##### Table of Contents

2008







United States

Securities and
Exchange Commission

Washington, D.C. 20549





Form 40-F







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



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



|                                            |  |                                  
|------------------------------------------- |  | ---------------------------------
|For the fiscal year ended December 31, 2008 |  | Commission File Number: 001-04307





Husky Energy Inc.

(Exact name of Registrant as specified in its charter)







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

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

(403) 298-6111

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

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

(212) 894-8400

(Name, address (including zip code) and telephone number (including area code) of
agent for service in the United States)

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

Title of Each Class: None

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

Title of Each Class: None





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

The Registrant is a voluntary filer and files annual reports on Form 40-F, amendments to such reports and furnishes information on Form 6-K to
the Securities and Exchange Commission, pursuant to its obligations under its Indentures dated June 14, 2002 and September 11, 2007 relating to its debt securities issued thereunder.

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



|                          |  |                                      
|------------------------- |  | -------------------------------------
|x Annual information form |  | x Audited annual financial statements

Number of outstanding shares of each of the issuers classes of capital or common stock as of
the close of the period covered by the annual report: 849,354,810

Common Shares outstanding as of December 31, 2008

Indicate by check mark whether the Registrant by filing the information contained in this Form is also thereby furnishing the information to the
Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the Exchange Act). If Yes is marked, indicate the filing number assigned to the Registrant in connection with such
Rule.    Yes   ̈    No  x

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No   ̈

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: For F-9 File No. 333-137211.









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##### Table of Contents

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, 2008 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 year ended December 31, 2008 and 2007, including the auditors report with respect thereto, is included as Document B of this Annual Report on Form 40-F. The reconciliation of Huskys
audited consolidated financial statements to accounting principles generally accepted in the United States is included as Document C of this Annual Report on Form 40-F. In addition, see the Disclosure about Oil and Gas Producing Activities
 Statement of Financial Accounting Standards No. 69 in the Annual Information Form included as Document A of this Annual Report on Form 40-F.



|C. | Reconciliation to Accounting Principles Generally Accepted in the United States
|-- | -------------------------------------------------------------------------------

The reconciliation of Huskys audited consolidated financial statements to accounting principles generally accepted in the United States is included as Document C of this Annual Report on Form 40-F. In addition,
see the Disclosure about Oil and Gas Producing Activities  Statement of Financial Accounting Standards No. 69 in the Annual Information Form as Document A of the Annual Report on Form 40-F.



|D. | Managements Discussion and Analysis
|-- | ------------------------------------

Huskys Managements Discussion and Analysis for the year ended December 31, 2008 is included as Document D of this Annual Report on Form 40-F.

Certificates

See Exhibits 23.1, 23.2, 31.1, 31.2, 32.1 and 32.2, which are included as
Exhibits to this Annual Report on Form 40-F.

Controls and Procedures

See the section Controls and Procedures in Huskys Managements Discussion and Analysis for the year ended December 31, 2008
which is included as Document D to this Annual Report on Form 40-F.

Managements Annual Report on Internal Control Over Financial Reporting

Attestation of the Registered Public Accounting Firm

The required disclosure is included in Auditors Report to the Shareholders that accompanies Huskys consolidated financial statements for the year ended December 31, 2008, which is included
as Document B to this Annual Report on Form 40-F.

Change in Internal Control Over Financial Reporting

The required disclosure is included in the section Controls and Procedures in Huskys Managements Discussion and Analysis for the
year ended December 31, 2008, which is included as Document D to this Annual Report on Form 40-F.

Notice Pursuant to Regulation BTR

Not Applicable.



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Audit Committee Financial Expert

The Board of Directors of Husky has determined that R. Donald Fullerton 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. Fullerton is a corporate director and is independent under the New York Stock Exchange standard. For a description of Mr. Fullertons relevant experience in financial matters, see
Mr. Fullertons five year history in the section Directors and Officers and in the section Audit Committee in the Registrants Annual Information Form for the year ended December 31, 2008, 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 all its other employees, and is posted on its website at www.huskyenergy.com. In the fiscal year ended December 31, 2008, there have been no
amendments to Huskys Code of Ethics, nor has Husky 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 Audit Committee in the Annual Information Form for the year ended
December 31, 2008, which is included as Document A to 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,
2008, which is included as Document D to this Annual Report on Form 40-F.

Disclosure of Contractual Obligations

See the section Contractual Obligations and Other Commercial Commitments in Huskys Managements Discussion and Analysis for the
year ended December 31, 2008, which is included as Document D to 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: R.D. Fullerton, M.J.G. Glynn, C. Russel and W. Shurniak.



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Undertaking and Consent to Service of Process

Undertaking

Husky undertakes to make available, in
person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form F-9; 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

Form F-X signed by Husky and its agent for service of process has been filed with the Commission together with Forms F-9 (333 -
137211), (333 - 117972) and (333 - 89714) in connection with its debt securities registered on such forms.

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 18th day of February, 2009



Husky Energy Inc.By:

/s/    JOHN C.S.
LAUName:

John C.S. LauTitle:

President & Chief Executive OfficerBy:

/s/    JAMES D.
GIRGULISName:

James D. GirgulisTitle:

Vice President, Legal & CorporateSecretary




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Document A

Form 40-F



Annual
Information Form

For the Year Ended December 31, 2008









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Husky Energy Inc.

Annual Information Form

For the Year Ended December 31, 2008

February 18, 2009











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TABLE OF CONTENTS



|                                                                              |  |   
|----------------------------------------------------------------------------- |  | --
|EXCHANGE RATE INFORMATION                                                     |  | 4 
|DISCLOSURE OF EXEMPTION UNDER NATIONAL INSTRUMENTS 51-101                     |  | 4 
|CORPORATE STRUCTURE                                                           |  | 6 
|Husky Energy Inc.                                                             |  | 6 
|Intercorporate Relationships                                                  |  | 6 
|GENERAL DEVELOPMENT OF HUSKY                                                  |  | 7 
|Three Year History of Husky                                                   |  | 7 
|Business Environment Trends                                                   |  | 10
|DESCRIPTION OF HUSKYS BUSINESS                                               |  | 10
|General                                                                       |  | 10
|Social and Environmental Policy                                               |  | 11
|Risk Factors                                                                  |  | 13
|Upstream Operations                                                           |  | 17
|Disclosures of Oil and Gas Activities                                         |  | 17
|Description of Major Properties and Facilities                                |  | 37
|Distribution of Oil and Gas Production                                        |  | 55
|Midstream Operations                                                          |  | 56
|Downstream Operations                                                         |  | 60
|Human Resources                                                               |  | 65
|DIVIDENDS                                                                     |  | 65
|DESCRIPTION OF CAPITAL STRUCTURE                                              |  | 66
|MARKET FOR SECURITIES                                                         |  | 67
|DIRECTORS AND OFFICERS                                                        |  | 68
|AUDIT COMMITTEE                                                               |  | 74
|LEGAL PROCEEDINGS                                                             |  | 75
|INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS                    |  | 75
|TRANSFER AGENT AND REGISTRARS                                                 |  | 76
|INTERESTS OF EXPERTS                                                          |  | 76
|ADDITIONAL INFORMATION                                                        |  | 76
|ABBREVIATIONS AND GLOSSARY OF TERMS                                           |  | 77
|SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS                             |  | 83
|Schedules                                                                     |  |   
|A  Audit Committee Charter                                                   |  | 85
|B  Report on Reserves Data by Qualified Reserves Evaluator                   |  | 90
|C  Report of Management and Directors on Reserves Data and Other Information |  | 92
|D  Independent Engineers Audit Opinion                                      |  | 94

In this Annual Information Form the term Husky, we, our,
us, and the Company, means Husky Energy Inc. and its subsidiaries and partnership interests on a consolidated basis including information with respect to predecessor corporations.

Unless otherwise indicated, all financial information is in accordance with accounting principles generally accepted in Canada. Unless otherwise
indicated, 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. Natural gas volumes are converted to a boe basis using the ratio of six mcf of natural gas to one bbl of oil and natural gas liquids. Unless otherwise indicated, oil and gas commodity
prices are quoted after the effect of hedging gains and losses. Natural gas volumes are stated at the official temperature and pressure basis of the area in which the reserves are located. The calculation of barrels of oil equivalent (boe) and
thousands of cubic feet equivalent (mcfge) are based on a conversion rate of six thousand cubic feet to one barrel of oil.



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Boe or mcfge may be misleading, particularly if used in isolation. A boe conversion ratio of six
mcf to one bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

This Annual Information Form contains forward-looking information and statements within the meaning of applicable securities laws. For a
full discussion of the forward-looking information and statements and the risks to which they are subject, see the Special Note Regarding Forward-Looking Statements in this Annual Information Form.

EXCHANGE RATE INFORMATION

Except where otherwise indicated, all dollar amounts stated in this Annual Information Form (AIF) are Canadian dollars. The following table discloses various indicators of the Canadian/United States rate of exchange or the cost
of a U.S. dollar in Canadian currency for the three years indicated.



|         |  |                        |  |       |  |      
|-------- |  | ---------------------- |  | ----- |  | -----
|         |  | Year ended December 31
|         |  | 2008                   |  | 2007  |  | 2006 
|Year end |  | 1.224                  |  | 0.988 |  | 1.165
|Low      |  | 0.972                  |  | 0.917 |  | 1.095
|High     |  | 1.297                  |  | 1.185 |  | 1.179
|Average  |  | 1.066                  |  | 1.074 |  | 1.134



Notes:



|(1) | The exchange rates were as quoted by the Federal Reserve Bank of New York for the noon buying rate.
|--- | ---------------------------------------------------------------------------------------------------



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

DISCLOSURE OF EXEMPTION UNDER NATIONAL INSTRUMENT 51-101

Husky believes that comparability of its disclosures with those required in its major capital market, the United States, is important to many of the investors and prospective investors in its securities. Accordingly, the Company applied for
and was granted an exemption by the Canadian securities regulators under the provisions of National Instrument 51-101 Standards of Disclosures for Oil and Gas Activities (NI 51-101). The exemption permits Husky to substitute
disclosures required by and consistent with those of the Securities and Exchange Commission of the United States (SEC) and the Financial Accounting Standards Board in the United States (FASB) in place of much of the
disclosure required by NI 51-101. In accordance with the exemption, proved oil and gas reserves data and certain other disclosures with respect to Huskys oil and gas activities in this Annual Information Form are presented in accordance with
the following requirements:



| |  |  | The FASB Statement No. 69 Disclosure about Oil and Gas Producing Activities  an amendment of FASB Statements No.s 19, 25, 33 and 39
(FAS 69);
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | FASB Current Text Section Oi5, Oil and Gas Producing Activities paragraphs .103, .106, .107, .108, .112, 160 through .167, .174 through .184 and .401
through .408;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | SEC Industry Guide 2;
| | - |  | ---------------------



| |  |  | SEC Item 102 of regulation S-K (17 CFR 229.102);
| | - |  | ------------------------------------------------



| |  |  | SEC Item 302(b) of Regulation S-K (17 CFR 229.302(b)); and
| | - |  | ----------------------------------------------------------



| |  |  | The definitions and disclosures required by SEC Regulation S-X (CFR 210.4-10).
| | - |  | ------------------------------------------------------------------------------

Proved oil and gas reserves information and other disclosures about oil and gas activities in this Annual Information Form following SEC requirements may
differ from corresponding information otherwise required by NI 51-101. Proved reserves disclosed in this Annual Information Form are in accordance with the SEC definitions.



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NI 51-101 specifies that proved reserves be determined in accordance with the Canadian Oil and Gas
Evaluation Handbook (COGEH) definitions. There were no material differences between the oil and gas reserves determined using the SEC definitions and the COGEH definitions. In addition, NI 51-101 requires the inclusion of probable
reserves and their associated future net revenue. The SEC does not normally permit the disclosure of probable reserves in documents filed with them.

The SEC requires the evaluation of oil and gas reserves to be based on prices, costs, fiscal regimes and other economic and operating conditions in effect at the time the evaluation is made (constant
prices). NI 51-101 allows the evaluation of oil and gas reserves on this basis as supplemental disclosure but requires an evaluation of oil and gas reserves to be based on a forecast of economic conditions. In establishing the constant prices
for bitumen NI 51-101 provides for a different interpretation of the phrase price will be the posted price of oil and the spot price of gas, after historical adjustments for transportation, gravity and other factors. On January 20,
2005 the Canadian Securities Administrators issued Staff Notice 51-315 Guidance Regarding the Determination of Constant Prices for Bitumen Reserves under National Instrument 51-101 Standards of Disclosure for Oil and Gas
Activities. Bitumen is very heavy crude oil that is 10 degrees API and lower. This guidance stipulates that for establishing the constant prices for bitumen companies should use the posted price for WTI and apply the average annual
adjustment for transportation, gravity and other factors that create the difference in price between WTI and bitumen. This method was developed primarily in response to the fluctuations in bitumen prices that, for various reasons, tend to experience
the lowest prices at the end of the calendar year. Under the FASB/SEC rules the determination of constant price for bitumen does not permit the use of annual average differentials between WTI and bitumen. These rules require the differentials
prevailing on the last day of the period to be used to calculate the constant price. There is no difference in determining the constant prices for crude oil classified as heavy oil, lighter than 10 degrees API under NI 51-101 and FASB/SEC although
heavy oil, which we classify as crude oil between 10 degrees and 20 degrees API, tends to behave in a similar manner as bitumen.

Husky
believes that its reserves evaluators are qualified and that it has a well established reserves evaluation process that is at least as rigorous as would be the case were we to rely upon independent reserves evaluators. Husky has adopted written
evaluation practices and procedures using the COGEH modified to the extent necessary to reflect the definitions and standards under SEC disclosure requirements. In addition, Husky engaged a firm of independent qualified reserves evaluators to
conduct an audit of the reserves estimates and respective present worth value of the reserves as at December 31, 2008. They conducted their audit in accordance with the standards described in the COGEH and the auditing standards generally
accepted in the United States.

The Audit Committee of the Board of Directors has reviewed the Companys procedures for providing
information to the internal and external qualified oil and gas reserves evaluators; met with the internal and external qualified oil and gas reserves evaluators to determine whether any restrictions placed by management affect the ability of the
qualified oil and gas reserves evaluator to report without reservation; and reviewed the reserves data with management and the internal qualified reserves evaluator. To assist the Audit Committee in its review, an external consultant was engaged to
provide an assessment and recommendation in respect of the oil and gas reserves evaluation and reporting process.

NI 51-101 prescribes a
relatively comprehensive set of disclosures in respect of oil and gas reserves and other disclosures about oil and gas activities. In comparison, the SEC prescribes a minimum set of disclosures and advises reporting companies not to approach the SEC
rules and regulations as merely a blank form but encourages them to provide such additional information that is necessary to further an investors understanding of their business.

In either jurisdiction, information to further an investors understanding is specifically encouraged to be included in the Companys
Managements Discussion and Analysis (MD&A). The MD&A is intended to be a narrative explanation describing the Company, both its history and prospects, as perceived by management. The readers of the AIF are encouraged to
also read the Companys MD&A, which is filed, in accordance with the requirements of the Canadian Securities Administrators, on the System for Electronic Data Analysis and



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Retrieval (SEDAR). Documents filed on SEDAR may be accessed online at www.sedar.com. This AIF together with the MD&A and the
Companys Audited Consolidated Financial Statements are included in Huskys Form 40-F which is filed with SECs Electronic Data Gathering Analysis and Retrieval (EDGAR) system, which may be accessed online at
www.sec.gov.

CORPORATE STRUCTURE

Husky Energy Inc.

Husky Energy Inc. (Husky Energy) was
incorporated under the Business Corporations Act(Alberta) on June 21, 2000.

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

Intercorporate
Relationships

The principal subsidiaries of Husky and place of incorporation, continuance or place of organization, as the case may be,
are as follows. All of the following companies, except as otherwise indicated, are 100% beneficially owned or controlled or directed, directly or indirectly.



|                                                             |  |                       
|------------------------------------------------------------ |  | ----------------------
|Name                                                         |  | Jurisdiction          
|Subsidiaries of Husky Energy Inc.                            |  |                       
|Husky Oil Operations Limited                                 |  | Nova Scotia           
|                                                             | 
|Subsidiaries of Husky Oil Operations Limited                 |  |                       
|Husky Oil Limited                                            |  | Nova Scotia           
|Husky Energy Marketing Inc.                                  |  | Alberta               
|Husky (U.S.A.) Inc.                                          |  | Delaware              
|Husky Refining Company                                       |  | Delaware              
|HOI Resources Co.                                            |  | Nova Scotia           
|Canterra Resources Canada Ltd. (formerly 147212 Canada Ltd.) |  | Canada                
|Sunrise Oil Sands Partnership (50%)                          |  | Alberta               
|BP Husky Refining LLC (50%)                                  |  | Delaware              
|                                                             | 
|Subsidiaries of Husky (U.S.A.) Inc.                          |  |                       
|Husky Gas Marketing Inc.                                     |  | Delaware              
|                                                             | 
|Subsidiaries of Husky Refining Company                       |  |                       
|Lima Refining Company                                        |  | Delaware              
|Husky Marketing and Supply Company                           |  | Delaware              
|                                                             | 
|Subsidiaries of HOI Resources Co.                            |  |                       
|Husky Energy International Corporation                       |  | British Columbia      
|                                                             | 
|Subsidiaries of Husky Energy International Corporation       |  |                       
|Husky Oil China Ltd.                                         |  | Alberta               
|Husky Oil (Madura) Ltd. (50%)                                |  | British Virgin Islands
|Husky Oil Overseas Ltd.                                      |  | Alberta               



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GENERAL DEVELOPMENT OF HUSKY

Three Year History of Husky

2006

In January 2006, Husky acquired two Exploration Licences (EL) in the Jeanne dArc Basin of the Grand Banks Region offshore
Newfoundland and Labrador. Husky holds a 100% working interest in the 33,320 acre EL1094 and the 5,260 acre EL 1096. Husky has committed to spend a total of $37 million evaluating the prospects of these ELs.

On February 1, 2006, Husky redeemed its 8.45% senior secured bonds for U.S. $85 million.

In April 2006, Husky acquired 23,680 acres of oil sands leases adjacent to its Saleski oil sands property. The cost was $10 million and increased
Huskys holdings in the Saleski area to 178,560 acres.

In June 2006, Husky completed a farm-in agreement with Norsk Hydro to earn
additional interests in two Significant Discovery Licences (SDLs) in the Jeanne dArc Basin. Under the terms of the agreement Husky drilled a delineation well on West Bonne Bay, SDL 1040, to earn a 25% working interest and an
additional 7.5% working interest in North Ben Nevis, SDL 1008.

In July 2006, Husky acquired 14,560 acres of oil sands leases adjacent to
its Saleski oil sands property. The cost was $6.6 million and increased Huskys holdings in the Saleski area to 193,120 acres.

The
second phase of modifications to produce low sulphur diesel fuel at the Prince George refinery was completed during the second quarter of 2006. The refinerys design rate capacity was increased to 12 mbbls/day as a result of this two phase
modification.

In August 2006, Husky acquired 19,200 acres of oil sands leases adjacent to its Saleski oil sands property. The cost was
$7.9 million and increased Huskys holdings in the Saleski area to 212,320 acres.

In August 2006, Husky acquired three exploration
blocks in the South China Sea totalling 4,168,915 acres. Block 29/06 covers 2,289,431 acres in the Pearl River Mouth Basin in 500 to 1500 metres of water, block 35/18 covers 1,104,314 acres in the Yinggehai Basin in less than 120 metres of water and
block 50/14 covers 775,170 acres in the Yinggehai Basin in less than 120 metres of water.

In September 2006, Husky commissioned its
Lloydminster ethanol plant, which is located adjacent to Huskys heavy oil upgrader on the Saskatchewan side of Lloydminster and has a design capacity to produce 130 million litres of ethanol per year.

In September 2006, Husky filed a base shelf prospectus that permits issue of up to U.S. $1 billion of debt securities or the equivalent in other
currencies during the 25 months that the prospectus is in effect.

In September 2006, Husky acquired 26,880 acres of oil sands leases
adjacent to its Saleski oil sands property. The cost was $13.7 million and increased Huskys holdings in the Saleski area to 239,200 acres.

In September 2006, Husky acquired an exploration block in the North East Java Basin offshore Indonesia totalling 1.2 million acres. This increased Huskys total holding in Indonesia to approximately 1.8 million acres.

In October 2006, Husky commissioned its Tucker oil sands project located 30 kilometres north-west of Cold Lake Alberta. The project
employs a steam assisted gravity drainage (SAGD) recovery system with a plant that has a design rate capacity of 30 mbbls/day.



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2007

On January 15, 2007, Husky acquired an interest in three ELs in the Jeanne dArc Basin offshore Newfoundland and Labrador. Husky acquired a 100% interest in EL 1099 covering 61,376 acres, a 50% interest in EL 1100 covering 75,545
acres and a 50% interest in EL 1101 covering 51,914 acres. Husky has committed to spend $23.5 million on these EL areas during the five year period commencing in 2007.

In January 2007, Husky signed a three-year contract with Seadrill Offshore AS for the deep water semi-submersible drilling rig, West Hercules. The rig, which was constructed in Korea, was delivered to
Huskys offshore properties in the South China Sea in late 2008. The rig commenced drilling operations in November 2008 and is scheduled to drill several delineation wells at the Liwan natural gas discovery and a number of stratigraphic test
wells on Huskys exploration blocks.

On June 19, 2007, Husky announced it had been awarded two exploration and exploitation
licences by the governments of Greenland and Denmark. The licences are for Block 5 with an area of 10,138 square kilometres and Block 7 with an area of 10,929 square kilometres. These blocks are located in an offshore area west of Disko Island in
West Greenland. Husky holds an 87.5% interest. Both of these licences expire on May 31, 2017.

Effective July 1, 2007, Husky
acquired all of the issued and outstanding shares of the Lima Refining Company from The Premcor Refinery Group Inc., a wholly owned subsidiary of Valero Energy Corporation. The purchase price was U.S. $1.9 billion plus U.S. $540 million for
feedstock and product inventory. The 160 mbbls/day refinery is located at Lima, Ohio.

On September 6, 2007, Husky announced the
issuance of U.S. $300 million of 6.2% 10 year notes due September 15, 2017 and U.S. $450 million of 6.8% 30 year notes due September 15, 2037. These notes rank equally with our other unsecured debt. The net proceeds from the notes were
used to partially repay a U.S. $1.5 billion short-term bridge financing arranged to acquire the Lima Refinery.

On October 11, 2007,
Husky was awarded an additional exploration and exploitation licence by the governments of Greenland and Denmark. The licence is for Block 6 with an area of 13,213 square kilometres. Block 6 is located in an offshore area west of Disko Island in
West Greenland. Husky holds a 43.75% interest. This licence will expire on May 31, 2017.

On October 30, 2007, Husky completed
Gas Sales Agreements between Husky Oil (Madura) Ltd. and PT Inti Parna Raya, PT Inti Alasindo Energy and PT Perusahaan Gas Negara (Persero) Tbk (PNG) for the sale of natural gas from the Madura BD natural gas and natural gas liquids
field offshore Java, Indonesia. The BD field is expected to be developed after receipt of an extension to the production sharing contract.

On December 4, 2007, Husky completed construction of the Minnedosa ethanol plant. The plant is located at Minnedosa, Manitoba and has the capacity to produce 130 million litres of ethanol for blending with gasoline.

On December 5, 2007, Husky announced an agreement with BP Corporation North America Inc. (BP) to create an integrated North American oil
sands business. The business consists of a 50/50 partnership to develop the Sunrise oil sands project contributed and operated by Husky and a 50/50 limited liability company for the Toledo Refinery contributed and operated by BP. The transaction
closed at the end of the first quarter of 2008 with an effective date of January 1, 2008.

On December 17, 2007, a framework
agreement between the Province of Newfoundland and Labrador and Husky and its partner was signed for the development of North Amethyst, West White Rose and the South White Rose Extension. Under the terms of the agreement, a crown corporation of
Newfoundland and Labrador acquired a 5% equity interest in the White Rose expansion oil fields in January 2009.



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##### Table of Contents

2008

On January 18, 2008, Husky announced that it had secured the Transocean owned semi-submersible drilling rig, GSF Grand Banks, for continuing operations in the White Rose area and for continued delineation drilling offshore
Newfoundland and Labrador. The three year agreement also includes an option for two additional one year extensions.

On March 11,
2008, Husky announced an agreement with Petro-Canada and StatoilHydro to secure the semi-submersible drilling rig, Henry Goodrich, for a period of 24 to 30 months. Husky will use the rig on its operated properties offshore Newfoundland and
Labrador for 17 months.

On March 31, 2008, Husky announced that all necessary government and regulatory approvals had been received
and the arrangements for the formation of an integrated oil sands/refining joint venture with BP had been completed. The effective date of the transaction was January 1, 2008.

On April 2, 2008, Husky announced that it had received approval from the federal and provincial governments and regulators to proceed with the
development of the North Amethyst oil field, a satellite of the South Avalon White Rose producing oil field.

On April 17, 2008, Husky
announced that it had reached agreement with China National Offshore Oil Corporation (CNOOC) to jointly develop the Madura BD natural gas and natural gas liquids field offshore the East Java Sea, Indonesia. The agreement covers the
development and further exploration of the Madura Strait Production Sharing Contract. CNOOC paid U.S. $125 million to acquire 50% equity interest in Husky Oil (Madura) Ltd., which holds the Madura Strait Production Sharing Contract.

On June 5, 2008, Husky repaid the remaining U.S. $750 million short-term bridge facility arranged in 2007 to acquire the Lima Refinery.

On June 12, 2008, Husky announced a cash tender offer to purchase any and all of its outstanding 8.90% Capital Securities. The offer was for
payment of U.S. $1,010 per U.S. $1,000 principal amount plus accrued and unpaid interest. On July 11, 2008, 95% of the 8.90% Capital Securities had been validly tendered and accepted for payment. The Company subsequently redeemed all remaining
8.90% Capital Securities.

On June 25, 2008, Husky announced that it had signed a contract with CNOOC for an exploration block in the
South China Sea. The 63/05 block covers approximately 1,777 square kilometres and is located in the Qiongdongnan Basin approximately 100 kilometres south of Hainan Island, in less than 120 metres of water.

On August 29, 2008, Husky redeemed the 6.95% medium-term notes Series E at a redemption price of $208 million including accrued interest.

On September 11, 2008, Husky announced that it had acquired two parcels (blocks1 and 3) offshore Labrador, on the Labrador Shelf.
Parcel NL07-2-1, block 1, covers approximately 2,370 square kilometres and Parcel NL07-2-3, block 3, covers approximately 2,337 square kilometres.

During 2008, Husky repurchased a total of U.S. $63 million of the outstanding U.S. $450 million 6.80% notes due September 2037.



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Business Environment Trends

There are a number of trends that are developing, which may have both long and short-term effects
on the oil and gas industry in Canada. Conventional production of crude oil in the Western Canada Sedimentary Basin (WCSB) has been in decline since 2000 and will, according to industry forecasts(1), continue to decline. Since 2000, increased crude oil production from the WCSB has come from mining and in-situ production of bitumen and heavy crude oils. An increase in overall
crude oil production from the WCSB beyond current production levels is forecast(1)to be non-conventional production. Natural gas exploration
efforts are focused on the traditionally less accessible areas in the overthrust belt along the eastern slope of the Rocky Mountains, in the Northwest Territories, offshore the East Coast of Canada and smaller shallow gas deposits and coal bed
methane in the WCSB.

The trend of volatile commodity prices is expected to continue. Natural gas prices are sensitive to regional
supply/demand imbalances, regional industrial activity levels, weather patterns and access to cheaper sources of energy. As a result of numerous supply disruptions and increased demand from emerging economies oil prices reached historic highs in
2008. Notwithstanding supply disruptions or major policy changes in respect of greenhouse gas emissions, recent forecasts by the Energy Information Administration (EIA) in the United States indicates the possibility of crude oil
production capacity increasing significantly over the next two decades, particularly conventional production from Brazil, Azerbaijan, Kazakhstan and world wide non-conventional production including Canadas oil sands. Although crude oil prices
declined significantly in the fourth quarter of 2008 in response to the economic downturn, the EIAs reference case forecast includes higher crude oil prices through the forecast period beginning in 2010.

The EIA short-term energy outlook was published on January 13, 2009 and provides the
following insights to the near-term energy environment. World energy demand is expected to decrease in 2009, rebound marginally in 2010 and then continue to respond to an expected global economic recovery. Oil consumption growth is expected to be
concentrated in countries outside the Organization for Economic Cooperation and Development, particularly China, the Middle East and Latin America. The global economic slowdown and declining oil prices provides additional uncertainties to
forecasting non-Organization of Petroleum Exporting Countries (OPEC) supply, such as project delays and higher than anticipated decline rates. Low crude oil prices may result in uneconomic projects and an inability to access capital(2).

DESCRIPTION OF HUSKYS BUSINESS

General

Husky is a publicly held integrated international energy and energy related company headquartered in Calgary, Alberta.

Huskys business is conducted predominantly in three major business sectors  upstream, midstream and downstream.

Upstream includes exploration for, development and production of crude oil, natural gas and natural gas liquids. The Companys upstream operations
and key prospects are located in Western Canada, offshore Eastern Canada, offshore China, Indonesia and Greenland (Upstream business segment).





Note:



|(1) | Canadian Crude Oil Production and Supply forecast, July 2004, Canadian Association of Petroleum Producers Oil Sands Technology Roadmap, January 30,
2004, Alberta Chamber of Resources.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | Short-Term Energy Outlook, January 13, 2009, Energy Information Administration U.S. Department of Energy.
|--- | -----------------------------------------------------------------------------------------------------------



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##### Table of Contents

Midstream includes upgrading of heavy crude oil feedstock into synthetic crude oil (upgrading); marketing
of the Companys and other producers crude oil, natural gas, natural gas liquids, sulphur and petroleum coke; pipeline transportation, processing of heavy crude oil, storage of crude oil, diluent and natural gas, and cogeneration of
electrical and thermal energy (infrastructure and marketing).

Downstream includes refining of light and heavy crude oil, production of
ethanol, and marketing of refined petroleum products including gasoline, diesel, jet fuel, blending stocks, ethanol blended fuels, asphalt and the marketing of a wide variety of merchandise through convenience stores at our retail outlet locations.
The downstream sector includes the Canadian refined products business segment and the U.S. refining and marketing business segment.

Social and Environmental Policy

Husky approaches social responsibility and sustainable development by seeking a balance among
economic, operational reliability, health, safety, environmental and social issues while maintaining growth. Husky strives to find solutions to these issues that do not compromise the needs of future generations. In 2008, Husky implemented the Husky
Operational Integrity Management System (HOIMS). HOIMS is to be followed by all Husky businesses, with particular emphasis on projects and operations, and manages operational integrity through the life cycle of the assets. HOIMS includes 14
fundamental elements; each element contains well defined aims and expectations that guide Husky to continuously improve operational integrity performance. The aims outline the overall intent behind each element and expectations outline the
individual activities that are undertaken to support the aims. HOIMS guides Husky employees in effectively managing the risks associated with Huskys business and creating a safe and secure place to work. Resources will be applied and dedicated
to the implementation of HOIMS, and progress will be monitored at all levels of the Company. Periodic reviews and audits will be conducted to ensure that HOIMS is effectively integrated into daily operations and to continuously improve performance.

Aims:



| | 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 demonstrate behaviours to perform their tasks and designated 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 how we conduct our business. Leave a positive legacy behind us when operations cease.
| | -- | -------------------------------------------------------------------------------------------------------------------------------------------------



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| | 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.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 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 our 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.
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

The Health, Safety and Environment Committee of the Board of Directors is responsible for
reviewing and recommending for approval by the Board of Directors updates to the health, safety and environment policy, the development with management and achievement of specific environmental objectives and targets, and for monitoring compliance
with the Companys environmental policies. The charter 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,
land disturbances and handling of hazardous 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
anticipates that environmental laws and regulations will continue to increase in number and complexity. According to the American Petroleum Institute, between 1990 and 2007, reported environmental expenditures by the oil and gas industry in the
United States increased by 85%.(1)

Husky is required by the Government of Canada to report facilities that emit greater than 100,000
tonnes of CO2. The Lloydminster upgrader, Prince George refinery, SeaRose FPSO, Ram River gas plant, Tucker oil sands plant, Bolney SAGD
thermal plant and Pikes Peak CSS thermal plant are in this category. Husky has initiated an Environmental Performance Reporting System (EPRS) that will gather, consolidate, calculate, report and identify trends including greenhouse gas
emissions. To ensure the integrity of the EPRS data, Husky will have an independent third party audit performed. Husky is also a member of the Integrated CO2Network, which is working to reduce greenhouse gas emissions. The group is currently studying technologies in respect of capture, transportation and storage of CO2. At Lloydminster and Rainbow Lake, Husky utilizes cogeneration to produce both electricity and thermal energy for use at its processing facilities. This configuration has less adverse effects on the environment and
is cost effective. Electrical energy in excess of Huskys requirements is sold into the grid. Fugitive emissions are a contributor to greenhouse gas, a potential hazard and a waste of money. In 2007, Husky initiated a program to detect and
repair leaks. At Huskys Tucker SAGD project vapour recovery systems are in use on all tanks and process vessels.





Note:



|(1) | Environmental Expenditures by the U.S. Oil and Natural Gas Industry, 2009, American Petroleum Institute.
|--- | ----------------------------------------------------------------------------------------------------------



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Husky has undertaken programs to minimize water
consumption, particularly potable water, and minimize risk to non-saline and potable water. At the Tucker project, 90% of water is recycled and saline water is used for make-up water. Husky is implementing various technologies to reduce water usage.
Huskys alkaline surfactant polymer floods which increases the efficiency of water and the use of CO2instead of water to mobilize heavy oil in
the reservoir are being evaluated in pilots to reduce water consumption.

A large proportion of environmental costs are embedded in general
capital costs, particularly when compliance is achieved by upgrading or expanding facilities. Husky continually implements a variety of initiatives that have cost efficiency, environmental protection and safety benefits. Such projects include gas
conservation, vapour recovery, boiler/heater efficiency and tank and pipeline integrity. In 2006, Husky completed a two phase modification at the Prince George refinery for approximately $105 million that reduces sulphur content in gasoline and
diesel to meet new Government of Canada regulations. Husky has approximately 500 retail locations in its light refined products operations. Husky is continually monitoring these locations for environmental issues and where required performing
remediation, which have averaged approximately $6 million per year for the past five years. Husky also performs routine underground tank replacements. During 2008, 11 locations received new tanks at a cost of approximately $14 million. Husky has
several legacy sites which require remediation. These inactive sites range from refinery sites to retail locations. In 2008 Husky spent $5 million on remediation and expects to spend approximately $9 million over the next three years to complete
remediation of these locations. Husky expects to spend approximately $40 million in 2009 at the Lima Refinery in respect of vapour recovery, emission control and water treatment.

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. 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.

Risk Factors

The following
factors should be considered in evaluating Husky:

Adequacy of crude oil and natural gas prices

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 has significant quantities of heavier grades of crude oil reserves 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 capacity for heavy crude oil is limited. As a result, wider price differentials could have adverse effects on financial
performance and condition, could reduce the value and quantities of our heavier crude oil reserves and could delay or cancel projects that involve the development of heavier crude oil resources.

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 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.



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##### Table of Contents

Demand for Huskys other products and services and the cost of required inputs

Huskys results of operations and financial condition are dependent on the price of refinery feedstock, the price of energy, the demand and pricing
for refined petroleum products and electrical power and the ability of Husky to recover the increased cost of these inputs from the customer. Husky is also dependent on the demand for our pipeline and processing capacity.

Huskys ability to replace reserves

Huskys future cash flow and cost of capital are dependent on its ability to replace its proved oil and gas reserves in a cost effective manner. Without economic reserve additions through exploration and development or acquisition,
Huskys production and, therefore, cash flow will decline. Without adequate proved reserves the Companys ability to fund development and other capital expenditures with external sources of funds is diminished.

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, to retain drilling capacity and field operating
and construction services, to attract and retain experienced skilled management and oil and gas professionals, to obtain sufficient pipeline and other transportation capacity, to 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 by an inability to acquire economic supplies and services due to competition. Subsequent increases in the
cost of, or delays in acquiring, supplies and services could result in uneconomic projects. Huskys competitors comprise all types of energy companies, some of which have greater resources.

Delays and cost overruns of capital projects

Husky
is involved in capital projects such as exploration programs, development of oil and gas properties, plant and facilities construction, expansion and modification. Project delays can adversely affect expected cash flow and overall project costs
thereby eroding project economics. Risk factors include, but are not limited to:



| |  |  | availability and cost of capital;
| | - |  | ---------------------------------



| |  |  | availability of skilled labour;
| | - |  | -------------------------------



| |  |  | availability of manufacturing capacity, supplies, material and equipment;
| | - |  | -------------------------------------------------------------------------



| |  |  | regulatory approvals;
| | - |  | ---------------------



| |  |  | faulty construction and design errors;
| | - |  | --------------------------------------



| |  |  | accidents, labour disruptions, bankruptcies and productivity issues affecting us directly or indirectly; and
| | - |  | ------------------------------------------------------------------------------------------------------------



| |  |  | unexpected changes in the scope of a project.
| | - |  | ---------------------------------------------

Business interruption of operations

Huskys operations are subject to various risks with respect to normal operating
conditions. These risks comprise, but are not limited to, explosions, blowouts, cratering, fires, severe storms and adverse weather, all forms of marine perils, release of toxic, combustible or explosive substances. These risks could cause loss of
life, injury and destruction of public, private and our owned property.

The occurrence of any of the above listed events, or others not
listed, could result in adverse financial performance and conditions that may not be fully recoverable from our insurers.



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##### Table of Contents

Foreign exchange risk

Huskys results are affected by the exchange rate between the Canadian and U.S. dollar. The majority of our 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. The majority of our expenditures are in Canadian dollars. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease the revenues received from the sale of oil and gas
commodities. Correspondingly, a decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of oil and gas commodities.

In addition, a change in the value of the Canadian dollar against the U.S. dollar will result in an increase or decrease in our U.S. dollar denominated
debt, as expressed in Canadian dollars, as well as in the related interest expense. At December 31, 2008, 100% or $2.0 billion of our long-term debt was denominated in U.S. dollars. The percentage of our long-term debt exposed to the U.S./Cdn
exchange rate decreases to 78% when cross currency swaps are included. Additionally, U.S. $687 million of our U.S. dollar denominated debt has been designated as a hedge of a net investment and the unrealized foreign exchange gain is recorded in
Other Comprehensive Income, further reducing the long-term debt exposed to the U.S./Cdn exchange rate to 35%.

The contribution receivable
representing BPs obligation to fund capital expenditures of the Sunrise partnership is denominated in U.S. dollars and gains and losses from changes in the value of the Canadian dollar versus the U.S. dollar are recorded in foreign exchange
gains and losses in the current year. At December 31, 2008, Huskys share of the balance of this receivable was U.S. $1.2 billion including accrued interest. Husky has an obligation to fund capital expenditures of the BP-Husky Toledo
Refinery and this contribution payable is denominated in U.S. dollars. Gains and losses from the translation of this obligation are recorded in Other Comprehensive Income as this item relates to a self sustaining foreign operation. At
December 31, 2008, Huskys share of the balance of this obligation was U.S. $1.4 billion including accrued interest.

Environmental risks

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 our 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. Compliance with environmental legislation can require significant expenditures and failure to comply with environmental legislation may result in the imposition of fines and penalties and liability for clean-up costs and damages. We
cannot be certain that the costs of complying with environmental legislation in the future will not have a material adverse effect on our financial condition and results of operations.

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 liability, and increased capital expenditures and operating costs, which could have a material adverse
effect on our financial condition and results of operations.

In 1994, the United Nations Framework Convention on Climate Change came
into force and three years later led to the Kyoto Protocol, which requires the reduction of greenhouse gas emissions. On December 16, 2002, Canada ratified the Kyoto Protocol. In 2007, the worlds nations met again to gain the agreement of
major



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##### Table of Contents

countries that were not signatories to the Kyoto protocol such as the United States, China and India. This meeting in Bali, Indonesia did little to advance
wider agreement on limiting greenhouse gases and setting new limits for emissions, which expire in 2012 under the Kyoto Protocol. These initiatives may require Husky to significantly reduce emissions at its operations of greenhouse gases such as
carbon dioxide, which may increase capital expenditures. Details regarding the implementation of the Kyoto Protocol and the ultimate completion of the Bali agreement in 2009 remain unclear.

The Federal Government of Canada has announced certain regulations in respect of greenhouse gases and other pollutants. Although uncertain, these
regulations may adversely affect our operations and increase our costs. These regulations may become more onerous over time as public and political pressures increase to implement initiatives that will effectively arrest the emission of greenhouse
gases.

Changes to government fiscal policy may reduce our cash flow

All of Huskys oil and gas production is subject to royalties which are potentially impacted by changes in government fiscal policies. In 2007, the Alberta Government announced its decision with respect of
recommendations issued by the Alberta Royalty Review Panel. The new Alberta fiscal regime has decreased Huskys future net revenue from proved reserves estimated at December 31, 2008 before income taxes discounted at 10% by approximately
1%.



Page 16



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##### Table of Contents

Upstream Operations

Disclosures of Oil and Gas Activities

In the tables that follow, the
following definitions apply: light crude oil (30° API and lighter), medium crude oil (between 20° and 30° API), heavy crude oil (20° and heavier but lighter than 10° API) and bitumen (10° API and heavier).

Production



|                          |  |       |  |               |  |           |  |        |  |       |  |      
|------------------------- |  | ----- |  | ------------- |  | --------- |  | ------ |  | ----- |  | -----
|                          |  | 2008 
|                          |  | Total |  | WesternCanada |  | EastCoast |  | Canada |  | China |  | Libya
|Crude Oil(mbbls/day)      |  |       |  |               |  |           |  |        |  |       |  |      
|Light crude oil and NGL   |  | 122.9 |  | 24.6          |  | 86.1      |  | 110.7  |  | 12.1  |  | 0.1  
|Medium crude oil          |  | 26.9  |  | 26.9          |  |          |  | 26.9   |  |      |  |     
|Heavy crude oil & bitumen |  | 107.0 |  | 107.0         |  |          |  | 107.0  |  |      |  |     
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Total gross(1)            |  | 256.8 |  | 158.5         |  | 86.1      |  | 244.6  |  | 12.1  |  | 0.1  
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Total net(1)              |  | 206.8 |  | 134.9         |  | 62.7      |  | 197.6  |  | 9.1   |  | 0.1  
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Natural Gas(mmcf/day)     |  |       |  |               |  |           |  |        |  |       |  |      
|Gross(1)                  |  | 594.4 |  | 594.4         |  |          |  | 594.4  |  |      |  |     
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Net(1)                    |  | 464.2 |  | 464.2         |  |          |  | 464.2  |  |      |  |     
|                          |  |       |  |               |  |           |  |        |  |       |  |      



|                          |  |       |  |               |  |           |  |        |  |       |  |      
|------------------------- |  | ----- |  | ------------- |  | --------- |  | ------ |  | ----- |  | -----
|                          |  | 2007 
|                          |  | Total |  | WesternCanada |  | EastCoast |  | Canada |  | China |  | Libya
|Crude Oil(mbbls/day)      |  |       |  |               |  |           |  |        |  |       |  |      
|Light crude oil and NGL   |  | 138.7 |  | 26.4          |  | 99.5      |  | 125.9  |  | 12.7  |  | 0.1  
|Medium crude oil          |  | 27.1  |  | 27.1          |  |          |  | 27.1   |  |      |  |     
|Heavy crude oil & bitumen |  | 106.9 |  | 106.9         |  |          |  | 106.9  |  |      |  |     
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Total gross(1)            |  | 272.7 |  | 160.4         |  | 99.5      |  | 259.9  |  | 12.7  |  | 0.1  
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Total net(1)              |  | 233.0 |  | 134.6         |  | 88.2      |  | 222.8  |  | 10.1  |  | 0.1  
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Natural Gas(mmcf/day)     |  |       |  |               |  |           |  |        |  |       |  |      
|Gross(1)                  |  | 623.3 |  | 623.3         |  |          |  | 623.3  |  |      |  |     
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Net(1)                    |  | 492.3 |  | 492.3         |  |          |  | 492.3  |  |      |  |     
|                          |  |       |  |               |  |           |  |        |  |       |  |      



|                          |  |       |  |               |  |           |  |        |  |       |  |      
|------------------------- |  | ----- |  | ------------- |  | --------- |  | ------ |  | ----- |  | -----
|                          |  | 2006 
|                          |  | Total |  | WesternCanada |  | EastCoast |  | Canada |  | China |  | Libya
|Crude Oil(mbbls/day)      |  |       |  |               |  |           |  |        |  |       |  |      
|Light crude oil and NGL   |  | 111.0 |  | 30.3          |  | 68.5      |  | 98.8   |  | 12.1  |  | 0.1  
|Medium crude oil          |  | 28.5  |  | 28.5          |  |          |  | 28.5   |  |      |  |     
|Heavy crude oil & bitumen |  | 108.1 |  | 108.1         |  |          |  | 108.1  |  |      |  |     
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Total gross(1)            |  | 247.6 |  | 166.9         |  | 68.5      |  | 235.4  |  | 12.1  |  | 0.1  
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Total net(1)              |  | 220.4 |  | 143.8         |  | 66.5      |  | 210.3  |  | 10.0  |  | 0.1  
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Natural Gas(mmcf/day)     |  |       |  |               |  |           |  |        |  |       |  |      
|Gross(1)                  |  | 672.3 |  | 672.3         |  |          |  | 672.3  |  |      |  |     
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Net(1)                    |  | 528.2 |  | 528.2         |  |          |  | 528.2  |  |      |  |     
|                          |  |       |  |               |  |           |  |        |  |       |  |      



Note:



|(1) | Gross volumes are Huskys lessor royalty, overriding royalty and working interest share of production before deduction of royalties. Net volumes are Huskys gross volumes,
less royalties.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Page 17



---

##### Table of Contents

Revenue



|                          |  |              |  |               |  |           |  |        |  |       |  |      
|------------------------- |  | ------------ |  | ------------- |  | --------- |  | ------ |  | ----- |  | -----
|                          |  | 2008        
|                          |  | Total        |  | WesternCanada |  | EastCoast |  | Canada |  | China |  | Libya
|                          |  | ($ millions)
|Crude Oil                 |  |              |  |               |  |           |  |        |  |       |  |      
|Light crude oil and NGL   |  | 4,374        |  | 780           |  | 3,157     |  | 3,937  |  | 433   |  | 4    
|Medium crude oil          |  | 805          |  | 805           |  |          |  | 805    |  |      |  |     
|Heavy crude oil & bitumen |  | 2,805        |  | 2,805         |  |          |  | 2,805  |  |      |  |     
|                          |  |              |  |               |  |           |  |        |  |       |  |      
|Total gross               |  | 7,984        |  | 4,390         |  | 3,157     |  | 7,547  |  | 433   |  | 4    
|                          |  |              |  |               |  |           |  |        |  |       |  |      
|Total net                 |  | 6,225        |  | 3,621         |  | 2,289     |  | 5,910  |  | 312   |  | 3    
|                          |  |              |  |               |  |           |  |        |  |       |  |      
|Natural Gas               |  |              |  |               |  |           |  |        |  |       |  |      
|Gross                     |  | 1,876        |  | 1,876         |  |          |  | 1,876  |  |      |  |     
|                          |  |              |  |               |  |           |  |        |  |       |  |      
|Net                       |  | 1,563        |  | 1,563         |  |          |  | 1,563  |  |      |  |     
|                          |  |              |  |               |  |           |  |        |  |       |  |      
|Processing/Transportation |  | 72           |  | 72            |  |          |  | 72     |  |      |  |     
|                          |  |              |  |               |  |           |  |        |  |       |  |      



|                          |  |              |  |               |  |           |  |        |  |       |  |      
|------------------------- |  | ------------ |  | ------------- |  | --------- |  | ------ |  | ----- |  | -----
|                          |  | 2007        
|                          |  | Total        |  | WesternCanada |  | EastCoast |  | Canada |  | China |  | Libya
|                          |  | ($ millions)
|Crude Oil                 |  |              |  |               |  |           |  |        |  |       |  |      
|Light crude oil and NGL   |  | 3,722        |  | 626           |  | 2,736     |  | 3,362  |  | 357   |  | 3    
|Medium crude oil          |  | 504          |  | 504           |  |          |  | 504    |  |      |  |     
|Heavy crude oil & bitumen |  | 1,567        |  | 1,567         |  |          |  | 1,567  |  |      |  |     
|                          |  |              |  |               |  |           |  |        |  |       |  |      
|Total gross               |  | 5,793        |  | 2,697         |  | 2,736     |  | 5,433  |  | 357   |  | 3    
|                          |  |              |  |               |  |           |  |        |  |       |  |      
|Total net                 |  | 4,965        |  | 2,421         |  | 2,256     |  | 4,677  |  | 285   |  | 3    
|                          |  |              |  |               |  |           |  |        |  |       |  |      
|Natural Gas               |  |              |  |               |  |           |  |        |  |       |  |      
|Gross                     |  | 1,430        |  | 1,430         |  |          |  | 1,430  |  |      |  |     
|                          |  |              |  |               |  |           |  |        |  |       |  |      
|Net                       |  | 1,200        |  | 1,200         |  |          |  | 1,200  |  |      |  |     
|                          |  |              |  |               |  |           |  |        |  |       |  |      
|Processing/Transportation |  | 64           |  | 64            |  |          |  | 64     |  |      |  |     
|                          |  |              |  |               |  |           |  |        |  |       |  |      



|                          |  |              |  |               |  |           |  |        |  |       |  |      
|------------------------- |  | ------------ |  | ------------- |  | --------- |  | ------ |  | ----- |  | -----
|                          |  | 2006        
|                          |  | Total        |  | WesternCanada |  | EastCoast |  | Canada |  | China |  | Libya
|                          |  | ($ millions)
|Crude Oil                 |  |              |  |               |  |           |  |        |  |       |  |      
|Light crude oil and NGL   |  | 2,799        |  | 691           |  | 1,779     |  | 2,470  |  | 324   |  | 5    
|Medium crude oil          |  | 515          |  | 515           |  |          |  | 515    |  |      |  |     
|Heavy crude oil & bitumen |  | 1,575        |  | 1,575         |  |          |  | 1,575  |  |      |  |     
|                          |  |              |  |               |  |           |  |        |  |       |  |      
|Total gross               |  | 4,889        |  | 2,781         |  | 1,779     |  | 4,560  |  | 324   |  | 5    
|                          |  |              |  |               |  |           |  |        |  |       |  |      
|Total net                 |  | 4,358        |  | 2,352         |  | 1,731     |  | 4,083  |  | 270   |  | 5    
|                          |  |              |  |               |  |           |  |        |  |       |  |      
|Natural Gas               |  |              |  |               |  |           |  |        |  |       |  |      
|Gross                     |  | 1,601        |  | 1,601         |  |          |  | 1,601  |  |      |  |     
|                          |  |              |  |               |  |           |  |        |  |       |  |      
|Net                       |  | 1,319        |  | 1,319         |  |          |  | 1,319  |  |      |  |     
|                          |  |              |  |               |  |           |  |        |  |       |  |      
|Processing/Transportation |  | 96           |  | 69            |  | 27        |  | 96     |  |      |  |     
|                          |  |              |  |               |  |           |  |        |  |       |  |      



Page 18



---

##### Table of Contents

Sales Prices



|                          |  |       |  |               |  |           |  |        |  |       |  |       
|------------------------- |  | ----- |  | ------------- |  | --------- |  | ------ |  | ----- |  | ------
|                          |  | 2008 
|                          |  | Total |  | WesternCanada |  | EastCoast |  | Canada |  | China |  | Libya 
|Crude Oil($/bbl)          |  |       |  |               |  |           |  |        |  |       |  |       
|Light crude oil and NGL   |  | 97.28 |  | 86.65         |  | 100.12    |  | 97.13  |  | 98.56 |  | 118.97
|Medium crude oil          |  | 81.79 |  | 81.79         |  |          |  | 81.79  |  |      |  |      
|Heavy crude oil & bitumen |  | 71.61 |  | 71.61         |  |          |  | 71.61  |  |      |  |      
|Total crude oil and NGL   |  | 84.96 |  | 75.67         |  | 100.12    |  | 84.28  |  | 98.56 |  | 118.97
|                          |  |       |  |               |  |          
|Natural Gas($/mcf)        |  | 7.94  |  | 7.94          |  |          |  | 7.94   |  |      |  |      



|                          |  |       |  |               |  |           |  |        |  |       |  |      
|------------------------- |  | ----- |  | ------------- |  | --------- |  | ------ |  | ----- |  | -----
|                          |  | 2007 
|                          |  | Total |  | WesternCanada |  | EastCoast |  | Canada |  | China |  | Libya
|Crude Oil($/bbl)          |  |       |  |               |  |           |  |        |  |       |  |      
|Light crude oil and NGL   |  | 73.54 |  | 65.01         |  | 75.37     |  | 73.18  |  | 77.03 |  | 82.21
|Medium crude oil          |  | 51.12 |  | 51.12         |  |          |  | 51.12  |  |      |  |     
|Heavy crude oil & bitumen |  | 40.19 |  | 40.19         |  |          |  | 40.19  |  |      |  |     
|Total crude oil and NGL   |  | 58.24 |  | 46.12         |  | 75.37     |  | 57.31  |  | 77.03 |  | 82.21
|                          |  |       |  |               |  |          
|Natural Gas($/mcf)        |  | 6.19  |  | 6.19          |  |          |  | 6.19   |  |      |  |     



|                          |  |       |  |               |  |           |  |        |  |       |  |      
|------------------------- |  | ----- |  | ------------- |  | --------- |  | ------ |  | ----- |  | -----
|                          |  | 2006 
|                          |  | Total |  | WesternCanada |  | EastCoast |  | Canada |  | China |  | Libya
|Crude Oil($/bbl)          |  |       |  |               |  |           |  |        |  |       |  |      
|Light crude oil and NGL   |  | 69.06 |  | 62.46         |  | 71.18     |  | 68.50  |  | 73.58 |  | 74.96
|Medium crude oil          |  | 49.48 |  | 49.48         |  |          |  | 49.48  |  |      |  |     
|Heavy crude oil & bitumen |  | 39.92 |  | 39.92         |  |          |  | 39.92  |  |      |  |     
|Total crude oil and NGL   |  | 54.08 |  | 45.64         |  | 71.18     |  | 53.07  |  | 73.58 |  | 74.96
|                          |  |       |  |               |  |          
|Natural Gas($/mcf)        |  | 6.47  |  | 6.47          |  |          |  | 6.47   |  |      |  |     



Page 19



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##### Table of Contents

Capital Expenditures



|                     |  |              |  |               |  |           |  |        |  |              |  |       |  |           |  |      
|-------------------- |  | ------------ |  | ------------- |  | --------- |  | ------ |  | ------------ |  | ----- |  | --------- |  | -----
|                     |  | 2008        
|                     |  | Total        |  | WesternCanada |  | EastCoast |  | Canada |  | UnitedStates |  | China |  | Indonesia |  | Libya
|                     |  | ($ millions)
|Property acquisition |  | 530          |  | 485           |  |          |  | 485    |  | 45           |  |      |  |          |  |     
|Exploration          |  | 836          |  | 436           |  | 160       |  | 596    |  | 15           |  | 214   |  | 11        |  |     
|Development          |  | 2,214        |  | 1,640         |  | 569       |  | 2,209  |  |             |  | 3     |  |          |  | 2    
|                     |  |              |  |               |  |           |  |        |  |              |  |       |  |           |  |      
|                     |  | 3,580        |  | 2,561         |  | 729       |  | 3,290  |  | 60           |  | 217   |  | 11        |  | 2    
|                     |  |              |  |               |  |           |  |        |  |              |  |       |  |           |  |      



|                     |  |              |  |               |  |           |  |        |  |       |  |           |  |      
|-------------------- |  | ------------ |  | ------------- |  | --------- |  | ------ |  | ----- |  | --------- |  | -----
|                     |  | 2007        
|                     |  | Total        |  | WesternCanada |  | EastCoast |  | Canada |  | China |  | Indonesia |  | Libya
|                     |  | ($ millions)
|Property acquisition |  | 172          |  | 172           |  |          |  | 172    |  |      |  |          |  |     
|Exploration          |  | 564          |  | 410           |  | 83        |  | 493    |  | 54    |  | 17        |  |     
|Development          |  | 1,652        |  | 1,449         |  | 197       |  | 1,646  |  | 1     |  | 5         |  |     
|                     |  |              |  |               |  |           |  |        |  |       |  |           |  |      
|                     |  | 2,388        |  | 2,031         |  | 280       |  | 2,311  |  | 55    |  | 22        |  |     
|                     |  |              |  |               |  |           |  |        |  |       |  |           |  |      



|                     |  |              |  |               |  |           |  |        |  |       |  |           |  |      
|-------------------- |  | ------------ |  | ------------- |  | --------- |  | ------ |  | ----- |  | --------- |  | -----
|                     |  | 2006        
|                     |  | Total        |  | WesternCanada |  | EastCoast |  | Canada |  | China |  | Indonesia |  | Libya
|                     |  | ($ millions)
|Property acquisition |  | 193          |  | 192           |  | 1         |  | 193    |  |      |  |          |  |     
|Exploration          |  | 774          |  | 618           |  | 79        |  | 697    |  | 71    |  | 6         |  |     
|Development          |  | 1,660        |  | 1,361         |  | 279       |  | 1,640  |  | 14    |  | 5         |  | 1    
|                     |  |              |  |               |  |           |  |        |  |       |  |           |  |      
|                     |  | 2,627        |  | 2,171         |  | 359       |  | 2,530  |  | 85    |  | 11        |  | 1    
|                     |  |              |  |               |  |           |  |        |  |       |  |           |  |      



Page 20



---

##### Table of Contents

Oil and Gas Netbacks (1)



|                          |  |       |  |               |  |           |  |        |  |       |  |       
|------------------------- |  | ----- |  | ------------- |  | --------- |  | ------ |  | ----- |  | ------
|                          |  | 2008 
|                          |  | Total |  | WesternCanada |  | EastCoast |  | Canada |  | China |  | Libya 
|Crude Oil($/bbl)          |  |       |  |               |  |           |  |        |  |       |  |       
|Light crude oil           |  |       |  |               |  |           |  |        |  |       |  |       
|Sales revenue             |  | 96.73 |  | 82.97         |  | 100.12    |  | 96.51  |  | 98.56 |  | 118.97
|Royalties                 |  | 25.14 |  | 11.53         |  | 28.45     |  | 24.89  |  | 27.65 |  |      
|Operating costs           |  | 6.56  |  | 13.90         |  | 4.99      |  | 6.74   |  | 4.78  |  | 17.35 
|                          |  |       |  |               |  |           |  |        |  |       |  |       
|Netback                   |  | 65.03 |  | 57.54         |  | 66.68     |  | 64.88  |  | 66.13 |  | 101.62
|                          |  |       |  |               |  |           |  |        |  |       |  |       
|Medium crude oil          |  |       |  |               |  |           |  |        |  |       |  |       
|Sales revenue             |  | 79.91 |  | 79.91         |  |          |  | 79.91  |  |      |  |      
|Royalties                 |  | 13.91 |  | 13.91         |  |          |  | 13.91  |  |      |  |      
|Operating costs           |  | 15.60 |  | 15.60         |  |          |  | 15.60  |  |      |  |      
|                          |  |       |  |               |  |           |  |        |  |       |  |       
|Netback                   |  | 50.40 |  | 50.40         |  |          |  | 50.40  |  |      |  |      
|                          |  |       |  |               |  |           |  |        |  |       |  |       
|Heavy crude oil & bitumen |  |       |  |               |  |           |  |        |  |       |  |       
|Sales revenue             |  | 71.19 |  | 71.19         |  |          |  | 71.19  |  |      |  |      
|Royalties                 |  | 10.52 |  | 10.52         |  |          |  | 10.52  |  |      |  |      
|Operating costs           |  | 15.60 |  | 15.60         |  |          |  | 15.60  |  |      |  |      
|                          |  |       |  |               |  |           |  |        |  |       |  |       
|Netback                   |  | 45.07 |  | 45.07         |  |          |  | 45.07  |  |      |  |      
|                          |  |       |  |               |  |           |  |        |  |       |  |       
|Total crude oil           |  |       |  |               |  |           |  |        |  |       |  |       
|Sales revenue             |  | 84.13 |  | 74.43         |  | 100.12    |  | 83.47  |  | 98.56 |  | 118.97
|Royalties                 |  | 17.75 |  | 11.26         |  | 28.45     |  | 17.28  |  | 27.65 |  |      
|Operating costs           |  | 11.39 |  | 15.27         |  | 4.99      |  | 11.68  |  | 4.78  |  | 17.35 
|                          |  |       |  |               |  |           |  |        |  |       |  |       
|Netback                   |  | 54.99 |  | 47.90         |  | 66.68     |  | 54.51  |  | 66.13 |  | 101.62
|                          |  |       |  |               |  |           |  |        |  |       |  |       
|Natural Gas($/mcf)        |  |       |  |               |  |           |  |        |  |       |  |       
|Sales revenue             |  | 8.21  |  | 8.21          |  |          |  | 8.21   |  |      |  |      
|Royalties                 |  | 1.60  |  | 1.60          |  |          |  | 1.60   |  |      |  |      
|Operating costs           |  | 1.59  |  | 1.59          |  |          |  | 1.59   |  |      |  |      
|                          |  |       |  |               |  |           |  |        |  |       |  |       
|Netback                   |  | 5.02  |  | 5.02          |  |          |  | 5.02   |  |      |  |      
|                          |  |       |  |               |  |           |  |        |  |       |  |       
|Equivalent Unit($boe)     |  |       |  |               |  |           |  |        |  |       |  |       
|Sales revenue             |  | 74.57 |  | 64.89         |  | 100.12    |  | 73.72  |  | 98.56 |  | 118.97
|Royalties                 |  | 15.52 |  | 10.63         |  | 28.45     |  | 15.09  |  | 27.65 |  |      
|Operating costs           |  | 10.93 |  | 13.16         |  | 4.99      |  | 11.14  |  | 4.78  |  | 17.35 
|                          |  |       |  |               |  |           |  |        |  |       |  |       
|Netback                   |  | 48.12 |  | 41.10         |  | 66.68     |  | 47.49  |  | 66.13 |  | 101.62
|                          |  |       |  |               |  |           |  |        |  |       |  |       



