starting in 2014.²

According to the EIA, global energy consumption increased by 1.4% in 2013 over 2012 and is forecast to increase by 2.9% through 2015. The increase can be attributed to consumption in countries outside of the Organization for Economic Cooperation and Development. Total global supply increased by 1.1% in 2013 over 2012 and is forecast to increase by 4.0% through 2015. As a result, total marketed production is forecast to exceed consumption by 0.2% in 2015.²

Commodity Pricing

Crude oil and natural gas producers negotiate purchase and sale contracts directly with respective buyers and these contracts are typically based on the prevailing market price of the commodity. The market price for crude oil is determined largely by global factors and the contract price considers oil quality, transportation and other terms of the agreement. The price for natural gas 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 United States. 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 EIA projects that the spot price of Brent, an imported light sweet benchmark crude oil produced in the North Sea, will decline gradually from an average of U.S. $108/bbl in 2013 to annual averages of U.S. $105/bbl and U.S. $102/bbl in 2014 and 2015, respectively. This forecasted decrease reflects the increasing supply of liquid fuels from non-OPEC countries. Averaging U.S. $98/bbl in 2013, the projected WTI price is U.S. $93/bbl in 2014 and U.S. $90/bbl in 2015. The EIA expects the discount of the WTI crude oil price to Brent to average $12/bbl through 2014 and 2015. The discount reflects continued uncertainty of whether current refining capacity and transportation infrastructure will absorb forecast production increases of crude oil in North America.²

Market Access

Transportation and market access in North America for crude oil emerged as a major issue in 2012, and continued to contribute to regional price volatility in 2013. Western Canada’s crude has very limited access to world markets and is essentially landlocked as production has outgrown capacity to transport. Companies continue to seek supplemental alternatives to pipelines and accelerated use of transportation by rail in 2013, a trend that is likely to continue until additional pipeline capacity is built.

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In addition to the price differential between Brent crude and WTI crude and transportation constraints, the increased production in the United States has contributed to volatility in Canadian crude prices. In 2013, Western Canadian synthetic crude oil prices traded at a small premium to WTI averaging U.S. $3/bbl compared to a discount averaging U.S. $2/bbl in 2012. Western Canada Select crude oil prices at Hardisty traded at a deep discount to WTI in 2013, averaging U.S. $25.20/bbl in 2013 compared to U.S. $21.03/bbl in 2012.

Current pipeline capacity exiting western Canada totals 3.7 mmbbls/day, 300 mbbls/day of which runs to the west coast. A number of pipeline proposals have been announced that could increase market access between 2014 and 2017 of up to 3.1 mmbbls/day. The proposed pipeline projects are the Keystone XL to the U.S. Gulf Coast, the Alberta Clipper expansion to Superior, Wisconsin, the Trans Mountain Expansion, the Enbridge Northern Gateway to the west coast, and the TransCanada Energy East to the east coast of Canada. Considerable uncertainty exists around if and when each of these will be in service.¹

The National Energy Board estimates that 200,000 bbl/day of crude was transported by rail at the end of 2013 and forecasts 300,000 bbl/day to be transferred by rail by the end of 2014.¹

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 12% in 2013 compared with 10% in 2012 due to a royalty credit adjustment received in 2012. In the Company’s Atlantic Region, the average royalty rate was 13% in 2013 compared with 11% in 2012, when lower rates resulted from planned turnarounds.

The Canadian federal corporate income tax rate was 15% in 2013 and 2012. Provincial rates ranged between 10% and 16% in 2013 and 2012.

Other Jurisdictions

Royalty rates in the Company’s Asia Pacific Region averaged 24% in 2013 and 2012.

Operations in the U.S are subject to the U.S. federal tax rate of 35% 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 30% for 2013 and 29% for 2012. Royalty rates averaged 13% of gross revenue in 2013 compared with 11% in 2012.

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 PSCs. Companies in the oil and gas industry are subject to ongoing compliance with the regulatory requirements established by the relevant country for the right to explore, develop and produce petroleum and natural gas in that particular jurisdiction.

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Environmental Regulations

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 United States, 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 begun 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 United States, Canada has adopted renewable fuels regulations, requiring fuel producers and importers to have an average of at least 5% of their gasoline supply come from renewable sources (such as ethanol) and to have an average of at least 2% of their diesel supply come from renewable sources (such as bio-diesel).

In its 2013 Canada’s Emission Trends report, Environment Canada noted the success of the measures taken by both the federal and provincial governments in reducing total greenhouse gas emissions. From 2005 to 2011, Canadian greenhouse gas emissions have decreased by 4.8% while the economy has grown by 8.4%. The 2013 Canada’s Emissions Trends report also estimates that, as a result of the combined efforts of federal, provincial and territorial governments, consumers and businesses, greenhouse gas emissions in 2020 will be 734 megatonnes. This is 128 Mt lower than where emissions would be in 2020 if no action were taken to reduce greenhouse gas emissions since 2005.⁴

Canadian Provincial Greenhouse Gas Regulations

During 2007 and 2008, Ontario, British Columbia, Quebec and Manitoba committed, as partners, to move forward with a cap-and-trade system designed under the Western Climate Initiative (“WCI”), while Nova Scotia, Saskatchewan and the Yukon territory signed on as observers of the WCI. The WCI initiative was designed to reduce greenhouse gas emissions at the regional level to 15% below 2005 levels by 2020. The cap-and-trade system is intended to limit the allowable emissions for each partner, allocate them to large industrial facilities, and create a market where emissions could be traded among participants.

In November 2011, the WCI formed WCI, Inc., a non-profit corporation, to provide administrative and technical services to support the implementation of state and provincial GHG emission trading programs. As WCI jurisdictions begin to implement cap-and-trade programs, WCI, Inc. will develop a compliance tracking system that tracks both allowances and offset certificates, administer allowance auctions and conduct market monitoring of allowance auctions and allowance and offset certificate trading. California and Quebec moved forward with cap-and-trade in 2012, with compliance requirements beginning in 2013. Ontario, British Columbia, and Manitoba have indicated that they are committed to implementing programs in the near future as well.

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U.S. Greenhouse Gas Regulations

The U.S. does not have federal legislation establishing targets for the reduction of greenhouse gas emissions. The U.S. 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 promulgated regulations requiring greenhouse gas emissions reporting from certain U.S. operations. The EPA has not yet issued greenhouse gas emission guidelines for existing refineries or new source performance standards for new refineries and modifications to existing refineries. The September 2013 proposed rules relate to new utility power generators and should not have a direct impact on a refinery. The EPA has issued a new source performance standard for natural gas wells that requires the use of green completion. 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 AER hired Group 10 Engineering Ltd., a third-party consultant, to review the industry’s pipeline requirements and industry best practices for public safety and response to pipeline incidents, pipeline integrity management, and the safety of pipelines at, or near, water crossings. Husky participated in the interview process. The final report was released in August 2013 and included 17 recommendations to improve pipeline safety that were accepted by the province of Alberta.

The British Columbia Oil and Gas Commission is currently 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.

In 2012, the Canadian Energy Pipeline Association (“CEPA”) announced CEPA Integrity First, an industry-wide initiative to improve the industry’s pipeline safety, environmental and socio-economic 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 emphasizing the importance of reliable and safe energy infrastructure to the oil and gas industry.

Reclamation

The AER maintains the regulatory process for the abandonment of wells. Over the years, the AER 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 AER 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 AER 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 AER identified a large number of historically abandoned wellbores within urban areas and on residential properties. Amendments to Alberta Municipal Affairs subdivision regulations were issued in the year 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.

In early 2013, the AER made significant changes to its abandonment liability program and licence transfer process. These changes were implemented on May 1, 2013 under Directive 006: Licensee Liability Rating (LLR) Program and Licence Transfer Process (“Directive 6”) and effected important changes to the LLR Program. The LLR Program is designed to prevent Alberta taxpayers from incurring costs to suspend, abandon, remediate, and reclaim a well, facility or pipeline. Under the LLR Program, each licensee is assigned a Liability Management Rating (“LMR”). LMR is the ratio of a licensee’s eligible deemed assets under the LLR Program, the Large Facility Liability Management Program, and the Oilfield Waste Liability Program to its deemed liabilities in these programs. The LMR assessment is designed to assess a licensee’s ability to address its suspension, abandonment, remediation and reclamation liabilities. This assessment is conducted monthly and on receipt of a licence transfer application in which the licensee is the transferor or transferee.

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Directive 6 requires oil and gas operators in Alberta to pay higher security deposits to maintain the required LMR with the AER. The changes will be implemented over a three-year period. If a licensee fails to post security, if required, then the AER may take a number of steps to enforce these provisions, which include non-compliance fees, partial or full suspension of operations, suspension and/or cancellation of a permit, licence or approval, and prevention of the transfer of licences held by licensees that do not meet the new requirements.

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 enable 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 AER 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, 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, China Offshore Oil Operation Safety Office, IPEICA, Wood Buffalo Environmental Association, Parkland Air Management Zone, Calgary Regional Airshed Zone, Lakeland Industry and Community Association, Southeast Saskatchewan Airshed Association, Regional Aquatics Monitoring Program, Alberta Biodiversity Monitoring Institute, Carbon Disclosure Project, Integrated CO₂ Network, Orphan Well Association, Cumulative Effects Management Association, Canadian Land Reclamation Association, Environmental Services Association of Alberta, North Saskatchewan, Watershed Alliance, Beaver River Watershed Alliance, Clearwater Mutual Aid CO-OP, Western Canadian Spill Services, One Ocean, Eastern Canada Response Corporation, Ottawa River Coalition, Ohio Chemistry Trade Council 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 three 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 Community Report at www.huskyenergy.com.

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⁽¹⁾  “Crude Oil Forecast, Markets and Pipelines”, June 2013, Canadian Association of Petroleum Producers

⁽²⁾  “Short-Term Energy Outlook”, January 2014, U.S. Energy Information Administration

⁽³⁾  “Marketable Natural Gas production in Canada”, January 7, 2014, National Energy Board

⁽⁴⁾  “Reducing Greenhouse Gases”, July 2013, Environment Canada

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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 to 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 that 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. Enterprise risk management, 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 2013 commodity price sensitivities, refer to Section 3.0 of the 2013 Annual Management 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 could negatively affect the Company’s reputation, investor confidence and the Company’s ability to deliver on its growth strategy.

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To maintain the Company’s future production of crude oil, natural gas and NGL and maintain the value of the reserves portfolio, additional reserves must be added through discoveries, extensions, improved recovery, performance related revisions and acquisitions. The production rate of oil and gas properties tends to decline as reserves are depleted, while the associated unit operating costs increase. To mitigate the effects of this, the Company must undertake successful exploration and development programs, increase the recovery factor from existing properties through applied technology, and identify and execute strategic acquisitions of proved developed and undeveloped properties and unproved prospects. Maintaining an inventory of potential development 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 and Pipeline Interruptions

Husky’s results depend upon its 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 by regulatory and/or other marketplace barriers. The interruptions and restrictions may be caused by the inability of a pipeline to operate, or they can be related to capacity constraints as the supply of feedstock into the system exceeds the infrastructure capacity. With growing 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. Unplanned shutdowns and closures of Husky’s refineries or upgrader may limit the Company’s ability to deliver product with negative implications on sales from operating activities.

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. Security and terrorist threats may also impact the Company’s personnel, which could result in death, injury, hostage taking and/or kidnapping. This 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. This could 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 could precipitate a human resource risk for the Company. Failure to manage any of the foregoing developments, retain current employees and attract new skilled employees could materially affect the Company’s ability to conduct its business.

AIF 2013 Page 68

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. Estimates of the economically recoverable oil and gas reserves attributable to any particular group of properties, prepared by different engineers or by the same engineers at different times, may vary substantially. All reserves estimates 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, anti-corruption laws, reserves access, limitations or increases 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.

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.

AIF 2013 Page 69

Following the 2010 Deepwater Horizon oil spill in the Gulf of Mexico, the United States implemented stricter regulation of offshore oil and gas operations 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.

The transportation of crude oil by rail is an emerging issue for the petroleum industry. There have been four major incidents in the past eight months involving Bakken crude oil transported on rail, and federal and industry reviews of regulations and equipment standards are underway. In January 2014, Transport Canada announced proposed regulatory amendments to further improve the safety of the transportation of dangerous goods by rail. This may result in stricter standards, larger fines and liabilities, and increased capital expenditures for the petroleum industry.

Climate Change Regulation

Husky continues to monitor the international and domestic efforts to address climate change, including international low carbon fuel standards and regulations and emerging regulations in the jurisdictions in which the Company operates. Existing regulations in Alberta require facilities that emit more than 100,000 tonnes of carbon dioxide equivalent in a year to reduce their emissions intensity by up to 12% below an established baseline emissions intensity. These regulations currently affect Husky’s Ram River Gas Plant and Tucker Thermal Oil Facility and are anticipated to affect the Sunrise Energy Project when it begins to produce oil. British Columbia currently has a $30 per tonne carbon tax that is placed on fuel Husky uses in that jurisdiction, which affects all of Husky’s operations in British Columbia. The Saskatchewan government is anticipated to release regulations similar to Alberta’s and the Federal Government of Canada has announced pending regulations for the oil and gas sector. Climate change regulations may become more onerous over time as public and political pressures increase to implement initiatives that further reduce the emissions of greenhouse gases. Although the impact of emerging regulation is uncertain, they may adversely affect the Company’s operations and increase costs.

In addition, the Company’s operations may be materially impacted by application of the EPA’s climate change rules or by future U.S. greenhouse gas legislation that applies 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.

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. 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 the rating agencies are not recommendations to purchase, hold or sell the securities in as much as such ratings do not comment as to market price or suitability for a particular investor. Any rating may not remain in effect for any given period of time or may be revised or withdrawn entirely by a rating agency in the future if in its judgment circumstances so warrant.

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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 lack of availability of oil and gas field equipment could adversely affect the Company’s ability to undertake exploration, development and construction projects. The oil and gas industry is cyclical in nature and is prone to shortages of supply of equipment and services including 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. This 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 adverse financial impacts.

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 a discussion of commodity price risk, see “Risk Factors—Commodity Price Volatility”.

Foreign Currency Risk

Husky’s results are affected by the exchange rates between various currencies including the Canadian and U.S. dollars. 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, 2013, the amount that the Company designated was U.S. $3.2 billion (December 31, 2012 - U.S. $2.8 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.

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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 EMPLOYEES

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

As at December 31,
2013		2012		2011
	5,479		5,178		4,726

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:

	2013		2012		2011
Dividends per Common Share	$	1.20	$	1.20	$	1.20
Dividends per Series 1 Preferred Share	$	1.11	$	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.

Prior to December 2013, shareholders had the ability to receive dividends in common shares or in cash. Quarterly dividends were declared in an amount expressed in dollars per common share and could be paid by way of issuance of a fraction of a common share per outstanding common share determined by dividing the dollar amount of the dividend by the volume weighted average trading price of the common shares on the principal stock exchange on which the common shares are traded. The volume weighted average trading price of the common shares was calculated by dividing the total value by the total volume of common shares traded over the five trading day period immediately prior to the payment date of the dividend on the common shares. The Board of Directors discontinued the payment of dividends by way of the issuance of common shares effective with the dividend declaration in February 2014.

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. During 2013, the Board of Directors discontinued the payment of dividends by way of the issuance of common shares. The change was effective with the dividend declaration in February 2014. 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.”

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.”

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.

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	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 creditworthiness 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.

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 creditworthiness 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, 2013:

	High		Low		Volume (000’s)
January		32.34		28.80		21,764
February		31.94		30.16		17,680
March		31.97		28.86		21,277
April		30.35		27.29		19,157
May		31.51		28.50		17,433
June		29.76		26.97		17,584
July		30.68		27.25		16,477
August		30.22		28.75		13,572
September		30.37		28.77		14,235
October		30.09		28.50		17,472
November		31.09		29.37		17,172
December		33.85		29.96		17,374

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, 2013:

	High		Low		Volume (000’s)
January		26.73		25.98		440
February		26.89		26.10		414
March		26.98		26.42		336
April		26.76		25.50		511
May		26.22		25.30		135
June		25.74		23.02		172
July		25.00		23.27		180
August		24.00		22.53		164
September		23.95		23.00		159
October		23.39		22.45		293
November		23.94		22.70		481
December		23.92		22.36		315

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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 the five preceding years. Each director will hold office until the Company’s next annual meeting or until his or her successor is appointed or elected.

Directors

Name & Residence	Office or Position	Principal Occupation During Past Five Years
Li, Victor T.K. Hong Kong Special Administrative Region	Co-Chair Director of Husky since August 2000	Mr. Li is Managing Director, Deputy Chairman and Chairman of the Executive Committee 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); a Non-Executive Director of Power Assets Holdings Limited (a holding company) (re-designated from an Executive Director to a Non-Executive Director since January 2014); and a non-executive Director of The Hongkong and Shanghai Banking Corporation Limited. Mr. Li is also the Deputy Chairman of Li Ka Shing Foundation Limited, Li Ka Shing (Overseas) Foundation and Li Ka Shing (Canada) Foundation.
		Mr. Li is a member of the Standing Committee of the 12th National Committee of the Chinese People’s Political Consultative Conference of the People’s Republic of China 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. 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 Master 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.

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Fok, Canning K.N. Hong Kong Special Administrative Region	Co-Chair and Chair of the Compensation Committee Director of Husky since August 2000	Mr. Fok is Group Managing Director and an Executive Director of Hutchison Whampoa Limited. Mr. Fok is Chairman and a Director of Hutchison Harbour Ring Limited, Hutchison Telecommunications Hong Kong Holdings Limited, Hutchison Telecommunications (Australia) Limited, Hutchison Port Holdings Management Pte. Limited as the trustee-manager of Hutchison Port Holdings Trust, Power Assets Holdings Limited, HK Electric Investments Manager Limited as the trustee-manger of HK Electric Investments, and HK Electric Investments Limited. Mr. Fok is Deputy Chairman and an Executive Director of Cheung Kong Infrastructure Holdings Limited, a Non-Executive Director of Cheung Kong (Holdings) Limited and 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. Beijing, People’s Republic of China	Member of Corporate Governance Committee Director of Husky since July 2010	Mr. Bradley is a Director of Broadlea Group Ltd., Vice Chairman, Beijing Uni-Alliance Property Development Co. Ltd., Senior Consultant, ICAP (Asia Pacific) Ltd. and a Director of Swire Properties Ltd. (Hong Kong).
		Mr. Bradley entered the British Diplomatic Service in 1981 and served in various capacities, including Director of Trade & Investment Promotions (Paris) from 1999 to 2002; Minister, Deputy Head of Mission & Consul-General (Beijing) from 2002 to 2003 and HM Consul-General (Hong Kong) from 2003 to 2008. Mr. Bradley also worked in the private sector as Marketing Director, Guinness Peat Aviation (Asia) from 1987 to 1988 and Associate Director, Lloyd George Investment Management (now part of BMO Global Asset Management) from 1993 to 1995. Mr. Bradley retired from the Diplomatic Service in 2009.
		Mr. Bradley obtained a Bachelor of Arts degree from Balliol College, Oxford University in 1980 and a post-graduate diploma from Fudan University, Shanghai in 1981.
Ghosh, Asim Alberta, Canada	President & Chief Executive Officer Director of Husky since May 2009	Mr. Ghosh was appointed the President & 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 Chair of UBC Investment Management Trust Inc. He was also recently appointed to the Public Sector Pension Investment Board.
		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.
Koh, Poh Chan Hong Kong Special Administrative Region	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).

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		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. Hong Kong Special Administrative Region	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 Special Administrative Region publicly listed companies in his career. He was also a former Principal Official with the Hong Kong Special Administrative Region Government.
		In addition to being a Director of Husky Energy Inc., he is currently an independent Non-Executive Director and Chairman of the Audit Committee of Agricultural Bank of China Limited and Aluminum Corporation of China Limited and an independent Non-Executive Director of Hutchison Port Holdings Management Pte. Limited and MTR Corporation Limited. Mr. Ma is also a Non-Executive Director of COFCO Corporation, China Mobile Communications Corporation and FWD Group Management Holdings Limited.

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		In July 2002, Mr. Ma joined the Government of the Hong Kong Special Administrative Region as the Secretary for Financial Services and the Treasury. He assumed the post of Secretary for Commerce and Economic Development in July 2007, but resigned from the Government in July 2008 due to medical reasons. Mr. Ma was appointed as a member of the International Advisory Council of China Investment Corporation in July 2009. In January 2013, he was appointed as a member of the Global Advisory Council of Bank of America. Mr. Ma was appointed as an Honorary Professor of the School of Economics and Finance at the University of Hong Kong in October 2008 and as a Professor of Finance Practice of the Institute of Advanced Executive Education at the Hong Kong Polytechnic University in July 2012. In August 2013, he was appointed as an Honorary Professor of the Faculty of Business Administration at the Chinese University of Hong Kong.
		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 Special Administrative Region	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 1963.
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. He is an Executive Director of Power Assets Holdings Limited. 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 Chief Financial Officer of Husky Energy Inc. from 2000 to 2005. Before joining Husky Oil Limited in 1998, 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.

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Russel, Colin S. Gloucestershire, United Kingdom	Member of the Audit Committee and the Health, Safety and Environment Committee Director of Husky since February 2008	Mr. Russel is the founder and Managing Director of Emerging Markets Advisory Services Ltd. (a business advisory company).
		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. Previously, Mr. Russel was an international project manager with RCA Ltd., Canada and development engineer with AEI Ltd., UK
		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 Director of Husky since August 2000	Mr. Shaw is the President of Imperial Valley Holdings Ltd., and prior to his retirement in April 2013, a Senior Partner with Stikeman Elliott LLP, Barristers and Solicitors. Mr. Shaw is also a Director of the Li Ka Shing (Canada) Foundation.
		Mr. Shaw holds a Bachelor of Arts degree and a Bachelor of Laws degree, both received from the University of Alberta in 1967. He is a member of the Law Society of Upper Canada.
Shurniak, William Saskatchewan, Canada	Deputy Chair 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).
		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.

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Sixt, Frank J. Hong Kong Special Administrative Region	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 a Non-Executive Chairman of TOM Group Limited, an Executive Director of Cheung Kong Infrastructure Holdings Limited, a Non-Executive Director of Cheung Kong (Holdings) Limited, Hutchison Telecommunications Hong Kong Holdings Limited, Hutchison Port Holdings Management Pte. Limited as the trustee-manager of Hutchison Port Holdings Trust, and Power Assets Holdings Limited 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 Company Ltd. from 1998 to 2009 and a Non-Executive Director of Hutchison Telecommunications International Limited from 2004 to 2010.
		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 Five Years
Cowan, Alister	Chief Financial	Chief Financial Officer of Husky since July 2008.
Alberta, Canada	Officer
Peabody, Robert J.	Chief Operating	Chief Operating Officer of Husky since January 2006.
Alberta, Canada	Officer
Girgulis, James D.	Senior Vice	Vice President, Legal & Corporate Secretary of Husky since
Alberta, Canada	President, General Counsel & Secretary	August 2000. Senior Vice President, General Counsel & Secretary since April 2012.

As at February 25, 2014, the directors and officers of Husky, as a group, beneficially owned or controlled or directed, directly or indirectly, 727,807 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 that require that directors act honestly, in good faith and with a view to the best interests of Husky and, in respect of the Business Corporations Act (Alberta), Husky’s governing statute that directors declare, and refrain from voting on, any matter in which a director may have a conflict of interest.

Corporate Cease Trade Orders or Bankruptcies

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

In addition, none of those persons who are directors or executive officers of Husky is, or has been within the past ten years, a director or executive officer of any company, including Husky and any personal holding companies of such persons, that while such person was acting in that capacity, or within a year of that person ceasing to act in that capacity became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manger or trustee appointed to hold its assets, other than as follows. Victor T. K. Li was a director of Star River Investment Limited, a Hong Kong Special Administrative Region 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.

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.

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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 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 Special Administrative Region 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.”

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)	2013		2012
Audit Fees		3,218		3,822
Audit-related Fees		158		152
Tax Fees		134		230
All Other Fees		—		—
		3,510		4,204

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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 2013.

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.

INTERESTS OF EXPERTS

Excluding the reserves attributed to the Heavy Oil and Gas business unit, other than the Tucker property, certain information relating to the Company’s reserves included in this AIF has been calculated by the Company and audited and opined upon as at December 31, 2013 by McDaniel & Associates Consultants Ltd. (“McDaniel”). Sproule Unconventional Limited (“Sproule”), evaluated and reported on the reserves attributed to the Company’s Heavy Oil and Gas business unit, excluding the Tucker property, as at December 31, 2013, and that reserves information is included in this AIF. Both McDaniel and Sproule are independent petroleum engineering consultants retained by Husky, and such reserves information has been so included in reliance on the opinion and analysis of McDaniel and Sproule, respectively, given upon the authority of said firms as experts in reserves engineering. The partners of McDaniel and Sproule, respectively, as a group beneficially own, directly or indirectly, less than 1% of the Company’s securities of any class.

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

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ADDITIONAL INFORMATION

Additional information, including directors’ and officers’ remuneration, principal shareholders of Husky’s common shares and a description of options to purchase common shares will be contained in Husky’s Management Information Circular prepared in connection with the annual meeting of shareholders to be held on May 7, 2014.

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, 2013.

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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READER ADVISORIES

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; the Company’s expected methods of funding future development costs; and the Company’s 2014 production guidance, including weighting of production amount product types;

• with respect to the Company’s Asia Pacific Region: expected timing of first production and sale of commercial product from the Company’s Liwan Gas Project; planned tie-in and expected timing of production of the Company’s Liuhua 34-2 field; expected timing of completion of the acquisition of a seismic survey at the Company’s offshore Taiwan exploration block; and scheduled timing and duration of the Liwan Gas Project production going off-line;

• with respect to the Company’s Atlantic Region: expected timing of the completion of the West Mira rig; expected timing and benefits of gas injection, expected timing of installation of oil production equipment, and anticipated timing of first production at the Company’s South White Rose Extension project; planned 2014 drilling operations in the Terra Nova oil field; anticipated volume of production and timing of production from the wellhead platform at the Company’s White Rose Extension Project; and anticipated timing of and plans for a seismic survey in the Flemish Pass Basin and further delineation drilling and exploration in the Flemish Pass Basin and Jeanne d’Arc Basin;

• with respect to the Company’s Oil Sands properties: scheduled timing of start up and anticipated volumes of production at the Company’s Sunrise Energy Project; targeted timing of turn over of well pads at the Company’s Sunrise Energy Project; and anticipated timing of drilling and field development at the Company’s Tucker Oil Sands Project;

• with respect to the Company’s Heavy Oil properties: anticipated volumes of production at the Company’s Sandall heavy oil thermal development project; expected timing of first production and anticipated volumes of production at the Company’s Rush Lake heavy oil thermal development project; scheduled timing of construction and first production, and anticipated volumes of production, at the Company’s Edam East and Vawn heavy oil thermal developments; and the Company’s horizontal and CHOPS drilling program for 2014;

• with respect to the Company’s Western Canadian oil and gas resource plays: 2014 drilling plans in McMullen; 2014 drilling plans for the Wapati, Elrose and Alliance areas; and conventional oil drilling plans for southern Alberta;

• with respect to the Company’s Infrastructure and Marketing operations: anticipated timing of bringing two new 300,000 barrel tanks into service at the Hardisty terminal; Husky’s intention to develop a flexible crude oil delivery strategy; and the Company’s plans to expand its marketing activities; and

• with respect to the Company’s Downstream operating segment: the anticipated benefits from and scheduled timing of completion of the Lima, Ohio refinery reconfiguration and the anticipated processing capacity once reconfiguration is complete; plans to expand the bitumen processing capacity of the BP-Husky Toledo Refinery; the anticipated benefits from and scheduled timing of completion of a Hydrotreater Recycle Gas Compressor Project at the BP-Husky Toledo Refinery; the Company’s plans to permit the Lloydminster Asphalt Refinery to run year round; and the Company’s 2014 plans for its asphalt distribution network.