Note:



|(1) | Netbacks reflect the results of operations for leases classified as oil or natural gas. Co-products, such as natural gas produced at an oil property or natural gas liquids produced
at a natural gas property, have been converted to equivalent units of oil or natural gas depending on the lease product classification.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Page 21



---

##### Table of Contents

|                          |  |       |  |               |  |           |  |        |  |       |  |      
|------------------------- |  | ----- |  | ------------- |  | --------- |  | ------ |  | ----- |  | -----
|                          |  | 2007 
|                          |  | Total |  | WesternCanada |  | EastCoast |  | Canada |  | China |  | Libya
|Crude Oil($/bbl)          |  |       |  |               |  |           |  |        |  |       |  |      
|Light crude oil           |  |       |  |               |  |           |  |        |  |       |  |      
|Sales revenue             |  | 72.94 |  | 61.02         |  | 75.37     |  | 72.56  |  | 77.03 |  | 82.21
|Royalties                 |  | 9.72  |  | 7.87          |  | 9.43      |  | 9.12   |  | 15.63 |  |     
|Operating costs           |  | 5.70  |  | 13.24         |  | 4.07      |  | 5.89   |  | 3.68  |  | 23.12
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Netback                   |  | 57.52 |  | 39.91         |  | 61.87     |  | 57.55  |  | 57.72 |  | 59.09
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Medium crude oil          |  |       |  |               |  |           |  |        |  |       |  |      
|Sales revenue             |  | 50.42 |  | 50.42         |  |          |  | 50.42  |  |      |  |     
|Royalties                 |  | 8.89  |  | 8.89          |  |          |  | 8.89   |  |      |  |     
|Operating costs           |  | 13.92 |  | 13.92         |  |          |  | 13.92  |  |      |  |     
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Netback                   |  | 27.61 |  | 27.61         |  |          |  | 27.61  |  |      |  |     
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Heavy crude oil & bitumen |  |       |  |               |  |           |  |        |  |       |  |      
|Sales revenue             |  | 40.14 |  | 40.14         |  |          |  | 40.14  |  |      |  |     
|Royalties                 |  | 5.26  |  | 5.26          |  |          |  | 5.26   |  |      |  |     
|Operating costs           |  | 12.81 |  | 12.81         |  |          |  | 12.81  |  |      |  |     
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Netback                   |  | 22.07 |  | 22.07         |  |          |  | 22.07  |  |      |  |     
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Total crude oil           |  |       |  |               |  |           |  |        |  |       |  |      
|Sales revenue             |  | 57.60 |  | 45.13         |  | 75.37     |  | 56.65  |  | 77.03 |  | 82.21
|Royalties                 |  | 7.87  |  | 6.30          |  | 9.43      |  | 7.49   |  | 15.63 |  |     
|Operating costs           |  | 9.37  |  | 13.07         |  | 4.07      |  | 9.64   |  | 3.68  |  | 23.12
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Netback                   |  | 40.36 |  | 25.76         |  | 61.87     |  | 39.52  |  | 57.72 |  | 59.09
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Natural Gas($/mcf)        |  |       |  |               |  |           |  |        |  |       |  |      
|Sales revenue             |  | 6.42  |  | 6.42          |  |          |  | 6.42   |  |      |  |     
|Royalties                 |  | 1.23  |  | 1.23          |  |          |  | 1.23   |  |      |  |     
|Operating costs           |  | 1.39  |  | 1.39          |  |          |  | 1.39   |  |      |  |     
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Netback                   |  | 3.80  |  | 3.80          |  |          |  | 3.80   |  |      |  |     
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Equivalent Unit($boe)     |  |       |  |               |  |           |  |        |  |       |  |      
|Sales revenue             |  | 52.41 |  | 42.57         |  | 75.37     |  | 51.54  |  | 77.03 |  | 82.21
|Royalties                 |  | 7.74  |  | 6.72          |  | 9.43      |  | 7.46   |  | 15.63 |  |     
|Operating costs           |  | 9.09  |  | 11.24         |  | 4.07      |  | 9.28   |  | 3.68  |  | 23.12
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Netback                   |  | 35.58 |  | 24.61         |  | 61.87     |  | 34.80  |  | 57.72 |  | 59.09
|                          |  |       |  |               |  |           |  |        |  |       |  |      



Note:



|(1) | Netbacks reflect the results of operations for leases classified as oil or natural gas. Co-products, such as natural gas produced at an oil property or natural gas liquids produced
at a natural gas property, have been converted to equivalent units of oil or natural gas depending on the lease product classification.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Page 22



---

##### Table of Contents

|                          |  |       |  |               |  |           |  |        |  |       |  |      
|------------------------- |  | ----- |  | ------------- |  | --------- |  | ------ |  | ----- |  | -----
|                          |  | 2006 
|                          |  | Total |  | WesternCanada |  | EastCoast |  | Canada |  | China |  | Libya
|Crude Oil($/bbl)          |  |       |  |               |  |           |  |        |  |       |  |      
|Light crude oil           |  |       |  |               |  |           |  |        |  |       |  |      
|Sales revenue             |  | 68.51 |  | 59.89         |  | 71.18     |  | 67.87  |  | 73.58 |  | 74.96
|Royalties                 |  | 4.49  |  | 7.34          |  | 1.95      |  | 3.52   |  | 12.33 |  |     
|Operating costs           |  | 6.96  |  | 11.89         |  | 5.48      |  | 7.36   |  | 3.61  |  | 18.51
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Netback                   |  | 57.06 |  | 40.66         |  | 63.75     |  | 56.99  |  | 57.64 |  | 56.45
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Medium crude oil          |  |       |  |               |  |           |  |        |  |       |  |      
|Sales revenue             |  | 48.97 |  | 48.97         |  |          |  | 48.97  |  |      |  |     
|Royalties                 |  | 8.61  |  | 8.61          |  |          |  | 8.61   |  |      |  |     
|Operating costs           |  | 13.09 |  | 13.09         |  |          |  | 13.09  |  |      |  |     
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Netback                   |  | 27.27 |  | 27.27         |  |          |  | 27.27  |  |      |  |     
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Heavy crude oil & bitumen |  |       |  |               |  |           |  |        |  |       |  |      
|Sales revenue             |  | 39.91 |  | 39.91         |  |          |  | 39.91  |  |      |  |     
|Royalties                 |  | 5.16  |  | 5.16          |  |          |  | 5.16   |  |      |  |     
|Operating costs           |  | 11.10 |  | 11.10         |  |          |  | 11.10  |  |      |  |     
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Netback                   |  | 23.65 |  | 23.65         |  |          |  | 23.65  |  |      |  |     
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Total crude oil           |  |       |  |               |  |           |  |        |  |       |  |      
|Sales revenue             |  | 53.55 |  | 44.90         |  | 71.18     |  | 52.51  |  | 73.58 |  | 74.96
|Royalties                 |  | 5.28  |  | 6.14          |  | 1.95      |  | 4.92   |  | 12.33 |  |     
|Operating costs           |  | 9.53  |  | 11.60         |  | 5.48      |  | 9.83   |  | 3.61  |  | 18.51
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Netback                   |  | 38.74 |  | 27.16         |  | 63.75     |  | 37.76  |  | 57.64 |  | 56.45
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Natural Gas($/mcf)        |  |       |  |               |  |           |  |        |  |       |  |      
|Sales revenue             |  | 6.65  |  | 6.65          |  |          |  | 6.65   |  |      |  |     
|Royalties                 |  | 1.37  |  | 1.37          |  |          |  | 1.37   |  |      |  |     
|Operating costs           |  | 1.18  |  | 1.18          |  |          |  | 1.18   |  |      |  |     
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Netback                   |  | 4.10  |  | 4.10          |  |          |  | 4.10   |  |      |  |     
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Equivalent Unit($boe)     |  |       |  |               |  |           |  |        |  |       |  |      
|Sales revenue             |  | 49.34 |  | 42.91         |  | 71.18     |  | 48.58  |  | 73.58 |  | 74.96
|Royalties                 |  | 6.19  |  | 6.97          |  | 1.95      |  | 5.99   |  | 12.33 |  |     
|Operating costs           |  | 8.77  |  | 9.79          |  | 5.48      |  | 8.98   |  | 3.61  |  | 18.51
|                          |  |       |  |               |  |           |  |        |  |       |  |      
|Netback                   |  | 34.38 |  | 26.15         |  | 63.75     |  | 33.61  |  | 57.64 |  | 56.45
|                          |  |       |  |               |  |           |  |        |  |       |  |      



Note:



|(1) | Netbacks reflect the results of operations for leases classified as oil or natural gas. Co-products, such as natural gas produced at an oil property or natural gas liquids produced
at a natural gas property, have been converted to equivalent units of oil or natural gas depending on the lease product classification.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Page 23



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##### Table of Contents

Producing Wells



|                        |  |              |  |                   |  |              |  |         |  |              |  |        
|----------------------- |  | ------------ |  | ----------------- |  | ------------ |  | ------- |  | ------------ |  | -------
|                        |  | Oil Wells    |  | Natural Gas Wells |  | Total       
|                        |  | Gross (1)(2) |  | Net(1)            |  | Gross (1)(2) |  | Net (1) |  | Gross (1)(2) |  | Net (1)
|Canada                  |  |              |  |                   |  |              |  |         |  |              |  |        
|Alberta                 |  | 4,276        |  | 3,406             |  | 5,631        |  | 4,346   |  | 9,907        |  | 7,752  
|Saskatchewan            |  | 5,697        |  | 4,682             |  | 1,318        |  | 1,205   |  | 7,015        |  | 5,887  
|British Columbia        |  | 203          |  | 58                |  | 259          |  | 205     |  | 462          |  | 263    
|Newfoundland            |  | 23           |  | 8                 |  |             |  |        |  | 23           |  | 8      
|                        |  |              |  |                   |  |              |  |         |  |              |  |        
|                        |  | 10,199       |  | 8,154             |  | 7,208        |  | 5,756   |  | 17,407       |  | 13,910 
|                        |  |              |  |                   |  |              |  |         |  |              |  |        
|International           |  |              |  |                   |  |              |  |         |  |              |  |        
|China                   |  | 29           |  | 12                |  |             |  |        |  | 29           |  | 12     
|Libya                   |  | 2            |  | 1                 |  |             |  |        |  | 2            |  | 1      
|                        |  |              |  |                   |  |              |  |         |  |              |  |        
|                        |  | 31           |  | 13                |  |             |  |        |  | 31           |  | 13     
|                        |  |              |  |                   |  |              |  |         |  |              |  |        
|As at December 31, 2008 |  | 10,230       |  | 8,167             |  | 7,208        |  | 5,756   |  | 17,438       |  | 13,923 
|                        |  |              |  |                   |  |              |  |         |  |              |  |        
|Canada                  |  |              |  |                   |  |              |  |         |  |              |  |        
|Alberta                 |  | 4,090        |  | 3,211             |  | 5,489        |  | 4,274   |  | 9,579        |  | 7,485  
|Saskatchewan            |  | 5,479        |  | 4,514             |  | 1,192        |  | 1,085   |  | 6,671        |  | 5,599  
|British Columbia        |  | 204          |  | 58                |  | 239          |  | 170     |  | 443          |  | 228    
|Newfoundland            |  | 22           |  | 7                 |  |             |  |        |  | 22           |  | 7      
|                        |  |              |  |                   |  |              |  |         |  |              |  |        
|                        |  | 9,795        |  | 7,790             |  | 6,920        |  | 5,529   |  | 16,715       |  | 13,319 
|                        |  |              |  |                   |  |              |  |         |  |              |  |        
|International           |  |              |  |                   |  |              |  |         |  |              |  |        
|China                   |  | 29           |  | 12                |  |             |  |        |  | 29           |  | 12     
|Libya                   |  | 2            |  | 1                 |  |             |  |        |  | 2            |  | 1      
|                        |  |              |  |                   |  |              |  |         |  |              |  |        
|                        |  | 31           |  | 13                |  |             |  |        |  | 31           |  | 13     
|                        |  |              |  |                   |  |              |  |         |  |              |  |        
|As at December 31, 2007 |  | 9,826        |  | 7,803             |  | 6,920        |  | 5,529   |  | 16,746       |  | 13,332 
|                        |  |              |  |                   |  |              |  |         |  |              |  |        
|Canada                  |  |              |  |                   |  |              |  |         |  |              |  |        
|Alberta                 |  | 4,390        |  | 3,395             |  | 5,385        |  | 4,235   |  | 9,775        |  | 7,630  
|Saskatchewan            |  | 5,076        |  | 4,118             |  | 1,084        |  | 1,028   |  | 6,160        |  | 5,146  
|British Columbia        |  | 203          |  | 57                |  | 219          |  | 150     |  | 422          |  | 207    
|Newfoundland            |  | 21           |  | 6                 |  |             |  |        |  | 21           |  | 6      
|Northwest Territories   |  | 5            |  | 1                 |  | 5            |  | 1       |  | 10           |  | 2      
|                        |  |              |  |                   |  |              |  |         |  |              |  |        
|                        |  | 9,695        |  | 7,577             |  | 6,693        |  | 5,414   |  | 16,388       |  | 12,991 
|                        |  |              |  |                   |  |              |  |         |  |              |  |        
|International           |  |              |  |                   |  |              |  |         |  |              |  |        
|China                   |  | 27           |  | 11                |  |             |  |        |  | 27           |  | 11     
|Libya                   |  | 2            |  | 1                 |  |             |  |        |  | 2            |  | 1      
|                        |  |              |  |                   |  |              |  |         |  |              |  |        
|                        |  | 29           |  | 12                |  |             |  |        |  | 29           |  | 12     
|                        |  |              |  |                   |  |              |  |         |  |              |  |        
|As at December 31, 2006 |  | 9,724        |  | 7,589             |  | 6,693        |  | 5,414   |  | 16,417       |  | 13,003 
|                        |  |              |  |                   |  |              |  |         |  |              |  |        



Notes:



|(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. Producing wells were producing or capable of producing at December 31.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(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, 2008, Husky had a royalty interest in
3,929 wells of which 1,272 were oil producers and 2,657 were gas producers.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(3) | For purposes of the above 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 2008, there were 313 gross, 298 net oil wells and 789 gross, 657 net natural gas wells which were completed in two or more formations and from which production is not commingled.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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##### Table of Contents

Landholdings



|                                 |  |                      |  |      
|-------------------------------- |  | -------------------- |  | -----
|                                 |  | Developed Acreage   
|                                 |  | Gross                |  | Net  
|                                 |  | (thousands of acres)
|As at December 31, 2008          |  |                      |  |      
|Western Canada                   |  |                      |  |      
|Alberta                          |  | 3,159                |  | 2,658
|Saskatchewan                     |  | 779                  |  | 657  
|British Columbia                 |  | 167                  |  | 114  
|                                 |  |                      |  |      
|                                 |  | 4,105                |  | 3,429
|                                 |  |                      |  |      
|Eastern Canada                   |  | 54                   |  | 18   
|                                 |  |                      |  |      
|                                 |  | 4,159                |  | 3,447
|                                 |  |                      |  |      
|China                            |  | 17                   |  | 7    
|Libya                            |  | 7                    |  | 2    
|                                 |  |                      |  |      
|                                 |  | 4,183                |  | 3,456
|                                 |  |                      |  |      
|As at December 31, 2007          |  |                      |  |      
|Western Canada                   |  |                      |  |      
|Alberta                          |  | 3,102                |  | 2,610
|Saskatchewan                     |  | 638                  |  | 574  
|British Columbia                 |  | 183                  |  | 115  
|                                 |  |                      |  |      
|                                 |  | 3,923                |  | 3,299
|                                 |  |                      |  |      
|Northwest Territories and Arctic |  |                     |  |     
|Eastern Canada                   |  | 42                   |  | 9    
|                                 |  |                      |  |      
|                                 |  | 3,965                |  | 3,308
|                                 |  |                      |  |      
|China                            |  | 17                   |  | 7    
|Libya                            |  | 7                    |  | 2    
|                                 |  |                      |  |      
|                                 |  | 3,989                |  | 3,317
|                                 |  |                      |  |      
|As at December 31, 2006          |  |                      |  |      
|Western Canada                   |  |                      |  |      
|Alberta                          |  | 3,235                |  | 2,709
|Saskatchewan                     |  | 592                  |  | 531  
|British Columbia                 |  | 185                  |  | 114  
|                                 |  |                      |  |      
|                                 |  | 4,012                |  | 3,354
|                                 |  |                      |  |      
|Northwest Territories and Arctic |  | 7                    |  | 1    
|Eastern Canada                   |  | 35                   |  | 4    
|                                 |  |                      |  |      
|                                 |  | 4,054                |  | 3,359
|                                 |  |                      |  |      
|China                            |  | 17                   |  | 7    
|Libya                            |  | 7                    |  | 2    
|                                 |  |                      |  |      
|                                 |  | 4,078                |  | 3,368
|                                 |  |                      |  |      



Page 25



---

##### Table of Contents

Landholdings (continued)



|                                 |  |                      |  |       
|-------------------------------- |  | -------------------- |  | ------
|                                 |  | Undeveloped Acreage 
|                                 |  | Gross                |  | Net   
|                                 |  | (thousands of acres)
|As at December 31, 2008          |  |                      |  |       
|Western Canada                   |  |                      |  |       
|Alberta                          |  | 4,287                |  | 3,743 
|Saskatchewan                     |  | 1,563                |  | 1,473 
|British Columbia                 |  | 962                  |  | 662   
|Manitoba                         |  | 1                    |  | 1     
|                                 |  |                      |  |       
|                                 |  | 6,813                |  | 5,879 
|                                 |  |                      |  |       
|Northwest Territories and Arctic |  | 1,042                |  | 629   
|Eastern Canada                   |  | 4,364                |  | 3,192 
|                                 |  |                      |  |       
|                                 |  | 12,219               |  | 9,700 
|                                 |  |                      |  |       
|United States                    |  | 1,707                |  | 422   
|                                 |  |                      |  |       
|China                            |  | 6,337                |  | 3,105 
|                                 |  |                      |  |       
|Indonesia                        |  | 2,992                |  | 2,646 
|                                 |  |                      |  |       
|Greenland                        |  | 8,471                |  | 5,983 
|                                 |  |                      |  |       
|                                 |  | 31,726               |  | 21,856
|                                 |  |                      |  |       
|As at December 31, 2007          |  |                      |  |       
|Western Canada                   |  |                      |  |       
|Alberta                          |  | 4,118                |  | 3,600 
|Saskatchewan                     |  | 1,547                |  | 1,404 
|British Columbia                 |  | 888                  |  | 610   
|Manitoba                         |  | 1                    |  | 1     
|                                 |  |                      |  |       
|                                 |  | 6,554                |  | 5,615 
|                                 |  |                      |  |       
|Northwest Territories and Arctic |  | 1,021                |  | 396   
|Eastern Canada                   |  | 2,429                |  | 1,566 
|                                 |  |                      |  |       
|                                 |  | 10,004               |  | 7,577 
|                                 |  |                      |  |       
|China                            |  | 7,372                |  | 3,612 
|                                 |  |                      |  |       
|Indonesia                        |  | 1,742                |  | 1,742 
|                                 |  |                      |  |       
|Greenland                        |  | 8,471                |  | 5,984 
|                                 |  |                      |  |       
|                                 |  | 27,589               |  | 18,915
|                                 |  |                      |  |       
|As at December 31, 2006          |  |                      |  |       
|Western Canada                   |  |                      |  |       
|Alberta                          |  | 4,358                |  | 3,841 
|Saskatchewan                     |  | 1,654                |  | 1,513 
|British Columbia                 |  | 906                  |  | 639   
|Manitoba                         |  | 1                    |  | 1     
|                                 |  |                      |  |       
|                                 |  | 6,919                |  | 5,994 
|                                 |  |                      |  |       
|Northwest Territories and Arctic |  | 884                  |  | 239   
|Eastern Canada                   |  | 2,591                |  | 1,786 
|                                 |  |                      |  |       
|                                 |  | 10,394               |  | 8,019 
|                                 |  |                      |  |       
|China                            |  | 7,637                |  | 3,742 
|                                 |  |                      |  |       
|Indonesia                        |  | 1,742                |  | 1,742 
|                                 |  |                      |  |       
|                                 |  | 19,773               |  | 13,503
|                                 |  |                      |  |       



Page 26



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##### Table of Contents

Drilling Activity



|                             |  |                        |  |       |  |       |  |     |  |       |  |      
|---------------------------- |  | ---------------------- |  | ----- |  | ----- |  | --- |  | ----- |  | -----
|                             |  | Year ended December 31
|                             |  | 2008                   |  | 2007  |  | 2006 
|                             |  | Gross                  |  | Net   |  | Gross |  | Net |  | Gross |  | Net  
|Western Canada Drilling      |  |                        |  |       |  |       |  |     |  |       |  |      
|Exploration                  |  |                        |  |       |  |       |  |     |  |       |  |      
|Oil                          |  | 80                     |  | 70    |  | 79    |  | 79  |  | 101   |  | 99   
|Gas                          |  | 102                    |  | 79    |  | 114   |  | 92  |  | 330   |  | 192  
|Dry                          |  | 27                     |  | 23    |  | 14    |  | 12  |  | 26    |  | 24   
|                             |  |                        |  |       |  |       |  |     |  |       |  |      
|                             |  | 209                    |  | 172   |  | 207   |  | 183 |  | 457   |  | 315  
|                             |  |                        |  |       |  |       |  |     |  |       |  |      
|Development                  |  |                        |  |       |  |       |  |     |  |       |  |      
|Oil                          |  | 685                    |  | 578   |  | 571   |  | 530 |  | 590   |  | 543  
|Gas                          |  | 435                    |  | 270   |  | 343   |  | 251 |  | 565   |  | 490  
|Dry                          |  | 36                     |  | 36    |  | 31    |  | 29  |  | 25    |  | 22   
|                             |  |                        |  |       |  |       |  |     |  |       |  |      
|                             |  | 1,156                  |  | 884   |  | 945   |  | 810 |  | 1,180 |  | 1,055
|                             |  |                        |  |       |  |       |  |     |  |       |  |      
|                             |  | 1,365                  |  | 1,056 |  | 1,152 |  | 993 |  | 1,637 |  | 1,370
|                             |  |                        |  |       |  |       |  |     |  |       |  |      
|Offshore East Coast  Canada |  |                        |  |       |  |       |  |     |  |       |  |      
|Development                  |  |                        |  |       |  |       |  |     |  |       |  |      
|Oil                          |  | 1                      |  | 1     |  | 1     |  | 1   |  | 4     |  | 2    
|                             |  |                        |  |       |  |       |  |     |  |       |  |      

Present Activities



|                             |  |             |  |             |  |       |  |    
|---------------------------- |  | ----------- |  | ----------- |  | ----- |  | ---
|                             |  | Exploratory |  | Development
|                             |  | Gross       |  | Net         |  | Gross |  | Net
|Wells Drilling (1)           |  |             |  |             |  |       |  |    
|Western Canada               |  | 5           |  | 3           |  | 13    |  | 11 
|United States                |  | 1           |  | 0.5         |  |      |  |   
|                             |  |             |  |             |  |       |  |    
|                             |  | 6           |  | 3.5         |  | 13    |  | 11 
|                             |  |             |  |             |  |       |  |    
|Stratigraphic Test Wells     |  |             |  |             |  |       |  |    
|Offshore East Coast  Canada |  | 1           |  | 0.4         |  |      |  |   
|Offshore China               |  | 2           |  | 1           |  |      |  |   
|                             |  |             |  |             |  |       |  |    
|                             |  | 3           |  | 1.4         |  |      |  |   
|                             |  |             |  |             |  |       |  |    



Note:



|(1) | Denotes wells that were drilling at December 31, 2008.
|--- | ------------------------------------------------------

Oil and
Gas Reserves Disclosures

Huskys oil and gas reserves as of December 31, 2008 are based on prices and costs in effect on that
date and remain constant in future periods in accordance with the rules of FASB and the SEC (U.S.) and are prepared internally by Huskys reserves evaluation staff. Husky uses a formalized process for determining, approving and booking
reserves. This process provides for all reserves evaluations to be done on a consistent basis using established definitions and guidelines. Approval of any significant reserve additions and changes requires review by an internal panel of qualified
reserves evaluators.

Audit of Oil and Gas Reserves

McDaniel & Associates Consultants Ltd., an independent firm of qualified oil and gas reserves evaluation engineers, was engaged to conduct an audit of Huskys crude oil, natural gas and natural gas
products reserves. McDaniel & Associates Consultants Ltd. issued an audit opinion stating that Huskys internally generated proved



Page 27



---

##### Table of Contents

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 in the United States and as set out in the COGEH.

Proved Reserves



|                         |  |                     |  |                 |  |                                       |  |         |  |        |  |      
|------------------------ |  | ------------------- |  | --------------- |  | ------------------------------------- |  | ------- |  | ------ |  | -----
|                         |  | Crude Oil & NGL (1) |  | Natural Gas (1) |  | Future NetCash FlowsBefore Tax
(1)(4)
|                         |  | Gross (2)           |  | Net (2)         |  | Gross (2)                             |  | Net (2) |  | 0%     |  | 10%  
|                         |  | (mmbbls)            |  | (bcf)           |  | ($ millions)                         
|Proved developed(3)      |  | 415                 |  | 363             |  | 1,760                                 |  | 1,524   |  | 11,989 |  | 7,913
|Proved undeveloped(3)(5) |  | 116                 |  | 107             |  | 430                                   |  | 388     |  | 2,214  |  | 876  
|                         |  |                     |  |                 |  |                                       |  |         |  |        |  |      
|Proved total(3)          |  | 531                 |  | 470             |  | 2,190                                 |  | 1,912   |  | 14,203 |  | 8,789
|                         |  |                     |  |                 |  |                                       |  |         |  |        |  |      



Notes:



|(1) | Husky applied for and was granted an exemption from National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities to provide oil and gas reserves
disclosures in accordance with the U.S. Securities and Exchange Commission guidelines and the U.S. Financial Accounting Standards Board disclosure standards. The information disclosed may differ from information prepared in accordance with National
Instrument 51-101. Huskys internally generated oil and gas reserves data was audited by an independent firm of qualified reserves evaluators.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | Gross reserves are Huskys lessor royalty, overriding royalty and working interest share of reserves, before deduction of royalties. Net reserves are gross reserves, less
royalties.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(3) | These reserve categories have the same meanings as those set out in SEC Regulation S-X.
|--- | ---------------------------------------------------------------------------------------



|(4) | On December 31, 2008, the date our proved oil and gas reserves were evaluated the discounted future net cash flows were based on the year-end spot NYMEX natural gas price of
U.S. $5.41/mmbtu and on a spot WTI crude oil price of U.S.$44.60/bbl. The calculated price of Lloydminster heavy crude was $34.56/bbl and Tucker bitumen was $29.86/bbl. When compared with Huskys reserves based on 2008 annual average prices the
year-end prices resulted in a negative price revision of 98/mmboe 70% of which was related to proved bitumen reserves and 13% was related to proved heavy crude oil reserves. Please refer to Huskys 2008 MD&A for further discussion about
price revisions.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(5) | Estimated future capital expenditures required to gain access to proved undeveloped reserves as at December 31, 2008 and 2007 were as follows:
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------



|               |  |                           |  |      |  |      |  |      |  |      |  |      |  |           
|-------------- |  | ------------------------- |  | ---- |  | ---- |  | ---- |  | ---- |  | ---- |  | ----------
|               |  | As at December 31, 2008  
|               |  | Total                     |  | 2009 |  | 2010 |  | 2011 |  | 2012 |  | 2013 |  | Thereafter
|               |  | ($ millions undiscounted)
|Western Canada |  | 1,615                     |  | 370  |  | 428  |  | 319  |  | 151  |  | 96   |  | 251       
|Eastern Canada |  | 391                       |  | 256  |  | 111  |  |     |  |     |  |     |  | 24        
|               |  |                           |  |      |  |      |  |      |  |      |  |      |  |           
|               |  | 2,006                     |  | 626  |  | 539  |  | 319  |  | 151  |  | 96   |  | 275       
|               |  |                           |  |      |  |      |  |      |  |      |  |      |  |           
|               | 
|               |  | As at December 31, 2007  
|               |  | Total                     |  | 2008 |  | 2009 |  | 2010 |  | 2011 |  | 2012 |  | Thereafter
|               |  | ($ millions undiscounted)
|Western Canada |  | 1,943                     |  | 713  |  | 520  |  | 272  |  | 119  |  | 87   |  | 232       
|Eastern Canada |  | 476                       |  | 198  |  | 237  |  | 19   |  |     |  |     |  | 22        
|               |  |                           |  |      |  |      |  |      |  |      |  |      |  |           
|               |  | 2,419                     |  | 911  |  | 757  |  | 291  |  | 119  |  | 87   |  | 254       
|               |  |                           |  |      |  |      |  |      |  |      |  |      |  |           
|               | 
|               |  | As at December 31, 2006  
|               |  | Total                     |  | 2007 |  | 2008 |  | 2009 |  | 2010 |  | 2011 |  | Thereafter
|               |  | ($ millions undiscounted)
|Western Canada |  | 1,725                     |  | 558  |  | 573  |  | 263  |  | 100  |  | 96   |  | 135       
|Eastern Canada |  |                          |  |     |  |     |  |     |  |     |  |     |  |          
|               |  |                           |  |      |  |      |  |      |  |      |  |      |  |           
|               |  | 1,725                     |  | 558  |  | 573  |  | 263  |  | 100  |  | 96   |  | 135       
|               |  |                           |  |      |  |      |  |      |  |      |  |      |  |           



Page 28



---

##### Table of Contents

Reconciliation of Proved Gross Reserves



|                                      |  |                    |   |  |                |   |       |                    |   |  |            |   |               |          |   |            |               |   |  |          |   |  |       |  |          |   |  |        |  
|------------------------------------- |  | ------------------ | - |  | -------------- | - | ----- | ------------------ | - |  | ---------- | - | ------------- | -------- | - | ---------- | ------------- | - |  | -------- | - |  | ----- |  | -------- | - |  | ------ | -
|                                      |  | Canada             |   |  | International  |   | Total |                   
|                                      |  | Western Canada     |   |  | East Coast     |   |       | LightCrudeOil &NGL |   |  | NaturalGas |   | CrudeOil& NGL |          |   | NaturalGas |              
|                                      |  | LightCrudeOil& NGL |   |  | MediumCrudeOil |   |       | HeavyCrudeOil      |   |  | NaturalGas |   |               | Bitumen  |   |            | LightCrudeOil |   |  |          |   | 
|                                      |  | (mmbbls)           |   |  | (mmbbls)       |   |       | (mmbbls)           |   |  | (bcf)      |   |               | (mmbbls) |   |            | (mmbbls)      |   |  | (mmbbls) |   |  | (bcf) |  | (mmbbls) |   |  | (bcf)  |  
|Proved reserves, before royalties (1) | 
|End of 2005                           |  | 167                |   |  | 91             |   |       | 217                |   |  | 2,136      |   |               | 48       |   |            | 89            |   |  | 17       |   |  |      |  | 629      |   |  | 2,136  |  
|                                      |  |                    |   |  |                |   |       |                    |   |  |            |   |               |          |   |            |               |   |  |          |   |  |       |  |          |   |  |        |  
|Revisions                             |  | (3                 | ) |  | (1             | ) |       | (2                 | ) |  | (87        | ) |               | (1       | ) |            | 31            |   |  | 2        |   |  |      |  | 26       |   |  | (87    | )
|Purchases                             |  | 1                  |   |  | 1              |   |       |                   |   |  | 25         |   |               |         |   |            |              |   |  |         |   |  |      |  | 2        |   |  | 25     |  
|Sales                                 |  | (1                 | ) |  |               |   |       |                   |   |  | (3         | ) |               |         |   |            |              |   |  |         |   |  |      |  | (1       | ) |  | (3     | )
|Discoveries and extensions            |  | 7                  |   |  | 5              |   |       | 37                 |   |  | 314        |   |               | 13       |   |            |              |   |  |         |   |  |      |  | 62       |   |  | 314    |  
|Improved recovery                     |  | 6                  |   |  | 1              |   |       |                   |   |  | 3          |   |               |         |   |            | 12            |   |  |         |   |  |      |  | 19       |   |  | 3      |  
|Production                            |  | (11                | ) |  | (10            | ) |       | (39                | ) |  | (245       | ) |               |         |   |            | (25           | ) |  | (5       | ) |  |      |  | (90      | ) |  | (245   | )
|                                      |  |                    |   |  |                |   |       |                    |   |  |            |   |               |          |   |            |               |   |  |          |   |  |       |  |          |   |  |        |  
|End of 2006                           |  | 166                |   |  | 87             |   |       | 213                |   |  | 2,143      |   |               | 60       |   |            | 107           |   |  | 14       |   |  |      |  | 647      |   |  | 2,143  |  
|                                      |  |                    |   |  |                |   |       |                    |   |  |            |   |               |          |   |            |               |   |  |          |   |  |       |  |          |   |  |        |  
|Revisions                             |  | 1                  |   |  | 4              |   |       | (8                 | ) |  | 64         |   |               |         |   |            | 26            |   |  | 2        |   |  |      |  | 25       |   |  | 64     |  
|Purchases                             |  | 1                  |   |  |               |   |       |                   |   |  | 36         |   |               |         |   |            |              |   |  |         |   |  |      |  | 1        |   |  | 36     |  
|Sales                                 |  | (10                | ) |  |               |   |       |                   |   |  | (23        | ) |               |         |   |            |              |   |  |         |   |  |      |  | (10      | ) |  | (23    | )
|Discoveries and extensions            |  | 8                  |   |  | 6              |   |       | 37                 |   |  | 189        |   |               | 11       |   |            | 19            |   |  |         |   |  |      |  | 81       |   |  | 189    |  
|Improved recovery                     |  | 2                  |   |  | 1              |   |       | 1                  |   |  | 10         |   |               |         |   |            |              |   |  |         |   |  |      |  | 4        |   |  | 10     |  
|Production                            |  | (9                 | ) |  | (10            | ) |       | (38                | ) |  | (228       | ) |               | (1       | ) |            | (36           | ) |  | (5       | ) |  |      |  | (99      | ) |  | (228   | )
|                                      |  |                    |   |  |                |   |       |                    |   |  |            |   |               |          |   |            |               |   |  |          |   |  |       |  |          |   |  |        |  
|End of 2007                           |  | 159                |   |  | 88             |   |       | 205                |   |  | 22,191     |   |               | 70       |   |            | 116           |   |  | 11       |   |  |      |  | 649      |   |  | 22,191 |  
|                                      |  |                    |   |  |                |   |       |                    |   |  |            |   |               |          |   |            |               |   |  |          |   |  |       |  |          |   |  |        |  
|Revisions                             |  | (12                | ) |  | 3              |   |       | (13                | ) |  | (42        | ) |               | (69      | ) |            | 15            |   |  |         |   |  |      |  | (76      | ) |  | (42    | )
|Purchases                             |  | 2                  |   |  | 1              |   |       | 6                  |   |  | 96         |   |               |         |   |            |              |   |  |         |   |  |      |  | 9        |   |  | 96     |  
|Sales                                 |  | (1                 | ) |  |               |   |       |                   |   |  | (19        | ) |               |         |   |            |              |   |  |         |   |  |      |  | (1       | ) |  | (19    | )
|Discoveries and extensions            |  | 6                  |   |  | 2              |   |       | 25                 |   |  | 150        |   |               |         |   |            |              |   |  |         |   |  |      |  | 33       |   |  | 150    |  
|Improved recovery                     |  | 3                  |   |  | 1              |   |       | 2                  |   |  | 32         |   |               |         |   |            | 5             |   |  |         |   |  |      |  | 11       |   |  | 32     |  
|Production                            |  | (9                 | ) |  | (10            | ) |       | (38                | ) |  | (218       | ) |               | (1       | ) |            | (32           | ) |  | (4       | ) |  |      |  | (94      | ) |  | (218   | )
|                                      |  |                    |   |  |                |   |       |                    |   |  |            |   |               |          |   |            |               |   |  |          |   |  |       |  |          |   |  |        |  
|End of 2008                           |  | 148                |   |  | 85             |   |       | 187                |   |  | 2,190      |   |               |         |   |            | 104           |   |  | 7        |   |  |      |  | 531      |   |  | 2,190  |  
|                                      |  |                    |   |  |                |   |       |                    |   |  |            |   |               |          |   |            |               |   |  |          |   |  |       |  |          |   |  |        |  



Note:



|(1) | Proved reserves are the estimated quantities of crude oil, natural gas and NGL which geological and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating conditions.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Page 29



---

##### Table of Contents

Reserves and Production by Principal Area



|                                  |  |                 |  |            
|--------------------------------- |  | --------------- |  | -----------
|                                  |  | Gross          
|                                  |  | Proved Reserves |  | Production 
|                                  |  | (mmbbls)        |  | (mbbls/day)
|Crude Oil and NGL (1)             |  |                 |  |            
|Canada                            |  |                 |  |            
|Western Canada                    |  |                 |  |            
|British Columbia and Foothills    |  |                 |  |            
|Alberta and BC Plains area        |  | 28.6            |  | 4.6        
|Foothills Deep Gas area           |  | 24.1            |  | 5.0        
|Ram River and Kaybob areas        |  | 5.7             |  | 2.1        
|Northwest Alberta Plains          |  |                 |  |            
|Rainbow Lake area                 |  | 73.9            |  | 7.4        
|Athabasca area                    |  | 6.5             |  | 1.9        
|East Central Alberta              |  |                 |  |            
|North area                        |  | 1.5             |  | 0.5        
|South area                        |  | 2.5             |  | 0.9        
|Provost area                      |  | 33.7            |  | 15.6       
|Southern Alberta and Saskatchewan |  |                 |  |            
|South Alberta area                |  | 25.8            |  | 8.3        
|South Saskatchewan area           |  | 61.2            |  | 14.4       
|Lloydminster Area                 |  |                 |  |            
|Primary production                |  | 91.6            |  | 74.5       
|Thermal production                |  | 64.7            |  | 20.0       
|Oil Sands                         |  |                |  | 2.7        
|Other                             |  | 0.1             |  | 0.6        
|                                  |  |                 |  |            
|                                  |  | 419.9           |  | 158.5      
|                                  |  |                 |  |            
|East Coast Canada                 |  |                 |  |            
|Terra Nova                        |  | 17.9            |  | 12.9       
|White Rose                        |  | 86.3            |  | 73.2       
|                                  |  |                 |  |            
|                                  |  | 104.2           |  | 86.1       
|                                  |  |                 |  |            
|China                             |  |                 |  |            
|Wenchang                          |  | 7.1             |  | 12.2       
|                                  |  |                 |  |            
|                                  |  | 531.2           |  | 256.8      
|                                  |  |                 |  |            



Note:



|(1) | Gross crude oil and NGL reserves as at December 31, 2008 and average 2008 daily gross production of crude oil and NGL.
|--- | ----------------------------------------------------------------------------------------------------------------------



Page 30



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##### Table of Contents

|                                  |  |                 |  |           
|--------------------------------- |  | --------------- |  | ----------
|                                  |  | Gross          
|                                  |  | Proved Reserves |  | Production
|                                  |  | (bcf)           |  | (mmcf/day)
|Natural Gas (1)                   |  |                 |  |           
|Canada                            |  |                 |  |           
|Western Canada                    |  |                 |  |           
|British Columbia and Foothills    |  |                 |  |           
|Alberta and BC Plains area        |  | 117.6           |  | 48.8      
|Foothills Deep Gas area           |  | 466.9           |  | 97.2      
|Ram River and Kaybob areas        |  | 215.3           |  | 71.3      
|Northwest Alberta Plains          |  |                 |  |           
|Rainbow Lake area                 |  | 482.0           |  | 72.0      
|Northern Alberta area             |  | 158.7           |  | 53.5      
|East Central Alberta              |  |                 |  |           
|Provost area                      |  | 128.4           |  | 46.6      
|North area                        |  | 177.8           |  | 40.7      
|South area                        |  | 135.1           |  | 51.2      
|Southern Alberta and Saskatchewan |  |                 |  |           
|South Alberta area                |  | 49.0            |  | 23.5      
|South Saskatchewan area           |  | 185.4           |  | 41.4      
|Lloydminster Area                 |  | 73.7            |  | 40.2      
|Other                             |  |                |  | 8.0       
|                                  |  |                 |  |           
|                                  |  | 2,189.9         |  | 594.4     
|                                  |  |                 |  |           



Note:



|(1) | Gross natural gas reserves as at December 31, 2008 and average daily gross production of natural gas.
|--- | -----------------------------------------------------------------------------------------------------

Probable Oil and Gas Reserves(1)



|                          |  |                |  |               |  |         |  |     |  |      
|------------------------- |  | -------------- |  | ------------- |  | ------- |  | --- |  | -----
|                          |  | Canada         |  | International |  | Total  
|                          |  | Western Canada |  | East Coast    |  |         |  |    
|                          |  | Conventional   |  | Bitumen (2)   |  |         |  |     |  |      
|Crude Oil & NGL           |  |                |  |               |  |         |  |     |  |      
|                          |  | (mmbbls)      
|2008                      |  | 129            |  | 96            |  | 64      |  | 14  |  | 303  
|2007                      |  | 149            |  | 1,765         |  | 100     |  | 25  |  | 2,039
|2006                      |  | 144            |  | 1,127         |  | 79      |  | 9   |  | 1,359
|                          |  |                |  |               | 
|Natural Gas               |  |                |  |               |  |         |  |     |  |      
|                          |  |                |  |               |  | (bcf)   |  |     |  |      
|2008                      |  | 458            |  |              |  |        |  | 258 |  | 716  
|2007                      |  | 473            |  |              |  |        |  | 516 |  | 989  
|2006                      |  | 390            |  |              |  |        |  | 93  |  | 483  
|                          |  |                |  |               | 
|Barrels of Oil Equivalent |  |                |  |               |  |         |  |     |  |      
|                          |  |                |  |               |  | (mmboe) |  |     |  |      
|2008                      |  | 206            |  | 96            |  | 64      |  | 57  |  | 423  
|2007                      |  | 228            |  | 1,765         |  | 100     |  | 111 |  | 2,204
|2006                      |  | 209            |  | 1,127         |  | 79      |  | 25  |  | 1,440



Notes:



|(1) | The probable reserves presented have been prepared, using constant prices and costs, in accordance with NI 51-101.
|--- | ------------------------------------------------------------------------------------------------------------------



|(2) | The SEC generally permits oil and gas registrants to disclose only reserves that meet the standards for proved reserves. Due to the higher uncertainty associated with probable
reserves, disclosure or reference to probable reserves does not meet the standards for the inclusion in a document filed with the SEC. The disclosure of probable reserves is included herein in accordance with NI 51-101.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Page 31



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##### Table of Contents

Disclosure about Oil and Gas Producing Activities  Statement of Financial Accounting Standards No. 69

The following disclosures have been prepared in accordance with FASB Statement No. 69 Disclosures about Oil and Gas Producing
Activities (FAS 69):

Oil and Gas Reserves

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions.

Proved developed oil and gas reserves are reserves that can be
expected to be recovered through existing wells with existing equipment and operating methods.

Proved undeveloped reserves are reserves
that are expected to be recovered from known accumulations where a significant expenditure is required.

Canadian provincial royalties are
determined based on a graduated percentage scale, which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume prices and royalty rates in existence at the time the estimates were made, and Huskys
estimate of future production volumes. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause our share of future production from Canadian reserves to be materially different from that
presented.

Subsequent to December 31, 2008, no major discovery or other favourable or adverse event is believed to have caused a
material change in the estimates of proved or proved developed reserves as of that date.

Results of Operations for Producing Activities(1)(2)



|                                         |  |                                     |  |               |  |       |  |       |  |       |  |       |  |       |  |       |  |      
|---------------------------------------- |  | ----------------------------------- |  | ------------- |  | ----- |  | ----- |  | ----- |  | ----- |  | ----- |  | ----- |  | -----
|                                         |  | Canada                              |  | International |  | Total
|                                         |  | 2008                                |  | 2007          |  | 2006  |  | 2008  |  | 2007  |  | 2006  |  | 2008  |  | 2007  |  | 2006 
|                                         |  | ($ millions except per boe amounts)
|Oil and gas production revenue           |  | 7,667                               |  | 5,998         |  | 5,567 |  | 315   |  | 288   |  | 274   |  | 7,982 |  | 6,286 |  | 5,841
|                                         |  |                                     |  |               |  |       |  |       |  |       |  |       |  |       |  |       |  |      
|Operating costs                          |  |                                     |  |               |  |       |  |       |  |       |  |       |  |       |  |       |  |      
|Lease operating expenses                 |  | 1,469                               |  | 1,292         |  | 1,215 |  | 25    |  | 21    |  | 22    |  | 1,494 |  | 1,313 |  | 1,237
|Production taxes                         |  | 93                                  |  | 64            |  | 69    |  |      |  |      |  |      |  | 93    |  | 64    |  | 69   
|Asset retirement obligation accretion    |  | 44                                  |  | 38            |  | 37    |  | 1     |  |      |  |      |  | 45    |  | 38    |  | 37   
|                                         |  |                                     |  |               |  |       |  |       |  |       |  |       |  |       |  |       |  |      
|                                         |  | 1,606                               |  | 1,394         |  | 1,321 |  | 26    |  | 21    |  | 22    |  | 1,632 |  | 1,415 |  | 1,343
|Depreciation, depletion and amortization |  | 1,457                               |  | 1,563         |  | 1,426 |  | 48    |  | 52    |  | 50    |  | 1,505 |  | 1,615 |  | 1,476
|                                         |  |                                     |  |               |  |       |  |       |  |       |  |       |  |       |  |       |  |      
|Earnings before taxes                    |  | 4,604                               |  | 3,041         |  | 2,820 |  | 241   |  | 215   |  | 202   |  | 4,845 |  | 3,256 |  | 3,022
|Income tax                               |  | 1,409                               |  | 994           |  | 982   |  | 74    |  | 70    |  | 72    |  | 1,483 |  | 1,064 |  | 1,054
|                                         |  |                                     |  |               |  |       |  |       |  |       |  |       |  |       |  |       |  |      
|Results of operations                    |  | 3,195                               |  | 2,047         |  | 1,838 |  | 167   |  | 145   |  | 130   |  | 3,362 |  | 2,192 |  | 1,968
|                                         |  |                                     |  |               |  |       |  |       |  |       |  |       |  |       |  |       |  |      
|Amortization rate per gross boe          |  | 11.58                               |  | 11.77         |  | 11.24 |  | 10.93 |  | 11.10 |  | 11.24 |  | 11.56 |  | 11.75 |  | 11.24
|Amortization rate per net boe            |  | 14.47                               |  | 14.06         |  | 13.09 |  | 14.77 |  | 14.01 |  | 13.50 |  | 14.48 |  | 14.05 |  | 13.10



Notes:



|(1) | The costs in this schedule exclude corporate overhead, interest expense and other operating costs, which are not directly related to producing activities.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | Under U.S. GAAP, the depreciation, depletion and amortization for Canadian producing activities for 2008 amounted to $1,435 million (2007  $1,507 million; 2006  $1,362
million). Income taxes for Canadian producing activities under U.S. GAAP for 2008 amounted to $1,415 million (2007  $1,011 million; 2006  $1,005 million).
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Page 32



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##### Table of Contents

Costs Incurred in Oil and Gas Property
Acquisition, Exploration and Development Activities (1)



|                              |  |              |  |               |  |      
|----------------------------- |  | ------------ |  | ------------- |  | -----
|                              |  | Canada       |  | International |  | Total
|                              |  | ($ millions)
|2008                          |  |              |  |               |  |      
|Property acquisition          |  |              |  |               |  |      
|Proved                        |  | 241          |  |              |  | 241  
|Unproved                      |  | 244          |  | 45            |  | 289  
|Exploration                   |  | 596          |  | 240           |  | 836  
|Development                   |  | 2,209        |  | 5             |  | 2,214
|Capitalized interest          |  |             |  |              |  |     
|                              |  |              |  |               |  |      
|Total costs incurred          |  | 3,290        |  | 290           |  | 3,580
|Less: Proved acquisitions     |  | 241          |  |              |  | 241  
|Capitalized interest          |  |             |  |              |  |     
|                              |  |              |  |               |  |      
|Finding and development costs |  | 3,049        |  | 290           |  | 3,339
|                              |  |              |  |               |  |      
|2007                          |  |              |  |               |  |      
|Property acquisition          |  |              |  |               |  |      
|Proved                        |  | 126          |  |              |  | 126  
|Unproved                      |  | 46           |  |              |  | 46   
|Exploration                   |  | 580          |  | 70            |  | 650  
|Development                   |  | 1,559        |  | 6             |  | 1,565
|Capitalized interest          |  | 6            |  |              |  | 6    
|                              |  |              |  |               |  |      
|Total costs incurred          |  | 2,317        |  | 76            |  | 2,393
|Less: Proved acquisitions     |  | 126          |  |              |  | 126  
|Capitalized interest          |  | 6            |  |              |  | 6    
|                              |  |              |  |               |  |      
|Finding and development costs |  | 2,185        |  | 76            |  | 2,261
|                              |  |              |  |               |  |      
|2006                          |  |              |  |               |  |      
|Property acquisition          |  |              |  |               |  |      
|Proved                        |  | 97           |  |              |  | 97   
|Unproved                      |  | 96           |  |              |  | 96   
|Exploration                   |  | 697          |  | 77            |  | 774  
|Development                   |  | 1,637        |  | 20            |  | 1,657
|Capitalized interest          |  | 23           |  |              |  | 23   
|                              |  |              |  |               |  |      
|Total costs incurred          |  | 2,550        |  | 97            |  | 2,647
|Less: Proved acquisitions     |  | 97           |  |              |  | 97   
|Capitalized interest          |  | 23           |  |              |  | 23   
|                              |  |              |  |               |  |      
|Finding and development costs |  | 2,430        |  | 97            |  | 2,527
|                              |  |              |  |               |  |      



Note:



|(1) | Development costs incurred exclude actual retirement expenditures and include asset retirement obligation incurred. Asset retirement obligation incurred for 2008 was $40 million
(2007  $39 million; 2006  $45 million).
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Acquisition costs include costs incurred to purchase, lease, or
otherwise acquire oil and gas properties.

Exploration costs include the costs of geological and geophysical activity, retaining
undeveloped properties and drilling and equipping exploration wells.

Development costs include the costs of drilling and equipping
development wells, facilities to extract, treat and gather and store oil and gas and settle the related asset retirement obligations.



Page 33



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Exploration and development costs include administrative costs and depreciation of support equipment
directly associated with these activities.

The following table sets forth a summary of oil and gas property costs not being amortized at
December 31, 2008, by the year in which the costs were incurred:



|                      |  |              |  |       |  |      |  |      |  |             
|--------------------- |  | ------------ |  | ----- |  | ---- |  | ---- |  | ------------
|Withheld Costs        |  | Total        |  | 2008  |  | 2007 |  | 2006 |  | Prior to2006
|                      |  | ($ millions)
|Property acquisitions |  |              |  |       |  |      |  |      |  |             
|Canada                |  | 67           |  |      |  |     |  | 67   |  |            
|International         |  | 63           |  |      |  |     |  |     |  | 63          
|                      |  |              |  |       |  |      |  |      |  |             
|                      |  | 130          |  |      |  |     |  | 67   |  | 63          
|                      |  |              |  |       |  |      |  |      |  |             
|Exploration           |  |              |  |       |  |      |  |      |  |             
|Canada                |  | 1,686        |  | 1,248 |  | 426  |  | 12   |  |            
|International         |  | 408          |  | 278   |  | 67   |  | 63   |  |            
|                      |  |              |  |       |  |      |  |      |  |             
|                      |  | 2,094        |  | 1,526 |  | 493  |  | 75   |  |            
|                      |  |              |  |       |  |      |  |      |  |             
|Development           |  |              |  |       |  |      |  |      |  |             
|Canada                |  | 846          |  | 544   |  | 302  |  |     |  |            
|International         |  | 14           |  | 1     |  | 4    |  | 5    |  | 4           
|                      |  |              |  |       |  |      |  |      |  |             
|                      |  | 860          |  | 545   |  | 306  |  | 5    |  | 4           
|                      |  |              |  |       |  |      |  |      |  |             
|Capitalized interest  |  |              |  |       |  |      |  |      |  |             
|Canada                |  | 104          |  |      |  | 6    |  | 58   |  | 40          
|                      |  |              |  |       |  |      |  |      |  |             
|                      |  | 3,188        |  | 2,071 |  | 805  |  | 205  |  | 107         
|                      |  |              |  |       |  |      |  |      |  |             

Capitalized Costs Relating to Oil and Gas Producing Activities



|                         |  |              |  |               |  |       
|------------------------ |  | ------------ |  | ------------- |  | ------
|                         |  | Canada       |  | International |  | Total 
|                         |  | ($ millions)
|2008                     |  |              |  |               |  |       
|Proved properties(1)     |  | 21,515       |  | 580           |  | 22,095
|Unproved properties      |  | 2,703        |  | 485           |  | 3,188 
|                         |  |              |  |               |  |       
|                         |  | 24,218       |  | 1,065         |  | 25,283
|Accumulated DD&A         |  | 10,946       |  | 486           |  | 11,432
|                         |  |              |  |               |  |       
|Net Capitalized Costs(2) |  | 13,272       |  | 579           |  | 13,851
|                         |  |              |  |               |  |       
|2007                     |  |              |  |               |  |       
|Proved properties(1)     |  | 20,830       |  | 584           |  | 21,414
|Unproved properties      |  | 1,954        |  | 243           |  | 2,197 
|                         |  |              |  |               |  |       
|                         |  | 22,784       |  | 827           |  | 23,611
|Accumulated DD&A         |  | 9,500        |  | 456           |  | 9,956 
|                         |  |              |  |               |  |       
|Net Capitalized Costs(2) |  | 13,284       |  | 371           |  | 13,655
|                         |  |              |  |               |  |       
|2006                     |  |              |  |               |  |       
|Proved properties(1)     |  | 19,087       |  | 586           |  | 19,673
|Unproved properties      |  | 1,932        |  | 165           |  | 2,097 
|                         |  |              |  |               |  |       
|                         |  | 21,019       |  | 751           |  | 21,770
|Accumulated DD&A         |  | 8,141        |  | 404           |  | 8,545 
|                         |  |              |  |               |  |       
|Net Capitalized Costs(2) |  | 12,878       |  | 347           |  | 13,225
|                         |  |              |  |               |  |       



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Notes:



|(1) | Capitalized costs related to proved properties include the asset retirement obligations. The asset retirement obligations for the years presented were as follows:
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------



|     |  |              |  |               |  |      
|---- |  | ------------ |  | ------------- |  | -----
|     |  | Canada       |  | International |  | Total
|     |  | ($ millions)
|2008 |  | 488          |  | 6             |  | 494  
|2007 |  | 454          |  | 6             |  | 460  
|2006 |  | 415          |  | 6             |  | 421  



|(2) | The net capitalized costs for Canadian oil and gas exploration, development and producing activities under U.S. GAAP for 2008 were $12,921 million (2007  $12,911 million, 2006
 $12,449 million). The net capitalized costs for International property oil & gas exploration, development and producing activities under U.S. GAAP for 2008 were $578 million (2007  $370 million, 2006  $346 million).
Please refer to the Companys Form 40-F for an explanation of the differences between Canadian and U.S. GAAP for oil and gas activities.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Oil and Gas Reserve Information

In Canada, Huskys proved crude oil, natural gas liquids and natural gas
reserves are located in the provinces of Alberta, Saskatchewan, British Columbia, and offshore the East Coast. Huskys international proved reserves are located in China and Libya.



|                                           |                |          |   |            |               |   |                |          |   |            |       |                |          |   |            |       |  
|------------------------------------------ | -------------- | -------- | - | ---------- | ------------- | - | -------------- | -------- | - | ---------- | ----- | -------------- | -------- | - | ---------- | ----- | -
|Reserves                                   |                | Canada   |   |            | International |   | Total          |         
|                                           | CrudeOil & NGL |          |   | NaturalGas |               |   | CrudeOil & NGL |          |   | NaturalGas |       | CrudeOil & NGL |          |   | NaturalGas |      
|                                           |                | (mmbbls) |   |            | (bcf)         |   |                | (mmbbls) |   |            | (bcf) |                | (mmbbls) |   |            | (bcf) |  
|Net proved reserves(1)(2)(3)(4)            |                |          |   |            |               |   |                |          |   |            |       |                |          |   |            |       |  
|End of year 2005                           |                | 549      |   |            | 1,771         |   |                | 16       |   |            |      |                | 565      |   |            | 1,771 |  
|Revisions                                  |                | 9        |   |            | (71           | ) |                |         |   |            |      |                | 9        |   |            | (71   | )
|Purchases                                  |                | 2        |   |            | 21            |   |                |         |   |            |      |                | 2        |   |            | 21    |  
|Sales                                      |                |         |   |            | (2            | ) |                |         |   |            |      |                |         |   |            | (2    | )
|Improved recovery                          |                | 16       |   |            | 2             |   |                |         |   |            |      |                | 16       |   |            | 2     |  
|Discoveries and extensions                 |                | 56       |   |            | 267           |   |                |         |   |            |      |                | 56       |   |            | 267   |  
|Production                                 |                | (77      | ) |            | (189          | ) |                | (4       | ) |            |      |                | (81      | ) |            | (189  | )
|                                           |                |          |   |            |               |   |                |          |   |            |       |                |          |   |            |       |  
|End of year 2006                           |                | 555      |   |            | 1,799         |   |                | 12       |   |            |      |                | 567      |   |            | 1,799 |  
|                                           |                |          |   |            |               |   |                |          |   |            |       |                |          |   |            |       |  
|Revisions                                  |                | 3        |   |            | 61            |   |                |         |   |            |      |                | 3        |   |            | 61    |  
|Purchases                                  |                | 1        |   |            | 29            |   |                |         |   |            |      |                | 1        |   |            | 29    |  
|Sales                                      |                | (9       | ) |            | (18           | ) |                |         |   |            |      |                | (9       | ) |            | (18   | )
|Improved recovery                          |                | 4        |   |            | 8             |   |                |         |   |            |      |                | 4        |   |            | 8     |  
|Discoveries and extensions                 |                | 71       |   |            | 155           |   |                |         |   |            |      |                | 71       |   |            | 155   |  
|Production                                 |                | (81      | ) |            | (180          | ) |                | (4       | ) |            |      |                | (85      | ) |            | (180  | )
|                                           |                |          |   |            |               |   |                |          |   |            |       |                |          |   |            |       |  
|End of year 2007                           |                | 544      |   |            | 1,854         |   |                | 8        |   |            |      |                | 552      |   |            | 1,854 |  
|                                           |                |          |   |            |               |   |                |          |   |            |       |                |          |   |            |       |  
|Revisions                                  |                | (54      | ) |            | 2             |   |                | 1        |   |            |      |                | (53      | ) |            | 2     |  
|Purchases                                  |                | 8        |   |            | 89            |   |                |         |   |            |      |                | 8        |   |            | 89    |  
|Sales                                      |                | (1       | ) |            | (16           | ) |                |         |   |            |      |                | (1       | ) |            | (16   | )
|Improved recovery                          |                | 10       |   |            | 28            |   |                |         |   |            |      |                | 10       |   |            | 28    |  
|Discoveries and extensions                 |                | 30       |   |            | 125           |   |                |         |   |            |      |                | 30       |   |            | 125   |  
|Production                                 |                | (73      | ) |            | (170          | ) |                | (3       | ) |            |      |                | (76      | ) |            | (170  | )
|                                           |                |          |   |            |               |   |                |          |   |            |       |                |          |   |            |       |  
|End of year 2008                           |                | 464      |   |            | 1,912         |   |                | 6        |   |            |      |                | 470      |   |            | 1,912 |  
|                                           |                |          |   |            |               |   |                |          |   |            |       |                |          |   |            |       |  
|Net proved developed reserves,(1)(2)(3)(4) |                |          |   |            |               |   |                |          |   |            |       |                |          |   |            |       |  
|End of year 2005                           |                | 327      |   |            | 1,413         |   |                | 15       |   |            |      |                | 342      |   |            | 1,413 |  
|End of year 2006                           |                | 442      |   |            | 1,424         |   |                | 12       |   |            |      |                | 454      |   |            | 1,424 |  
|End of year 2007                           |                | 407      |   |            | 1,494         |   |                | 8        |   |            |      |                | 415      |   |            | 1,494 |  
|End of year 2008                           |                | 357      |   |            | 1,524         |   |                | 6        |   |            |      |                | 363      |   |            | 1,524 |  



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Notes:



|(1) | Net reserves are the Companys lessor royalty, overriding royalty and working interest share of the gross remaining reserves, after deduction of any crown, freehold and
overriding royalties. Such royalties are subject to change by legislation or regulation and can also vary depending on production rates, selling prices and timing of initial production.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | Reserves are the estimated quantities of crude oil, natural gas and related substances anticipated from geological and engineering data to be recoverable from known accumulations
from a given date forward, by known technology, under existing operating conditions and prices in effect at year end.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(3) | Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(4) | Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped
reserves are reserves that are expected to be recovered from known accumulations where a significant expenditure is required.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following
information has been developed utilizing procedures prescribed by FAS 69 and based on crude oil and natural gas reserve and production volumes estimated by our reserves evaluation staff. It may be useful for certain comparison purposes, but should
not be solely relied upon in evaluating Husky or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of
discounted future net cash flows be viewed as representative of the current value of Huskys reserves.