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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. There are numerous uncertainties inherent in estimating quantities of reserves and resources and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary from reserve, resource and production estimates.

Although the Company believes that the expectations reflected by the forward-looking statements presented in this AIF are reasonable, the Company’s forward-looking statements have been based on assumptions and factors concerning future events that may prove to be inaccurate. Those assumptions and factors are based on information currently available to the Company about itself and the businesses in which it operates. Information used in developing forward-looking statements has been acquired from various sources including third party consultants, suppliers, 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, Western Canadian oil and gas resource plays and Infrastructure and Marketing operations: 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 the Company’s projects, for which the Company or a third party is the designated operator, that may result from the inability of suppliers to meet their commitments, lack of regulatory or third-party approvals or other governmental actions, harsh weather or other calamitous event; the absence of significant disruption of operations such as may result from harsh weather, natural disaster, accident, civil unrest or other calamitous event; the absence of significant unexpected technological or commercial difficulties that adversely affect exploration, development, production, processing or transportation; the sufficiency of budgeted capital expenditures in carrying out planned activities; and the absence of significant increases in the cost of major growth projects; and

• with respect to the Company’s Downstream operating segment: the absence of significant delays of the development, construction or commissioning of the Company’s projects that may result from the inability of suppliers to meet their commitments, lack of regulatory or third-party approvals or other governmental actions, harsh weather or other calamitous event; the absence of significant disruption of operations such as may result from harsh weather, natural disaster, accident, civil unrest or other calamitous event; the absence of significant unexpected technological or commercial difficulties that adversely affect processing or transportation; the sufficiency of budgeted capital expenditures in carrying out planned activities; and the absence of significant increase in the cost of major growth projects.

Because actual results or outcomes could differ materially from those expressed in any forward-looking statements, investors should not place undue reliance on any such forward-looking statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the predicted outcomes will not occur. Some of these risks, uncertainties and other factors are similar to those faced by other oil and gas companies and some are unique to Husky. The risks, uncertainties and other factors, many of which are beyond Husky’s control, that could cause actual results to differ (potentially significantly) from those expressed in the forward-looking statements include, but are not limited to:

• with respect to the business, operations and results of the Company generally: those risks, uncertainties and other factors described under “Risk Factors” in this AIF and throughout the Company’s Management’s Discussion and Analysis for the year ended December 31, 2013; the demand for the Company’s products and prices received for crude oil and natural gas production and refined petroleum products; the economic

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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, Western Canadian oil and gas resource plays and the Infrastructure and Marketing operations: the availability of prospective drilling rights; the costs to acquire exploration rights, undertake geological studies, appraisal drilling and project development; the availability and cost of labour, technical expertise, material and equipment to efficiently, effectively and safely undertake capital projects; the costs to operate properties, plants and equipment in an efficient, reliable and safe manner; prevailing climatic conditions in the Company’s operating locations; regulations to deal with climate change issues; the competitive actions of other companies, including increased competition from other oil and gas companies; business interruptions because of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events affecting the Company or other parties whose operations or assets directly or indirectly affect the Company and that may or may not be financially recoverable; the co-operation of business partners especially where the Company is not operator of production projects or developments in which it has an interest; the inability to obtain regulatory approvals to operate existing properties or develop significant growth projects; risk associated with transportation of production or product to market or transportation of feedstock to processing facilities resulting from an interruption in pipeline and other transportation services both owned and contracted, due to calamitous event or regulatory obligation; and the inability to reach estimated production levels from existing and future oil and gas development projects as a result of technological or commercial difficulties; 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, 2013 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 2013 Page 90

Disclosure of Oil and Gas Information

Unless otherwise stated, reserve and resource estimates in this document have an effective date of December 31, 2013 and represent Husky’s share. Unless otherwise noted, historical production numbers given represent Husky’s share.

The Company has disclosed best-estimate contingent resources in this document. Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters, or a lack of markets. There is no certainty that it will be commercially viable to produce any portion of the contingent resources.

Best estimate as it relates to resources is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Estimates of contingent resources have not been adjusted for risk based on the chance of development. There is no certainty as to the timing of such development. For movement of resources to reserves categories, all projects must have an economic depletion plan and may require, among other things: (i) additional delineation drilling for unrisked contingent resources; (ii) regulatory approvals; and (iii) Company and partner approvals to proceed with development.

Specific contingencies preventing the classification of contingent resources at the Company’s Atlantic Region discoveries as reserves include additional exploration and delineation drilling, well testing, facility design, preparation of firm development plans, regulatory applications, Company and partner approvals.

Positive and negative factors relevant to the estimate of Atlantic Region resources include water depth and distance from existing infrastructure.

Note to U.S. Readers

The Company reports its reserves and resources information in accordance with Canadian practices and specifically in accordance with National Instrument 51-101, “Standards of Disclosure for Oil and Gas Disclosure”, adopted by the Canadian securities regulators. Because the Company is permitted to prepare its reserves and resources information in accordance with Canadian disclosure requirements, it uses certain terms in this document, such as “best estimate contingent resources” that U.S. oil and gas companies generally do not include or may be prohibited from including in their filings with the SEC.

.

AIF 2013 Page 91

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.

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.

AIF 2013 Page 92

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.

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.

AIF 2013 Page 93

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.

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.

AIF 2013 Page 94

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 2013 Page 95

Schedule B

Husky Energy Inc.

Report on Reserves Data by Internal Qualified Reserves Evaluator

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

1. Other than the reserves data attributed to the Heavy Oil and Gas business unit (excluding the Tucker property), which was evaluated and reported on by an external independent reserves evaluator as at December 31, 2013, our staff has evaluated all remaining Husky reserves data as at December 31, 2013. Husky’s staff has also reviewed the external independent reserves evaluation. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2013, 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, 2013 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)
Canada	$	26,999 million
China	$	5,221 million
Indonesia	$	247 million
Libya	$	5 million
	$	32,472 million

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.

8. I have signed this report in my capacity as an employee of Husky and not in my personal capacity.

/s/ Frederick Au-Yeung

Frederick Au-Yeung, P. Eng

Manager, Reserves

Calgary, Alberta

January 28, 2014

AIF 2013 Page 96

Husky Energy Inc.

Report on Reserves Data by Qualified Reserves Evaluator

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

1. We have evaluated the Company’s reserves data as at December 31, 2013. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2013, attributed to the Company’s Lloydminster Heavy Oil Group (excluding the Tucker property), estimated using forecast prices and costs.

2. The reserves data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation. We carried out our evaluation in accordance with 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).

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 principles and definitions presented in the COGE Handbook.

4. The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us as of December 31, 2013, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company’s management and Board of Directors:

Independent Qualified Reserves Evaluator or Auditor	Description and Preparation Date of Evaluation Report	Location of Reserves (Country)		Net Present Value of Future Net Revenue Before Income Taxes (10% Discount Rate)
				Audited (M$)		Evaluated (M$)		Reviewed (M$)		Total (M$)
Sproule	Evaluation of the P&NG Reserves of Husky Energy Inc. in the Lloydminster Heavy Oil Group (excluding the Tucker property), As of December 31, 2013, prepared September 2013 to January 2014		Canada
Total					Nil		8,376,878		Nil		8,376,878

5. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are presented in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.

6. We have no responsibility to update the report referred to in paragraph 4 for events and circumstances occurring after its preparation date.

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

AIF 2013 Page 97

Executed as to our report referred to above:

Sproule Unconventional Limited

/s/ James A. Chm,P.Eng.

James A. Chm,P.Eng.

Supervisor, Engineering and Partner

/s/ Art McMullen, P.Eng.

Art McMullen, P.Eng.

Manager, Engineering and Partner

/s/ Alec Kovaltchouk, P.Geo.

Alec Kovaltchouk, P.Geo.

Manager, Geoscience and Partner

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

Cameron P. Six, P.Eng.

Vice-President, Unconventional and Director

Calgary, Alberta

February 3, 2014

AIF 2013 Page 98

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, 2013, 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 Reserves, 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 external reserves auditors;

(b) met with the Internal Qualified Reserves Evaluator, the external reserves auditors and the external reserves evaluator to determine whether any restrictions placed by management affected the ability of the Internal Qualified Reserves Evaluator, the external reserves auditors and the external reserves evaluator to report without reservation; and

(c) reviewed the reserves data with management, the Internal Qualified Reserves Evaluator, the external reserves auditors and the external reserves evaluator.

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 Disclosure” to involve independent qualified oil and gas reserve evaluators or auditors. Notwithstanding this exemption, we involve independent qualified reserve auditors as part of Husky’s corporate governance practices. Their involvement helps assure that our internal oil and gas reserve 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 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 2013 Page 99

/s/ Asim Ghosh	March 6, 2014
Asim Ghosh
President & Chief Executive Officer
/s/ Robert J. Peabody	March 6, 2014
Robert J. Peabody
Chief Operating Officer
/s/ William Shurniak	March 6, 2014
William Shurniak
Director
/s/ Colin S. Russel	March 6, 2014
Colin S. Russel
Director

AIF 2013 Page 100

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 Husky internally generated reserves estimates and the respective net present values as at December 31, 2013. Husky internally evaluates all their properties with the exception of the Lloydminster business unit. The Tucker Property is internally evaluated. Husky’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 test basis, to confirm that there is adherence on the part of Husky’s internal reserve evaluators and other employees to the reserves management and administration policies and procedures established by the company. An audit also includes conducting reserves evaluation on a sufficient number of the company’s internally evaluated properties as considered necessary in order to express an opinion.

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 below:

Husky Energy

Internally Evaluated Reserves and Net Present Values

Forecast Prices and Costs as of December 31^st, 2013

	Company Share of Remaining Reserves (mmboe)		Company Share of Net Present Value Remaining Reserves Before Income Tax (MM$) @ 10%
Total Proved		1,099		14,476
Total Proved Plus Probable		2,723		24,095

Sincerely,

McDaniel & Associates Consultants Ltd.

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

B. J. Wurster, P. Eng.

Vice President

Calgary, Alberta

January 17, 2014

AIF 2013 Page 101

Document B

Form 40-F

Consolidated Financial Statements and

Auditors’ Report to Shareholders

For the Year Ended December 31, 2013

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, 2013 and December 31, 2012, 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, 2013 and December 31, 2012, 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, 2013, based on the criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 25, 2014 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

Calgary, Canada

February 25, 2014

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, 2013, based on the criteria established in Internal Control—Integrated Framework (1992) 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, 2013, based on the criteria established in Internal Control—Integrated Framework (1992) 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, 2013 and December 31, 2012, 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, 2013, and our report dated February 25, 2014 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

KPMG _LLP

Chartered Accountants

Calgary, Canada

February 25, 2014

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, 2013. 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 & Chief Executive Officer

Alister Cowan

Chief Financial Officer

Calgary, Canada

February 25, 2014

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, 2013 and December 31, 2012, 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, 2013 and December 31, 2012, 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 25, 2014

Consolidated Financial Statements  2

CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Balance Sheets

(millions of Canadian dollars)	December 31, 2013		December 31, 2012
Assets
Current assets
Cash and cash equivalents (note 9)		1,097		2,025
Accounts receivable (notes 3, 4)		1,458		1,345
Income taxes receivable		461		323
Inventories (note 5)		1,812		1,736
Prepaid expenses		89		64
		4,917		5,493
Exploration and evaluation assets (notes 3, 6)		1,144		773
Property, plant and equipment, net (notes 3, 7)		29,750		27,354
Goodwill (note 10)		698		663
Contribution receivable (note 8)		136		607
Investment in joint ventures (notes 3, 8)		153		132
Other assets (note 3)		106		139
Total Assets		36,904		35,161
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities (notes 3, 12)		3,155		2,985
Asset retirement obligations (note 16)		210		107
Long-term debt due within one year (note 13)		798		—
		4,163		3,092
Long-term debt (note 13)		3,321		3,918
Other long-term liabilities (notes 3, 15)		271		328
Contribution payable (notes 8, 22)		1,421		1,336
Deferred tax liabilities (notes 3, 17)		4,942		4,640
Asset retirement obligations (note 16)		2,708		2,686
Commitments and contingencies (note 20)
Total Liabilities		16,826		16,000
Shareholders’ equity
Common shares (note 18)		6,974		6,939
Preferred shares (note 18)		291		291
Retained earnings		12,615		11,950
Other reserves		198		(19	)
Total Shareholders’ Equity		20,078		19,161
Total Liabilities and Shareholders’ Equity		36,904		35,161

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

	Year ended December 31,
(millions of Canadian dollars, except share data)	2013			2012
Gross revenues		23,869			22,550
Royalties		(864	)		(693	)
Marketing and other		312			398
Revenues, net of royalties		23,317			22,255
Expenses
Purchases of crude oil and products		14,067			13,416
Production and operating expenses		2,793			2,610
Selling, general and administrative expenses		558			448
Depletion, depreciation, amortization and impairment (note 7)		3,005			2,580
Exploration and evaluation expenses (note 6)		246			344
Other – net		(87	)		(123	)
		20,582			19,275
Earnings from operating activities		2,735			2,980
Share of equity investment (note 8)		(10	)		(11	)
Financial items (note 14)
Net foreign exchange gains		21			14
Finance income		51			93
Finance expenses		(169	)		(240	)
		(97	)		(133	)
Earnings before income taxes		2,628			2,836
Provisions for income taxes (note 17)
Current		589			536
Deferred		210			278
		799			814
Net earnings		1,829			2,022
Earnings per share (note 18)
Basic		1.85			2.06
Diluted		1.85			2.06
Weighted average number of common shares outstanding (note 18)
Basic (millions)		983.0			975.8
Diluted (millions)		983.6			975.9

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)	2013			2012
Net earnings		1,829			2,022
Other comprehensive income (loss)
Items that will not be reclassified into earnings, net of tax:
Remeasurements of pension plans, net of tax (note 19)		20			15
Items that may be reclassified into earnings, net of tax:
Derivatives designated as cash flow hedges (note 22)		36			3
Exchange differences on translation of foreign operations		361			(95	)
Hedge of net investment (note 22)		(180	)		15
Other comprehensive income (loss)		237			(62	)
Comprehensive income		2,066			1,960

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		Preferred Shares		Retained Earnings			Foreign Currency Translation			Hedging			Total Shareholders’ Equity
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)
Remeasurements of pension plans (net of tax of $5 million)		—		—		15			—			—			15
Derivatives designated as cash flow hedges (net of tax of $1 million) (note 22)		—		—		—			—			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 (note 18)		607		—		—			—			—			607
Stock options exercised (note 18)		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
Net earnings		—		—		1,829			—			—			1,829
Other comprehensive income (loss)
Remeasurements of pension plans (net of tax of $7 million)		—		—		20			—			—			20
Derivatives designated as cash flow hedges (net of tax of $13 million) (note 22)		—		—		—			—			36			36
Exchange differences on translation of foreign operations (net of tax of $58 million)		—		—		—			361			—			361
Hedge of net investment (net of tax of $27 million) (note 22)		—		—		—			(180	)		—			(180	)
Total comprehensive income (loss)		—		—		1,849			181			36			2,066
Transactions with owners recognized directly in equity:
Stock dividends paid (note 18)		8		—		—			—			—			8
Stock options exercised (note 18)		27		—		—			—			—			27
Dividends declared on common shares (note 18)		—		—		(1,180	)		—			—			(1,180	)
Dividends declared on preferred shares (note 18)		—		—		(13	)		—			—			(13	)
Change in accounting policy (note 3)		—		—		9			—			—			9
Balance as at December 31, 2013		6,974		291		12,615			161			37			20,078

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)	2013			2012
Operating activities
Net earnings		1,829			2,022
Items not affecting cash:
Accretion (note 14)		125			97
Depletion, depreciation, amortization and impairment (note 7)		3,005			2,580
Exploration and evaluation expenses		10			60
Deferred income taxes (note 17)		210			278
Foreign exchange		11			(20	)
Stock-based compensation (note 18)		105			54
Loss (gain) on sale of assets		(27	)		1
Other		(46	)		(62	)
Settlement of asset retirement obligations (note 16)		(142	)		(123	)
Income taxes paid		(433	)		(575	)
Interest received		19			34
Change in non-cash working capital (note 9)		(21	)		847
Cash flow – operating activities		4,645			5,193
Financing activities
Long-term debt issuance		—			500
Long-term debt repayment (note 13)		—			(410	)
Settlement of cross currency swaps		—			(89	)
Debt issue costs		—			(9	)
Proceeds from exercise of stock options (note 18)		27			5
Dividends on common shares (note 18)		(1,171	)		(557	)
Dividends on preferred shares (note 18)		(13	)		(17	)
Interest paid		(243	)		(252	)
Contribution receivable payment (note 8)		520			563
Other		53			25
Change in non-cash working capital (note 9)		(19	)		79
Cash flow – financing activities		(846	)		(162	)
Investing activities
Capital expenditures		(5,028	)		(4,701	)
Proceeds from asset sales		37			24
Contribution payable payment (note 8)		(87	)		(152	)
Other		(8	)		(61	)
Change in non-cash working capital (note 9)		364			56
Cash flow – investing activities		(4,722	)		(4,834	)
Increase (decrease) in cash and cash equivalents		(923	)		197
Effect of exchange rates on cash and cash equivalents		(5	)		(13	)
Cash and cash equivalents at beginning of year		2,025			1,841
Cash and cash equivalents at end of year		1,097			2,025

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.

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, the 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 China, offshore Indonesia and offshore Taiwan.

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).

Consolidated Financial Statements  8

Segmented Financial Information

	Upstream
($ millions)	Exploration and Production(1)						Infrastructure and Marketing						Total
Year ended December 31,	2013			2012			2013			2012			2013			2012
Gross revenues(3)		7,333			6,581			2,134			2,377			9,467			8,958
Royalties		(864	)		(693	)		—			—			(864	)		(693	)
Marketing and other(3)		—			—			312			398			312			398
Revenues, net of royalties		6,469			5,888			2,446			2,775			8,915			8,663
Expenses
Purchases of crude oil and products(3)		91			73			2,004			2,258			2,095			2,331
Production and operating expenses		2,016			1,875			14			12			2,030			1,887
Selling, general and administrative expenses		240			175			19			21			259			196
Depletion, depreciation, amortization and impairment		2,515			2,121			20			22			2,535			2,143
Exploration and evaluation expenses		246			344			—			—			246			344
Other – net		(35	)		(105	)		(3	)		—			(38	)		(105	)
Earnings (loss) from operating activities		1,396			1,405			392			462			1,788			1,867
Share of equity investment		(10	)		(11	)		—			—			(10	)		(11	)
Financial items
Net foreign exchange gains		—			—			—			—			—			—
Finance income		4			5			—			—			4			5
Finance expenses		(107	)		(78	)		—			—			(107	)		(78	)
Earnings (loss) before income taxes		1,283			1,321			392			462			1,675			1,783
Provisions for (recovery of) income taxes
Current		162			134			222			171			384			305
Deferred		169			211			(122	)		(55	)		47			156
Total income tax provision (recovery)		331			345			100			116			431			461
Net earnings (loss)		952			976			292			346			1,244			1,322
Intersegment revenues		1,714			2,003			—			—			1,714			2,003
Other non-cash items
Gain (loss) on sale of assets		19			1			—			—			19			1

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

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

⁽³⁾  Gross revenues, marketing and other and purchases of crude oil and products have been recast to reflect a change in the classification of certain trading transactions.

Consolidated Financial Statements  9

Downstream																								Corporate and Eliminations(2)						Total
Upgrading						Canadian Refined Products						U.S. Refining and Marketing						Total
2013			2012			2013			2012			2013			2012			2013			2012			2013			2012			2013			2012
	2,023			2,191			3,737			3,848			10,728			9,856			16,488			15,895			(2,086	)		(2,303	)		23,869			22,550
	—			—			—			—			—			—			—			—			—			—			(864	)		(693	)
	—			—			—			—			—			—			—			—			—			—			312			398
	2,023			2,191			3,737			3,848			10,728			9,856			16,488			15,895			(2,086	)		(2,303	)		23,317			22,255
	1,378			1,636			3,134			3,208			9,546			8,544			14,058			13,388			(2,086	)		(2,303	)		14,067			13,416
	161			150			193			184			409			385			763			719			—			4			2,793			2,610
	7			3			60			58			15			13			82			74			217			178			558			448
	96			102			90			83			233			212			419			397			51			40			3,005			2,580
	—			—			—			—			—			—			—			—			—			—			246			344
	(27	)		(17	)		(5	)		(2	)		—			4			(32	)		(15	)		(17	)		(3	)		(87	)		(123	)
	408			317			265			317			525			698			1,198			1,332			(251	)		(219	)		2,735			2,980
	—			—			—			—			—			—			—			—			—			—			(10	)		(11	)
	—			—			—			—			—			—			—			—			21			14			21			14
	—			—			—			—			—			—			—			—			47			88			51			93
	(7	)		(11	)		(5	)		(6	)		(3	)		(5	)		(15	)		(22	)		(47	)		(140	)		(169	)		(240	)
	401			306			260			311			522			693			1,183			1,310			(230	)		(257	)		2,628			2,836
	19			31			65			89			18			(1	)		102			119			103			112			589			536
	85			49			1			(9	)		165			258			251			298			(88	)		(176	)		210			278
	104			80			66			80			183			257			353			417			15			(64	)		799			814
	297			226			194			231			339			436			830			893			(245	)		(193	)		1,829			2,022
	172			134			200			166			—			—			372			300			—			—			2,086			2,303
	—			—			8			(2	)		—			—			8			(2	)		—			—			27			(1	)

Consolidated Financial Statements  10

Segmented Financial Information

	Upstream
($ millions)	Exploration and Production(1)						Infrastructure and Marketing						Total
Year ended December 31,	2013			2012			2013			2012			2013			2012
Expenditures on exploration and evaluation assets(2)		575			273			—			—			575			273
Expenditures on property, plant and equipment(2)		3,689			3,833			96			54			3,785			3,887
As at December 31,
Exploration and evaluation assets		1,144			773			—			—			1,144			773
Developing and producing assets at cost		43,128			38,781			—			—			43,128			38,781
Accumulated depletion, depreciation, amortization and impairment		(20,439	)		(17,947	)		—			—			(20,439	)		(17,947	)
Other property, plant and equipment at cost		—			47			1,033			934			1,033			981
Accumulated depletion, depreciation and amortization		—			(29	)		(448	)		(414	)		(448	)		(443	)
Total exploration and evaluation assets and property, plant and equipment, net		23,833			21,625			585			520			24,418			22,145
Total assets		24,653			22,774			1,670			1,506			26,323			24,280

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

⁽²⁾  Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the period. Includes assets acquired through acquisitions.

Geographical Financial Information

($ millions)	Canada
Year ended December 31,	2013			2012
Gross revenues(1)(2)		11,926			11,356
Royalties		(794	)		(611	)
Marketing and other(2)		316			395
Revenue, net of royalties(2)		11,448			11,140
As at December 31,
Exploration and evaluation assets		855			496
Property, plant and equipment, net		22,928			21,718
Goodwill		160			160
Total non-current assets		24,152			23,090

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

⁽²⁾ Gross revenues and marketing and other have been recast to reflect a change in the classification of certain trading transactions.

Consolidated Financial Statements  11

Downstream																								Corporate and Eliminations						Total
Upgrading						Canadian Refined Products						U.S. Refining and Marketing						Total
2013			2012			2013			2012			2013			2012			2013			2012			2013			2012			2013			2012
	—			—			—			—			—			—			—			—			—			—			575			273
	205			47			109			97			220			313			534			457			134			84			4,453			4,428
	—			—			—			—			—			—			—			—			—			—			1,144			773
	—			—			—			—			—			—			—			—			—			—			43,128			38,781
	—			—			—			—			—			—			—			—			—			—			(20,439	)		(17,947	)
	2,221			2,006			2,332			2,189			5,020			4,487			9,573			8,682			775			643			11,381			10,306
	(1,046	)		(950	)		(1,046	)		(967	)		(1,257	)		(951	)		(3,349	)		(2,868	)		(523	)		(475	)		(4,320	)		(3,786	)
	1,175			1,056			1,286			1,222			3,763			3,536			6,224			5,814			252			168			30,894			28,127
	1,355			1,242			1,788			1,646			5,537			5,326			8,680			8,214			1,901			2,667			36,904			35,161

United States					Other International						Total
2013			2012		2013			2012			2013			2012
	11,663			10,822		280			372			23,869			22,550
	—			—		(70	)		(82	)		(864	)		(693	)
	(4	)		3		—			—			312			398
	11,659			10,825		210			290			23,317			22,255
	—			—		289			277			1,144			773
	3,764			3,535		3,058			2,101			29,750			27,354
	538			503		—			—			698			663
	4,320			4,055		3,515			2,523			31,987			29,668

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 the Chief Executive Officer on February 25, 2014, having been duly authorized to do so by the Board of Directors.

Certain prior years’ amounts have been recast to conform with current presentation, including the change in classification of certain trading activities.

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 and 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”), the determination of a joint arrangement, 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 and measured at fair value less costs to sell based on Level 2 observable inputs. 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 that are directly attributable to the purchase or development of an asset. Borrowing costs directly attributable to the acquisition, construction or production of a qualifying asset are included in the asset cost. Capitalization ceases when substantially all activities necessary to prepare the qualifying asset for its intended use are complete.

The appropriate accounting treatment of costs incurred for oil and natural gas exploration, evaluation and development is determined by the classification of the underlying activities as either exploratory or developmental. The results from an exploration drilling program can take considerable time to analyze, and the determination that commercial reserves have been discovered requires 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 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.