The future cash flows
presented below are based on sales prices, cost rates, and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil and natural gas reserves may occur in the
future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of
factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2008 was
based on the NYMEX year-end natural gas spot price of U.S. $5.41/mmbtu (2007  U.S. $7.11/mmbtu; 2006  U.S. $5.51/mmbtu) and on crude oil prices computed with reference to the year-end WTI spot price of U.S. $44.60/bbl (2007  U.S.
$95.98/bbl; 2006  U.S. $60.85/bbl).



|                                   |      |              |      |                   |      |           |      |     |      |     |      |     |      |        |      |        |      |       
|---------------------------------- | ---- | ------------ | ---- | ----------------- | ---- | --------- | ---- | --- | ---- | --- | ---- | --- | ---- | ------ | ---- | ------ | ---- | ------
|Standardized Measure               |      | Canada (1)   |      | International (1) |      | Total (1)
|                                   | 2008 |              | 2007 |                   | 2006 |           | 2008 |     | 2007 |     | 2006 |     | 2008 |        | 2007 |        | 2006
|                                   |      | ($ millions)
|Future cash inflows                |      | 29,640       |      | 49,383            |      | 37,006    |      | 278 |      | 952 |      | 900 |      | 29,918 |      | 50,335 |      | 37,906
|Future production costs            |      | 11,596       |      | 12,394            |      | 10,915    |      | 99  |      | 136 |      | 143 |      | 11,695 |      | 12,530 |      | 11,058
|Future development costs           |      | 4,006        |      | 4,550             |      | 3,406     |      | 14  |      | 16  |      | 14  |      | 4,020  |      | 4,566  |      | 3,420 
|Future income taxes(2)             |      | 3,667        |      | 9,022             |      | 6,934     |      | 48  |      | 252 |      | 234 |      | 3,715  |      | 9,274  |      | 7,168 
|                                   |      |              |      |                   |      |           |      |     |      |     |      |     |      |        |      |        |      |       
|Future net cash flows              |      | 10,371       |      | 23,417            |      | 15,751    |      | 117 |      | 548 |      | 509 |      | 10,488 |      | 23,965 |      | 16,260
|Annual 10% discount factor         |      | 4,121        |      | 9,039             |      | 6,045     |      | 8   |      | 93  |      | 93  |      | 4,129  |      | 9,132  |      | 6,138 
|                                   |      |              |      |                   |      |           |      |     |      |     |      |     |      |        |      |        |      |       
|Standardized measure of discounted |      |              |      |                   |      |           |      |     |      |     |      |     |      |        |      |        |      |       
|                                   |      |              |      |                   |      |           |      |     |      |     |      |     |      |        |      |        |      |       
|Future net cash flows              |      | 6,250        |      | 14,378            |      | 9,706     |      | 109 |      | 455 |      | 416 |      | 6,359  |      | 14,833 |      | 10,122
|                                   |      |              |      |                   |      |           |      |     |      |     |      |     |      |        |      |        |      |       



Note:



|(1) | The schedules above are calculated using year-end prices, costs, statutory income tax rates and existing proved oil and gas reserves. The value of exploration properties and
probable reserves, future exploration costs, future change in oil and gas prices and in production and development costs are excluded.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | Future income taxes at a 10% annual discount factor are $2,430 million in 2008, $6,149 million in 2007 and $4,704 million in 2006.
|--- | ----------------------------------------------------------------------------------------------------------------------------------



Page 36



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Changes in Standardized Measure of Discounted Future Net Cash Flows Relating

to Proved Oil and Gas Reserves



|                                                                                 |  |              |   |  |                   |   |  |           |   |  |      |   |  |      |   |  |      |   |  |         |   |  |        |   |  |        |  
|-------------------------------------------------------------------------------- |  | ------------ | - |  | ----------------- | - |  | --------- | - |  | ---- | - |  | ---- | - |  | ---- | - |  | ------- | - |  | ------ | - |  | ------ | -
|                                                                                 |  | Canada (1)   |   |  | International (1) |   |  | Total (1) |  
|                                                                                 |  | 2008         |   |  | 2007              |   |  | 2006      |   |  | 2008 |   |  | 2007 |   |  | 2006 |   |  | 2008    |   |  | 2007   |   |  | 2006   |  
|                                                                                 |  | ($ millions) |  
|Present value at January 1                                                       |  | 14,378       |   |  | 9,706             |   |  | 10,521    |   |  | 455  |   |  | 416  |   |  | 482  |   |  | 14,833  |   |  | 10,122 |   |  | 11,003 |  
|Sales and transfers, net of production costs                                     |  | (6,167       | ) |  | (4,696            | ) |  | (4,318    | ) |  | (294 | ) |  | (270 | ) |  | (257 | ) |  | (6,461  | ) |  | (4,966 | ) |  | (4,575 | )
|Net change in sales and transfer prices, net of development and production costs |  | (10,514      | ) |  | 7,380             |   |  | (1,721    | ) |  | (338 | ) |  | 265  |   |  | 126  |   |  | (10,852 | ) |  | 7,645  |   |  | (1,595 | )
|Development cost incurred that reduced future development costs                  |  | 2,450        |   |  | 1,772             |   |  | 1,640     |   |  | 5    |   |  | 6    |   |  | 20   |   |  | 2,455   |   |  | 1,778  |   |  | 1,660  |  
|Changes in estimated future development costs                                    |  | (1,582       | ) |  | (2,157            | ) |  | (1,526    | ) |  | (6   | ) |  | (4   | ) |  | (19  | ) |  | (1,588  | ) |  | (2,161 | ) |  | (1,545 | )
|Extensions, discoveries and improved recovery, net of related costs              |  | 1,572        |   |  | 2,226             |   |  | 1,666     |   |  | 18   |   |  | 13   |   |  |     |   |  | 1,590   |   |  | 2,239  |   |  | 1,666  |  
|Revisions of quantity estimates                                                  |  | 107          |   |  | 868               |   |  | 563       |   |  | 12   |   |  | (13  | ) |  | (27  | ) |  | 119     |   |  | 855    |   |  | 536    |  
|Accretion of discount                                                            |  | 2,032        |   |  | 1,422             |   |  | 1,601     |   |  | 66   |   |  | 61   |   |  | 70   |   |  | 2,098   |   |  | 1,483  |   |  | 1,671  |  
|Sale of reserves in place                                                        |  | (104         | ) |  | (256              | ) |  | (19       | ) |  |     |   |  |     |   |  |     |   |  | (104    | ) |  | (256   | ) |  | (19    | )
|Purchase of reserves in place                                                    |  | 368          |   |  | 114               |   |  | 65        |   |  |     |   |  |     |   |  |     |   |  | 368     |   |  | 114    |   |  | 65     |  
|Changes in timing of future net cash flows and other                             |  | 155          |   |  | (575              | ) |  | 263       |   |  | 27   |   |  |     |   |  | (5   | ) |  | 182     |   |  | (575   | ) |  | 258    |  
|Net change in income taxes                                                       |  | 3,555        |   |  | (1,426            | ) |  | 971       |   |  | 164  |   |  | (19  | ) |  | 26   |   |  | 3,719   |   |  | (1,445 | ) |  | 997    |  
|                                                                                 |  |              |   |  |                   |   |  |           |   |  |      |   |  |      |   |  |      |   |  |         |   |  |        |   |  |        |  
|Net increase (decrease)                                                          |  | (8,128       | ) |  | 4,672             |   |  | (815      | ) |  | (346 | ) |  | 39   |   |  | (66  | ) |  | (8,474  | ) |  | 4,711  |   |  | (881   | )
|                                                                                 |  |              |   |  |                   |   |  |           |   |  |      |   |  |      |   |  |      |   |  |         |   |  |        |   |  |        |  
|Present value at December 31                                                     |  | 6,250        |   |  | 14,378            |   |  | 9,706     |   |  | 109  |   |  | 455  |   |  | 416  |   |  | 6,359   |   |  | 14,833 |   |  | 10,122 |  
|                                                                                 |  |              |   |  |                   |   |  |           |   |  |      |   |  |      |   |  |      |   |  |         |   |  |        |   |  |        |  



Note:

|(1) | The schedules above are calculated using year-end prices, costs, statutory income tax rates and existing proved oil and gas reserves. The value of exploration properties and
probable reserves, future exploration costs, future changes in oil and gas prices and in production and development costs are excluded.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Description of Major Properties and Facilities

Description of Major Properties and Facilities

Huskys portfolio of upstream assets includes properties with reserves of light (30° API and lighter), medium (between 20° and 30° API),
heavy (20° API and heavier but lighter than 10° API) and bitumen (10° API and heavier) gravity crude oil, NGL, natural gas and sulphur.

Lloydminster Heavy Oil and Gas

Huskys heavy oil assets are primarily concentrated in a large producing region in the
Lloydminster Alberta/Saskatchewan area. The Company maintains a land position of approximately 1.98 million acres within this area, of which approximately 68% is undeveloped. Approximately 92% of Huskys proved reserves in the region are
contained in the heavy crude oil producing fields of Pikes Peak, Edam, Tangleflags, Celtic, Bolney, Westhazel, Big Gully, Hillmond, Mervin, Marwayne, Lashburn, Gully Lake and Rush Lake, and in the medium gravity crude oil producing fields of
Wildmere and Wainwright. These fields contain accumulations of heavy crude oil at relatively shallow depths.



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Husky currently produces from oil and gas wells ranging in depth from 450 to 650 metres and holds a 100%
working interest in the majority of these wells. Production of heavy oil from the Lloydminster area uses a variety of techniques, including standard primary production methods, as well as steam injection, horizontal well technology and SAGD. Husky
has increased primary production from the area through cold production techniques which utilize progressive cavity pumps capable of simultaneous production of sand and heavy oil from unconsolidated formations. Huskys gross heavy and medium
crude oil production from the area totalled 94.4 mbbls/day in 2008. Of the total production, 71.7 mbbls/day was primary production of heavy crude oil, including cold production techniques, 19.9 mbbls/day was production from Huskys thermal
operations at Pikes Peak (cyclic steam), Bolney/Celtic (SAGD) and the Pikes Peak South pilot (SAGD), and 2.8 mbbls/day was from the medium gravity waterflooded fields in the Wainwright and Wildmere areas. Husky believes that the future growth of
crude oil production from this area will be driven by primary heavy oil production, including cold production, and new thermal projects. Husky produces natural gas from numerous small shallow pools in the Lloydminster region. During 2008,
Huskys natural gas production from the Lloydminster region averaged 40.2 mmcf/day.

In the Lloydminster area the Company owns and
operates 19 oil treating facilities, all of which are tied into the Husky heavy oil pipeline systems. These pipeline systems transport heavy crude oil from the field locations to the Husky Lloydminster asphalt refinery, to the Husky Lloydminster
Upgrader and to the Enbridge Pipeline, Express Pipeline and Inter Pipeline Fund systems at Hardisty, Alberta.

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

Lloydminster Area

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British Columbia/Foothills/Northwest Plains

Rainbow Lake District

Rainbow Lake, located approximately 700 kilometres north-west of
Edmonton, Alberta, is the site of Huskys largest light oil production operation in Western Canada. Husky operates a number of crude oil pools in the Rainbow basin, with an average working interest of 54%. Production in this district is derived
from more than 50 oil and gas pools.

Husky uses secondary and tertiary oil recovery methods extensively in the Rainbow Lake district.
These methods include injecting water, natural gas and NGL into various sections of the oil reservoirs to enhance crude oil recovery. The use of tertiary recovery programs, such as the miscible flood used at Rainbow Lake, has increased the estimated
amount recoverable from discovered petroleum initially in-place from 50% to 70% in certain pools. Historically, only small volumes of gas and NGL have been marketed from the Rainbow Lake district prior to 2002. In 2003, the recovery of natural gas
commenced from several pools. Husky uses horizontal drilling techniques, including the re-entry of existing well bores, to maintain the level of crude oil production and to increase recovery rates. Husky plans to continue exploration efforts to
supplement its development initiatives in the Rainbow Lake district. Huskys gross production from this area averaged 7.2 mbbls/day of light crude oil and NGL and 24.6 mmcf/day of natural gas during 2008.

Husky holds a 50% interest in, and operates, the Rainbow Lake processing plant. The processing design rate capacity of the plant is 69 mbbls/day of crude
oil and water and 230 mmcf/day of raw gas. The extraction design capacity is 17 mbbls/day of NGL.

Husky also has a 100% interest in a
compression and dehydration facility at Bivouac that has a capacity to process 20 mmcf/day. In 2008, throughput at this facility averaged 17.0 mmcf/day. Huskys strategy in respect of this area is to drill and tie-in eight to ten development
wells per year to fully load the facility in 2009. Husky is advancing plans to expand production to 40-50 mmcf/day from this area in the 2011-2013 timeframe.

Husky holds an interest in two significant non-operated properties in the Rainbow Lake District. They include the Ekwan/Sierra property in north-eastern British Columbia and the Bistcho property in Northwest Alberta.
Huskys gross production from these properties currently averages 12.7 mmcf/day of natural gas and 44 bbls/day of liquid hydrocarbons. Husky also holds a working interest in the Encana Sierra gas plant and the Paramount Bistcho gas plant for
processing this production. In October 2008, Husky completed an asset exchange divesting its interest in the Sierra area to increase its interest and gain operatorship of the Ekwan non-operated assets which have greater development potential. The
Company is active in both these areas with development and exploration drilling. Husky holds in excess of 200,000 acres of undeveloped land in these two areas.

North East Alberta District

The North East Alberta District is located approximately 200 kilometres north-east of
Edmonton, Alberta and is comprised primarily of shallow gas production and is currently developing primary heavy oil production. Natural gas is produced from the Clearwater, Colony, McMurray and Wabasca or a combination of these zones that lie at a
depth of approximately 600 metres. In 2008, gross natural gas production from this district averaged 54.9 mmcf/day. Huskys largest property in the district is at Muskwa, which consists of a 32 mmcf/day dehydrator facility, 6,255 horsepower of
compression and a gathering system that collects natural gas from an area seven townships in size. Husky gross production from Muskwa averaged 10.2 mmcf/day in 2008. The Company is also expanding its primary heavy oil production base in this
district with a development program at Cadotte where primary heavy oil production increased from 700 bbls/day in January, 2008 to 3,100 bbls/day by December, 2008. Primary heavy oil production tests are currently underway in both the Amadou and
McMullen areas. In 2009, Husky plans to continue to undertake recompletions and work-overs to increase production and add natural gas reserves at a low unit cost and take advantage of existing infrastructure and capacity. The Company will continue
technical evaluations on its primary heavy oil assets to position for development when market conditions improve.



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High Level District

The High Level district of Alberta is approximately 600 kilometres northwest of Edmonton, Alberta. Husky is the operator and holds close to 100% working interests in its properties. The area contains shallow Bluesky
natural gas reservoirs that are characterized as low deliverability and low decline. In 2008, gross production from this area averaged 17.6 mmcf/day of natural gas.

Ram River District

The Ram River district is located in west central Alberta and includes the
large Blackstone, Ricinus and Clearwater/ Limestone natural gas fields.

The Blackstone field is the most prolific of these fields and
contains four high deliverability natural gas wells, capable of combined raw gas production of 31.5 mmcf/day. Husky holds a 34% interest in two unitized wells, and a 24% and 50% interest, respectively, in two non-unit wells, and acts as the contract
operator of the Blackstone field. Production from the area is processed at the Ram River gas plant.

Husky holds an average 72% interest in
and operates the Ram River sour gas plant and related processing facilities. The Ram River plant has the capacity to process 622 mmcf/day of sour gas, resulting in sales gas capacity of 525 mmcf/day. The plant also has the capacity to produce in
excess of 2.8 mlt/day of sulphur from raw gas. During 2008, the plant operated at approximately 65% of its approved inlet raw gas capacity. The Ram River plant processes in excess of 10% of the Companys total gross natural gas production. This
includes an average of 35 mmcf/day of Husky gross production from the Blackstone, Brown Creek, Cordel and Stolberg fields and an average of 14.6 mmcf/day Husky gross production from Ricinus and Clearwater/Limestone and Benjamin fields. In addition
the Company processes third-party volumes. Gross production from the Strachan, Ferrier and North Blackstone areas, which is processed at other gas plants, averaged 10.7 mmcf/day of natural gas, bringing total Husky gross production of natural gas
from the Ram River district to 71.3 mmcf/day in 2008. The Companys 2009 plans for the Ram River district include continued exploration and development drilling in Ferrier and North Blackstone including evaluation of deeper targets.

Husky has a sour gas pipeline network that supports the Ram River plant. Husky operates a network of 845 kilometres of sour gas pipelines in the Ram
River district and holds a 30% interest in 684 kilometres of this pipeline system. The sour gas processed at the Ram River plant is produced from 18 sour gas fields located as far as 145 kilometres from the Ram River plant.

Husky believes that the Ram River plant and the extensive infrastructure of gathering pipelines, transmission systems and rail lines, which support the
plant, represents a strategic base for natural gas exploration and development planned in this part of the foothills region.

In addition,
other companies are actively pursuing exploration and production activities in this area which may provide additional opportunities for generating third party natural gas processing revenue. In 2008, net processing income increased from $19.8
million in 2007 to $49.9 million due, in part, to additional Shell Tay River natural gas volumes, continued activity along the Chungo Mississippian trend and additional processing of third party re-melt sulphur volumes.

Kaybob District

The Kaybob District consists
of land located in the Fox Creek region of Alberta and is divided into three areas. The Kaybob South Triassic Unit 1 (40.5% working interest), Kaybob South Triassic Unit 2 (26.8% working interest), and non-unit lands (various working interests from
gross overriding royalty to 100% working interest). Husky divested of its 35.6% working interest in the Kaybob South Beaverhill Lake Unit #1 effective January 1, 2008.



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Husky has a 13.2% working interest in the sour gas portion and a 17.8% working interest in the sweet gas
portion of the plant. The interests in the plant reflect Huskys divestiture of 4.6% working interest in the Kaybob amalgamated plant when Husky divested its interest in the Beaverhill Lake Unit #1 January 1, 2008. The Company also has
various working interests in sweet gas gathering and compression facilities in the area. During 2008, Husky gross production from this district was 688 bbls/day of crude oil and NGL and 9.7 mmcf/day of natural gas.

Alberta/British Columbia Plains District

Boundary Lake Area

Husky holds a 50% working interest in the Boundary Lake Gas Unit and a 34% and 19% interest in the Boundary Lake oil unit 1 and 2,
respectively, in north-east British Columbia. Husky natural gas production from this area is derived from five Belloy sour gas pools, and is processed at the nearby Boundary Lake processing plant. Husky gross production from this area was 7.5
mmcf/day of natural gas and 1,362 bbls/day of crude oil and NGL during 2008.

Valhalla and Wapiti Area

Husky holds an approximate 30% interest in three Valhalla oil units, a 100% interest in the Valhalla non-unit waterflood wells and a 100% interest in the
Wapiti property. Production is primarily from the Doe Creek and Cardium zones and consists of light crude oil, NGL and natural gas. Husky gross production from these properties averaged 2,608 bbls/day of crude oil and NGL and 7.1 mmcf/day of natural
gas in 2008. The Companys plans for this area in 2009 are to continue optimizing Huskys Valhalla assets to improve waterflood conformance and arrest declining production in the main Doe Creek I pool.

Kakwa Area

Husky holds an average 60% working
interest in oil and gas processing facilities and associated oil and gas gathering systems in the Kakwa area. Husky gross production from this area was 10.8 mmcf/day of natural gas and 486 bbls/day of crude oil and NGL in 2008.

Lynx, Copton and Grande Cache Areas

Husky
plans to continue to focus on development in the Lynx/Copton/Grande Cache areas of western Alberta with the drilling of 1.5 net wells and tie-in of 2.5 net wells in 2008. During 2008, Husky average gross production was 18.8 mmcf/day of natural gas.
The Company plans to continue to develop these properties in 2009 to increase gross production to 25 mmcf/day of natural gas.

Foothills West District

Caroline Area

Husky holds
an 11% working interest in the 32,000 acre Caroline natural gas field located approximately 97 kilometres north-west of Calgary. The field has a high proportion of NGL and as a result the economics of this field are enhanced.

Husky also holds an 11% interest in the Caroline sour gas processing facility. The plant is presently running at 62% utilization based on design capacity
and is processing approximately 93 mmcf/day of total plant sales gas and 15,575 mbbls/day of NGL. Husky gross production was 1,748 bbls/day of NGL and 4.5 mmcf/day of natural gas in 2008. In 2008, the newly installed low pressure steam recovery unit
was started up to displace approximately one third of the plants external power consumption.



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Edson Area

Husky holds and operates an average 85% working interest in two gas processing facilities and associated gas gathering systems in the Edson area. Huskys gross production from these properties averaged 39.4
mmcf/day of natural gas and 1,627 bbls/day of NGL in 2008. The 2008 development drilling program consisted of 30 gross wells. In 2008, Husky installed 4,100 horsepower of additional field and plant inlet booster compressors at Ansell and Galloway to
reduce the gathering system pressure and improve overall field recovery. The Company plans to drill 5 gross gas wells in 2009 to maintain average production at 38 mmcf/day and improve drainage of the reservoir.

Sikanni and Federal Areas

Husky holds
interests in properties in the Sikanni and Federal areas of north-east British Columbia, which averaged gross production of 14.9 mmcf/day of natural gas from six wells in 2008. Husky natural gas production flows through its gathering systems for
processing at third party plants at Sikanni and McMahon. In March 2008, Husky completed the tie-in of a discovery well in the Federal area, which added 10.5 mmcf/day of additional production, commencing April 2008.

Graham Area

Husky holds a 40% working
interest in lands in the Graham area of northeastern British Columbia. Husky gross production from this area in 2008 averaged 5.0 mmcf/day of natural gas. Production from the property is from one Halfway and seven Baldonnel pools. Husky also holds
an interest in two 1,500 horsepower compressor stations and the non-operated Cypress gas plant. Plant capacity is 45 mmcf/day and the plant is currently operating at 57% capacity. The Company holds a 33.2% interest in the gas treating unit, 28.2%
interest in the amine unit and 28% interest in the sulphur unit.

Grizzly Valley and Bullmoose Area

Husky holds a 33-50% working interest in four wells in this new exploration area. Husky and a partner in the area have agreed to terms with a custom
processor to construct a gathering system into the Grizzly Valley to transport production into Alberta for processing. The gathering system is expected to be completed by the middle of 2010. Huskys total capacity in the system will be 30
mmcf/day. Husky is currently flowing natural gas production though interruptible capacity in the Duke system and averaged 7.2 mmcf/day of gross natural gas production from this area in 2008. The Company plans to drill and complete 1.5 net wells in
2009 to establish sufficient deliverability to meet its capacity commitment in 2010.

East Central Alberta

Red Deer and Hussar Districts

The core of the
Red Deer and Hussar districts is located between Calgary, Drumheller and Sylvan Lake. Husky operates 21 facilities with gas gathering systems in these districts. Husky gross production from this area averaged 76.2 mmcf/day of natural gas and 2.4
mmbbls/day of crude oil and NGL in 2008. Husky intends to continue to develop the natural gas potential of these districts with infill, step out and exploratory wells to optimize gas recovery and develop new pools in order to operate the facilities
at capacity. The Company is involved in coal bed methane development in this district. During 2008, 126 gross coal bed methane wells were drilled, to total 636 gross wells at year end. There were 546 producing coal bed methane wells at year-end that
were producing a total of 56 mmcf/day (27 mmcf/day Huskys share) of natural gas. Huskys development plan for 2009 has been significantly reduced due to lower returns in the current price environment. Husky plans to drill approximately 40
wells in an undeveloped area, and expects to hold Husky gross production at approximately 25 mmcf/day of natural gas from coal bed methane.



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Provost District

The centre of the Provost district is approximately 240 kilometres south-east of Edmonton. It is predominantly a medium crude oil area that averaged gross production of 14.1 mbbls/day of crude oil and 21.6 mmcf/day of
natural gas in 2008. Husky intends to increase efforts to reduce operating costs and improve oil recovery. There is significant competition in the area for land as well as infrastructure. Husky has a large land position and maintains close to a 100%
working interest in most of its facilities. In 2009, Husky intends to continue to develop several 2005 to 2007 natural gas and oil discoveries.

Athabasca District

The Athabasca district extends approximately 175 kilometres north of Edmonton, and from the
Alberta-Saskatchewan border in the east, to the Alberta foothills in the west. The area target is predominantly shallow gas, ranging from 450-900 metres in the multi-zone Palaeozoic Mannville formation. The main producing areas are Athabasca,
Craigend and Cold Lake. Husky operates 32 facilities with a pipeline system and an average working interest of 90% in the producing wells. Husky intends to continue developing this area with infill, step out and exploratory wells to optimize
recovery and develop new pools at a reduced pace from past years in light of the current market conditions. Husky gross production from this area averaged 40.7 mmcf/day of natural gas and 495 bbls/day of crude oil in 2008.

Southern Alberta and Southern Saskatchewan

Southern
Saskatchewan District

Husky is a prominent operator in southern Saskatchewan primarily producing medium gravity crude oil, with
some natural gas and light crude oil. Husky gross production from properties in this district averaged 22.9 mbbls/day of crude oil and 60.8 mmcf/day of natural gas during 2008.

Husky operates 32 oil batteries and 8 gas facilities in the southern Saskatchewan district. The oil pools in this area are exploited using pressure
maintenance and waterflood recovery operations.

At the Shackleton/Lacadena Milk River shallow gas project, 127 wells were drilled and 87
were tied-in in 2008. The remaining 40 wells will be tied-in in Q1/09. The project was producing at a rate of 31.4 mmcf/day of natural gas at December 31, 2008 from a total of 627 wells.

At Gull Lake North an alkaline surfactant polymer flood (ASP) is under construction. The first phase of drilling was completed in 2008 (27
wells), and the facility was approximately 60% complete at December 31, 2008. Project completion is expected by June, 2009.

Southern Alberta
District

Taber and Brooks are Huskys two major centres in southern Alberta. Husky operates 28 oil facilities and 3 natural
gas facilities with an average working interest of 95%. Oil production is mainly medium gravity crude with the majority of reserves being supported by waterfloods or active aquifers. Natural gas production is from a mixture of deep and shallow
formations. At Warner, near Taber, Husky operates a recently implemented alkaline-polymer flood to increase recovery from the Cretaceous Mannville reservoir and Husky implemented an additional ASP flood at Crowsnest in 2008. Husky gross production
from this district averaged 8.3 mbbls/day of crude oil and 23.5 mmcf/day of natural gas during 2008.



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Oil Sands

Athabasca, Cold Lake and Peace River

Husky currently holds interests in 779,267 acres in the bitumen prone areas of
Athabasca, Cold Lake and Peace River.

Tucker

At Tucker, an in-situ SAGD oil sands project located 30 kilometres northwest of Cold Lake, Alberta, production commenced at the end of 2006. Production from the initial 32 well pairs was slow to ramp-up as
anticipated, largely due to the position of some wells relative to the water saturation zone of the reservoir. At the end of 2007, eight new well pairs had been completed. Optimization strategies were conducted through 2008 on existing well pads and
the eight new well pairs on Pad C resulting in encouraging production response. Production during December 2008 averaged 4.8 mbbls/day. Drilling of eight new well pairs on Pad D has been deferred pending improved market conditions.

Sunrise

During the fourth quarter of 2007,
agreement, in principle, was reached with BP to create an integrated North American oil sands business consisting of upstream and downstream assets based on Huskys Sunrise holdings and BPs Toledo, Ohio, USA Refinery. The business
consists of a 50/50 partnership to develop the Sunrise oil sands project contributed and operated by Husky and a 50/50 limited liability company for the Toledo Refinery contributed and operated by BP. Details of the agreement were finalized in the
first quarter of 2008.

The front-end engineering design (FEED) continues to progress for the Sunrise in-situ SAGD oil sands
project, located in the Athabasca region of northern Alberta. Site preparation, including clearing of development areas at the central plant site and five well pads is nearly complete. Detailed engineering is expected to begin mid 2010.

The Sunrise Project was approved by the Energy Resources Conservation Board (ERCB) in December, 2005. An amendment application was
submitted in March of 2007, which outlines changes and optimizations resulting from ongoing depletion planning and front-end engineering design. Amendment approvals from the ERCB were received in December 2008 and approval from Alberta Environment
is expected by the end of the first quarter of 2009. Collaboration with various industry participants on regional infrastructure issues, including an access road and aerodrome, is underway. Bitumen production is expected to commence approximately
four years following project sanction and is currently planned to increase to 200 mbbls/day. The project is currently in an optimization phase to simplify the projects scope and take advantage of the recent downturn in the demand for goods and
services. Subject to regulatory and government approval, the partners will review the project sanction decision in 2009 for formal approval in mid 2010. The development of this project is strategically linked to the repositioning project at the
BP-Husky Toledo Refinery.

Saleski/Caribou/McMullen

At Saleski, Husky acquired oil sands leases totalling 16,640 acres in 2008. Husky now holds 258,400 acres in this area, which is located approximately 120 kilometres west of Fort McMurray, Alberta. Husky drilled seven
vertical and one horizontal stratigraphic test wells during the 2007/2008 winter drilling season. In addition, development planning continued regarding water source and disposal wells and the appropriate bitumen recovery technique for Saleski.

At Caribou, Husky completed the drilling of five stratigraphic test wells and tested one water source well and one water injection well
during the 2008/2009 winter drilling season.



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At McMullen, we acquired 108,800 acres of oil sands leases in January 2008. Husky has identified and
prioritized an area for a potential thermal pilot development, drilled 22 stratigraphic test wells, three water source wells, initiated an 8,400 acre 3-D seismic program, and completed the front-end engineering and design for a small scale thermal
pilot. In December 2008, a joint application was submitted by Husky to both the ERCB and Alberta Environment for the construction and operation of a 500 bbl/day thermal pilot project. In addition, the development of a long term strategy for this
asset is progressing.

Oil Sands Leases



|                                          |  |               |  |            |  |          |  |              
|----------------------------------------- |  | ------------- |  | ---------- |  | -------- |  | -------------
|General Location Name                     |  | Oil SandsArea |  | GrossAcres |  | NetAcres |  | HuskyOperator
|South Athabasca  overriding royalty      |  | Athabasca     |  | 35,601     |  |         |  | No           
|South Athabasca                           |  | Athabasca     |  | 22,672     |  | 11,656   |  | Yes          
|Sunrise  In situ(1)                      |  | Athabasca     |  | 64,034     |  | 64,034   |  | Yes          
|South Sunrise                             |  | Athabasca     |  | 40,320     |  | 40,320   |  | Yes          
|Misthae (Drowned, Martin Hills W. & Spur) |  | Athabasca     |  | 28,160     |  | 28,160   |  | Yes          
|Misthae (McMullen)                        |  | Athabasca     |  | 108,800    |  | 108,800  |  | Yes          
|Saleski                                   |  | Athabasca     |  | 258,400    |  | 258,400  |  | Yes          
|Hoole  overriding royalty                |  | Athabasca     |  | 47,040     |  |         |  | No           
|Beaverdam                                 |  | Cold Lake     |  | 11,520     |  | 11,520   |  | Yes          
|Caribou(2)                                |  | Cold Lake     |  | 35,840     |  | 35,840   |  | Yes          
|Lobstick                                  |  | Cold Lake     |  | 37,120     |  | 37,120   |  | Yes          
|Tucker                                    |  | Cold Lake     |  | 10,080     |  | 10,080   |  | Yes          
|Panny (Senex & Welstead)                  |  | Peace River   |  | 50,560     |  | 50,560   |  | Yes          
|Peace River (Cadotte Lake)                |  | Peace River   |  | 11,840     |  | 11,840   |  | Yes          
|Sawn Lake (Loon)                          |  | Peace River   |  | 17,280     |  | 17,280   |  | Yes          
|                                          |  |               |  |            |  |          |  |              
|                                          |  |               |  | 779,267    |  | 685,610  |  |              
|                                          |  |               |  |            |  |          |  |              



Notes:



|(1) | Included in the gross and net amounts are an additional 6,400 acres of petroleum and natural gas rights held as protection acreage for gas over bitumen issues. In 2003, the Alberta
regulatory authority issued General Bulletin GB 2003-28 that required natural gas wells within certain bitumen prone areas to be shut-in. The production of natural gas where natural gas reservoirs were believed to be in pressure contact with bitumen
reserves was deemed to present an unacceptable risk to future in-situ bitumen production. Sunrise was formerly named Kearl.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | Husky also has the exclusive right to acquire an additional 65,280 acres in the Caribou area.
|--- | ---------------------------------------------------------------------------------------------



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Northwest Territories

In the Northwest Territories Husky has a focused land position in the Central Mackenzie Valley consisting of EL 397, EL 423, EL 441 and EL 443. In addition, the Company has interests in several freehold blocks. During
2008, Husky was granted SDLs for the Summit Creek B-44 and Stewart D-57 discoveries. Two exploration wells were drilled in the first half of 2008 on EL 423. Both wells were abandoned without testing. No activity is planned for 2009. Husky holds a
75% working interest in this play.

Offshore East Coast  Canada

Huskys offshore East Coast exploration and development program is focused in the Jeanne dArc Basin offshore Newfoundland and Labrador, which contains the Hibernia, Terra Nova and White Rose oil fields.
Husky is the operator of the White Rose oil field and satellite tiebacks and holds a working interest in Terra Nova as well as in a number of smaller undeveloped fields in the central part of the basin. Husky also holds significant exploration
acreage including five SDLs on the Labrador shelf.

White Rose Oil Field

The White Rose oil field is located 354 kilometres off the coast of Newfoundland, approximately 48 kilometres east of the Hibernia oil field, on the
eastern rim of the North American continental shelf. Huskys interest in the core White Rose oil field development is 72.5%. Husky is also the operator of the White Rose satellite tiebacks, which include North Amethyst, West White Rose and the
South White Rose Extension, with a 68.875% working interest.

White Rose was the third oil field developed offshore Newfoundland and
Labrador, achieving first production on November 12, 2005. During 2008, development drilling included an eighth production well, as well as one water injector and one gas injector. Husky transports White Rose crude oil to market with three
chartered shuttle tankers.

During 2008, work progressed on formal subordinate agreements to the Framework Agreement signed during 2007
with the Government of Newfoundland and Labrador on fiscal terms for the White Rose satellite oil fields. Under the terms of the agreements, the provinces energy corporation, Nalcor Energy has purchased a 5% equity interest in the
White Rose growth lands, which include identified pools at North Amethyst, South White Rose Extension and West White Rose. The purchase price is subject to adjustment based on subsequent reserves determination. Husky intends to develop the growth
lands through a series of subsea tiebacks to the SeaRose FPSO. Husky will remain the project operator, and will retain a 68.875% working interest in the growth lands. The existing partnership and fiscal terms for the White Rose core field are
unchanged. The fiscal terms for the satellite tiebacks also provide for a 6.5% Tier 3 super royalty to be paid after Tier 2 payout has been achieved and when oil is above WTI U.S. $50/bbl.

Delineation wells were completed at both the North Amethyst and West White Rose satellite fields in the fourth quarter of 2008, the results of which
continue to be assessed.

Progress continues on the first White Rose satellite tie-back at North Amethyst. Necessary government, corporate
and regulatory approvals for the expansion were received during 2008 and Temporary Guide Bases were placed in protective glory holes in August 2008. Systems integration testing will take place in spring 2009, with subsea equipment and flow lines to
be installed and tied back to the SeaRose FPSOproduction vessel in summer 2009. The overall project is on schedule for first oil in late 2009 / early 2010.

At West White Rose, Husky continues to evaluate results of the latest test well, with a view towards optimizing reservoir depletion. The Company anticipates filing relevant development applications with the regulator
during 2009.



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Husky has and will continue to consider technical options for the development of natural gas in the
Jeanne dArc Basin and intends to proceed with technical screening of a short list of proposed solutions and review of high level cost estimates. In parallel and pending rig availability, exploration and delineation drilling will improve
estimates of the resource base ahead of future development.

Terra Nova Oil Field

The Terra Nova oil field is located approximately 350 kilometres south-east of St. Johns, Newfoundland and Labrador 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. Huskys current pooled interest in the Terra Nova field is 12.51%. This interest is subject to change, pending the completion
of a re-determination process which commenced in 2008 and is expected to be finalized before the end of 2010. Production at Terra Nova commenced in January 2002. Huskys gross share of production in 2008 from the Terra Nova field was 4.8 mmbbls
or an average 12.9 mbbls/day.

As at December 31, 2008, there were 14 development wells drilled in the Graben area, 8 production
wells, three water injection wells and 3 gas injection wells. In the East Flank area there were eleven development wells including six production wells and five water injection wells. There is one extended reach producer and an extended reach water
injection well in the Far East Central area. Terra Nova completed the latest phase of the development drilling program in August 2007. Drilling operations are expected to resume for approximately 6 months in 2009.

East Coast Exploration

Husky believes that
the areas offshore Canadas East Coast possess high impact exploration potential and its lands will provide growth opportunities in the medium to long-term. Husky presently holds working interests ranging from 5.33% to 73.125% in 16 SDLs in the
Jeanne dArc Basin. Husky also holds interests ranging from 17.1% to 42.0% in six SDLs on the Labrador Shelf, a region that could be significant, in the long-term, for natural gas reserves.

As of December 31, 2008, Husky held a working interest in 17 ELs on the East Coast of Canada: 10 in the Jeanne dArc Basin, two in the Flemish
Pass basin, two in the Central Ridge Complex, one in the Sydney basin and two in Labrador totalling 15,360 square kilometres (3.8 million acres).

In the Jeanne dArc basin, Husky joined with PetroCanada and StatoilHydro in a rig sharing agreement that resulted in the return of the Henry Goodrich rig to the Grand Banks region. Husky participated in its largest offshore seismic
acquisition program to date, covering 2,150 square kilometres including the Terra Nova and White Rose areas and portions of ELs, 1090, 1091, 1099, 1100 and 1101. Husky continues to evaluate drilling opportunities in the context of its full portfolio
of East Coast land holdings.

Husky farmed into StatoilHydros EL1049 in the Flemish Pass basin and is participating in the drilling
of the deep-water exploration well Mizzen O-16 (Husky 35% interest). At the 2008 land sale, Husky acquired one new exploration licenses located in the Flemish Pass.

On the Labrador Shelf, Husky is operator of the Hekja (Husky 42% interest) and Hopedale (Husky 19.4% interest) natural gas discoveries. In 2008, the Canada Newfoundland and Labrador Offshore Petroleum Board awarded
four ELs on the Labrador Shelf marking the return of the oil industry to this long dormant area. Husky acquired two ELs at the 2008 land sale. Huskys extensive grid of 2-D seismic over of the Labrador Shelf was used to evaluate the blocks. A
3D seismic program and additional 2D seismic acquisition are planned for 2010.



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East Coast

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International

Huskys international exploration and development programs are currently located in Southeast Asia and Greenland. In China, the Company has a 40% interest in one offshore oil producing operation at Wenchang and a 100% interest in six
exploration blocks in the South China Sea and one in the East China Sea. In Indonesia, the Company has a 50% interest in the Madura Strait block production sharing contract (PSC), 100% interest in the North Sumbawa II exploration block
and a 100% interest in the Bawean II exploration block.

LOGO

China

South
China Sea

Wenchang

The
Wenchang oil field is located in the western Pearl River Mouth Basin, approximately 400 kilometres south of Hong Kong and 100 kilometres east of Hainan Island. Husky holds a 40% working interest in the oil fields, which commenced production in July
2002. The Wenchang 13-1 and 13-2 oil fields are producing from 29 wells in 100 metres of water into a floating production, storage and offloading vessel stationed between fixed platforms located in the fields. The blended crude oil from the two
fields averages approximately 35° API, similar to the benchmark Minas blend. At December 31, 2008, Husky gross proved reserves at Wenchang were 7.2 mmbbls of crude oil and NGL. Husky gross production averaged 12.0 mbbls/day during 2008.



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Block 39/05

Husky executed a PSC with CNOOC for the 39/05 exploration block surrounding the Wenchang fields on October 1, 2001. CNOOC has the right to participate in development of any discoveries up to a 51% working interest. In January 2003, the
Qionghai 18-1-3 exploration type stratigraphic well on the block was plugged and abandoned without testing and in February 2003, the Wenchang 8-1-1 exploration type stratigraphic well was plugged and abandoned without testing. Husky relinquished 25%
of Block 39/05 in 2004, 25% in 2006, and in 2008 the remainder of the block with the exception of a 14,159 acre area (57.3 sq. km.) around Prospect QH29-2. Husky is currently in Phase III, the final exploration phase of the PSC expiring
March 31, 2009. In accordance with the contract, the Company committed to drilling a third exploration well, which spud on January 22, 2009.

Block 29/26

Husky executed a PSC with CNOOC for the 29/26 exploration block on October 1, 2004. The block is located
in the South China Sea approximately 300 kilometres south-east of Hong Kong and 65 kilometres south-east of the Panyu gas discovery. The block covers an area of approximately 734,777 acres (2,973.6 sq. kms), after the 25% relinquishment at the end
of Phase I in 2007. CNOOC has the right to participate in the development of any discoveries up to a 51% working interest. Husky completed a drilling program in 2006, with the drilling of the Liwan 3-1-1 natural gas discovery. The well location was
chosen based on 2-D seismic data and drilled to a total depth of 3,843 metres on a large structure with 14,826 acres of closure and encountered 56 metres of net natural gas pay on logs over four zones. This well was drilled in water 1,500 metres
deep. In August 2006, Husky shot a 98,842 acre (400 sq. kms) seismic survey over Liwan 3-1-1 and the adjacent structures. In January 2007, the Company signed a 3 year contract with Seadrill Offshore AS for the deep water semi-submersible drilling
rig, West Hercules. In preparation for the West Hercules, delineation drilling and further exploration drilling, the Company signed a contract with China Offshore Seismic Limited for the acquisition of 646,180 acres (2,615 sq. kms) of
3-D seismic data in 2007. The seismic program was commenced in 2007 and completed in the second quarter of 2008. The West Herculesarrived on location at Liwan on November 4, 2008 and spud the first appraisal well on November 20,
2008. The rig will drill a four well delineation program. Husky also plans to conduct further exploration drilling on the block. In order to further accelerate the Liwan 3-1 development, a number of preliminary engineering studies were completed in
late 2007 to conceptualize facilities options covering a range of potential production scenarios. These engineering studies included field development options, topsides facilities and preliminary pipeline routing. Husky also completed a desktop
metocean study and awarded a contract for the field acquisition of new proprietary metocean data, which commenced in early 2008 and will take approximately two years.

Block 29/06

Husky executed a PSC with CNOOC for the 29/06 exploration block on October 1, 2006.
The block is located in the South China Sea immediately east and adjacent to block 29/26. The block is more than twice the size of Block 29/26, covering an area of approximately 2,289,382 acres (9,265 sq. kms). CNOOC has the right to participate in
development of any discoveries up to a 51% working interest. In the first exploration phase, Husky is committed to acquiring seismic and drilling two exploration wells within three years. Husky acquired 179,148 acres (725 sq. kms) of 3-D seismic in
the second quarter of 2008 and is currently evaluating this data to identify potential drilling locations.

Block 35/18 and 50/14

Husky executed two PSCs with CNOOC for the 35/18 and 50/14 exploration blocks on October 1, 2006. Both contract areas are located in shallow water in
the South China Sea immediately west of Hainan Island adjacent to the Dong Fang and Ledong gas fields. The 35/18 block is approximately 1,104,290 acres (4,469 sq. kms) and the Block 50/14 is 775,153 acres (3,137 sq. kms). The work program
requires a single exploration well on each block within three years. Husky has exceeded the requirement for seismic work in acquiring 185,325 acres (750 sq. kms) of 3-D seismic on Block 35/18 in 2008. CNOOC has the right to participate in
development of any discoveries up to a 51% working interest.



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Block 63/05

Husky executed a PSC with CNOOC for the 63/05 exploration block on June 25, 2008. The block is located in the South China Sea approximately 100 kilometres south of Hainan Island and covers an area of approximately 439,100 acres (1,777
sq. kms). The 63/05 block is located in the Qiongdongnan Basin in water depth of less than 120 metres. Existing seismic data is currently being interpreted and Husky plans to acquire new seismic data in early 2010. CNOOC has the right to participate
in development of any discoveries up to a 51% working interest.

East China Sea

Block 04/35

Husky executed a PSC with CNOOC for the 04/35 exploration block on December 1,
2003. The block is located in the East China Sea approximately 350 kilometres east of the city of Shanghai and covers an area of approximately 979,771 acres (3,965 sq. kms). The PSC requires the drilling of a single exploration well in the first
exploration phase to a depth of 2,500 metres and a minimum work commitment of U.S. $3 million. Technical evaluations of the hydrocarbon potential are complete and Husky expects to fulfill its Phase I drilling commitment subject to drilling rig
logistics. CNOOC has the right to participate in development of any discoveries up to a 51% working interest.

Indonesia

East Bawean II, Indonesia

Husky executed a PSC
in September, 2006 with the Government of Indonesia for the East Bawean II block. The 1,051,433 acres (4,255 sq. kms) are located in the North East Java Basin approximately 200 kilometres north of the Madura Strait PSC where the Company is in the
early development phase of the BD gas field. The PSC requires the acquisition of 3-D seismic with a commitment of U.S. $7 million, and the drilling of two exploration wells with a commitment of U.S. $16 million, within the first three years of the
contract. The acquisition of the 348,270-acre (1,410 sq kms) 3-D program was completed in December, 2007 and data processing was completed in May, 2008. The Company has secured a jack-up drilling rig to drill two exploration wells which are planned
for mid 2009.

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North Sumbawa II, Indonesia

Husky executed a PSC in November, 2008 with the Government of Indonesia for the North Sumbawa II block. The block covers an area of 1,249,831 acres (5,058 sq kms) and is located in the East Java Basin approximately
300 km east of Madura Strait PSC. The acquisition of this block increases Husky total area in Indonesia to 2,991,886 acres (12,108 sq kms). The PSC requires the acquisition of 2D seismic with a commitment of U.S. $2 million, and the drilling of one
exploration well with a commitment of U.S. $10 million within the first three years of contract.

Madura Strait, Indonesia

Husky has a 50% interest in approximately 690,412 acres (2,794 sq. kms) of the Madura Strait block, located offshore East Java south of Madura Island,
Indonesia. There are two discovered natural gas fields on the block. The larger of these is the Madura BD field, which was granted commercial status and had a plan of development approved by the Indonesian state oil company in 1995. The field was to
supply natural gas to a new 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. Current market
conditions are favourable for the BD development and Husky expects to proceed with plans to supply gas to meet the demand of the East Java region. Husky has gas sales contracts signed with three gas buyers. The updated development plan was approved
by the Government of Indonesia and negotiations with the Government of Indonesia to obtain an extension to the PSC are ongoing. Husky expects to conclude these arrangements in 2009 and commence the front-end engineering design for the BD field
development. Production is expected to come on stream approximately three to four years after all agreements have been approved by the Government of Indonesia.

LOGO



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United States

Columbia River Basin (Washington State  USA)

In September 2008, Husky acquired approximately 422,000 net acres
of undeveloped land in the Columbia River Basin located in the states of Washington and Oregon, for U.S. $42 million. Husky is also participating at a 50% working interest in the drilling of an exploration well at Gray 31-23. Although currently in a
non-operating position, the agreement with the operating partner allows Husky to assume operatorship in the future if Husky chooses to do so. This under explored basin is characterized by gas saturated tertiary sandstones that lie below a layer of
volcanic basalt. The potential exists for modern completion techniques to unlock a large gas resource that is located in an area containing existing sales gas pipelines that transport gas to the states of Washington, Oregon and California.

Greenland

Husky holds three
ELs totalling 35,000 square kilometres offshore the west coast of Disko Island, Greenland. During 2008, Husky acquired 7,000 kilometres of 2D seismic over Husky operated Blocks 5 and 7 (HOOL 87.5% working interest). In addition, Esso Greenland
acquired 3,000 kilometres of 2D seismic over the jointly held Block 6 license (HOOL 43.75% working interest). The aerogravity and magnetic survey over Blocks 5 and 6 was also completed in 2008. The survey on Block 7 will resume in the first half of
2009. Environmental impact studies were initiated for all three licenses in 2008. A 1,000 square kilometre 3D seismic survey on Block 7 is planned for 2009.

Shatirah, Libya

The Company has a non-operated interest in a small crude oil production operation in the Shatirah
field, onshore Libya.

Distribution of Oil and Gas Production

Crude Oil and NGLs

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 equal to approximately 75% of Huskys heavy
crude oil production from the Lloydminster area. Husky also 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. Natural gas liquids are sold to local petrochemical end users, retail and wholesale distributors and to refiners in North America.

Husky markets third party volumes of light crude oil, heavy crude oil and NGLs in addition to its own production.

Natural Gas

The following table shows the
distribution of Husky gross average daily natural gas production for the years indicated:



|                     |  |                          |  |      |  |     
|-------------------- |  | ------------------------ |  | ---- |  | ----
|                     |  | Years ended December 31,
|                     |  | 2008                     |  | 2007 |  | 2006
|                     |  | (mmcf/day)              
|Sales to end users   |  |                          |  |      |  |     
|United States        |  | 348                      |  | 338  |  | 335 
|Canada               |  | 201                      |  | 208  |  | 231 
|                     |  |                          |  |      |  |     
|                     |  | 549                      |  | 546  |  | 566 
|                     |  |                          |  |      |  |     
|Sales to aggregators |  | 19                       |  | 21   |  | 26  
|Internal use(1)      |  | 28                       |  | 56   |  | 80  
|                     |  |                          |  |      |  |     
|                     |  | 596                      |  | 623  |  | 672 
|                     |  |                          |  |      |  |     



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Note:



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

The Company also markets third party natural gas production in addition to its own production.

Delivery Commitments

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.



|     |  |             |  |              |  |    
|---- |  | ----------- |  | ------------ |  | ---
|     |  | Fixed Price |  | Market Price
|     |  | Bcf         |  | $/mmbtu      |  | Bcf
|2009 |  | 19          |  | 5.18         |  | 8  
|2010 |  | 19          |  | 5.46         |  | 1  
|2011 |  | 19          |  | 5.77         |  |   
|2012 |  | 19          |  | 6.05         |  |   
|2013 |  | 18          |  | 5.85         |  |   
|2014 |  | 10          |  | 3.84         |  |   

Midstream Operations

Overview

The midstream operations include:



| |  |  | Upgrading  the upgrading of heavy crude oil into synthetic light crude oil;
| | - |  | ----------------------------------------------------------------------------



| |  |  | Infrastructure  pipeline transportation and processing of heavy crude oil, storage of crude oil, diluent and natural gas, extraction of NGL from natural gas,
cogeneration of electrical and thermal energy; and
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Commodity Marketing  the purchase and marketing of Huskys and other producers crude oil, natural gas, NGLs, sulphur, petroleum coke and electrical
power.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------

Upgrading Operations

Husky owns and operates the Husky Lloydminster Upgrader (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.

Prior to the Upgrader, the market for heavy crude oil was either as feedstock for asphalt production or it was sold as blended
heavy crude oil for feedstock for specific refineries designed to process or upgrade heavier crude. The Upgrader was commissioned in 1992 with an original design capacity of 46 mbbls/day of synthetic crude oil. Actual production is considerably
higher than the original design rate capacity as a result of throughput modifications and improved reliability. In 2007, the Upgrader commenced production of off-road diesel for locomotive and other uses. The Upgraders current rated production
capacity is 82 mbbls/day of synthetic crude oil, diluent and off-road diesel. Production at the Upgrader averaged 57.5 mbbls/day of synthetic crude oil, 10.4 mbbls/day of diluent and 3.2 mbbls/day of low sulphur diesel in 2008. In addition, the
Upgrader also produced, as by-products of its upgrading operations, approximately 317 lt/day of sulphur and 341 lt/day of petroleum coke during 2008. These products are sold in local and international markets.



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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 approximately 2,000 kilometres of
pipeline and are capable of transporting in excess of 720 mbbls/day of blended heavy crude oil, diluent and synthetic crude oil. The pipeline systems transport blended heavy crude oil to Lloydminster, accessing markets through the Upgrader and
asphalt refinery in Lloydminster. Blended heavy crude oil from the field and synthetic crude oil from the upgrading operations are moved south to Hardisty, Alberta to a connection with the Enbridge Pipeline, the Kinder Morgan Express Pipeline and
the Inter Pipeline Fund systems. The 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 Cold Lake Pipeline, the Echo Pipeline, the
Gibsons Terminal, the Enbridge Athabasca Pipeline and the Talisman Chauvin Pipeline.

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



|                             |  |                          |  |             |  |     
|---------------------------- |  | ------------------------ |  | ----------- |  | ----
|                             |  | Years ended December 31,
|                             |  | 2008                     |  | 2007        |  | 2006
|                             |  |                          |  | (mbbls/day) |  |     
|Combined pipeline throughput |  | 507                      |  | 501         |  | 475 

In recent years Husky has expanded and expects to further expand its heavy crude pipeline systems
to capitalize on anticipated increases in heavy oil production from the Lloydminster and Cold Lake areas.

Husky considers the expansion
and optimization of its pipeline systems in the Lloydminster area to be necessary to further its own development objectives in the area. As a result of ongoing expansion of the mainline pipeline systems in the area, competition for throughput
volumes has increased.

Husky operates 16 heavy crude oil processing facilities located throughout the Lloydminster area. These facilities
process Huskys and other producers raw heavy crude oil from the field by removing sand, water and other impurities to produce clean dry heavy crude oil. The heavy crude oil is then blended with a diluent to lower both viscosity and
density in order to meet pipeline specifications for transportation.



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Cogeneration

Husky has a 50% interest in a 215 MW natural gas fired cogeneration facility at the site of the Lloydminster Upgrader. This cogeneration plant was commissioned in December 1999. Electricity produced at the facility is being sold to
Saskatchewan Power Corporation under a 25 year power purchase agreement effective in 1999. Thermal energy (steam) is sold to the Upgrader.

Husky also has a 50% interest in a 90 MW natural gas fired cogeneration facility adjacent to Huskys Rainbow Lake processing plant. The cogeneration plant produces electricity for the Alberta Power Pool and thermal energy (steam) for
the Rainbow Lake processing plant. It provides power directly to the Alberta Power Pool under an agreement with the Alberta Transmission Administrator to provide additional electricity generating capacity and system stability for northwestern
Alberta. The power plant has the capability of being expanded to approximately 110 MW in total. Husky is the operator of the facility.

Natural Gas
Storage Facilities

Husky has been operating a natural gas storage facility at Hussar, Alberta since April 2000. The facility has a
working storage capacity of 17 bcf of natural gas. Husky also operates and has a 50% interest in a 6 bcf natural gas storage facility at East Cantuar near Swift Current, Saskatchewan. The Company is continuing to evaluate additional storage
opportunities within Western Canada.

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.

Husky supplies feedstock to its 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 its refinery at Prince George, British Columbia. Husky markets the synthetic crude oil produced at the Husky Upgrader in Lloydminster to
refiners in Canada and the United States.

Husky markets natural gas sourced from its own production and third party production. The
Company is currently committed to gas sales contracts with third parties, which in aggregate do not exceed amounts forecast to be deliverable from Husky reserves. Huskys contracts are with customers located in eastern Canada/northeastern
United States (34%), midwestern United States (29%), Western Canada (35%) and northwestern United States (2%). The natural gas sales contracted are primarily at market prices (91%). At December 31, 2005, Huskys natural gas sales
contracts totalled 158 bcf over eight years. The natural gas is deliverable at the rate of 27% of the total 115 bcf over six years. The natural gas is deliverable at the rate of 24% in 2009, 17% in 2010, 17% in 2011, 17% in 2012, 17% in 2013 and 8%
in 2014. Husky has acquired rights to firm pipeline capacity to transport the natural gas to most of these markets. The Company manages and trades natural gas in conjunction with Husky owned and operated natural gas storage facilities. Husky also
contracts additional natural gas storage under long-term arrangements. At December 31, 2008, Husky managed natural gas storage capacity of 37 bcf.

Husky has developed its commodity marketing operations to include the acquisition of third party volumes in order to increase volumes and enhance the value of its midstream assets. The Company plans to expand its



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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. At December 31, 2008, Husky estimated commitments of approximately $467 million in natural gas purchases, 95% of which is to be purchased in 2009. At December 31, 2008, the
Company did not have any long-term commitments to purchase crude oil. Huskys purchases of crude oil primarily involve 30 day evergreen arrangements.

Downstream Operations

Canada

Overview

Huskys Canadian refined products operations include refining of light crude
oil, manufacturing of fuel and industrial grade ethanol, manufacturing of asphalt products from heavy crude oil, acquisition by purchase and exchange of refined petroleum products. Huskys retail network provides a platform for substantial
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 and are marketed directly or through Huskys eight emulsion plants, four of which are also asphalt terminals located throughout Western Canada.

Branded Petroleum Product Outlets and Commercial Distribution

As of December 31, 2008, there were 492 independently operated Husky and Mohawk branded petroleum product outlets. These petroleum product outlets include service stations, travel centres 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 24 hours per day, 365 days a year 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
will electronically process transactions and provide detailed billing, sales tax and other information. A variety of full and self serve retail locations under the Mohawk and Husky brand names serve urban and rural markets, while Husky and Mohawk
bulk distributors offer direct sales to commercial and farm markets in Western Canada.

Huskys strategy in respect of its petroleum
product outlets includes continuing to increase profits and sales through the strategic location of new outlets, the enhancement of ancillary non-fuel income streams, the modernization, automation and upgrading of existing petroleum product outlets,
expanding customer loyalty programs and the sale of non-core locations. Husky also plans to enter into strategic alliances with third parties to sell various consumer products at Husky and Mohawk branded petroleum outlets in order to generate
revenue and increase demand for other products and services provided at those outlets. The Company is pursuing acquisitions and joint venture opportunities to further enhance its existing distribution network.



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LOGO

Independent retailers or agents operate all Husky and Mohawk branded petroleum product outlets. Branded outlets
feature varying services such as 24 hour service, convenience stores, service bays, car washes, Husky House full service family style restaurants, proprietary and co-branded quick serve restaurants, bank machines and alternate fuels such as propane
and compressed natural gas. In addition to conventional gasolines, ethanol blended fuels branded as Mother Natures Fuel and additive enhanced Diesel Max are offered in all markets together with Chevron lubricants. Husky
supplies refined petroleum products to its branded independent retailers on an exclusive basis and provides financial and other assistance for location improvements, marketing support and related services. Huskys brands are promoted through
the Husky Snowstars Program, various national and university athletic sponsorships as well as advertising designed to reach both national and regional audiences.



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The following table shows the number of Husky and Mohawk branded petroleum outlets by class of trade and
by province as of December 31, 2008:



|                                     |  |                       |  |         |  |       |  |          |  |         |  |           |  |          
|------------------------------------ |  | --------------------- |  | ------- |  | ----- |  | -------- |  | ------- |  | --------- |  | ---------
|                                     |  | BritishColumbia&Yukon |  | Alberta |  | Sask. |  | Manitoba |  | Ontario |  | 2008Total |  | 2007Total
|Retail Owned Outlets                 |  |                       |  |         |  |       |  |          |  |         |  |           |  |          
|Travel Centres                       |  | 10                    |  | 10      |  | 4     |  | 2        |  | 12      |  | 38        |  | 36       
|Full Serve                           |  | 9                     |  | 12      |  | 1     |  | 3        |  | 3       |  | 28        |  | 28       
|Full/Self Serve                      |  | 19                    |  | 15      |  | 6     |  | 10       |  | 3       |  | 53        |  | 59       
|Self Serve                           |  | 17                    |  | 27      |  | 1     |  |         |  | 2       |  | 47        |  | 41       
|Bulk Distributor                     |  | 1                     |  | 9       |  | 2     |  | 1        |  |        |  | 13        |  | 15       
|Other Service Facilities Distributor |  | 3                     |  | 7       |  |      |  |         |  | 1       |  | 11        |  | 13       
|                                     |  |                       |  |         |  |       |  |          |  |         |  |           |  |          
|                                     |  | 59                    |  | 80      |  | 14    |  | 16       |  | 21      |  | 190       |  | 192      
|                                     |  |                       |  |         |  |       |  |          |  |         |  |           |  |          
|Leased                               |  |                       |  |         |  |       |  |          |  |         |  |           |  |          
|Travel Centres                       |  | 1                     |  |        |  |      |  |         |  |        |  | 1         |  | 1        
|Full Serve                           |  | 3                     |  | 7       |  | 5     |  | 5        |  |        |  | 20        |  | 22       
|Full/Self Serve                      |  | 8                     |  | 17      |  | 3     |  | 3        |  |        |  | 31        |  | 37       
|Self Serve                           |  | 35                    |  | 28      |  | 0     |  | 1        |  |        |  | 64        |  | 61       
|Bulk Distributor                     |  | 2                     |  |        |  | 1     |  |         |  | 1       |  | 4         |  | 2        
|Other Service Facilities Distributor |  | 2                     |  | 4       |  |      |  | 3        |  | 2       |  | 11        |  | 8        
|                                     |  |                       |  |         |  |       |  |          |  |         |  |           |  |          
|                                     |  | 51                    |  | 56      |  | 9     |  | 12       |  | 3       |  | 131       |  | 131      
|                                     |  |                       |  |         |  |       |  |          |  |         |  |           |  |          
|Independent Retailers                |  |                       |  |         |  |       |  |          |  |         |  |           |  |          
|Travel Centres                       |  | 1                     |  | 2       |  |      |  |         |  | 4       |  | 7         |  | 7        
|Full Serve                           |  | 20                    |  | 10      |  | 8     |  | 9        |  | 7       |  | 54        |  | 57       
|Full/Self Serve                      |  | 12                    |  | 5       |  | 4     |  | 1        |  | 1       |  | 23        |  | 26       
|Self Serve                           |  | 27                    |  | 39      |  | 4     |  | 2        |  | 1       |  | 73        |  | 78       
|Bulk Distributor                     |  | 2                     |  | 4       |  | 2     |  |         |  |        |  | 8         |  | 8        
|Other Service Facilities Distributor |  | 1                     |  | 2       |  |      |  |         |  | 3       |  | 6         |  | 6        
|                                     |  |                       |  |         |  |       |  |          |  |         |  |           |  |          
|                                     |  | 63                    |  | 62      |  | 18    |  | 12       |  | 16      |  | 171       |  | 182      
|                                     |  |                       |  |         |  |       |  |          |  |         |  |           |  |          
|Total                                |  |                       |  |         |  |       |  |          |  |         |  |           |  |          
|Travel Centres                       |  | 12                    |  | 12      |  | 4     |  | 2        |  | 16      |  | 46        |  | 44       
|Full Serve                           |  | 32                    |  | 29      |  | 14    |  | 17       |  | 10      |  | 102       |  | 107      
|Full/Self Serve                      |  | 39                    |  | 37      |  | 13    |  | 14       |  | 4       |  | 107       |  | 122      
|Self Serve                           |  | 79                    |  | 94      |  | 5     |  | 3        |  | 3       |  | 184       |  | 180      
|Bulk Distributor                     |  | 5                     |  | 13      |  | 5     |  | 1        |  | 1       |  | 25        |  | 25       
|Other Service Facilities Distributor |  | 6                     |  | 13      |  |      |  | 3        |  | 6       |  | 28        |  | 27       
|                                     |  |                       |  |         |  |       |  |          |  |         |  |           |  |          
|                                     |  | 173                   |  | 198     |  | 41    |  | 40       |  | 40      |  | 492       |  | 505      
|                                     |  |                       |  |         |  |       |  |          |  |         |  |           |  |          
|Cardlocks(1)                         |  | 27                    |  | 30      |  | 6     |  | 6        |  | 25      |  | 94        |  | 80       
|Convenience Stores(1)                |  | 157                   |  | 173     |  | 34    |  | 35       |  | 32      |  | 431       |  | 444      
|Restaurants                          |  | 11                    |  | 13      |  | 4     |  | 2        |  | 16      |  | 46        |  | 46       



Note:



|(1) | All of these are 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 north-western United
States.



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



|                        |  |                          |  |      |  |     
|----------------------- |  | ------------------------ |  | ---- |  | ----
|                        |  | Years ended December 31,
|                        |  | 2008                     |  | 2007 |  | 2006
|                        |  | (mbbls/day)             
|Gasoline                |  | 25.0                     |  | 27.8 |  | 27.5
|Diesel fuel             |  | 23.8                     |  | 27.4 |  | 26.4
|Liquefied petroleum gas |  | 0.9                      |  | 0.9  |  | 0.9 
|                        |  |                          |  |      |  |     
|                        |  | 49.7                     |  | 56.1 |  | 54.8
|                        |  |                          |  |      |  |     

Supply

Prince George Refinery

The Prince George refinery production is equal to approximately 20% of Huskys total refined
product supply requirements and is the source of its lowest cost refined products. The refinery produces all grades of unleaded gasoline, seasonal diesel fuels, a mixed propane and butane stream and heavy oil products.

Lloydminster Asphalt Refinery

Huskys
Lloydminster refinery processes heavy crude into asphalt products used in road construction and maintenance, manufactured building products, locomotive blendstock and specialty oil field products. The refinery has a throughput capacity of 28,000
barrels per day of heavy crude oil. It also produces a distillate stream used by the Upgrader and a condensate stream used to blend with heavy oil production. In addition, Husky produces and sells straight run gasoline, bulk distillates and
residuals. The bulk distillates are hydrogen deficient and are transferred directly to the Upgrader and then treated for blending into the Husky Synthetic Blend stream. The straight run gasoline stream is removed and re-circulated into the heavy oil
pipeline network as pipeline diluent. Residuals are a blend of medium and light distillate and gas oil streams, which are sold directly to customers or further processed at the Upgrader into off-road diesel.

Ethanol Manufacturing

In September 2006, Husky
commissioned an ethanol facility in Lloydminster, Saskatchewan. This plant has an annual capacity of 130 million litres. In December 2007, the Minnedosa, Manitoba ethanol plant was commissioned also with an annual capacity of 130 million
litres.

Huskys ethanol production supports its Mother Natures Fuel ethanol-blended gasoline marketing program.
When added to gasoline, ethanol improves fuel combustion, raises octane levels, 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 continued to position its Refined Products business segment
as the leader in ethanol blended fuels in Western Canada.

Other Supply Arrangements

In addition to the refined petroleum products supplied by the Prince George refinery of 3.2 mbbls/day, the Company has rack based pricing purchase
agreements for refined products with all major Canadian refiners. During 2008, the Company purchased approximately 24.6 mbbls/day of refined petroleum products from refiners and acquired approximately 9.2 mbbls/day of refined petroleum products
pursuant to exchange agreements with third party refiners. During 2008, the Company also delivered an average of 12.5 mbbls/day of crude oil to be refined under a processing agreement by another refiner, yielding approximately 11.2 mbbls/day of
refined petroleum products.



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Asphalt Product

Husky produces asphalt and residual products at its 28 mbbls/day asphalt refinery at Lloydminster and markets these products to customers across western Canada and the northwestern and midwestern United States.

Husky has 39% of the market for paving asphalt sold in Western Canada. Huskys Pounder Emulsions division has a 50% market share in
Western Canada for road application emulsion products. Additional non-asphalt based road maintenance products are marketed and distributed through Western Road Management, a division of Husky. The Companys sales to the United States and
Eastern Canada accounted for 39% of production in 2008. Exported asphalt products are shipped as far as Texas, Florida and New Brunswick. Husky sells in excess of 5 mmbbls of asphalt cements per year.

Huskys asphalt distribution network consists of four emulsion/asphalt terminals located at Kamloops, British Columbia; Lethbridge, Alberta;
Yorkton, Saskatchewan; and Winnipeg, Manitoba and four emulsion plants located at Edmonton, Alberta; Watson Lake, Yukon; Lloydminster and Saskatoon, Saskatchewan. Husky also uses an independently operated terminal at Langley, British Columbia.

All of Huskys asphalt requirements are supplied by the Lloydminster, Alberta asphalt refinery. The refinery had an original design
rate throughput capacity of 25 mbbls/day. Debottleneck modifications have allowed Husky to increase that to 28 mbbls/day. The crude oil feedstock for the Lloydminster refinery is supplied through Huskys pipeline systems from the supply of
heavy crude oil in the region, including Husky produced heavy crude oil.

The following table shows average daily sales volumes of products
produced at the Lloydminster refinery for the years indicated:



|                   |  |                          |  |      |  |     
|------------------ |  | ------------------------ |  | ---- |  | ----
|                   |  | Years ended December 31,
|                   |  | 2008                     |  | 2007 |  | 2006
|                   |  | (mbbls/day)             
|Asphalt            |  | 13.6                     |  | 14.0 |  | 14.0
|Residual and other |  | 10.4                     |  | 7.8  |  | 9.4 
|                   |  |                          |  |      |  |     
|                   |  | 24.0                     |  | 21.8 |  | 23.4
|                   |  |                          |  |      |  |     

Refinery throughput averaged 26.1 mbbls/day of blended heavy crude oil feedstock during 2008.

Due to the seasonal demand for asphalt products most 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 producing low sulphur diesel, entering into custom processing arrangements and
developing other U.S. and international markets for asphalt products. This allows Husky to run at or near full capacity year round.

Huskys strategy with respect to its asphalt marketing business is to increase sales volumes by increasing asphalt supply and developing new product streams, to enhance margins by soliciting industry for Husky ideal specifications, to
minimize costs and expand income base through new products and new markets and to pursue mergers, acquisitions, brokering and processing opportunities within its niche markets.

In 2009, Husky will direct its efforts to identifying acquisition, merger, brokering, terminalling, and processing opportunities. In addition, Husky
expects to increase residual sales relative to diluents and bulk distillates to enhance margins, concentrate on sales of higher quality products with larger margins, develop new products and improve existing products.



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United States

Refining and Marketing

Lima Ohio Refinery

Acquisition of the Lima Refining Company closed on July 3, 2007. The Lima Refinery has an atmospheric crude throughput capacity of 160 mbbls per
stream day. The refinery is located in Ohio between Toledo and Dayton and currently processes primarily light sweet crude oil feedstock sourced from the United States and Africa. The refinery produces gasoline, gasoline blend stocks, diesel, jet
fuel, petrochemical feedstock and other by-products. The feedstock is received via the Mid-Valley and Marathon pipelines and the refined products are transported via the Buckeye and Inland pipeline systems and by rail car to primary markets in Ohio,
Illinois, Indiana and southern Michigan.

During 2008 crude oil feedstock throughput averaged 137 mbbls/day. Production of gasoline
averaged 79 mbbls/day, middle distillates averaged 50 mbbls/day and other fuel and feedstock averaged 8 mbbls/day.

Toledo Ohio
Refinery

On March 31, 2008, Husky and BP completed a transaction that created an integrated North American oil sands business.
The business comprises a 50/50 partnership to develop the Sunrise Oil Sands project, operated by Husky, and a 50/50 limited liability company for the Toledo Ohio Refinery, operated by BP.

The Toledo Refinery has an atmospheric crude throughput capacity of 160 mbbls per stream day. Products include low sulphur gasoline, ultra low sulphur
diesel, aviation fuels, propane, kerosene and asphalt. It is located in one of the highest energy consumption regions in the United States.

Husky and BP plan to expand the refinerys bitumen processing capacity to process 120 mbbls/day with total processing capacity increased to 170 mbbls/day by 2015. BP currently markets 100% of the refinerys output; however, upon
commencement of bitumen deliveries from Sunrise, Husky will have the right to market its own share of the refined products.

During the
nine months ended December 31, 2008, crude oil feedstock throughput averaged 60 mbbls/day (Huskys share). Production of gasoline averaged 36 mbbls/day, middle distillates averaged 18 mbbls/day and other fuel and feedstock averaged 6
mbbls/day.

Human Resources

The number of employees was as follows:



| |  |              |  |       |  |      
| |  | ------------ |  | ----- |  | -----
| |  | December 31,
| |  | 2008         |  | 2007  |  | 2006 
| |  | 4,592        |  | 4,142 |  | 3,570
| |  |              |  |       |  |      

DIVIDENDS

The following table shows the aggregate amount of the dividends per common share of the Company paid in respect of its last three years ended
December 31:



|                           |  |      |      |      |   |      |  |   |     
|-------------------------- |  | ---- | ---- | ---- | - | ---- |  | - | ----
|                           |  | 2008 |      | 2007 |   | 2006
|Dividends per common share |  | $    | 1.70 |      | $ | 1.16 |  | $ | 1.13



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Dividend Policy and Restrictions

The Board of Directors of Husky has established a dividend policy that pays quarterly dividends. The dividend policy was reviewed in July 2006 and was increased to $0.25 ($1.00 annually) per common share and again in
October 2007 when it was increased to $0.33 ($1.32 annually). The dividend policy was again reviewed in April 2008 and was increased to $0.40 ($1.60 annually) per common share and again in July 2008 when it increased to $0.50 ($2.00 annually). In
February 2009, the dividend policy was reviewed and was decreased to $0.30 ($1.20 annually) per common share. The Board declared special dividends in the amount of $0.50 per common share in July 2003 and $0.27 per common share in November 2004. In
October 2005, the Board declared a special dividend of $0.50 per common share. In February 2007, the Board declared a special dividend of $0.25 per common share. Huskys dividend policy will continue to be reviewed and there can be no assurance
that further dividends will be declared.

The declaration and payment of dividends will be at the discretion of the Board, 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.

DESCRIPTION OF CAPITAL STRUCTURE

Common Shares

Husky is authorized to issue an unlimited number of common shares. Holders of common
shares are entitled to one vote per share at meetings of shareholders of Husky, to receive such dividends as declared by the Board of Directors on the common shares and to receive pro-rata the remaining property and assets of Husky upon its
dissolution or winding up, subject to any rights having priority over the common shares.

Preferred Shares

Husky is authorized to issue an unlimited number of preferred shares. Holders of preferred shares shall not be entitled to vote at meetings of Husky, are
entitled to receive such dividends as and when declared by the Board of Directors in priority to common shares and shall be entitled to receive pro-rata in priority to holders of common shares the remaining property and assets of Husky upon its
dissolution or winding up. There are no preferred shares currently outstanding.

Credit Ratings Summary



|                              |  |         |  |                   |  |                   
|----------------------------- |  | ------- |  | ----------------- |  | ------------------
|                              |  | Rating  |  | Last Review       |  | Last Rating Change
|Moodys:                      |  |         |  |                   |  |                   
|Outlook                       |  | Stable  |  | July 9, 2008      |  |                  
|Senior Unsecured Debt         |  | Baa2    |  | July 9, 2008      |  | April 25, 2001    
|Standard and Poors:          |  |         |  |                   |  |                   
|Outlook                       |  | Stable  |  | May 5, 2007       |  | July 27, 2006     
|Senior Unsecured Debt         |  | BBB+    |  | May 5, 2007       |  | July 27, 2006     
|Dominion Bond Rating Service: |  |         |  |                   |  |                   
|Trend                         |  | Stable  |  | November 28, 2008 |  | March 31, 2008    
|Senior Unsecured Debt         |  | A (low) |  | November 28, 2008 |  | March 31, 2008    

Credit ratings are intended to provide investors with an independent measure of credit quality of
any issue 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.



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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 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.

Dominion Bond Rating Service

Dominion Bond Rating Services credit rating system ranges from AAA (highest) to D
(lowest). Debt securities rated within the BBB category are considered to be of adequate 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.

MARKET FOR SECURITIES

Huskys common shares are listed and posted for trading on the Toronto Stock Exchange under the trading symbol HSE.

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, 2008:



|          |  |       |  |       |  |              
|--------- |  | ----- |  | ----- |  | -------------
|          |  | High  |  | Low   |  | Volume(000s)
|January   |  | 45.84 |  | 38.50 |  | 27,950       
|February  |  | 43.22 |  | 39.42 |  | 21,774       
|March     |  | 42.88 |  | 38.95 |  | 19,865       
|April     |  | 47.31 |  | 39.65 |  | 23,181       
|May       |  | 54.24 |  | 44.50 |  | 32,091       
|June      |  | 53.00 |  | 46.80 |  | 28,021       
|July      |  | 50.19 |  | 40.30 |  | 24,690       
|August    |  | 49.21 |  | 42.55 |  | 20,128       
|September |  | 49.99 |  | 39.40 |  | 44,757       
|October   |  | 44.62 |  | 29.00 |  | 51,241       
|November  |  | 37.91 |  | 26.50 |  | 28,899       
|December  |  | 33.20 |  | 26.85 |  | 29,405       



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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 Annual Information Form, their positions and
offices with Husky and their principal occupations during the past five years.

Directors



|                            |  |                                                           |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|--------------------------- |  | --------------------------------------------------------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Name & Residence            |  | Officer or Position                                       |  | Principal Occupation During Past 5 Years                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|Li, Victor T.K. Hong Kong   |  | Director and Co-Chair                                     |  | Mr Li is Managing Director and Deputy Chairman of Cheung Kong (Holdings) Limited (a public investment holding and project management company).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|                            |  |                                                          
|                            |  |                                                           |  | Mr. Li is also Deputy Chairman and Executive Director of Hutchison Whampoa Limited (an investment holding company); Chairman and Executive Director of Cheung Kong Infrastructure Holdings
Limited (an infrastructure development company) and of CK Life Sciences Intl., (Holdings) Inc. (a biotechnology company); Executive Director of Hongkong Electric Holdings Limited (a holding company); and a Non-executive Director of The
Hongkong and Shanghai Banking Corporation Limited.                                                                                                                                                                                                                                                
|                            |  |                                                          
|                            |  |                                                           |  | Mr. Li is a member of the Standing Committee of the 11th National Committee of the Chinese Peoples Political Consultative Conference of the Peoples Republic of China and he is
also a member of the Commission on Strategic Development of the Hong Kong Special Administrative Region.                                                                                                                                                                                                                                                                                                                                                                                                                                                
|                            |  |                                                          
|                            |  |                                                           |  | Mr. Li holds a Bachelor of Science degree in Civil Engineering and a Master of Science degree in Structural Engineering.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|                            |  |                                                          
|Fok, Canning K.N. Hong Kong |  | Director, Co-Chairand Chair of the Compensation Committee |  | Mr. Fok is Group Managing Director and Executive Director of Hutchison Whampoa Limited.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|                            |  |                                                          
|                            |  |                                                           |  | Mr. Fok is also a director and Chairman of Hutchison Harbour Ring Limited (an investment holding company), Hutchison Telecommunications International Limited (a telecommunications company),
Hutchison Telecommunications (Australia) Limited (a telecommunications company), Partner Communications Company Ltd. (a telecommunications company) and Hongkong Electric Holdings Limited (a holding company); a director and Deputy Chairman of Cheung
Kong Infrastructure Holdings Limited (an infrastructure holding company); and a director of Cheung Kong (Holdings) Limited (an investment holding company). Mr. Fok was also a director of Hanny Holdings Limited from 1992-2005 and of Panvas Gas
Holdings Limited from 2002-2006.



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|                                            |  |                                                                                                          |  |                                                                                                                                                                                                                                                                               
|------------------------------------------- |  | -------------------------------------------------------------------------------------------------------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Name & Residence                            |  | Officer or Position                                                                                      |  | Principal Occupation During Past 5 Years                                                                                                                                                                                                                                      
|                                            |  |                                                                                                          |  | Mr. Fok holds a Bachelor of Arts degree and a Diploma in Financial Management, and is a member of the Australian Institute of Chartered Accountants.                                                                                                                          
|                                            |  |                                                                                                         
|Fullerton, R. Donald Ontario,
Canada        |  | Director and Chair of the Audit Committee                                                                |  | Mr. Fullerton serves as a corporate director of a number of private companies. Mr. Fullerton is also a director of the Li Ka Shing (Canada) Foundation.                                                                                                                       
|                                            |  |                                                                                                         
|                                            |  |                                                                                                          |  | Mr. Fullerton was a director of Asia Satellite Telecommunications Holdings Limited from 1996 to 2006; George Weston Limited (a holding company) from 1991 to 2005; Partner Communications Ltd.
from 2003 to 2005; and CIBC from 1974 to 2004.                                 
|                                            |  |                                                                                                         
|                                            |  |                                                                                                          |  | Mr. Fullerton holds a Bachelor of Arts degree.                                                                                                                                                                                                                                
|                                            |  |                                                                                                         
|Glynn, Martin J.G. British Columbia,
Canada |  | Director, Chair of the Corporate Governance Committee and Member of the Audit Committee                  |  | Mr. Glynn is a director of Hathor Exploration Limited (mining exploration), VinaCapital Vietnam Opportunity Fund Ltd. (investment fund) and MF Global Ltd. (futures and options
broker).                                                                                      
|                                            |  |                                                                                                         
|                                            |  |                                                                                                          |  | 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 holds a Bachelor of Arts, Honours degree and a Masters degree in Business Administration.                                                                                                                                                                           
|                                            |  |                                                                                                         
|Kluge, Holger Ontario, Canada               |  | Director, Chair of the Health, Safety and Environment Committee and Member of the Compensation Committee |  | Mr. Kluge is a director of Hongkong Electric Holdings Limited, Hutchison Whampoa Limited and Shoppers Drug Mart Corporation.                                                                                                                                                  
|                                            |  |                                                                                                         
|                                            |  |                                                                                                          |  | Mr. Kluge was a director of Hutchison Telecommunications (Australia) Limited from 1999 to 2005; TOM Group Limited (a publishing company) from 2000 to 2005; and Loring Ward International
Limited (a financial planning company) from 2004 to 2005.                           
|                                            |  |                                                                                                         
|                                            |  |                                                                                                          |  | Mr. Kluge holds a Bachelor of Commerce degree and a Masters degree in Business Administration.                                                                                                                                                                               
|                                            |  |                                                                                                         
|Koh, Poh Chan Hong Kong                     |  | Director                                                                                                 |  | Ms. Koh is Finance Director, Harbour Plaza Hotel Management (International) Ltd. (a hotel management company).                                                                                                                                                                



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|                                                 |  |                                                                                       |  |                                                                                                                                                                                                                                                         
|------------------------------------------------ |  | ------------------------------------------------------------------------------------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Name & Residence                                 |  | Officer or Position                                                                   |  | Principal Occupation During Past 5 Years                                                                                                                                                                                                                
|                                                 |  |                                                                                       |  | 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 and the
Chartered Institute of Taxation in the U.K.                 
|                                                 |  |                                                                                      
|Kwok, Eva L. British Columbia, Canada            |  | Director, Member of the Compensation Committee and the Corporate Governance Committee |  | Mrs. Kwok is Chairman, a director and Chief Executive Officer of Amara International Investment Corp. (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 is a director of Bank of Montreal Group of Companies and was a Director of Shoppers Drug Mart Corporation from 2004 to 2006.                                                                                                                  
|                                                 |  |                                                                                      
|                                                 |  |                                                                                       |  | Mrs. Kwok holds a Masters degree in Science.                                                                                                                                                                                                            
|                                                 |  |                                                                                      
|Kwok, Stanley T.L. British Columbia, Canada      |  | Director & Member of the Health, Safety and Environment Committee                     |  | Mr. Kwok is a director and President of Stanley Kwok Consultants (an architecture, planning and development company).                                                                                                                                   
|                                                 |  |                                                                                      
|                                                 |  |                                                                                       |  | Mr. Kwok is also a director and President of Amara International Investment Corp. and a director of Cheung Kong (Holdings) Limited.                                                                                                                     
|                                                 |  |                                                                                      
|                                                 |  |                                                                                       |  | Mr. Kwok holds a Bachelor of Science degree (Architecture) and an A.A. Diploma from the Architectural Association School of Architecture in London (England).                                                                                           
|                                                 |  |                                                                                      
|Lau, John C.S. Alberta, Canada                   |  | Director, President & Chief Executive Officer                                         |  | Mr. Lau is the President & Chief Executive Officer of Husky Energy Inc. Prior to joining Husky in 1992, Mr. Lau served in a number of senior executive roles within the Cheung Kong
(Holdings) Limited and Hutchison Whampoa Limited group of companies.
|                                                 |  |                                                                                      
|                                                 |  |                                                                                       |  | Mr. Lau holds a Bachelor of Economics degree and a Bachelor of Commerce degree.                                                                                                                                                                         
|                                                 |  |                                                                                      
|Russel, Colin S. Gloucestershire, United Kingdom |  | Director & Member of the Audit Committee                                              |  | 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 is a Professional Engineer and Qualified Commercial Mediator. He received his Masters degree in Business Administration and a degree in electronics engineering from McGill
University, Canada.                                             



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|                                       |  |                                                                                                         |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|-------------------------------------- |  | ------------------------------------------------------------------------------------------------------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Name & Residence                       |  | Officer or Position                                                                                     |  | Principal Occupation During Past 5 Years                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|Shaw, Wayne E. Ontario, Canada         |  | Director, Member of the Corporate Governance Committee and the Health, Safety and Environment Committee |  | Mr. Shaw is a Senior Partner with Stikeman Elliott LLP, Barristers and Solicitors. Mr. Shaw is also a director of the Li Ka Shing (Canada) Foundation.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|                                       |  |                                                                                                        
|                                       |  |                                                                                                         |  | Mr. Shaw holds a Bachelor of Arts degree and a Bachelor of Laws degree.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|                                       |  |                                                                                                        
|Shurniak, William Saskatchewan, Canada |  | Director, Deputy Chair and Member of the Audit Committee                                                |  | Mr. Shurniak is a director of Hutchison Whampoa Limited and a director and Chairman of Northern Gas Networks Limited (a private distributor of natural gas in Northern
England).                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|                                       |  |                                                                                                        
|                                       |  |                                                                                                         |  | Mr. Shurniak 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 holds an Honorary Doctor of Laws degree from the University of Saskatchewan and from The University of Western Ontario.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               
|                                       |  |                                                                                                        
|Sixt, Frank J. Hong Kong               |  | Director & Member of the Compensation Committee                                                         |  | Mr. Sixt is Group Finance Director and Executive Director of Hutchison Whampoa Limited.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|                                       |  |                                                                                                        
|                                       |  |                                                                                                         |  | Mr. Sixt is also the Non-executive Chairman and a director of TOM Group Limited; Executive Director of Cheung Kong Infrastructure Holdings Limited (an infrastructure development company) and
Hongkong Electric Holdings Limited (a holding company); a director of Cheung Kong (Holdings) Limited (an investment holding company); Hutchison Telecommunications International Limited (a telecommunications company); Hutchison Telecommunications
(Australia) Limited (a telecommunications company) and Partner Communications Company Ltd. (a telecommunications company). Mr. Sixt is also a director of the Li Ka Shing (Canada) Foundation.
|                                       |  |                                                                                                        
|                                       |  |                                                                                                         |  | Mr. Sixt holds a Masters degree in Arts and a Bachelors degree in Civil Law, and is a member of the Bar and of the Law Society of the Provinces of Quebec and Ontario, Canada.                                                                                                                                                                                                                                                                                                                                                                                                                                                                   



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Officers



|                                   |  |                                                |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|---------------------------------- |  | ---------------------------------------------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Name and Residence                 |  | Office or Position                             |  | Principal Occupation During Past 5 Years                                                                                                                                                                                                                                                                                                                                                                                                                   
|Cowan, Alister Alberta, Canada     |  | Vice President & Chief Financial Officer       |  | Vice President & Chief Financial Officer of Husky Energy Inc. since July 2008. He was previously Executive Vice President and Chief Financial Officer, British Columbia Hydro & Power
Authority from 2004 to 2008,. Vice President, Direct Energy Marketing Limited, from 2003 to 2004 and Vice President and Comptroller, TransAlta Corporation from 2000 to 2003.                                                                                        
|                                   |  |                                               
|Peabody, Robert J. Alberta,
Canada |  | Chief Operating Officer, Operations & Refining |  | Chief Operating Officer, Operations and Refining of Husky since January 2006. Prior to joining Husky, Mr. Peabody held the following positions with British Petroleum: Director Innovence
Separation & Initial Public Offering Project from 2005 to 2006, President of Global Polymers, Chemicals from 2004 to 2005, Vice President, Polyester and Aromatics Americas from 2002 to 2004 and Vice President, BP Group Strategy & Planning
from 1991 to 2001.
|                                   |  |                                               
|Girgulis, James D. Alberta, Canada |  | Vice President, Legal & Corporate Secretary    |  | Vice President, Legal & Corporate Secretary of Husky since August 2000.                                                                                                                                                                                                                                                                                                                                                                                    

As at February 12, 2009, the directors and officers of Husky, as a group, owned or controlled
or directed, directly or indirectly, 433,640 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 future hold an interest. As a result, situations may arise where the interests of such directors and officers conflict with their interests as
directors and officers of other companies. In the case of the directors the resolution of such conflicts is governed by applicable corporate laws which require that directors act honestly, in good faith and with a view to the best interests of Husky
and, in respect of the Business Corporations Act(Alberta), Huskys governing statute, that directors declare, and refrain from voting on, any matter in which a director may have a conflict of interest.

Corporate Cease Trade Orders or Bankruptcies

None of
those persons who are directors or executive officers of Husky is or has 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 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



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insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed
to hold its assets, other than Eva Kwok who was a director of Air Canada in 2003 at the time it became subject to creditor protection under the Companies Creditors Arrangement Act(Canada). In addition, Holger Kluge and Frank Sixt were
directors until April 12, 2002, of vLinx Inc., a private Canadian company which was petitioned into bankruptcy on April 15, 2002. vLinx Inc. developed technology and software to facilitate international trade. Victor Li was a director of
Star River Investment Limited, a Hong Kong company, until June 4, 2005, which commenced creditors voluntary winding up on September 28, 2004. The company was subsequently dissolved on June 4, 2005.

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 made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or
instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold his or her assets.

None of the persons who are directors or executive officers of the Company (or any personal holding companies of such persons) have been subject to any penalties or sanctions imposed by a court relating to securities
legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority or been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely be
considered important to a reasonable investor in making an investment decision.



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AUDIT COMMITTEE

The members of Huskys Audit Committee are R.D. Fullerton (Chair), M.J.G. Glynn, W. Shurniak and C.S. Russel. Each of the members of the
Companys Audit Committee (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 board of directors of Husky (the Board), reasonably interfere with the exercise of a members independent judgment.

The Committees Charter provides that the Committee is to be comprised of at least three (3) members of the Board, all of whom shall be
independent and meet the financial literacy requirements of applicable laws and regulations. Each member of the Committee is financially literate in that each has the ability to read and understand a set of financial statements that present a
breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can reasonably be expected to be raised by the Companys financial statements.

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

R.D. Fullerton (Chair)  Before his retirement Mr. Fullerton served as Chief Executive Officer of CIBC and also
served as a director and/or an Audit Committee member of 16 major domestic and international public companies as well as a director of a number of affiliates of CIBC.

M.J.G. Glynn  Mr. Glynn was a director and President and Chief Executive Officer of HSBC Bank USA N.A. from 2000 until his recent retirement in 2006, as well as a director of a number of affiliates of HSBC.
Mr. Glynn also serves as a director and an Audit Committee member of three domestic and international public companies.

W. Shurniak
 Mr. Shurniak is a non-executive director and member of the audit committee of Hutchison Whampoa Limited and a director and Chairman of Northern Gas Networks Limited, a private company. 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 Committee of five other private companies,
three of which are regulated electricity distribution companies.

C.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.

Huskys Audit Committee Charter 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:



|                   |  |                                             |  |      
|------------------ |  | ------------------------------------------- |  | -----
|                   |  | Aggregate feesbilled by
theExternal Auditor
|                   |  | 2008                                        |  | 2007 
|                   |  | ($ thousands)                              
|Audit fees         |  | 1,832                                       |  | 1,964
|Audit-related fees |  | 121                                         |  | 154  
|Tax fees           |  | 142                                         |  | 77   
|All other fees     |  | 41                                          |  |     
|                   |  |                                             |  |      
|                   |  | 2,136                                       |  | 2,195
|                   |  |                                             |  |      



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Audit Fees. 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. Audit-related services included attest services not required by statute or regulation and services with respect to acquisitions and dispositions.

Tax Fees. Tax fees included tax planning and various taxation matters.

All Other Fees. Other services provided by the Companys external auditor, other than audit, audit-related and tax services.

The audit fees disclosed in the table above reflect amounts billed in the period indicated rather than the period of the audit.

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 approved all of the audit-related, tax and other services provided by KPMG LLP in 2008.

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 except as follows.

In late 2007, TransAlta Power, L.P. was acquired by an indirect subsidiary of Cheung Kong Infrastructure Holdings Limited, which is majority owned by Hutchison Whampoa Limited, which owns 100% of U.F. Investments (Barbados) Ltd. a 34.57%
shareholder in Husky. TransAlta Power L.P. is a 49.99% owner of TransAlta Cogeneration, L.P., the Companys partner in the Meridian Cogeneration plant in Lloydminster, Saskatchewan. Husky sells natural gas to the Meridian Cogeneration plant and
other cogeneration plants owned by TransAlta Power L.P. In 2008, Husky sold $125 million of natural gas to TransAlta Power L.P.

The
Company entered into a management agreement effective July 15, 2004 with Western Canadian Place Ltd. for general management of Western Canadian Place Ltd.s leasehold interest in office space at 635  8th Avenue S.W., Calgary,
Alberta. Western Canadian Place Ltd. is indirectly controlled by the Companys principal shareholders. The Companys President & Chief Executive Officer is also a director and officer of Western Canadian Place Ltd. The Vice
President, Special Projects of the Companys subsidiary, Husky Oil Operations Limited, was also a director and officer of Western Canadian Place Ltd. The Company was paid fees of $99,715 in 2006 and $129,547 in 2005 for providing such
management services. This agreement was terminated effective August 31, 2006.



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TRANSFER AGENT 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 shares are maintained by Computershare Trust Company of Canada at its principal offices in the cities of Calgary and Toronto. Queries should be directed to
Computershare Trust Company at 1-888-267-6555 (toll free in North America).

INTERESTS OF EXPERTS

Certain information relating to the Companys reserves included in this Annual Information Form has been calculated by the
Company and audited and opined upon as of December 31, 2008 by McDaniel & Associates Consultants Ltd. (McDaniel), independent petroleum engineering consultants retained by Husky, and has been so included in reliance on the
opinion and analysis of McDaniel, given upon the authority of said firm as experts in reserve engineering. The partners of McDaniel as a group beneficially own, directly or indirectly, less than 1% of the Companys securities of any class.

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 to be dated March 12, 2009, prepared in connection with the annual meeting of shareholders to be held on April 21, 2009.

Additional financial information is provided in Huskys Consolidated Financial Statements and Managements Discussion and Analysis for the most
recently completed fiscal year ended December 31, 2008.

Additional information relating to Husky Energy Inc. is available on SEDAR
atwww.sedar.com.



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ABBREVIATIONS AND GLOSSARY OF TERMS

As used in this Annual Information Form, the following terms have the meanings indicated:



|                |  |                                                         
|--------------- |  | --------------------------------------------------------
|Units ofMeasure |  |                                                         
|bbl             |  | -barrel                                                 
|bbls            |  | -barrels                                                
|mbbls           |  | -thousand barrels                                       
|mmbbls          |  | -million barrels                                        
|bbls/day        |  | -barrels per calendar day                               
|mbbls/day       |  | -thousand barrels per calendar day                      
|boe             |  | -barrels of oil equivalent                              
|boe/day         |  | -barrels of oil equivalent per calendar day             
|mcf             |  | -thousand cubic feet                                    
|mmcf            |  | -million cubic feet                                     
|bcf             |  | -billion cubic feet                                     
|mmcf/day        |  | -million cubic feet per calendar day                    
|mcfge           |  | -thousand cubic feet of gas equivalent                  
|lt              |  | -long ton                                               
|mlt             |  | -thousand long tons                                     
|lt/day          |  | -long tons per calendar day                             
|mlt/day         |  | -thousand long tons per calendar day                    
|mmbtu           |  | -million British thermal units                          
|Kms             |  | -kilometres                                             
|MW              |  | -megawatts                                              
|                | 
|Acronyms        |  |                                                         
|API             |  | -American Petroleum Institute                           
|CNOOC           |  | -China National Offshore Oil Corporation                
|COGEH           |  | -Canadian Oil and Gas Evaluation Handbook               
|EIA             |  | -Energy Information Administration                      
|EL              |  | -Exploration Licence                                    
|ERCB            |  | -Energy Resources Conservation Board                    
|FAS             |  | -Financial Accounting Statement                         
|FASB            |  | -Financial Accounting Standards Board                   
|FPSO            |  | -Floating production, storage and offloading vessel     
|LLB             |  | -Lloydminster Blend                                     
|NGL             |  | -Natural gas liquids                                    
|NWT             |  | -Northwest Territories                                  
|NYMEX           |  | -New York Mercantile Exchange                           
|OPEC            |  | -Organization of Petroleum Exporting Countries          
|PSC             |  | -Production Sharing Contract                            
|SAGD            |  | -Steam assisted gravity drainage                        
|SDL             |  | -Significant Discovery License                          
|SEC             |  | -Securities and Exchange Commission of the United States
|SEDAR           |  | -System for Electronic Document Analysis and Retrieval  
|WCSB            |  | -Western Canada Sedimentary Basin                       
|WTI             |  | -West Texas Intermediate crude oil                      



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API° gravity

Measure of oil density or specific gravity used in the petroleum industry. The American Petroleum Institute (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

A
highly viscous oil which is too thick to flow in its native state, and which cannot be produced without altering its viscosity. The density of bitumen is generally less than 10 degrees API.

Bulk terminal

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

Coal bed methane

The primary energy source of natural gas is methane (CH(4)). Coal bed methane is methane found and recovered from the coal bed seams. The methane is normally trapped in the coal by water that is under pressure. When
the water is removed the methane is released.

Cold production

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

Debottleneck

To remove restrictions thus improving flow rates and productive capacity.

Delineation well

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

Developed area

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

Development well

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

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.



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Enhanced recovery

The increased recovery from a crude oil pool achieved by artificial means or by the application of energy extrinsic to the pool, which 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 and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in
another reservoir, or to extend a known reservoir. Generally, an exploratory well is any well that is not a development well, a service well, 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.

Gathering system

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

Horizontal drilling

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

Hydrogen sulphide

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

Infill well

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

Liquefied petroleum gas

Liquefied propanes and
butanes, separately or in mixtures.



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Metocean data

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

Miscible flood

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

Multiple completion well

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

Natural gas liquids

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

Oil battery

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

Oil sands

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

Overriding royalty interests

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

Primary recovery

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

Production Sharing Contract

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

Raw gas

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



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Secondary recovery

Oil or gas recovered by injecting water or gas into the reservoir to force additional oil 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.

Sour gas

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

Specific gravity

The ratio between the weight of equal volumes of water and another liquid measured at standard
temperature, the weight of water is assigned a value of one (1). 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

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

Step-out well

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



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Stratigraphic test well

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

Synthetic oil

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

Tertiary recovery

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

Three-D seismic (survey)

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

Turnaround

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

Undeveloped area

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

Waterflood

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

Well abandonment costs

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

Wellhead

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

Working interest

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



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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Information Form are forward-looking statements or information, collectively forward-looking statements,
within the meaning of Section 21E of the United States Securities Exchange Act of 1934, as amended, Section 27A of the United States Securities Act of 1933, as amended and of applicable Canadian Securities legislation. The Company is
hereby providing cautionary statements identifying important factors that could cause the Companys actual results to differ materially from those projected in forward-looking statements made in this Annual Information Form. 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 result, are expected
to, will continue, is anticipated, estimated, intend, plan, projection, could, vision, goals, objective and
outlook) are not historical facts and may be forward-looking statements and may involve estimates, assumptions and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the
forward-looking statements. In particular the 2009 spending plans for the Lima refinery; the anticipated effect of costs incurred for environmental protection to Huskys liquidity and financial position in the long term; the anticipated effect
of the Alberta Governments new fiscal regime on Huskys future net revenue; reserve estimates; discounted future net cash flows relating to proved oil and gas reserves; our plans to increase heavy oil production through the application of
improved technologies; our exploration plans throughout the Western Canada Sedimentary Basin; our exploitation plans, schedules and production forecasts throughout the Western Canada Sedimentary Basin through optimizations, recompletions, workovers,
enhanced recovery techniques, infill and step out drilling, additional facilities and tie-in of discovery wells; the schedule for detailed engineering, project sanction decision review and formal approval and production schedule for the Sunrise oil
sands project; our White Rose tie-back project activities and schedule; plans regarding the development of the natural gas discoveries in the Jeanne dArc Basin; our expectations in respect of the timing of the Terra Nova re-determination; our
drilling plans at Terra Nova; our East Coast exploration and delineation drilling plans; our seismic acquisition and xploration drilling programs in the South China Sea and the East China Sea; our delineation and exploration drilling program at the
Liwan natural gas discovery in the South China Sea; our exploration drilling program on the East Bawean II PSC; our development plans for the BD natural gas and NGL in the Madura Strait, Indonesia; the schedule for our aerogravity and magnetic
survey offshore Greenland; our plans for further pipeline expansion in the Cold Lake and Lloydminster areas; our plans to strategically locate new retail outlets and form strategic alliances in our downstream businesses and our plans to capture
value through various business opportunities in the downstream business are forward-looking statements.

Although the Company believes that
the expectations reflected by the forward-looking statements presented in this Annual Information Form are reasonable, our 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 us about ourselves and the businesses in which we operate. Information used in developing forward-looking statements has been acquired from various sources
including third party consultants, suppliers, regulators and other sources. In some instances, material assumptions are disclosed elsewhere in this Annual Information Form in respect of forward-looking statements. We caution the reader that the
following list of assumptions is not exhaustive. The material factors and assumptions used to develop the forward-looking statements include but are not limited to:



| |  |  | no 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 we operate;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | no significant delays of the development, construction or commissioning of our projects that may result from the inability of suppliers to meet their commitments,
lack of regulatory approvals or other governmental actions, harsh weather or other calamitous event;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | no significant disruption of our operations such as may result from harsh weather, natural disaster, accident, civil unrest or other calamitous event;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | no significant unexpected technological or commercial difficulties that adversely affect our exploration, development, production, processing or transportation;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------



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| |  |  | continuing availability of economical capital resources; demand for our products and our cost of operations;
| | - |  | ------------------------------------------------------------------------------------------------------------



| |  |  | no significant adverse legislative and regulatory changes, in particular changes to the legislation and regulation governing fiscal regimes and environmental
issues; environmental risks and liability under provincial/state, federal or other jurisdictions;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | stability of general domestic and global economic, market and business conditions; and
| | - |  | --------------------------------------------------------------------------------------



| |  |  | no significant increase in the cost of our 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. The risks, uncertainties and other factors, many of
which are beyond our control, that could influence actual results include, but are not limited to:



| |  |  | crude oil and natural gas prices;
| | - |  | ---------------------------------



| |  |  | the economic conditions of the markets in which Husky conducts business;
| | - |  | ------------------------------------------------------------------------



| |  |  | the price differential between light and heavy crude oil and demand related to various crude oil qualities;
| | - |  | -----------------------------------------------------------------------------------------------------------



| |  |  | the price differential between refined products and crude oil;
| | - |  | --------------------------------------------------------------



| |  |  | the exchange rate between the Canadian and U.S. dollar;
| | - |  | -------------------------------------------------------



| |  |  | the availability of incremental reserves of oil and gas, whether sourced from exploration, improved recovery or acquisitions;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------



| |  |  | 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, 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;
| | - |  | ------------------------------------------------------------------------------------------------



| |  |  | potential actions of governments, regulatory authorities and other stakeholders in the jurisdictions where the Company has operations;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------



| |  |  | prevailing climatic conditions in the Companys operating locations;
| | - |  | --------------------------------------------------------------------



| |  |  | regulations to deal with climate change issues;
| | - |  | -----------------------------------------------



| |  |  | changes to government fiscal policies;
| | - |  | --------------------------------------



| |  |  | changes in workforce demographics; and
| | - |  | --------------------------------------



| |  |  | the cost and availability of capital, including access to capital markets at acceptable rates.
| | - |  | ----------------------------------------------------------------------------------------------

These and other factors are discussed throughout this Annual Information Form and in our Managements Discussion and Analysis of Financial
Condition and Results of Operations, available on SEDAR at www.sedar.com.

Further, 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 or statements 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 statements.



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Schedule A

Husky Energy Inc.

Audit Committee Charter

The Audit Committee (the Committee) of the Board of Directors (the Board) of Husky Energy Inc. (the Company) will have
the oversight responsibility, authority and specific duties as described below.

Composition

The Committee will be comprised of three or more directors as determined by the Board, each of whom shall satisfy the independence and financial literacy
requirements of applicable securities regulatory requirements. In addition, one of the members of the Committee will be an audit committee financial expert as defined in applicable securities regulatory requirements. The members of the Committee
will be elected annually at the organizational meeting of the full Board on the recommendation of the Corporate Governance Committee to the Co-Chairmen and will be listed in the annual report to shareholders. One of the members of the Committee will
be elected Committee Chair by the Board.

Responsibility

The Committee is a part of the Board. Its primary function is to assist the Board in fulfilling its oversight responsibilities with respect to:



| | (i) | the quarterly and annual financial statements and quarterly and annual MD&A be provided to shareholders and the appropriate regulatory agencies;
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------



| | (ii) | earnings press releases before the Company publicly discloses this information;
| | ---- | -------------------------------------------------------------------------------



| | (iii) | the system of internal controls that management has established;
| | ----- | ----------------------------------------------------------------



| | (iv) | the internal and external audit process;
| | ---- | ----------------------------------------



| | (v) | the appointment of qualified reserves evaluators or auditors; and
| | --- | -----------------------------------------------------------------



| | (vi) | the filing of statements and reports with respect to the Companys oil and gas reserves.
| | ---- | ----------------------------------------------------------------------------------------

In addition, the Committee provides an avenue for communication between the Board and each of internal audit, the external auditors, financial
management, external qualified reserves evaluators or auditors and internal qualified reserves evaluators. The Committee should 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.

The Committee will make regular reports to the Board concerning its
activities.

While the Audit Committee has the responsibilities and powers set forth in this Charter, the role of the Audit Committee is
oversight. The members of the Committee are not full time employees of the Company 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 Audit Committee to plan or conduct audits or to determine that the Companys financial statements are complete and accurate and are in accordance with generally accepted accounting 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 shall also have the responsibility to conduct investigations and to assure compliance with
laws and regulations and the Companys business conduct guidelines.



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Authority

Subject to the prior approval of 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 Company and the reporting of the
Companys reserves and oil and gas activities.

The Committee has the authority to engage independent counsel and other advisors as it
determines necessary to carry out its duties and to set and pay the compensation for any advisors employed by the Committee.

In
recognition of the fact that the independent auditors are ultimately accountable to the Committee, the Committee shall have the authority and responsibility to nominate for shareholder approval, evaluate and, where appropriate, replace the
independent auditors and shall approve all audit engagement fees and terms and all non-audit engagements with the independent auditors. The Committee shall consult with management and the internal audit group but shall not delegate these
responsibilities.

Meetings

The
Committee is to meet at least four times annually and as many additional times as the Committee deems necessary. Committee members will strive to be present at all meetings either in person or by telephone. 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. Likewise, as necessary or desirable, but in any case at least annually, the Committee shall meet the management and representatives of the external reserve 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.

Specific Duties

In carrying out its oversight responsibilities, the Committee will:



| | 1. | Review and reassess the adequacy of this Charter annually and recommend any proposed changes to the Board for approval.
| | -- | -----------------------------------------------------------------------------------------------------------------------



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

(b) Review with the Companys management, internal audit and external auditors and approve the Companys quarterly financial statements and
quarterly MD&A which is to be provided to shareholders and the appropriate regulatory agencies.



| | 3. | Review with the Companys management and approve earnings press releases before the Company publicly discloses this information.
| | -- | --------------------------------------------------------------------------------------------------------------------------------



| | 4. | Recommend to the Board the external auditors to be nominated for the purpose of preparing or issuing an audit report or performing other audit, review or attest services and the
compensation to be paid to the external auditors. The external auditors shall report directly to the Committee.
| | -- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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| | 6. | Review with the Companys management, internal audit and external auditors the Companys accounting and financial reporting controls. Obtain annually in writing from the
external auditors their observations, if any, on significant weaknesses in internal controls as noted during the course of their work.
| | -- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 7. | Review with the Companys management, internal audit and external auditors significant accounting and reporting principles, practices and procedures applied by the
Company in preparing its financial statements. Discuss with the external auditors their judgments about the quality, not just the acceptability, of the Company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 auditors and how management is addressing the conditions
reported.
| | -- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 9. | Review the scope and general extent of the external auditors annual audit. The Committees review should include an explanation from the external auditors of the factors
considered in determining the audit scope, including the major risk factors. The external auditors should confirm to the Committee 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 Company as contemplated by Independence Standards Board Standard No. 1, Independence Discussions with Audit Committees.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 7. | Review with the Companys management, internal audit and external auditors significant accounting and reporting principles, practices and procedures applied by the
Company in preparing its financial statements. Discuss with the external auditors their judgments about the quality, not just the acceptability, of the Company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 auditors and how management is addressing the conditions
reported.
| | -- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 9. | Review the scope and general extent of the external auditors annual audit. The Committees review should include an explanation from the external auditors of the factors
considered in determining the audit scope, including the major risk factors. The external auditors should confirm to the Committee 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 Company as contemplated by Independence Standards Board Standard No. 1, Independence Discussions with Audit Committees.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 11. | Have a predetermined arrangement with the external auditors that they will advise the Committee, through its Chair and management of the Company, of any matters identified through
procedures followed for the review of interim quarterly financial statements of the Company, and that such notification is to be made prior to the related press release. Also receive a written confirmation provided by the external auditors 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. | At the completion of the annual audit, review with management, internal audit and the external auditors the following:
| | --- | ----------------------------------------------------------------------------------------------------------------------



| |  |  | The annual financial statements and related footnotes and financial information to be included in the Companys annual report to shareholders.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | 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.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| |  |  | Significant changes to the audit plan, if any, and any serious disputes or difficulties with management encountered during the audit. Inquire about the cooperation
received by the external auditors during their audit, including access to all requested records, data and information.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | 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 Companys financial statements.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 13. | Discuss with the external auditors, without management being present, (a) the quality of the Companys financial and accounting personnel, and (b) the completeness
and accuracy of the Companys financial statements. Also, elicit the comments of management regarding the responsiveness of the external auditors to the Company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. The Committee should review responses of management to the Letter of Comments
and Recommendations from the external auditors and receive follow-up reports on action taken concerning the aforementioned recommendations.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 15. | Have 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, in connection
therewith, to approve all fees and other terms of engagement. The Committee shall also review and approve disclosures required to be included in periodic reports filed with Canadian securities regulators and the Securities and Exchange Commission
with respect to non-audit services performed by external auditors.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 16. | Be satisfied that adequate procedures are in place for the review of the Companys disclosure of financial information extracted or derived from the Company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 Company regarding accounting, internal accounting controls or auditing matter,
and (b) the confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 18. | Review and approve the Company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 Companys policies with respect to unethical or illegal
activities by Company employees that may have a material impact on the financial statements.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 21. | Generally as part of the review of the annual financial statements, receive a report(s), at least annually, from the Companys general counsel concerning legal, regulatory and
compliance matters that may have a material impact on the financial statements.
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 22. | Review, with reasonable frequency, the Companys procedures relating to the disclosure of information with respect to the Companys oil and gas reserves, including the
Companys procedures for complying with the disclosure requirements and restrictions of applicable regulations.
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 23. | Review with management the appointment of 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 the appointed external qualified reserves evaluators or auditors, and management.
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| | 24. | Review, with reasonable frequency, the Company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 laws.
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 25. | Before the approval and the release of the Companys reserves data and the report of the qualified reserve evaluators or auditors thereon, meet with 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.
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 26. | Recommend to the Board for approval the content and filing of required statements and reports relating to the Companys disclosure of reserve data as prescribed by applicable
regulations.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 27. | Review and approve (a) any change or waiver in the Companys Code of Business Conduct for the chief executive officer and senior financial officers and (b) any public
disclosure made regarding such change or waiver.
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Calgary, Alberta, Canada

February 16, 2006



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Schedule B

Husky Energy Inc.

Report on Reserves Data by Qualified Reserves Evaluator

To the Board of Directors of

Husky Energy Inc. (Husky):



|1. | Our staff has evaluated Huskys oil and gas reserves data as at December 31, 2008. The reserves data consist of the following:
|-- | ------------------------------------------------------------------------------------------------------------------------------



| | (a) | proved oil and gas reserve quantities estimated as at December 31, 2008 using constant prices and costs; and
| | --- | ------------------------------------------------------------------------------------------------------------



| | (b) | the related standardized measure of discounted future net cash flows.
| | --- | ---------------------------------------------------------------------



|2. | The oil and gas reserves data are the responsibility of Huskys management. As the Corporate Representatives 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.
|-- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|3. | 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 COGEH) with the necessary modifications to reflect definitions and standards under the applicable U.S. Financial Accounting Standards Board standards (the FASB Standards and the legal requirements of
the U.S. Securities and Exchange Commission (SEC Requirements)). Our internal reserves evaluators are not independent of Husky, within the meaning of the term independent under those standards.
|-- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|4. | Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the oil and gas 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 COGEH as modified or replaced by the FASB Standards and SEC Requirements.
|-- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|5. | The following sets forth the estimated standardized measure of discounted future net cash flows (before deducting income taxes) attributed to proved oil and gas reserve quantities,
estimated using constant prices and costs and calculated using a discount rate of 10%, included in the reserves data of Husky evaluated for the year ended December 31, 2008:
|-- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|                     |  |                                                                        |          |  
|-------------------- |  | ---------------------------------------------------------------------- | -------- | -
|Location of Reserves |  | Discounted Future Net Cash Flowsbefore income taxes, 10% discount rate |         
|                     |  | ($                                                                     | millions | )
|Canada               |  |                                                                        | 8,633    |  
|China                |  |                                                                        | 156      |  
|Libya                |  |                                                                        | 0        |  
|                     |  |                                                                        |          |  
|                     |  |                                                                        | 8,789    |  
|                     |  |                                                                        |          |  

We have filed Huskys oil and gas reserves disclosures in accordance with Financial Accounting
Standards Board Statement No. 69 Disclosures about Oil and Gas Producing Activities concurrently with this form.



|6. | In our opinion, the oil and gas reserves data evaluated by us have, in all material respects, been determined in accordance with principles and definitions presented in the COGEH as
modified or replaced by the FASB Standards and SEC Requirements.
|-- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|7. | We have no responsibility to update our evaluation for events and circumstances occurring after the date of this report.
|-- | ------------------------------------------------------------------------------------------------------------------------



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|8. | Oil and gas reserves are estimates only, and not exact quantities. In addition, the oil and gas reserves data are based on judgments regarding future events, actual results will
vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.
|-- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Calgary, Alberta

January 23, 2009



|                                
|--------------------------------
|/S/    FREDERICK
AU-YEUNG       
|Frederick Au-Yeung, P. Eng      
|Manager of Reservoir Engineering



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Schedule C

Husky Energy Inc.

Report of Management and Directors on Reserves Data and Other Information

Management of Husky Energy Inc. (Husky) are responsible for the preparation and disclosure of information with respect to
the Companys oil and gas activities in accordance with securities regulatory requirements. This information includes oil and gas reserves data, which consist of the following:



| | (1) | proved oil and gas reserve quantities estimated as at December 31, 2008 using constant prices and costs; and
| | --- | ------------------------------------------------------------------------------------------------------------



| | (2) | the related standardized measure of discounted future net cash flows.
| | --- | ---------------------------------------------------------------------

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 the
U.S. Securities and Exchange Commission (SEC) and the applicable provisions of the U.S. Financial Accounting Standards Board Statement of Financial Accounting Standards No. 69 (collectively, the Oil and Gas Reserves Data
Process). Huskys Internal Qualified Reserves Evaluator is the Manager of Reservoir Engineering, who is an employee of Husky and has evaluated Huskys oil and gas reserves data and certified that the 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 the Companys procedures for providing information to the internal qualified reserves evaluators and the external reserves auditors;
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------



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



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

The Audit Committee of the Board of Directors has reviewed the Companys procedures for assembling and reporting other information associated with
oil and gas activities and has reviewed that information with management. The Board of Directors has 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 reserves 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 reserves estimates are materially correct.

In Huskys view, the reliability of Huskys internally generated oil and gas reserves data is not materially different 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. Husky is therefore relying on an



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exemption, which it sought and was granted by securities regulatory authorities, from the requirement under securities legislation to involve independent
qualified reserves evaluators or independent qualified reserves auditors.

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.

Huskys view is based in large part on
the following. Our reserves data were developed in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook. Huskys procedures, records and controls relating to the accumulation of source data and preparation of
reserves data by Huskys internal reserves evaluation staff have been established, refined and documented over many years. Our internal reserves evaluation staff includes 101 individuals, including support staff, of whom 50 individuals are
qualified reserves evaluators as defined in the Canadian Oil and Gas Evaluation Handbook, with an average of 14 years of relevant experience in evaluating reserves. Huskys internal reserves evaluation management personnel includes 24
individuals with an average of 13 years of relevant experience in evaluating oil and gas and managing the evaluation process.

Reserves
data are estimates only, and are not exact quantities. Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact
that reserves are categorized according to the probability of their recovery.



|                                            |  |                  
|------------------------------------------- |  | -----------------
|/S/    JOHN C.S.
LAU                        |  | February 18, 2009
|John C. S. Lau                              |  |                  
|President & Chief Executive Officer         |  |                  
|                                            | 
|/S/    JAMES D.
GIRGULIS                    |  | February 18, 2009
|James D. Girgulis                           |  |                  
|Vice President, Legal & Corporate Secretary |  |                  
|                                            | 
|/S/    R. DONALD
FULLERTON                  |  | February 18, 2009
|R. Donald Fullerton                         |  |                  
|Director                                    |  |                  
|                                            | 
|/S/    WILLIAM
SHURNIAK                     |  | February 18, 2009
|William Shurniak                            |  |                  
|Director                                    |  |                  



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Schedule D

Husky Energy Inc.

Independent Engineers Audit Opinion

Husky Energy Inc.

707  8th Avenue S.W.

Calgary, Alberta

T2P 3G7

Gentlemen:

Pursuant to Huskys request we have
conducted an audit of the reserves estimates and the respective present worth value of these reserves of Husky Energy Inc., as at December 31, 2008. The Companys detailed reserves information was provided to us for this audit. Our
responsibility is to express an independent opinion on the reserves and respective present worth value estimates, in aggregate, based on our audit tests and procedures.

We conducted our audit in accordance with Canadian generally accepted standards as described in the Canadian Oil and Gas Evaluation Handbook (COGEH) and auditing standards generally accepted in the United States of
America. 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 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 sufficient number of Company properties as considered necessary 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 in the United States and as set out in the Canadian Oil and Gas Evaluation Handbook.

Sincerely,

McDaniel & Associates Consultants Ltd.



|                             
|-----------------------------
|/S/    P.A.
WELCH            
|P.A. Welch, P. Eng.          
|President & Managing Director

Calgary, Alberta

January 23, 2009



Page 94



---

##### Table of Contents

Document B

Form 40-F

Consolidated Financial Statements and

Auditors Report to Shareholders

For the Year Ended December 31, 2008



Page 95



---

##### Table of Contents

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 Canadian generally accepted accounting principles. 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.

Husky Energy Inc. 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 evaluation concluded that our
internal control over financial reporting was effective as of December 31, 2008. 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, as well as the external auditors, to discuss auditing (external, internal and joint
venture), internal controls, accounting policy, financial reporting matters and 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 generally accepted auditing
standards on behalf of the shareholders. KPMG LLP has full and free access to the Audit Committee.



|                                        
|----------------------------------------
|/s/    JOHN C.S.
LAU                    
|John C.S. Lau                           
|President & Chief Executive Officer     
|                                        
|/s/    ALISTER
COWAN                    
|Alister Cowan                           
|Vice President & Chief Financial Officer

Calgary, Alberta, Canada

February 4, 2009



PAGE 1



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##### Table of Contents

AUDITORS REPORT TO THE SHAREHOLDERS

We have audited the consolidated balance sheets of Husky Energy Inc. (the Company) as at December 31, 2008, 2007 and 2006 and the
consolidated statements of earnings and comprehensive income, changes in shareholders equity and cash flows for each of the years in the three-year period ended December 31, 2008. These financial statements are the responsibility of the
Companys management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our
audits in accordance with Canadian generally accepted auditing standards and in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2008 and the results of its operations and its cash flows for each of the years
in the three-year period ended December 31, 2008 in accordance with Canadian generally accepted accounting principles.

We also have
audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Companys internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal
Control  Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 4, 2009 expressed an unqualified opinion on the effectiveness of the Companys
internal control over financial reporting.



|                        
|------------------------
|/s/ KPMG LLP            
|KPMG LLP                
|Chartered Accountants   
|Calgary, Alberta, Canada
|February 4, 2009        

Comments by Auditors for US readers on Canada  US Reporting Differences

To the Board of Directors of Husky Energy Inc. (the Company)

In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principles that has a material effect on
the comparability of the Companys financial statements, such as the change described in Note 7 (Inventories) to the consolidated financial statements as at December 31, 2008, and for the year then ended. Our report to the shareholders dated
February 4, 2009is expressed in accordance with Canadian reporting standards, which do not require a reference to such a change in accounting principles in the auditors report when the change is properly accounted for and adequately
disclosed in the financial statements.



|                        
|------------------------
|/s/ KPMG LLP            
|KPMG LLP                
|Chartered Accountants   
|Calgary, Alberta, Canada
|February 4, 2009        



PAGE 2



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##### Table of Contents

Report of Independent Registered Public Accounting Firm to the Board of Directors of Husky Energy Inc.