Consolidated Financial Statements  14

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 anticipated date of the next turnaround.

v) Depletion, depreciation and amortization

Oil and gas properties are depleted on a unit-of-production basis over the proved developed reserves of the particular field, except in the case of assets whose useful life is shorter or longer than the lifetime of the proved developed reserves of that field, in which case the straight-line method or a unit-of-production method based on total 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, with the exception of certain Heavy Oil properties that are evaluated by independent qualified reserve engineers, and audited by independent qualified reserve engineers. The estimation of reserves is an inherently complex process and involves the exercise of professional judgment. Estimates are based on projected future rates of production, estimated commodity prices, engineering data and the timing of future expenditures, all of which are subject to uncertainty. Changes in reserve estimates can have an impact on reported net earnings through revisions to depletion, depreciation and amortization expense, in addition to determining possible impairments of property, plant and equipment.

Net reserves represent the Company’s undivided gross working interest in total reserves after deducting crown, freehold and overriding royalty interests. Assumptions reflect market and regulatory conditions, as applicable, as at the balance sheet date and could differ significantly from other points in time throughout the year or future periods. Changes in market and regulatory conditions and assumptions can materially impact the estimation of net reserves.

Depreciation for substantially all other property, plant and equipment is provided using the straight-line method based on the estimated useful lives of assets, which range from five to forty-five years, less any estimated residual value. The useful lives of assets are estimated based upon the period the asset is expected to be available for use by the Company. Residual values are based upon the estimated amount that would be obtained on disposal, net of any costs associated with the disposal. Other property, plant and equipment held under finance leases are depreciated over the shorter of the lease term and the estimated useful life of the asset.

Depletion, depreciation and amortization rates for all capitalized costs associated with the Company’s activities are reviewed at least annually, or when events or conditions occur that impact capitalized costs, reserves and estimated service lives.

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.

Consolidated Financial Statements  15

e) Joint Arrangements

Joint arrangements represent activities where the Company has joint control established by a contractual agreement. Joint control requires unanimous consent for financial and operational decisions. A joint arrangement is either a joint operation, whereby the parties have rights to the assets and obligations for the liabilities, or a joint venture, whereby the parties have rights to the net assets.

For a joint operation the consolidated financial statements include the Company’s proportionate share of the assets, liabilities, revenues, expenses and cash flows of the 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.

Joint ventures are accounted for using the equity method of accounting and recognized at cost and adjusted thereafter for the post-acquisition change in the Company’s share of the joint venture’s net assets. The Company’s consolidated financial statements include its share of the joint venture’s profit or loss and other comprehensive income (“OCI”) included in investment in joint ventures, until the date that joint control ceases.

Determining the type of joint arrangement as either joint operation or joint venture is based on management’s assumptions of whether it has joint control over another entity. The considerations include, but are not limited to, determining if the arrangement is structured through a separate vehicle and whether the legal form and contractual arrangements give the entity direct rights to the assets and obligations for the liabilities within the normal course of business. Other facts and circumstances are also assessed by management, including the entity’s rights to the economic benefits of assets and its involvement and responsibility for settling liabilities associated with the arrangement.

f) Investments in Associates

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

g) Business Combinations

Business combinations are accounted for using the acquisition method. Determining whether an acquisition meets the definition of a business combination or represents an asset purchase requires judgment on a case-by-case basis. If the acquisition meets the definition of a business combination, the assets and liabilities are recognized based on the contractual terms, economic conditions, the Company’s operating and accounting policies, and other factors that exist on the acquisition date, which is the date on which control is transferred to the Company. The identifiable assets and liabilities are measured at their fair values on the acquisition date with limited exceptions. Any additional consideration payable, contingent upon the occurrence of a future event, is recognized at fair value on the acquisition date; subsequent changes in the fair value of the liability are recognized in net earnings. Acquisition costs incurred are expensed and included in other - net in the consolidated statements of income.

h) Goodwill

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

i) 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.

Consolidated Financial Statements  16

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 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 that 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 and probable volumes, which are risk-weighted utilizing geological, production, recovery, market price and economic projections. Either the cash flow estimates or the discount rate is risk-adjusted to reflect local conditions as appropriate.

Given that the calculations for recoverable amounts require the use of estimates and assumptions, including forecasts of commodity prices, marketing supply and demand, product margins and in the case of oil and gas properties, expected production volumes, it is possible that the assumptions may change, which may impact the estimated life of the CGU and may require a material adjustment to the carrying value of goodwill and non-financial assets.

An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses recognized with respect to CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the units and then to reduce the carrying amounts of the other assets in the CGU or group of CGUs on a pro rata basis. Impairment losses are recognized in depletion, depreciation, amortization and impairment in the consolidated statements of income.

Impairment losses recognized 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.

j) Asset Retirement Obligations (“ARO”)

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

Consolidated Financial Statements  17

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

k) Legal and Other Contingent Matters

Provisions and liabilities for legal and other contingent matters are recognized in the period when the circumstance becomes probable that a future cash outflow resulting from past operations or events will occur and the amount of the cash outflow can be reasonably estimated. The timing of recognition and measurement of the provision requires the application of judgment to existing facts and circumstances, which can be subject to change, and the carrying amounts of provisions and liabilities are reviewed regularly and adjusted accordingly. The Company is required to both determine whether a loss is probable based on judgment and interpretation of laws and regulations, and determine that the loss can be reasonably estimated. When a loss is recognized, it is charged to net earnings. The Company continually monitors known and potential contingent matters and makes appropriate provisions when warranted by the circumstances present.

l) Share Capital

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

m) Financial Instruments

Financial instruments are any contracts that give rise to a financial asset of one entity and a financial liability or equity instrument of another entity. Financial 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 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.

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.

n) Derivative Instruments and Hedging Activities

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

Consolidated Financial Statements  18

The fair values of derivatives are determined using valuation models that require assumptions concerning the amount and timing of future cash flows and discount rates. These estimates are also subject to change with fluctuations in commodity prices, interest rates, foreign currency exchange rates and estimates of non-performance. 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 held for trading and are recorded at fair value. Gains and losses on these instruments are recorded in the consolidated statements of income in the period they occur.

The Company may enter into commodity price contracts in order to offset fixed or floating prices with market rates to manage exposures to fluctuations in commodity prices. The estimation of the fair value of commodity derivatives incorporates forward prices and adjustments for quality or location. The related inventory is measured at fair value based on exit prices. Gains and losses from these derivative contracts, which are not designated as effective hedging instruments, are recognized in revenues or purchases of crude oil and products and are initially recorded at settlement date. Derivative instruments that have been designated as effective hedging instruments are further classified as either fair value or cash flow hedges (see “Hedging Activities”).

ii) Embedded Derivatives

Derivatives embedded 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, formal designation and documentation is required. The documentation must include: identification of the hedged item or transaction, the hedging instrument, the nature of the risk being hedged, the Company’s risk management objective and strategy for undertaking the hedge and how the Company will assess the hedging instrument’s effectiveness in offsetting the exposure to changes in the hedged item.

A hedge is assessed at inception and at the end of each reporting period to ensure that it is highly effective in offsetting changes in fair values or cash flows of the hedged item. For a fair value hedge, the gain or loss from remeasuring the hedging instrument at fair value is recognized immediately in net earnings with the offsetting gain or loss on the hedged item. When fair value hedge accounting is discontinued, the carrying amount of the hedging instrument is deferred and amortized to net earnings over the remaining maturity of the hedged item.

For a cash flow hedge, the effective portion of the gain or loss is recorded in OCI. Any hedge or portion of a hedge that is ineffective is immediately recognized in net earnings. Hedge accounting is discontinued on a prospective basis when the hedging relationship no longer qualifies for hedge accounting. Any gain or loss on the hedging instrument resulting from the discontinuation of a cash flow hedge is deferred in OCI until the forecasted transaction date. If the forecasted transaction date is no longer expected to occur, the gain or loss is recognized in net earnings in the period of discontinuation.

A net investment hedge of a foreign operation is accounted for similarly to a cash flow hedge. The Company may designate certain U.S. dollar denominated debt as a hedge of its net investment in foreign operations for which the U.S. dollar is the functional currency. The unrealized foreign exchange gains and losses arising from the translation of the debt are recorded in OCI, net of tax, and are limited to the translation gain or loss on the net investment.

o) Comprehensive Income

Comprehensive income consists of net earnings and OCI. OCI is comprised of the change in the fair value of the effective portion of the derivatives used as hedging items in a cash flow hedge or net investment hedge, the 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.

p) Impairment of Financial Assets

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

Consolidated Financial Statements  19

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. A revaluation 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 require the use of estimates and assumptions, including forecasts of commodity prices, marketing supply and demand, product margins and expected production volumes, it is possible that the assumptions may change, which may require a material adjustment to the carrying value of financial assets.

q) Pensions and Other Post-employment Benefits

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

The defined benefit asset or liability is comprised of the present value of the defined benefit obligation 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.

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 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.

r) 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.

Consolidated Financial Statements  20

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

Deferred tax assets and liabilities are recognized at expected tax rates in effect in the year when the asset is expected to be realized or the liability settled, based on tax rates and tax laws that have been enacted or substantively enacted at the reporting date. Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net earnings in the period that the change occurs unless it relates to items recognized directly to equity, including OCI, in which case the deferred income tax is also recorded in equity. Deferred tax assets and deferred tax liabilities are offset if a legally enforceable right exists to set off current tax assets against current income tax liabilities and the deferred taxes relate to the same taxable entity and the same taxation authority.

The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. Estimates that require significant judgments are also made with respect to the timing of temporary difference reversals, the realizability of tax assets and in circumstances where the transaction and calculations for which the ultimate tax determination are uncertain. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management.

s) Asset Exchange Transactions

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

t) Revenue Recognition

Revenue 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 or services 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.

u) Foreign Currency

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

The Company’s transactions in foreign currencies are translated to the appropriate functional currency at the foreign exchange rate on the dates of the transactions. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency at the foreign exchange rate at the balance sheet date and differences arising on translation are recognized in net earnings. Non-monetary assets that are measured in terms of historical cost in a foreign currency are translated using the exchange rate at the dates of the transactions.

Consolidated Financial Statements  21

v) Share-based Payments

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

The Company’s stock option plan is a tandem plan that provides the stock option holder with the right to exercise the stock option or surrender the option for a cash payment. A liability for the stock options is accrued over their vesting period and measured at fair value using the Black-Scholes option pricing model. The liability is revalued each reporting period until it is settled to reflect changes in the fair value of the options. The net change is recognized in net earnings. When stock options are surrendered for cash, the cash settlement paid reduces the outstanding liability. When stock options are exercised for common shares, consideration paid by the stock option holders and the previously recognized liability associated with the stock options are recorded as share capital.

The Company’s Performance Share Unit Plan provides a time-vested award to certain officers and employees of the Company. Performance Share Units (“PSU”) entitle participants to receive cash based on the Company’s share price at the time of vesting. The amount of cash payment is contingent on the Company’s total shareholder return relative to a peer group of companies and achieving certain corporate performance targets. 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.

w) Earnings per Share

The number of basic common shares outstanding is the weighted average number of common shares outstanding for each period. Shares issued during the period are included in the weighted average number of shares from the date consideration is 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 stock options granted to employees. Stock options granted to employees provide the holder with the ability to settle in cash or equity. For the purposes of the diluted earnings per share calculation, the Company must adjust the numerator for the more dilutive effect of cash-settlement versus equity-settlement despite how the stock options are accounted for in net earnings. As a result, net earnings reported based on accounting of cash-settled stock options may be adjusted for the results of equity-settlements for the purposes of determining the numerator for the diluted earnings per share calculation.

x) Government Grants

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

y) Recent Accounting Standards

i) Impairment of Assets

In May 2013, the IASB published narrow-scope amendments to IAS 36, “Impairment of Assets,” which requires the disclosure of information about the recoverable amount of impaired assets, particularly if that amount is based on fair value less costs of disposal. Amendments to IAS 36 are effective for the Company on January 1, 2014, with required retrospective application and early adoption permitted. The Company intends to retrospectively adopt the amendments on January 1, 2014. The adoption of the standard is not expected to have a material impact on the Company’s annual consolidated financial statements.

Consolidated Financial Statements  22

z) Change in Accounting Policy

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 was effective for the Company on January 1, 2013, with required retrospective application and early adoption permitted. The Company retrospectively adopted IFRS 10 on January 1, 2013. The adoption of the standard had no impact on the Company’s consolidated 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 joint arrangement shall be classified as a joint venture and accounted for using the equity method of accounting. Under the previous standard, the Company had the option to account for any interests in joint arrangements using either proportionate consolidation or equity accounting. IFRS 11 was effective for the Company on January 1, 2013, with required retrospective application and early adoption permitted. The Company retrospectively adopted IFRS 11 on January 1, 2013.

The adoption of the standard resulted in the following cumulative balance sheet impact related to the Madura joint arrangement, applied prospectively from January 1, 2012:

Balance Sheet Impact
($ millions)	December 31, 2012			January 1, 2012
Accounts receivable		(4	)		(4	)
Exploration and evaluation assets		(37	)		(14	)
Property, plant and equipment, net		(45	)		(42	)
Investment in joint ventures		132			91
Other assets		(25	)		—
Accounts payable and accrued liabilities		1			18
Other long-term liabilities		3			(24	)
Deferred tax liabilities		(25	)		(25	)
Total Balance Sheet Impact		—			—

iii) Disclosure of Interests in Other Entities

In May 2011, the IASB published IFRS 12, “Disclosure of Interests in Other Entities,” which contains new annual 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 consolidated financial statements. IFRS 12 was effective for the Company on January 1, 2013, with required retrospective application and early adoption permitted. The Company retrospectively adopted IFRS 12 on January 1, 2013. The adoption of the standard did not have a material impact on the Company’s annual consolidated 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 were effective for the Company on January 1, 2013, with required retrospective application and early adoption permitted. The Company retrospectively adopted these amendments on January 1, 2013. The adoption of the amendments had no impact on the Company’s consolidated financial statements.

Consolidated Financial Statements  23

v) 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 the 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 was effective for the Company on January 1, 2013 with required prospective application and early adoption permitted. The Company adopted IFRS 13 on January 1, 2013. The adoption of the standard did not 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 were effective for the Company on January 1, 2013, with required retrospective application and early adoption permitted. The Company retrospectively adopted these amendments on January 1, 2013.

The adoption of this amended standard resulted in the following balance sheet impact, applied retrospectively to January 1, 2010:

Balance Sheet Impact
($ millions)	2012			2011			2010			Total
Increase/(decrease) in net defined benefit liability		1			2			(12	)		(9	)
Increase/(decrease) in retained earnings		(1	)		(2	)		12			9
Total balance sheet impact		—			—			—			—

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 were effective for the Company on January 1, 2013, with required retrospective application and early adoption permitted. Amendments to IAS 32 were effective for the Company for reporting periods ending after January 1, 2014, with required retrospective application and early adoption permitted. The Company retrospectively adopted both IFRS 7 and IAS 32 amendments on January 1, 2013. The adoption of the amendments did not have a material impact on the Company’s consolidated financial statements. Refer to Note 22.

Note 4 Accounts Receivable

Accounts Receivable
($ millions)	December 31, 2013			December 31, 2012
Trade receivables		1,383			1,291
Allowance for doubtful accounts		(27	)		(23	)
Derivatives due within one year		22			14
Other(1)		80			63
		1,458			1,345

⁽¹⁾ Accounts receivable as at December 31, 2012 has been adjusted to reflect the impact of equity method accounting with respect to the Madura joint arrangement.

Consolidated Financial Statements  24

Note 5 Inventories

Inventories
($ millions)	December 31, 2013		December 31, 2012
Crude oil, natural gas and sulphur		1,061		1,113
Refined petroleum products		181		157
Trading inventories measured at fair value		421		328
Materials, supplies and other		149		138
		1,812		1,736

Impairment of inventory to net realizable value as at December 31, 2013 was $1 million (December 31, 2012 – $1 million), primarily due to a reduction in market prices for asphalt. During 2013, there were no inventory impairment reversals (2012 - nil).

Trading inventories measured at fair value less costs to sell consist of natural gas inventories and crude oil inventories. The fair value measurement incorporates exit commodity prices and adjustments for quality and location. Refer to Note 22.

Consolidated Financial Statements  25

Note 6 Exploration and Evaluation Costs

Exploration and Evaluation Assets
($ millions)	2013			2012
Beginning of year		773			746
Additions		574			291
Acquisitions		1			16
Transfers to oil and gas properties (note 7)		(209	)		(198	)
Expensed exploration expenditures previously capitalized		(10	)		(42	)
Exchange adjustments		15			(3	)
Change in accounting policy (note 3)		—			(37	)
End of year		1,144			773

The following exploration and evaluation expenses for the years ended December 31, 2013 and 2012 relate to activities associated with the exploration for and evaluation of oil and natural gas resources and recorded in the Upstream segment:

Exploration and Evaluation Expense Summary
($ millions)	2013		2012
Seismic, geological and geophysical		133		146
Expensed drilling		104		188
Expensed land		9		16
Change in accounting policy (note 3)		—		(6	)
		246		344

Consolidated Financial Statements  26

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, 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	)
Change in accounting policy (note 3)		(45	)		—			—			—			—			(45	)
December 31, 2012		38,781			981			2,006			5,094			2,225			49,087
Additions		3,890			93			206			282			179			4,650
Acquisitions		38			—			—			—			—			38
Transfers from exploration and evaluation (note 6)		209			—			—			—			—			209
Transfers between categories		—			—			—			(27	)		27			—
Changes in asset retirement obligations		68			17			9			12			35			141
Disposals and derecognition		(66	)		(11	)		—			(1	)		(16	)		(94	)
Exchange adjustments		161			—			—			316			—			477
December 31, 2013		43,081			1,080			2,221			5,676			2,450			54,508
Accumulated depletion, depreciation, amortization and impairment
December 31, 2011		(15,900	)		(407	)		(848	)		(1,046	)		(1,154	)		(19,355	)
Depletion, depreciation, and amortization		(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	)
Depletion, depreciation, amortization and impairment(1)		(2,501	)		(36	)		(96	)		(255	)		(119	)		(3,007	)
Transfer between categories		—			—			—			12			(12	)		—
Disposals and derecognition		55			—			—			1			13			69
Exchange adjustments		(15	)		—			—			(72	)		—			(87	)
December 31, 2013		(20,408	)		(479	)		(1,046	)		(1,574	)		(1,251	)		(24,758	)
Net book value
December 31, 2012		20,834			538			1,056			3,834			1,092			27,354
December 31, 2013		22,673			601			1,175			4,102			1,199			29,750

⁽¹⁾  Depletion, depreciation, amortization and impairment for the year ended December 31, 2013 does not include an amortization recovery of research and development assets of $1 million (2012 – expense of $5 million), and an exchange adjustment of $1 million (2012 – $8 million).

Included in depletion, depreciation, amortization and impairment expense recognized in the fourth quarter of 2013 is a non-cash impairment charge of $275 million (2012 - nil) on conventional natural gas assets located in Western Canada and included within the Upstream segment. The impairment charge, attributed to East Central Alberta, was the result of low estimated long-term future natural gas prices and a reduction in the investment of natural gas property development. The recoverable amount was $384 million as at December 31, 2013 and was estimated based on value-in-use methodology using estimated discounted cash flows based on proved plus probable reserves and discounted using an average pre-tax discount rate of 8% (2012 - 8%).

Costs of property, plant and equipment, including major development projects, excluded from costs subject to depletion, depreciation and amortization as at December 31, 2013 were $7.1 billion (December 31, 2012 – $5.2 billion) including undeveloped land assets of $408 million as at December 31, 2013 (December 31, 2012 - $397).

Consolidated Financial Statements  27

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, 2012	3,051
December 31, 2013	3,044

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, 2012	1,796
December 31, 2013	3,677

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, 2012	30
December 31, 2013	29

Consolidated Financial Statements  28

Note 8 Joint Arrangements

Joint Operations

BP-Husky Refining LLC

The Company holds a 50% ownership interest in BP-Husky Refining LLC, which owns and operates the BP-Husky Toledo Refinery in Ohio. 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)	2013			2012
Beginning of year		1,336			1,437
Accretion (note 14)		80			81
Paid		(87	)		(152	)
Foreign exchange		92			(30	)
End of year		1,421			1,336

The contribution payable accretes at a rate of 6% and is payable between December 31, 2013 and December 31, 2015 with the final balance due by December 31, 2015. The timing of payments made during this period will be determined by the capital expenditures at the refinery during the same period. The entity is included as part of U.S. Refining and Marketing in the Downstream segment.

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)	2013			2012
Revenues		2,856			2,574
Expenses		(2,762	)		(2,319	)
Proportionate share of net earnings		94			255

Balance Sheets ($ millions)	December 31, 2013			December 31, 2012
Current assets		442			416
Non-current assets		1,938			1,864
Current liabilities		(264	)		(210	)
Non-current liabilities		(664	)		(492	)
Proportionate share of net assets		1,452			1,578

Consolidated Financial Statements  29

Sunrise Oil Sands Partnership

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, 2013 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 included in the consolidated balance sheets is as follows:

Contribution Receivable ($ millions)	2013			2012
Beginning of year		607			1,147
Accretion (note 14)		22			53
Received		(520	)		(563	)
Foreign exchange		27			(30	)
End of year		136			607

Summarized below is the Company’s proportionate share of operating results and financial position in the Sunrise Oil Sands Partnership that have been included in the consolidated statements of income and the consolidated balance sheets in Exploration and Production in the Upstream segment:

Results of Operations ($ millions)	2013			2012
Revenues		—			—
Expenses		(10	)		(9	)
Financial items		48			30
Proportionate share of net earnings		38			21

Balance Sheets ($ millions)	December 31, 2013			December 31, 2012
Current assets		149			475
Non-current assets		1,890			1,407
Current liabilities		(113	)		(106	)
Non-current liabilities		(21	)		(12	)
Proportionate share of net assets		1,905			1,764

Consolidated Financial Statements  30

Atlantic Region Joint Operations

The Company holds interests in the White Rose oil field, with a 72.5% interest in the core field and a 68.875% interest in the satellite fields. The Company also holds 35% interests in two exploration licenses and two significant discovery licenses in the Flemish Pass Basin related to the Bay Du Nord, Harpoon and Mizzen discoveries. Both areas are located off the coast of Newfoundland and Labrador and are a part of Husky’s offshore East Coast exploration and development program. The Company’s proportionate share of operating results and financial position in the White Rose oil field and Flemish Pass Basin have been included in the consolidated statements of income and the consolidated balance sheets in Exploration and Production in the Upstream segment.

Joint Venture

Husky-CNOOC Madura Ltd.

The Company currently holds 40% joint control in Husky-CNOOC Madura Ltd., which is engaged in exploring for oil and gas resources in Indonesia. Results of the joint venture are included in the consolidated statements of income in Exploration and Production in the Upstream segment.

Summarized below is the financial information for Husky-CNOOC Madura Ltd. accounted for using the equity method:

Results of Operations ($ millions, except share of equity investment)	2013			2012
Revenues		—			—
Expenses		(24	)		(11	)
Share of equity investment (percent)		40	%		40	%
Proportionate share of equity investment		(10	)		(11	)

Balance Sheets ($ millions, except share of equity investment)	December 31, 2013			December 31, 2012
Current assets(1)		28			34
Non-current assets		439			411
Current liabilities		(50	)		(26	)
Non-current liabilities		(188	)		(149	)
Net assets		229			270
Share of net assets (percent)		40	%		40	%
Carrying amount in statement of financial position		153			132

⁽¹⁾  Current assets include cash and cash equivalents of $14 million (2012 - nil).

The Company’s share of equity investment and carrying amount of share of net assets does not equal the 40% joint control of the expenses and net assets of Husky-CNOOC Madura Ltd. due to differences in the accounting policies of the joint venture and the Company.

Consolidated Financial Statements  31

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

Non-cash Working Capital ($ millions)	2013			2012
Decrease (increase) in non-cash working capital
Accounts receivable(1)		200			318
Inventories		30			329
Prepaid expenses		(22	)		(29	)
Accounts payable and accrued liabilities		116			364
Change in non-cash working capital		324			982
Relating to:
Operating activities(1)		(21	)		847
Financing activities		(19	)		79
Investing activities		364			56

⁽¹⁾ Non-cash working capital for 2012 has been adjusted to reflect the impact of equity method accounting with respect to the Madura joint arrangement.

Cash and cash equivalents at December 31, 2013 included $305 million of cash (December 31, 2012 – $127 million) and $792 million of short-term investments with original maturities less than three months at the time of purchase (December 31, 2012 – $1,898 million).

Note 10 Goodwill

Goodwill ($ millions)	2013		2012
Beginning of year		663		674
Exchange adjustments		35		(11	)
End of year		698		663

As at December 31, 2013, 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 8% (2012 – 8%). 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% (2012 – 2%). At December 31, 2013, 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. The values assigned to key assumptions reflect past experience from both internal and external sources.

Consolidated Financial Statements  32

Note 11 Bank Operating Loans

At December 31, 2013, the Company had unsecured short-term borrowing lines of credit with banks totalling $595 million (December 31, 2012 – $515 million) and letters of credit under these lines of credit totalling $224 million (December 31, 2012 – $235 million). As at December 31, 2013, bank operating loans were nil (December 31, 2012 – nil). Interest payable is based on Bankers’ Acceptance, U.S. LIBOR or prime rates. During 2013, the Company’s weighted average interest rate on short-term borrowings was approximately 1.2% (2012 – 1.2%).

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, 2013, there was no balance outstanding under this credit facility (December 31, 2012 – nil).

Note 12 Accounts Payable and Accrued Liabilities

Accounts Payable and Accrued Liabilities ($ millions)	December 31, 2013		December 31, 2012
Trade payables		82		152
Accrued liabilities(1)		2,466		2,291
Dividend payable (note 18)		295		295
Stock-based compensation		122		47
Derivatives due within one year		21		5
Contingent consideration (note 22)		29		27
Other		140		168
		3,155		2,985

⁽¹⁾ Accrued liabilities as at December 31, 2012 has been adjusted to reflect the impact of equity method accounting with respect to the Madura joint arrangement.

Consolidated Financial Statements  33

Note 13 Long-term Debt

			Canadian $ Amount						U.S. $ Denominated
Long-term Debt ($ millions)	Maturity		December 31, 2013			December 31, 2012			December 31, 2013		December 31, 2012
Long-term debt
5.90% notes(1)(5)		2014		—			746			—		750
3.75% medium-term notes(6)		2015		300			300			—		—
7.55% debentures(1)(3)		2016		213			199			200		200
6.20% notes(1)(5)		2017		319			298			300		300
6.15% notes(1)(4)		2019		319			298			300		300
7.25% notes(1)(5)		2019		798			746			750		750
5.00% medium-term notes(6)		2020		400			400			—		—
3.95% notes(1)(5)		2022		532			498			500		500
6.80% notes(1)(5)		2037		411			385			387		387
Debt issue costs(2)				(21	)		(24	)		—		—
Unwound interest rate swaps (note 22)				50			72			—		—
Long-term debt				3,321			3,918			2,437		3,187
Long-term debt due within one year
5.90% notes(1)(5)		2014		798			—			750		—

⁽¹⁾ 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.

⁽²⁾ Calculated using the effective interest rate method.

⁽³⁾ The 7.55% debentures represent unsecured securities under a trust indenture dated October 31, 1996.

⁽⁴⁾ The 6.15% notes represent unsecured securities under a trust indenture dated June 14, 2002.

⁽⁵⁾ 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.

⁽⁶⁾ The 3.75% and the 5.00% medium-term notes represent unsecured securities under a trust indenture dated December 21, 2009.

Credit Facilities

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. 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. In February 2013, the limit on the $1.5 billion facility was increased to $1.6 billion.

There continues to be no difference between the terms of these facilities, other than their maturity dates. 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, 2013, the Company had no borrowings under either revolving syndicated credit facility (December 31, 2012 – nil).

Notes and Debentures

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 enabled 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. The unused capacity of $1.5 billion under the U.S. Base Prospectus expired in July 2013.

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. The amount paid to note holders was equivalent to $410 million in Canadian dollars.

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 in Canada up to and including January 30, 2015. As at December 31, 2013, 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.

Consolidated Financial Statements  34

On October 31, 2013 and November 1, 2013, Husky 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, respectively, that enables the Company to offer up to U.S. $3.0 billion of debt securities, common shares, preferred shares, subscription receipts, warrants and units of the Company in the United States up to and including November 30, 2015. During the 25-month period that the U.S. Shelf Prospectus is effective, securities may be offered in amounts, at prices and on terms set forth in a prospectus supplement. As at December 31, 2013, the Company had not issued securities under the U.S. Shelf Prospectus.

The ability of the Company to raise capital utilizing the the Canadian Shelf Prospectus or U.S. Shelf 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.

Consolidated Financial Statements  35

Note 14 Financial Items

Financial Items
($ millions)	2013			2012
Foreign exchange
Gains (losses) on translation of U.S. dollar denominated long-term debt		(11	)		43
Gains on cross currency swaps		—			2
Gains (losses) on contribution receivable		27			(7	)
Other foreign exchange gains (losses)(1)		5			(24	)
Net foreign exchange gains		21			14
Finance income
Contribution receivable (note 8)		22			53
Interest income		19			34
Other		10			6
Finance income		51			93
Finance expenses
Long-term debt		(233	)		(232	)
Contribution payable (note 8)		(80	)		(81	)
Other		3			(3	)
		(310	)		(316	)
Interest capitalized(2)		266			173
		(44	)		(143	)
Accretion of asset retirement obligations (note 16)		(118	)		(87	)
Accretion of other long-term liabilities (note 22)		(7	)		(10	)
Finance expenses		(169	)		(240	)
		(97	)		(133	)

⁽¹⁾  Other foreign exchange gains and losses primarily include realized and unrealized foreign exchange gains and losses on purchases of property, plant and equipment, and working capital.

⁽²⁾  Interest capitalized on project costs in 2013 is calculated using the Company’s annualized effective interest rate of 6% (2012 – 6%).

Note 15 Other Long-term Liabilities

Other Long-term Liabilities
($ millions)	December 31, 2013		December 31, 2012
Employee future benefits (notes 3, 19)		116		147
Finance lease obligations		31		31
Stock-based compensation		39		21
Contingent consideration (note 22)		31		78
Other(1)		54		51
		271		328

⁽¹⁾ Other long-term liabilities as at December 31, 2012 has been adjusted to reflect the impact of equity method accounting with respect to the Madura joint arrangement.

Consolidated Financial Statements  36

Note 16 Asset Retirement Obligations

At December 31, 2013, the estimated total undiscounted inflation-adjusted amount required to settle the Company’s ARO was $12.3 billion (December 31, 2012 – $10.3 billion). These obligations will be settled based on the useful lives of the underlying assets, which currently extend an average of 49 years into the future. This amount has been discounted using credit-adjusted risk-free rates of 3.1% to 5.3% (December 31, 2012 – 2.8% to 4.7%). Obligations related to future environmental remediation and cleanup of oil and gas producing assets are included in the estimated ARO.

The change in estimates in 2013 are related to increased cost estimates and asset growth offset by higher average discount rates and a revision of the timing of future ARO cash flows.

While the provision is based on management’s best estimates of future costs, discount rates, and the economic lives of the assets, there is uncertainty regarding the amount and timing of incurring these costs.

A reconciliation of the carrying amount of asset retirement obligations at December 31, 2013 and 2012 is set out below:

Asset Retirement Obligations
($ millions)	2013			2012
Beginning of year		2,793			1,767
Additions		78			154
Liabilities settled		(142	)		(123	)
Liabilities disposed		(6	)		(1	)
Change in discount rate		(288	)		174
Change in estimates		351			737
Exchange adjustment		14			(2	)
Accretion (note 14)		118			87
End of year		2,918			2,793
Expected to be incurred within 1 year		210			107
Expected to be incurred beyond 1 year		2,708			2,686

Note 17 Income Taxes

The major components of income tax expense for the years ended December 31, 2013 and 2012 were as follows:

Income Tax Expense
($ millions)	2013			2012
Current income tax
Current income tax charge		413			529
Adjustments to current income tax estimates		176			7
		589			536
Deferred income tax
Relating to origination and reversal of temporary differences		364			221
Adjustments to deferred income tax estimates		(154	)		57
		210			278

Consolidated Financial Statements  37

Deferred Tax Items in OCI
($ millions)	2013			2012
Deferred tax items expensed (recovered) directly in OCI
Derivatives designated as cash flow hedges		13			1
Remeasurement of pension plans		7			5
Exchange differences on translation of foreign operations		58			(12	)
Hedge of net investment		(27	)		2
		51			(4	)

Deferred Tax Items in Equity
($ millions)	2013		2012
Deferred tax items expensed (recovered) directly in equity
Share issue costs		—		—

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, 2013 and 2012 were accounted for as follows:

Reconciliation of Effective Tax Rate
($ millions, except tax rate)	2013			2012
Earnings before income taxes
Canada		2,110			2,097
United States		379			575
Other foreign jurisdictions		139			164
		2,628			2,836
Statutory Canadian income tax rate (percent)		25.8	%		25.8	%
Expected income tax		678			732
Effect on income tax resulting from:
Capital gains and losses		(10	)		(10	)
Foreign jurisdictions		64			37
Non-taxable items		33			12
Other – net		34			43
Income tax expense		799			814

The statutory tax rate was 25.8% in 2013 (2012 – 25.8%). The 2012 to 2013 tax rates were unchanged due to no significant changes to applicable tax rates.

Consolidated Financial Statements  38

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

Deferred Tax Liabilities and Assets ($ millions)	January 1, 2013			Recognized in Earnings			Recognized in OCI			Other			December 31, 2013
Deferred tax liabilities
Exploration and evaluation assets and property, plant and equipment		(5,425	)		(258	)		(65	)		(41	)		(5,789	)
Foreign exchange gains taxable on realization		(64	)		(10	)		14			—			(60	)
Financial assets at fair value		(7	)		(1	)		—			—			(8	)
Deferred tax assets
Pension plans		39			3			(7	)		—			35
Asset retirement obligations		778			30			4			—			812
Loss carry-forwards		30			18			3			—			51
Debt issue costs		6			(3	)		—			—			3
Other temporary differences		3			11			—			—			14
		(4,640	)		(210	)		(51	)		(41	)		(4,942	)

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(1)		(4,939	)		(487	)		13			(12	)		(5,425	)
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
		(4,354	)		(278	)		4			(12	)		(4,640	)

⁽¹⁾ Deferred tax liability and assets for the 2012 comparative has been adjusted to reflect the impact of equity method accounting with respect to the Madura joint arrangement.

The Company has temporary differences associated with its investments in its foreign subsidiaries, branches, and interests in joint ventures. At December 31, 2013, the Company has no deferred tax liabilities in respect of these temporary differences (December 31, 2012 - nil).

At December 31, 2013, the Company had $138 million (December 31, 2012 – $86 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  39

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, 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
Stock dividends		290,667		8
Options exercised		859,187		27
December 31, 2013		983,379,074		6,974

Prior to December 2013, shareholders had the option to receive dividends in common shares or in cash. Quarterly dividends were declared in an amount expressed in dollars per common share and could be paid by way of issuance of a fraction of a common share per outstanding common share determined by dividing the dollar amount of the dividend by the volume-weighted average trading price of the common shares on the principal stock exchange on which the common shares are traded. The volume-weighted average trading price of the common shares was calculated by dividing the total value by the total volume of common shares traded over the five trading day period immediately prior to the payment date of the dividend on the common shares. In the fourth quarter of 2013, the Board of Directors determined to discontinue the payment of dividends by way of the issuance of common shares. The change became effective with the dividend declaration in February of 2014.

During the year ended December 31, 2013, the Company declared dividends payable of $1.20 per common share (2012 – $1.20 per common share), resulting in dividends of $1,180 million (2012 – $1,171 million). An aggregate of $1,171 million was paid in cash during 2013 (2012 - $557 million). At December 31, 2013, $295 million, including $291 million in cash and $4 million in common shares, was payable to shareholders on account of dividends declared on October 24, 2013 (December 31, 2012 – $295 million, including $293 million in cash and $2 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, 2011		12,000,000		291
Cumulative Redeemable Preferred Shares, Series 1 issued, net of share issue costs		—		—
December 31, 2012		12,000,000		291
Cumulative Redeemable Preferred Shares, Series 1 issued, net of share issue costs		—		—
December 31, 2013		12,000,000		291

Holders of the Series 1 Preferred Shares are entitled to receive a cumulative quarterly fixed dividend yielding 4.45% annually for an 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.

Consolidated Financial Statements  40

During the year ended December 31, 2013, the Company declared dividends payable of $13 million on the Series 1 Preferred Shares (2012 – $13 million) representing approximately $1.11 per Series 1 Preferred Share (2012 – $1.11 per Series 1 Preferred Share). At December 31, 2013, there were no amounts payable as dividends on the Series 1 Preferred Shares (December 31, 2012 – nil). A total of $13 million was paid during 2013 (2012 - $17 million), representing approximately $0.28 per quarter per Series 1 Preferred Share (2012– $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. When the stock option is surrendered to the Corporation, the cash payment is equal to the excess of the aggregate fair market value of the common shares able to be purchased pursuant to the vested and exercisable portion of such stock options on the date of surrender over the aggregate exercise price for those common shares pursuant to those stock options. The fair market value of common shares is calculated as the closing price of the common shares on the date on which board lots of common shares have traded immediately preceding the date a holder of the stock options provides notice to the Corporation that he or she wishes to surrender his or her stock options to the Corporation in lieu of exercise.

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, 2013 was $134 million (December 31, 2012 – $57 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, 2013 was $83 million (2012 – $42 million). At December 31, 2013, stock options exercisable for cash had an intrinsic value of $135 million (December 31, 2012 – $31 million).

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

Outstanding and Exercisable Options	2013					2012
	Number of Options (thousands)			Weighted Average Exercise Prices ($)		Number of Options (thousands)			Weighted Average Exercise Prices ($)
Outstanding, beginning of year		29,021			28.85		33,337			34.62
Granted(1)		6,314			31.46		11,137			25.61
Exercised for common shares		(859	)		27.75		(177	)		27.61
Surrendered for cash		(1,857	)		28.43		—			—
Expired or forfeited		(3,682	)		38.92		(15,276	)		39.09
Outstanding, end of year		28,937			28.20		29,021			28.85
Exercisable, end of year		13,574			27.87		10,796			32.19

⁽¹⁾  Options granted during the year ended December 31, 2013 were attributed a fair value of $4.02 per option (2012 – $3.94) 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		22,780		27.31		2		13,465		27.84
$30.00 – $31.69		6,157		31.50		4		109		31.69
December 31, 2013		28,937		28.20		3		13,574		27.87

Consolidated Financial Statements  41

The fair value of the share options is estimated at each reporting date using the Black-Scholes option pricing model, taking into account the terms and conditions upon which the share options are granted and for the performance options, the current likelihood of achieving the specified target. The following table lists the assumptions used in the Black-Scholes option pricing model for the share options and performance options:

Black-Scholes Assumptions	December 31, 2013				December 31, 2012
	Tandem Options		Tandem Performance Options		Tandem Options		Tandem Performance Options
Dividend per option		1.20		1.20		1.31		1.31
Range of expected volatilities used (percent)		15.5 - 24.5		15.5 - 17.4		13.5 - 33.2		13.5 - 24.8
Range of risk-free interest rates used (percent)		0.9 - 1.9		0.9 - 1.0		0.9 - 1.4		0.9 - 1.1
Expected life of share options from vesting date (years)		1.85		1.85		1.82		1.82
Expected forfeiture rate (percent)		10.2		10.2		11.0		11.0
Weighted average exercise price		27.95		30.54		29.16		41.36
Weighted average fair value		5.74		3.22		2.84		0.28

The expected life of the share options is based on historical data and current expectations and is not necessarily indicative of exercise patterns that may occur. The expected volatility reflects the assumption that the historical volatility over a period similar to the expected life of the options is indicative of future trends, which may also not necessarily be the actual outcome.

Performance Share Units

In February 2010, the Compensation Committee of the Board of Directors of the Company established the Performance Share Unit Plan for executive officers and certain employees of the Company. The term of each PSU is three years, and the PSU vests on the second and third anniversary dates of the grant date in percentages determined by the Compensation Committee based on the Company reaching certain shareholder return and corporate performance 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, 2013, the carrying amount of the liability relating to PSUs was $27 million (December 31, 2012 – $11 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, 2013 was $22 million (2012 – expense of $12 million). The weighted average contractual life of the PSUs at December 31, 2013 was two years.

The number of PSUs outstanding was as follows:

Performance Share Units	2013			2012
Beginning of year		864,500			500,000
Granted		2,194,015			539,500
Exercised		(209,331	)		(82,000	)
Forfeited		(57,309	)		(93,000	)
Outstanding, end of year		2,791,875			864,500
Vested, end of year		809,947			429,835

Consolidated Financial Statements  42

Earnings per Share

Earnings per Share
($ millions)	2013			2012
Net earnings		1,829			2,022
Effect of dividends declared on preferred shares in the year		(13	)		(13	)
Net earnings - basic and diluted(1)		1,816			2,009
(millions)
Weighted average common shares outstanding - basic		983.0			975.8
Effect of stock dividends declared in the year		0.6			0.1
Weighted average common shares outstanding - diluted		983.6			975.9
Earnings per share – basic ($/share)		1.85			2.06
Earnings per share – diluted ($/share)		1.85			2.06

⁽¹⁾  Stock-based compensation expense was $83 million based on cash-settlement for the year ended December 31, 2013 (2012 – $42 million). Stock-based compensation expense was $29 million based on equity-settlement for the year ended December 31, 2013 (2012 - $33 million). For the year ended December 31, 2013, 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, 2013, 26 million tandem options and 96,150 tandem performance options (2012 – 29 million tandem options and 1 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, 2013. The most recent actuarial valuation of the plans was December 31, 2012 for the Canadian defined benefit plan. The most recent actuarial valuation was December 31, 2011 for the Canadian Other Post-employment benefit plan. The most recent actuarial valuation of the U.S. plans was January 1, 2013.

Defined Contribution Pension Plan

During the year ended December 31, 2013, the Company recognized a $37 million expense (2012 – $33 million) for the defined contribution plan and the U.S. 401(k) plan in net earnings.

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, 2013			December 31, 2012			December 31, 2011
Fair value of plan assets		173			156			147
Defined benefit obligation		(180	)		(189	)		(183	)
Funded status		(7	)		(33	)		(36	)
Net liability		(7	)		(33	)		(36	)
Non-current liability		(7	)		(33	)		(36	)

Consolidated Financial Statements  43

OPEB Plan
($ millions)	December 31, 2013			December 31, 2012			December 31, 2011
Fair value of plan assets		—			—			—
Defined benefit obligation		(109	)		(105	)		(120	)
Funded status		(109	)		(105	)		(120	)
Net Liability		(109	)		(105	)		(120	)
Non-current liability		(109	)		(105	)		(120	)

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

DB Pension Plan
($ millions)	2013		2012			2011
Experience adjustments arising on plan liabilities		0.4		(0.5	)		0.2

OPEB Plan
($ millions)	2013			2012		2011
Experience adjustments arising on plan liabilities		(0.5	)		1.6		(1.2	)

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, 2013 and 2012:

DB Pension Plan and OPEB Plan Net Asset (Liability)	DB Pension Plan						OPEB Plan
($ millions)	2013			2012			2013			2012
Beginning of year		(33	)		(36	)		(105	)		(120	)
Employer contributions		8			8			—			1
Benefit cost		(3	)		(3	)		(11	)		(11	)
Benefit paid		—			—			1			—
Remeasurements
Actuarial gain (loss) due to liability experience		—			1			1			(2	)
Actuarial gain (loss) due to liability assumption changes		8			(8	)		5			27
Return on plan assets (greater) less than discount rate		13			5			—			—
End of year		(7	)		(33	)		(109	)		(105	)

DB Pension Plan and OPEB Plan	DB Pension Plan						OPEB Plan
($ millions)	2013			2012			2013			2012
Amounts recognized in net earnings
Current service cost		2			2			7			7
Net Interest cost		1			1			4			4
Benefit cost		3			3			11			11
Remeasurements
Actuarial (gain) loss due to liability experience		—			(1	)		(1	)		2
Actuarial (gain) loss due to liability assumption changes		(8	)		8			(5	)		(27	)
Loss (gain) on plan assets		(13	)		(5	)		—			0
Remeasurement effects recognized in OCI		(21	)		2			(6	)		(25	)

Consolidated Financial Statements  44

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

Defined Benefit Obligation	DB Pension Plan						OPEB Plan
($ millions)	2013			2012			2013			2012
Beginning of year		189			183			105			120
Current service cost		2			2			7			7
Interest cost		8			7			4			4
Benefits paid		(11	)		(10	)		(1	)		(1	)
Remeasurements
Actuarial (gain) loss - experience		—			(1	)		(1	)		2
Actuarial (gain) loss - demographic assumptions		6			—			9			—
Actuarial (gain) loss - financial assumptions		(14	)		8			(14	)		(27	)
Curtailment gain		—			—			—			—
End of year		180			189			109			105

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

Fair Value of Plan Assets
($ millions)	2013			2012
Beginning of year		156			147
Contributions by employer		8			8
Benefits paid		(11	)		(10	)
Interest income		7			6
Return on plan assets greater (less) than discount rate		13			5
End of year		173			156

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	Canada - DB Pension Plan				U.S. - DB Pension Plan
(percent)	2013		2012		2013		2012
Discount rate for benefit expense		3.80		4.1		3.2		3.9
Discount rate for benefit obligation		4.5		3.8		4.1		3.2
Rate of compensation expense		3.5		3.5		4.50		4.5

OPEB Plan Long-term Assumptions	OPEB Plan
(percent)	2013		2012
Discount rate for benefit expense		3.3 - 4.0		4.1 - 4.3
Discount rate for benefit obligation		4.3 - 4.7		3.3 - 4.0
Dental care escalation rate		4.0		4.0
Provincial health care premium		2.50		2.5

The average health care cost trend rate used for the benefit expense for the Canadian OPEB Plan was 7.0% for 2013 and 2014, grading 0.5% per year for 4 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 2014, grading 0.5% per year for 4 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 2013, and 7.0% for 2014, grading 0.5% per year for 4 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 7.0% for 2014, grading 0.25% per year for 8 years to 5.0% in 2022 and thereafter.

Consolidated Financial Statements  45

The medical cost trend rate assumption has a significant effect on amounts reported for the OPEB plan. A 1% 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		2.7		(2.2	)
Effect on defined benefit obligation		19.3		(15.7	)

During 2013, the Company contributed $8 million (2012 – $8 million) to the defined benefit pension plan assets and is expecting to contribute $8 million in 2014. Benefits of $25 million are expected to be paid in 2014.

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.

The composition of the DB Pension Plan assets at December 31, 2013 and 2012 was as follows:

DB Pension Plan Assets
(percent)	Target allocation range		2013		2012
Money market type funds		0 - 15		0.5		—
Equity securities		35 – 80		64.5		59.8
Debt securities		30 – 65		34.5		39.6
Real estate		0 – 5		—		—
Other		—		0.5		0.6

Consolidated Financial Statements  46

Note 20 Commitments and Contingencies

At December 31, 2013, 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		155		958		367		1,480
Firm transportation agreements		289		1,073		2,702		4,064
Unconditional purchase obligations		2,287		2,028		71		4,386
Lease rentals and exploration work agreements		107		431		1,208		1,746
		2,838		4,490		4,348		11,676

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.

Note 21 Related Party Transactions

Significant subsidiaries and jointly controlled entities at December 31, 2013 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
Husky Energy International Corporation	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

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, 2013, the senior notes are included in long-term debt in the Company’s consolidated balance sheets.

Consolidated Financial Statements  47

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, 2013, the amount of natural gas sales to Meridian and other cogeneration facilities owned by the related party totalled $55 million (2012 - $74 million). For the year ended December 31, 2013, the amount of steam purchases by the Company from Meridian totalled $17 million (2012 - $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, 2013, the total cost recovery for these services was $9 million (2012 - $19 million).

On December 7, 2010, the Company issued 28.9 million common shares at a price of $24.50 per share for total gross proceeds of $707 million in a private placement to its then principal shareholders, L.F. Management and Investment S.à r.l (formerly L.F. Investments (Barbados) Limited) and Hutchison Whampoa Luxembourg Holdings S.à r.l.

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 in a private placement to its then principal shareholders, L.F. Management and Investment S.à r.l and Hutchison Whampoa Luxembourg Holdings S.à r.l.

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

Compensation of Key Management Personnel
($ millions)	2013		2012
Short-term employee benefits(1)		13		11
Post-employment benefits(2)		—		—
Stock-based compensation(3)		10		4
		23		15

⁽¹⁾  Short-term employee benefits are comprised of salary and benefits earned during the year, plus cash bonuses awarded during the year. Annual bonus awards settled in shares are included in stock-based compensation expense.

⁽²⁾  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.

⁽³⁾  Stock-based compensation expense represents the cost to the Company for participation in share-based payment plans. Refer to Note 18.

Consolidated Financial Statements  48

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, 2013			December 31, 2012
Derivatives – fair value through profit or loss (“FVTPL”)
Accounts receivable		18			13
Accounts payable and accrued liabilities		(19	)		(5	)
Other assets, including derivatives		2			1
Other – FVTPL(1)
Accounts payable and accrued liabilities		(29	)		(27	)
Other long-term liabilities		(31	)		(78	)
Hedging instruments(2)
Derivatives designated as a cash flow hedge		37			1
Hedge of net investment(3)		(93	)		88
		(115	)		(7	)

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

⁽²⁾  Hedging instruments are presented net of tax.

⁽³⁾  Represents the translation of the Company’s U. S. denominated long-term debt designated as a hedge of the Company’s net investment in its U.S. refining operations.

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 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, 2013 was $4.6 billion (December 31, 2012 – $4.6 billion).

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 estimation of the fair value of commodity derivatives and held-for-trading inventories incorporates exit prices and adjustments for quality and location. The estimation of the fair value of interest rate and foreign currency derivatives incorporates forward market prices, which are compared to quotes received from financial institutions to ensure reasonability. The estimation of the fair value of the net investment hedge incorporates foreign exchange rates and market interest rates from financial institutions. All financial assets and liabilities are classified as Level 2 measurements with the exception of contingent consideration payments. During the year ended December 31, 2013, there were no transfers between Level 1 and Level 2 fair value measurements, and no transfers into and out of Level 3 fair value measurements.

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.

Consolidated Financial Statements  49

A reconciliation of changes in fair value of financial liabilities classified in Level 3 is provided below:

Level 3 Valuations
($ millions)	2013			2012
Beginning of year		105			129
Accretion		7			11
Upside interest payment		(25	)		(17	)
Increase (decrease) on revaluation(1)		(27	)		(18	)
End of year		60			105
Expected to be incurred within 1 year		29			27
Expected to be incurred beyond 1 year		31			78

⁽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 risks related to the volatility of commodity prices, foreign exchange rates 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.

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. The Company also has natural gas inventory in storage that could have an impact on earnings based on changes in natural gas prices. 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 that has a U.S. dollar functional currency. The unrealized foreign exchange gain related to this hedge is recorded in OCI.

At December 31, 2013, the Company had designated all of its U.S. $3.2 billion denominated debt as a hedge of the Company’s net investment in its U.S. refining operations (December 31, 2012 – U.S. $2.8 billion). Of this amount, U.S. $400 million was designated in the third quarter of 2013. For the year ended December 31, 2013, the unrealized loss arising from the translation of the debt was $180 million (2012 – unrealized gain of $15 million), net of tax of $27 million (2012 – $2 million ), which was recorded in net investment hedge within OCI.

Consolidated Financial Statements  50

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, 2013, the balance in long-term debt related to deferred gains resulting from unwound interest rate swaps that had previously been designated as a fair value hedge was $50 million (December 31, 2012 – $72 million). The amortization of the accrued gain upon terminating the interest rate swaps resulted in an offset to finance expenses of $22 million for the year ended December 31, 2013 (2012 – $21 million).

Cash flow hedges may also be used to mitigate risk related to interest rates. At December 31, 2013, 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. The effective portion of these contracts has been recorded at fair value in other assets; there was no ineffective portion at December 31, 2013. For the year ended December 31, 2013, the Company incurred an unrealized gain of $36 million (2012 – $3 million ), arising from the revaluation of the forward starting swaps, net of tax of $13 million (2012 – $1 million), which was recorded in cash flow hedge within OCI.

The forward starting swaps had the following terms and fair value as at December 31, 2013:

				December 31, 2013
Forward Starting Swaps ($ millions)	Swap Rate(1)			Notional Amount(U.S. $ millions)		Fair Value
Swap Maturity
June 15, 2024		2.24	%		105		10
June 16, 2024		2.25	%		310		31
June 17, 2024		2.24	%		85		9
					500		50

⁽¹⁾  Weighted average rate.

iv) Financial Position of Market Risk Management Contracts

The following represents the cumulative fair value adjustments on the Company’s other risk management contracts as at December 31, 2013 and 2012:

Risk Management ($ millions)	December 31, 2013								December 31, 2012
	Asset		Liability			Net			Asset		Liability			Net
Commodity Price
Natural gas contracts		15		(7	)		8			3		(2	)		1
Natural gas storage contracts		2		(2	)		—			10		—			10
Natural gas storage inventory(1)		27		—			27			6		—			6
Crude oil contracts		2		(10	)		(8	)		—		(3	)		(3	)
Crude oil inventory(2)		49		—			49			53		—			53
Foreign Currency
Foreign currency forwards		—		—			—			—		—			—
		95		(19	)		76			72		(5	)		67

⁽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 $124 million at December 31, 2013 (December 31, 2012 – $107 million).