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

We have audited Husky Energy Inc. (the Company)s internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Companys management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of
internal control over financial reporting included in the accompanying Managements Annual Report on Internal Control over Financial Reporting. 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, 2008, based
on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have conducted our audits on the consolidated financial statements in accordance with Canadian generally accepted auditing standards and in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Our report dated February 4, 2009, expressed an unqualified opinion on those consolidated financial statements.



|                        
|------------------------
|/s/ KPMG LLP            
|KPMG LLP                
|Chartered Accountants   
|Calgary, Alberta, Canada
|February 4, 2009        



PAGE 3



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##### Table of Contents

CONSOLIDATED BALANCE SHEETS



|                                                   |  |      |        |      |   |        |      |  |   |       
|-------------------------------------------------- |  | ---- | ------ | ---- | - | ------ | ---- |  | - | ------
|As at December 31 (millions of dollars)            |  | 2008 |        | 2007 |   |        | 2006
|Assets                                             |  |      |        |      |   |        |      |  |   |       
|Current assets                                     |  |      |        |      |   |        |      |  |   |       
|Cash and cash equivalents                          |  | $    | 913    |      | $ | 208    |      |  | $ | 442   
|Accounts receivable (notes 6, 22)                  |  |      | 1,344  |      |   | 1,622  |      |  |   | 1,284 
|Inventories (note 7)                               |  |      | 1,032  |      |   | 1,190  |      |  |   | 428   
|Prepaid expenses                                   |  |      | 33     |      |   | 28     |      |  |   | 25    
|                                                   |  |      |        |      |   |        |      |  |   |       
|                                                   |  |      | 3,322  |      |   | 3,048  |      |  |   | 2,179 
|Property, plant and equipment, net (notes 1, 8)    |  |      | 20,839 |      |   | 17,805 |      |  |   | 15,550
|Goodwill (notes 1, 12)                             |  |      | 779    |      |   | 660    |      |  |   | 160   
|Contribution receivable (note 10)                  |  |      | 1,448  |      |   |       |      |  |   |      
|Other assets (notes 15, 22)                        |  |      | 134    |      |   | 184    |      |  |   | 44    
|                                                   |  |      |        |      |   |        |      |  |   |       
|                                                   |  | $    | 26,522 |      | $ | 21,697 |      |  | $ | 17,933
|                                                   |  |      |        |      |   |        |      |  |   |       
|Liabilities and Shareholders Equity               |  |      |        |      |   |        |      |  |   |       
|Current liabilities                                |  |      |        |      |   |        |      |  |   |       
|Accounts payable and accrued liabilities (note 14) |  | $    | 2,896  |      | $ | 2,358  |      |  | $ | 2,574 
|Long-term debt due within one year (notes 15, 22)  |  |      |       |      |   | 741    |      |  |   | 100   
|                                                   |  |      |        |      |   |        |      |  |   |       
|                                                   |  |      | 2,896  |      |   | 3,099  |      |  |   | 2,674 
|Long-term debt (notes 15, 22)                      |  |      | 1,957  |      |   | 2,073  |      |  |   | 1,511 
|Contribution payable (note 10)                     |  |      | 1,659  |      |   |       |      |  |   |      
|Other long-term liabilities (note 16)              |  |      | 898    |      |   | 918    |      |  |   | 756   
|Future income taxes (note 17)                      |  |      | 4,724  |      |   | 3,957  |      |  |   | 3,372 
|Commitments and contingencies (note 18)            |  |      |        |      |   |        |      |  |   |       
|Shareholders equity                               |  |      |        |      |   |        |      |  |   |       
|Common shares (note 19)                            |  |      | 3,568  |      |   | 3,551  |      |  |   | 3,533 
|Retained earnings                                  |  |      | 10,461 |      |   | 8,176  |      |  |   | 6,087 
|Accumulated other comprehensive income             |  |      | 359    |      |   | (77    | )    |  |   |      
|                                                   |  |      |        |      |   |        |      |  |   |       
|                                                   |  |      | 14,388 |      |   | 11,650 |      |  |   | 9,620 
|                                                   |  |      |        |      |   |        |      |  |   |       
|                                                   |  | $    | 26,522 |      | $ | 21,697 |      |  | $ | 17,933
|                                                   |  |      |        |      |   |        |      |  |   |       

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

On behalf of the Board:



|                     |  |  |  |                      
|-------------------- |  |  |  | ---------------------
|/s/    JOHN C.S.
LAU |  |  |  | /s/    R.D.
FULLERTON
|John C. S. Lau       |  |  |  | R.D. Fullerton       
|Director             |  |  |  | Director             



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##### Table of Contents

CONSOLIDATED STATEMENTS OF EARNINGS AND COMPREHENSIVE INCOME



|                                                                       |  |      |        |   |      |   |        |      |  |   |        |  
|---------------------------------------------------------------------- |  | ---- | ------ | - | ---- | - | ------ | ---- |  | - | ------ | -
|Year ended December 31 (millions of dollars, except per share amounts) |  | 2008 |        |   | 2007 |   |        | 2006 | 
|Sales and operating revenues, net of royalties                         |  | $    | 24,701 |   |      | $ | 15,518 |      |  | $ | 12,664 |  
|Costs and expenses                                                     |  |      |        |   |      |   |        |      |  |   |        |  
|Cost of sales and operating expenses (note 16)                         |  |      | 17,701 |   |      |   | 9,296  |      |  |   | 7,169  |  
|Selling and administration expenses                                    |  |      | 284    |   |      |   | 219    |      |  |   | 162    |  
|Stock-based compensation (note 19)                                     |  |      | (33    | ) |      |   | 88     |      |  |   | 138    |  
|Depletion, depreciation and amortization (notes 1,8)                   |  |      | 1,832  |   |      |   | 1,806  |      |  |   | 1,599  |  
|Interest  net (note 15)                                               |  |      | 147    |   |      |   | 130    |      |  |   | 92     |  
|Foreign exchange (note 15)                                             |  |      | (335   | ) |      |   | (51    | )    |  |   | (24    | )
|Other  net (notes 18, 22)                                             |  |      | (45    | ) |      |   | (97    | )    |  |   | 22     |  
|                                                                       |  |      |        |   |      |   |        |      |  |   |        |  
|                                                                       |  |      | 19,551 |   |      |   | 11,391 |      |  |   | 9,158  |  
|                                                                       |  |      |        |   |      |   |        |      |  |   |        |  
|Earnings before income taxes                                           |  |      | 5,150  |   |      |   | 4,127  |      |  |   | 3,506  |  
|                                                                       |  |      |        |   |      |   |        |      |  |   |        |  
|Income taxes (note 17)                                                 |  |      |        |   |      |   |        |      |  |   |        |  
|Current                                                                |  |      | 901    |   |      |   | 347    |      |  |   | 678    |  
|Future                                                                 |  |      | 495    |   |      |   | 566    |      |  |   | 102    |  
|                                                                       |  |      |        |   |      |   |        |      |  |   |        |  
|                                                                       |  |      | 1,396  |   |      |   | 913    |      |  |   | 780    |  
|                                                                       |  |      |        |   |      |   |        |      |  |   |        |  
|Net earnings                                                           |  |      | 3,754  |   |      |   | 3,214  |      |  |   | 2,726  |  
|Other comprehensive income                                             |  |      |        |   |      |   |        |      |  |   |        |  
|Cumulative foreign currency translation adjustment                     |  |      | 607    |   |      |   | (175   | )    |  |   |       |  
|Hedge of net investment, net of tax (note 22)                          |  |      | (165   | ) |      |   | 102    |      |  |   |       |  
|Derivatives designated as cash flow hedges, net of tax (note 22)       |  |      | (6     | ) |      |   | 14     |      |  |   |       |  
|                                                                       |  |      |        |   |      |   |        |      |  |   |        |  
|                                                                       |  |      | 436    |   |      |   | (59    | )    |  |   |       |  
|                                                                       |  |      |        |   |      |   |        |      |  |   |        |  
|Comprehensive income                                                   |  | $    | 4,190  |   |      | $ | 3,155  |      |  | $ | 2,726  |  
|                                                                       |  |      |        |   |      |   |        |      |  |   |        |  
|Earnings per share                                                     |  |      |        |   |      |   |        |      |  |   |        |  
|Basic and diluted (note 19)                                            |  | $    | 4.42   |   |      | $ | 3.79   |      |  | $ | 3.21   |  
|Weighted average number of common shares outstanding (millions)        |  |      |        |   |      |   |        |      |  |   |        |  
|Basic and diluted (note 19)                                            |  |      | 849.2  |   |      |   | 848.8  |      |  |   | 848.4  |  
|                                                                       |  |      |        |   |      |   |        |      |  |   |        |  

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



PAGE 5



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##### Table of Contents

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS EQUITY



|                                                                 |  |      |        |   |      |   |        |      |  |   |       |  
|---------------------------------------------------------------- |  | ---- | ------ | - | ---- | - | ------ | ---- |  | - | ----- | -
|Year ended December 31 (millions of dollars)                     |  | 2008 |        |   | 2007 |   |        | 2006 | 
|Common shares                                                    |  |      |        |   |      |   |        |      |  |   |       |  
|Beginning of year                                                |  | $    | 3,551  |   |      | $ | 3,533  |      |  | $ | 3,523 |  
|Options exercised                                                |  |      | 17     |   |      |   | 18     |      |  |   | 10    |  
|                                                                 |  |      |        |   |      |   |        |      |  |   |       |  
|End of year                                                      |  |      | 3,568  |   |      |   | 3,551  |      |  |   | 3,533 |  
|                                                                 |  |      |        |   |      |   |        |      |  |   |       |  
|Retained earnings                                                |  |      |        |   |      |   |        |      |  |   |       |  
|Beginning of year                                                |  |      | 8,176  |   |      |   | 6,087  |      |  |   | 3,997 |  
|Net earnings                                                     |  |      | 3,754  |   |      |   | 3,214  |      |  |   | 2,726 |  
|Dividends on common shares (note 19)                             |  |      |        |   |      |   |        |      |  |   |       |  
|Ordinary                                                         |  |      | (1,469 | ) |      |   | (917   | )    |  |   | (636  | )
|Special                                                          |  |      |       |   |      |   | (212   | )    |  |   |      |  
|Adoption of financial instruments (note 22)                      |  |      |       |   |      |   | 4      |      |  |   |      |  
|                                                                 |  |      |        |   |      |   |        |      |  |   |       |  
|End of year                                                      |  |      | 10,461 |   |      |   | 8,176  |      |  |   | 6,087 |  
|                                                                 |  |      |        |   |      |   |        |      |  |   |       |  
|Accumulated other comprehensive income                           |  |      |        |   |      |   |        |      |  |   |       |  
|Beginning of year                                                |  |      | (77    | ) |      |   |       |      |  |   |      |  
|Adoption of financial instruments (note 22)                      |  |      |       |   |      |   | (18    | )    |  |   |      |  
|Other comprehensive income                                       |  |      |        |   |      |   |        |      |  |   |       |  
|Cumulative foreign currency translation adjustment               |  |      | 607    |   |      |   | (175   | )    |  |   |      |  
|Hedge of net investment, net of tax (note 22)                    |  |      | (165   | ) |      |   | 102    |      |  |   |      |  
|Derivatives designated as cash flow hedges, net of tax (note 22) |  |      | (6     | ) |      |   | 14     |      |  |   |      |  
|                                                                 |  |      |        |   |      |   |        |      |  |   |       |  
|                                                                 |  |      | 436    |   |      |   | (59    | )    |  |   |      |  
|                                                                 |  |      |        |   |      |   |        |      |  |   |       |  
|End of year                                                      |  |      | 359    |   |      |   | (77    | )    |  |   |      |  
|                                                                 |  |      |        |   |      |   |        |      |  |   |       |  
|Shareholders equity                                             |  | $    | 14,388 |   |      | $ | 11,650 |      |  | $ | 9,620 |  
|                                                                 |  |      |        |   |      |   |        |      |  |   |       |  

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



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##### Table of Contents

CONSOLIDATED STATEMENTS OF CASH FLOWS



|                                                     |  |      |        |   |      |   |        |      |  |   |        |  
|---------------------------------------------------- |  | ---- | ------ | - | ---- | - | ------ | ---- |  | - | ------ | -
|Year ended December 31 (millions of dollars)         |  | 2008 |        |   | 2007 |   |        | 2006 | 
|Operating activities                                 |  |      |        |   |      |   |        |      |  |   |        |  
|Net earnings                                         |  | $    | 3,754  |   |      | $ | 3,214  |      |  | $ | 2,726  |  
|Items not affecting cash                             |  |      |        |   |      |   |        |      |  |   |        |  
|Accretion (note 16)                                  |  |      | 54     |   |      |   | 47     |      |  |   | 45     |  
|Depletion, depreciation and amortization             |  |      | 1,832  |   |      |   | 1,806  |      |  |   | 1,599  |  
|Future income taxes                                  |  |      | 495    |   |      |   | 566    |      |  |   | 102    |  
|Foreign exchange                                     |  |      | (94    | ) |      |   | (135   | )    |  |   | (3     | )
|Other                                                |  |      | (71    | ) |      |   | (72    | )    |  |   | 32     |  
|Settlement of asset retirement obligations (note 16) |  |      | (56    | ) |      |   | (51    | )    |  |   | (36    | )
|Change in non-cash working capital (note 11)         |  |      | 888    |   |      |   | (718   | )    |  |   | 544    |  
|                                                     |  |      |        |   |      |   |        |      |  |   |        |  
|Cash flow  operating activities                     |  |      | 6,802  |   |      |   | 4,657  |      |  |   | 5,009  |  
|                                                     |  |      |        |   |      |   |        |      |  |   |        |  
|Financing activities                                 |  |      |        |   |      |   |        |      |  |   |        |  
|Long-term debt issue                                 |  |      | 949    |   |      |   | 7,222  |      |  |   | 1,226  |  
|Long-term debt repayment                             |  |      | (2,205 | ) |      |   | (5,722 | )    |  |   | (1,493 | )
|Settlement of cross currency swap                    |  |      |       |   |      |   |       |      |  |   | (47    | )
|Debt issue costs                                     |  |      |       |   |      |   | (8     | )    |  |   |       |  
|Proceeds from exercise of stock options              |  |      | 5      |   |      |   | 5      |      |  |   | 3      |  
|Proceeds from monetization of financial instruments  |  |      | 12     |   |      |   |       |      |  |   |       |  
|Dividends on common shares                           |  |      | (1,469 | ) |      |   | (1,129 | )    |  |   | (636   | )
|Other                                                |  |      | 3      |   |      |   |       |      |  |   | (1     | )
|Change in non-cash working capital (note 11)         |  |      | 146    |   |      |   | 65     |      |  |   | (678   | )
|                                                     |  |      |        |   |      |   |        |      |  |   |        |  
|Cash flow  financing activities                     |  |      | (2,559 | ) |      |   | 433    |      |  |   | (1,626 | )
|                                                     |  |      |        |   |      |   |        |      |  |   |        |  
|Available for investing                              |  |      | 4,243  |   |      |   | 5,090  |      |  |   | 3,383  |  
|                                                     |  |      |        |   |      |   |        |      |  |   |        |  
|Investing activities                                 |  |      |        |   |      |   |        |      |  |   |        |  
|Capital expenditures                                 |  |      | (4,060 | ) |      |   | (2,931 | )    |  |   | (3,171 | )
|Corporate acquisition (note 9)                       |  |      |       |   |      |   | (2,589 | )    |  |   |       |  
|Joint venture arrangement (note 10)                  |  |      | 127    |   |      |   |       |      |  |   |       |  
|Asset sales                                          |  |      | 37     |   |      |   | 333    |      |  |   | 34     |  
|Other                                                |  |      | (13    | ) |      |   | (44    | )    |  |   | (12    | )
|Change in non-cash working capital (note 11)         |  |      | 371    |   |      |   | (93    | )    |  |   | 40     |  
|                                                     |  |      |        |   |      |   |        |      |  |   |        |  
|Cash flow  investing activities                     |  |      | (3,538 | ) |      |   | (5,324 | )    |  |   | (3,109 | )
|                                                     |  |      |        |   |      |   |        |      |  |   |        |  
|Increase (decrease) in cash and cash equivalents     |  |      | 705    |   |      |   | (234   | )    |  |   | 274    |  
|Cash and cash equivalents at beginning of year       |  |      | 208    |   |      |   | 442    |      |  |   | 168    |  
|                                                     |  |      |        |   |      |   |        |      |  |   |        |  
|Cash and cash equivalents at end of year             |  | $    | 913    |   |      | $ | 208    |      |  | $ | 442    |  
|                                                     |  |      |        |   |      |   |        |      |  |   |        |  

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



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##### Table of Contents

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Except where indicated and per share amounts, all dollar amounts are in millions.

Note 1    Segmented Financial Information



|                                                     |  |           |        |                              |   |        |  |      |        |      |   |       |  |      |       |  |      |       |      |   |        |   |  |   |        |  |   |      
|---------------------------------------------------- |  | --------- | ------ | ---------------------------- | - | ------ |  | ---- | ------ | ---- | - | ----- |  | ---- | ----- |  | ---- | ----- | ---- | - | ------ | - |  | - | ------ |  | - | -----
|                                                     |  | Upstream  |        | Midstream                   
|                                                     |  | Upgrading |        | Infrastructure and Marketing
|Year ended December 31                               |  | 2008      |        | 2007                         |   | 2006   |  | 2008 |        | 2007 |   | 2006  |  | 2008 |       |  | 2007 |       | 2006
|Sales and operating revenues, net of royalties       |  | $         | 7,889  |                              | $ | 6,222  |  | $    | 5,772  |      | $ | 2,435 |  | $    | 1,524 |  | $    | 1,679 |      | $ | 13,544 |   |  | $ | 10,217 |  | $ | 9,559
|Costs and expenses                                   |  |           |        |                              |   |        |  |      |        |      |   |       |  |      |       |  |      |       |      |   |        |   |  |   |        |  |   |      
|Operating, cost of sales, selling and general        |  |           | 1,627  |                              |   | 1,308  |  |      | 1,321  |      |   | 2,054 |  |      | 1,127 |  |      | 1,273 |      |   | 13,192 |   |  |   | 9,838  |  |   | 9,258
|Depletion, depreciation and amortization             |  |           | 1,505  |                              |   | 1,615  |  |      | 1,476  |      |   | 31    |  |      | 25    |  |      | 24    |      |   | 31     |   |  |   | 28     |  |   | 24   
|Interest  net                                       |  |           |       |                              |   |       |  |      |       |      |   |      |  |      |      |  |      |      |      |   |       |   |  |   |       |  |   |     
|Foreign exchange                                     |  |           |       |                              |   |       |  |      |       |      |   |      |  |      |      |  |      |      |      |   |       |   |  |   |       |  |   |     
|                                                     |  |           |        |                              |   |        |  |      |        |      |   |       |  |      |       |  |      |       |      |   |        |   |  |   |        |  |   |      
|                                                     |  |           | 3,132  |                              |   | 2,923  |  |      | 2,797  |      |   | 2,085 |  |      | 1,152 |  |      | 1,297 |      |   | 13,223 |   |  |   | 9,866  |  |   | 9,282
|                                                     |  |           |        |                              |   |        |  |      |        |      |   |       |  |      |       |  |      |       |      |   |        |   |  |   |        |  |   |      
|Earnings (loss) before income taxes                  |  |           | 4,757  |                              |   | 3,299  |  |      | 2,975  |      |   | 350   |  |      | 372   |  |      | 382   |      |   | 321    |   |  |   | 351    |  |   | 277  
|Current income taxes                                 |  |           | 585    |                              |   | 122    |  |      | 519    |      |   | 84    |  |      | 10    |  |      | 53    |      |   | 126    |   |  |   | 68     |  |   | 79   
|Future income taxes                                  |  |           | 795    |                              |   | 581    |  |      | 161    |      |   | 21    |  |      | 80    |  |      | 44    |      |   | (29    | ) |  |   | 30     |  |   | 1    
|                                                     |  |           |        |                              |   |        |  |      |        |      |   |       |  |      |       |  |      |       |      |   |        |   |  |   |        |  |   |      
|Net earnings (loss)                                  |  | $         | 3,377  |                              | $ | 2,596  |  | $    | 2,295  |      | $ | 245   |  | $    | 282   |  | $    | 285   |      | $ | 224    |   |  | $ | 253    |  | $ | 197  
|                                                     |  |           |        |                              |   |        |  |      |        |      |   |       |  |      |       |  |      |       |      |   |        |   |  |   |        |  |   |      
|Property, plant and equipment  As at December 31    |  |           |        |                              |   |        |  |      |        |      |   |       |  |      |       |  |      |       |      |   |        |   |  |   |        |  |   |      
|Cost                                                 |  | $         | 25,283 |                              | $ | 23,611 |  | $    | 21,770 |      | $ | 1,704 |  | $    | 1,607 |  | $    | 1,390 |      | $ | 931    |   |  | $ | 842    |  | $ | 750  
|Accumulated depletion, depreciation and amortization |  |           | 11,432 |                              |   | 9,956  |  |      | 8,545  |      |   | 510   |  |      | 480   |  |      | 455   |      |   | 330    |   |  |   | 298    |  |   | 270  
|                                                     |  |           |        |                              |   |        |  |      |        |      |   |       |  |      |       |  |      |       |      |   |        |   |  |   |        |  |   |      
|Net                                                  |  | $         | 13,851 |                              | $ | 13,655 |  | $    | 13,225 |      | $ | 1,194 |  | $    | 1,127 |  | $    | 935   |      | $ | 601    |   |  | $ | 544    |  | $ | 480  
|                                                     |  |           |        |                              |   |        |  |      |        |      |   |       |  |      |       |  |      |       |      |   |        |   |  |   |        |  |   |      
|Capital expenditures  Year ended December 31(2)     |  | $         | 3,580  |                              | $ | 2,388  |  | $    | 2,627  |      | $ | 99    |  | $    | 217   |  | $    | 184   |      | $ | 94     |   |  | $ | 92     |  | $ | 68   
|Goodwill additions  Year ended December 31          |  | $         |       |                              | $ |       |  | $    |       |      | $ |      |  | $    |      |  | $    |      |      | $ |       |   |  | $ |       |  | $ |     
|Total assets  As at December 31                     |  | $         | 15,653 |                              | $ | 14,395 |  | $    | 13,920 |      | $ | 1,349 |  | $    | 1,405 |  | $    | 992   |      | $ | 1,486  |   |  | $ | 1,134  |  | $ | 1,329
|                                                     |  |           |        |                              |   |        |  |      |        |      |   |       |  |      |       |  |      |       |      |   |        |   |  |   |        |  |   |      



|(1) | Eliminations relate to
sales and operating revenues between segments recorded at transfer prices based on current market prices, and to unrealized intersegment profits in inventories.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | Excludes capitalized
costs related to asset retirement obligations incurred during the period and corporate acquisitions (Notes 9 and 10).
|--- | ------------------------------------------------------------------------------------------------------------------------------------------



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Geographical Financial Information



|                                               |  |        |        |               |   |                    |  |       |        |      |   |       |  |      |       |      |   |       |  |      |     |      |   |      |  |   |     |  |   |        |  |   |        |  |   |       
|---------------------------------------------- |  | ------ | ------ | ------------- | - | ------------------ |  | ----- | ------ | ---- | - | ----- |  | ---- | ----- | ---- | - | ----- |  | ---- | --- | ---- | - | ---- |  | - | --- |  | - | ------ |  | - | ------ |  | - | ------
|                                               |  | Canada |        | United States |   | OtherInternational |  | Total
|                                               |  | 2008   |        | 2007          |   | 2006               |  | 2008  |        | 2007 |   | 2006  |  | 2008 |       | 2007 |   | 2006  |  | 2008 |     | 2007 |   | 2006
|Year ended December 31                         |  |        |        |               |   |                    |  |       |        |      |   |       |  |      |       |      |   |       |  |      |     |      |   |      |  |   |     |  |   |        |  |   |        |  |   |       
|Sales and operating revenues, net of royalties |  | $      | 15,213 |               | $ | 11,736             |  | $     | 11,050 |      | $ | 9,172 |  | $    | 3,494 |      | $ | 1,340 |  | $    | 316 |      | $ | 288  |  | $ | 274 |  | $ | 24,701 |  | $ | 15,518 |  | $ | 12,664
|Capital expenditures (1)                       |  |        | 3,685  |               |   | 2,877              |  |       | 3,104  |      |   | 193   |  |      | 21    |      |   |      |  |      | 230 |      |   | 76   |  |   | 97  |  |   | 4,108  |  |   | 2,974  |  |   | 3,201 
|As at December 31                              |  |        |        |               |   |                    |  |       |        |      |   |       |  |      |       |      |   |       |  |      |     |      |   |      |  |   |     |  |   |        |  |   |        |  |   |       
|Property, plant and equipment, net             |  | $      | 16,234 |               | $ | 16,017             |  | $     | 15,200 |      | $ | 4,093 |  | $    | 1,417 |      | $ | 3     |  | $    | 512 |      | $ | 371  |  | $ | 347 |  | $ | 20,839 |  | $ | 17,805 |  | $ | 15,550
|Goodwill (2)                                   |  |        | 160    |               |   | 160                |  |       | 160    |      |   | 619   |  |      | 500   |      |   |      |  |      |    |      |   |     |  |   |    |  |   | 779    |  |   | 660    |  |   | 160   
|Total assets                                   |  |        | 20,241 |               |   | 17,983             |  |       | 17,443 |      |   | 5,747 |  |      | 3,240 |      |   | 115   |  |      | 534 |      |   | 474  |  |   | 375 |  |   | 26,522 |  |   | 21,697 |  |   | 17,933



|(1) | Excludes capitalized costs related to asset retirement obligations incurred during the period
and corporate acquisitions (Notes 9 and 10).
|--- | ------------------------------------------------------------------------------------------------------------------------------------------



|(2) | Goodwill relates to Western Canada in the upstream segment and to the Lima Refinery in the
downstream segment  U.S. refining and marketing.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------



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|                                                     |  |                          |       |                              |   |       |       |      |       |  |      |       |      |  |      |       |  |      |   |  |      |         |   |      |   |        |      |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|---------------------------------------------------- |  | ------------------------ | ----- | ---------------------------- | - | ----- | ----- | ---- | ----- |  | ---- | ----- | ---- |  | ---- | ----- |  | ---- | - |  | ---- | ------- | - | ---- | - | ------ | ---- |  | - | ------ | - |  | - | ------ | - |  | - | ------ | - |  | - | ------ | -
|                                                     |  | Downstream               |       | Corporate andEliminations(1) |   |       | Total |     
|                                                     |  | Canadian RefinedProducts |       | U.S. Refining andMarketing   |   |       |       |      |       | 
|Year ended December 31                               |  | 2008                     |       | 2007                         |   | 2006  |       | 2008 |       |  | 2007 |       | 2006 |  | 2008 |       |  | 2007 |   |  | 2006 |         |   | 2008 |   |        | 2007 |  |   | 2006   |  
|Sales and operating revenues, net of royalties       |  | $                        | 3,564 |                              | $ | 2,916 |       | $    | 2,575 |  | $    | 7,802 |      |  | $    | 2,383 |  | $    |  |  | $    | (10,533 | ) |      | $ | (7,744 | )    |  | $ | (6,921 | ) |  | $ | 24,701 |   |  | $ | 15,518 |   |  | $ | 12,664 |  
|Costs and expenses                                   |  |                          |       |                              |   |       |       |      |       |  |      |       |      |  |      |       |  |      |   |  |      |         |   |      |   |        |      |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|Operating, cost of sales, selling and general        |  |                          | 3,337 |                              |   | 2,608 |       |      | 2,381 |  |      | 8,277 |      |  |      | 2,167 |  |      |  |  |      | (10,580 | ) |      |   | (7,542 | )    |  |   | (6,742 | ) |  |   | 17,907 |   |  |   | 9,506  |   |  |   | 7,491  |  
|Depletion, depreciation and amortization             |  |                          | 81    |                              |   | 66    |       |      | 48    |  |      | 154   |      |  |      | 47    |  |      |  |  |      | 30      |   |      |   | 25     |      |  |   | 27     |   |  |   | 1,832  |   |  |   | 1,806  |   |  |   | 1,599  |  
|Interest  net                                       |  |                          |      |                              |   |      |       |      |      |  |      | 3     |      |  |      | 1     |  |      |  |  |      | 144     |   |      |   | 129    |      |  |   | 92     |   |  |   | 147    |   |  |   | 130    |   |  |   | 92     |  
|Foreign exchange                                     |  |                          |      |                              |   |      |       |      |      |  |      |      |      |  |      |      |  |      |  |  |      | (335    | ) |      |   | (51    | )    |  |   | (24    | ) |  |   | (335   | ) |  |   | (51    | ) |  |   | (24    | )
|                                                     |  |                          |       |                              |   |       |       |      |       |  |      |       |      |  |      |       |  |      |   |  |      |         |   |      |   |        |      |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|                                                     |  |                          | 3,418 |                              |   | 2,674 |       |      | 2,429 |  |      | 8,434 |      |  |      | 2,215 |  |      |  |  |      | (10,741 | ) |      |   | (7,439 | )    |  |   | (6,647 | ) |  |   | 19,551 |   |  |   | 11,391 |   |  |   | 9,158  |  
|                                                     |  |                          |       |                              |   |       |       |      |       |  |      |       |      |  |      |       |  |      |   |  |      |         |   |      |   |        |      |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|Earnings (loss) before income taxes                  |  |                          | 146   |                              |   | 242   |       |      | 146   |  |      | (632  | )    |  |      | 168   |  |      |  |  |      | 208     |   |      |   | (305   | )    |  |   | (274   | ) |  |   | 5,150  |   |  |   | 4,127  |   |  |   | 3,506  |  
|Current income taxes                                 |  |                          | 28    |                              |   | 17    |       |      | 19    |  |      | (24   | )    |  |      | 28    |  |      |  |  |      | 102     |   |      |   | 102    |      |  |   | 8      |   |  |   | 901    |   |  |   | 347    |   |  |   | 678    |  
|Future income taxes                                  |  |                          | 12    |                              |   | 33    |       |      | 21    |  |      | (207  | )    |  |      | 35    |  |      |  |  |      | (97     | ) |      |   | (193   | )    |  |   | (125   | ) |  |   | 495    |   |  |   | 566    |   |  |   | 102    |  
|                                                     |  |                          |       |                              |   |       |       |      |       |  |      |       |      |  |      |       |  |      |   |  |      |         |   |      |   |        |      |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|Net earnings (loss)                                  |  | $                        | 106   |                              | $ | 192   |       | $    | 106   |  | $    | (401  | )    |  | $    | 105   |  | $    |  |  | $    | 203     |   |      | $ | (214   | )    |  | $ | (157   | ) |  | $ | 3,754  |   |  | $ | 3,214  |   |  | $ | 2,726  |  
|                                                     |  |                          |       |                              |   |       |       |      |       |  |      |       |      |  |      |       |  |      |   |  |      |         |   |      |   |        |      |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|Property, plant and equipment As at December 31     |  |                          |       |                              |   |       |       |      |       |  |      |       |      |  |      |       |  |      |   |  |      |         |   |      |   |        |      |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|Cost                                                 |  | $                        | 1,691 |                              | $ | 1,550 |       | $    | 1,344 |  | $    | 4,249 |      |  | $    | 1,459 |  | $    |  |  | $    | 406     |   |      | $ | 338    |      |  | $ | 298    |   |  | $ | 34,264 |   |  | $ | 29,407 |   |  | $ | 25,552 |  
|Accumulated depletion, depreciation and amortization |  |                          | 669   |                              |   | 590   |       |      | 525   |  |      | 229   |      |  |      | 46    |  |      |  |  |      | 255     |   |      |   | 232    |      |  |   | 207    |   |  |   | 13,425 |   |  |   | 11,602 |   |  |   | 10,002 |  
|                                                     |  |                          |       |                              |   |       |       |      |       |  |      |       |      |  |      |       |  |      |   |  |      |         |   |      |   |        |      |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|Net                                                  |  | $                        | 1,022 |                              | $ | 960   |       | $    | 819   |  | $    | 4,020 |      |  | $    | 1,413 |  | $    |  |  | $    | 151     |   |      | $ | 106    |      |  | $ | 91     |   |  | $ | 20,839 |   |  | $ | 17,805 |   |  | $ | 15,550 |  
|                                                     |  |                          |       |                              |   |       |       |      |       |  |      |       |      |  |      |       |  |      |   |  |      |         |   |      |   |        |      |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|Capital expenditures- Year ended December 31(2)      |  | $                        | 155   |                              | $ | 212   |       | $    | 285   |  | $    | 133   |      |  | $    | 21    |  | $    |  |  | $    | 47      |   |      | $ | 44     |      |  | $ | 37     |   |  | $ | 4,108  |   |  | $ | 2,974  |   |  | $ | 3,201  |  
|Goodwill additions- Year ended December 31           |  | $                        |      |                              | $ |      |       | $    |      |  | $    |      |      |  | $    | 536   |  | $    |  |  | $    |        |   |      | $ |       |      |  | $ |       |   |  | $ |       |   |  | $ | 536    |   |  | $ |       |  
|Total assets  As at December 31                     |  | $                        | 1,381 |                              | $ | 1,335 |       | $    | 1,114 |  | $    | 5,383 |      |  | $    | 3,058 |  | $    |  |  | $    | 1,270   |   |      | $ | 370    |      |  | $ | 578    |   |  | $ | 26,522 |   |  | $ | 21,697 |   |  | $ | 17,933 |  
|                                                     |  |                          |       |                              |   |       |       |      |       |  |      |       |      |  |      |       |  |      |   |  |      |         |   |      |   |        |      |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  



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Note 2    Nature of Operations and Organization

Husky Energy Inc. (Husky or the Company) is a publicly traded, integrated energy and energy-related company headquartered in
Calgary, Alberta, Canada.

Management has segmented the Companys business based on differences in products and services and
management responsibility. The Companys business is conducted predominantly through three major business segments  upstream, midstream and downstream.

Upstream includes exploration for, development and production of crude oil, natural gas and natural gas liquids. The Companys upstream operations are located primarily in Western Canada, offshore Eastern Canada,
offshore Greenland, offshore China and offshore Indonesia.

Midstream includes upgrading of heavy crude oil feedstock into synthetic crude
oil (upgrading); marketing of the Companys and other producers crude oil, natural gas, natural gas liquids, sulphur and petroleum coke; and pipeline transportation and processing of heavy crude oil, storage of crude oil, diluent and
natural gas and cogeneration of electrical and thermal energy (infrastructure and marketing).

Downstream includes 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).

Note
3    Significant Accounting Policies

a) Principles of Consolidation and the Preparation of Financial Statements

These financial statements are prepared in accordance with Canadian generally accepted accounting principles (GAAP) which, in the case of
the Company, differ in certain respects from those in the United States. These differences are described in the section, Reconciliation to Accounting Principles Generally Accepted in the United States, contained in Form 40-F filed with the United
States Securities and Exchange Commission and available at www.sec.gov.

The consolidated financial statements include the accounts
of Husky Energy Inc. and its subsidiaries after the elimination of intercompany balances and transactions. The Company consolidates all investments in which it has either direct or indirect voting ownership in excess of 50%. In addition, the Company
consolidates variable interest entities when it is deemed to be the primary beneficiary, and proportionately consolidates joint venture entities.

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 flow
from these activities.

b) Use of Estimates

The preparation of financial statements in conformity with Canadian GAAP requires management to make estimates 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 revenues and expenses during the period. Specifically, amounts recorded for depletion, depreciation, amortization of accretion expense, asset retirement obligations, fair value
measurements, management contracts, employee future benefits and amounts used in impairment tests for intangible assets, goodwill, inventory and property, plant and equipment are based on estimates. These estimates include petroleum and natural gas
reserves, future petroleum and natural gas prices, future interest rates and future costs required to develop those reserves as well as other fair value assumptions. By their nature, these estimates are subject to measurement uncertainty and changes
in such estimates in future years could require a material change on the financial statements.



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c) Cash and Cash Equivalents

Cash and cash equivalents consist of cash on hand less outstanding cheques and deposits with a maturity of less than three months at the time of purchase. When outstanding cheques are in excess of cash on hand, the
excess is reported in bank operating loans.

d) Inventories

Crude oil, natural gas, refined petroleum products and purchased 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. Previous impairment write-downs are reversed when there is a
change in the situation that caused the impairment. Intersegment profits are eliminated.

e) Precious Metals

The Company uses precious metals in conjunction with catalyst as part of the downstream U.S. refining process. These precious metals remain intact;
however, there is a loss during the reclamation process. The estimated loss is amortized to 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 earnings.

f) Property, Plant and Equipment

i) Oil and Gas

The Company
employs the full cost method of accounting for oil and gas interests whereby all costs of acquisition, exploration for and development of oil and gas reserves are capitalized and accumulated within cost centres on a country-by-country basis. Such
costs include land acquisition, geological and geophysical activity, drilling of productive and non-productive wells, carrying costs directly related to unproved properties and administrative costs directly related to exploration and development
activities.

Depletion of oil and gas properties and depreciation of associated production facilities are calculated using
the unit of production method, based on gross proved oil and gas reserves as estimated by the Companys engineers, for each cost centre. Depreciation of gas plants and certain other oil and gas facilities is provided using the straight-line
method based on their estimated useful lives. Costs subject to depletion and depreciation include both the estimated costs required to develop proved undeveloped reserves and the associated addition to the asset retirement obligations. In the normal
course of operations, retirements of oil and gas interests are accounted for by charging the asset cost, net of any proceeds, to accumulated depletion or depreciation. Gains or losses on the disposition of oil and gas properties are not recognized
unless the gain or loss changes the depletion rate by 20% or more.

Costs of acquiring and evaluating significant unproved
oil and gas interests are excluded from costs subject to depletion and depreciation until it is determined that proved oil and gas reserves are attributable to such interests or until impairment occurs. Costs of major development projects are
excluded from costs subject to depletion and depreciation until proved developed reserves have been attributed to a portion of the property or the property is determined to be impaired.

Impairment losses are recognized when the carrying amount of a cost centre exceeds the sum of:



| |  |  | the undiscounted cash flow expected to result from production from proved reserves based on forecast oil and gas prices and costs;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------



| |  |  | the costs of unproved properties, less impairment; and
| | - |  | ------------------------------------------------------



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| |  |  | the costs of major development projects, less impairment.
| | - |  | ---------------------------------------------------------

The amount of impairment loss is determined to be the amount by which the carrying amount of the cost centre exceeds the sum of:



| |  |  | the fair value of proved and probable reserves calculated using a present value technique that uses the cash flows expected to result from production of the proved
reserves and a portion of the probable reserves discounted using a risk free rate; and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the cost, less impairment, of unproved properties and major development projects that do not have probable reserves attributed to them.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------

ii) Other Plant and Equipment

Depreciation for substantially all other plant and equipment, except upgrading assets, is provided using the straight-line method based on
estimated useful lives of assets which range from five to thirty-five years. Depreciation for upgrading assets is provided using the unit of production method, based on the plants estimated productive life. Repairs and maintenance costs, other
than major turnaround costs, are charged to earnings as incurred. Certain turnaround costs are deferred to other assets when incurred and amortized over the estimated period of time to the next scheduled turnaround. At the time of disposition of
plant and equipment, accounts are relieved of the asset values and accumulated depreciation and any resulting gain or loss is reflected in earnings.

iii) Asset Retirement Obligations

The recognition of the fair value of legal obligations
associated with the retirement of tangible long-lived assets as calculated using the current estimated costs to retire the asset inflated to the estimated retirement date discounted using a credit-adjusted risk free rate, is recorded in the period
that the asset is put into use, with a corresponding increase to the carrying value of the related asset. The obligations recognized are legal obligations. The liability is accreted over time for changes in the fair value of the liability through
charges to accretion, which is included in cost of sales and operating expenses. The liability will also be adjusted to reflect revisions to the previous estimates of the undiscounted obligation. The costs capitalized to the related assets are
amortized to earnings in a manner consistent with the depletion, depreciation and amortization of the underlying asset. Actual retirement expenditures are charged to the accumulated liability as incurred.

iv) Capitalized Interest

Interest is capitalized on significant major capital projects based on the Companys long-term cost of borrowing. Capitalization of interest ceases when the capital project is substantially complete and ready for its intended use.

g) Impairment or Disposal of Long-lived Assets

An impairment loss is recognized when the carrying value of a long-lived asset is not recoverable and exceeds its fair value. Testing for recoverability uses the undiscounted cash flows expected from the assets use and disposition. To
test for and measure impairment, long-lived assets are grouped at the lowest level for which identifiable cash flows are largely independent.

A long-lived asset that meets the conditions as held for sale is measured at the lower of its carrying amount or fair value less costs to sell. Such assets are not amortized while they are classified as held for sale. The results of
operations of a component of an entity that has been disposed of, or is classified as held for sale, are reported in discontinued operations if: i) the operations and cash flows of the component have been or will be eliminated as a result of the
disposal transaction; and, ii) the entity will not have a significant continuing involvement in the operations of the component after the disposal transaction.



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h) Goodwill

Goodwill is the excess of the purchase price paid over the fair value of net assets acquired. Goodwill is subject to impairment tests on at least an annual basis or sooner if there are indicators of impairment. The Company tests impairment
annually in the fourth quarter of each year. To assess impairment, the fair values of the assets and liabilities of the reporting unit are compared to their carrying amounts. If excess of the reporting units fair value over its carrying
amounts is greater than the carrying amount of the goodwill then there is no impairment. Any amount that the carrying amount of the goodwill exceeds the excess of the reporting units fair value over its carrying amount is goodwill impairment.
Impairment losses would be recognized in current period earnings.

i) Derivative Financial Instruments and Hedging Activities

i) Financial Instruments

All
financial instruments must initially be recognized at fair value on the balance sheet. The Company has classified each financial instrument into the following categories: held for trading financial assets and financial liabilities, loans or
receivables, held to maturity investments, available for sale financial assets, and other financial liabilities. Subsequent measurement of the financial instruments is based on their classification. Unrealized gains and losses on held for trading
financial instruments are recognized in earnings. Gains and losses on available for sale financial assets are recognized in other comprehensive income (OCI) and are transferred to earnings when the asset is derecognized. The other
categories of financial instruments are recognized at amortized cost using the effective interest rate method.

A held for trading
financial instrument is not a loan or receivable and includes one of the following criteria:



| |  |  | is a derivative, except for those derivatives that have been designated as effective hedging instruments;
| | - |  | ---------------------------------------------------------------------------------------------------------



| |  |  | has been acquired or incurred principally for the purpose of selling or repurchasing in the near future; or
| | - |  | -----------------------------------------------------------------------------------------------------------



| |  |  | is part of a portfolio of financial instruments that are managed together and for which there is evidence of a recent actual pattern of short-term profit taking.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------

For financial assets and financial liabilities that are not classified as held for trading, the
transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability are added to the fair value initially recognized for that financial instrument. These costs are expensed to earnings using the
effective interest rate method.

ii) Derivative Instruments and Hedging Activities

Derivative instruments are utilized by the Company to manage market risk against the 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 choose to designate derivative instruments as hedges. Hedge accounting continues to be optional.

At the inception of a hedge, if the Company elects to use hedge accounting, the Company formally documents the designation
of the hedge, the risk management objectives, the hedging relationships between the hedged items and hedging items and the method for testing the effectiveness of the hedge, which must be reasonably assured over the term of the hedge. This process
includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. The Company formally assesses, both at the inception of the hedge and on an ongoing basis, whether
the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of hedged items.



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All derivative instruments are recorded on the balance sheet at fair value in accounts
receivable, other assets, accounts payable and accrued liabilities, or other long-term liabilities. Freestanding derivative instruments are classified as held for trading financial instruments. Gains and losses on these instruments are recorded in
other expenses in the consolidated statement of earnings in the period they occur. Derivative instruments that have been designated and qualify for hedge accounting are classified as either fair value or cash flow hedges. For fair value hedges, the
gains or losses arising from adjusting the derivative to its fair value are recognized immediately in earnings along with the gain or loss on the hedged item. For cash flow hedges, the effective portion of the gains and losses is recorded in OCI
until the hedged transaction is recognized in earnings. When the earnings impact of the underlying hedged transaction is recognized in the consolidated statement of earnings, the fair value of the associated cash flow hedge is reclassified from OCI
into earnings. Any hedge ineffectiveness is immediately recognized in earnings. Hedge accounting is discontinued on a prospective basis when the hedging relationship no longer qualifies for hedge accounting.

The Company may enter into commodity price contracts to hedge anticipated sales of crude oil and natural gas production to manage its
exposure to price fluctuations. Gains and losses from these contracts are recognized in upstream oil and gas revenues as the related sales occur.

The Company may enter into commodity price contracts to offset fixed price contracts entered into with customers and suppliers to retain market prices while meeting customer or supplier pricing requirements. Gains and
losses from these contracts are recognized in midstream revenues or costs of sales.

The Company may enter into power price
contracts to hedge anticipated purchases of electricity to manage its exposure to price fluctuations. Gains and losses from these contracts are recognized in upstream operating expenses as the related purchases occur.

The Company may enter into interest rate swap agreements to hedge its fixed and floating interest rate mix on long-term debt. Gains and
losses from these contracts are recognized as an adjustment to the interest expense on the hedged debt instrument.

The
Company may enter into foreign exchange contracts to hedge its foreign currency exposures on U.S. dollar denominated long-term debt. Gains and losses on these instruments related to foreign exchange are recorded in foreign exchange expense in the
period to which they relate, offsetting the respective foreign exchange gains and losses recognized on the underlying foreign currency long-term debt. The remaining portion of the gain or loss is recorded in accumulated other comprehensive income
and is adjusted for changes in the fair value of the instrument over the life of the debt.

The Company may designate
certain U.S. dollar denominated debt as a hedge of its net investment in self-sustaining foreign operations. The unrealized foreign exchange gains and losses arising from the translation of the debt are recorded in OCI, net of tax and are limited to
the translation gain or loss on the net investment.

The Company may enter into foreign exchange forwards and foreign
exchange collars to hedge anticipated U.S. dollar denominated crude oil and natural gas sales. Gains and losses on these instruments are recognized in upstream oil and gas revenues when the sale is recorded.

The Company may enter into foreign exchange contracts to offset its foreign exchange exposure. Gains and losses on these instruments are
recorded at fair value and are recognized in other expense in the consolidated statement of earnings.

For cash flow hedges
that have been terminated or cease to be effective, prospective gains or losses on the derivative are recognized in earnings. Any gain or loss that has been included in accumulated other comprehensive income at the time the hedge is discontinued
continues to be deferred in accumulated other comprehensive income until the original hedged transaction is recognized in earnings. However, if the likelihood of the original hedged transaction occurring is no longer probable, the entire gain or
loss in accumulated other comprehensive income related to this transaction is immediately reclassified to earnings.



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Fair values of the derivatives are based on quoted market prices where available. The
fair values of swaps and forward contracts are based on forward market prices. If a forward price is not available for a commodity based forward contract, a forward price is estimated using an existing forward price adjusted for quality or location.

iii) Embedded Derivatives

Embedded derivatives are derivatives embedded in a host contract. They are recorded separately from the host contract when their economic characteristics and risks are not clearly and closely related to those of the
host contract, the terms of the embedded derivatives are the same as those of a freestanding derivative and the combined contract is not classified as held for trading or designated at fair value. The Company selected January 1, 2003 as its
transition date for accounting for any potential embedded derivatives.

iv) Comprehensive Income

Comprehensive income consists of net earnings and OCI. OCI comprises 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 and exchange gains and losses arising from the translaton of the financial statements of a self-sustaining foreign operation. Amounts included in OCI are shown net of
tax. Accumulated other comprehensive income is an equity category comprised of the cumulative amounts of OCI.

j) Employee Future Benefits

In Canada, the Company provides a defined contribution pension plan and a post-retirement health and dental care plan 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. The cost of the pension benefits earned by employees in the defined
contribution pension plan is paid and expensed when incurred. The cost of the benefits earned by employees in the post-retirement health and dental care plan and defined benefit pension plan is charged to earnings as services are rendered using the
projected benefit method prorated on service. The cost of the post-retirement health and dental care plan and defined benefit pension plan reflects a number of assumptions that affect the expected future benefit payments. These assumptions 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 plan
assets are valued at fair value for the purposes of calculating the expected return on plan assets.

Adjustments arising out of plan
amendments, changes in assumptions and experience gains and losses are normally amortized over the expected remaining average service life of the employee group.

k) Future Income Taxes

The Company follows the liability method of accounting for income taxes. Future income tax assets
and liabilities are recognized at expected tax rates in effect when temporary differences between the tax basis and the carrying value of the Companys assets and liabilities reverse. The effect of a change to the tax rate on the future tax
assets and liabilities is recognized in earnings when substantively enacted.

l) Non-monetary Transactions

Non-monetary transactions are measured based on fair value when there is evidence to support the fair value unless the transaction lacks commercial
substance or is an exchange of product or property held for sale in the ordinary course of business.



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##### Table of Contents

m) Revenue Recognition

Revenues from the sale of crude oil, natural gas, natural gas liquids, synthetic crude oil, purchased commodities and refined petroleum products are recorded when title passes to an external party and payment has
either been received or collection is reasonably certain. Sales between the business segments of the Company are eliminated from sales and operating revenues and cost of sales. Revenues associated with the sale of transportation, processing and
natural gas storage services are recognized when the services are provided.

n) Foreign Currency Translation

Results of foreign operations, which are considered financially and operationally integrated, are translated to Canadian dollars at the monthly average
exchange rates for revenue and expenses, except for depreciation and depletion which are translated at the rate of exchange applicable to the related assets. Monetary assets and liabilities are translated at current exchange rates and non-monetary
assets and liabilities are translated using historical rates of exchange. Gains or losses resulting from these translation adjustments are included in earnings.

The accounts of self-sustaining foreign operations are translated to Canadian dollars using the current rate method. Assets and liabilities are translated at the period-end exchange rate and revenues and expenses are
translated at the average exchange rates for the period. Gains and losses on the translation of self-sustaining foreign operations are included in OCI.

o) Stock-based Compensation

In accordance with the Companys stock option plan, common share options 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.

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 expected cash settlements is accrued over
the vesting period of the stock options based on the difference between the exercise price of the stock options and the market price of the Companys common shares. The liability is revalued to reflect changes in the market price of the
Companys common shares and the net change is recognized in 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. Accrued compensation for an option that is forfeited is adjusted to earnings by decreasing the compensation
cost in the period of forfeiture.

p) Earnings per Share

Basic common shares outstanding are the weighted average number of common shares outstanding for each period. The calculation of basic earnings per common share is based on net earnings divided by the weighted average
number of common shares outstanding.

Diluted common shares outstanding are calculated using the treasury stock method, which assumes that
any proceeds received from in-the-money options would be used to buy back common shares at the average market price for the period. However, since the Company has a tandem stock option plan and accrues a liability for expected cash settlements, the
potential common shares issuable upon exercise associated with the stock options are not included in diluted common shares outstanding. Shares that were potentially issuable on the settlement of the capital securities were not included in the
determination of diluted earnings per common share, as the Company had neither the obligation nor intention to settle amounts due through the issuance of shares.

q) Reclassification

Certain prior years amounts have been reclassified to conform with current presentation.



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Note 4    Pending Accounting Pronouncements

a) Goodwill and Intangible Assets

In February 2008,
the Canadian Institute of Chartered Accountants (CICA) issued CICA section 3064, Goodwill and Intangible Assets, which will replace CICA section 3062 of the same name. As a result of issuing this guidance, CICA section 3450,
Research and Development Costs, and Emerging Issues Committee Abstract No. 27, Revenues and Expenditures during the Pre-Operating Period, will be withdrawn. This new guidance requires recognizing all goodwill and
intangible assets in accordance with CICA section 1000, Financial Statement Concepts. Section 3064 will eliminate the current practice of recognizing items as assets that do not meet the section 1000 definition and recognition
criteria.

As of January 1, 2009, the Company will retroactively adopt CICA section 3064. This adoption will result in a reduction of
retained earnings at January 1, 2007 of $9 million, a reduction of earnings after tax of $3 million and $13 million for the years ended December 31, 2008 and 2007, respectively, and a reduction to assets of $36 million and $31 million as
at December 31, 2008 and 2007, respectively.

b) Business Combinations

In December 2008, the CICA issued section 1582 Business Combinations, which will replace CICA section 1581 of the same name. Under this
guidance, the purchase price used in a business combination is based on the fair value of shares exchanged at their market price at the date of the exchange. Currently the purchase price used is based on the market price of the shares for a
reasonable period before and after the date the acquisition is agreed upon and announced. This new guidance generally requires all acquisition costs to be expensed, which currently are capitalized as part of the purchase price. Contingent
liabilities are to be recognized at fair value at the acquisition date and remeasured at fair value through earnings each period until settled. Currently only contingent liabilities that are resolved and payable are included in the cost to acquire
the business. In addition, negative goodwill is required to be recognized immediately in earnings, unlike the current requirement to eliminate it by deducting it from non-current assets in the purchase price allocation. Section 1582 will be
effective for Husky on January 1, 2011 with prospective application.

Note 5    International Financial Reporting Standards

In January 2006, the Canadian Accounting Standards Board (AcSB) adopted a strategic plan for the direction of accounting
standards in Canada. In February 2008, as part of its strategic plan, the AcSB confirmed that Canadian publicly accountable entities will be required to report under International Financial Reporting Standards (IFRS), which will replace
Canadian GAAP for years beginning on or after January 1, 2011. An omnibus exposure draft was issued by the AcSB in the second quarter of 2008, which incorporates IFRS into the CICA Handbook and prescribes the transitional provisions for
adopting IFRS.

The Company has completed the diagnostic assessment phase by performing comparisons of the differences between Canadian
GAAP and IFRS and is currently assessing the effects of adoption and finalizing its conversion plan. The Company has determined that accounting for property, plant and equipment will be impacted by the conversion to IFRS. The Company currently
follows full cost accounting as prescribed in Accounting Guideline (AcG) 16, Oil and Gas Accounting  Full Cost. Conversion from Canadian GAAP to IFRS may have an impact on how the Company accounts for costs pertaining
to oil and gas activities, in particular those related to the pre-exploration and development phases. The conversion to IFRS will also result in other impacts, some of which may be significant in nature and these continue to be assessed by the
Company. At this time, the impact on Huskys financial position and results of operations is not reasonably determinable or estimable for any of the IFRS conversion impacts identified. The Company will continue to monitor any changes in the
adoption of IFRS and will update its plan as necessary.



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Note 6    Accounts Receivable



|                                |  |      |       |   |      |   |       |      |  |   |       |  
|------------------------------- |  | ---- | ----- | - | ---- | - | ----- | ---- |  | - | ----- | -
|                                |  | 2008 |       |   | 2007 |   |       | 2006 | 
|Trade receivables               |  | $    | 1,135 |   |      | $ | 1,599 |      |  | $ | 1,286 |  
|Allowance for doubtful accounts |  |      | (22   | ) |      |   | (10   | )    |  |   | (10   | )
|Derivatives due within one year |  |      | 111   |   |      |   | 22    |      |  |   |      |  
|Income taxes receivable         |  |      | 106   |   |      |   |      |      |  |   |      |  
|Other                           |  |      | 14    |   |      |   | 11    |      |  |   | 8     |  
|                                |  |      |       |   |      |   |       |      |  |   |       |  
|                                |  | $    | 1,344 |   |      | $ | 1,622 |      |  | $ | 1,284 |  
|                                |  |      |       |   |      |   |       |      |  |   |       |  

Sale of Accounts Receivable

As at December 31, 2008, the Companys ceiling on its securitization program to sell, on a revolving basis, accounts receivable to a third party
was $350 million. As at December 31, 2008, no accounts receivable had been sold under the program (2007 and 2006  nil). The agreement includes a program fee. During 2008, no accounts receivable had been sold under the program. The average
effective rate for 2007 was approximately 5.3% (2006  4.1%). Proceeds from revolving sales between the third party and the Company in 2007 totalled approximately $3.5 billion (2006  $3.1 billion). The securitization agreement has been
extended to March 31, 2009.

Note 7    Inventories

Effective January 1, 2008, the Company adopted CICA section 3031, Inventories, which replaced CICA section 3030 of the same name. The new
guidance provides additional measurement and disclosure requirements and requires the Company to reverse previous impairment write-downs when there is a change in the situation that caused the impairment. The adoption of this standard did not have
an impact on the Companys financial statements.



|                              |  |      |       |      |   |       |  |   |    
|----------------------------- |  | ---- | ----- | ---- | - | ----- |  | - | ---
|                              |  | 2008 |       | 2007 |   | 2006 
|Crude oil                     |  | $    | 480   |      | $ | 539   |  | $ | 119
|Natural gas                   |  |      | 222   |      |   | 192   |  |   | 193
|Refined petroleum products    |  |      | 263   |      |   | 409   |  |   | 89 
|Materials, supplies and other |  |      | 67    |      |   | 50    |  |   | 27 
|                              |  |      |       |      |   |       |  |   |    
|                              |  | $    | 1,032 |      | $ | 1,190 |  | $ | 428
|                              |  |      |       |      |   |       |  |   |    

Write-downs of inventories to net realizable value in 2008 amounted to $721 million (2007 
$11 million) primarily caused by the economic events in the fourth quarter of 2008.

Note 8    Property, Plant and Equipment

Refer to Note 1, Segmented Financial Information, which presents the Companys property, plant and equipment by segment.

Administrative costs related to exploration and development activities capitalized in 2008 were $43 million (2007  $48 million; 2006
 $68 million).

Costs of oil and gas properties, including major development projects, excluded from costs subject to depletion and
depreciation at December 31 were as follows:



|              |  |      |       |      |   |       |  |   |      
|------------- |  | ---- | ----- | ---- | - | ----- |  | - | -----
|              |  | 2008 |       | 2007 |   | 2006 
|Canada        |  | $    | 2,703 |      | $ | 1,954 |  | $ | 1,932
|International |  |      | 485   |      |   | 243   |  |   | 165  
|              |  |      |       |      |   |       |  |   |      
|              |  | $    | 3,188 |      | $ | 2,197 |  | $ | 2,097
|              |  |      |       |      |   |       |  |   |      



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The prices used in the ceiling test evaluation of the Companys crude oil and natural gas reserves
at December 31, 2008 were:



|                    |  |      |       |      |   |       |  |      |       |      |   |                                    |  |   |       |  |  
|------------------- |  | ---- | ----- | ---- | - | ----- |  | ---- | ----- | ---- | - | ---------------------------------- |  | - | ----- |  | -
|Canada              |  | 2009 |       | 2010 |   | 2011  |  | 2012 |       | 2013 |   | Priceincrease2013 to 2028(percent)
|Crude oil ($/bbl)   |  | $    | 52.88 |      | $ | 63.44 |  | $    | 67.26 |      | $ | 70.82                              |  | $ | 74.52 |  | 2
|Natural gas ($/mcf) |  |      | 7.04  |      |   | 7.53  |  |      | 7.87  |      |   | 8.30                               |  |   | 8.76  |  | 2

Note 9    Corporate Acquisition

In July 2007, the Company acquired a refinery in Lima, Ohio from The Premcor Refining Group Inc., an indirect wholly owned subsidiary of Valero Energy
Corporation through the purchase of all of the issued and outstanding shares of Lima Refining Company (Lima). The total cash consideration was U.S. $1.9 billion plus U.S. $540 million for the cost of feedstock and product inventory. The
results of Lima are included in the consolidated financial statements of the Company from its acquisition date. The Lima operations have been included in the downstream  U.S. refining and marketing segment in Note 1, Segmented Financial
Information. The operations of Lima are a self-sustaining foreign operation for foreign currency translation purposes.

The
allocation of the aggregate purchase price based on the estimated fair values of the net assets of Lima on its acquisition date was as follows:



|                                         |  |        |       |   |       |   |       |  
|---------------------------------------- |  | ------ | ----- | - | ----- | - | ----- | -
|                                         |  | U.S. $ |       |   | Cdn $ |  
|Net assets acquired                      |  |        |       |   |       |   |       |  
|Working capital                          |  | $      | 4     |   |       | $ | 4     |  
|Property, plant and equipment            |  |        | 1,455 |   |       |   | 1,542 |  
|Goodwill (1)                             |  |        | 506   |   |       |   | 536   |  
|Other assets                             |  |        | 25    |   |       |   | 26    |  
|Other long-term liabilities              |  |        | (86   | ) |       |   | (91   | )
|                                         |  |        |       |   |       |   |       |  
|                                         |  |        | 1,904 |   |       |   | 2,017 |  
|Feedstock and product inventory acquired |  |        | 540   |   |       |   | 572   |  
|                                         |  |        |       |   |       |   |       |  
|Total                                    |  | $      | 2,444 |   |       | $ | 2,589 |  
|                                         |  |        |       |   |       |   |       |  



|(1) | Allocated to U.S. refining and marketing in the Companys downstream
segment. For U.S. income tax purposes, goodwill is deductible and amortized over a 15-year period. Refer to Note 1, Segmented Financial Information.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Note 10    Joint Ventures

a) BP

On March 31, 2008, the Company completed a transaction with BP, which resulted in the formation of a 50/50 joint venture upstream entity and a 50/50
joint venture downstream entity.

The upstream entity is a partnership to which Husky has contributed the Sunrise oil sands assets with a
fair value of U.S. $2.5 billion as at January 1, 2008, plus capital expenditures for the three-month period ended March 31, 2008 of $15 million. BPs contribution was U.S. $250 million cash and a contribution receivable for the
balance of U.S. $2.25 billion and $15 million. The contribution receivable accretes at a rate of 6% and is payable between December 31, 2008 and December 31, 2015 with the final balance due and payable by December 31, 2015. The
upstream entity is included as part of the upstream segment.



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The downstream entity is a limited liability company (LLC) to which BP has contributed the
Toledo Refinery plus inventories and other net assets, less accounts payable and adjusted net earnings. Huskys contribution was U.S. $250 million cash and a contribution payable for the balance of U.S. $2.6 billion. Huskys share of the
value of the amounts contributed at March 31, 2008 by both entities to the downstream LLC is described below:



|                                                            |  |   |       |  
|----------------------------------------------------------- |  | - | ----- | -
|Cash                                                        |  | $ | 129   |  
|Inventory                                                   |  |   | 199   |  
|Property, plant and equipment (including adjusted earnings) |  |   | 1,928 |  
|Partner contribution receivable                             |  |   | 1,331 |  
|Other assets                                                |  |   | 2     |  
|Inventory related payables                                  |  |   | (12   | )
|Future income tax liability                                 |  |   | (658  | )
|                                                            |  |   |       |  
|Total contribution to downstream joint venture              |  | $ | 2,919 |  
|                                                            |  |   |       |  

The contribution payable accretes at a rate of 6% and is payable between December 31, 2008
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. The downstream entity
is included as part of the U.S. refining and marketing segment. This entity is a self-sustaining foreign operation.

Summarized below are
the results of operations, cash flows and financial position relating to the Companys proportional interests in its downstream joint venture:



|                                |  |      |       |  
|------------------------------- |  | ---- | ----- | -
|Results of Operations           |  | 2008 |      
|Revenues                        |  | $    | 1,843 |  
|Expenses                        |  |      | 2,020 |  
|                                |  |      |       |  
|Proportionate share of net loss |  | $    | (177  | )
|                                |  |      |       |  



|                                                             |  |      |      |  
|------------------------------------------------------------ |  | ---- | ---- | -
|Cash Flows                                                   |  | 2008 |     
|Cash flow  operating activities                             |  | $    | (90  | )
|Cash flow  financing activities                             |  |      |     |  
|Cash flow  investing activities                             |  |      | (58  | )
|                                                             |  |      |      |  
|Proportionate share of decrease in cash and cash equivalents |  | $    | (148 | )
|                                                             |  |      |      |  



|                                  |  |      |       |  
|--------------------------------- |  | ---- | ----- | -
|Financial Position                |  | 2008 |      
|Current assets                    |  | $    | 245   |  
|Long-term assets                  |  |      | 2,292 |  
|Current liabilities               |  |      | (42   | )
|Long-term liabilities             |  |      | (666  | )
|                                  |  |      |       |  
|Proportionate share of net assets |  | $    | 1,829 |  
|                                  |  |      |       |  

Both joint ventures are being accounted for using proportionate consolidation. The amounts
recorded in the consolidated financial statements represent the Companys 50% interest in the joint ventures.

b) CNOOC Southeast Asia Limited

In April 2008, a subsidiary of the Company, Husky Oil Madura Partnership (HOMP), entered into an agreement with CNOOC Southeast
Asia Limited (CNOOCSE), which resulted in the acquisition by CNOOCSE of a 50% equity interest in Husky Oil (Madura) Limited, a subsidiary of HOMP, for a consideration



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##### Table of Contents

of $127 million (U.S. $125 million) resulting in a gain of $69 million included in othernet in the Consolidated Statements of Earnings and
Comprehensive Income. Husky Oil (Madura) Limited holds a 100% interest in the Madura Strait Production Sharing Contract. The resulting joint venture arrangement is being accounted for using the proportionate consolidation method.

c) Results of Joint Ventures

The results of Huskys
proportionate share of its downstream joint venture with BP are described in Note 10 a). The results from the upstream joint venture with BP and the joint venture arrangement with CNOOCSE are considered to be in the pre-production phase. As a
result, any impact on the financial results of the Company subsequent to entering into these joint ventures is considered immaterial.

Note
11    Cash Flows  Change in Non-cash Working Capital

a) Change in non-cash working capital was as follows:



|                                                |  |      |       |      |   |      |      |  |   |      |  
|----------------------------------------------- |  | ---- | ----- | ---- | - | ---- | ---- |  | - | ---- | -
|                                                |  | 2008 |       | 2007 |   |      | 2006 | 
|Decrease (increase) in non-cash working capital |  |      |       |      |   |      |      |  |   |      |  
|Accounts receivable                             |  | $    | 453   |      | $ | (345 | )    |  | $ | (428 | )
|Inventories                                     |  |      | 522   |      |   | (212 | )    |  |   | 43   |  
|Prepaid expenses                                |  |      | 2     |      |   | 1    |      |  |   | 14   |  
|Accounts payable and accrued liabilities        |  |      | 428   |      |   | (190 | )    |  |   | 277  |  
|                                                |  |      |       |      |   |      |      |  |   |      |  
|Change in non-cash working capital              |  | $    | 1,405 |      | $ | (746 | )    |  | $ | (94  | )
|                                                |  |      |       |      |   |      |      |  |   |      |  
|Relating to:                                    |  |      |       |      |   |      |      |  |   |      |  
|Operating activities                            |  | $    | 888   |      | $ | (718 | )    |  | $ | 544  |  
|Financing activities                            |  |      | 146   |      |   | 65   |      |  |   | (678 | )
|Investing activities                            |  |      | 371   |      |   | (93  | )    |  |   | 40   |  

b) Other cash flow information:



|                   |  |      |     |      |   |      |  |   |    
|------------------ |  | ---- | --- | ---- | - | ---- |  | - | ---
|                   |  | 2008 |     | 2007 |   | 2006
|Cash taxes paid    |  | $    | 615 |      | $ | 926  |  | $ | 215
|Cash interest paid |  | $    | 103 |      | $ | 162  |  | $ | 147

Cash and cash equivalents at December 31, 2008, included $269 million of cash and $644
million of short-term investments with maturities less than 90 days.

Note 12    Goodwill



|                                                                            |  |      |     |      |   |     |      |  |   |    
|--------------------------------------------------------------------------- |  | ---- | --- | ---- | - | --- | ---- |  | - | ---
|                                                                            |  | 2008 |     | 2007 |   |     | 2006
|Balance at beginning of year                                                |  | $    | 660 |      | $ | 160 |      |  | $ | 160
|Acquired during the year                                                    |  |      |    |      |   | 536 |      |  |   |   
|Foreign currency translation of goodwill in self-sustaining U.S. operations |  |      | 119 |      |   | (36 | )    |  |   |   
|                                                                            |  |      |     |      |   |     |      |  |   |    
|Balance at end of year                                                      |  | $    | 779 |      | $ | 660 |      |  | $ | 160
|                                                                            |  |      |     |      |   |     |      |  |   |    

Note 13    Bank Operating Loans

At December 31, 2008, the Company had unsecured short-term borrowing lines of credit with banks totalling $370 million (2007  $270 million;
2006  $220 million). As at December 31, 2008, bank operating loans (excluding reclassified outstanding cheques) were nil (2007 and 2006  nil) and letters of credit under these lines of credit totalled $166 million (2007  $73
million; 2006  $19 million). Interest payable is based on Bankers Acceptance, U.S. LIBOR or prime rates. During 2008, the weighted average interest rate on short-term borrowings was approximately 7.1% (2007 and 2006  5.8%).



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The Sunrise Oil Sands Partnership has an unsecured demand credit facility of $10 million available for
general purposes. The Companys proportionate share is $5 million. As at December 31, 2008, there was no balance outstanding under this credit facility.

Note 14    Accounts Payable and Accrued Liabilities



|                         |  |      |       |      |   |       |  |   |      
|------------------------ |  | ---- | ----- | ---- | - | ----- |  | - | -----
|                         |  | 2008 |       | 2007 |   | 2006 
|Trade payables           |  | $    | 93    |      | $ | 23    |  | $ | 74   
|Accrued liabilities      |  |      | 1,813 |      |   | 1,743 |  |   | 1,322
|Dividend payable         |  |      | 425   |      |   | 280   |  |   | 212  
|Stock-based compensation |  |      | 24    |      |   | 159   |  |   | 234  
|Current income taxes     |  |      | 419   |      |   | 36    |  |   | 615  
|Other                    |  |      | 122   |      |   | 117   |  |   | 117  
|                         |  |      |       |      |   |       |  |   |      
|                         |  | $    | 2,896 |      | $ | 2,358 |  | $ | 2,574
|                         |  |      |       |      |   |       |  |   |      

Note 15    Long-term Debt



|                                   |      |              |       |                    |  |   |       |   |      |   |       |  |      |       |  |   |       |  |   |      
|---------------------------------- | ---- | ------------ | ----- | ------------------ |  | - | ----- | - | ---- | - | ----- |  | ---- | ----- |  | - | ----- |  | - | -----
|Maturity                           |      | Cdn $ Amount |       | U.S. $ Denominated
|                                   | 2008 |              |       | 2007               |  |   | 2006  |   | 2008 |   | 2007  |  | 2006
|Long-term debt                     |      |              |       |                    |  |   |       |   |      |   |       |  |      |       |  |   |       |  |   |      
|6.95% medium-term notes  Series E |      | $            |      |                    |  | $ | 203   |   |      | $ | 200   |  | $    |      |  | $ |      |  | $ |     
|6.25% notes 2012                   |      |              | 490   |                    |  |   | 395   |   |      |   | 466   |  |      | 400   |  |   | 400   |  |   | 400  
|7.55% debentures 2016              |      |              | 245   |                    |  |   | 198   |   |      |   | 233   |  |      | 200   |  |   | 200   |  |   | 200  
|6.20% notes 2017                   |      |              | 367   |                    |  |   | 296   |   |      |   |      |  |      | 300   |  |   | 300   |  |   |     
|6.15% notes 2019                   |      |              | 367   |                    |  |   | 296   |   |      |   | 350   |  |      | 300   |  |   | 300   |  |   | 300  
|8.90% capital securities           |      |              |      |                    |  |   | 223   |   |      |   | 262   |  |      |      |  |   | 225   |  |   | 225  
|6.80% notes 2037                   |      |              | 474   |                    |  |   | 445   |   |      |   |      |  |      | 387   |  |   | 450   |  |   |     
|Debt issue costs                   |      |              | (18   | )                  |  |   | (20   | ) |      |   |      |  |      |      |  |   |      |  |   |     
|Unwound interest rate swaps        |      |              | 32    |                    |  |   | 37    |   |      |   |      |  |      |      |  |   |      |  |   |     
|                                   |      |              |       |                    |  |   |       |   |      |   |       |  |      |       |  |   |       |  |   |      
|                                   |      | $            | 1,957 |                    |  | $ | 2,073 |   |      | $ | 1,511 |  | $    | 1,587 |  | $ | 1,875 |  | $ | 1,125
|                                   |      |              |       |                    |  |   |       |   |      |   |       |  |      |       |  |   |       |  |   |      
|Long-term debt due within one year |      |              |       |                    |  |   |       |   |      |   |       |  |      |       |  |   |       |  |   |      
|Bridge financing                   |      | $            |      |                    |  | $ | 741   |   |      | $ |      |  | $    |      |  | $ | 750   |  | $ |     
|6.85% medium-term notes  Series B |      |              |      |                    |  |   |      |   |      |   | 100   |  |      |      |  |   |      |  |   |     
|                                   |      |              |       |                    |  |   |       |   |      |   |       |  |      |       |  |   |       |  |   |      
|                                   |      | $            |      |                    |  | $ | 741   |   |      | $ | 100   |  | $    |      |  | $ | 750   |  | $ |     
|                                   |      |              |       |                    |  |   |       |   |      |   |       |  |      |       |  |   |       |  |   |      

Interest  net for the years ended December 31 was as follows:



|                        |  |      |     |   |      |   |     |      |  |   |     |  
|----------------------- |  | ---- | --- | - | ---- | - | --- | ---- |  | - | --- | -
|                        |  | 2008 |     |   | 2007 |   |     | 2006 | 
|Interest expense        |  |      |     |   |      |   |     |      |  |   |     |  
|Long-term debt          |  | $    | 154 |   |      | $ | 151 |      |  | $ | 130 |  
|Contribution payable    |  |      | 63  |   |      |   |    |      |  |   |    |  
|Short-term debt         |  |      | 5   |   |      |   | 6   |      |  |   | 5   |  
|                        |  |      |     |   |      |   |     |      |  |   |     |  
|                        |  |      | 222 |   |      |   | 157 |      |  |   | 135 |  
|Amount capitalized      |  |      |    |   |      |   | (19 | )    |  |   | (33 | )
|                        |  |      |     |   |      |   |     |      |  |   |     |  
|                        |  |      | 222 |   |      |   | 138 |      |  |   | 102 |  
|Interest income         |  |      |     |   |      |   |     |      |  |   |     |  
|Contribution receivable |  |      | (55 | ) |      |   |    |      |  |   |    |  
|Other                   |  |      | (20 | ) |      |   | (8  | )    |  |   | (10 | )
|                        |  |      |     |   |      |   |     |      |  |   |     |  
|                        |  |      | (75 | ) |      |   | (8  | )    |  |   | (10 | )
|                        |  |      |     |   |      |   |     |      |  |   |     |  
|                        |  | $    | 147 |   |      | $ | 130 |      |  | $ | 92  |  
|                        |  |      |     |   |      |   |     |      |  |   |     |  



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Foreign exchange for the years ended December 31 was as follows:



|                                                                     |  |      |      |   |      |   |      |      |  |   |     |  
|-------------------------------------------------------------------- |  | ---- | ---- | - | ---- | - | ---- | ---- |  | - | --- | -
|                                                                     |  | 2008 |      |   | 2007 |   |      | 2006 | 
|(Gain) loss on translation of U.S. dollar denominated long-term debt |  | $    | 217  |   |      | $ | (197 | )    |  | $ | (7  | )
|Cross currency swaps                                                 |  |      | (83  | ) |      |   | 62   |      |  |   | 4   |  
|Contribution receivable                                              |  |      | (228 | ) |      |   |     |      |  |   |    |  
|Other (gains) losses                                                 |  |      | (241 | ) |      |   | 84   |      |  |   | (21 | )
|                                                                     |  |      |      |   |      |   |      |      |  |   |     |  
|                                                                     |  | $    | (335 | ) |      | $ | (51  | )    |  | $ | (24 | )
|                                                                     |  |      |      |   |      |   |      |      |  |   |     |  

Other gains and losses include realized and unrealized foreign exchange gains and losses on
working capital.

Credit Facilities

The revolving syndicated credit facility allows the Company to borrow up to $1.25 billion in either Canadian or U.S. currency from a group of banks on an unsecured basis. The facility is structured as a five-year committed revolving credit
facility. 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.

The Companys $150 million revolving bilateral credit facilities have substantially the same terms as the
syndicated credit facility.

In July 2007, the Company obtained U.S. $1.5 billion of short-term bridge financing at an interest rate based
on U.S. LIBOR, maturing June 26, 2008, to facilitate closing the acquisition of the Lima, Ohio refinery. On September 11, 2007, the Company refinanced U.S. $750 million with long-term notes. The remaining bridge financing of U.S. $750
million was repaid in June 2008.

As at December 31, 2008, there were no borrowings under the syndicated credit facility or the
bilateral credit facilities. See Note 23 for debt covenants.

Notes and Debentures

On September 21, 2006, Husky filed a shelf prospectus, which enabled the Company to offer up to U.S. $1.0 billion of debt securities in the United
States until October 21, 2008. During the 25 month period that the prospectus remained effective, debt securities could be offered in amounts, at prices and on terms to be determined based on market conditions at the time of sale and set forth
in an accompanying prospectus supplement. In 2007, U.S. $750 million of debt securities were issued under this shelf prospectus.

The 6.25%
and the 6.15% notes represent unsecured securities under a trust indenture dated June 14, 2002. Interest is payable semi-annually.

The 7.55% debentures represent unsecured securities under a trust indenture dated October 31, 1996. Interest is payable semi-annually.

The 6.20% and the 6.80% notes represent unsecured securities under a trust indenture dated September 11, 2007. During 2008, the Company repurchased U.S. $63 million of the 6.80% notes. Interest is payable
semi-annually.

The 8.90% capital securities represented unsecured securities under an indenture dated August 10, 1998. On
June 12, 2008, the Company initiated a cash tender offer to purchase any and all of the 8.90% capital securities.



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The tender offer expired on July 11, 2008 at which date U.S. $214 million or 95% of the capital securities had been tendered. The settlement date
occurred July 11, 2008. The remaining capital securities were redeemed on August 14, 2008.

The 6.95% medium-term notes Series E
represented unsecured securities under a trust indenture dated May 4, 1999 and were redeemed in August 2008 at a redemption price, including accrued interest, of $208 million.

The 6.85% medium-term notes Series B represented unsecured securities under a trust indenture dated February 3, 1997 and matured in 2007.

The 7.125% notes represented unsecured securities under a trust indenture dated October 31, 1996 and matured in 2006.

The 8.45% senior secured bonds represented securities under a trust indenture dated July 20, 1999 that were redeemed in full on February 1,
2006.

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.

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

Commencing in 2007, debt issue costs have been
reclassified to long-term debt with the adoption of CICA section 3855, Financial Instruments  Recognition and Measurement. Previously, these deferred costs were included in other assets. As at December 31, 2006, other assets
included $12 million of deferred debt issue costs.

The unamortized portion of the gain on previously unwound interest rate swaps that
would be designated as fair value hedges is included in the carrying value of long-term debt with the adoption of Canadian Financial Instruments Standards in 2007.

Note 16    Other Long-term Liabilities



|                                   |  |      |     |      |   |      |  |   |    
|---------------------------------- |  | ---- | --- | ---- | - | ---- |  | - | ---
|                                   |  | 2008 |     | 2007 |   | 2006
|Asset retirement obligations       |  | $    | 711 |      | $ | 662  |  | $ | 622
|Cross currency swaps (1)           |  |      | 19  |      |   | 107  |  |   | 40 
|Interest rate swaps                |  |      |    |      |   |     |  |   | 37 
|Employee future benefits (note 20) |  |      | 81  |      |   | 69   |  |   | 30 
|Capital lease obligations          |  |      | 44  |      |   | 36   |  |   |   
|Stock-based compensation (note 19) |  |      |    |      |   | 13   |  |   | 4  
|Other                              |  |      | 43  |      |   | 31   |  |   | 23 
|                                   |  |      |     |      |   |      |  |   |    
|                                   |  | $    | 898 |      | $ | 918  |  | $ | 756
|                                   |  |      |     |      |   |      |  |   |    



|(1) | Refer to Note 22, Financial Instruments and Risk
Factors.
|--- | -----------------------------------------------------------

Asset Retirement Obligations

At December 31, 2008, the estimated total undiscounted inflation adjusted amount required to settle the asset retirement obligations was $5.4
billion. These obligations will be settled based on the useful lives of the underlying assets, which currently extend an average of 30 years into the future. This amount has been discounted using credit-adjusted risk free rates ranging from 6.2% to
9.6%.



PAGE 25



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##### Table of Contents

Changes to the asset retirement obligations were as follows:



|                                                  |  |      |     |   |      |   |     |      |  |   |     |  
|------------------------------------------------- |  | ---- | --- | - | ---- | - | --- | ---- |  | - | --- | -
|                                                  |  | 2008 |     |   | 2007 |   |     | 2006 | 
|Asset retirement obligations at beginning of year |  | $    | 662 |   |      | $ | 622 |      |  | $ | 557 |  
|Liabilities incurred/acquired                     |  |      | 56  |   |      |   | 57  |      |  |   | 35  |  
|Liabilities disposed                              |  |      | (5  | ) |      |   | (13 | )    |  |   | (1  | )
|Liabilities settled                               |  |      | (56 | ) |      |   | (51 | )    |  |   | (36 | )
|Revisions                                         |  |      |    |   |      |   |    |      |  |   | 22  |  
|Accretion (1)                                     |  |      | 54  |   |      |   | 47  |      |  |   | 45  |  
|                                                  |  |      |     |   |      |   |     |      |  |   |     |  
|Asset retirement obligations at end of year       |  | $    | 711 |   |      | $ | 662 |      |  | $ | 622 |  
|                                                  |  |      |     |   |      |   |     |      |  |   |     |  



|(1) | Accretion is included in cost of sales and operating expenses.
|--- | --------------------------------------------------------------

Note 17    Income Taxes

The provision for income taxes in the Consolidated Statements of Earnings and Comprehensive Income reflects an effective tax rate which differs from the
expected statutory tax rate. Differences for the years ended December 31 were accounted for as follows:



|                                                                |  |      |       |   |      |   |       |      |  |   |       |  
|--------------------------------------------------------------- |  | ---- | ----- | - | ---- | - | ----- | ---- |  | - | ----- | -
|                                                                |  | 2008 |       |   | 2007 |   |       | 2006 | 
|Earnings (loss) before income taxes                             |  |      |       |   |      |   |       |      |  |   |       |  
|Canada                                                          |  | $    | 5,689 |   |      | $ | 3,763 |      |  | $ | 3,276 |  
|United States                                                   |  |      | (817  | ) |      |   | 95    |      |  |   | 15    |  
|Other foreign jurisdictions                                     |  |      | 278   |   |      |   | 269   |      |  |   | 215   |  
|                                                                |  |      |       |   |      |   |       |      |  |   |       |  
|                                                                |  |      | 5,150 |   |      |   | 4,127 |      |  |   | 3,506 |  
|Statutory income tax rate (percent)                             |  |      | 30.6  |   |      |   | 32.7  |      |  |   | 35.7  |  
|                                                                |  |      |       |   |      |   |       |      |  |   |       |  
|Expected income tax                                             |  |      | 1,576 |   |      |   | 1,350 |      |  |   | 1,252 |  
|Effect on income tax of:                                        |  |      |       |   |      |   |       |      |  |   |       |  
|Royalties, lease rentals and mineral taxes payable to the crown |  |      |      |   |      |   |      |      |  |   | 10    |  
|Resource allowance on Canadian production income                |  |      |      |   |      |   |      |      |  |   | (35   | )
|Change in statutory tax rate                                    |  |      |      |   |      |   | (395  | )    |  |   | (328  | )
|Rate benefit on partnership earnings                            |  |      | (60   | ) |      |   | (53   | )    |  |   | (97   | )
|Capital gains and losses                                        |  |      | (19   | ) |      |   | (24   | )    |  |   | (1    | )
|Foreign jurisdictions                                           |  |      | (102  | ) |      |   | 8     |      |  |   | (6    | )
|Non-deductible capital taxes                                    |  |      |      |   |      |   |      |      |  |   | (17   | )
|Other  net                                                     |  |      | 1     |   |      |   | 27    |      |  |   | 2     |  
|                                                                |  |      |       |   |      |   |       |      |  |   |       |  
|Income tax expense                                              |  | $    | 1,396 |   |      | $ | 913   |      |  | $ | 780   |  
|                                                                |  |      |       |   |      |   |       |      |  |   |       |  

During 2007, a tax benefit of $395 million was recognized as a result of reductions in the
Canadian federal tax rate, compared with a benefit of $328 million in 2006 as a result of reductions in both federal and provincial tax rates. No similar tax benefits were recognized in 2008.



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The future income tax liabilities at December 31 comprised the tax effect of temporary differences
as follows:



|                                              |  |      |       |      |   |       |  |   |      
|--------------------------------------------- |  | ---- | ----- | ---- | - | ----- |  | - | -----
|                                              |  | 2008 |       | 2007 |   | 2006 
|Future tax liabilities                        |  |      |       |      |   |       |  |   |      
|Property, plant and equipment                 |  | $    | 5,226 |      | $ | 4,081 |  | $ | 3,607
|Foreign exchange gains taxable on realization |  |      | 92    |      |   | 131   |  |   | 48   
|Other temporary differences                   |  |      | 2     |      |   | 1     |  |   | 1    
|                                              |  |      |       |      |   |       |  |   |      
|                                              |  |      | 5,320 |      |   | 4,213 |  |   | 3,656
|Future tax assets                             |  |      |       |      |   |       |  |   |      
|Asset retirement obligations                  |  |      | 207   |      |   | 186   |  |   | 194  
|Loss carry forwards                           |  |      | 348   |      |   |      |  |   | 2    
|Provincial royalty rebates                    |  |      |      |      |   |      |  |   | 2    
|Other temporary differences                   |  |      | 41    |      |   | 70    |  |   | 86   
|                                              |  |      |       |      |   |       |  |   |      
|                                              |  |      | 596   |      |   | 256   |  |   | 284  
|                                              |  |      |       |      |   |       |  |   |      
|                                              |  | $    | 4,724 |      | $ | 3,957 |  | $ | 3,372
|                                              |  |      |       |      |   |       |  |   |      

Note 18    Commitments and Contingencies

Certain former owners of interests in the upgrading assets retained a 20-year upside financial interest expiring in 2014 which requires payments to them
when the average differential between heavy crude oil feedstock and synthetic crude oil exceeds $6.50 per barrel. The calculation is based on a two-year rolling average of the differential. During 2008, the Company capitalized $73 million (2007
 $84 million; 2006  $85 million) of payments under this arrangement.

At December 31, 2008, the Company had commitments
for non-cancellable operating leases and other long-term agreements that require the following minimum future payments:



|                                              |  |      |       |      |   |       |  |      |     |      |   |           |  |       |     |  |   |       |  |   |       
|--------------------------------------------- |  | ---- | ----- | ---- | - | ----- |  | ---- | --- | ---- | - | --------- |  | ----- | --- |  | - | ----- |  | - | ------
|                                              |  | 2009 |       | 2010 |   | 2011  |  | 2012 |     | 2013 |   | After2013 |  | Total
|Long-term debt and interest                   |  | $    | 127   |      | $ | 127   |  | $    | 127 |      | $ | 599       |  | $     | 96  |  | $ | 2,478 |  | $ | 3,554 
|Operating leases                              |  |      | 115   |      |   | 106   |  |      | 81  |      |   | 74        |  |       | 62  |  |   | 28    |  |   | 466   
|Firm transportation agreements                |  |      | 144   |      |   | 90    |  |      | 52  |      |   | 55        |  |       | 47  |  |   | 249   |  |   | 637   
|Unconditional purchase obligations            |  |      | 2,775 |      |   | 897   |  |      | 455 |      |   | 77        |  |       | 36  |  |   | 162   |  |   | 4,402 
|Lease rentals and exploration work agreements |  |      | 178   |      |   | 142   |  |      | 167 |      |   | 105       |  |       | 114 |  |   | 314   |  |   | 1,020 
|Asset retirement obligations                  |  |      | 29    |      |   | 31    |  |      | 27  |      |   | 26        |  |       | 26  |  |   | 5,093 |  |   | 5,232 
|                                              |  |      |       |      |   |       |  |      |     |      |   |           |  |       |     |  |   |       |  |   |       
|                                              |  | $    | 3,368 |      | $ | 1,393 |  | $    | 909 |      | $ | 936       |  | $     | 381 |  | $ | 8,324 |  | $ | 15,311
|                                              |  |      |       |      |   |       |  |      |     |      |   |           |  |       |     |  |   |       |  |   |       

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 by reason thereof 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 future income taxes.



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##### Table of Contents

Note 19    Share Capital

The Companys authorized share capital is as follows:

Common shares  an unlimited number of no par value.

Preferred shares  an unlimited number of no
par value, none outstanding.

Common Shares

Changes to issued share capital were as follows:



|                  |  |                 |  |        |      
|----------------- |  | --------------- |  | ------ | -----
|                  |  | Number ofShares |  | Amount
|December 31, 2005 |  | 848,250,156     |  | $      | 3,523
|Options exercised |  | 286,862         |  |        | 10   
|                  |  |                 |  |        |      
|December 31, 2006 |  | 848,537,018     |  |        | 3,533
|Options exercised |  | 423,292         |  |        | 18   
|                  |  |                 |  |        |      
|December 31, 2007 |  | 848,960,310     |  |        | 3,551
|Options exercised |  | 394,500         |  |        | 17   
|                  |  |                 |  |        |      
|December 31, 2008 |  | 849,354,810     |  | $      | 3,568
|                  |  |                 |  |        |      

Stock Options

At December 31, 2008, 50.5 million common shares were reserved for issuance under the Company stock option plan. The stock option plan is a tandem plan that provides the stock option holder with the right to
exercise the option 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 date of the award. When the
option is surrendered for cash, the cash payment is the difference between the weighted average trading price of the Companys common shares on the trading day prior to the surrender date and the exercise price of the option.

Under the terms of the original stock option plan, the options awarded have a maximum term of five years and vest over three years on the basis of
one-third per year. Effective February 26, 2007, the Board of Directors approved amendments to the Companys stock option plan to also provide for performance vesting of stock options. Shareholder ratification was obtained at the Annual
and Special Meeting of Shareholders on April 19, 2007. Performance options granted may vest in up to one-third increments if the Companys annual total shareholder return (stock price appreciation and cumulative dividends on a reinvested
basis) falls within certain percentile ranks relative to its industry peer group. 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. This expense is recognized over the three-year vesting period of the performance options.

As a result of
the special $0.25 per share dividend that was declared in February 2007, a downward adjustment of $0.175 was made to the exercise price of all outstanding stock options effective February 28, 2007, in accordance with the terms of the stock
option plan under which the options were issued.



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



|                            |  |                             |   |  |                               |       |                                        |   |                               |      
|--------------------------- |  | --------------------------- | - |  | ----------------------------- | ----- | -------------------------------------- | - | ----------------------------- | -----
|                            |  | Number ofOptions(thousands) |   |  | WeightedAverageExercisePrices |       | WeightedAverageContractualLife (years) |   | OptionsExercisable(thousands)
|December 31, 2005           |  | 14,570                      |   |  | $                             | 12.91 |                                        | 3 |                               | 3,066
|Granted                     |  | 1,804                       |   |  | $                             | 35.71 |                                        | 4 |                               |      
|Exercised for common shares |  | (287                        | ) |  | $                             | 11.15 |                                        | 2 |                               |      
|Surrendered for cash        |  | (3,902                      | ) |  | $                             | 11.97 |                                        | 2 |                               |      
|Forfeited                   |  | (529                        | ) |  | $                             | 21.41 |                                        | 3 |                               |      
|                            |  |                             |   |  |                               |       |                                        |   |                               |      
|December 31, 2006           |  | 11,656                      |   |  | $                             | 16.40 |                                        | 3 |                               | 4,463
|Granted                     |  | 26,926                      |   |  | $                             | 41.65 |                                        | 4 |                               |      
|Exercised for common shares |  | (423                        | ) |  | $                             | 11.84 |                                        | 1 |                               |      
|Surrendered for cash        |  | (5,147                      | ) |  | $                             | 13.40 |                                        | 2 |                               |      
|Forfeited                   |  | (2,881                      | ) |  | $                             | 40.41 |                                        | 4 |                               |      
|                            |  |                             |   |  |                               |       |                                        |   |                               |      
|December 31, 2007           |  | 30,131                      |   |  | $                             | 37.18 |                                        | 4 |                               | 4,494
|Granted                     |  | 7,596                       |   |  | $                             | 41.18 |                                        | 5 |                               |      
|Exercised for common shares |  | (395                        | ) |  | $                             | 13.65 |                                        | 1 |                               |      
|Surrendered for cash        |  | (4,132                      | ) |  | $                             | 22.50 |                                        | 1 |                               |      
|Forfeited                   |  | (2,373                      | ) |  | $                             | 41.58 |                                        | 3 |                               |      
|                            |  |                             |   |  |                               |       |                                        |   |                               |      
|December 31, 2008           |  | 30,827                      |   |  | $                             | 40.10 |                                        | 3 |                               | 7,239
|                            |  |                             |   |  |                               |       |                                        |   |                               |      



|                        |  |                             |  |                               |       |                                        |   |                             |       |                               |   |      
|----------------------- |  | --------------------------- |  | ----------------------------- | ----- | -------------------------------------- | - | --------------------------- | ----- | ----------------------------- | - | -----
|As at December 31, 2008 |  | Outstanding Options         |  | Options Exercisable          
|Range of Exercise Price |  | Number ofOptions(thousands) |  | WeightedAverageExercisePrices |       | WeightedAverageContractualLife (years) |   | Number ofOptions(thousands) |       | WeightedAverageExercisePrices
|$11.67 - $11.99         |  | 1,138                       |  | $                             | 11.74 |                                        |  |                             | 1,138 |                               | $ | 11.74
|$12.00 - $17.99         |  | 52                          |  | $                             | 15.46 |                                        | 1 |                             | 52    |                               | $ | 15.46
|$18.00 - $27.99         |  | 224                         |  | $                             | 26.43 |                                        | 2 |                             | 224   |                               | $ | 26.43
|$28.00 - $36.99         |  | 2,124                       |  | $                             | 32.40 |                                        | 4 |                             | 314   |                               | $ | 35.49
|$37.00 - $39.99         |  | 833                         |  | $                             | 39.49 |                                        | 4 |                             | 133   |                               | $ | 38.20
|$40.00 - $40.99         |  | 2,417                       |  | $                             | 40.88 |                                        | 4 |                             | 285   |                               | $ | 40.85
|$41.00 - $45.02         |  | 24,039                      |  | $                             | 42.24 |                                        | 4 |                             | 5,093 |                               | $ | 41.68
|                        |  |                             |  |                               |       |                                        |   |                             |       |                               |   |      
|                        |  | 30,827                      |  | $                             | 40.10 |                                        | 3 |                             | 7,239 |                               | $ | 35.95
|                        |  |                             |  |                               |       |                                        |   |                             |       |                               |   |      

Dividends

During 2008, the Company declared dividends of $1.73 per common share (2007  $1.33 per common share; 2006  $0.75 per common share), including a special dividend of $0.25 per common share in 2007.

Note 20    Employee Future Benefits

a) Canada

The Company currently provides a defined contribution pension plan for all qualified employees. The Company also
maintains a defined benefit pension plan, which is closed to new entrants, and all current participants are vested. The Company also provides certain health and dental coverage to its retirees, which is accrued over the expected average remaining
service life of the employees.



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Defined Benefit Pension Plan

Weighted average long-term assumptions are based on independent historical and projected references and are noted below:



|                                                            |  |      |  |      |  |     
|----------------------------------------------------------- |  | ---- |  | ---- |  | ----
|                                                            |  | 2008 |  | 2007 |  | 2006
|Discount rate (percent)                                     |  | 6.3  |  | 5.0  |  | 5.0 
|Long-term rate of increase in compensation levels (percent) |  | 5.0  |  | 5.0  |  | 5.0 
|Long-term rate of return on plan assets (percent)           |  | 7.0  |  | 7.5  |  | 7.5 

The discount rate used at the end of 2008 to determine the accrued benefit obligation was 6.3%.

The long-term rate of return on the assets was determined based on managements best estimate and the historical rates of return,
adjusted periodically. The rate at the end of 2008 was 7.0%.

The status of the defined benefit pension plan at December 31 was as
follows:

Benefit Obligation



|                                      |  |      |     |   |      |   |     |      |  |   |     |  
|------------------------------------- |  | ---- | --- | - | ---- | - | --- | ---- |  | - | --- | -
|                                      |  | 2008 |     |   | 2007 |   |     | 2006 | 
|Benefit obligation, beginning of year |  | $    | 150 |   |      | $ | 149 |      |  | $ | 138 |  
|Current service cost                  |  |      | 2   |   |      |   | 2   |      |  |   | 3   |  
|Interest cost                         |  |      | 8   |   |      |   | 7   |      |  |   | 7   |  
|Benefits paid                         |  |      | (9  | ) |      |   | (8  | )    |  |   | (7  | )
|Actuarial (gains) losses              |  |      | (19 | ) |      |   |    |      |  |   | 8   |  
|                                      |  |      |     |   |      |   |     |      |  |   |     |  
|Benefit obligation, end of year       |  | $    | 132 |   |      | $ | 150 |      |  | $ | 149 |  
|                                      |  |      |     |   |      |   |     |      |  |   |     |  

Fair Value of Plan Assets



|                                             |  |      |     |   |      |   |     |      |  |   |     |  
|-------------------------------------------- |  | ---- | --- | - | ---- | - | --- | ---- |  | - | --- | -
|                                             |  | 2008 |     |   | 2007 |   |     | 2006 | 
|Fair value of plan assets, beginning of year |  | $    | 141 |   |      | $ | 132 |      |  | $ | 108 |  
|Contributions                                |  |      | 6   |   |      |   | 10  |      |  |   | 13  |  
|Benefits paid                                |  |      | (9  | ) |      |   | (8  | )    |  |   | (7  | )
|Expected return on plan assets               |  |      | 10  |   |      |   | 10  |      |  |   | 8   |  
|Gain (loss) on plan assets                   |  |      | (38 | ) |      |   | (3  | )    |  |   | 10  |  
|                                             |  |      |     |   |      |   |     |      |  |   |     |  
|Fair value of plan assets, end of year       |  | $    | 110 |   |      | $ | 141 |      |  | $ | 132 |  
|                                             |  |      |     |   |      |   |     |      |  |   |     |  

Funded Status of Plan



|                                |  |      |      |   |      |   |      |      |  |   |      |  
|------------------------------- |  | ---- | ---- | - | ---- | - | ---- | ---- |  | - | ---- | -
|                                |  | 2008 |      |   | 2007 |   |      | 2006 | 
|Fair value of plan assets       |  | $    | 110  |   |      | $ | 141  |      |  | $ | 132  |  
|Benefit obligation              |  |      | (132 | ) |      |   | (150 | )    |  |   | (149 | )
|                                |  |      |      |   |      |   |      |      |  |   |      |  
|Excess obligation               |  |      | (22  | ) |      |   | (9   | )    |  |   | (17  | )
|Unrecognized past service costs |  |      | 2    |   |      |   | 3    |      |  |   | 3    |  
|Unrecognized losses             |  |      | 50   |   |      |   | 32   |      |  |   | 33   |  
|                                |  |      |      |   |      |   |      |      |  |   |      |  
|Accrued benefit asset           |  | $    | 30   |   |      | $ | 26   |      |  | $ | 19   |  
|                                |  |      |      |   |      |   |      |      |  |   |      |  



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Husky adheres to a Statement of Investment Policies and Procedures (the Policy). The 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 Companys actuaries perform valuations annually as at December 31 for the defined benefit pension plan.

The composition of the defined benefit pension plan assets was as follows:



|                                   |  |      |   |  |      |   |  |      |  
|---------------------------------- |  | ---- | - |  | ---- | - |  | ---- | -
|                                   |  | 2008 |   |  | 2007 |   |  | 2006 |  
|U.S. common equities               |  | 1    | % |  | 1    | % |  | 1    | %
|Canadian common equities           |  | 26   |   |  | 30   |   |  | 30   |  
|International equity mutual funds  |  | 23   |   |  | 27   |   |  | 30   |  
|Canadian government bonds          |  | 18   |   |  | 14   |   |  | 16   |  
|Canadian corporate bonds           |  | 4    |   |  | 4    |   |  | 3    |  
|International fixed income         |  | 1    |   |  | 2    |   |  |     |  
|Canadian fixed income mutual funds |  | 25   |   |  | 20   |   |  | 19   |  
|Cash and receivables               |  | 2    |   |  | 2    |   |  | 1    |  
|                                   |  |      |   |  |      |   |  |      |  
|Total                              |  | 100  | % |  | 100  | % |  | 100  | %
|                                   |  |      |   |  |      |   |  |      |  

During 2008, Husky contributed $6 million to the defined benefit pension plan assets, $3.8 million
of which was in respect of additional contributions as a result of the plans deficiency. Husky currently plans to contribute $5.2 million in 2009.

The Company amortizes the portion of the unrecognized actuarial gains or losses that exceed 10% of the greater of the accrued benefit obligation or the market-related value of pension plan assets. The market-related
value of pension plan assets is the fair value of the assets. The gains or losses that are in excess of 10% are amortized over the expected future years of service, which is currently seven years.

The past service costs are amortized over the expected future years of service.

Post-retirement Health and Dental Care Plan

The discount rate used in the calculation of the benefit obligation was 6.6%. The average health care cost trend used was 9.0% which is reduced by 0.50% until 2016. The average dental care cost trend used was 4%, which remains constant.

The status of the post-retirement health and dental care plan at December 31 was as follows:

Benefit Obligation



|                                      |  |      |    |   |      |   |    |      |  |   |   
|------------------------------------- |  | ---- | -- | - | ---- | - | -- | ---- |  | - | --
|                                      |  | 2008 |    |   | 2007 |   |    | 2006
|Benefit obligation, beginning of year |  | $    | 54 |   |      | $ | 49 |      |  | $ | 33
|Current service cost                  |  |      | 4  |   |      |   | 4  |      |  |   | 2 
|Interest cost                         |  |      | 3  |   |      |   | 2  |      |  |   | 2 
|Benefits paid                         |  |      | (1 | ) |      |   | (1 | )    |  |   |  
|Actuarial (gains) losses              |  |      | (7 | ) |      |   |   |      |  |   | 12
|                                      |  |      |    |   |      |   |    |      |  |   |   
|Benefit obligation, end of year       |  | $    | 53 |   |      | $ | 54 |      |  | $ | 49
|                                      |  |      |    |   |      |   |    |      |  |   |   



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##### Table of Contents

Funded Status of Plan



|                          |  |      |     |   |      |   |     |      |  |   |     |  
|------------------------- |  | ---- | --- | - | ---- | - | --- | ---- |  | - | --- | -
|                          |  | 2008 |     |   | 2007 |   |     | 2006 | 
|Benefit obligation        |  | $    | (53 | ) |      | $ | (54 | )    |  | $ | (49 | )
|Unrecognized losses       |  |      | 10  |   |      |   | 17  |      |  |   | 19  |  
|                          |  |      |     |   |      |   |     |      |  |   |     |  
|Accrued benefit liability |  | $    | (43 | ) |      | $ | (37 | )    |  | $ | (30 | )
|                          |  |      |     |   |      |   |     |      |  |   |     |  

The assumed health care cost trend can have a significant effect on the amounts reported for
Huskys post-retirement health and dental care plan. A one percent increase and decrease in the assumed trend rate would have the following effect:



|                                                     |  |             |      |             |   |      |  
|---------------------------------------------------- |  | ----------- | ---- | ----------- | - | ---- | -
|                                                     |  | 1% Increase |      | 1% Decrease |  
|Effect on total service and interest cost components |  | $           | 1.8  |             | $ | (1.4 | )
|Effect on post-retirement benefit obligation         |  | $           | 11.4 |             | $ | (8.9 | )

Pension Expense and Post-retirement Health and Dental Care Expense

The expenses for the years ended December 31 were as follows:

Pension Expense



|                                     |  |      |     |   |      |   |     |      |  |   |    |  
|------------------------------------ |  | ---- | --- | - | ---- | - | --- | ---- |  | - | -- | -
|                                     |  | 2008 |     |   | 2007 |   |     | 2006 | 
|Defined benefit pension plan         |  |      |     |   |      |   |     |      |  |   |    |  
|Employer current service cost        |  | $    | 2   |   |      | $ | 2   |      |  | $ | 3  |  
|Interest cost                        |  |      | 8   |   |      |   | 7   |      |  |   | 7  |  
|Expected return on plan assets       |  |      | (10 | ) |      |   | (10 | )    |  |   | (8 | )
|Amortization of net actuarial losses |  |      | 3   |   |      |   | 3   |      |  |   | 3  |  
|                                     |  |      |     |   |      |   |     |      |  |   |    |  
|                                     |  |      | 3   |   |      |   | 2   |      |  |   | 5  |  
|Defined contribution pension plan    |  |      | 20  |   |      |   | 18  |      |  |   | 16 |  
|                                     |  |      |     |   |      |   |     |      |  |   |    |  
|Total expense                        |  | $    | 23  |   |      | $ | 20  |      |  | $ | 21 |  
|                                     |  |      |     |   |      |   |     |      |  |   |    |  

Post-retirement Health and Dental Care Expense



|                                     |  |      |   |      |   |      |  |   |  
|------------------------------------ |  | ---- | - | ---- | - | ---- |  | - | -
|                                     |  | 2008 |   | 2007 |   | 2006
|Employer current service cost        |  | $    | 4 |      | $ | 4    |  | $ | 2
|Interest cost                        |  |      | 3 |      |   | 2    |  |   | 2
|Amortization of net actuarial losses |  |      | 1 |      |   | 1    |  |   | 
|                                     |  |      |   |      |   |      |  |   |  
|Total expense                        |  | $    | 8 |      | $ | 7    |  | $ | 4
|                                     |  |      |   |      |   |      |  |   |  

Future Benefit Payments

The following table discloses the current estimate of future benefit payments:



|            |  |                              |    |                                            |   |   
|----------- |  | ---------------------------- | -- | ------------------------------------------ | - | --
|            |  | Defined Benefit Pension Plan |    | Post-retirement Healthand Dental Care Plan
|2009        |  | $                            | 9  |                                            | $ | 1 
|2010        |  |                              | 9  |                                            |   | 1 
|2011        |  |                              | 10 |                                            |   | 1 
|2012        |  |                              | 10 |                                            |   | 1 
|2013        |  |                              | 10 |                                            |   | 2 
|2014 - 2018 |  |                              | 53 |                                            |   | 12



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##### Table of Contents

b) United States

Defined Benefit Pension Plan

As at December 31, 2008, the benefit obligation was $5 million (2007  $1 million)
and the fair value of the plan assets was $4 million (2007  $1 million). The discount rate used at the end of 2008 to determine the accrued benefit obligation was 6.0% (2007  6.1%). During 2008, Husky contributed $2 million to the
defined benefit pension plan assets and currently plans to contribute $3 million in 2009.

Pension expense for 2008 was $2 million (six
months ended December 31, 2007  $1 million).

Defined Contribution Pension Plan

The Companys contribution to the U.S. 401(k) plan was $2.6 million in 2008 (2007  $0.9 million).

Post-retirement Welfare Plan

As at
December 31, 2008, the benefit obligation was $13 million (2007  $33 million). The discount rate used at the end of 2008 to determine the accrued benefit obligation was 6.10% (2007  6.25%).

Post-retirement welfare expense for 2008 was $3 million (six months ended December 31, 2007  $1.5 million).

Note 21 Related Party Transactions

TransAlta Power,
L.P. (TAPLP) is under the indirect control of Huskys principal shareholders. TAPLP is a 49.99% owner in TransAlta Cogeneration, L.P. (TACLP) which is the Companys joint venture partner for the Meridian
cogeneration facility at Lloydminster. The Company sells natural gas to the Meridian cogeneration facility and other cogeneration facilities owned by TACLP. These natural gas sales are related party transactions and have been measured at the
exchange amount. For 2008, the total value of natural gas sales to the Meridian and other cogeneration facilities owned by TACLP was $125 million (2007  $104 million). At December 31, 2008, the total value of accounts receivables related
to these transactions was nil (2007  $10 million).

Note 22 Financial Instruments and Risk Factors

Details of the Companys significant accounting policies for the recognition and measurement of financial instruments and the basis for which income
and expense are recognized are disclosed in Note 3, Significant Accounting Policies.

Risk Management Overview

The Company is exposed to market risks related to the volatility of commodity prices, foreign exchange rates and interest rates. 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. Risk management is ultimately established by the Companys Board of Directors and is implemented and monitored by senior management within the Company.

Fair Value of Financial Instruments

The Companys financial instruments as at
December 31, 2008 included cash and cash equivalents, accounts receivable, contribution receivable, bank operating loans, accounts payable and accrued liabilities, contribution payable, long-term debt, the derivative portion of cash flow hedges
and freestanding derivatives.



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##### Table of Contents

The carrying value of cash and cash equivalents, accounts receivable, bank operating loans, accounts
payable and accrued liabilities approximates their fair value due to the short-term maturity of these investments.

At December 31,
2008, the carrying value of the contribution receivable and contribution payable was $1.5 billion and $1.7 billion respectively. The fair value of these financial instruments is not readily determinable due to uncertainties regarding timing of the
cash flows. Refer to Note 10, Joint Ventures.

The estimation of the fair value of commodity derivatives incorporates forward
prices and adjustments for quality or 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 fair value of long-term debt is the present value of future cash flows associated with the debt. Market information
such as treasury rates and credit spreads is 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 was as follows:



|               |  |               |       |           |   |               |  |           |       |               |   |           |  |   |       |  |   |      
|-------------- |  | ------------- | ----- | --------- | - | ------------- |  | --------- | ----- | ------------- | - | --------- |  | - | ----- |  | - | -----
|               |  | 2008          |       | 2007      |   | 2006         
|               |  | CarryingValue |       | FairValue |   | CarryingValue |  | FairValue |       | CarryingValue |   | FairValue
|Long-term debt |  | $             | 1,957 |           | $ | 1,739         |  | $         | 2,814 |               | $ | 2,903     |  | $ | 1,611 |  | $ | 1,671

Market Risk

Market risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in market prices. Market risk is comprised of foreign currency risk, interest rate risk and
other price risk, for example, commodity price risk. The objective of market risk management is to manage and control market price exposures within acceptable limits, while maximizing returns.

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. The Company holds crude oil inventories that are feedstock or part of the in-process inventories at its refineries. These inventories are subject to a lower of cost or net realizable value test on a monthly basis and the
Company is exposed to declining crude prices.

The Companys results are affected by the exchange rate between 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.

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 interest expense. In order to mitigate the Companys
exposure to long-term debt affected by the U.S./Canadian dollar exchange rate, the Company has entered into cash flow hedges using cross currency debt swaps. 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 self-sustaining foreign operation and the unrealized foreign exchange gain is recorded in other comprehensive income.



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To mitigate risk related to interest rates, the Company may enter into fair value hedges using interest
rate swaps. The Companys objectives, processes and policies for managing market risk have not changed from the previous year.

Commodity Price
Risk Management

Natural Gas Contracts

At December 31, 2008, the Company had the following third party offsetting physical purchase and sale natural gas contracts, which met the definition of a derivative instrument:



|                            |  |               |   |  |           |    |  
|--------------------------- |  | ------------- | - |  | --------- | -- | -
|                            |  | Volumes(mmcf) |   |  | FairValue |   
|Physical purchase contracts |  | 23,785        |   |  | $         | (2 | )
|Physical sale contracts     |  | (23,785       | ) |  | $         | 3  |  

These contracts have been recorded at their fair value in accounts receivable and accrued
liabilities and the resulting unrealized gain or loss has been recorded in other expenses in the consolidated statement of earnings.

Natural Gas
Storage Contracts

At December 31, 2008, the Company had the following third party physical purchase and sale natural gas storage
contracts:



|                            |  |               |   |  |           |    |  
|--------------------------- |  | ------------- | - |  | --------- | -- | -
|                            |  | Volumes(mmcf) |   |  | FairValue |   
|Physical purchase contracts |  | 14,067        |   |  | $         | (7 | )
|Physical sale contracts     |  | (46,632       | ) |  | $         | 58 |  

These contracts have been recorded at their fair value in accounts receivable and accrued
liabilities and the resulting unrealized gain or loss has been recorded in revenue and cost of sales in the consolidated statement of earnings.

Interest Rate Risk Management

At December 31, 2008, the Company had a freestanding derivative that requires the
payment of amounts based on a floating interest rate in exchange for receipt of payments based on a fixed interest rate with the following terms:



|                |  |               |  |                     |  |            |  
|--------------- |  | ------------- |  | ------------------- |  | ---------- | -
|Notional Amount |  | Swap Maturity |  | Swap Rate (percent) |  | Fair Value
|$ 200           |  | July 14, 2009 |  | CDOR + 175 bps      |  | $          | 4

This contract has been recorded at fair value in accounts receivable. Prior to August 29,
2008, this derivative was a hedging item in a fair value hedge and a gain of $3 million was recorded through interest expense. On August 29, 2008, the underlying debt was redeemed and the fair value hedge was discontinued. The gain of $1
million subsequent to August 29, 2008 has been recorded in other expenses.

Foreign Currency Risk Management

The Company manages its exposure to foreign exchange fluctuations by balancing the U.S. dollar denominated cash flows with U.S. dollar denominated
borrowings and other financial instruments. Husky utilizes spot and forward sales to convert cash flows to or from U.S. or Canadian currency.



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At December 31, 2008, the Company had a cash flow hedge using the following cross currency debt
swaps:



|            |  |             |     |                    |   |               |  |                        |  |            |  |   |     |  
|----------- |  | ----------- | --- | ------------------ | - | ------------- |  | ---------------------- |  | ---------- |  | - | --- | -
|Debt        |  | Swap Amount |     | CanadianEquivalent |   | Swap Maturity |  | Interest Rate(percent) |  | Fair Value | 
|6.25% notes |  | U.S. $      | 150 |                    | $ | 211           |  | June 15, 2012          |  | 7.41       |  | $ | (44 | )
|6.25% notes |  | U.S. $      | 75  |                    | $ | 89            |  | June 15, 2012          |  | 5.65       |  | $ | 3   |  
|6.25% notes |  | U.S. $      | 50  |                    | $ | 59            |  | June 15, 2012          |  | 5.67       |  | $ | 3   |  
|6.25% notes |  | U.S. $      | 75  |                    | $ | 88            |  | June 15, 2012          |  | 5.61       |  | $ | 5   |  

These contracts have been recorded at fair value in other long-term liabilities. The portion of
the fair value of the derivative related to foreign exchange losses has been recorded in earnings to offset the foreign exchange on the translation of the underlying debt and the remaining loss has been included in other comprehensive income. As at
December 31, 2008, the unrealized foreign exchange loss of $6 million (2007  $14 million gain), net of tax of $2 million (2007  $7 million) is recorded in other comprehensive income. At December 31, 2008, the balance in
accumulated other comprehensive income was $10 million (2007  $4 million), net of tax of $4 million (2007  $2 million). For the year ended December 31, 2008, the Company recognized a foreign exchange gain of $83 million (2007 
loss of $62 million) on the cross currency debt swaps.

The Company enters into short-dated foreign exchange contracts to fix the exchange
rate for conversion of U.S. dollars to Canadian dollars. During 2008, the impact of these contracts was a loss of $34 million (2007  loss of $18 million) recorded in foreign exchange expense.

The Company entered into forward purchases of U.S. dollars. During the third quarter of 2008, the Company unwound one of the forward purchases realizing
a gain of $12 million recorded in other expenses in the consolidated statement of earnings. At December 31, 2008, the following foreign exchange transactions had been entered into:



|                 |  |                   |    |                     |   |            |  |   |   
|---------------- |  | ----------------- | -- | ------------------- | - | ---------- |  | - | --
|Date             |  | Forward Purchases |    | Canadian Equivalent |   | Fair Value
|October 5, 2007  |  | U.S. $            | 98 |                     | $ | 97         |  | $ | 23
|October 11, 2007 |  | U.S. $            | 98 |                     | $ | 96         |  | $ | 23

These forward contracts have been recorded at fair value in accounts receivable and the resulting
gain has been recorded in other expenses in the consolidated statement of earnings. During 2008, the impact was a gain of $38 million (2007  $8 million gain).

Effective July 1, 2007, the Companys U.S. $1.5 billion of debt financing related to the Lima acquisition was designated as a hedge of the Companys net investment in the U.S. refining and marketing
operations, which are considered self-sustaining. During the second quarter of 2008, the Company repaid its bridge financing of U.S. $750 million. In the last half of 2008, the Company repurchased U.S. $63 million of bonds that were classified as a
net investment hedge. As a result, the Companys net investment hedge is limited to the remaining U.S. $687 million. As at December 31, 2008, the foreign exchange loss of $165 million (2007  $102 million gain), net of tax of $27
million (2007  $19 million), arising from the translation of the debt is recorded in other comprehensive income.

Sensitivity Analysis

A sensitivity analysis for foreign currency, commodities and interest rate risks has been calculated by increasing or decreasing the
interest rate or foreign currency exchange rate, as appropriate, in the fair value methodologies described in the Fair Value of Financial Instruments section of this note. These sensitivities represent the effect resulting from changing
the relevant rates with all other variables held constant and have been applied only to financial instruments. The Companys process for determining these sensitivities has not changed during the year. All calculations are on a pre-tax basis.



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The Company is exposed to interest rate risk on its interest rate swaps. As at December 31, 2008,
had interest rates been 50 basis points higher or lower and assuming all other variables remained constant, the impact to earnings before tax would have been less than $1 million.

The Company is exposed to interest rate and foreign currency risk on its cross currency debt swaps. As at December 31, 2008, had the Canadian dollar
been 1% stronger versus the U.S. dollar and assuming all other variables remained constant, the impact to other comprehensive income would have been $4 million lower. Had the Canadian dollar been 1% weaker versus the U.S. dollar and assuming all
other variables remained constant, the impact to other comprehensive income would have been $7 million higher. As at December 31, 2008, had the interest rates been 50 basis points higher and assuming all other variables remained constant, the
impact to other comprehensive income would have been $2 million higher. Had the interest rates been 50 basis points lower and assuming all other variables remained constant, the impact to other comprehensive income would have been $7 million lower.

The Company is exposed to foreign currency risk on its forward purchases of U.S. dollars. As at December 31, 2008, had the Canadian
dollar been 1% stronger relative to the U.S. dollar and assuming all other variables remained constant, the impact to earnings before tax would have been $2 million lower. Equal and offsetting impacts would have occurred had the Canadian dollar been
1% weaker relative to the U.S. dollar and assuming all other variables remained constant.

The Company is exposed to commodity price risk
on its natural gas storage contracts. As at December 31, 2008, had the forward price been $0.20/mmbtu higher, the impact to earnings before tax would have been $7 million lower. Had the forward price been $0.20/mmbtu lower, the impact to
earnings before tax would have been $7 million higher.

Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The Companys processes for
managing liquidity risk include ensuring, to the extent possible, that it will have sufficient liquidity to meet its liabilities when they become due. The Company prepares annual capital expenditure budgets, which are monitored and are updated as
required. In addition, the Company requires authorizations for expenditures on projects to assist with the management of capital.

Since
the Company operates in the upstream oil and gas industry, it requires sufficient cash to fund capital programs necessary to maintain or increase production and develop reserves, to acquire strategic oil and gas assets, to repay maturing debt and to
pay dividends. The Companys upstream capital programs are funded principally by cash provided from operating activities. During times of low oil and gas prices, a portion of capital programs can generally be deferred. However, due to the long
cycle times and the importance to future cash flow in maintaining the Companys production, it may be necessary to utilize alternative sources of capital to continue the Companys strategic investment plan during periods of low commodity
prices. As a result, the Company frequently evaluates the options available with respect to sources of long and short-term capital resources. Occasionally, the Company will hedge a portion of its production to protect cash flow in the event of
commodity price declines. In addition, the Company has access to a revolving syndicated credit facility, which allows the Company to borrow money from a group of banks on an unsecured basis.

The following are the contractual maturities of financial liabilities as at December 31, 2008:



|                                               |  |                 |       |                       |   |                       |  |            |       |  |   |      
|---------------------------------------------- |  | --------------- | ----- | --------------------- | - | --------------------- |  | ---------- | ----- |  | - | -----
|Financial Liability                            |  | Less than1 Year |       | 1 to less than2 Years |   | 2 to less than5 Years |  | Thereafter
|Accounts payable and accrued liabilities       |  | $               | 2,896 |                       | $ |                      |  | $          |      |  | $ |     
|Cross currency swaps                           |  |                 |      |                       |   |                      |  |            | 447   |  |   |     
|Long-term debt and interest on fixed rate debt |  |                 | 127   |                       |   | 127                   |  |            | 822   |  |   | 2,478
|                                               |  |                 |       |                       |   |                       |  |            |       |  |   |      
|Total                                          |  | $               | 3,023 |                       | $ | 127                   |  | $          | 1,269 |  | $ | 2,478
|                                               |  |                 |       |                       |   |                       |  |            |       |  |   |      



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The Companys contribution payable to the joint venture with BP (refer to Note 10) is payable
between December 31, 2008 and December 31, 2015, with the final balance due and payable by December 31, 2015.

The
Companys objectives, processes and policies for managing liquidity risk have not changed from the previous year.

Credit Risk

Credit risk represents the financial loss that the Company would suffer if the Companys counterparties to a financial
instrument, in owing an amount to the Company, fail to meet or discharge their obligation to the Company. The Companys accounts receivables are broad based with customers in the energy industry, midstream and end user segment 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 reassurances as deemed necessary, reducing
the amount and duration of credit exposures and close monitoring of all accounts. The Company did not have any customers that constituted more than 10% of total sales and operating revenues during 2008.

The Companys objectives, processes and policies for managing credit risk have not changed from the previous year.

Cash and cash equivalents include cash bank balances and short-term deposits maturing in less than 90 days. 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 amount of accounts receivable and cash and cash equivalents represents the maximum credit exposure.

The Companys accounts
receivable excluding income taxes receivable and doubtful accounts was aged as follows:



|                             |  |               |      
|---------------------------- |  | ------------- | -----
|Aging                        |  | Dec. 31, 2008
|Current                      |  | $             | 1,145
|Past due (1  30 days)       |  |               | 75   
|Past due (31  60 days)      |  |               | 17   
|Past due (61  90 days)      |  |               | 4    
|Past due (more than 90 days) |  |               | 19   
|                             |  |               |      
|Total                        |  | $             | 1,260
|                             |  |               |      

The movement in the Companys allowance for doubtful accounts for 2008 was as follows:



|                             |  |   |   
|---------------------------- |  | - | --
|Balance at January 1, 2008   |  | $ | 10
|Provisions and revisions     |  |   | 12
|                             |  |   |   
|Balance at December 31, 2008 |  | $ | 22
|                             |  |   |   

For 2008, the Company wrote off $3 million of uncollectible receivables.

Held-for-Trading Financial Liabilities

The
Companys cross currency swaps have been designated as a cash flow hedge and the derivative component of the hedge meets the definition of a held-for-trading financial liability. The cross currency swap counterparties credit profiles have
not materially changed since the past year or since inception. As a result, the



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amount of change during the period and cumulatively in the fair value of the cross currency swaps has not been materially impacted by changes resulting from
credit risk. At December 31, 2008, the amount the Company would be contractually required to pay under the cross currency swaps at maturity was $414 million higher (December 31, 2007  $341 million higher) than their carrying amount.

Embedded Derivative

During the
fourth quarter of 2008, a drilling contract previously treated as an embedded derivative no longer met the criteria and the related accounting treatment was discontinued. A loss of $71 million, after tax, was recorded in 2008 compared with a gain of
$71 million, after tax, for the same period in 2007.

Note 23    Capital Disclosures

The Companys objectives when managing capital are: (i) to maintain a flexible capital structure, which optimizes the cost of capital at
acceptable risk; and (ii) to maintain investor, creditor and market confidence to sustain the future development of the business.

The
Company manages its capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of its underlying assets. The Company considers its capital structure to include shareholders equity and
debt. 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 from operations (defined as total debt divided by earnings
from operations plus non-cash charges before settlement of asset retirement obligations and change 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 cash flow from operations ratio of less than two times. At December 31, 2008, debt to cash flow from operations was 0.3 times. The ratio may increase at certain times as a result of
acquisitions. 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 bilateral credit facilities and
the syndicated credit facility include a debt to cash flow covenant. The Company was fully compliant with this covenant at December 31, 2008.

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



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##### Table of Contents

Document C

Form 40-F



Reconciliation
to Accounting Principles Generally Accepted

in the United States







PAGE 1



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##### Table of Contents

Report of Independent Registered Public Accounting Firm on Reconciliation

to Accounting Principles Generally Accepted in the United States

To the Board of Directors of Husky Energy Inc.

On February 4, 2009, we reported on the consolidated
balance sheets of Husky Energy Inc. (the Company) as at December 31, 2008, 2007 and 2006 and the consolidated statements of earnings and comprehensive income, changes in shareholders equity and cash flows for each of the years
in the three-year period ended December 31, 2008 which are included in the annual report on Form 40-F. In connection with our audits of the aforementioned consolidated financial statements, we also have audited the related supplemental
note entitled Reconciliation to Accounting Principles Generally Accepted in the United States included in the Form 40-F. This supplemental note is the responsibility of the Companys management. Our responsibility is to
express an opinion on this supplemental note based on our audits.