⁽²⁾  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 $297 million at December 31, 2013 (December 31, 2012 – $221 million).

Consolidated Financial Statements  51

v) Earnings Impact of Market Risk Management Contracts

The gains (losses) recognized on risk management positions for the years ended December 31, 2013 and 2012 are set out below.:

	2013
Earnings Impact ($ millions)	Marketing and Other			Purchases of Crude Oil and Products		Other – Net		Net Foreign Exchange Gains (Losses)
Commodity Price
Natural gas		16			12		1		—
Crude oil		(9	)		—		—		—
		7			12		1		—
Foreign Currency
Foreign currency forwards(1)		—			—		1		(27	)
		7			12		2		(27	)

	2012
Earnings Impact ($ millions)	Marketing and Other		Purchases of Crude Oil and Products			Other – Net			Net Foreign Exchange Gains (Losses)
Commodity Price
Natural gas		2		—			—			—
Crude oil		48		(2	)		—			—
		50		(2	)		—			—
Foreign Currency
Cross currency swaps		—		—			(2	)		2
Foreign currency forwards(1)		—		—			(1	)		(5	)
		50		(2	)		(3	)		(3	)

⁽¹⁾ 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.

Offsetting Financial Assets and Liabilities

The tables below outline the financial assets and financial liabilities that are subject to set-off rights and related arrangements, and the effect of those rights and arrangements on the consolidated balance sheets:

	As at December 31, 2013
Offsetting Financial Assets and Liabilities ($ millions)	Gross Amount			Amount Offset			Net Amount
Financial Assets
Financial derivatives		22			(5	)		17
Normal purchase and sale agreements		551			(170	)		381
		573			(175	)		398
Financial Liabilities
Financial derivatives		(293	)		271			(22	)
Normal purchase and sale agreements		(778	)		284			(494	)
		(1,071	)		555			(516	)

Consolidated Financial Statements  52

	As at December 31, 2012
Offsetting Financial Assets and Liabilities ($ millions)	Gross Amount			Amount Offset			Net Amount
Financial Assets
Financial derivatives		36			(5	)		31
Normal purchase and sale agreements		595			(116	)		479
		631			(121	)		510
Financial Liabilities
Financial derivatives		(141	)		138			(3	)
Normal purchase and sale agreements		(687	)		260			(427	)
		(828	)		398			(430	)

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 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		22			(22	)
Natural gas price		(12	)		12
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		41			(46	)

⁽¹⁾  Based on average crude oil and natural gas market prices as at December 31, 2013.

⁽²⁾  Based on the U.S./Canadian dollar exchange rate as at December 31, 2013.

⁽³⁾  Based on U.S. LIBOR as at December 31, 2013.

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 capability 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  53

The Company had the following available credit facilities as at December 31, 2013:

Credit Facilities
($ millions)	Available		Unused
Operating facilities(1) (note 11)		595		371
Syndicated bank facilities (note 13)		3,200		3,200
		3,795		3,571

⁽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. $3.0 billion. 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, 2013:

Contractual Maturities of Financial Liabilities
($ millions)	2014		2015		2016		2017		2018		Thereafter
Accounts payable and accrued liabilities		3,155		—		—		—		—		—
Other long-term liabilities		3		38		3		3		3		26
Long-term debt		1,015		487		395		486		146		3,163

The Company’s contribution payable pursuant to the joint arrangement with BP is payable between December 31, 2013 and December 31, 2015, with the final balance due and payable by December 31, 2015. Refer to 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, 2013 or December 31, 2012, 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  54

The Company’s accounts receivable was aged as follows at December 31, 2013:

Accounts Receivable Aging
($ millions)	December 31, 2013
Current		1,353
Past due (1 – 30 days)		74
Past due (31 – 60 days)		25
Past due (61 – 90 days)		10
Past due (more than 90 days)		23
Allowance for doubtful accounts		(27	)
		1,458

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, 2013, the Company impaired $1 million (2012 – $4 million) of uncollectible receivables.

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 was $24.2 billion as at December 31, 2013 (December 31, 2012 – $23.1 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, 2013, debt to capital employed was 17% (December 31, 2012 – 17%) 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, 2013, debt to cash flow was 0.8 times (December 31, 2012 – 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 in compliance with these covenants at December 31, 2013.

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 2013, the Company received $26 million (2012 – $40 million) under these programs. The grants are accrued for operational purposes and have been recorded as revenues in the consolidated statements of income.

Consolidated Financial Statements  55

Note 25 Employee Salaries and Benefit Expenses

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, 2013 was $778 million (2012 – $673 million) as follows:

Compensation of Employees
($ millions)	2013			2012
Short-term employee benefits(1)		711			661
Post-employment benefits(2)		48			42
Stock-based compensation(3)		105			54
		864			757
Less: capitalized portion		(86	)		(84	)
		778			673

(1) Short-term employee benefits are comprised of salary and benefits earned during the year, plus cash bonuses awarded during the year. Annual bonus awards settled in shares are included in stock-based compensation expense.

(2) 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.

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

Consolidated Financial Statements  56

Document C

Form 40-F

Management’s Discussion and Analysis

February 25, 2014

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 capital employed, return on equity 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 2013

1

1.4 Selected Annual Information

($ millions, except where indicated)	2013			2012			2011
Gross revenues(1)		24,181			22,948			22,829
Net earnings by segment(1)
Upstream(1)		1,244			1,322			1,710
Downstream(1)		830			893			814
Corporate		(245	)		(193	)		(300	)
Net earnings		1,829			2,022			2,224
Net earnings per share – basic		1.85			2.06			2.40
Net earnings per share – diluted		1.85			2.06			2.34
Ordinary dividends per common share		1.20			1.20			1.20
Dividends per cumulative redeemable preferred share, series 1		1.11			1.11			0.87
Cash flow from operations(2)		5,222			5,010			5,198
Total assets		36,904			35,161			32,426
Other long-term liabilities(3)		271			328			342
Long-term debt including current portion		4,119			3,918			3,911
Total non-current liabilities		12,663			12,908			11,263
Cash and cash equivalents		1,097			2,025			1,841
Return on equity (percent)(2)(4)		9.3			10.9			13.8
Return on capital in use (percent)(2)(5)		12.6			12.7			15.9
Return on capital employed (percent)(2)(6)		8.7			9.5			12.1

⁽¹⁾  Gross revenues, marketing and other and purchases have been recast for the comparative periods to reflect a change in the classification of certain trading transactions.

⁽²⁾  Cash flow from operations and financial ratios constitute non-GAAP measures. (Refer to Section 11.3)

⁽³⁾  As at December 31, 2013, 2012 or 2011, the Company did not have long-term financial liabilities.

⁽⁴⁾  Return on equity equals net earnings divided by the two-year average shareholder’s equity. (Refer to Section 11.3)

⁽⁵⁾  Return on capital in use for the years ended December 31, 2013 and 2011 was adjusted for after-tax impairments on property, plant and equipment of $204 million and $52 million, respectively. Return on capital in use, based on the calculation used in prior periods for the years ended December 31, 2013 and 2011, was 11.3% and 15.6%, respectively. (Refer to Section 11.3)

⁽⁶⁾  Return on capital employed for the years ended December 31, 2013 and 2011 was adjusted for after-tax impairments on property, plant and equipment of $204 million and $52 million, respectively. Return on capital employed, based on the calculation used in prior periods for the years ended December 31, 2013 and 2011, was 7.9% and 11.8%, respectively. (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.

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, are being field tested and advanced, while techniques that have been in practice for several decades continue to be optimized;

• Large position in Western Canada oil and liquids-rich natural gas resource plays of approximately 1,800,000 net acres;

• Thermal production for Heavy Oil grew from 17,000 boe/day in 2010 to approximately 37,000 boe/day in 2013, due to the addition of two new steam-assisted gravity drainage (“SAGD”) projects, Pikes Peak South and Paradise Hills. Production is expected to be over 55,000 boe/day by 2016 from thermal projects such as the 3,500 boe/day project at Sandall, which achieved first oil in early 2014, the Rush Lake thermal project, with planned production in the second half of 2015, and the recently sanctioned Edam and Vawn SAGD projects;

Management’s Discussion and Analysis 2013

2

• 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 start up of Phase 1 of the project expected in the second half of 2014. Phase 1 is expected to produce approximately 60,000 bbls/day (30,000 bbls/day net Husky share). Sunrise will use proven 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 this 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 the 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”). The Liwan Gas Project development on Block 29/26 in the South China Sea is substantially complete, with first production expected in the latter part of the first quarter of 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 and five discovered natural gas fields;

• Husky and its joint venture partner CPC Corporation have rights to 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 68.875% 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. The offshore exploration and development program in the Atlantic Region is focused on the Jeanne d’Arc Basin and the Flemish Pass Basin;

• Husky has a 35% interest in each of the three Flemish Pass Basin discoveries: Bay Du Nord, Mizzen and Harpoon;

• Extensive integrated heavy oil pipeline systems in the Lloydminster producing region; and

• The Infrastructure and Marketing business manages the sale and transportation of the Company’s Upstream and Downstream production and managed third-party commodity trading volumes of approximately 175 mboe/day in 2013 through access to capacity on third-party pipelines and storage facilities in both Canada and the United States and natural gas storage of 43 bcf, owned and leased.

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;

• A refinery at Lima, Ohio with a gross crude oil throughput capacity of 160 mbbls/day and a 50% interest in the BP-Husky Refinery in Toledo, Ohio with a name plate capacity of 160 mbbls/day and operating capacity of 135 - 145 mbbls/day on its current crude slate;

• 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 of capacity at plants located in Lloydminster, Saskatchewan and Minnedosa, Manitoba; and

• Major regional motor fuel marketer with 503 retail marketing locations as at December 31, 2013, including bulk plants and travel centres with strategic land positions in Western Canada and Ontario.

Management’s Discussion and Analysis 2013

3

3.0 The 2013 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 2013, that are anticipated to continue to impact the industry to varying degrees into 2014 and beyond. Business factors impacting Husky’s industry during 2013 include, but are not limited, to the following:

• Pricing benchmarks for crude oil and natural gas and underlying market supply and demand drivers;

• Industry advancement in alternative and improved extraction methods have rapidly evolved North American and international on-shore and offshore activity;

• Growing domestic production of natural gas and crude oil continues to reshape the U.S. energy economy, with U.S. crude oil production approaching the historical high achieved in 1970;

• Increased production from U.S. shale gas and liquids-rich gas plays continues to assert downward pressure on North American natural gas pricing;

• Key takeaway capacity constraints for Western Canadian crude oil in North America causing a widening of differentials of crude oil relative to key benchmarks, such as West Texas Intermediate (“WTI”);

• Political unrest in the Middle East has caused continued unplanned production outages having an impact on crude oil benchmark pricing;

• Expected continued production growth from the Western Canadian oil sands, which is expected to grow to approximately 3.2 million bbls/day by 2020 from approximately 1.8 million bbls/day in 2012;

• 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 from historical norms, 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 natural gas and related products. For a discussion on Risk and Risk Management, see Section 7.0 and the 2013 Annual Information Form.

Commodity prices, foreign exchange rates and refining crack spreads are some of the most significant factors that affect the results of Husky’s operations.

Management’s Discussion and Analysis 2013

4

Average Benchmarks		2013		2012
WTI crude oil(1)	(U.S. $/bbl)		97.97		94.21
Brent crude oil(2)	(U.S. $/bbl)		107.91		111.54
Canadian light crude 0.3% sulphur	($/bbl)		93.85		86.57
Western Canada Select @ Hardisty(3)	(U.S. $/bbl)		72.77		73.18
Lloyd heavy crude oil @ Lloydminster	($/bbl)		64.41		62.89
NYMEX natural gas(4)	(U.S. $/mmbtu)		3.65		2.79
NIT natural gas	($/GJ)		3.00		2.28
WTI/Lloyd crude blend differential	(U.S. $/bbl)		25.33		21.46
New York Harbor 3:2:1 crack spread	(U.S. $/bbl)		22.21		31.36
Chicago 3:2:1 crack spread	(U.S. $/bbl)		21.30		27.63
U.S./Canadian dollar exchange rate	(U.S. $)		0.971		1.001
Canadian Equivalents(5)
WTI crude oil	($/bbl)		100.90		94.12
Brent crude oil	($/bbl)		111.13		111.43
Western Canada Select @ Hardisty	($/bbl)		74.94		73.11
WTI/Lloyd crude blend differential	($/bbl)		26.08		21.44
NYMEX natural gas	($/mmbtu)		3.76		2.79

⁽¹⁾  Prices quoted are near-month contract prices for settlement during the next month.

⁽²⁾  Quoted Brent prices are dated less than 15 days prior to loading for delivery.

⁽³⁾  Western Canadian Select is a heavy crude blend primarily based on existing Canadian heavy conventional and bitumen crude oils and is traded at Hardisty, Alberta. Quoted prices are based on the average price during the month.

⁽⁴⁾ Prices quoted are average settlement prices for deliveries during the period.

⁽⁵⁾ Prices quoted are calculated using U.S. benchmark commodity prices and U.S./Canadian dollar exchange rates.

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, as well as 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 receives 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. Starting in 2014, natural gas produced from the Company’s Liwan Gas Project in the Asia Pacific Region will supply the Guangdong Province and will receive a fixed price for five years in line with the current Guangdong gate station price set by the Chinese Government.

The Downstream segment is heavily impacted by the price of crude oil and natural gas, as the largest cost factor in the Downstream segment is crude oil feedstock, a portion of which is heavy crude oil. 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 the mix is 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, under supply contracts, from other Canadian refiners at rack prices or exchanged with production from the Husky Prince George Refinery.

Crude Oil

Management’s Discussion and Analysis 2013

5

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, a light sweet benchmark crude oil produced in the North Sea. The price of WTI ended 2013 at U.S. $98.42/bbl compared to U.S. $94.19/bbl on December 31, 2012, and averaged U.S. $97.97/bbl in 2013 compared with U.S. $94.21/bbl in 2012. The price of Canadian light crude ended 2013 at $97.49/bbl compared to $74.32/bbl on December 31, 2012 and averaged $93.85/bbl in 2013 compared with $86.57/bbl in 2012. The price of Brent ended 2013 at U.S. $110.28/bbl, compared to U.S. $111.66/bbl on December 31, 2012, and averaged U.S. $107.91/bbl in 2013 compared with U.S. $111.54/bbl in 2012.

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 both 2013 and 2012, 54% of Husky’s crude oil production was heavy crude oil or bitumen. The light/heavy crude oil differential averaged U.S. $25.33/bbl or 26% of WTI in 2013 compared to U.S. $21.46/bbl or 23% of WTI in 2012.

Natural Gas

In 2013, 27% of Husky’s total oil and gas production was natural gas compared with 31% in 2012, reflecting a shift in investment from dry gas development to higher netback liquids-rich natural gas and crude oil production. The near-month natural gas price quoted on the NYMEX ended 2013 at U.S. $4.23/mmbtu compared with U.S. $3.35/mmbtu at December 31, 2012. During 2013, the NYMEX near-month contract price of natural gas averaged U.S. $3.65/mmbtu compared with U.S. $2.79/mmbtu in 2012. The near-month natural gas contract price for NOVA Inventory Transfer (“NIT”), which is a Canadian natural gas benchmark, was $3.73/mmbtu at the end of 2013 compared with $2.87/mmbtu at December 31, 2012. During 2013, the NIT near-month contract price of natural gas averaged $3.00/mmbtu compared to $2.28/mmbtu in 2012.

Management’s Discussion and Analysis 2013

6

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. 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. The majority of the Company’s expenditures are in Canadian dollars. In addition, changes in foreign exchange rates impact the translation of the U.S. Downstream segment and the Asia Pacific Region.

The Canadian dollar ended 2013 at U.S. $0.940 compared to U.S. $1.005 on December 31, 2012. In 2013, the Canadian dollar averaged U.S. $0.971, weakening by 3% compared with U.S. $1.001 during 2012. Crude oil prices realized by Husky in 2013 benefited from the weakening of the Canadian dollar against the U.S. dollar compared to 2012. In 2013, the price of WTI in U.S. dollars increased by 4% while the price of WTI in Canadian dollars increased by 7% when compared to 2012.

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”).

Management’s Discussion and Analysis 2013

7

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.

The New York Harbor 3:2:1 refining crack spread averaged U.S. $22.21/bbl in 2013 compared to U.S. $31.36/bbl in 2012, and the Chicago 3:2:1 refining crack spread averaged U.S. $21.30/bbl in 2013 compared to U.S. $27.63/bbl in 2012.

The following table is indicative of the relative annualized effect on pre-tax earnings and net earnings from changes in certain key variables in 2013. The table below shows what the effect would have been on 2013 financial results had the indicated variable increased by the notional amount. The analysis is based on business conditions and production volumes during 2013. 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.

	2013			Effect on Earnings						Effect on
Sensitivity Analysis	Average		Increase	before Income Taxes(1)						Net Earnings(1)
				($ millions)			($/share)(2)			($ millions)			($/share)(2)
WTI benchmark crude oil price(3)(4)		97.97	U.S. $1.00/bbl		74			0.08			55			0.06
NYMEX benchmark natural gas price(5)		3.65	U.S. $0.20/mmbtu		27			0.03			19			0.02
WTI/Lloyd crude blend differential(6)		25.33	U.S. $1.00/bbl		(23	)		(0.02	)		(17	)		(0.02	)
Canadian light oil margins		0.043	Cdn $0.005/litre		15			0.02			11			0.01
Asphalt margins		22.62	Cdn $1.00/bbl		10			0.01			7			0.01
New York Harbor 3:2:1 crack spread(7)		22.21	U.S. $1.00/bbl		55			0.06			35			0.04
Exchange rate (U.S. $ per Cdn $)(3)(8)		0.971	U.S. $0.01		(54	)		(0.06	)		(40	)		(0.04	)

⁽¹⁾  Excludes mark to market accounting impacts.

⁽²⁾  Based on 983.4 million common shares outstanding as of December 31, 2013.

⁽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 and 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 and liquids-rich natural gas resource plays and expanding thermal and horizontal drilling in heavy oil. The Company advanced its oil and gas resource play positions in 2013 with development activities ongoing in the Bakken, Viking, Cardium, Lower Shaunavon, Muskwa, Canol, Duvernay, Spirit River, Montney, Second White Specs and Willrich formations.

Husky has an extensive portfolio of oil sands leases, encompassing 2,500 square kilometers in northern Alberta. Husky advanced the development of the Sunrise Energy Project in 2013, a multiple stage in-situ oil sands development. The first phase is expected to produce approximately 60,000 barrels per day, with start up expected in second half of 2014. Husky’s working interest is 50%. Sunrise will use proven SAGD technology, keeping site disturbance to a minimum.

Management’s Discussion and Analysis 2013

8

The Asia Pacific Region consists of the Wenchang oil field, the Liwan 3-1, Liuhua 34-2 and Liuhua 29-1 fields on Block 29/26 located offshore China, the Madura Strait block BD, MDA, MBH development fields, five discoveries offshore Indonesia, and the rights to an exploration block in the South China Sea located offshore Taiwan. The Liwan Gas Project development, located approximately 300 kilometers southeast of the Hong Kong Special Administrative Region, is an important component of the Company’s near term production growth strategy and a key step in accessing the burgeoning energy markets in the Hong Kong Special Administrative Region and Mainland China. Husky has partnered with China National Offshore Oil Corporation (“CNOOC”) on the development, with first gas production anticipated in the latter half of the first quarter of 2014.

In the Atlantic Region, the Company holds interests in eight Production Licences, 15 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. In 2013, the Company made two significant discoveries in the Flemish Pass Basin at the Harpoon and Bay du Nord prospects. With the Mizzen discovery made in 2009, this brings the total number of discoveries in the Flemish Pass Basin to three, making long-term development a viable option subject to further delineation and review. The Company has a 35% working interest in each of these discoveries. The Company has significant exploration acreage in this region and continues to explore 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. The Company also plans to expand terminal pipeline access and product storage opportunities to enhance market access.

4.2 Downstream

Downstream supports heavy oil and oil sands production and makes prudent investments in respect of feedstock, product and market access flexibility. 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. In support of the downstream strategy, the Company sanctioned a refinery reconfiguration project at the Lima, Ohio Refinery to allow the refinery to process up to 40,000 bbls/day of Western Canadian heavy oil while maintaining the capability and flexibility to refine existing light crude oil.

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 foundation 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. 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 2013 Capital Program built on the momentum achieved over the past two years with respect to repositioning 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.

Management’s Discussion and Analysis 2013

9

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 in 2013 was approximately 25,000 bbls/day, representing a 15% increase compared to 2012.

Oil Resource Plays

During 2013, the Company continued to advance exploration and development projects on its extensive oil resource land base. A total of 101 horizontal wells (gross) were drilled and two vertical and 94 horizontal wells (gross) were completed in 2013.

The following table summarizes the key oil resource play drilling and completion activity for the year ended December 31, 2013:

Oil Resource Plays - Drilling and Completion Activity(1)(2)		Year ended December 31, 2013
Project	Location	Gross Wells Drilled		Gross Wells Completed
Oungre Bakken	S.E. Saskatchewan		14		12
Lower Shaunavon	S.W. Saskatchewan		9		7
Viking(3)	Alberta and S.W. Saskatchewan		59		64
N.Cardium	Wapiti, Alberta		13		9
Muskwa	Rainbow, Northern Alberta		6		2
Canol Shale	Northwest Territories		—		2
Total Gross			101		96
Total Net			96		92

⁽¹⁾  Excludes service/stratigraphic test wells for evaluation purposes.

⁽²⁾  Drilling activity includes operated and non-operated wells.

⁽³⁾ Viking is comprised of project activity at Redwater in central Alberta, Alliance in Southeastern Alberta and drilling in Southwestern Saskatchewan.

In the Northwest Territories, the Slater River Canol shale play all-season road construction is substantially complete, and the Company plans to drill and complete two horizontal wells in 2015.

Liquids-Rich Natural Gas Resource Plays

During 2013, the Company continued to advance exploration and development projects on its extensive liquids-rich natural gas resource land base. A total of 31 wells (gross) were drilled and 36 wells (gross) were completed in 2013 in key plays across the liquids-rich natural gas resource plays.

The following table summarizes the key liquids-rich natural gas drilling and completion activity for the year ended December 31, 2013:

Liquids-Rich Natural Gas Resource Plays - Drilling and Completion Activity(1)(2)		Year ended December 31, 2013
Project	Location	Gross Wells Drilled		Gross Wells Completed
Ansell Multi-Zone	Ansell/Edson, Alberta		25		30
Duvernay	Kaybob, Alberta		6		6
Total Gross			31		36
Total Net			29		34

⁽¹⁾  Excludes service/stratigraphic test wells for evaluation purposes.

⁽²⁾  Drilling activity includes operated and non-operated wells.

The liquids-rich gas formations at Ansell in west central Alberta continue to be a key area of focus, with 25 wells (gross) drilled and 30 wells (gross) completed in 2013. To date, the Company has drilled and completed over 300 (gross) wells at the play with average production of 13,800 boe/day in 2013.

Management’s Discussion and Analysis 2013

10

At the Duvernay play in Kaybob, Alberta, the Company drilled and completed the first four well pad, with production from the pad commencing in late 2013. The Company also drilled a second two well pad in the year, which is scheduled to be completed and brought on production in early 2014.

Heavy Oil

Production in 2013 at the Pikes Peak South and Paradise Hill heavy oil thermal projects continued to exceed the combined 11,500 bbls/day design rate capacity. Average 2013 production levels from the developments were approximately 11,400 bbls/day at Pikes Peak South and 4,900 bbls/day at Paradise Hill.

Production commenced at the 3,500 bbls/day Sandall thermal development project in early 2014.

Construction work continued at the 10,000 bbls/day Rush Lake commercial project, with first production expected in the second half of 2015. Production performance from the two well pair pilot is in line with expectations.

Two 10,000 bbls/day thermal developments were sanctioned at Edam East and Vawn, both located in Saskatchewan. Construction is scheduled to begin in 2014 and these projects are expected to deliver a total of 20,000 bbls/day of production in 2016.

The Company advanced its horizontal drilling program in 2013 drilling 140 wells. In 2014, the Company plans to carry out a 144 well program. The Company also drilled 228 gross cold heavy oil production with sand (“CHOPS”) wells during 2013. In 2014, the Company plans to carry out a 177 CHOPS well program.

Asia Pacific Region

China

Block 29/26

At the Liwan Gas Project development, testing and commissioning is underway. All nine wells on the Liwan 3-1 gas field are complete and ready for production and first production is expected in the latter part of the first quarter of 2014.

The platform topsides were completed and transported approximately 2,500 kilometers from Qingdao, China to the South China Sea and successfully installed onto the jacket. In addition, the 261 kilometers of shallow water pipeline from the central platform to the gas plant and construction of the onshore gas plant was completed. Five major construction vessels and their support vessels were in operation during 2013 while construction continued on the deep water facilities. Despite encountering unusually difficult weather conditions during an extended typhoon season in late 2013, all piping to connect the individual wells to the manifolds and the manifolds to the connecting infield production flow lines was installed. Final testing and commissioning of the gas plant and offshore infrastructure is now underway.

The single development well of the Liuhua 34-2 field is expected to be tied into the Liwan 3-1 field deep water facilities, with production expected later in the second half of 2014. Production from the Liwan Gas Project is scheduled to go off-line in the second half of 2014 for approximately six to eight weeks to tie in the Liuhua 34-2 field.

Negotiations for the sale of gas and liquids from the third deep water field, Liuhua 29-1, are ongoing.

Offshore Taiwan

The acquisition of two-dimensional seismic survey data on the Company’s offshore Taiwan block commenced in September 2013, and approximately half of the minimum committed survey distance was completed, with the remainder planned for the second half of 2014.

Indonesia

Progress continued on the shallow water gas developments in the Madura Strait Block during 2013. The BD field engineering and construction has commenced. The last outstanding tender for the BD field floating production, storage and offloading vessel (“FPSO”) is awaiting government approval, and the tender plans for the combined MDA and MBH development projects are under final review by Indonesia’s regulatory authority. The Government of Indonesia appointed a lead distributor for the majority of the gas to be produced from the MDA and MBH fields and the negotiation of a gas sales contract is in progress. Exploration drilling on the block resulted in an additional discovery, the MBF field, located west of the MBH field.

Oil Sands

Sunrise Energy Project

Phase 1 of the Sunrise Energy Project remains on track for start up in the second half of 2014.

Management’s Discussion and Analysis 2013

11

The Central Processing Facility is more than 75% complete, with major equipment installed and field tanks and buildings for Plant 1A now in place. In addition, all modules have been delivered and major equipment installation has been completed for Plant 1B. Field facilities are substantially complete. The main power line to the plant is now energized and the testing of piping and the completion of remaining electrical and instrumentation work is an area of focus in advance of the planned systems turn over. Six of the eight well pads have been turned over, with commissioning underway on four well pads. The remaining two well pads are targeted to be turned over in early 2014. To date, approximately 90% of the project’s total cost estimate has been spent.

Development work continued on the next phase of the project with the Design Basis Memorandum completed in 2013. Early engineering is underway.

McMullen

During 2013, 51 wells were drilled and 49 wells were placed on production in the conventional portion of the Company’s McMullen play. CHOPS production from 27 wells drilled and completed on three well pads commenced in late 2013. In addition, at the air injection pilot, the Company received approval from the Alberta Energy Regulator in 2013 to allow an additional three horizontal wells to be brought on production, bringing the total number of producing wells to six at the pilot.

Atlantic Region

White Rose Field and Satellite Extensions

Government and regulatory approval was granted for a development plan amendment to include gas injection and storage at the South White Rose Extension. The development plan amendment will also enable the production of additional reserves from the main White Rose field. Installation of gas injection equipment to support the South White Rose Extension was completed at the end of 2013, with gas injection commencing in early 2014. Installation of oil production equipment is scheduled in 2014, with first oil anticipated by the end of 2014.

A number of key milestones were met for the West White Rose Extension project, including approval of a benefits agreement with the Government of Newfoundland and Labrador, release of the environmental impact assessment for further federal and provincial approval, and submission of the Development Application to the Canada-Newfoundland and Labrador Offshore Petroleum Board. Husky and its partners progressed detailed engineering, design and due diligence in anticipation of a final investment decision.

At North Amethyst, development continued with the drilling and completion of the North Amethyst G-25-8 water injection well. In addition, the North Amethyst G-25-9 multilateral well was completed and brought online in late November, with average gross production of 20,000 bbls/day (14,000 bbls/day net Husky share). This concludes the wells proposed as part of the base plan for the North Amethyst field and the Company continues to examine additional oil recovery improvement opportunities. Drilling has commenced on the North Amethyst Hibernia formation well, which will target a secondary deeper zone below the main North Amethyst field. The well is expected to be brought on production later in 2014.

Atlantic Exploration

Husky and its partner made two significant discoveries in the year of a high-quality, light, sweet crude oil resource in the Flemish Pass Basin. The first discovery was made at the Harpoon O-85 well followed by a second discovery made at the Bay Du Nord prospect, both located approximately 500 kilometres offshore Newfoundland. The evaluation of well results at the Harpoon discovery is ongoing with further appraisal drilling required to assess the potential of the prospect. The evaluation of well results at the Bay Du Nord prospect has confirmed significant quantities of hydrocarbons with best estimate contingent resources estimated by Husky at 400 million barrels on a 100% working interest basis as at December 31, 2013. The two discoveries made in the year bring the total number of significant discoveries in the region to three with the 2009 Mizzen discovery of slightly heavier oil with best estimate contingent resources estimated by Husky at 130 million barrels on a 100% working interest basis as at December 31, 2013. Husky holds a 35% working interest in all three wells.

The Husky-operated White Rose H-70 delineation well, which is part of a near-field drilling program northwest of the main White Rose field, encountered hydrocarbons and the evaluation of results is ongoing. Husky holds a 68.875% working interest in the well. The non-operated Federation well in the southern Jeanne d’Arc Basin did not encounter commercial quantities of hydrocarbons and was expensed.

Infrastructure and Marketing

The Hardisty terminal expansion project includes multiple initiatives intended to increase pipeline connectivity and re-configure the existing terminal facility to accommodate the expansion and inclusion of the Company as a Western Canadian Select stream

Management’s Discussion and Analysis 2013

12

participant by 2015. In 2013, detailed engineering, procurement and construction progressed on two 300,000-barrel tanks and procurement of long lead equipment continued for the required terminal reconfigurations in order to accommodate Western Canadian Select.

In order to accommodate the anticipated increase in production from heavy oil thermal development projects, the Company has undertaken initiatives related to the extension of pipeline systems from the Sandall thermal development project to Lloydminster and expansion of the South Saskatchewan Gathering System for the Rush Lake commerical project. Both initiatives are on track to align with anticipated production from these projects.

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 increased on-road diesel and jet fuel production volumes, was completed and brought on-line in early 2013. In addition, front-end engineering design commenced to revamp existing refinery process units and add new equipment to allow the refinery to process up to 40,000 bbls/day of Western Canadian heavy oil while maintaining the capability and flexibility to refine existing light crude oil. Regulatory approval was granted by the U.S. Environmental Protection Agency. The capability to refine heavy oil at the Husky Lima Refinery is anticipated by 2017.

BP-Husky Toledo Refinery

The Continuous Catalyst Regeneration Reformer Project at the BP-Husky Toledo Refinery was completed and became operational in early 2013. Work progressed on the Hydrotreater Recycle Gas Compressor Project during 2013 and is scheduled to be completed in 2014. The installation of a new recycle gas compressor in the existing hydrotreater is intended to improve operational integrity and plant performance. 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 2013

13

6.0 Results of Operations

6.1 Segment Earnings

	Earnings (Loss) before Income Taxes						Net Earnings (Loss)						Capital Expenditures(1)
($ millions)	2013			2012			2013			2012			2013		2012
Upstream(2)
Exploration and Production(2)		1,283			1,321			952			976			4,264		4,106
Infrastructure and Marketing(2)		392			462			292			346			96		54
Downstream
Upgrading		401			306			297			226			205		47
Canadian Refined Products		260			311			194			231			109		97
U.S. Refining and Marketing(2)		522			693			339			436			220		313
Corporate		(230	)		(257	)		(245	)		(193	)		134		84
Total		2,628			2,836			1,829			2,022			5,028		4,701

⁽¹⁾  Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the period.

⁽²⁾  Gross revenues, marketing and other and purchases have been recast for the comparative period to reflect a change in the classification of certain trading transactions.

6.2 Summary of Quarterly Results

⁽¹⁾ Cash flow from operations is a non-GAAP measure. (Refer to Section 11.3)

Management’s Discussion and Analysis 2013

14

6.3 Upstream

2013 Total Upstream Earnings $1,244 million

Exploration and Production

Exploration and Production Earnings Summary ($ millions)	2013			2012
Gross revenues(1)(2)		7,333			6,581
Royalties		(864	)		(693	)
Net revenues		6,469			5,888
Purchases, operating, transportation and administrative expenses		2,347			2,123
Depletion, depreciation, amortization and impairment		2,515			2,121
Exploration and evaluation expenses		246			344
Other expenses (income)		78			(21	)
Income taxes		331			345
Net earnings		952			976

⁽¹⁾ Gross revenues have been recast for the comparative period to reflect a change in the classification of certain trading transactions.

⁽²⁾  In 2013, the Company reclassified its processing facilities from Infrastructure and Marketing to Exploration and Production. Prior period amounts have been adjusted to conform with current presentation.

Exploration and Production net earnings, excluding an after-tax impairment of $204 million on Western Canada natural gas properties, were $180 million higher in 2013 compared with 2012, primarily due to higher average realized commodity prices, higher production from the Atlantic Region where the Company completed two major turnarounds in 2012, increased production from heavy oil thermal projects in Western Canada, and lower exploration and evaluation expenses. These were partially offset by higher depletion expense due to higher production and increased operating costs in Western Canada. Other expenses in 2013 were higher compared to 2012 due to an increase in accretion expense associated with increased remediation cost estimates associated with the growing asset base and a decrease in realized profits due to period changes in inventory balances.

Management’s Discussion and Analysis 2013

15

Average Sales Prices Realized	2013		2012
Crude oil and NGL ($/bbl)
Light crude oil & NGL		102.35		99.22
Medium crude oil		74.29		71.51
Heavy crude oil		63.44		61.91
Bitumen		61.68		59.49
Total crude oil and NGL average		78.12		75.50
Natural gas average ($/mcf)		3.19		2.60
Total average ($/boe)		61.96		57.16

During 2013, the average realized price for crude oil, NGL and bitumen increased 3% to $78.12/bbl compared with $75.50/bbl during 2012, primarily due to higher WTI prices combined with a weaker Canadian dollar partially offset by wider Western Canada crude oil differentials. Realized natural gas prices averaged $3.19/mcf during 2013 compared with $2.60/mcf in 2012, an increase of 23% as supply and demand fundamentals improved in 2013 compared to 2012.

Daily Gross Production	2013		2012
Crude oil and NGL (mbbls/day)
Western Canada
Light crude oil & NGL		29.7		30.1
Medium crude oil		23.2		24.1
Heavy crude oil		74.5		76.9
Bitumen(1)		47.7		35.9
		175.1		167.0
Atlantic Region
White Rose and Satellite Fields – light crude oil		39.3		30.8
Terra Nova – light crude oil		4.8		3.0
		44.1		33.8
China
Wenchang – light crude oil & NGL		7.3		8.4
Crude oil (mbbls/day)		226.5		209.2
Natural gas (mmcf/day)		512.7		554.0
Total (mboe/day)		312.0		301.5

(1) Bitumen production includes heavy oil thermal average daily gross production of 37.4 mbbls/day for the year ended December 31, 2013. Heavy oil thermal production typically receives a higher price than bitumen production.

Management’s Discussion and Analysis 2013

16

Exploration and Production Revenue Mix (Percentage of Upstream Net Revenues)	2013			2012
Crude oil
Light crude oil & NGL		43	%		43	%
Medium crude oil		9	%		10	%
Heavy crude oil		25	%		28	%
Bitumen		15	%		12	%
Crude oil		92	%		93	%
Natural gas		8	%		7	%
Total		100	%		100	%

During 2013, crude oil, bitumen and NGL production increased by 17.3 bbls/day or 8% compared with 2012, primarily due to increased production in Western Canada at the Pikes Peak South and Paradise Hill heavy oil thermal projects combined with higher production in the Atlantic Region, where the SeaRose and Terra Nova FPSO planned turnarounds were performed in 2012, partially offset by lower production at Wenchang due to typhoon related shut-ins.

Production from dry natural gas decreased by 41.3 mmcf/day or 7% in 2013 compared with 2012 due to natural reservoir declines in mature properties as capital investment continues to be directed at higher return oil and liquids-rich natural gas developments.

2014 Production Guidance and 2013 Actual

	Guidance		Year ended December 31		Guidance
Gross Production	2014		2013		2013
Crude oil, NGL and Asia Pacific Region (mbbls/day)
Light / Medium crude oil & NGL		110 - 115		104		110 - 120
Heavy crude oil & bitumen		125 - 130		122		110 - 120
Natural gas Asia Pacific Region (mboe/day)		25 - 30		—		—
Crude oil, NGL and Asia Pacific Region (mbbls/day)		260 - 275		226		220 - 240
Natural gas (mmcf/day)		420 - 480		513		540 - 580
Total (mboe/day)		330 - 355		312		310 - 330

The Company’s total production for the year ended December 31, 2013 was within production guidance. In 2012, the Company set a compound annual production growth rate of 5% to 8% through the plan period of 2012 to 2017, which it is on track to achieve. Husky expects that production levels in 2014 will be higher compared to 2013 due to new production from the Liwan Gas Project in the Asia Pacific Region and new production at North Amethyst in the Atlantic Region.

Factors that could potentially impact Husky’s production performance for 2014 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 12% of gross revenues in 2013 compared with 11% in 2012. Royalty rates in Western Canada averaged 12% in 2013 compared with 10% in 2012 due to a royalty credit adjustment received in 2012. Royalty rates in the Atlantic Region averaged 13% in 2013 compared with 11% in 2012 when lower rates reflected the ongoing SeaRose and Terra Nova FPSO turnarounds. Royalty rates in the Asia Pacific Region averaged 24% in both 2013 and 2012.

Management’s Discussion and Analysis 2013

17

Operating Costs

($ millions)	2013		2012
Western Canada		1,745		1,571
Atlantic Region		201		212
Asia Pacific		31		31
Total		1,977		1,814
Unit operating costs ($/boe)		16.28		15.49

Total operating costs increased to $1,977 million in 2013 from $1,814 million in 2012. Total Upstream unit operating costs in 2013 averaged $16.28/boe compared with $15.49/boe in 2012 due to higher energy consumption and increased natural gas and electricity prices associated with Western Canada crude oil production.

Operating costs in Western Canada increased to $17.05/boe in 2013 compared with $15.45/boe in 2012 primarily due to higher energy consumption and increased natural gas and electricity prices.

Operating costs in the Atlantic Region averaged $12.47/boe in 2013 compared with $17.12/boe in 2012. The decrease in operating costs was attributable to higher production and lower maintenance and supply costs compared to 2012 when the planned SeaRose and Terra Nova FPSO turnarounds were performed.

Operating costs in the Asia Pacific Region averaged $11.39/boe in 2013 compared with $10.08/boe in 2012. The increase was due to lower production associated with typhoon-related shut-ins in 2013.

Exploration and Evaluation Expenses

($ millions)	2013		2012
Seismic, geological and geophysical		133		140
Expensed drilling		102		188
Expensed land		11		16
Total		246		344

Total exploration and evaluation expenses decreased by $98 million in 2013 compared to 2012 primarily due to high drilling success rates, which resulted in more capitalized exploration costs. Expensed drilling in 2012 included costs related to the Searcher well in the Atlantic Region and the Liuhua 32-1-1 well in the Asia Pacific Region. The decrease in seismic, geological and geophysical expense in 2013 was primarily due to a shift from exploration to development activities in Western Canada and the Asia Pacific Region in 2013.

Depletion, Depreciation, Amortization (“DD&A”) and Impairment

During 2013, the Company recognized a pre-tax impairment charge of $275 million on certain conventional natural gas assets located in Western Canada. The impairment charge was the result of low estimated long-term future natural gas prices and the redirection of capital investments to higher yield oil and liquids-rich natural gas opportunities.

During 2013, total unit DD&A, excluding the impairment charge, was $19.67/boe compared to $19.20/boe during 2012.

At December 31, 2013, capital costs in respect of unproved properties and major development projects were $8.3 billion compared with $6.1 billion at the end of 2012. 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.

Management’s Discussion and Analysis 2013

18

⁽¹⁾  Operating netback is a non-GAAP measure and is equal to Husky’s realized price less royalties, operating costs and transportation costs on a per unit basis. Refer to section 11.3

Exploration and Production Capital Expenditures

In 2013, Upstream Exploration and Production capital expenditures were $4,264 million. Capital expenditures were $2,420 million (57%) in Western Canada, $552 million (13%) in Oil Sands, $638 million (15%) in the Atlantic Region and $654 million (15%) in the Asia Pacific Region.

Exploration and Production Capital Expenditures(1) ($ millions)	2013		2012
Exploration
Western Canada		353		238
Atlantic Region		201		13
Asia Pacific Region		21		22
		575		273
Development
Western Canada		2,029		2,029
Oil Sands		552		658
Atlantic Region		437		400
Asia Pacific Region		633		725
		3,651		3,812
Acquisitions
Western Canada		38		21
		4,264		4,106

⁽¹⁾  Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the period.

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:

	2013				2012
Wells Drilled (wells)	Gross		Net		Gross		Net
Exploration
Oil		39		24		47		30
Gas		19		14		19		12
Dry		—		—		—		—
		58		38		66		42
Development
Oil		768		709		775		715
Gas		68		41		23		17
Dry		1		—		5		4
		837		750		803		736
Total		895		788		869		778

The Company drilled 788 net wells in the Western Canada, Heavy Oil and Oil Sands business units in 2013 resulting in 733 net oil wells and 55 net natural gas wells compared to 778 net wells resulting in 745 net oil wells and 29 net natural gas wells in 2012.

Management’s Discussion and Analysis 2013

19

During 2013, Husky invested $2,420 million on exploration, development and acquisitions, including Heavy Oil, throughout the Western Canada Sedimentary Basin compared to $2,288 million in 2012. Property acquisitions totalling $38 million were completed in 2013 compared to $21 million in 2012. Investment in oil related exploration and development was $576 million in 2013 compared to $538 million in 2012. Investment in natural gas related exploration and development, primarily liquids-rich, was $596 million in 2013 compared to $500 million in 2012.

In addition, $232 million was spent on production optimization and cost reduction initiatives in 2013. Capital expenditures on facilities, land acquisition and retention, and environmental protection totalled $349 million.

Capital expenditures on heavy oil thermal projects, CHOPS drilling and horizontal drilling were $629 million during 2013 compared to $586 million in 2012.

Oil Sands

During 2013, $552 million was invested in Oil Sands projects, primarily for Phase 1 of the Sunrise Energy Project. In addition, the Company drilled 34 gross (17 net) evaluation wells for the next phase of the Sunrise Energy Project.

Atlantic Region

The following table discloses Husky’s offshore Atlantic Region drilling activity during 2013:

Atlantic Region Offshore Drilling Activity

Well	Working Interest			Well Type
North Amethyst G-25 9		WI 68.875	%	Development (Producer)
Terra Nova E-18-12Z		WI 13	%	Development (Producer)
North Amethyst G-25-8		WI 68.875	%	Development (Injector)
Harpoon 0-85		WI 35	%	Exploration
Bay Du Nord C-78		WI 35	%	Exploration
Federation K-78		WI 35	%	Exploration
White Rose H-70		WI 68.875	%	Delineation
White Rose H-70Z		WI 93.33	%	Delineation
Terra Nova E-19		WI 13	%	Delineation

During 2013, $638 million was invested in Atlantic Region projects, primarily on the continued development of the White Rose Extension projects, including the North Amethyst and South White Rose Extension satellite fields and exploration at the Bay Du Nord and Harpoon discoveries made during the year.

Asia Pacific Region

Total capital expenditures of $654 million were invested in the Asia Pacific Region in 2013, primarily for development of the Liwan Gas Project. In addition, the Company drilled the MBF-1 exploration well (50% interest) and the MAX-3 appraisal well (40% interest) at the Madura Strait in Indonesia in 2013.

2014 Upstream Capital Program

($ millions)
Western Canada	2,500
Oil sands	400
Atlantic Region	600
Asia Pacific Region	500
Total Upstream capital expenditures(1)	4,000

⁽¹⁾  Capital program excludes capitalized administration costs, capitalized interest and asset retirement obligations incurred.

The 2014 Capital Program will enable Husky to build on the momentum achieved over the past three 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 $500 million for the Asia Pacific Region in 2014, mainly for the completion of the Liwan Gas Project including the tie-in of the Liuhua 34-2 field into the Liwan deep water infrastructure and development of the Madura Strait block in Indonesia.

Management’s Discussion and Analysis 2013

20

Oil Sands capital for 2014 will primarily be for completing the development of Phase 1 of the Sunrise Energy Project as well as planning, design and engineering for the next phase of the project.

Budgeted investment in the Atlantic Region of $600 million is for continued development of the White Rose fields and extensions. The Company plans to conduct additional drilling in 2014 in the Flemish Pass Basin to further assess the economic potential of oil development following the three major discoveries.

In addition to advancing mid and long-term growth pillars, the 2014 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 2014. 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 10,000 bbls/day Rush Lake thermal project, with expected first production in the second half of 2015. In addition, two 10,000 bbls/day thermal developments were sanctioned in late 2013 at Edam East and Vawn, both located in Saskatchewan, with construction scheduled to begin in 2014.

Upstream Turnarounds

2013 Turnarounds

A planned maintenance turnaround was completed on the SeaRose FPSO during 2013. The six-day shutdown focused on annual regulatory inspections and maintenance and tie-in of equipment for the South White Rose Extension.

An 11-week turnaround of the Terra Nova FPSO was completed in 2013. The planned maintenance shutdown was extended to accommodate repair and replacement of nine mooring chains. The impact to Husky’s 2013 annual production was approximately 2,100 bbls/day.

Planned Turnarounds

Planned plant maintenance activities for Western Canada are scheduled in the second and third quarters of 2014, including the full shutdown and maintenance of the Rainbow oil and gas facility for approximately four weeks in the second quarter.

In the Atlantic Region, the partner-operated Terra Nova FPSO is scheduled to undergo a 28-day turnaround in the third quarter of 2014.

A planned offstation for the Wenchang FPSO is scheduled for approximately five months in 2014. The offstation is intended to address dry dock maintenance and mooring line replacement.

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, 2013. 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.

Note: All heavy oil thermal reserves are classified as bitumen.

Management’s Discussion and Analysis 2013

21

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.

Sproule Unconventional Limited (“Sproule”), an independent firm of oil and gas reserves evaluation engineers, was engaged to conduct a full evaluation of Husky’s crude oil, natural gas and natural gas products reserves for the Heavy Oil and Gas business unit, excluding the Tucker property.

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, excluding those estimated by Sproule. McDaniel & Associates Consultants Ltd. issued an audit opinion stating that Husky’s internally evaluated 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, 2013, Husky’s proved oil and gas reserves were 1,265 mmboe, up from 1,192 mmboe at the end of 2012. Additions to proved reserves, including acquisitions and divestitures, represent 166% excluding economic revisions (164% including economic revisions) of 2013 production. Major additions to proved reserves in 2013 included:

• The extension through additional drilling locations at the Sunrise Energy Project in the Oil Sands that resulted in the booking of an additional 39 mmbbls of bitumen in proved undeveloped reserves;

• The project sanction at the South White Rose Extension in the Atlantic Region that resulted in the booking of an additional 7 mmbbls of light oil in proved undeveloped reserves; and

• The extension through additional drilling locations at the Ansell liquids-rich natural gas resource play in the Alberta Deep Basin that resulted in the booking of an additional 32 mmboe of natural gas and NGL in proved undeveloped reserves.

Note: Reserves reported represent proved plus probable reserves.

Management’s Discussion and Analysis 2013

22

Reconciliation of Proved Reserves

(forecast prices and costs before royalties)	Canada																		International					Total
	Western Canada															Atlantic Region
	Light Crude Oil & NGL (mmbbls)			Medium Crude Oil (mmbbls)			Heavy Crude Oil (mmbbls) (1)			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, 2012		173			95			105			311			2,073			68			22			434		774			2,507			1,192
Revision of previous estimate		(10	)		(3	)		7			24			79			13			3			—		34			79			48
Purchase of reserves in place		—			—			—			1			1			—			—			—		1			1			1
Sale of reserves in place		—			—			—			—			(3	)		—			—			—		—			(3	)		(1	)
Discoveries, extensions and improved recovery		15			7			28			40			232			9			1			18		100			250			142
Economic revision		1			—			—			—			(20	)		—			—			—		1			(20	)		(3	)
Production		(12	)		(8	)		(27	)		(17	)		(187	)		(16	)		(3	)		—		(83	)		(187	)		(114	)
Proved reserves December 31, 2013		167			91			113			359			2,175			74			23			452		827			2,627			1,265
Proved and probable reserves December 31, 2013		223			112			176			1,870			2,669			125			33			859		2,539			3,528			3,127
December 31, 2012		229			117			140			1,725			2,547			130			30			718		2,371			3,265			2,915

⁽¹⁾  Heavy oil thermal property reserves are classified as bitumen.

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)(1)			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, 2012		149			88			84			59			1,714			56			8			—		444			1,714			729
Revision of previous estimate		(6	)		(2	)		14			11			106			12			2			—		31			106			50
Transfer from proved undeveloped		4			3			6			13			58			8			8			267		42			325			97
Purchase of reserves in place		—			—			—			—			1			—			—			—		—			1			—
Sale of reserves in place		—			—			—			—			(3	)		—			—			—		—			(3	)		(1	)
Discoveries, extensions and improved recovery		10			4			15			—			33			—			—			—		29			33			34
Economic revision		1			—			—			—			(20	)		—			—			—		1			(20	)		(3	)
Production		(12	)		(8	)		(27	)		(17	)		(187	)		(16	)		(3	)		—		(83	)		(187	)		(114	)
Proved developed reserves December 31, 2013		146			85			92			66			1,702			60			15			267		464			1,969			792

⁽¹⁾  Heavy oil thermal property reserves are classified as bitumen.

Infrastructure and Marketing

The Company is engaged in the marketing of its own and other producers’ crude oil, natural gas, NGL, sulphur and petroleum coke production. The Company owns extensive infrastructure in Western Canada, including pipeline and storage facilities, and has access to capacity on third-party pipelines and storage facilities in both Canada and the United States.

Management’s Discussion and Analysis 2013

23

Infrastructure and Marketing Earnings Summary ($ millions, except where indicated)	2013			2012
Infrastructure gross margin(1)		130			119
Marketing and other gross margin(2)		312			398
Gross margin		442			517
Operating and administrative expenses		33			33
Depletion, depreciation and amortization		20			22
Other expenses		(3	)		—
Income taxes		100			116
Net earnings		292			346
Commodity trading volumes managed (mboe/day)		174.5			180.1

⁽¹⁾  In 2013, the Company reclassified its processing facilities from Infrastructure and Marketing to Exploration and Production. Prior period amounts have been adjusted to conform with current presentation.

⁽²⁾  Marketing and other gross margin has been recast to reflect a change in the classification of certain trading transactions.

Infrastructure and Marketing net earnings decreased by $54 million in 2013 compared to 2012 due to lower marketing margins as a result of the narrowing of WTI to Brent crude oil price differentials in the second and third quarters of 2013 and fewer arbitrage opportunities available from utilizing the Company’s access to infrastructure to move crude oil from Canada to the United States.

Infrastructure and Marketing capital expenditures totalled $96 million in 2013 compared to $54 million in 2012. The majority of Infrastructure and Marketing capital expenditures during the year related to pipeline maintenance and storage tank expenditures.

6.4 Downstream

2013 Total Downstream Earnings $830 million

Upgrader

Management’s Discussion and Analysis 2013

24

Upgrader Earnings Summary ($ millions, except where indicated)	2013			2012
Gross revenues		2,023			2,191
Gross margin		645			555
Operating and administrative expenses		168			153
Depreciation and amortization		96			102
Other income		(20	)		(6	)
Income taxes		104			80
Net earnings		297			226
Upgrader throughput(1) (mbbls/day)		66.1			77.4
Synthetic crude oil sales (mbbls/day)		50.5			60.4
Upgrading differential ($/bbl)		29.14			22.34
Unit margin ($/bbl)		34.99			25.17
Unit operating cost(2) ($/bbl)		6.96			5.42

⁽¹⁾ Throughput includes diluent returned to the field.

⁽²⁾  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.

The increase in Upgrader earnings in 2013 compared to 2012 was primarily due to higher upgrading differentials that resulted from a deep discount on Lloyd Heavy Blend feedstock in early and late 2013 and higher realized prices for Husky Synthetic Blend crude oil, partially offset by lower throughput due to a major planned turnaround completed in the year.