In our opinion, such supplemental note, when considered in relation
to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.



|                        
|------------------------
|/s/ KPMG LLP            
|KPMG LLP                
|Chartered Accountants   
|Calgary, Alberta, Canada
|February 4, 2009        



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##### Table of Contents

Document C

Form 40-F

Reconciliation to Accounting Principles Generally Accepted in the United States

The Companys consolidated financial statements have been prepared in accordance with GAAP (Generally Accepted Accounting Principles) in Canada,
which differ in some respects from those in the United States. Any differences in accounting principles as they pertain to the accompanying consolidated financial statements were insignificant except as described below:

Consolidated Statements of Earnings



|                                                                                              |  |      |       |   |      |   |       |      |  |   |       |  
|--------------------------------------------------------------------------------------------- |  | ---- | ----- | - | ---- | - | ----- | ---- |  | - | ----- | -
|($ millions, except per share amounts)                                                        |  | 2008 |       |   | 2007 |   |       | 2006 | 
|Net earnings under Canadian GAAP                                                              |  | $    | 3,754 |   |      | $ | 3,214 |      |  | $ | 2,726 |  
|Adjustments:                                                                                  |  |      |       |   |      |   |       |      |  |   |       |  
|Full cost accounting (a)                                                                      |  |      | 22    |   |      |   | 56    |      |  |   | 64    |  
|Related income taxes                                                                          |  |      | (6    | ) |      |   | (17   | )    |  |   | (20   | )
|Energy trading contracts (c)                                                                  |  |      |      |   |      |   |      |      |  |   | 4     |  
|Related income taxes                                                                          |  |      |      |   |      |   |      |      |  |   | (1    | )
|Stock-based compensation (d)                                                                  |  |      | (2    | ) |      |   | (43   | )    |  |   | (10   | )
|Related income taxes                                                                          |  |      |      |   |      |   | 13    |      |  |   | 3     |  
|                                                                                              |  |      |       |   |      |   |       |      |  |   |       |  
|Earnings before cumulative effect of change in accounting principle underU.S. GAAP            |  |      | 3,768 |   |      |   | 3,223 |      |  |   | 2,766 |  
|Cumulative effect of change in accounting principle, net of tax (d)                           |  |      |      |   |      |   |      |      |  |   | 11    |  
|                                                                                              |  |      |       |   |      |   |       |      |  |   |       |  
|Net earnings under U.S. GAAP                                                                  |  | $    | 3,768 |   |      | $ | 3,223 |      |  | $ | 2,777 |  
|                                                                                              |  |      |       |   |      |   |       |      |  |   |       |  
|Weighted average number of common shares outstanding under U.S. GAAP (millions)               |  |      |       |   |      |   |       |      |  |   |       |  
|Basic and diluted                                                                             |  |      | 849.4 |   |      |   | 848.8 |      |  |   | 848.4 |  
|Earnings per share before cumulative effect of change in accounting principle under U.S. GAAP |  |      |       |   |      |   |       |      |  |   |       |  
|Basic and diluted                                                                             |  | $    | 4.44  |   |      | $ | 3.80  |      |  | $ | 3.26  |  
|Earnings per share under U.S. GAAP                                                            |  |      |       |   |      |   |       |      |  |   |       |  
|Basic and diluted                                                                             |  | $    | 4.44  |   |      | $ | 3.80  |      |  | $ | 3.27  |  
|                                                                                              |  |      |       |   |      |   |       |      |  |   |       |  



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|                                                       |  |              |        |   |          |   |        |              |  |   |          |   |  |              |        |          |  |   |        |  |   |        |  
|------------------------------------------------------ |  | ------------ | ------ | - | -------- | - | ------ | ------------ |  | - | -------- | - |  | ------------ | ------ | -------- |  | - | ------ |  | - | ------ | -
|Condensed Consolidated Balance Sheets                  | 
|                                                       |  | 2008         |        |   | 2007     |   |        | 2006         | 
|($ millions)                                           |  | CanadianGAAP |        |   | U.S.GAAP |   |        | CanadianGAAP |  |   | U.S.GAAP |   |  | CanadianGAAP |        | U.S.GAAP | 
|Current assets                                         |  | $            | 3,322  |   |          | $ | 3,322  |              |  | $ | 3,048    |   |  | $            | 3,048  |          |  | $ | 2,179  |  | $ | 2,190  |  
|Property, plant and equipment, net (a)                 |  |              | 20,839 |   |          |   | 20,487 |              |  |   | 17,805   |   |  |              | 17,431 |          |  |   | 15,550 |  |   | 15,120 |  
|Other assets(b)(g)                                     |  |              | 2,361  |   |          |   | 2,349  |              |  |   | 844      |   |  |              | 838    |          |  |   | 204    |  |   | 185    |  
|                                                       |  |              |        |   |          |   |        |              |  |   |          |   |  |              |        |          |  |   |        |  |   |        |  
|                                                       |  | $            | 26,522 |   |          | $ | 26,158 |              |  | $ | 21,697   |   |  | $            | 21,317 |          |  | $ | 17,933 |  | $ | 17,495 |  
|                                                       |  |              |        |   |          |   |        |              |  |   |          |   |  |              |        |          |  |   |        |  |   |        |  
|Current liabilities (d)(g)                             |  | $            | 2,896  |   |          | $ | 2,927  |              |  | $ | 3,099    |   |  | $            | 3,125  |          |  | $ | 2,674  |  | $ | 2,696  |  
|Long-term debt (b)                                     |  |              | 1,957  |   |          |   | 1,975  |              |  |   | 2,073    |   |  |              | 2,093  |          |  |   | 1,511  |  |   | 1,557  |  
|Other long-term liabilities (d)(g)                     |  |              | 2,557  |   |          |   | 2,566  |              |  |   | 918      |   |  |              | 955    |          |  |   | 756    |  |   | 749    |  
|Future income taxes (a)(d)(g)                          |  |              | 4,724  |   |          |   | 4,587  |              |  |   | 3,957    |   |  |              | 3,806  |          |  |   | 3,372  |  |   | 3,210  |  
|Share capital (e) (f)                                  |  |              | 3,568  |   |          |   | 3,802  |              |  |   | 3,551    |   |  |              | 3,785  |          |  |   | 3,533  |  |   | 3,767  |  
|Retained earnings                                      |  |              | 10,461 |   |          |   | 9,965  |              |  |   | 8,176    |   |  |              | 7,666  |          |  |   | 6,087  |  |   | 5,572  |  
|Accumulated other comprehensive income                 |  |              |        |   |          |   |        |              |  |   |          |   |  |              |        |          |  |   |        |  |   |        |  
|Derivatives designated as cash flow hedges, net of tax |  |              | (10    | ) |          |   | (10    | )            |  |   | (4       | ) |  |              | (4     | )        |  |   |       |  |   | (18    | )
|Cumulative foreign currency translation                |  |              | 432    |   |          |   | 432    |              |  |   | (175     | ) |  |              | (175   | )        |  |   |       |  |   |       |  
|Hedge of net investment, net of tax                    |  |              | (63    | ) |          |   | (63    | )            |  |   | 102      |   |  |              | 102    |          |  |   |       |  |   |       |  
|Pension accounting (g)                                 |  |              |       |   |          |   |       |              |  |   |         |   |  |              |       |          |  |   |       |  |   | (38    | )
|Pension obligation (g)                                 |  |              |       |   |          |   | (23    | )            |  |   |         |   |  |              | (36    | )        |  |   |       |  |   |       |  
|                                                       |  |              |        |   |          |   |        |              |  |   |          |   |  |              |        |          |  |   |        |  |   |        |  
|                                                       |  | $            | 26,522 |   |          | $ | 26,158 |              |  | $ | 21,697   |   |  | $            | 21,317 |          |  | $ | 17,933 |  | $ | 17,495 |  
|                                                       |  |              |        |   |          |   |        |              |  |   |          |   |  |              |        |          |  |   |        |  |   |        |  



|                                                                                                  |  |              |        |   |          |   |        |              |  |   |          |   |  |              |        |   |          |   |       |   |  |   |       |  
|------------------------------------------------------------------------------------------------- |  | ------------ | ------ | - | -------- | - | ------ | ------------ |  | - | -------- | - |  | ------------ | ------ | - | -------- | - | ----- | - |  | - | ----- | -
|Condensed Consolidated Statements of Retained Earnings and Accumulated Other Comprehensive Income | 
|                                                                                                  |  | 2008         |        |   | 2007     |   |        | 2006         | 
|($ millions)                                                                                      |  | CanadianGAAP |        |   | U.S.GAAP |   |        | CanadianGAAP |  |   | U.S.GAAP |   |  | CanadianGAAP |        |   | U.S.GAAP |  
|Retained earnings, beginning of year                                                              |  | $            | 8,176  |   |          | $ | 7,666  |              |  | $ | 6,087    |   |  | $            | 5,572  |   |          | $ | 3,997 |   |  | $ | 3,431 |  
|Net earnings                                                                                      |  |              | 3,754  |   |          |   | 3,768  |              |  |   | 3,214    |   |  |              | 3,223  |   |          |   | 2,726 |   |  |   | 2,777 |  
|Adoption of financial instruments (b)                                                             |  |              |       |   |          |   |       |              |  |   | 4        |   |  |              |       |   |          |   |      |   |  |   |      |  
|Dividends on common shares                                                                        |  |              | (1,469 | ) |          |   | (1,469 | )            |  |   | (1,129   | ) |  |              | (1,129 | ) |          |   | (636  | ) |  |   | (636  | )
|                                                                                                  |  |              |        |   |          |   |        |              |  |   |          |   |  |              |        |   |          |   |       |   |  |   |       |  
|Retained earnings, end of year                                                                    |  | $            | 10,461 |   |          | $ | 9,965  |              |  | $ | 8,176    |   |  | $            | 7,666  |   |          | $ | 6,087 |   |  | $ | 5,572 |  
|                                                                                                  |  |              |        |   |          |   |        |              |  |   |          |   |  |              |        |   |          |   |       |   |  |   |       |  
|Accumulated other comprehensive income, beginning of year                                         |  | $            | (77    | ) |          | $ | (113   | )            |  | $ |         |   |  | $            | (56    | ) |          | $ |      |   |  | $ | (41   | )
|Adoption of financial instruments (b)                                                             |  |              |       |   |          |   |       |              |  |   | (18      | ) |  |              |       |   |          |   |      |   |  |   |      |  
|Derivatives designated as cash flow hedges, net oftax (b)                                         |  |              | (6     | ) |          |   | (6     | )            |  |   | 14       |   |  |              | 14     |   |          |   |      |   |  |   | 3     |  
|Cumulative foreign currency translation                                                           |  |              | 607    |   |          |   | 607    |              |  |   | (175     | ) |  |              | (175   | ) |          |   |      |   |  |   |      |  
|Hedge of net investment, net of tax                                                               |  |              | (165   | ) |          |   | (165   | )            |  |   | 102      |   |  |              | 102    |   |          |   |      |   |  |   |      |  
|Minimum pension liability, net of tax (g)                                                         |  |              |       |   |          |   |       |              |  |   |         |   |  |              |       |   |          |   |      |   |  |   | (5    | )
|Reversal of minimum pension liability, net oftax (g)                                              |  |              |       |   |          |   |       |              |  |   |         |   |  |              |       |   |          |   |      |   |  |   | 25    |  
|Pension accounting (g)                                                                            |  |              |       |   |          |   |       |              |  |   |         |   |  |              |       |   |          |   |      |   |  |   | (38   | )
|Pension obligation (g)                                                                            |  |              |       |   |          |   | 13     |              |  |   |         |   |  |              | 2      |   |          |   |      |   |  |   |      |  
|                                                                                                  |  |              |        |   |          |   |        |              |  |   |          |   |  |              |        |   |          |   |       |   |  |   |       |  
|Accumulated other comprehensive income, end of year                                               |  | $            | 359    |   |          | $ | 336    |              |  | $ | (77      | ) |  | $            | (113   | ) |          | $ |      |   |  | $ | (56   | )
|                                                                                                  |  |              |        |   |          |   |        |              |  |   |          |   |  |              |        |   |          |   |       |   |  |   |       |  



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|                                                                               |  |              |        |          |   |              |      |   |          |   |  |              |        |          |  |   |        |  |   |       
|------------------------------------------------------------------------------ |  | ------------ | ------ | -------- | - | ------------ | ---- | - | -------- | - |  | ------------ | ------ | -------- |  | - | ------ |  | - | ------
|Condensed Consolidated Statements of Earnings and Comprehensive Income        
|                                                                               |  | 2008         |        | 2007     |   |              | 2006
|($ millions)                                                                   |  | CanadianGAAP |        | U.S.GAAP |   | CanadianGAAP |      |   | U.S.GAAP |   |  | CanadianGAAP |        | U.S.GAAP
|Sales and operating revenues(c)                                                |  | $            | 24,701 |          | $ | 21,967       |      | $ | 15,518   |   |  | $            | 14,072 |          |  | $ | 12,664 |  | $ | 10,790
|Costs and expenses (excluding depletion, depreciation and amortization) (c)(d) |  |              | 17,518 |          |   | 14,786       |      |   | 9,408    |   |  |              | 8,005  |          |  |   | 7,422  |  |   | 5,554 
|Accretion expense                                                              |  |              | 54     |          |   | 54           |      |   | 47       |   |  |              | 47     |          |  |   | 45     |  |   | 45    
|Depletion, depreciation and amortization (a)                                   |  |              | 1,832  |          |   | 1,810        |      |   | 1,806    |   |  |              | 1,750  |          |  |   | 1,599  |  |   | 1,535 
|Interest  net                                                                 |  |              | 147    |          |   | 147          |      |   | 130      |   |  |              | 130    |          |  |   | 92     |  |   | 92    
|                                                                               |  |              |        |          |   |              |      |   |          |   |  |              |        |          |  |   |        |  |   |       
|Earnings before income taxes                                                   |  |              | 5,150  |          |   | 5,170        |      |   | 4,127    |   |  |              | 4,140  |          |  |   | 3,506  |  |   | 3,564 
|Income taxes (a)(d)                                                            |  |              | 1,396  |          |   | 1,402        |      |   | 913      |   |  |              | 917    |          |  |   | 780    |  |   | 798   
|                                                                               |  |              |        |          |   |              |      |   |          |   |  |              |        |          |  |   |        |  |   |       
|Earnings before cumulative effect of change in accounting principle            |  |              | 3,754  |          |   | 3,768        |      |   | 3,214    |   |  |              | 3,223  |          |  |   | 2,726  |  |   | 2,766 
|Cumulative effect of change in accounting principle, net of tax (d)            |  |              |       |          |   |             |      |   |         |   |  |              |       |          |  |   |       |  |   | 11    
|                                                                               |  |              |        |          |   |              |      |   |          |   |  |              |        |          |  |   |        |  |   |       
|Net earnings                                                                   |  |              | 3,754  |          |   | 3,768        |      |   | 3,214    |   |  |              | 3,223  |          |  |   | 2,726  |  |   | 2,777 
|Other comprehensive income (g)                                                 |  |              | 436    |          |   | 449          |      |   | (59      | ) |  |              | (57    | )        |  |   |       |  |   | 2     
|                                                                               |  |              |        |          |   |              |      |   |          |   |  |              |        |          |  |   |        |  |   |       
|Comprehensive income                                                           |  | $            | 4,190  |          | $ | 4,217        |      | $ | 3,155    |   |  | $            | 3,166  |          |  | $ | 2,726  |  | $ | 2,779 
|                                                                               |  |              |        |          |   |              |      |   |          |   |  |              |        |          |  |   |        |  |   |       

The increases or decreases noted above refer to the following differences between U.S. GAAP and
Canadian GAAP:



| | (a) | Under Canadian GAAP the ceiling test is performed by comparing the carrying value of the cost centre based on the sum of the undiscounted cash flows expected from the cost
centres use and eventual disposition. If the carrying value is unrecoverable the cost centre is written down to its fair value using the expected present value approach of proved plus probable reserves using future prices. Under U.S. GAAP,
companies using the full cost method of accounting for oil and gas producing activities perform a ceiling test on each cost centre using discounted estimated future net revenue from proved oil and gas reserves using a discount factor of 10%. Prices
used in the U.S. GAAP ceiling tests performed for this reconciliation were those in effect at the applicable year-end. At December 31, 2001, the Company recognized a U.S. GAAP ceiling test write down of $334 million after tax. Depletion expense
for U.S. GAAP is reduced by $44 million (2007  $52 million; 2006  $60 million), before tax of $13 million (2007  $16 million; 2006  $19 million).
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Under U.S. GAAP, prices used in the reserve determination were those in effect at the applicable year-end. For Canadian GAAP, forecast prices are used in
the reserve determination. The different prices result in a lower reserve base for U.S. GAAP. Additional depletion of $39 million, net of tax of $14 million, was recorded under U.S. GAAP in December 2004. As of the first quarter of 2005 these
reserves became economical again. Depletion expense for U.S. GAAP is reduced by $3 million (2007 and 2006  $4 million), before tax of $1 million (2007 and 2006  $1 million). In 2008, additional depletion of $25 million, net of tax of $8
million was recorded.



| | (b) | Effective January 1, 2007, the Company adopted the new Canadian GAAP standards relating to financial instruments. These standards have been adopted prospectively. This new
guidance substantially harmonizes Canadian GAAP with U.S. GAAP, with the exception of the treatment of debt issue costs. Under the new Canadian GAAP requirements, unamortized debt issue costs are offset against the related long-term debt. Under U.S.
GAAP, debt issue costs are deferred in other assets. At December 31, 2008, $18 million (2007  $20 million) was reclassified from long term-debt to other assets for U.S. GAAP purposes.
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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##### Table of Contents

| | (c) | Prior to the adoption of the new Canadian standards for financial instruments in 2007, Canadian GAAP differed from U.S. GAAP with regards to natural gas purchase and sales
contracts. Under U.S. GAAP, natural gas purchase and sale contracts related to energy trading activities are recorded at fair value in accordance with Emerging Issues Task Force (EITF) 02-03, Issues Involved in Accounting for
Derivative Contracts held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Previously under Canadian GAAP, the impact of energy trading contracts was recorded as the contracts settled. Under U.S. GAAP, unlike Canadian GAAP, these gains and losses continue to be netted against sales and operating revenues.



| | (d) | In January 2006, the Company adopted the fair value accounting provisions under FAS 123(R), Share-Based Payment. Under FAS 123(R) awards that are classified as
liabilities are re-measured based on the awards fair value at each reporting date until settlement. Under FAS 123 awards classified as liabilities were measured at their intrinsic value. FAS 123(R) was adopted using the modified prospective
application method. The related cumulative effect of the change in accounting principle to net earnings at January 1, 2006 was an increase of $16 million, before tax of $5 million. The change resulted in a decrease to current liabilities of $12
million and long-term liabilities of $4 million and an increase to future income tax liability of $5 million. There was no impact on the Companys cash flow as a result of adoption of FAS 123(R).
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

At December 31, 2008, for U.S. GAAP purposes, the Company recorded an increase to current liabilities of $28 million (2007  $17 million; 2006
 decrease of $7 million) and an increase to long-term liabilities of $11 million (2007  $20 million; 2006  $1 million). The Company also recorded a decrease to net earnings of $2 million (2007  $43 million; 2006 
increase of $6 million), before tax of less than $1 million (2007  $13 million; 2006  $2 million).

Under FAS 123(R), the
Company is using the Black-Scholes option pricing model to estimate the fair value of the liability related to the options issued under the Companys tandem plan. The assumptions used in calculating fair value were:



|                                           |  |      |             |      |   |             |  |   |            
|------------------------------------------ |  | ---- | ----------- | ---- | - | ----------- |  | - | -----------
|                                           |  | 2008 |             | 2007 |   | 2006       
|Initial expected life (years)              |  |      | 3.3         |      |   | 3.5         |  |   | 3.5        
|Expected annual dividend per share         |  | $    | 2.00        |      | $ | 1.32        |  | $ | 1.00       
|Range of expected volatilities used (%)    |  |      | 35.3  73.6 |      |   | 21.4  27.1 |  |   | 19.1  29.4
|Weighted-average expected volatility (%)   |  |      | 42.1        |      |   | 25.5        |  |   | 27.6       
|Range of risk-free interest rates used (%) |  |      | 0.7  1.3   |      |   | 3.7  3.9   |  |   | 3.9  4.2  

At December 31, 2008, the total intrinsic value of options exercised during the year was $12
million (2007  $13 million; 2006  $7 million), the share-based liability paid for the year was $101 million (2007  $151 million; 2006  97 million) and the total fair value of options vested during the year was $32 million
(2007  $66 million; 2006  $87 million).

The weighted average remaining contractual term of options fully vested and currently
exercisable is 2.9 years (2007  1.6 years; 2006  2.4 years). The aggregate intrinsic value of options fully vested and currently exercisable is $24 million (2007  $137 million; 2006  $120 million) and the aggregate intrinsic
value of options fully vested and expected to vest is $24 million (2007  $181 million; 2006  $267 million). The unrecognized compensation cost for 2008 related to non-vested awards is $17 million (2007  $51 million; 2006  $30
million) and the weighted average period that these costs will be recognized over is 1.3 years (2007  1.6 years; 2006  0.9 years).



| | (e) | As a result of the reorganization of the capital structure which occurred in 2000, the deficit of Husky Oil Limited of $160 million was eliminated. Elimination of the deficit would
not be permitted under U.S. GAAP.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| | (f) | Until 1997 the Company recorded interest waived on subordinated shareholders loans and dividends waived on Class C shares as a reduction of ownership charges. Under U.S. GAAP,
waived interest and dividends in those years would be recorded as interest on subordinated shareholders loans and dividends on Class C shares and as capital contributions.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (g) | FAS 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans requires the Company to recognize the overfunded or underfunded status of
a defined benefit postretirement plan as an asset or liability. The funded status is measured as the difference between the fair value of a plans assets and its benefit obligations. Changes in this funded status are recognized through
comprehensive income in the year in which the change occurs. The additional minimum liability previously recorded under FAS 87 has been eliminated. There is no impact to earnings recognition under the new requirement.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

At December 31, 2008, the underfunded status of the plan recorded to current and other long-term liabilities was $10 million (2007  $9 million;
2006  $8 million) and $79 million (2007  $54 million; 2006  $28 million), respectively. Other comprehensive income decreased by $13 million (2007  $2 million), net of tax of $7 million (2007  $1 million).



| | (h) | In January 2007, the Company adopted FASB Interpretation No. (FIN) 48, Accounting for Uncertainty in Income Taxes. This Interpretation clarifies the
accounting for the uncertainty in income taxes recognized in accordance with FAS 109. FIN 48 establishes a two-step process for the evaluation of a tax position taken or expected to be taken in a tax return. The first step recognizes whether or not
a tax position is sustainable based on a more-likely-than-not determination. If the tax position meets the more-likely-than-not threshold, the second step measures the amount of tax benefit to recognize in the financial statements. Under
FIN 48, the tax position is measured as the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. Huskys adoption of FIN 48 resulted in no adjustments to its tax provision recorded under Canadian
GAAP.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:



|                                                             |  |      |    |   |      |   |   
|------------------------------------------------------------ |  | ---- | -- | - | ---- | - | --
|                                                             |  | 2008 |    |   | 2007
|Balance at January 1                                         |  | $    | 30 |   |      | $ |  
|Gross increases  prior period tax positions                 |  |      | 3  |   |      |   |  
|Additions based on tax positions related to the current year |  |      | 50 |   |      |   | 30
|Settlements                                                  |  |      | (5 | ) |      |   |  
|                                                             |  |      |    |   |      |   |   
|Balance at December 31                                       |  | $    | 78 |   |      | $ | 30
|                                                             |  |      |    |   |      |   |   

The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax
rate is $78 million.

The Company does not expect any significant changes to its unrecognized tax benefits within the next 12 month period
at this time.

The following are the tax years which remain subject to examination by major tax jurisdictions:



|            |  |                                                      
|----------- |  | -----------------------------------------------------
|Tax Years   |  | Jurisdiction                                         
|1998  2008 |  | Federal  Canada Revenue Agency (Alberta and Ontario)
|1999  2008 |  | Internal Revenue Service  United States             



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Additional U.S. GAAP Disclosures

Stock Option Plan

In December 2004, the Financial Accounting Standards Board (FASB)
issued FAS 123(R), which replaced FAS 123 and superseded Accounting Principles Board (APB) Opinion 25. FAS 123(R) requires compensation cost related to share-based payments be recognized in the financial statements and that the cost must
be measured based on the fair value of the equity or liability instruments issued. Under FAS 123(R) all share-based payment plans must be valued using option-pricing models. For U.S. GAAP, the liability related to the options issued under the
Companys tandem plan is measured at fair value using an option pricing model. Under Canadian GAAP, the liability is measured based on the intrinsic value of the option. Over the life of the option the amount of compensation expense recognized
will differ under U.S. and Canadian GAAP, creating a temporary GAAP timing difference. At exercise or surrender of the option, the compensation expense to be recorded will be equal to the cash payment, which will be identical under U.S. and Canadian
GAAP and there will no longer be a GAAP difference. FAS 123(R) was effective January 1, 2006.

Depletion, Depreciation and Amortization

Upstream depletion, depreciation and amortization per gross equivalent barrel is calculated by converting natural gas volumes to a
barrel of oil equivalent (boe) using the ratio of 6 mcf of natural gas to 1 barrel of crude oil (sulphur volumes have been excluded from the calculation). Depletion, depreciation and amortization per boe as calculated under U.S. GAAP for
the years ended December 31 were as follows:



|                                                 |  |      |       |      |   |       |  |   |      
|------------------------------------------------ |  | ---- | ----- | ---- | - | ----- |  | - | -----
|                                                 |  | 2008 |       | 2007 |   | 2006 
|Depletion, depreciation and amortization per boe |  | $    | 11.39 |      | $ | 11.34 |  | $ | 10.75

Changes in Accounting Policies

Fair Value Measurement

On January 1, 2008, the Company adopted the FASB statement FAS 157,
Fair Value Measurements, which defines fair value, establishes a framework for measuring fair value in U.S. GAAP pronouncements and expands the disclosure requirements for fair value measurements. Prior to FAS 157, various definitions of
fair value existed with limited guidance for application of these definitions in U.S. GAAP. Fair value under this standard is focused on a market-based measurement as opposed to an entity-specific measurement. This standard establishes a fair value
hierarchy which distinguishes between market participant assumptions based on market data obtained from independent sources and the reporting entitys own assumptions about the market.

The Companys financial assets and liabilities that are recorded at fair value on a recurring basis have been categorized into one of the three
categories based upon fair value hierarchy in accordance with FAS 157. Fair values of assets and liabilities included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. 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 valuations are based on inputs that are unobservable and significant to the
overall fair value measurement. All of Huskys assets and liabilities are included in Level 2.

New Accounting Standards not yet
Implemented

Business Combinations and Non-Controlling Interests

In December 2007, the FASB issued FAS 141 (R), Business Combinations (Revised 2007) and FAS 160, Non-Controlling Interests in Consolidated Financial Statements  An Amendment of Accounting
Research Bulletin (ARB) No. 51. These standards require the use of fair value accounting for business combinations and



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##### Table of Contents

non-controlling interests. Equity securities issued as consideration in a business combination will be recorded at fair value as of the acquisition date as
opposed to being valued over a period which includes a few days prior to and after the terms of the business combination have been agreed to and announced. In addition, entities will no longer have the ability to capitalize any direct and
incremental costs incurred in the business combination. Instead, these transaction costs will require to be expensed under the new standards. The period of one year to complete the accounting for a business combination remains unchanged.
Non-controlling interests will require initial measurement at fair value and will be classified as a separate component of equity. FAS 141(R) is to be applied prospectively and is effective for the Company for business combinations for which the
acquisition date is on or after January 1, 2009. FAS 160 is effective for the Company on January 1, 2009 and is to be applied prospectively, with the exception of the presentation and disclosure requirements, which will require
retrospective application for all periods presented.

Derivative Instruments and Hedging Activities

In March 2008, the FASB issued FAS 161, Disclosures about Derivative Instruments and Hedging Activities  An amendment of FASB Statement
133. This standard requires qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the gains and losses on derivative contracts and details of credit-risk-related contingent features. The
standard also requires the disclosure of the location and amount of derivative instruments in the financial statements in a tabular format. This standard is effective for the Company on January 1, 2009 and will require additional disclosures on
the financial statements.

Hierarchy of Generally Accepted Accounting Principles

In May 2008, the FASB issued FAS 162, The Hierarchy of Generally Accepted Accounting Principles. This standard identifies the sources of
accounting principle and the framework for selecting the principles to be used in the preparation of financial statements. This standard is effective for the Company 60 days following the SECs approval of the PCAOBs amendments to AU
Section 411, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles. The Company does not expect the application of FAS 162 to have an impact on the financial statements.

Postretirement Benefit Plan Asset Disclosures

In
December 2008, the FASB issued FSP FAS 132(R)-1, which amends Statement 132(R) to require more detailed disclosure about employers plan assets, including employers investment strategies, major categories of plan assets, concentration of
risk within plan assets, and valuation techniques used to measure the fair value of plan assets. This standard is effective for the company on December 31, 2009 and will require additional disclosures on the financial statements.



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##### Table of Contents

Document D

Form 40-F



Managements Discussion and Analysis

February 18, 2009









---

##### Table of Contents

Managements Discussion and Analysis

February 18, 2009

Table of Contents



|    |  |                                                      |  |                                                       |  |   
|--- |  | ---------------------------------------------------- |  | ----------------------------------------------------- |  | --
|1.  |  | Financial Summary                                    |  | 3                                                    
|    |  | 1.1                                                  |  | Financial Position                                    |  | 3 
|    |  | 1.2                                                  |  | Financial Performance                                 |  | 3 
|    |  | 1.3                                                  |  | Total Shareholder Returns                             |  | 3 
|    |  | 1.4                                                  |  | Selected Annual Information                           |  | 4 
|2.  |  | Huskys Businesses                                   |  | 4                                                    
|3.  |  | Capability to Deliver Results                        |  | 4                                                    
|    |  | 3.1                                                  |  | Upstream                                              |  | 4 
|    |  | 3.2                                                  |  | Midstream                                             |  | 5 
|    |  | 3.3                                                  |  | Downstream                                            |  | 5 
|    |  | 3.4                                                  |  | Corporate                                             |  | 6 
|4.  |  | Strategic Plan                                       |  | 6                                                    
|    |  | 4.1                                                  |  | Upstream                                              |  | 6 
|    |  | 4.2                                                  |  | Midstream                                             |  | 7 
|    |  | 4.3                                                  |  | Downstream                                            |  | 7 
|    |  | 4.4                                                  |  | Financial                                             |  | 7 
|5.  |  | Key Growth Highlights                                |  | 7                                                    
|    |  | 5.1                                                  |  | Upstream                                              |  | 7 
|    |  | 5.2                                                  |  | Downstream                                            |  | 10
|6.  |  | The 2008 Business Environment                        |  | 10                                                   
|    |  | 6.1                                                  |  | Business Risk Factors                                 |  | 10
|    |  | 6.2                                                  |  | Economic Sensitivities                                |  | 11
|    |  | 6.3                                                  |  | Sensitivities by Segment for 2008 Results             |  | 14
|7.  |  | Results of Operations                                |  | 15                                                   
|    |  | 7.1                                                  |  | Segment Earnings                                      |  | 15
|    |  | 7.2                                                  |  | Summary of Quarterly Results                          |  | 15
|    |  | 7.3                                                  |  | Upstream                                              |  | 16
|    |  | 7.4                                                  |  | Midstream                                             |  | 28
|    |  | 7.5                                                  |  | Downstream                                            |  | 30
|    |  | 7.6                                                  |  | Corporate                                             |  | 33
|    |  | 7.7                                                  |  | Fourth Quarter                                        |  | 35
|    |  | 7.8                                                  |  | Results of Operations for 2007 Compared with 2006     |  | 36
|8.  |  | Liquidity and Capital Resources                      |  | 36                                                   
|    |  | 8.1                                                  |  | Summary of Cash Flow                                  |  | 36
|    |  | 8.2                                                  |  | Working Capital Components                            |  | 37
|    |  | 8.3                                                  |  | Cash Requirements                                     |  | 38
|    |  | 8.4                                                  |  | Off-Balance Sheet Arrangements                        |  | 39
|    |  | 8.5                                                  |  | Transactions with Related Parties and Major Customers |  | 40
|    |  | 8.6                                                  |  | Financial Risk and Risk Management                    |  | 40
|    |  | 8.7                                                  |  | Outstanding Share Data                                |  | 41
|9.  |  | Application of Critical Accounting Estimates         |  | 42                                                   
|10. |  | New and Pending Accounting Standards                 |  | 44                                                   
|11. |  | Reader Advisories                                    |  | 47                                                   
|    |  | 11.1                                                 |  | Forward-looking Statements                            |  | 47
|    |  | 11.2                                                 |  | Oil and Gas Reserve Reporting                         |  | 48
|    |  | 11.3                                                 |  | Non-GAAP Measures                                     |  | 48
|    |  | 11.4                                                 |  | Additional Reader Advisories                          |  | 49
|    |  | 11.5                                                 |  | Controls and Procedures                               |  | 52
|12. |  | Selected Quarterly Financial & Operating Information |  | 54                                                   



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##### Table of Contents

1. Financial Summary

1.1 Financial Position

LOGO

1.2 Financial Performance

LOGO

1.3 Total Shareholder Returns

The following table shows the total shareholder returns compared with the Standard and Poors and the Toronto Stock Exchange energy and composite
indices.



|                            |  |                   |    |  |                    |    |  |                       |   
|--------------------------- |  | ----------------- | -- |  | ------------------ | -- |  | --------------------- | --
|                            |  | Huskycommonshares |    |  | S&P/TSXenergyindex |    |  | S&P/TSXcompositeindex |   
|2004                        |  | 48                | %  |  | 29                 | %  |  | 12                    | % 
|2005                        |  | 77                | %  |  | 61                 | %  |  | 22                    | % 
|2006                        |  | 37                | %  |  | 3                  | %  |  | 15                    | % 
|2007                        |  | 18                | %  |  | 5                  | %  |  | 7                     | % 
|2008                        |  | (28               | )% |  | (36                | )% |  | (35                   | )%
|Five year average           |  | 30                | %  |  | 12                 | %  |  | 4                     | % 
|Five year cumulative return |  | 201               | %  |  | 43                 | %  |  | 9                     | % 



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##### Table of Contents

1.4 Selected Annual Information



|                                               |  |      |        |   |      |   |        |      |  |   |        |  
|---------------------------------------------- |  | ---- | ------ | - | ---- | - | ------ | ---- |  | - | ------ | -
|($ millions, except where indicated)           |  | 2008 |        |   | 2007 |   |        | 2006 | 
|Sales and operating revenues, net of royalties |  | $    | 24,701 |   |      | $ | 15,518 |      |  | $ | 12,664 |  
|Net earnings by sector                         |  |      |        |   |      |   |        |      |  |   |        |  
|Upstream                                       |  | $    | 3,377  |   |      | $ | 2,596  |      |  | $ | 2,295  |  
|Midstream                                      |  |      | 469    |   |      |   | 535    |      |  |   | 482    |  
|Downstream                                     |  |      | (295   | ) |      |   | 297    |      |  |   | 106    |  
|Corporate and eliminations                     |  |      | 203    |   |      |   | (214   | )    |  |   | (157   | )
|                                               |  |      |        |   |      |   |        |      |  |   |        |  
|Net earnings                                   |  | $    | 3,754  |   |      | $ | 3,214  |      |  | $ | 2,726  |  
|                                               |  |      |        |   |      |   |        |      |  |   |        |  
|Per share  basic/diluted                      |  | $    | 4.42   |   |      | $ | 3.79   |      |  | $ | 3.21   |  
|Ordinary dividends per common share            |  | $    | 1.70   |   |      | $ | 1.16   |      |  | $ | 0.88   |  
|Special dividend per common share              |  | $    |       |   |      | $ |       |      |  | $ | 0.25   |  
|Cash flow from operations                      |  | $    | 5,970  |   |      | $ | 5,426  |      |  | $ | 4,501  |  
|Total assets                                   |  | $    | 26,522 |   |      | $ | 21,697 |      |  | $ | 17,933 |  
|Long-term debt including current portion       |  | $    | 1,957  |   |      | $ | 2,814  |      |  | $ | 1,611  |  
|Cash and cash equivalents December 31          |  | $    | 913    |   |      | $ | 208    |      |  | $ | 442    |  
|Return on equity (percent)                     |  |      | 28.8   |   |      |   | 30.2   |      |  |   | 31.8   |  
|Return on average capital employed (percent)   |  |      | 25.0   |   |      |   | 25.7   |      |  |   | 27.0   |  

2. Huskys Businesses

Husky is a Canadian-based international energy and energy-related company with total assets greater than $26 billion and over 4,000 employees. Husky is
integrated through the three industry sectors: upstream, midstream and downstream.



| |  |  | In the upstream sector, the Company explores for, develops and produces crude oil and natural gas (upstream business segment).
| | - |  | ------------------------------------------------------------------------------------------------------------------------------



| |  |  | In the midstream sector, Husky upgrades heavy crude oil (upgrading business segment), processes and transports via pipeline heavy crude oil, maintains
interests in two cogeneration plants as well as markets and operates storage facilities for crude oil and natural gas (infrastructure and marketing business segment).
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | In the downstream sector, the Company distributes motor fuel and ancillary and convenience products, manufactures and markets asphalt products, produces ethanol and
operates two regional refineries in Canada (Canadian refined products business segment) and refines crude oil in two refineries in Ohio and markets refined products in the U.S. Midwest (U.S. refining and marketing business segment).
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

3. Capability to Deliver Results

Huskys ability to deliver results is dependent on commodity prices and foreign exchange rates, the Companys continued success in exploring for
oil and natural gas, efficient and safe execution of capital projects, efficient and safe operations, effective marketing, retention of expertise and continued access to the financial markets.

3.1 Upstream



| |  |  | Large base of crude oil producing properties in Western Canada that have responded well to the application of increasingly sophisticated exploitation techniques.
Enhanced oil recovery (EOR) techniques are extensively used in the mature Western Canadian Sedimentary Basin to increase recovery rates and stabilize decline rates of heavy and light crude oil. Emerging EOR techniques are being field
tested, while techniques that have been in practice for several decades continue to be optimized;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| |  |  | Expertise and experience exploring and developing the high impact natural gas potential in the deep basin, foothills, and northwest plains of Alberta and British
Columbia;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Substantial position in the Alberta oil sands. The initial stages of the development of this asset include the Tucker oil sands project currently in production and
the Sunrise project that is in the early development phase. The Sunrise project will proceed as a joint 50/50 partnership with BP and is an integral part of a North American oil sands business that includes the BP-Husky Toledo Refinery;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Harsh weather offshore exploration, development and production expertise as demonstrated by the successful White Rose development and further development of White
Rose satellites including the North Amethyst field, West White Rose field and South White Rose extension offshore Newfoundland. Husky also holds an interest in the Terra Nova field and a large portfolio of significant discovery and exploration
licenses offshore Newfoundland and Labrador and offshore Greenland;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Large acreage position offshore China that includes an interest in the Wenchang oil field which is producing, the Liwan natural gas discovery, which has commenced
development, and a large portfolio of exploration blocks; and
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Offshore Indonesia Husky holds significant discovery and exploration licenses. The Madura BD natural gas and natural gas liquids discovery, in which the Company
holds a 50% interest, is the current focus for development.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

3.2 Midstream



| |  |  | Reliable heavy oil upgrading facility located in the Lloydminster heavy oil producing region with a throughput capacity of 82 mbbls/day;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Reliable and efficient heavy oil pipeline systems well integrated in the Lloydminster producing region;
| | - |  | -------------------------------------------------------------------------------------------------------



| |  |  | Participation in two cogeneration power facilities having a combined 295 MW of capacity, both of which support local plant operations;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Natural gas storage in excess of 37 bcf, owned and leased;
| | - |  | ----------------------------------------------------------



| |  |  | Large scale petroleum marketer balancing the needs of both customers and suppliers; and
| | - |  | ---------------------------------------------------------------------------------------



| |  |  | Large scale supplier of crude oil and natural gas feedstock for the Companys plants and facilities.
| | - |  | ----------------------------------------------------------------------------------------------------

3.3 Downstream



| |  |  | Refinery at Lima, Ohio, and a 50% interest in the BP-Husky Refinery in Toledo, Ohio each with a crude oil throughput capacity of 160 mbbls/day;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Refinery at Prince George, British Columbia with 12 mbbls/day capacity of low sulphur gasoline and ultra low sulphur diesel;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------



| |  |  | Largest marketer of paving asphalt in Western Canada with a 28 mbbls/day capacity asphalt refinery located at Lloydminster, integrated with the local heavy oil
production, transportation and upgrading infrastructure;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Largest producer of ethanol in Western Canada with a combined 260 million litre per year capacity at plants located in Lloydminster, Saskatchewan and
Minnedosa, Manitoba; and
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Major regional motor fuel marketer with 492 retail marketing locations including bulk plants and travel centres with strategic land positions in Western Canada and
Ontario. Retail outlets include in many cases convenience stores, restaurants, service bays and carwashes.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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3.4 Corporate

Huskys corporate capabilities are discussed in the following sections:



| |  |  | Section 8. Liquidity and Capital Resources
| | - |  | ------------------------------------------



| |  |  | Section 
11.5 Controls and Procedures
| | - |  | -------------------------------------

4. Strategic Plan

Huskys overall strategy is to create superior shareholder value through financial discipline and the development of a quality asset base, including
the development of large scale sustainable oil and gas reserves and enhancing integration through the value chain.

Huskys upstream
strategy is to expand and develop the highly prospective basins offshore Southeast Asia, offshore Canadas East Coast, Alberta oil sands and heavy oil thermal production while continuing to exploit the Companys oil and gas asset base in
the Western Canadian Sedimentary Basin by optimizing oil and gas production with focussed exploration and enhanced recovery technology.

The Company will continue to build on its proven track record of creating value through the integrated production to refined products value chain, and will expand and optimize its midstream and downstream throughput capacity to enhance the
integration strategy.

In the current global economic environment, Husky is focussed on maintaining financial discipline and the strength
of the balance sheet in order to successfully execute this strategy. Huskys capital programs are funded principally by cash provided from operating activities and cash on hand. During periods of low commodity prices, capital will be directed
to those areas that provide the highest potential for returns and long-term growth. Long-term debt will supplement cash provided by operating activities in funding capital investments.

Huskys strategic direction by business segment is as follows:

4.1 Upstream

Husky continues to maximize the value of its assets offshore the East Coast of
Canada through the development of the White Rose satellite tieback fields and the continuing development of Terra Nova. The Company is also pursuing exploration opportunities and evaluating options to develop natural gas discoveries in the region.

Husky is building a Southeast Asia business with the development of current resources and exploration of prospects. The Company has
commenced a deep water drilling program at the Liwan natural gas discovery offshore China and will proceed with its development and also the development of the Madura BD Indonesia natural gas and natural gas liquids project. Husky will continue
exploration in the prospective basins in the South China Sea, the East China Sea and the North East Java Basin.

The Company is increasing
heavy oil production through cold production, thermal recovery and other enhanced recovery techniques integrated with downstream processing.

In Western Canada, Husky will optimize light and medium crude oil production with the application of selected enhanced recovery techniques and continue to focus on high impact natural gas plays in the foothills and deep basin portion of
Western Canada. The Company will expand its position in unconventional natural gas exploration and development including shale gas, tight gas and coal bed methane.



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Husky is well positioned in the oil sands business with approximately 550 thousand net acres of land
in the Athabasca and Cold Lake deposits in Alberta, Canada. Husky will continue to optimize the Tucker oil sands project which is currently producing. The Company, together with its partner BP, is continuing work on the Sunrise oil sands project
with production to be developed in stages up to an estimated peak rate of 200 mbbls/day. Husky will continue to evaluate its other oil sands holdings including the Saleski and Caribou projects.

4.2 Midstream

Husky will
continue to enhance and expand the infrastructure in the Lloydminster area and optimize the integration of the upgrader, pipeline, asphalt refinery, cogeneration and ethanol facilities. Husky will enhance and expand terminalling infrastructure and
services to meet the requirements associated with growing bitumen and heavy oil development and will pursue greenhouse gas management strategies including participation in industry initiatives, carbon offset opportunities, sequestration and
identification of carbon credit and trading opportunities.

4.3 Downstream

Husky will continue to pursue projects to optimize, integrate and reconfigure the Lima, Ohio Refinery for heavy crude oil feedstock and is planning to
reconfigure and expand the BP-Husky Toledo, Ohio Refinery to accommodate Sunrise production as its primary feedstock. The Company will also expand terminalling and product storage opportunities.

4.4 Financial

Husky is
committed to maintain its strong financial position to support large capital growth projects and provide shareholders an enhanced return on their investment. Over the business cycle, the Company intends to maintain a debt to capitalization ratio of
less than 40% and maintain debt to cash flow from operations of less than two times. During the current period of economic and financial uncertainty, action has been taken to maintain the Companys strong balance sheet including reduced capital
spending, implementation of cost containment and efficiency programs and managing access to credit markets to enhance liquidity.

5. Key Growth Highlights

To achieve corporate strategic objectives Husky focussed on the
following key projects in 2008. In 2009, the capital program will focus mainly on optimizing upstream production, midstream and downstream development and progressing major projects offshore the East Coast of Canada and South East Asia. The 2009
capital budget has been established with a view to maintaining the strength of Huskys balance sheet during a period of significant economic and financial uncertainty. Capital expenditures will be focussed on those projects offering the highest
potential for returns and long-term growth.

5.1 Upstream

White Rose Development Projects

Approval of the North Amethyst development application by the
CanadaNewfoundland and Labrador Offshore Petroleum Board (CNLOPB) and the provincial and federal governments was received in April 2008. Delineation wells were completed at both the North Amethyst and West White Rose satellite
fields, the results of which continue to be assessed with a view to optimizing production and reservoir depletion.

Progress continues on
the North Amethyst development, the first White Rose satellite tie-back. Engineering and procurement activities remain on track with System Integration Testing due to commence in the first quarter of 2009 followed by subsea equipment and flow line
installation and tie-back to the SeaRose production vessel in summer 2009.



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East Coast Exploration

In September 2008, Husky acquired two exploration blocks on the Labrador Shelf off the coast of Labrador. Parcel NL07-2-1 is 585,580 acres with a work commitment of $10.2 million (100% Husky working interest) and
Parcel NL07-2-3 is 557,502 acres with a work commitment of $120.2 million (75% Husky working interest). The work commitment will be undertaken during the first six years of the nine-year term of the Exploration Licence.

Husky participated in its largest offshore seismic acquisition program that was completed in September, covering 2,150 square kilometres including the
Terra Nova and White Rose areas and portions of ELs, 1090, 1091, 1099, 1100 and 1101.

In December, the Mizzen exploration well (35%
working interest) located in the Flemish Pass Basin, Exploration Licence (EL) 1049, was spud and is expected to reach total depth during the first quarter of 2009.

Offshore Greenland

The acquisition of 7,000 kilometres of 2-D seismic on Blocks 5 and 7 is now
complete and is being evaluated. Husky is the operator and holds an 87.5% interest in these two blocks. Husky also holds a 43.75% working interest in Block 6 where the acquisition of 3,000 kilometres of 2D seismic is complete.

Offshore China Liwan Delineation

The West
Hercules deep water drilling rig spud the first delineation well at the Liwan natural gas discovery on Block 29/26 in the South China Sea on November 20, 2008. The initial deep water drilling program will include delineation wells at Liwan
and exploration wells on other prospects in the area. The delineation program, including exploration wells at the satellite prospects, will provide key information for the Liwan projects facilities design which will commence in 2009.

Offshore China Exploration

On
June 25, 2008, Husky announced the acquisition of exploration Block 63/05 covering 1,777 square kilometres located in the natural gas prone Qiondongnan Basin approximately 100 kilometres south of Hainan Island. CNOOC Ltd. has the right to
participate in the development of any discoveries up to a 51% working interest. Under the terms of the petroleum contract, Husky has committed to drill one well and acquire 300 square kilometres of seismic data within a three-year period.

Husky completed a 3-D seismic data program on Block 29/26 in April 2008 and Block 29/06 in June 2008, which surround the Liwan natural gas
discovery. Acquisition of 3-D seismic data was also completed on Blocks 35/18 and 50/14, which are located to the west of Hainan Island in the Yinggehai Basin. The first phase exploration work commitment for these two Yinggehai blocks expires on
September 30, 2009.

At the end of 2008 the shallow water jack-up drilling rig, Frontier Discoverer, was secured and spud the
QH 29-2-1 exploration well on January 22, 2009. This well will test a prospect on Block 39/05 in the Pearl River Mouth Basin immediately southwest of the Wenchang oil fields. In addition, an exploration drilling program is being planned in the
East China Sea on Block 04/35 and in the Yinggehai Basin on blocks 35/18 and 50/14 near the Dong Fang and Ledong natural gas fields immediately west of Hainan Island.

In August 2008, Husky relinquished all but 58 square kilometres of Block 39/05, which surrounds the Wenchang oil fields, and secured an extension of Phase III exploration commitments. Subsequent to the evaluation of
the Wushi 23-2-1 exploration well and fulfillment of the Companys Phase II exploration commitments on Block 23/15 in the Beibu Wan Basin, Husky relinquished the remainder of this block.



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Indonesia Exploration and Development

In April 2008, Husky completed an agreement with CNOOC Ltd. to jointly develop the Madura BD gas and natural gas liquids field located offshore East Java,
Indonesia. Under the agreement, CNOOC Southeast Asia Limited acquired a 50% equity interest and operatorship of Husky Oil (Madura) Limited, which holds a 100% interest in the Madura Strait Production Sharing Contract (PSC). The agreement
covers the development and further exploration of the Madura Strait PSC. The Madura BD field development plan was approved by the government of Indonesia in July 2008 and Husky and its partner expect to receive an extension to the Production Sharing
Agreement (PSC) in 2009. Engineering work has been tendered and will commence upon receipt of the PSC extension.

In the East
Bawean II PSC, in which Husky holds a 100% interest, the Transocean Adriatic XI jack up rig has been secured to drill two exploration wells in the second quarter of 2009. During October 2008, Husky was awarded a PSC from the government of Indonesia
for a 100% interest in the North Sumbawa II Block comprising 5,000 square kilometres in the East Java Sea.

Sunrise Oil Sands Integrated Project

On March 31, 2008, Husky and BP formed an integrated oil sands joint venture. The transaction consists of a 50/50 partnership to
develop the Sunrise oil sands project in Canada, which Husky will operate, and a 50/50 limited liability company for the existing BP-Husky Toledo Refinery in Ohio, which BP operates.

The development of the Sunrise oil sands integrated project (Husky 50%) will proceed in multiple phases. Bitumen production is expected to commence
approximately four years following project sanction and is currently planned to increase to 200 mbbls/day. The project is currently in an optimization phase to simplify the projects scope and take advantage of the recent downturn in the demand
for goods and services. Subject to regulatory and government approval, the partners will review the project sanction decision in 2009 for formal approval in mid 2010. The development of this project is strategically linked to the repositioning
project at the BP-Husky Toledo Refinery.

Tucker Oil Sands Project

A number of optimization strategies to address the ramp-up issues at the Tucker SAGD project were investigated during 2008. Production from eight new well pairs is showing encouraging results. These well pairs, which
have been in SAGD mode for one to six months, have been placed in an optimized position in the reservoir. Drilling on the new Pad D has been deferred until commodity prices improve. During December 2008, Tuckers bitumen production averaged 4.8
mbbls/day. In January 2009, the Tucker oil sands project was integrated with Huskys heavy oil and gas business unit to capitalize on synergies with the Companys heavy oil thermal operations.

United States

In September 2008, Husky entered into
a joint venture agreement to acquire a 50% working interest in 844,000 net acres of leasehold ownership and wells in the U.S. Columbia River Basin in southeast Washington and northeast Oregon for consideration of approximately U.S. $100 per acre for
422,000 acres. Husky is currently participating in an exploration well, the Gray 31-23. The well had reached a depth of 3,800 metres in early January and planned total depth is 4,700 metres. The basin is characterized by over-pressure, tight sand
natural gas formations.

Western Canada

Huskys Alkaline Surfactant Polymer (ASP) enhanced oil recovery program, which currently includes ASP developments at Gull Lake and Fosterton, Saskatchewan and operating ASP applications at Warner and Crowsnest, Alberta,
continues to move forward. The front end engineering design for the Fosterton ASP project



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##### Table of Contents

commenced in December. Husky holds a 62.4% working interest. The drilling program and pipeline construction at Gull Lake are complete and facility
construction was approximately 60% complete at year end. Start up of the Gull Lake project is planned for the second quarter of 2009, subject to market conditions.

Huskys development of the McMullen property, which is located in the west central region of the Athabasca oil sands of northern Alberta, involves a cold production project and a thermal pilot project. In 2008,
the Company received approval to drill 18 cold production wells and 9 wells were drilled in 2008. Twenty-two delineation wells and 3 water source wells were completed by the end of 2008. An application to construct a pilot project has been submitted
to the Energy Resources Conservation Board.

During 2008, Husky participated (50%
working interest) in approximately 110 coal bed methane wells. In the Lloydminster heavy oil producing area, Husky is continuing to test various enhanced recovery techniques. In August 2008, CO2injection began at the Companys second cold solvent pilot project. This pilot project is designed to test oil recovery and production rates utilizing CO2and propane.

5.2 Downstream

Lima, Ohio Refinery

An engineering
evaluation has been completed to determine the reconfiguration of the Lima Refinery to increase its capacity to process heavier, less costly, crude oil feedstock; realize complex refining processes to enhance margins; and increase flexibility in
product outputs. The current configuration at the Lima Refinery allows it to process a predominantly light sweet crude oil feedstock. This limits the refinerys ability to process a lower cost heavier crude feedstock to meet seasonal and longer
term market demands. This project has been deferred subject to improved market conditions.

Toledo, Ohio Refinery

Husky and BP continued to progress the Continuous Catalyst Regeneration Reformer Project. The scope of this project is to replace two naphtha reformers
and one hydrogen plant with one 42,000 bbls/day continuous catalyst regeneration system plant. The projects objectives are to effectively and safely improve profitability while reducing operating risk, meet future product requirements and
reduce the environmental footprint. A project team has also been launched to reposition the refinery to process bitumen from the first two phases of the Sunrise oil sands integrated project. Due to the integrated nature of this project, progress
will coincide with the upstream development requirements. The refinery continues to make progress on a multi-year program to improve operational integrity and plant performance.

6. The 2008 Business Environment

6.1 Business Risk Factors

Huskys results of operations are significantly influenced by the global and domestic business environment. Some risk factors are
entirely beyond the Companys influence and others can, to some extent, be strategically managed. Salient risk factors include:



| |  |  | crude oil and natural gas prices;
| | - |  | ---------------------------------



| |  |  | the economic conditions of the markets in which Husky conducts business;
| | - |  | ------------------------------------------------------------------------



| |  |  | the price differential between light and heavy crude oil and demand related to various crude oil qualities;
| | - |  | -----------------------------------------------------------------------------------------------------------



| |  |  | the price differential between refined products and crude oil;
| | - |  | --------------------------------------------------------------



| |  |  | the exchange rate between the Canadian and U.S. dollar;
| | - |  | -------------------------------------------------------



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##### Table of Contents

| |  |  | the availability of incremental reserves of oil and gas, whether sourced from exploration, improved recovery or acquisitions;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------



| |  |  | 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, 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;
| | - |  | ------------------------------------------------------------------------------------------------



| |  |  | potential actions of governments, regulatory authorities and other stakeholders in the jurisdictions where the Company has operations;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------



| |  |  | prevailing climatic conditions in the Companys operating locations;
| | - |  | --------------------------------------------------------------------



| |  |  | regulations to deal with climate change issues;
| | - |  | -----------------------------------------------



| |  |  | 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; and
| | - |  | --------------------------------------------------------------------------------------------------



| |  |  | other financial risks as described in Section 8.6.
| | - |  | --------------------------------------------------

6.2 Economic Sensitivities

Average Benchmarks



|                                     |  |                |  |        |  |       |  |      
|------------------------------------ |  | -------------- |  | ------ |  | ----- |  | -----
|                                     |  | 2008           |  | 2007   |  | 2006 
|Upstream                             |  |                |  |        |  |       |  |      
|WTI crude oil                        |  | (U.S. $/bbl)   |  | 99.65  |  | 72.31 |  | 66.22
|Brent crude oil                      |  | (U.S. $/bbl)   |  | 96.99  |  | 72.52 |  | 65.14
|Canadian light crude 0.3% sulphur    |  | ($/bbl)        |  | 102.84 |  | 77.07 |  | 73.29
|Lloyd heavy crude oil @ Lloydminster |  | ($/bbl)        |  | 72.44  |  | 40.75 |  | 39.92
|NYMEX natural gas                    |  | (U.S. $/mmbtu) |  | 9.04   |  | 6.86  |  | 7.23 
|NIT natural gas                      |  | ($/GJ)         |  | 7.70   |  | 6.26  |  | 6.62 
|Midstream heavy crude oil upgrading  |  |                |  |        |  |       |  |      
|WTI/Lloyd crude blend differential   |  | (U.S. $/bbl)   |  | 20.38  |  | 23.81 |  | 22.00
|Downstream                           |  |                |  |        |  |       |  |      
|New York Harbor 3:2:1 crack spread   |  | (U.S. $/bbl)   |  | 9.96   |  | 14.15 |  | 9.80 
|Chicago 3:2:1 crack spread           |  | (U.S. $/bbl)   |  | 11.17  |  | 17.68 |  | 13.41
|Cross segment                        |  |                |  |        |  |       |  |      
|U.S./Canadian dollar exchange rate   |  | (U.S. $)       |  | 0.937  |  | 0.931 |  | 0.882

As an integrated producer, Huskys profitability is largely determined by realized prices for
crude oil and natural gas and refinery processing margins including the effect of changes in the U.S./Canadian dollar exchange rate. All of Huskys crude oil production and the majority of its natural gas production receive the prevailing
market price. The price for crude oil is determined largely by global factors and is beyond the Companys control. The price for natural gas is determined more by the North America 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 dramatic effect on short-term supply and demand.

Heavier grades of crude oil trade at a discount to light crude oil refinery feedstock since they are more costly to process into motor fuels.



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The majority of Huskys crude oil and natural gas production is marketed in North America.

In the midstream and downstream segments, the price of crude oil represents the largest cost and the price of natural gas is one of the
most significant operating costs. The largest cost factor in the midstreamupgrading business segment is the price of heavy crude oil feedstock, which is processed into light synthetic crude oil. The largest cost factors in the downstream
sector are crude feedstock and processing costs. Huskys U.S. refining operations process a mix of different types of crude oil from various sources but are primarily light sweet crude oil at Lima and approximately 60% heavy crude oil feedstock
at Toledo. The Companys refined products business in Canada relies primarily on the cost of purchasing refined products for resale in the retail distribution network. Refined products are acquired from other Canadian refiners at rack prices or
exchanged with production from the Husky Prince George refinery.

Refining margins (Crack Spread) are calculated as the price difference
between crude oil feedstock and two or more refined products in different proportions. The New York Harbor 3:2:1 refining crack spread is a benchmark and 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 is calculated using WTI, regular unleaded gasoline and low sulphur diesel. Each refinery has
a unique crack spread depending on several variables. The mix of different grades of crude oil feedstock and the mix of produced refined products result in different refinery crack spread calculations from quoted market benchmarks.

Crude Oil

LOGO

In 2008, the price of the main benchmark crude oil, West Texas Intermediate (WTI), initially
declined in the first weeks of 2008, and then increased steadily through to the beginning of July 2008. High prices in the first half of the year resulted in demand abatement in the United States toward mid year. In July 2008, global demand for
energy began to collapse following the global economic and financial crisis and prices fell through the fourth quarter. Production cuts announced by OPEC have not led to a measurable increase in oil prices. In light of an expected increase in
non-OPEC production and declining world consumption, the increase in surplus supply could further exacerbate the soft price environment. During 2008, the near-month contract price of WTI averaged U.S. $99.65/bbl and peaked above U.S. $145/bbl in mid
July before declining to U.S. $44.60/bbl on December 31, 2008. The average in 2007 was U.S. $72.31/bbl.

A portion of Huskys
crude oil production is classified as heavy crude oil, which trades at a discount to light crude oil. In 2008, 42% of Huskys crude oil production was heavy compared with 39% in 2007. The light/heavy crude oil differential averaged U.S. $20.38
or 20% of WTI in 2008 compared with U.S. $23.81 or 33% of WTI in 2007.



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Natural Gas

LOGO

Natural gas prices quoted on the NYMEX rose sharply through the first seven months of 2008 based on lower
storage levels and higher demand. After July 2008, natural gas prices fell steadily as natural gas storage levels increased as the North American economy weakened. At the end of 2008, natural gas inventory in underground storage in the United States
was 3% higher than the five year average and 1% higher than the previous year.

During 2008, the NYMEX near-month contract price of natural
gas averaged U.S. $9.04/mmbtu and peaked above U.S. $13.50/mmbtu at the beginning of July before declining to U.S. $5.62/mmbtu on December 31, 2008. The average in 2007 was U.S. $6.86/bbl.

Foreign Exchange

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. Huskys results are affected by the exchange rate between the Canadian and U.S. dollar with a
decrease in the value of the Canadian dollar relative to the U.S. dollar increasing the revenues received from the sale of oil and gas commodities offsetting the effect of lower oil and natural gas prices. Correspondingly, 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.

In 2008,
the Canadian dollar averaged U.S. $0.937, 1% stronger than the previous year. The Canadian dollar weakened 14% against the U.S. dollar in the fourth quarter, closing at $0.817 U.S. per Canadian dollar at December 31, 2008.

Refinery Crack Spreads

During 2008, the New York
Harbor 3:2:1 refining crack spread averaged U.S. $9.96/bbl compared with U.S. $14.15/bbl in 2007. During 2008, the Chicago crack spread averaged U.S. $11.17/bbl compared with U.S. $17.68/bbl in 2007.