During 2013, the price of Husky’s synthetic crude oil averaged $100.57/bbl compared with the average cost of blended heavy crude oil from the Lloydminster area of $71.43/bbl. During 2012, the price of Husky’s synthetic crude oil averaged $91.90/bbl compared with an average cost of blended heavy crude oil from the Lloydminster area of $69.56/bbl. This resulted in an average synthetic/heavy crude oil differential of $29.14/bbl in 2013 compared to $22.34/bbl in 2012 and a gross unit margin of $34.99/bbl in 2013 compared to $25.17/bbl in 2012. The cost of upgrading averaged $6.96/bbl in 2013 compared to $5.42/bbl in 2012, due to the major planned turnaround in 2013, which resulted in a net margin for upgrading heavy crude of $28.03/bbl, up 42% compared with $19.75/bbl in 2012.

Canadian Refined Products

Management’s Discussion and Analysis 2013

25

Canadian Refined Products Earnings Summary ($ millions, except where indicated)	2013		2012
Gross revenues		3,737		3,848
Gross margin
Fuel		140		153
Refining		175		180
Asphalt		233		257
Ancillary		55		50
		603		640
Operating and administrative expenses		253		242
Depreciation and amortization		90		83
Other expense		—		4
Income taxes		66		80
Net earnings		194		231
Number of fuel outlets(1)		509		531
Fuel sales volume, including wholesale
Fuel sales (million of litres/day)(2)		8.1		8.7
Fuel sales per outlet (thousand of litres/day)(2)		13.5		13.1
Refinery throughput
Prince George refinery (mbbls/day)		10.3		11.1
Lloydminster refinery (mbbls/day)		26.4		28.3
Ethanol production (thousand of litres/day)		742.4		721.2

⁽¹⁾  Average number of fuel outlets for period indicated.

⁽²⁾  Fuel sales have been recast to exclude non-retail products. Prior periods have been adjusted to conform with the current period presentation.

Fuel margins decreased in 2013 compared to 2012 primarily due to lower diesel margins, decreased wholesale sales volumes and lower fuel sales resulting from retail site construction and selected outlet closures.

Refining gross margins decreased slightly in 2013 compared to 2012 primarily due to higher priced feedstock costs and lower throughput and sales volumes, partially offset by higher realized prices for refined products.

Asphalt gross margins decreased compared to the same period in 2012 primarily due to lower asphalt production as a result of a scheduled refinery turnaround in the year.

Management’s Discussion and Analysis 2013

26

U.S. Refining and Marketing

U.S. Refining and Marketing Earnings Summary ($ millions, except where indicated)	2013		2012
Gross revenues(1)		10,728		9,856
Gross refining margin(1)		1,182		1,312
Operating and administrative expenses		424		398
Depreciation and amortization		233		212
Other expenses		3		9
Income taxes		183		257
Net earnings		339		436
Selected operating data:
Lima Refinery throughput (mbbls/day)		149.4		150.0
BP-Husky Toledo Refinery throughput (mbbls/day)		65.0		60.6
Refining margin (U.S. $/bbl crude throughput)(1)		15.06		17.48
Refinery inventory (feedstocks and refined products) (mmbbls)(2)		10.3		11.3

⁽¹⁾  Gross revenues and purchases have been recast for the comparative period to reflect a change in the classification of certain trading transactions.

⁽²⁾ Refinery inventory includes feedstock and refined products.

U.S. Refining and Marketing net earnings in 2013 decreased compared to 2012 primarily due to a significant drop in the Chicago 3:2:1 market crack spread in the second half of 2013, resulting in an annual decrease of approximately $300 million in gross refining margin, partially offset by increased throughput at the BP-Husky Toledo Refinery due to turnaround activity in 2012.

The Chicago 3:2:1 market crack spread 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 lower. The estimated FIFO impact was a reduction in net earnings of approximately $18 million in 2013 compared to a reduction in net earnings of $28 million in 2012.

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 $534 million for 2013 compared to $457 million in 2012. In Canada, capital expenditures were $314 million related to upgrades at the Prince George Refinery, the Upgrader and at retail stations. In the United States, capital expenditures totalled $220 million. At the Lima Refinery, $143 million was spent on various process improvement projects, optimizations and environmental initiatives. At the BP-Husky Toledo Refinery, capital expenditures totalled $77 million (Husky’s 50% share) and were primarily for facility upgrades and environmental protection initiatives.

Management’s Discussion and Analysis 2013

27

Downstream Planned Turnarounds

The Lloydminster Upgrader is scheduled to undergo a partial outage in the fall of 2014 for planned maintenance. Plant rates are expected to remain at approximately 80% during the planned 42-day turnaround.

The Lima Refinery is scheduled to complete a major turnaround in 2015 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 2016. In addition, the Refinery is scheduled to undergo an 18-day outage in March 2014 for planned maintenance to prepare for the major turnaround in 2015. The Refinery is expected to operate at approximately 60% capacity during the outage.

The BP-Husky Toledo Refinery is scheduled to complete a turnaround in 2014 that will affect approximately 30% of its operating capacity. Refinery operations will be impacted for approximately 35 to 50 days depending on the unit. The remaining 70% of the operating units are scheduled to be addressed in a turnaround planned for 2015.

6.5 Corporate

2013 Loss $245 million

Corporate Summary ($ millions) income (expense)	2013			2012
Administration expenses		(112	)		(128	)
Stock-based compensation		(105	)		(54	)
Depreciation and amortization		(51	)		(40	)
Other income		17			3
Foreign exchange gains		21			14
Interest - net		—			(52	)
Income taxes		(15	)		64
Net loss		(245	)		(193	)

The Corporate segment reported a loss in 2013 of $245 million compared to a loss of $193 million in 2012. Stock-based compensation expense increased by $51 million in 2013 due to a higher share price at the end of 2013 compared to 2012. Interest - net decreased by $52 million in 2013 compared to 2012 due to increases in amounts of capitalized interest related to projects in the Asia Pacific Region and the Sunrise Energy Project. Other income increased by $14 million in 2013 compared to 2012 primarily due to the recovery of an insurance provision from the prior year.

Foreign Exchange Summary ($ millions, except exchange rate amounts)	2013			2012
Gains (losses) on translation of U.S. dollar denominated long-term debt		(11	)		43
Gains on cross currency swaps		—			2
Gains (losses) on contribution receivable		27			(7	)
Other foreign exchange gains (losses)		5			(24	)
Foreign exchange gains		21			14
U.S./Canadian dollar exchange rates:
At beginning of year	U.S. $	1.005		U.S. $	0.983
At end of year	U.S. $	0.940		U.S. $	1.005

Consolidated Income Taxes

Consolidated income taxes decreased in 2013 to $799 million from $814 million in 2012, resulting in an effective tax rate of 30% in 2013 compared to 29% in 2012. The increase in the effective tax rate was attributable to the increase in non-deductible stock-based compensation expense.

($ millions)	2013		2012
Income taxes as reported		799		814
Cash taxes paid		433		575

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 are now payable over a five-year period that commenced in 2013.

Management’s Discussion and Analysis 2013

28

Corporate Capital Expenditures

Corporate capital expenditures of $134 million in 2013 were primarily related to computer hardware and software and leasehold improvements.

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

The Company’s businesses are subject to inherent operational risks and hazards in respect to 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 that 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. Enterprise risk management, 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

The Company’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 the Company’s financial performance and condition, reduce the value and quantities of 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.

The Company’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.

Management’s Discussion and Analysis 2013

29

The fluctuations in crude oil and natural gas prices are beyond the Company’s control and accordingly, could have a material adverse effect on the Company’s business, financial condition and cash flow.

For information on 2013 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 could negatively affect the Company’s reputation, investor confidence and the Company’s ability to deliver on its growth strategy.

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. 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 potential development 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 and Pipeline Interruptions

The Company’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 by regulatory and/or other marketplace barriers. The interruptions and restrictions may be caused by the inability of a pipeline to operate, or they can be related to capacity constraints as the supply of feedstock into the system exceeds the infrastructure capacity. With growing 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. Unplanned shutdowns and closures of our refineries or upgrader may limit our ability to deliver product with negative implications on sales from operating activities.

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. Security and terrorist threats may also impact the Company’s personnel, which could result in death, injury, hostage taking and/or kidnapping. This 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. This could 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 the Company’s current and future business strategies. However, a tight labour market, an insufficient number of qualified candidates, and an aging workforce are factors that could precipitate a human resource risk for the Company. Failure to manage any of the foregoing developments, 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 the Company’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

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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 the Company 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. The Company is at times dependent upon its partners for the successful execution of various projects. If a dispute with partners were to occur over the development and operation of a project, or if partners were unable to fund their contractual share of the capital expenditures, a 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. Estimates of the economically recoverable oil and gas reserves attributable to any particular group of properties, prepared by different engineers or by the same engineers at different times, may vary substantially. All reserves estimates 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 the Company’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, anti-corruption laws, reserves access, limitations or increases 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.

Environmental Regulation

The Company 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 the Company’s financial condition and results of operations.

Following the 2010 Deepwater Horizon oil spill in the Gulf of Mexico, the United States implemented stricter regulation of offshore oil and gas operations 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 the Company’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.

The transportation of crude oil by rail is an emerging issue for the petroleum industry. There have been four major incidents in the past eight months involving Bakken crude oil transported on rail, and federal and industry reviews of regulations and equipment standards are underway. In early 2014, Transport Canada announced proposed regulatory amendments to further improve the safety of the transportation of dangerous goods by rail. This may result in stricter standards, larger fines and liabilities, and increased capital expenditures for the petroleum industry.

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Climate Change Regulation

The Company continues to monitor the international and domestic efforts to address climate change, including international low carbon fuel standards and regulations and emerging regulations in the jurisdictions in which the Company operates. Existing regulations in Alberta require facilities that emit more than 100,000 tonnes of carbon dioxide equivalent in a year to reduce their emissions intensity by up to 12% below an established baseline emissions intensity. These regulations currently affect the Company’s Ram River Gas Plant and Tucker Thermal Oil Facility and are anticipated to affect the Sunrise Energy Project when it begins to produce oil. British Columbia currently has a $30 per tonne carbon tax that is placed on fuel the Company uses in that jurisdiction, which affects all of the Company’s operations in British Columbia. The Saskatchewan government is anticipated to release regulations similar to Alberta’s and the Federal Government of Canada has announced pending regulations for the oil and gas sector. Climate change regulations may become more onerous over time as public and political pressures increase to implement initiatives that further reduce the emissions of greenhouse gases. Although the impact of emerging regulation is uncertain, they may adversely affect the Company’s operations and increase costs.

In addition, the Company’s operations may be materially impacted by application of the EPA’s climate change rules or by future U.S. greenhouse gas legislation that applies 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 U.S. refining operations to significantly reduce emissions and/or purchase allowances, which may increase capital and operating expenditures.

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. The Company competes with others to acquire prospective lands, retain drilling capacity and field operating and construction services, obtain sufficient pipeline and other transportation capacity, gain access to and retain adequate markets for its products and services, and gain access to capital markets. The Company’s ability to successfully complete development projects could be 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. Competitors comprise all types of energy companies, some of which have greater resources.

Internal Credit Risk

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

General Economic Conditions

General economic conditions may have a material adverse effect on the Company’s results of operations, 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 lack of availability of oil and gas field equipment could adversely affect the Company’s ability to undertake exploration, development and construction projects. The oil and gas industry is cyclical in nature and is prone to shortages of supply of equipment and services including 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. This 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 adverse financial impacts.

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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, the Company 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 2013 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.

Foreign Currency Risk

The Company’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, 2013, the amount that the Company designated was U.S. $3.2 billion (December 31, 2012 - U.S. $2.8 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.

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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)	As at December 31, 2013			As at December 31, 2012
Derivatives – fair value through profit or loss (“FVTPL”)
Accounts receivable		18			13
Accounts payable and accrued liabilities		(19	)		(5	)
Other assets, including derivatives		2			1
Other – FVTPL(1)
Accounts payable and accrued liabilities		(29	)		(27	)
Other long-term liabilities		(31	)		(78	)
Hedging instruments(2)
Derivatives designated as cash flow hedge		37			1
Hedge of net investment(3)		(93	)		88
		(115	)		(7	)
Net gains (losses) for the year related to financial instruments held at fair value		(111	)		122
Included in net earnings		33			104
Included in OCI		(144	)		18

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

⁽²⁾  Hedging instruments are presented net of tax.

⁽³⁾  Represents the translation of the Company’s 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 2013, Husky funded its capital programs and dividend payments through cash generated from operating activities and cash on hand. At December 31, 2013, Husky had total debt of $4,119 million partially offset by cash on hand of $1,097 million for $3,022 million of net debt compared to $1,893 million of net debt as at December 31, 2012. At December 31, 2013, the Company had $3.6 billion of unused credit facilities of which $3.2 billion was long-term committed credit facilities and $371 million was short-term uncommitted credit facilities. In addition, the Company had $3.0 billion in unused capacity under its December 2012 Canadian universal short form base shelf prospectus and U.S. $3.0 billion in unused capacity under its October 2013 U.S. universal short form base shelf prospectus. The ability of the Company to utilize the capacity under its base shelf prospectuses is dependent on market conditions at the time of sale. Refer to Section 8.2.

	2013			2012
Cash flow
Operating activities ($ millions)		4,645			5,193
Financing activities ($ millions)		(846	)		(162	)
Investing activities ($ millions)		(4,722	)		(4,834	)
Financial Ratios(1)
Debt to capital employed (percent)(2)		17.0			17.0
Debt to cash flow (times)(3)(4)		0.8			0.8
Corporate reinvestment ratio (percent)(3)(5)		108			106
Interest coverage on long-term debt only(3)(6)
Earnings		11.2			12.5
Cash flow		22.4			24.9
Interest coverage on total debt(3)(7)
Earnings		11.3			12.3
Cash flow		22.6			24.6

⁽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 $4,645 million in 2013 compared to $5,193 million in 2012, primarily due to a decrease in non-cash working capital resulting from the timing of accounts payable settlements and inventory movement. The decrease in cash flow generated from operating activities was partially offset by higher crude oil production and realized commodity prices in Exploration and Production.

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Cash Flow used for Financing Activities

Cash used for financing activities was $846 million in 2013 compared to $162 million in 2012. The increase in cash flow used for financing activities was primarily due to higher cash versus stock dividends paid in 2013 compared to 2012.

Cash Flow used for Investing Activities

Cash used for investing activities was $4,722 million in 2013 compared to $4,834 million in 2012. Cash invested in both periods was primarily for capital expenditures.

8.2 Working Capital Components

Working capital is the amount by which current assets exceed current liabilities. At December 31, 2013, Husky’s working capital was $754 million compared with $2,401 million at December 31, 2012.

Movement in Working Capital

($ millions)	December 31, 2013			December 31, 2012			Increase/ (Decrease)
Cash and cash equivalents		1,097			2,025			(928	)
Accounts receivable		1,458			1,345			113
Income taxes receivable		461			323			138
Inventories		1,812			1,736			76
Prepaid expenses		89			64			25
Accounts payable and accrued liabilities		(3,155	)		(2,985	)		(170	)
Asset retirement obligations		(210	)		(107	)		(103	)
Long-term debt due within one year		(798	)		—			(798	)
Net working capital		754			2,401			(1,647	)

The decrease in cash was primarily due to lower cash flow from operations in the year and higher cash versus stock dividends paid in 2013 compared to 2012. Movements in accounts receivable, income taxes receivable and accounts payable were due to the timing of settlements compared to 2012. The increase in long-term debt due within one year was due to the reclassification of long-term debt maturing in 2014 to current liabilities as at December 31, 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, 2013, no production was hedged.

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At December 31, 2013, Husky had the following available credit facilities:

Credit Facilities ($ millions)	Available		Unused
Operating facilities(1)		595		371
Syndicated bank facilities		3,200		3,200
		3,795		3,571

⁽¹⁾  Consists of demand credit facilities.

Cash and cash equivalents at December 31, 2013 totalled $1,097 million compared to $2,025 million at the beginning of the year.

At December 31, 2013, Husky had unused short and long-term borrowing credit facilities totalling $3.6 billion. A total of $224 million of the Company’s short-term borrowing credit facilities was used in support of outstanding letters of credit.

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. During the year ended December 31, 2013, the Company declared dividends payable of $1.20 per common share, resulting in dividends of $1,180 million. An aggregate of $1,171 million was paid in cash during 2013. At December 31, 2013, $295 million, including $291 million in cash and $4 million in common shares, was payable to shareholders on account of dividends declared on October 24, 2013. Commencing in the fourth quarter of 2013, the Board of Directors discontinued the payment of dividends by way of the issuance of common shares. The change became effective with the dividend declaration in February 2014.

On March 22, 2012, the Company issued U.S. $500 million of 3.95% senior unsecured notes due April 15, 2022 pursuant to a universal short form base shelf prospectus filed with the Alberta Securities Commission and the U.S. Securities and Exchange Commission (“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, 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. 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. In February 2013, the limit on the $1.5 billion facility was increased to $1.6 billion. There continues to be no difference between the terms of these facilities, other than their maturity dates. As at December 31, 2013, there were no amounts drawn under the facilities.

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 in Canada up to and including January 30, 2015. As at December 31, 2013, the Company had not issued securities under the Canadian Shelf Prospectus.

On October 31, 2013 and November 1, 2013, the Company filed a universal short form base shelf prospectus (the “U.S. Shelf Prospectus”) with the Alberta Securities Commission and the SEC, respectively, that enables the Company to offer up to U.S. $3.0 billion of debt securities, common shares, preferred shares, subscription receipts, warrants and units of the Company in the United States up to and including November 30, 2015. During the 25-month period that the U.S. Shelf Prospectus is effective, securities may be offered in amounts, at prices and on terms set forth in a prospectus supplement. As at December 31, 2013, the Company had not issued securities under the U.S. Shelf Prospectus.

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

Capital Structure	December 31, 2013
($ millions)	Outstanding		Available(1)
Total long-term debt		4,119		3,571
Common shares, retained earnings and other reserves		20,078

⁽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)	2014		2015-2016		2017-2018		Thereafter		Total
Long-term debt and interest on fixed rate debt		1,015		882		632		3,163		5,692
Operating leases		155		526		432		367		1,480
Firm transportation agreements		289		548		525		2,702		4,064
Unconditional purchase obligations(1)		2,287		1,977		51		71		4,386
Lease rentals and exploration work agreements		107		251		180		1,208		1,746
Asset retirement obligations(2)		132		226		221		11,666		12,245
		3,985		4,410		2,041		19,177		29,613

⁽¹⁾ Includes purchase of refined petroleum products, processing services, distribution services, insurance premiums, drilling services and natural gas purchases.

⁽²⁾ Asset retirement obligation amounts represent the undiscounted future payments for the estimated cost of abandonment, removal and remediation associated with retiring the Company’s assets.

The Company updated its estimates for Asset Retirement Obligations as outlined in Note 16 to the 2013 Consolidated Financial Statements. On an undiscounted basis, the ARO increased from $10.3 billion as at December 31, 2012 to $12.3 billion as at December 31, 2013, due to increased cost estimates and asset growth in both the Upstream and Downstream segments.

The Company is in the process of renegotiating certain purchase, distribution and terminal commitments related to light oil and asphalt products as the existing contracts are approaching expiration.

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.

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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 86 active employees, 97 participants with deferred benefits and 532 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 210 active union represented employees in the United States, which was curtailed effective July 31, 2013. A defined benefit pension plan for 175 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 2013 Consolidated Financial Statements).

Husky has an obligation to fund capital expenditures of the BP-Husky Toledo Refinery (Refer to Note 8 to the 2013 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, 2013, 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, results of operations, liquidity or capital expenditures.

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

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, 2013, the senior notes are included in long-term debt in the Company’s consolidated balance sheets.

On December 7, 2010, the Company issued 28.9 million common shares at a price of $24.50 per share for total gross proceeds of $707 million in a private placement to its then principal shareholders, L.F. Management and Investment S.à r.l (formerly L.F. Investments (Barbados) Limited) and Hutchison Whampoa Luxembourg Holdings S.à r.l.

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 in a private placement to its then principal shareholders, L.F. Management and Investment S.à r.l and Hutchison Whampoa Luxembourg Holdings S.à r.l.

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In April 2011, the Company sold its 50% interest in the Meridian cogeneration facility (“Meridian”) 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, 2013, the amounts of natural gas sales to Meridian and other cogeneration facilities owned by the related party totalled $55 million. For the year ended December 31, 2013, the amounts of steam purchased by the Company from Meridian totalled $17 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, 2013, the total cost recovery for these services was $9 million.

8.6 Outstanding Share Data

Authorized:

• unlimited number of common shares

• unlimited number of preferred shares

Issued and outstanding: February 25, 2014

• common shares	983,491,183
• cumulative redeemable preferred shares, series 1	12,000,000
• stock options	27,548,178
• stock options exercisable	12,311,092

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 2013 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 instrument 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. Estimates that require significant judgments are also are made with respect to the timing of temporary difference reversals, the realizability of tax assets and in circumstances where the transaction and calculations for which the ultimate tax determination are uncertain. All tax filings are subject to audit and potential reassessment, often after the passage of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management.

Legal, Environmental Remediation and Other Contingent Matters

Husky is required to determine both whether a loss is probable based on judgment and interpretation of laws and regulations and whether the loss can be reasonably estimated. When a loss is determined it is charged to net earnings. 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”), the determination of a joint arrangement 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 the end of each reporting period 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 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, and 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.

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Joint Arrangements

Joint arrangements represent activities where the Company has joint control established by a contractual agreement. Joint control requires unanimous consent for financial and operational decisions. A joint arrangement is either a joint operation whereby the parties have rights to the assets and obligations for the liabilities, or a joint venture whereby the parties have rights to the net assets.

Determining the type of joint arrangement as either joint operation or joint venture is based on management’s assumptions of whether it has joint control over another entity. The considerations include, but are not limited to, determining if the arrangement is structured through a separate vehicle, and whether the legal form and contractual arrangements give the entity direct rights to the assets and obligations for the liabilities within the normal course of business. Other facts and circumstances are also assessed by management, including the entity’s rights to the economic benefits and its involvement and responsibility for settling liabilities associated with the arrangement.

Functional and Presentation Currency

Functional currency is the currency of the primary economic environment in which the Company and its subsidiaries operate and is normally the currency in which the entity primarily generates and expends cash. The designation of the Company’s functional currency is a management judgement based on the composition of revenues and costs in the locations in which it operates.

10.0 Recent Accounting Standards and Changes in Accounting Policies

Recent Accounting Standards

Impairment of Assets

In May 2013, the IASB published narrow-scope amendments to IAS 36, “Impairment of Assets,” which requires the disclosure of information about the recoverable amount of impaired assets, particularly if that amount is based on fair value less costs of disposal. Amendments to IAS 36 are effective for the Company on January 1, 2014, with required retrospective application and early adoption permitted. The Company intends to retrospectively adopt the amendments on January 1, 2014. The adoption of the standard is not expected to have a material impact on the Company’s annual consolidated financial statements.

Change in Accounting Policy

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 was effective for the Company on January 1, 2013, with required retrospective application and early adoption permitted. The Company retrospectively adopted IFRS 10 on January 1, 2013. The adoption of the standard had no impact on the Company’s annual consolidated financial statements.

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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 joint arrangement shall be classified as a joint venture and accounted for using the equity method of accounting. Under the previous standard, the Company had the option to account for any interests in joint arrangements using either proportionate consolidation or equity accounting. IFRS 11 was effective for the Company on January 1, 2013 with required retrospective application and early adoption permitted. The Company retrospectively adopted IFRS 11 on January 1, 2013. The adoption of the standard resulted in the following cumulative balance sheet impact related to the Madura joint arrangement, applied prospectively from January 1, 2012:

Balance Sheet Impact ($ millions)	December 31, 2012			January 1, 2012
Accounts receivable		(4	)		(4	)
Exploration and evaluation assets		(37	)		(14	)
Property, plant and equipment, net		(45	)		(42	)
Investment in joint ventures		132			91
Other assets		(25	)		—
Accounts payable and accrued liabilities		1			18
Other long-term liabilities		3			(24	)
Deferred tax liabilities		(25	)		(25	)
Total Balance Sheet Impact		—			—

Disclosure of Interests in Other Entities

In May 2011, the IASB published IFRS 12, “Disclosure of Interests in Other Entities,” which contains new annual 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 consolidated financial statements. IFRS 12 was effective for the Company on January 1, 2013 with required retrospective application and early adoption permitted. The Company retrospectively adopted IFRS 12 on January 1, 2013. The adoption of the standard did not have a material impact on the Company’s annual consolidated financial statements.

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 were effective for the Company on January 1, 2013, with required retrospective application and early adoption permitted. The Company retrospectively adopted these amendments on January 1, 2013. The adoption of the amendments had no impact on the Company’s annual consolidated 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 the 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 was effective for the Company on January 1, 2013, with required prospective application and early adoption permitted. The Company adopted IFRS 13 on January 1, 2013. The adoption of the standard did not have a material impact on the Company’s annual consolidated 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. Amendments to IAS 19 were effective for the Company on January 1, 2013 with required retrospective application and early adoption permitted. The Company retrospectively adopted these amendments on January 1, 2013.

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The adoption of this amended standard resulted in the following balance sheet impact, applied retrospectively to January 1, 2010:

(millions of Canadian dollars) (unaudited)	2012			2011			2010			Total
Increase/(decrease) in net defined benefit liability		1			2			(12	)		(9	)
Increase/(decrease) in retained earnings		(1	)		(2	)		12			9
Total balance sheet impact		—			—			—			—

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 were effective for the Company on January 1, 2013, with required retrospective application and early adoption permitted. Amendments to IAS 32 were effective for the Company for reporting periods ending after January 1, 2014, with required retrospective application and early adoption permitted. The Company retrospectively adopted both IFRS 7 and IAS 32 amendments on January 1, 2013. The adoption of the amendments did not have a material impact on the Company’s consolidated financial statements (refer to note 22 of the Consolidated Financial Statements).

11.0 Reader Advisories

11.1 Forward-Looking Statements

Certain statements in this document are forward-looking statements and information (collectively “forward-looking statements”), within the meaning of the applicable Canadian securities legislation, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. The forward-looking statements contained in this document are forward-looking and not historical facts.

Some of the forward-looking statements may be identified by statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as “will likely result”, “are expected to”, “will continue”, “is anticipated”, “is targeting”, “estimated”, “intend”, “plan”, “projection”, “could”, “aim”, “vision”, “goals”, “objective”, “target”, “schedules” and “outlook”). In particular, forward-looking statements in this document include, but are not limited to, references to:

• with respect to the business, operations and results of the Company generally: the Company’s general strategic plans and growth strategies; target debt to cash flow and debt to capital employed ratios; the Company’s 2014 production guidance, including weighting of production among product types; target compound annual production growth rate for 2012-2017; and the Company’s 2014 Upstream capital program;

• with respect to the Company’s Asia Pacific Region: expected timing of first production at the Company’s Liwan Gas Project; expected timing of tie-in and production of the Company’s Liuhua 34-2 field; expected timing of completion of the acquisition of a seismic survey at the Company’s offshore Taiwan exploration block; scheduled timing and duration of the Liwan Gas Project production going off-line; and scheduled timing, duration and expected impact of the planned offstation for the Wenchang FPSO;

• with respect to the Company’s Atlantic Region: expected timing of installation of oil production equipment and anticipated timing of first production at the Company’s South White Rose Extension project; scheduled timing and duration of a planned turnaround of the Terra Nova FPSO; scheduled timing of first production from the North Amethyst Hibernia formation well; and plans for further drilling in the Flemish Pass Basin;

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• with respect to the Company’s Oil Sands properties: scheduled timing of start up and anticipated volumes of production at the Company’s Sunrise Energy Project; and targeted timing of turn over of well pads at the Company’s Sunrise Energy Project;

• with respect to the Company’s Heavy Oil properties: anticipated volumes of production at the Company’s Sandall heavy oil thermal development project; estimated timing and volume of production growth from the Company’s thermal projects; expected timing of first production and anticipated volumes of production at the Company’s Rush Lake heavy oil thermal development project; scheduled timing of construction and first production, and anticipated volumes of production, at the Company’s Edam East and Vawn heavy oil thermal developments; and the Company’s horizontal and CHOPS drilling program for 2014;

• with respect to the Company’s Western Canadian oil and gas resource plays: the Company’s drilling and completion plans for its Slater River Canol shale play in the Northwest Territories; anticipated timing of completion activities and production from the Company’s Kaybob project in the Duvernay play; and planned maintenance activities for Western Canada, including scheduled timing and duration of a shutdown at the Rainbow oil and gas facility;

• with respect to the Company’s Infrastructure and Marketing operations: plans to increase pipeline connectivity and re-configure the terminal facility at the Hardisty terminal; anticipated timing of the extension of pipeline systems from the Sandall thermal development to Lloydminster; and the expansion of the South Saskatchewan Gathering System for the Rush Lake commercial project; and

• with respect to the Company’s Downstream operating segment: the anticipated benefits from and scheduled timing of completion of the Lima, Ohio refinery reconfiguration and the anticipated processing capacity once reconfiguration is complete; scheduled timing and duration of a partial outage of the Lloydminster Upgrader for planned maintenance; the anticipated benefits from and scheduled timing of completion of a Hydrotreater Recycle Gas Compressor Project at the BP-Husky Toledo Refinery; plans to reconfigure and increase capacity at the BP-Husky Toledo Ohio Refinery; scheduled timing, duration and expected impact of turnarounds at the BP-Husky Toledo Refinery; and scheduled timing, duration and expected impact of an outage for planned maintenance and turnarounds at the Lima 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. There are numerous uncertainties inherent in estimating quantities of reserves and resources and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary from reserve, resource and production estimates.

Although the Company believes that the expectations reflected by the forward-looking statements presented in this document are reasonable, the Company’s forward-looking statements have been based on assumptions and factors concerning future events 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.

The Company’s Annual Information Form for the year ended December 31, 2013 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.

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11.2 Oil and Gas Reserves Reporting

Disclosure of Oil and Gas Reserves and Other Oil and Gas Information

Unless otherwise stated, reserve and resource estimates in this document have an effective date of December 31, 2013 and represent Husky’s share. Unless otherwise noted, historical production numbers given represent Husky’s share.

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.

The Company has disclosed best-estimate contingent resources in this document. Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but that are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters, or a lack of markets. There is no certainty that it will be commercially viable to produce any portion of the contingent resources.

Best estimate as it relates to resources is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Estimates of contingent resources have not been adjusted for risk based on the chance of development. There is no certainty as to the timing of such development. For movement of resources to reserves categories, all projects must have an economic depletion plan and may require, among other things: (i) additional delineation drilling for unrisked contingent resources; (ii) regulatory approvals; and (iii) Company and partner approvals to proceed with development.

Specific contingencies preventing the classification of contingent resources at the Company’s Atlantic Region discoveries as reserves include additional exploration and delineation drilling, well testing, facility design, preparation of firm development plans, regulatory applications, Company and partner approvals.

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Positive and negative factors relevant to the estimate of Atlantic Region resources include water depth and distance from existing infrastructure.

Note to U.S. Readers

The Company reports its reserves and resources information in accordance with Canadian practices and specifically in accordance with National Instrument 51-101, “Standards of Disclosure for Oil and Gas Disclosure”, adopted by the Canadian securities regulators. Because the Company is permitted to prepare its reserves and resources information in accordance with Canadian disclosure requirements, it uses certain terms in this Management’s Discussion and Analysis , such as “best estimate contingent resources” that U.S. oil and gas companies generally do not include or may be prohibited from including in their filings with the SEC. All currency is expressed in Canadian dollars unless otherwise directed.

11.3 Non-GAAP Measures

Disclosure of non-GAAP Measurements

Husky uses measurements primarily based on IFRS as issued by the IASB and also certain secondary non-GAAP measurements. The non-GAAP measurements included in this Management’s Discussion and Analysis are net operating earnings, 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 equity, return on capital employed and return on capital in use. Return on capital employed and return on capital in use were adjusted for an after-tax impairment charge on property, plant and equipment of $204 million and $52 million for the years ended December 31, 2013 and 2011, respectively. Return on capital employed based on the calculation used in prior periods for the years ended December 31, 2013 and 2011 was 7.9% and 11.8%, respectively. Return on capital in use based on the calculation used in prior periods for the years ended December 31, 2013 and 2011 was 11.3% and 15.6%, respectively. None of these measurements are used to enhance the Company’s reported financial performance or position. With the exception of net operating earnings and cash flow from operations, there are no comparable measures to these non-GAAP measures in accordance with IFRS. These non-GAAP measurements are 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 Net Operating Earnings

The metric “Net Operating Earnings” is a non-GAAP measure comprised of net earnings excluding extraordinary and non-recurring items such as impairment charges not considered indicative of the Company’s ongoing financial performance. Net operating earnings is a complementary measure used in assessing Husky’s financial performance through providing comparability between periods.

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The following table shows the reconciliation of net earnings to net operating earnings and the related per share amounts for the years ended December 31:

($ millions)		2013		2012		2011
GAAP	Net earnings		1,829		2,022		2,224
	Impairment of property, plant and equipment, net of tax		204		—		52
Non-GAAP	Net operating earnings		2,033		2,022		2,276
	Net operating earnings – basic		2.07		2.07		2.44
	Net operating earnings – diluted		2.07		2.07		2.37

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, amortization and impairment, exploration and evaluation expenses, deferred income taxes, foreign exchange, stock-based compensation, gain or loss on sale of assets, 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)	2013			2012			2011
GAAP cash flow – operating activities		4,645			5,193			5,092
Settlement of asset retirement obligations		142			123			105
Income taxes paid		433			575			282
Interest received		(19	)		(34	)		(12	)
Change in non-cash working capital		21			(847	)		(269	)
Non-GAAP cash flow from operations		5,222			5,010			5,198
Cash flow from operations – basic		5.31			5.13			5.63
Cash flow from operations – diluted		5.31			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 Operating 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 consolidated 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 25, 2014. Any events subsequent to that date could materially alter the veracity and usefulness of the information contained in this document.

Additional Husky Documents Filed with Securities Commissions

This 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 2013, which contain the Management’s Discussion and Analysis and Consolidated Financial Statements, and Husky’s 2013 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, 2013 and 2012 and Husky’s financial position as at December 31, 2013 and at December 31, 2012.

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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 Husky’s securities.

Additional Reader Guidance

Unless otherwise indicated:

• Financial information is presented in accordance with IFRS as issued by the IASB;

• 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; and

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

Terms

Brent Crude Oil	Brent Crude is a major trading classification of sweet light crude oil that serves as a major benchmark price for purchases of oil worldwide. Brent Crude is sourced from the North Sea and is 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
Corporate Reinvestment Ratio	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
Feedstock	Raw materials that 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
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

Management’s Discussion and Analysis 2013

49

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
Operating Netback	Net revenues after deduction of operating costs, transportation and royalty payments
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 shareholders’ 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 reserves” are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g. when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves 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 be greater or less than the sum of the estimated proved plus probable reserves.

Abbreviations

bbls	barrels	CNOOC	China National Offshore Oil Corporation
bpd	barrels per day	CSA	Canadian Securities Administrators
EOR	enhanced oil recovery	FPSO	Floating production, storage and offloading vessel
bps	basis points	GAAP	Generally Accepted Accounting Principles
mbbls	thousand barrels	GJ	gigajoule
mbbls/day	thousand barrels per day	LIBOR	London Interbank Offered Rate
mmbbls	million barrels	MD&A	Management’s Discussion and Analysis
mcf	thousand cubic feet	MW	megawatt
mmcf	million cubic feet	NGL	natural gas liquids
mmcf/day	million cubic feet per day	NIT	NOVA Inventory Transfer
bcf	billion cubic feet	NYMEX	New York Mercantile Exchange
tcf	trillion cubic feet	OPEC	Organization of Petroleum Exporting Countries
boe	barrels of oil equivalent		PSC	production sharing contract
mboe	thousand barrels of oil equivalent		SAGD	Steam assisted gravity drainage
mboe/day	thousand barrels of oil equivalent per day	SEC	U.S. Securities and Exchange Commission
mmboe	million barrels of oil equivalent	SEDAR	System for Electronic Document Analysis and Retrieval
mcfge	thousand cubic feet of gas equivalent	WI	working interest
mmbtu	million British Thermal Units	WTI	West Texas Intermediate

Management’s Discussion and Analysis 2013

50

mmlt	million long tons	C-NLOPB	Canada-Newfoundland and Labrador Offshore
tcfe	trillion cubic feet equivalent		Petroleum Board
tgal	thousand gallons	IFRS	International Financial Reporting Standards
ASP	alkali surfactant polymer
CHOPS	cold heavy oil production with sand

11.5 Disclosure Controls and Procedures

Disclosure Controls and Procedures

Husky’s management, under supervision of the Chief Executive Officer and the Chief Financial Officer, have evaluated the effectiveness of Husky’s disclosure controls and procedures (as defined in the rules of the SEC and the Canadian Securities Administrators (“CSA”)) as at December 31, 2013, and have concluded that such disclosure controls and procedures are effective.

Management’s Annual Report on Internal Control over Financial Reporting

The following report is provided by management in respect of Husky’s internal controls over financial reporting (as defined in the rules of the SEC and the CSA):

1) Husky’s management, under the supervision of the Chief Executive Officer and Chief Financial Officer, is responsible for designing, establishing and maintaining adequate internal control over financial reporting for Husky. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

2) Husky’s management has used the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework to evaluate the effectiveness of Husky’s internal control over financial reporting.

3) As at December 31, 2013, management, under the supervision of the Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of Husky’s internal control over financial reporting and concluded that such internal control over financial reporting is effective.

4) KPMG LLP, who has audited the Consolidated Financial Statements of Husky for the year ended December 31, 2013, has also issued a report on internal controls over financial reporting under Auditing Standard No. 5 of the Public Company Accounting Oversight Board (United States) that attests to 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, 2013, that have materially affected or are reasonably likely to materially affect its internal control over financial reporting.

Management’s Discussion and Analysis 2013

51

12.0 Selected Quarterly Financial & Operating Information

Segmented Operational Information

	2013								2012
	Q4		Q3		Q2		Q1		Q4		Q3		Q2		Q1
Upstream
Daily production, before royalties
Light crude oil & NGL (mbbls/day)		78.3		77.7		82.3		86.4		86.1		55.4		56.8		91.2
Medium crude oil (mbbls/day)		23.4		23.2		22.9		23.0		23.2		23.9		24.1		24.9
Heavy crude oil (mbbls/day)		75.9		75.3		72.3		74.4		76.0		77.1		78.1		76.2
Bitumen (mbbls/day)		46.7		48.0		48.3		47.9		46.7		37.8		29.6		29.6
Total crude oil production (mboe/day)		224.3		224.2		225.8		231.7		232.0		194.2		188.6		221.9
Natural gas (mmcf/day)		503.8		505.5		504.7		537.3		523.7		544.9		559.5		588.3
Total production (mboe/day)		308.3		308.5		309.9		321.3		319.3		285.0		281.9		319.9
Average sales prices
Light crude oil & NGL ($/bbl)		101.95		107.83		96.22		103.59		94.91		90.50		94.71		111.53
Medium crude oil ($/bbl)		67.86		93.67		73.62		61.74		67.55		69.59		69.92		78.63
Heavy crude oil ($/bbl)		56.51		84.45		66.77		45.67		57.90		60.58		60.42		68.93
Bitumen ($/bbl)		54.08		83.17		65.71		43.12		55.74		60.10		58.09		65.83
Natural gas ($/mcf)		3.30		2.66		3.72		3.08		3.25		2.48		2.05		2.64
Operating costs ($/boe)		16.31		17.20		16.79		15.29		15.05		16.69		15.83		14.56
Operating netbacks(1)
Lloydminster – Thermal Oil ($/boe)(2)		38.76		67.57		50.57		32.55		45.47		48.42		43.42		50.25
Lloydminster – Non-Thermal Oil ($/boe)(2)		27.32		49.69		37.70		19.06		30.09		33.35		37.07		47.94
Oil Sands – Bitumen ($/boe)(2)		21.45		52.68		35.30		12.32		19.49		33.91		30.05		35.88
Western Canada – Crude Oil ($/boe)(2)		37.60		54.41		39.24		31.17		38.31		37.12		38.52		43.67
Western Canada – Natural gas ($/mcf)(3)		1.93		1.21		1.81		1.68		1.49		1.16		1.11		1.52
Atlantic – Light Oil ($/boe)(2)		83.90		87.14		78.66		89.37		85.05		66.97		70.99		94.34
Asia Pacific – Light Oil & NGL ($/boe)(2)		70.35		74.60		62.52		73.46		69.28		72.97		73.54		88.16
Total ($/boe)(2)		34.29		46.15		38.32		31.78		35.99		30.08		30.43		43.00
Net wells drilled(4)
Exploration Oil		7		8		—		9		8		1		3		18
Gas		5		—		4		5		—		2		—		10
Dry		—		—		—		—		—		—		—		—
		12		8		4		14		8		3		3		28
Development Oil		201		249		30		229		217		245		56		197
Gas		12		12		2		15		6		1		2		8
Dry		—		—		—		—		3		—		—		1
		213		261		32		244		226		246		58		206
Total net wells drilled		225		269		36		258		234		249		61		234
Success ratio (percent)		100		100		100		100		99		100		100		100
Upgrader
Synthetic crude oil sales (mbbls/day)		52.0		37.5		56.7		56.1		63.4		64.1		53.1		61.1
Upgrading differential ($/bbl)		26.63		23.59		27.39		38.51		24.27		22.04		22.64		20.38
Canadian Refined Products
Fuel sales (million litres/day)(5)		7.9		8.3		8.0		8.2		8.8		9.0		8.4		8.3
Refinery throughput
Lloydminster refinery (mbbls/day)		28.4		28.7		18.7		28.3		28.3		28.7		29.1		27.2
Prince George refinery (mbbls/day)		12.0		11.8		6.3		11.2		11.4		11.3		10.4		11.1
Refinery utilization (percent)		96		61		100		100		97		97		96		93
U.S. Refining and Marketing
Refinery throughput
Lima refinery (mbbls/day)		151.8		148.8		149.8		146.9		155.9		153.9		150.7		139.4
BP-Husky Toledo refinery (mbbls/day)		66.3		59.1		68.1		66.3		58.1		52.7		64.9		67.3

⁽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.

⁽⁵⁾ Fuel sales have been recast to exclude non-retail products. Prior periods have been adjusted to conform with the current period presentation.

Management’s Discussion and Analysis 2013

52

Segmented Capital Expenditures⁽¹⁾

	2013								2012
($ millions)	Q4		Q3		Q2		Q1		Q4			Q3		Q2		Q1
Upstream
Exploration
Western Canada		80		99		64		110		79			43		29		87
Atlantic Region		55		102		39		5		(28	)		35		6		—
Asia Pacific Region		14		1		—		6		5			17		—		—
		149		202		103		121		56			95		35		87
Development
Western Canada		744		505		267		513		662			497		293		577
Oil Sands		111		146		137		158		220			152		132		154
Atlantic Region		34		148		116		139		91			150		101		58
Asia Pacific Region		215		133		156		129		213			175		203		134
		1,104		932		676		939		1,186			974		729		923
Acquisitions
Western Canada		27		1		4		6		—			16		—		5
Total Exploration and Production		1,280		1,135		783		1,066		1,242			1,085		764		1,015
Infrastructure and Marketing		41		27		17		11		19			14		11		10
Total Upstream		1,321		1,162		800		1,077		1,261			1,099		775		1,025
Downstream
Upgrader		43		129		20		13		17			13		9		8
Canadian Refined Products		32		24		41		12		33			32		19		13
U.S. Refining and Marketing		99		52		42		27		113			92		65		43
		174		205		103		52		163			137		93		64
Corporate		42		40		29		23		49			16		14		5
		1,537		1,407		932		1,152		1,473			1,252		882		1,094

⁽¹⁾  Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the period.

Management’s Discussion and Analysis 2013

53

Segmented Financial Information

	Upstream																								Downstream
	Exploration and Production(1)												Infrastructure and Marketing												Upgrading
2013 ($ millions)	Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
Gross revenues		1,734			2,111			1,843			1,645			457			646			664			367			484			437			573			529
Royalties		(215	)		(237	)		(208	)		(204	)		—			—			—			—			—			—			—			—
Marketing and other		—			—			—			—			76			17			57			162			—			—			—			—
Reve1nues, net of royalties		1,519			1,874			1,635			1,441			533			663			721			529			484			437			573			529
Expenses
Purchases of crude oil and products		29			17			20			25			438			609			622			335			362			341			388			287
Production and operating expenses		502			528			504			482			1			3			7			3			45			38			41			37
Selling, general and administrative expenses		44			60			84			52			4			4			5			6			2			2			1			2
Depletion, depreciation, amortization and impairment		791			594			568			562			2			6			6			6			25			24			23			24
Exploration and evaluation expenses		28			56			74			88			—			—			—			—			—			—			—			—
Other – net		(63	)		11			(24	)		41			(2	)		—			(1	)		—			(23	)		(2	)		(1	)		(1	)
Earnings from operating activities		188			608			409			191			90			41			82			179			73			34			121			180
Share of equity investment		(5	)		1			(6	)		—			—			—			—			—			—			—			—			—
Net foreign exchange gains (losses)		1			(1	)		—			—			—			—			—			—			—			—			—			—
Finance income		2			—			2			—			—			—			—			—			—			—			—			—
Finance expenses		(27	)		(28	)		(23	)		(29	)		—			—			—			—			(1	)		(2	)		(2	)		(2	)
		(24	)		(29	)		(21	)		(29	)		—			—			—			—			(1	)		(2	)		(2	)		(2	)
Earnings (loss) before income tax		159			580			382			162			90			41			82			179			72			32			119			178
Provisions for (recovery of) income taxes
Current		54			86			(30	)		52			43			(3	)		90			92			6			6			1			6
Deferred		(13	)		64			129			(11	)		(20	)		14			(69	)		(47	)		13			2			30			40
		41			150			99			41			23			11			21			45			19			8			31			46
Net earnings (loss)		118			430			283			121			67			30			61			134			53			24			88			132
Capital expenditures(3)		1,280			1,135			783			1,066			41			27			17			11			43			129			20			13
Total assets		24,653			24,058			23,603			23,250			1,670			1,766			1,554			1,476			1,355			1,214			1,217			1,214

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

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

⁽³⁾  Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the period.

Management’s Discussion and Analysis 2013

54

Downstream (continued)																						Corporate and Eliminations(2)												Total
Canadian Refined Products											U.S. Refining and Marketing
Q4		Q3			Q2			Q1			Q4			Q3			Q2		Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
	1,288		993			613			843			2,690			2,405			2,922		2,711			(597	)		(573	)		(466	)		(450	)		6,056			6,019			6,149			5,645
	—		—			—			—			—			—			—		—			—			—			—			—			(215	)		(237	)		(208	)		(204	)
	—		—			—			—			—			—			—		—			—			—			—			—			76			17			57			162
	1,288		993			613			843			2,690			2,405			2,922		2,711			(597	)		(573	)		(466	)		(450	)		5,917			5,799			5,998			5,603
	1,129		875			468			662			2,543			2,174			2,504		2,325			(597	)		(573	)		(466	)		(450	)		3,904			3,443			3,536			3,184
	49		50			50			44			99			105			104		101			—			—			—			—			696			724			706			667
	16		16			14			14			3			4			4		4			90			55			20			52			159			141			128			130
	23		23			22			22			60			58			58		57			17			13			11			10			918			718			688			681
	—		—			—			—			—			—			—		—			—			—			—			—			28			56			74			88
	1		(3	)		(2	)		(1	)		—			(1	)		1		—			—			(8	)		5			(14	)		(87	)		(3	)		(22	)		25
	70		32			61			102			(15	)		65			251		224			(107	)		(60	)		(36	)		(48	)		299			720			888			828
	—		—			—			—			—			—			—		—			—			—			—			—			(5	)		1			(6	)		—
	—		—			—			—			—			—			—		—			12			7			10			(8	)		13			6			10			(8	)
	—		—			—			—			—			—			—		—			13			11			12			11			15			11			14			11
	(1)		(1	)		(2	)		(1	)		(1	)		(1	)		—		(1	)		(4	)		(10	)		(13	)		(20	)		(34	)		(42	)		(40	)		(53	)
	(1)		(1	)		(2	)		(1	)		(1	)		(1	)		—		(1	)		21			8			9			(17	)		(6	)		(25	)		(16	)		(50	)
	69		31			59			101			(16	)		64			251		223			(86	)		(52	)		(27	)		(65	)		288			696			866			778
	11		17			7			30			(43	)		(25	)		44		42			22			33			62			(14	)		93			114			174			208
	6		(9	)		8			(4	)		38			47			44		36			(6	)		(48	)		(55	)		21			18			70			87			35
	17		8			15			26			(5	)		22			88		78			16			(15	)		7			7			111			184			261			243
	52		23			44			75			(11	)		42			163		145			(102	)		(37	)		(34	)		(72	)		177			512			605			535
	32		24			41			12			99			52			42		27			42			40			29			23			1,537			1,407			932			1,152
	1,788		1,704			1,656			1,714			5,537			5,665			5,525		5,397			1,901			2,193			2,439			2,468			36,904			36,600			35,994			35,519

Management’s Discussion and Analysis 2013

55

	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(3)(4)		1,773			1,440			1,389			1,979			785			365			623			604			562			576			472			581
Royalties		(189	)		(145	)		(140	)		(219	)		—			—			—			—			—			—			—			—
Marketing and other(3)		—			—			—			—			79			122			124			73			—			—			—			—
Revenues, net of royalties		1,584			1,295			1,249			1,760			864			487			747			677			562			576			472			581
Expenses
Purchases of crude oil and products(3)(5)		20			15			13			25			741			335			591			591			417			423			344			452
Production and operating expenses(4)(5)		513			456			441			465			—			6			4			2			40			33			42			35
Selling, general and administrative expenses		18			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		157			59			53			75			—			—			—			—			—			—			—			—
Other – net		(72	)		28			(60	)		(1	)		—			—			1			(1	)		(17	)		—			—			—
Earnings from operating activities		334			167			273			631			111			136			139			76			94			95			60			68
Share of equity investment		(11	)		—			—			—			—			—			—			—			—			—			—			—
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		304			151			254			612			111			136			139			76			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)		226			110			187			453			83			101			104			58			68			68			42			48
Capital expenditures(6)		1,242			1,085			764			1,015			19			14			11			10			17			13			9			8
Total assets		22,774			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 Infrastructure and Marketing, as these assets provide a service to the Exploration and Production.

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

⁽³⁾  Gross revenues, marketing and other and purchases of crude oil products have been recast to reflect a change in the classification of certain trading transactions.

⁽⁴⁾  In 2013, the Company reclassified its processing facilities from Infrastructure and Marketing to Exploration and Production. 2012 amounts have been adjusted to conform with current presentation.

⁽⁵⁾  Certain hydrogen feedstock costs were reclassified in 2012 from production and operating expenses to purchases of of crude oil products.

⁽⁶⁾  Excludes capitalized costs related to asset retirement obligations and capitalized interest incurred during the period.

Management’s Discussion and Analysis 2013

56

Downstream (continued)																							Corporate and Eliminations(2)												Total
Canadian Refined Products											U.S. Refining and Marketing
Q4		Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1
	933		1,067			968			880			2,355			2,436			2,623			2,442			(598	)		(596	)		(484	)		(625	)		5,810			5,288			5,591			5,861
	—		—			—			—			—			—			—			—			—			—			—			—			(189	)		(145	)		(140	)		(219	)
	—		—			—			—			—			—			—			—			—			—			—			—			79			122			124			73
	933		1,067			968			880			2,355			2,436			2,623			2,442			(598	)		(596	)		(484	)		(625	)		5,700			5,265			5,575			5,715
	794		849			802			763			2,046			1,980			2,335			2,183			(598	)		(596	)		(484	)		(625	)		3,420			3,006			3,601			3,389
	49		45			50			40			102			91			100			92			(1	)		1			1			3			703			632			638			637
	15		14			15			14			3			4			3			3			63			34			40			41			106			112			131			99
	21		21			21			20			57			52			52			51			13			11			9			7			738			629			576			637
	—		—			—			—			—			—			—			—			—			—			—			—			157			59			53			75
	—		(2	)		—			—			4			—			—			—			(19	)		4			7			5			(104	)		30			(52	)		3
	54		140			80			43			143			309			133			113			(56	)		(50	)		(57	)		(56	)		680			797			628			875
	—		—			—			—			—			—			—			—			—			—			—			—			(11	)		—			—			—
	—		—			—			—			—			—			—			—			(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			142			308			131			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			87			195			83			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			35,161			33,466			32,842			33,286

57

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.
23.3	Consent of Sproule Unconventional Limited, independent engineers.
23.4	Consent of Frederick Au-Yeung, internal qualified reserves evaluator.
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities
	Exchange Act of 1934.
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities
	Exchange Act of 1934.
32.1	Certification of Chief Executive Officer pursuant to Rule 13(a)-14(b) or Rule 15d-14(b)and
	Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
32.2	Certification of Chief Financial Officer pursuant to Rule 13(a)-14(b) or Rule 15d-14(b) and
	Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
99.1	Supplemental Disclosures of Oil and Gas Activities.
99.2	Recent Amendments to the Code of Business Conduct
99.3	Amended Code of Business Conduct