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The lower 3:2:1 crack spreads were primarily due to low gasoline margins partially offset by higher
distillate margins. Lower gasoline margins resulted mainly from high cost feedstock and ethanol blending coincident with decreasing demand for gasoline resulting from a faltering economy in the U.S. Distillate margins were higher throughout 2008 due
to strong global demand. Realized refining margins are affected by the product configuration of each refinery and by the time lag between the purchase and delivery of crude oil feedstock which is accounted for on a first in first out basis in
accordance with Canadian Generally Accepted Accounting Principles (GAAP).

Cost Environment

The oil and gas industry has been experiencing an increase in costs in excess of the general rate of inflation. These increases affect the cost of
operating the Companys oil and gas properties, processing plants and refineries. They also affect capital projects which are susceptible to cost volatility. The cost environment has not yet been impacted to the same extent as commodity prices
by the current economic conditions.

Global Economic and Financial Crisis

The current global economic and financial crisis has reduced liquidity in financial markets, restricted access to financing and caused significant demand
destruction for commodities resulting in lower pricing. These have affected the economy in the latter half of 2008 and continue to impact the performance of the economy going forward. However, companies with low operating costs and flexible capital
expenditure plans, strong cash generation from operations, availability of cash and cash equivalents, low debt with long maturities and unused committed credit facilities will be better positioned to manage through this crisis.

In view of the current economic environment, Husky has prudently reduced capital spending in 2009 and is reviewing cost containment and efficiency
opportunities throughout the organization. Husky is managing its credit facilities and access to credit markets in order to enhance the Companys liquidity in the coming year. The Company will continue to monitor the economic environment and
make adjustments as required.

6.3 Sensitivities by Segment for 2008 Results

The following table is indicative of the relative annualized effect on pre-tax cash flow and net earnings from changes in certain key variables in 2008.
In essence, the disclosure shows what the effect would have been on 2008 financial results had the indicated variable increased by the notional amount. The analysis is based on business conditions and production volumes during 2008. 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.



|                                        |  |             |       |          |        |                               |  |     |                           |  |       |              |  |     |              |  |       |  
|--------------------------------------- |  | ----------- | ----- | -------- | ------ | ----------------------------- |  | --- | ------------------------- |  | ----- | ------------ |  | --- | ------------ |  | ----- | -
|Sensitivity Analysis                    |  | 2008Average |       | Increase |        | Effect on Pre-taxCash Flow(7) |  |     | Effect on Net Earnings(7) | 
|                                        |  |             |       |          |        | ($ millions)                  |  |     | ($/share)(8)              |  |       | ($ millions) |  |     | ($/share)(8) | 
|Upstream and Midstream                  |  |             |       |          |        |                               |  |     |                           |  |       |              |  |     |              |  |       |  
|WTI benchmark crude oil price (1)       |  | $           | 99.65 |          | U.S. $ | 1.00/bbl                      |  | 80  |                           |  | 0.09  |              |  | 56  |              |  | 0.07  |  
|NYMEX benchmark natural gas price (2)   |  | $           | 9.04  |          | U.S. $ | 0.20/mmbtu                    |  | 26  |                           |  | 0.03  |              |  | 18  |              |  | 0.02  |  
|WTI/Lloyd crude blend differential (3)  |  | $           | 20.38 |          | U.S. $ | 1.00/bbl                      |  | (17 | )                         |  | (0.02 | )            |  | (13 | )            |  | (0.02 | )
|Downstream                              |  |             |       |          |        |                               |  |     |                           |  |       |              |  |     |              |  |       |  
|Canadian light oil margins              |  | $           | 0.033 |          | Cdn $  | 0.005/litre                   |  | 14  |                           |  | 0.02  |              |  | 10  |              |  | 0.01  |  
|Asphalt margins                         |  | $           | 13.25 |          | Cdn $  | 1.00/bbl                      |  | 9   |                           |  | 0.01  |              |  | 6   |              |  | 0.01  |  
|New York Harbor 3:2:1 crack spread (4)  |  | $           | 9.96  |          | U.S. $ | 1.00/bbl                      |  | 68  |                           |  | 0.08  |              |  | 43  |              |  | 0.05  |  
|Consolidated                            |  |             |       |          |        |                               |  |     |                           |  |       |              |  |     |              |  |       |  
|Exchange rate (U.S. $ per Cdn $) (1)(5) |  | $           | 0.937 |          | U.S. $ | 0.01                          |  | (85 | )                         |  | (0.10 | )            |  | (60 | )            |  | (0.07 | )
|Interest rate (6)                       |  |             |       |          |        | 100 basis points              |  |    |                           |  |      |              |  |    |              |  |      |  



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|(1) | Does not include gains or losses on inventory.
|--- | ----------------------------------------------

|(2) | Includes decrease in earnings related to natural gas consumption.
|--- | -----------------------------------------------------------------

|(3) | Excludes impact on asphalt operations.
|--- | --------------------------------------

|(4) | Relates to U.S. Refining & Marketing.
|--- | -------------------------------------

|(5) | Assumes no foreign exchange gains or losses on U.S. dollar denominated long-term debt and other monetary items, including cash balances.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------

|(6) | An interest rate change would not have an impact as Husky did not have variable rate debt outstanding as of December 31, 2008.
|--- | ------------------------------------------------------------------------------------------------------------------------------

|(7) | Excludes derivatives.
|--- | ---------------------

|(8) | Based on 849.4 million common shares outstanding as of December 31, 2008.
|--- | -------------------------------------------------------------------------

7. Results of Operations

7.1 Segment Earnings



|                                    |  |          |           |           |                             |            |                         |   |                           |  |   |       |  |   |      |   |  |   |      |   |  |   |      
|----------------------------------- |  | -------- | --------- | --------- | --------------------------- | ---------- | ----------------------- | - | ------------------------- |  | - | ----- |  | - | ---- | - |  | - | ---- | - |  | - | -----
|Segment Earnings                    |  |          |          
|                                    |  | Upstream |           | Midstream |                             | Downstream |                         |   | Corporate andEliminations |  |   | Total
|($ millions)                        |  |          | Upgrading |           | Infrastructureand Marketing |            | CanadianRefinedProducts |   | U.S. RefiningandMarketing |  |   |      
|2008                                |  |          |           |           |                             |            |                         |   |                           |  |   |       |  |   |      |   |  |   |      |   |  |   |      
|Earnings (loss) before income taxes |  | $        | 4,757     |           | $                           | 350        |                         | $ | 321                       |  | $ | 146   |  | $ | (632 | ) |  | $ | 208  |   |  | $ | 5,150
|Net earnings (loss)                 |  |          | 3,377     |           |                             | 245        |                         |   | 224                       |  |   | 106   |  |   | (401 | ) |  |   | 203  |   |  |   | 3,754
|Capital expenditures (1)            |  |          | 3,580     |           |                             | 99         |                         |   | 94                        |  |   | 155   |  |   | 133  |   |  |   | 47   |   |  |   | 4,108
|                                    |  |          |           |           |                             |            |                        
|2007                                |  |          |           |           |                             |            |                         |   |                           |  |   |       |  |   |      |   |  |   |      |   |  |   |      
|Earnings (loss) before income taxes |  |          | 3,299     |           |                             | 372        |                         |   | 351                       |  |   | 242   |  |   | 168  |   |  |   | (305 | ) |  |   | 4,127
|Net earnings (loss)                 |  |          | 2,596     |           |                             | 282        |                         |   | 253                       |  |   | 192   |  |   | 105  |   |  |   | (214 | ) |  |   | 3,214
|Capital expenditures (1)            |  |          | 2,388     |           |                             | 217        |                         |   | 92                        |  |   | 212   |  |   | 21   |   |  |   | 44   |   |  |   | 2,974
|                                    |  |          |           |           |                             |            |                        
|2006                                |  |          |           |           |                             |            |                         |   |                           |  |   |       |  |   |      |   |  |   |      |   |  |   |      
|Earnings (loss) before income taxes |  |          | 2,975     |           |                             | 382        |                         |   | 277                       |  |   | 146   |  |   |     |   |  |   | (274 | ) |  |   | 3,506
|Net earnings (loss)                 |  |          | 2,295     |           |                             | 285        |                         |   | 197                       |  |   | 106   |  |   |     |   |  |   | (157 | ) |  |   | 2,726
|Capital expenditures (1)            |  |          | 2,627     |           |                             | 184        |                         |   | 68                        |  |   | 285   |  |   |     |   |  |   | 37   |   |  |   | 3,201



|(1) | Excludes capitalized costs related to asset retirement obligations incurred during the period and the Lima acquisition and the BP joint venture transaction.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------

7.2 Summary of Quarterly Results

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7.3 Upstream

2008 Earnings $3,377 Million, up $781 Million from 2007

LOGO

Upstream Earnings Summary



|                                         |  |      |       |      |   |       |      |  |   |      
|---------------------------------------- |  | ---- | ----- | ---- | - | ----- | ---- |  | - | -----
|($ millions)                             |  | 2008 |       | 2007 |   |       | 2006
|Gross revenues                           |  | $    | 9,932 |      | $ | 7,287 |      |  | $ | 6,586
|Royalties                                |  |      | 2,043 |      |   | 1,065 |      |  |   | 814  
|                                         |  |      |       |      |   |       |      |  |   |      
|Net revenues                             |  |      | 7,889 |      |   | 6,222 |      |  |   | 5,772
|Operating and administration expenses    |  |      | 1,596 |      |   | 1,409 |      |  |   | 1,321
|Depletion, depreciation and amortization |  |      | 1,505 |      |   | 1,615 |      |  |   | 1,476
|Other                                    |  |      | 31    |      |   | (101  | )    |  |   |     
|Income taxes                             |  |      | 1,380 |      |   | 703   |      |  |   | 680  
|                                         |  |      |       |      |   |       |      |  |   |      
|Net earnings                             |  | $    | 3,377 |      | $ | 2,596 |      |  | $ | 2,295
|                                         |  |      |       |      |   |       |      |  |   |      

Upstream earnings were $781 million higher in 2008 compared with 2007 primarily as a result of higher crude oil
and natural gas prices which more than offset decreases in production. Earnings in 2007 include a recovery of income taxes of $330 million reflecting changes in the statutory tax rate announced in 2007. Higher royalties are a result of East Coast
production reaching Tier II status at White Rose and Terra Nova in March, 2008.

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|                                    |  |      |   |  |      |   |  |      |  
|----------------------------------- |  | ---- | - |  | ---- | - |  | ---- | -
|Upstream Revenue Mix                | 
|Percentage of upstream net revenues |  | 2008 |   |  | 2007 |   |  | 2006 |  
|Crude oil                           |  |      |   |  |      |   |  |      |  
|Light crude oil & NGL               |  | 41   | % |  | 51   | % |  | 45   | %
|Medium crude oil                    |  | 8    | % |  | 7    | % |  | 7    | %
|Heavy crude oil & bitumen           |  | 30   | % |  | 22   | % |  | 24   | %
|Natural gas                         |  | 21   | % |  | 20   | % |  | 24   | %
|                                    |  |      |   |  |      |   |  |      |  
|                                    |  | 100  | % |  | 100  | % |  | 100  | %
|                                    |  |      |   |  |      |   |  |      |  



|                              |  |      |       |      |   |       |  |   |      
|----------------------------- |  | ---- | ----- | ---- | - | ----- |  | - | -----
|Average Sales Prices Realized
|                              |  | 2008 |       | 2007 |   | 2006 
|Crude oil($/bbl)              |  |      |       |      |   |       |  |   |      
|Light crude oil & NGL         |  | $    | 97.28 |      | $ | 73.54 |  | $ | 69.06
|Medium crude oil              |  |      | 81.79 |      |   | 51.12 |  |   | 49.48
|Heavy crude oil & bitumen     |  |      | 71.61 |      |   | 40.19 |  |   | 39.92
|Total average                 |  |      | 84.96 |      |   | 58.24 |  |   | 54.08
|Natural gas($/mcf)            |  |      |       |      |   |       |  |   |      
|Average                       |  | $    | 7.94  |      | $ | 6.19  |  | $ | 6.47 
|                              |  |      |       |      |   |       |  |   |      



|                               |  |       |  |       |  |      
|------------------------------ |  | ----- |  | ----- |  | -----
|Daily Gross Production         |  |       |  |       |  |      
|                               |  | 2008  |  | 2007  |  | 2006 
|Crude oil (mbbls/day)          |  |       |  |       |  |      
|Western Canada                 |  |       |  |       |  |      
|Light crude oil & NGL          |  | 24.6  |  | 26.5  |  | 30.4 
|Medium crude oil               |  | 26.9  |  | 27.1  |  | 28.5 
|Heavy crude oil & bitumen      |  | 107.0 |  | 106.9 |  | 108.1
|                               |  |       |  |       |  |      
|                               |  | 158.5 |  | 160.5 |  | 167.0
|East Coast Canada              |  |       |  |       |  |      
|White Roselight crude oil     |  | 73.2  |  | 85.0  |  | 63.8 
|Terra Novalight crude oil     |  | 12.9  |  | 14.5  |  | 4.7  
|China                          |  |       |  |       |  |      
|Wenchanglight crude oil & NGL |  | 12.2  |  | 12.7  |  | 12.1 
|                               |  |       |  |       |  |      
|                               |  | 256.8 |  | 272.7 |  | 247.6
|                               |  |       |  |       |  |      
|Natural gas (mmcf/day)         |  | 594.4 |  | 623.3 |  | 672.3
|                               |  |       |  |       |  |      
|Total (mboe/day)               |  | 355.9 |  | 376.6 |  | 359.7
|                               |  |       |  |       |  |      

In 2008, crude oil and NGL production decreased by 6% compared with the previous year. Production
from the White Rose field was shut down for 11 days in April due to the encroachment of severe ice pack and iceberg conditions, which also delayed the drilling of the eighth producing well, and for 4 days in September due to offloading operational
restrictions combined with tanker availability. White Rose was shut down for 16 days for scheduled maintenance in July 2007. In June 2008, Terra Nova was shut down for 14 days for a scheduled maintenance turnaround and in the third and fourth
quarters operational and maintenance issues also resulted in reduced production.

During 2008, crude oil and NGL production from Western
Canada was down 1% compared with 2007 primarily due to reservoir decline, development delays and shut-in facilities. In Western Canada, conventional light and medium crude oil production was affected by net divestitures and normal production
declines. Bitumen production from the Tucker oil sands project has increased from 2.1 mbbls/day at the end of 2007 to 4.8 mbbls/day at the end of 2008.



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Production from natural gas decreased by 5% in 2008 compared with 2007 due to lower levels of drilling in
the fourth quarter of 2007 versus the fourth quarter of 2006 which support production in the following years. Husky drilled 92 net natural gas exploration wells and 251 net development wells in 2007 compared with 192 net exploration and 490 net
development wells in 2006 which resulted in fewer additions to producing wells. This reduction in drilling contributed to a drop in natural gas production in 2008 in all quarters. In addition, pipeline capacity was lower in the fourth quarter of
2008 as a result of unplanned repairs and maintenance combined with unscheduled plant outages and in the first quarter natural gas production was impacted by severe cold weather.

2009 Production Guidance and 2008 Actual



|                                           |  |              |  |                           |  |                     
|------------------------------------------ |  | ------------ |  | ------------------------- |  | --------------------
|Gross Production                           |  | Guidance2009 |  | Year endedDecember 312008 |  | OriginalGuidance2008
|Crude oil & NGL (mbbls/day)                |  |              |  |                           |  |                     
|Light crude oil & NGL                      |  | 92 -109      |  | 123                       |  | 139 -148            
|Medium crude oil                           |  | 25 - 28      |  | 27                        |  | 28 - 29             
|Heavy crude oil & bitumen                  |  | 95 -105      |  | 107                       |  | 114 - 124           
|                                           |  |              |  |                           |  |                     
|                                           |  | 212 -242     |  | 257                       |  | 281 - 301           
|Natural gas (mmcf/day)                     |  | 585 -620     |  | 594                       |  | 625 - 655           
|Total barrels of oil equivalent (mboe/day) |  | 310 - 345    |  | 356                       |  | 385 - 410           
|                                           |  |              |  |                           |  |                     

Production in 2008 was consistent with Huskys revised guidance of July, 2008. Reduced
production levels in 2009 are expected due to facility turnaround activities at White Rose and Terra Nova, a period of reduced production at White Rose to allow for the tie-in of the North Amethyst satellite and reduced spending in Western Canada.

Royalties

Royalty rates for 2008
averaged 16% in Western Canada and 28% offshore the East Coast compared with 16% and 13% respectively in 2007. The Tier II incremental royalty rate became effective for White Rose and Terra Nova in March 2008.

Operating Costs

Total upstream unit operating costs
in 2008 averaged $10.93/boe compared with $9.09/boe in 2007. Operating costs in Western Canada averaged $13.16 in 2008 compared with $11.25 in 2007. Increasing operating costs in Western Canada are generally related to the nature of exploitation
necessary to manage production from maturing fields and new more extensive but less prolific reservoirs. Western Canada operations require increasing amounts of infrastructure including more wells, facilities associated with enhanced recovery
schemes, more extensive pipeline systems, crude and water trucking and more complex natural gas compression systems. These factors in turn require higher energy consumption, workovers and generally more material costs. Husky is focussed on managing
rising operating costs through cost reduction and efficiency initiatives and keeping the Companys infrastructure, including gas plants, crude processing plants, transportation systems, compression systems, lease access and other infrastructure
fully utilized.

Operating costs at the East Coast offshore operations averaged $4.99/bbl in 2008 compared with $4.07/bbl in 2007. Costs
increased compared with the previous year due to additional resources required to manage ice encroachment and subsurface mechanical issues.

Operating costs at the South China Sea offshore operations averaged $4.78/bbl compared with $3.68/bbl in 2007. Increased costs were the result of well workovers undertaken to support production from the declining reservoir.



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Depletion, Depreciation and Amortization (DD&A)

DD&A under the full cost method of accounting for oil and gas activities is calculated on a country-by-country basis. The DD&A rate is calculated
by dividing the capital costs subject to DD&A by the proved oil and gas reserves expressed as equivalent barrels (boe). The resultant dollar per boe is assigned to each boe of production to determine the DD&A expense for the
period.

In 2008, total unit DD&A averaged $11.56/boe compared with $11.75/boe in 2007. DD&A in Canada averaged $11.58/boe in 2008
compared with $11.77/boe in 2007. The lower DD&A rate in Canada was primarily due to the disposition of 50% of the Sunrise oil sands asset, which reduced the full cost base by approximately $1.6 billion or $1.29/boe in 2008. The Sunrise oil
sands project currently does not have any proved reserves attributed to it. This was partially offset by a higher cost base in respect of conventional oil and gas operations in Western Canada and lower oil and gas reserves.

At December 31, 2008, capital costs in respect of unproved properties and major development projects were $3.2 billion compared with $2.2 billion at
the end of 2007. These costs are excluded from the Companys DD&A calculation until the unproved properties are evaluated and proved reserves are attributed to the project or the project is deemed to be impaired.

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|                                    |  |        |  |       |   |  |      
|----------------------------------- |  | ------ |  | ----- | - |  | -----
|Netback Analysis                    |  |        |  |       |   |  |      
|                                    |  | 2008   |  | 2007  |   |  | 2006 
|Total                               |  |        |  |       |   |  |      
|Crude oil equivalent (per boe)(1)   |  |        |  |       |   |  |      
|Gross price                         |  | 74.57  |  | 52.41 |   |  | 49.34
|Royalties                           |  | 15.52  |  | 7.74  |   |  | 6.19 
|                                    |  |        |  |       |   |  |      
|Net sales price                     |  | 59.05  |  | 44.67 |   |  | 43.15
|Operating costs (2)                 |  | 10.93  |  | 9.09  |   |  | 8.77 
|                                    |  |        |  |       |   |  |      
|                                    |  | 48.12  |  | 35.58 |   |  | 34.38
|DD&A                                |  | 11.56  |  | 11.75 |   |  | 11.24
|Administration expenses & other (2) |  | 0.05   |  | (0.17 | ) |  | 0.48 
|                                    |  |        |  |       |   |  |      
|Earnings before income taxes        |  | 36.51  |  | 24.00 |   |  | 22.66
|                                    |  |        |  |       |   |  |      
|Canada                              |  |        |  |       |   |  |      
|Crude oil equivalent (per boe)(1)   |  |        |  |       |   |  |      
|Gross price                         |  | 73.72  |  | 51.54 |   |  | 48.48
|Royalties                           |  | 15.09  |  | 7.46  |   |  | 6.00 
|                                    |  |        |  |       |   |  |      
|Net sales price                     |  | 58.63  |  | 44.08 |   |  | 42.48
|Operating costs (2)                 |  | 11.14  |  | 9.28  |   |  | 9.01 
|                                    |  |        |  |       |   |  |      
|Operating netback                   |  | 47.49  |  | 34.80 |   |  | 33.47
|                                    |  |        |  |       |   |  |      
|Western Canada                      |  |        |  |       |   |  |      
|Crude oil (per boe) (1)             |  |        |  |       |   |  |      
|Light crude oil                     |  |        |  |       |   |  |      
|Gross price                         |  | 82.97  |  | 61.02 |   |  | 59.84
|Royalties                           |  | 11.53  |  | 7.87  |   |  | 7.34 
|                                    |  |        |  |       |   |  |      
|Net sales price                     |  | 71.44  |  | 53.15 |   |  | 52.50
|Operating costs (2)                 |  | 13.90  |  | 13.24 |   |  | 11.89
|                                    |  |        |  |       |   |  |      
|Operating netback                   |  | 57.54  |  | 39.91 |   |  | 40.61
|                                    |  |        |  |       |   |  |      
|Medium crude oil                    |  |        |  |       |   |  |      
|Gross price                         |  | 79.91  |  | 50.42 |   |  | 48.97
|Royalties                           |  | 13.91  |  | 8.89  |   |  | 8.61 
|                                    |  |        |  |       |   |  |      
|Net sales price                     |  | 66.00  |  | 41.53 |   |  | 40.36
|Operating costs (2)                 |  | 15.60  |  | 13.92 |   |  | 13.09
|                                    |  |        |  |       |   |  |      
|Operating netback                   |  | 50.40  |  | 27.61 |   |  | 27.27
|                                    |  |        |  |       |   |  |      
|Heavy crude oil & bitumen           |  |        |  |       |   |  |      
|Gross price                         |  | 71.19  |  | 40.14 |   |  | 39.91
|Royalties                           |  | 10.52  |  | 5.26  |   |  | 5.16 
|                                    |  |        |  |       |   |  |      
|Net sales price                     |  | 60.67  |  | 34.88 |   |  | 34.75
|Operating costs (2)                 |  | 15.60  |  | 12.81 |   |  | 11.10
|                                    |  |        |  |       |   |  |      
|Operating netback                   |  | 45.07  |  | 22.07 |   |  | 23.65
|                                    |  |        |  |       |   |  |      
|Natural gas (per mcfge)(3)          |  |        |  |       |   |  |      
|Gross price                         |  | 8.21   |  | 6.42  |   |  | 6.65 
|Royalties                           |  | 1.60   |  | 1.23  |   |  | 1.37 
|                                    |  |        |  |       |   |  |      
|Net sales price                     |  | 6.61   |  | 5.19  |   |  | 5.28 
|Operating costs (2)                 |  | 1.59   |  | 1.39  |   |  | 1.18 
|                                    |  |        |  |       |   |  |      
|Operating netback                   |  | 5.02   |  | 3.80  |   |  | 4.10 
|                                    |  |        |  |       |   |  |      
|East Coast                          |  |        |  |       |   |  |      
|Light crude oil (per boe)(1)        |  |        |  |       |   |  |      
|Gross price                         |  | 100.12 |  | 75.37 |   |  | 71.18
|Royalties (4)                       |  | 28.45  |  | 9.43  |   |  | 1.95 
|                                    |  |        |  |       |   |  |      
|Net sales price                     |  | 71.67  |  | 65.94 |   |  | 69.23
|Operating costs (2)                 |  | 4.99   |  | 4.07  |   |  | 5.48 
|                                    |  |        |  |       |   |  |      
|Operating netback                   |  | 66.68  |  | 61.87 |   |  | 63.75
|                                    |  |        |  |       |   |  |      
|International                       |  |        |  |       |   |  |      
|Light crude oil (per boe)(1)        |  |        |  |       |   |  |      
|Gross price                         |  | 98.70  |  | 77.07 |   |  | 73.60
|Royalties                           |  | 27.46  |  | 15.50 |   |  | 12.17
|                                    |  |        |  |       |   |  |      
|Net sales price                     |  | 71.24  |  | 61.57 |   |  | 61.43
|Operating costs (2)                 |  | 4.86   |  | 3.84  |   |  | 3.81 
|                                    |  |        |  |       |   |  |      
|Operating netback                   |  | 66.38  |  | 57.73 |   |  | 57.62
|                                    |  |        |  |       |   |  |      



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##### Table of Contents



|(1) | Includes associated co-products converted to boe.
|--- | -------------------------------------------------

|(2) | Operating costs exclude accretion, which is included in administration expenses & other.
|--- | ----------------------------------------------------------------------------------------

|(3) | Includes associated co-products converted to mcfge.
|--- | ---------------------------------------------------

|(4) | During the third quarter of 2007, White Rose royalties increased to 16% because the project, off the East Coast,
achieved payout status for Tier 1 royalties. During March 2008, White Rose and Terra Nova achieved payout status for Tier 2 royalties.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Other Items

In 2008, a drilling contract previously treated as an embedded derivative no longer met the criteria and the
related accounting treatment was discontinued. A loss of $101 million ($71 million after tax) was recorded in 2008 compared with a gain of $101 million ($71 million after tax) for the same period in 2007.

A gain of $69 million was recorded on the sale of 50% of the shares of Husky Oil (Madura) Limited to CNOOC Southeast Asia Limited.

Upstream Capital Expenditures

At December 31,
2008, overall upstream capital expenditures were $3.6 billion, including acquisitions. Huskys major upstream projects offshore the East Coast of Canada and offshore China and Indonesia remain essentially on schedule. Capital expenditures were
$2.6 billion (72%) in Western Canada, $729 million (20%) offshore the East Coast of Canada, $230 million (6%) offshore China and Indonesia and $60 million (2%) in the Northwest United States.



|                                  |  |      |       |      |   |       |  |   |      
|--------------------------------- |  | ---- | ----- | ---- | - | ----- |  | - | -----
|Upstream Capital Expenditures (1) |  |      |       |      |   |       |  |   |      
|($ millions)                      |  | 2008 |       | 2007 |   | 2006 
|Exploration                       |  |      |       |      |   |       |  |   |      
|Western Canada                    |  | $    | 680   |      | $ | 456   |  | $ | 497  
|East Coast Canada and Frontier    |  |      | 160   |      |   | 84    |  |   | 79   
|Northwest United States           |  |      | 60    |      |   |      |  |   |     
|International                     |  |      | 225   |      |   | 70    |  |   | 77   
|                                  |  |      |       |      |   |       |  |   |      
|                                  |  |      | 1,125 |      |   | 610   |  |   | 653  
|                                  |  |      |       |      |   |       |  |   |      
|Development                       |  |      |       |      |   |       |  |   |      
|Western Canada                    |  |      | 1,881 |      |   | 1,575 |  |   | 1,675
|East Coast Canada                 |  |      | 569   |      |   | 197   |  |   | 279  
|International                     |  |      | 5     |      |   | 6     |  |   | 20   
|                                  |  |      |       |      |   |       |  |   |      
|                                  |  |      | 2,455 |      |   | 1,778 |  |   | 1,974
|                                  |  |      |       |      |   |       |  |   |      
|                                  |  | $    | 3,580 |      | $ | 2,388 |  | $ | 2,627
|                                  |  |      |       |      |   |       |  |   |      



|(1) | Excludes capitalized costs related to asset retirement obligations incurred during the period and the Lima acquisition and the BP joint venture transaction.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------



|                        |  |       |  |       |  |       |  |     |  |       |  |      
|----------------------- |  | ----- |  | ----- |  | ----- |  | --- |  | ----- |  | -----
|Western Canada Drilling
|                        |  | 2008  |  | 2007  |  | 2006 
|(wells)                 |  | Gross |  | Net   |  | Gross |  | Net |  | Gross |  | Net  
|Exploration Oil         |  | 80    |  | 70    |  | 79    |  | 79  |  | 101   |  | 99   
|Gas                     |  | 102   |  | 79    |  | 114   |  | 92  |  | 330   |  | 192  
|Dry                     |  | 27    |  | 23    |  | 14    |  | 12  |  | 26    |  | 24   
|                        |  |       |  |       |  |       |  |     |  |       |  |      
|                        |  | 209   |  | 172   |  | 207   |  | 183 |  | 457   |  | 315  
|                        |  |       |  |       |  |       |  |     |  |       |  |      
|Development Oil         |  | 685   |  | 578   |  | 571   |  | 530 |  | 590   |  | 543  
|Gas                     |  | 435   |  | 270   |  | 343   |  | 251 |  | 565   |  | 490  
|Dry                     |  | 36    |  | 36    |  | 31    |  | 29  |  | 25    |  | 22   
|                        |  |       |  |       |  |       |  |     |  |       |  |      
|                        |  | 1,156 |  | 884   |  | 945   |  | 810 |  | 1,180 |  | 1,055
|                        |  |       |  |       |  |       |  |     |  |       |  |      
|Total                   |  | 1,365 |  | 1,056 |  | 1,152 |  | 993 |  | 1,637 |  | 1,370
|                        |  |       |  |       |  |       |  |     |  |       |  |      



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##### Table of Contents

Western CanadaExcluding Oil Sands

During 2008, Husky invested $2.2 billion on exploration and development throughout the Western Canadian Sedimentary Basin excluding oil sands. Of this,
$678 million was invested on oil development and $360 million was invested on natural gas development. The Company drilled 1,056 net wells in the basin resulting in 648 net oil wells and 349 net natural gas wells. In addition, $211 million was spent
on production optimization and operating cost reduction initiatives. Capital spending on facilities, land acquisition and retention and environmental protection amounted to $291 million. During 2008, $308 million was spent on property acquisitions.

Huskys high impact exploration program is conducted along the foothills of Alberta and British Columbia and in the deep basin region
of Alberta. In 2008, $362 million was invested in drilling in these natural gas prone areas. During this period, 25 net exploration wells were drilled in the foothills and deep basin regions; 21 net wells were cased as natural gas wells and one was
cased as a net oil well. The remaining 147 net exploration wells were drilled primarily in the shallow regions of the Western Canada Sedimentary Basin.

Oil Sands

Oil sands capital expenditures totalled $302 million during 2008. At Tucker, Husky spent $90 million on
completion of new well pairs, facility modification and new pad preparation. At Sunrise, $143 million was spent on engineering design, site preparation and facilities and equipment requisitions. At Caribou and Saleski, the Company spent $69 million
on stratigraphic drilling and engineering and geophysical studies.

East Coast Development

During 2008, $569 million was incurred for East Coast development projects primarily for the North Amethyst and West White Rose tie-back development
projects and completion of an infill production well and other capital enhancements at White Rose. Construction commenced on North Amethyst and long lead equipment was procured. Engineering design began at the West White Rose development and a
production well and water injection well were drilled at the White Rose South Avalon field.

East Coast and Northwest Territories Exploration

During 2008, Husky spent $160 million on two exploration wells in the Central Mackenzie Valley and on East Coast seismic programs.

Northwest United States

On
September 30, 2008, Husky spent $50 million to acquire petroleum and natural gas rights in the Columbia River Basin located in southeastern Washington and northeast Oregon and a 50% interest in an exploration well currently being drilled.

Offshore China and Indonesia

During 2008, $225
million was spent on exploration drilling in the South China Sea and seismic data acquisition on the East Bawean II exploration block in the Java Sea, Indonesia.

2009 Upstream Capital Program



|                             |  |   |      
|---------------------------- |  | - | -----
|($ millions)                 |  |  
|Western Canada - oil and gas |  | $ | 725  
|- oil sands                  |  |   | 65   
|East Coast Canada            |  |   | 800  
|International                |  |   | 500  
|                             |  |   |      
|                             |  | $ | 2,090
|                             |  |   |      



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Note: Capital program excludes capitalized administration costs, capitalized interest and asset retirement obligations
incurred.

The 2009 capital budget has been established with a view to maintaining the strength of Huskys balance sheet during a
period of significant economic and financial uncertainty. Capital expenditures will be focussed on those projects offering the highest potential for returns and long-term growth. A number of projects have been deferred pending improved economics.

Capital expenditures for Western Canada upstream development and exploration will continue to optimize oil and gas producing assets and
develop new resource plays. Capital spending on oil sands will be primarily to continue to ramp up Tucker production and optimize development planning at Sunrise.

Offshore the East Coast of Canada, spending will be for North Amethyst tie-back development and to advance the West White Rose tie-back project.

In China and Indonesia, capital spending will be for the delineation and evaluation of the Liwan natural gas discovery, Madura BD, Indonesia natural gas
and liquids development and exploration programs offshore China and Indonesia.

Oil and Gas Reserves

Husky applied for and was granted an exemption from certain of the provisions of Canadas National Instrument 51-101 Standards of Disclosure
for Oil and Gas Activities and provides oil and gas reserves disclosures in accordance with the United States Securities and Exchange Commission (SEC) guidelines and the United States Financial Accounting Standards Board
(FASB) disclosure standards. The information disclosed may differ from information prepared in accordance with National Instrument 51-101.

LOGO

Note: Based on year end prices.

For more detail on the Companys oil and gas reserves and the disclosures with respect to the FASBs Statement No. 69, Disclosures
about Oil and Gas Producing Activities and the differences between Huskys disclosures and those prescribed by National Instrument 51-101, refer to Huskys Annual Information Form available at www.sedar.com or Huskys
Form 40-F available at www.sec.gov or on the Companys website at www.huskyenergy.com.

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



PAGE 23



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##### Table of Contents

Associates Consultants Ltd. issued an audit opinion stating that Huskys internally generated proved and probable reserves and net present values are,
in aggregate, reasonable, and have been prepared in accordance with generally accepted oil and gas engineering and evaluation practices in the United States and as set out in the Canadian Oil and Gas Evaluation Handbook.

Huskys proved oil and gas reserves at December 31, 2008 were 896 million boe, down 118 mmboe or 12% from the previous year. Oil and gas
reserves decreased in 2008 primarily as a result of a negative revision mainly related to lower heavy oil and bitumen prices at year end.

At December 31, 2008, the present value of future net cash flows after tax from Huskys proved oil and gas reserves, based on prices and costs in effect at year end and discounted at 10%, was $6.4 billion compared with $14.8
billion at December 31, 2007.

Huskys oil and gas reserves are estimated in accordance with the regulations and guidance of the
SEC, which requires reserves to be evaluated using prices in effect on the day the reserves are estimated. On December 31, 2008, West Texas Intermediate was U.S. $44.60/bbl, Lloydminster heavy crude oil was $34.56/bbl and bitumen was
$29.86/bbl. At these prices some heavy oil proved reserves and all proved bitumen reserves became uneconomic and were removed from reserves until market conditions improve. Heavy crude oil and bitumen are discounted because they require upgrading
before processing by conventional refineries and upgrading capacity in North America is limited. Heavy crude oil and bitumen require blending with condensate or light synthetic crude oil (diluent) in order to be transported in a
pipeline.

The additions to crude oil and NGL proved reserves from discoveries, extensions and improved recovery amounted to 44 mmbbls and
were primarily from Lloydminster reservoir extensions from step-out drilling, improved recovery from ASP floods and White Rose improved recovery.

The additions to natural gas proved reserves from discoveries, extensions and improved recovery amounted to 182 bcf and were primarily related to exploration in the foothills and deep basin areas of Alberta and British Columbia. Natural gas
reserve additions also resulted from field extensions and improved recovery primarily at Bivouac, Caroline and Blackstone. Natural gas proved reserves acquired amounted to 96 bcf mainly in the British Columbia and Alberta foothills.

The revision of previous estimates of negative 84 mmboe to proved oil and gas reserves includes a reduction of 98 mmboe related to the drop in commodity
prices at the end of 2008 compared with the end of 2007. This was offset by net positive technical revisions of 14 mmboe. The application of year end pricing for bitumen resulted in a reduction in bitumen reserves which accounted for 69 mmboe or 70%
of the total price revision. The remainder was due to lower heavy and medium oil and natural gas prices. This price related revision did not result in any impairment of property, plant and equipment.



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Huskys probable oil and gas reserves decreased by 1,781 million boe in 2008. The negative
price revision to probable oil and gas reserves amounted to 1,042 million boe; 1,016 million boe or 98% was related to lower bitumen prices. Probable reserves were also reduced by divestitures of 50% of the Sunrise oil sands project and
50% of the Madura natural gas and natural gas liquids development in Indonesia, which in aggregate were 886 million boe.

LOGO

Note: Based on year end prices.



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##### Table of Contents

Reconciliation of Proved Reserves



|                                                  |                    |          |   |                |               |   |               |          |       |         |          |   |            |       |   |               |          |   |               |          |   |            |       |               |          |   |            |       |   |                 |         |  
|------------------------------------------------- | ------------------ | -------- | - | -------------- | ------------- | - | ------------- | -------- | ----- | ------- | -------- | - | ---------- | ----- | - | ------------- | -------- | - | ------------- | -------- | - | ---------- | ----- | ------------- | -------- | - | ---------- | ----- | - | --------------- | ------- | -
|(constant prices andcosts before royalties)       |                    | Canada   |   |                | International |   |               |          |       |         |          |   |            |      
|                                                  | Western Canada     |          |   | East Coast     |               |   |               |          | Total |        
|                                                  | LightCrudeOil &NGL |          |   | MediumCrudeOil |               |   | HeavyCrudeOil |          |       | Bitumen |          |   | NaturalGas |       |   | LightCrudeOil |          |   | LightCrudeOil |          |   | NaturalGas |       | CrudeOil &NGL |          |   | NaturalGas |       |   | EquivalentUnits |        
|                                                  |                    | (mmbbls) |   |                | (mmbbls)      |   |               | (mmbbls) |       |         | (mmbbls) |   |            | (bcf) |   |               | (mmbbls) |   |               | (mmbbls) |   |            | (bcf) |               | (mmbbls) |   |            | (bcf) |   |                 | (mmboe) |  
|Proved reserves at December 31, 2007              |                    | 159      |   |                | 88            |   |               | 205      |       |         | 70       |   |            | 2,191 |   |               | 116      |   |               | 11       |   |            |      |               | 649      |   |            | 2,191 |   |                 | 1,014   |  
|Revision of previous estimate                     |                    | (12      | ) |                | 3             |   |               | (13      | )     |         | (69      | ) |            | (42   | ) |               | 15       |   |               |         |   |            |      |               | (76      | ) |            | (42   | ) |                 | (84     | )
|Purchase of reserves in place                     |                    | 2        |   |                | 1             |   |               | 6        |       |         |         |   |            | 96    |   |               |         |   |               |         |   |            |      |               | 9        |   |            | 96    |   |                 | 25      |  
|Sale of reserves in place                         |                    | (1       | ) |                |              |   |               |         |       |         |         |   |            | (19   | ) |               |         |   |               |         |   |            |      |               | (1       | ) |            | (19   | ) |                 | (4      | )
|Discoveries, extensions and improved recovery     |                    | 9        |   |                | 3             |   |               | 27       |       |         |         |   |            | 182   |   |               | 5        |   |               |         |   |            |      |               | 44       |   |            | 182   |   |                 | 75      |  
|Production                                        |                    | (9       | ) |                | (10           | ) |               | (38      | )     |         | (1       | ) |            | (218  | ) |               | (32      | ) |               | (4       | ) |            |      |               | (94      | ) |            | (218  | ) |                 | (130    | )
|                                                  |                    |          |   |                |               |   |               |          |       |         |          |   |            |       |   |               |          |   |               |          |   |            |       |               |          |   |            |       |   |                 |         |  
|Proved reserves at December 31, 2008              |                    | 148      |   |                | 85            |   |               | 187      |       |         |         |   |            | 2,190 |   |               | 104      |   |               | 7        |   |            |      |               | 531      |   |            | 2,190 |   |                 | 896     |  
|                                                  |                    |          |   |                |               |   |               |          |       |         |          |   |            |       |   |               |          |   |               |          |   |            |       |               |          |   |            |       |   |                 |         |  
|Proved and probable reserves At December 31, 2008 |                    | 195      |   |                | 99            |   |               | 255      |       |         | 96       |   |            | 2,648 |   |               | 168      |   |               | 21       |   |            | 258   |               | 834      |   |            | 2,906 |   |                 | 1,319   |  
|                                                  |                    |          |   |                |               |   |               |          |       |         |          |   |            |       |   |               |          |   |               |          |   |            |       |               |          |   |            |       |   |                 |         |  
|At December 31, 2007                              |                    | 213      |   |                | 105           |   |               | 282      |       |         | 1,835    |   |            | 2,664 |   |               | 216      |   |               | 37       |   |            | 516   |               | 2,688    |   |            | 3,180 |   |                 | 3,218   |  
|                                                  |                    |          |   |                |               |   |               |          |       |         |          |   |            |       |   |               |          |   |               |          |   |            |       |               |          |   |            |       |   |                 |         |  

On December 29, 2008, the SEC announced that it had approved revisions to modernize its oil
and gas reporting requirements to help investors evaluate their investments in oil and gas companies. The new rules will be effective for fiscal years ending on or after December 31, 2009. These rules provide for disclosure of oil and gas
reserves evaluated using annual average prices based on the prices in effect on the first day of each month. Applying this method during 2008, the price of WTI averaged U.S. $101.87, Lloydminster heavy crude oil averaged $60.90/bbl and the price of
bitumen averaged $54.51/bbl.



PAGE 26



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##### Table of Contents

Had the new SEC rules in respect of pricing been in effect at December 31, 2008, Huskys oil
and gas reserves based on annual average prices would have been reported as follows:

Proved Reserves in accordance with pending SEC pricing rules



|                                                           |                    |          |                |               |               |          |         |          |            |       |                |          |               |          |            |       |               |          |            |       |                 |        
|---------------------------------------------------------- | ------------------ | -------- | -------------- | ------------- | ------------- | -------- | ------- | -------- | ---------- | ----- | -------------- | -------- | ------------- | -------- | ---------- | ----- | ------------- | -------- | ---------- | ----- | --------------- | -------
|(constant prices andcosts before royalties)                |                    | Canada   |                | International |               |          |         |          |            |      
|                                                           | Western Canada     |          | East Coast     |               |               |          | Total  
|                                                           | LightCrudeOil &NGL |          | MediumCrudeOil |               | HeavyCrudeOil |          | Bitumen |          | NaturalGas |       | LightCrude Oil |          | LightCrudeOil |          | NaturalGas |       | CrudeOil &NGL |          | NaturalGas |       | EquivalentUnits
|                                                           |                    | (mmbbls) |                | (mmbbls)      |               | (mmbbls) |         | (mmbbls) |            | (bcf) |                | (mmbbls) |               | (mmbbls) |            | (bcf) |               | (mmbbls) |            | (bcf) |                 | (mmboe)
|Proved reserves at December 31, 2008 as reported           |                    | 148      |                | 85            |               | 187      |         |         |            | 2,190 |                | 104      |               | 7        |            |      |               | 531      |            | 2,190 |                 | 896    
|Price revision                                             |                    | 6        |                | 4             |               | 13       |         | 69       |            | 32    |                |         |               |         |            |      |               | 92       |            | 32    |                 | 98     
|                                                           |                    |          |                |               |               |          |         |          |            |       |                |          |               |          |            |       |               |          |            |       |                 |        
|Proved reserves at December 31, 2008 restated              |                    | 154      |                | 89            |               | 200      |         | 69       |            | 2,222 |                | 104      |               | 7        |            |      |               | 623      |            | 2,222 |                 | 994    
|                                                           |                    |          |                |               |               |          |         |          |            |       |                |          |               |          |            |       |               |          |            |       |                 |        
|Proved and probable reserves At December 31, 2008 restated |                    | 203      |                | 103           |               | 270      |         | 1,182    |            | 2,704 |                | 186      |               | 21       |            | 258   |               | 1,965    |            | 2,962 |                 | 2,459  
|                                                           |                    |          |                |               |               |          |         |          |            |       |                |          |               |          |            |       |               |          |            |       |                 |        

Reconciliation of Proved Developed Reserves



|                                               |                     |          |   |                 |               |   |                |          |   |         |          |   |            |       |   |                |          |   |                |          |   |                |          |   |            |       |   |                 |         |  
|---------------------------------------------- | ------------------- | -------- | - | --------------- | ------------- | - | -------------- | -------- | - | ------- | -------- | - | ---------- | ----- | - | -------------- | -------- | - | -------------- | -------- | - | -------------- | -------- | - | ---------- | ----- | - | --------------- | ------- | -
|(constant prices and costsbefore royalties)    |                     | Canada   |   |                 | International |   |                | Total    |  
|                                               | Western Canada      |          |   | East Coast      |               |   |                |          |  
|                                               | LightCrude Oil& NGL |          |   | MediumCrude Oil |               |   | HeavyCrude Oil |          |   | Bitumen |          |   | NaturalGas |       |   | LightCrude Oil |          |   | LightCrude Oil |          |   | Crude Oil& NGL |          |   | NaturalGas |       |   | EquivalentUnits |        
|                                               |                     | (mmbbls) |   |                 | (mmbbls)      |   |                | (mmbbls) |   |         | (mmbbls) |   |            | (bcf) |   |                | (mmbbls) |   |                | (mmbbls) |   |                | (mmbbls) |   |            | (bcf) |   |                 | (mmboe) |  
|Proved developed reserves at December 31, 2007 |                     | 136      |   |                 | 80            |   |                | 124      |   |         | 47       |   |            | 1,780 |   |                | 94       |   |                | 11       |   |                | 492      |   |            | 1,780 |   |                 | 788     |  
|Revision of previous estimate                  |                     | (3       | ) |                 | 6             |   |                | 20       |   |         | (46      | ) |            | 78    |   |                | 16       |   |                |         |   |                | (7       | ) |            | 78    |   |                 | 5       |  
|Purchase of reserves in place                  |                     | 1        |   |                 | 1             |   |                | 4        |   |         |         |   |            | 19    |   |                |         |   |                |         |   |                | 6        |   |            | 19    |   |                 | 9       |  
|Sale of reserves in place                      |                     | (1       | ) |                 |              |   |                |         |   |         |         |   |            | (16   | ) |                |         |   |                |         |   |                | (1       | ) |            | (16   | ) |                 | (3      | )
|Discoveries, extensions and improved recovery  |                     | 4        |   |                 | 2             |   |                | 8        |   |         |         |   |            | 117   |   |                | 5        |   |                |         |   |                | 19       |   |            | 117   |   |                 | 39      |  
|Production                                     |                     | (9       | ) |                 | (10           | ) |                | (38      | ) |         | (1       | ) |            | (218  | ) |                | (32      | ) |                | (4       | ) |                | (94      | ) |            | (218  | ) |                 | (130    | )
|                                               |                     |          |   |                 |               |   |                |          |   |         |          |   |            |       |   |                |          |   |                |          |   |                |          |   |            |       |   |                 |         |  
|Proved developed reserves at December 31, 2008 |                     | 128      |   |                 | 79            |   |                | 118      |   |         |         |   |            | 1,760 |   |                | 83       |   |                | 7        |   |                | 415      |   |            | 1,760 |   |                 | 708     |  
|                                               |                     |          |   |                 |               |   |                |          |   |         |          |   |            |       |   |                |          |   |                |          |   |                |          |   |            |       |   |                 |         |  



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##### Table of Contents

Had the new SEC rules been in effect at December 31, 2008, Huskys proved developed oil and gas
reserves based on annual average prices would have been reported as follows:

Proved Developed Reserves in accordance with pending SEC rules



|                                                           |                     |          |                 |               |                |          |         |          |            |       |                |          |                |          |                |          |            |       |                 |        
|---------------------------------------------------------- | ------------------- | -------- | --------------- | ------------- | -------------- | -------- | ------- | -------- | ---------- | ----- | -------------- | -------- | -------------- | -------- | -------------- | -------- | ---------- | ----- | --------------- | -------
|(constant prices andcosts beforeroyalties)                 |                     | Canada   |                 | International |                |          |         |          |            |      
|                                                           | Western Canada      |          | East Coast      |               |                |          | Total  
|                                                           | LightCrude Oil& NGL |          | MediumCrude Oil |               | HeavyCrude Oil |          | Bitumen |          | NaturalGas |       | LightCrude Oil |          | LightCrude Oil |          | Crude Oil& NGL |          | NaturalGas |       | EquivalentUnits
|                                                           |                     | (mmbbls) |                 | (mmbbls)      |                | (mmbbls) |         | (mmbbls) |            | (bcf) |                | (mmbbls) |                | (mmbbls) |                | (mmbbls) |            | (bcf) |                 | (mmboe)
|Proved developed reserves at December 31, 2008 as reported |                     | 128      |                 | 79            |                | 118      |         |         |            | 1,760 |                | 83       |                | 7        |                | 415      |            | 1,760 |                 | 708    
|Price revision                                             |                     | 4        |                 | 3             |                | 3        |         | 46       |            | 24    |                |         |                |         |                | 56       |            | 24    |                 | 61     
|                                                           |                     |          |                 |               |                |          |         |          |            |       |                |          |                |          |                |          |            |       |                 |        
|Proved developed reserves at December 31, 2008 restated    |                     | 132      |                 | 82            |                | 121      |         | 46       |            | 1,784 |                | 83       |                | 7        |                | 471      |            | 1,784 |                 | 769    
|                                                           |                     |          |                 |               |                |          |         |          |            |       |                |          |                |          |                |          |            |       |                 |        

7.4 Midstream

2008 Earnings $469 Million, down $66 Million from 2007

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Upgrading Earnings Summary



|                                      |  |             |     |   |       |   |     |      |       |   |     |   |       | 
|------------------------------------- |  | ----------- | --- | - | ----- | - | --- | ---- | ----- | - | --- | - | ----- | 
|($ millions, except where indicated)  |  | 2008        |     |   | 2007  |   |     | 2006 |      
|Gross margin                          |  | $           | 633 |   |       | $ | 614 |      |       | $ | 624 |  
|Operating and administration expenses |  |             | 256 |   |       |   | 221 |      |       |   | 224 |  
|Other recoveries                      |  |             | (4  | ) |       |   | (4  | )    |       |   | (6  | )
|Depreciation and amortization         |  |             | 31  |   |       |   | 25  |      |       |   | 24  |  
|Income taxes                          |  |             | 105 |   |       |   | 90  |      |       |   | 97  |  
|                                      |  |             |     |   |       |   |     |      |       |   |     |   |       | 
|Net earnings                          |  | $           | 245 |   |       | $ | 282 |      |       | $ | 285 |  
|                                      |  |             |     |   |       |   |     |      |       |   |     |   |       | 
|Upgrader throughput (1)               |  | (mbbls/day) |     |   | 68.1  |   |     |      | 61.4  |   |     |   | 71.0  | 
|Synthetic crude oil sales             |  | (mbbls/day) |     |   | 58.7  |   |     |      | 53.1  |   |     |   | 62.5  | 
|Upgrading differential                |  | ($/bbl)     |     | $ | 28.77 |   |     | $    | 30.73 |   |     | $ | 26.16 | 
|Unit margin                           |  | ($/bbl)     |     | $ | 29.48 |   |     | $    | 31.67 |   |     | $ | 27.35 | 
|Unit operating cost (2)               |  | ($/bbl)     |     | $ | 10.30 |   |     | $    | 9.83  |   |     | $ | 8.65  | 
|                                      |  |             |     |   |       |   |     |      |       |   |     |   |       | 



|(1) | Throughput includes diluent returned to the field.
|--- | --------------------------------------------------



|(2) | Based on throughput.
|--- | --------------------

In 2008, upgrading earnings were 13% lower than 2007. Upgrader throughput was 11% higher compared with the same period in 2007. In May and June 2007, throughput was lower due to a 49-day scheduled turnaround and
installation of new coke drums. In March and April 2008, the upgrader was shut down for 34 days for a scheduled turnaround and throughput was also impacted by a temporary shutdown to replace the hydrogen plant catalyst. However, the higher
throughput in 2008 was offset by declining differentials compared with 2007.

Unlike heavy crude oil, synthetic crude oil is a higher value
feedstock for many refineries in Canada and the United States. During 2008, the price of Huskys synthetic crude oil averaged $108.73/bbl (2007, $79.11/bbl) compared with the average cost of blended heavy crude oil from the Lloydminster area of
$79.96/bbl (2007, $48.38/bbl). This resulted in an average synthetic/heavy crude differential of $28.77/bbl (2007, $30.73/bbl) and a gross unit margin of $29.48/bbl (2007, $31.67/bbl). Gross unit margin includes secondary products. The cost of
upgrading averaged $10.30/bbl compared with $9.83/bbl in 2007, which results in a net margin for upgrading Lloydminster heavy crude of $19.18/bbl, down 12% compared with $21.84/bbl in 2007.

Operating costs have increased in 2008 due to higher steam, gas, and electricity volumes and prices, offset by lower contract labor. Depreciation is
recorded at the upgrader on a unit of production basis which is the primary driver behind the increase in 2008 compared with 2007.

Earnings in 2007 include a recovery of income taxes of $26 million reflecting changes in the statutory tax rate announced in 2007.

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Infrastructure and Marketing Earnings Summary



|                                      |  |             |     |      |       |      |  |       |     |  |    
|------------------------------------- |  | ----------- | --- | ---- | ----- | ---- |  | ----- | --- |  | ---
|($ millions, except where indicated)  |  | 2008        |     | 2007 |       | 2006
|Gross margin                          |  |             |     |      |       |      |  |       |    
|Pipeline                              |  | $           | 120 |      | $     | 115  |  | $     | 104
|Other infrastructure and marketing    |  |             | 249 |      |       | 278  |  |       | 208
|                                      |  |             |     |      |       |      |  |       |     |  |    
|                                      |  |             | 369 |      |       | 393  |  |       | 312
|Operating and administration expenses |  |             | 17  |      |       | 14   |  |       | 11 
|Depreciation and amortization         |  |             | 31  |      |       | 28   |  |       | 24 
|Income taxes                          |  |             | 97  |      |       | 98   |  |       | 80 
|                                      |  |             |     |      |       |      |  |       |     |  |    
|Net earnings                          |  | $           | 224 |      | $     | 253  |  | $     | 197
|                                      |  |             |     |      |       |      |  |       |     |  |    
|Commodity volumes managed             |  | (mboe/day)  |     |      | 1,103 |      |  | 1,042 |     |  | 994
|                                      |  |             |     |      |       |      |  |       |     |  |    
|Aggregate pipeline throughput         |  | (mbbls/day) |     |      | 507   |      |  | 501   |     |  | 475
|                                      |  |             |     |      |       |      |  |       |     |  |    

Infrastructure and marketing earnings in 2008 decreased by $29 million compared with 2007. In
2007, higher earnings from oil and gas commodity marketing were realized as crude oil premiums, gas storage profits and NGL extraction margins rose to unprecedented levels. In the latter half of 2008, rapidly declining commodity prices resulted in
lower marketing earnings. Pipeline earnings in 2008 increased over 2007 supported by higher throughput volume. Earnings in 2007 include a recovery of income taxes of $13 million reflecting changes in the statutory tax rate announced in 2007.

Midstream Capital Expenditures

Midstream capital expenditures totalled $193 million in 2008. At the Lloydminster upgrader, Husky spent $99 million, primarily for contingent consideration and facility reliability projects. The remaining $94 million was spent on the
pipeline extension between Lloydminster and Hardisty, Alberta, tankage upgrades at Hardisty and capital enhancements of the cogeneration plants.

7.5 Downstream

2008 Loss $295 Million, down $592 Million from 2007

In 2008, the downstream segment earnings include twelve months from the Lima, Ohio Refinery, which was acquired on July 1, 2007 and nine months from
the BP-Husky Toledo, Ohio Refinery, 50% of which was acquired on March 31, 2008.

Canadian Refined Products

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Canadian Refined Products Earnings Summary



|                                      |   |                       |     |      |       |      |   |       |     |  |     
|------------------------------------- | - | --------------------- | --- | ---- | ----- | ---- | - | ----- | --- |  | ----
|($ millions, except where indicated)  |   | 2008                  |     | 2007 |       | 2006
|Gross margin                          |   |                       |     |      |       |      |   |       |    
|Fuel sales                            |   | $                     | 96  |      | $     | 156  |   | $     | 137
|Ethanol sales                         |   |                       | 26  |      |       | 32   |   |       | 1  
|Ancillary sales                       |   |                       | 42  |      |       | 42   |   |       | 36 
|Asphalt sales                         |   |                       | 130 |      |       | 160  |   |       | 94 
|                                      |   |                       |     |      |       |      |   |       |     |  |     
|                                      |   |                       | 294 |      |       | 390  |   |       | 268
|Operating and administration expenses |   |                       | 67  |      |       | 82   |   |       | 74 
|Depreciation and amortization         |   |                       | 81  |      |       | 66   |   |       | 48 
|Income taxes                          |   |                       | 40  |      |       | 50   |   |       | 40 
|Net earnings                          |   |                       |     |      |       |      |   |       |    
|                                      | $ | 106                   |     | $    | 192   |      | $ | 106  
|                                      |   |                       |     |      |       |      |   |       |     |  |     
|Number of fuel outlets                |   |                       | 492 |      |       | 505  |   |       | 505
|Refined products sales volume         |   |                       |     |      |       |      |   |       |    
|Light oil products                    |   | (million litres/day)  |     |      | 7.9   |      |   | 8.7   |     |  | 8.7 
|Light oil products per outlet         |   | (thousand litres/day) |     |      | 13.0  |      |   | 13.2  |     |  | 12.9
|Asphalt products                      |   | (mbbls/day)           |     |      | 24.0  |      |   | 21.8  |     |  | 23.4
|Refinery throughput                   |   |                       |     |      |       |      |   |       |     |  |     
|Prince George refinery                |   | (mbbls/day)           |     |      | 10.1  |      |   | 10.5  |     |  | 9.0 
|Lloydminster refinery                 |   | (mbbls/day)           |     |      | 26.1  |      |   | 25.3  |     |  | 27.1
|Ethanol production                    |   | (thousand litres/day) |     |      | 627.2 |      |   | 324.6 |     |  | 59.7
|                                      |   |                       |     |      |       |      |   |       |     |  |     

Fuel sales margins in 2008 decreased due to lower average retail margins and lower sales volumes
due to weak demand. Volumes sold were also impacted by shortages from third party suppliers due to refinery outages. Margins on asphalt products were lower than those of the previous year due to rising crude oil feedstock costs for the first nine
months of 2008 partially offset by declining costs in the fourth quarter. Ethanol production increased 93% over 2007 due to the startup of the new Minnedosa Ethanol Plant, which commenced operations at the end of 2007; however earnings from total
ethanol sales for both plants were lower than 2007 due to much lower sales values, higher feedstock costs, and natural gas costs.

Earnings
in 2007 include a recovery of income taxes of $26 million reflecting changes in the statutory tax rate announced in 2007.

U.S. Refining and Marketing

U.S. Refining and Marketing Earnings Summary



|                                                     |  |                          |      |   |       |     |     |  |       |    
|---------------------------------------------------- |  | ------------------------ | ---- | - | ----- | --- | --- |  | ----- | ---
|($ millions, except where indicated)                 |  | 2008                     |      |   | 2007  |    
|Gross refining margin                                |  | $                        | (58  | ) |       | $   | 310 | 
|Processing costs                                     |  |                          | 414  |   |       |     | 93  | 
|Operating and administration expenses                |  |                          | 3    |   |       |     | 1   | 
|Interest  net                                       |  |                          | 3    |   |       |     | 1   | 
|Depreciation and amortization                        |  |                          | 154  |   |       |     | 47  | 
|Income taxes                                         |  |                          | (231 | ) |       |     | 63  | 
|                                                     |  |                          |      |   |       |     |     |  |       |    
|Net earnings (loss)                                  |  | $                        | (401 | ) |       | $   | 105 | 
|                                                     |  |                          |      |   |       |     |     |  |       |    
|Selected operating data:                             |  |                          |      |   |       |     |     | 
|Lima Refinery throughput                             |  | (mbbls/day)              |      |   | 136.6 |     |     |  | 143.8 | (2)
|Toledo Refinery throughput                           |  | (mbbls/day)              |      |   | 60.6  | (1) |     |  |      |    
|Refining margin                                      |  | ($/bbl crude throughput) |      |   | (0.88 | )   |     |  | 12.42 |    
|Refinery inventory (feedstocks and refined products) |  | (mmbbls)                 |      |   | 11.9  |     |     |  | 7.4   |    
|                                                     |  |                          |      |   |       |     |     |  |       |    



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|(1) | The BP-Husky Toledo Refinery operating results are included from March 31, 2008, the date the acquisition was completed. Throughput represents Huskys share of nine
months of operations.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | The Lima Refinery operating results are included from July 1, 2007, the date the acquisition was completed. Throughput represents six months of operations.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------

The U.S. Refining and Marketing segment commenced operations on July 1, 2007 with the acquisition of the Lima, Ohio
Refinery, as a first step in pursuing integration and enhancing the value of heavy oil and bitumen production.

On March 31, 2008,
Husky completed a transaction that resulted in the formation of two joint venture entities forming an integrated oil sands business and a refining joint venture. Husky holds a 50% interest in the BP-Husky Toledo Refinery.

Results in 2008 were significantly impacted by the drop in demand for motor fuels that began in mid-2007 and continued through 2008, in line with
deteriorating U.S. and global economic conditions. Lower consumption combined with higher product stocks resulted in narrow refining crack spreads compared with 2007. Margins on distillates, which were in high demand globally, were stronger than
gasoline margins and Husky continued to optimize refinery throughput toward distillate production to maximize margins. Low gasoline margins resulted in lower crude throughputs at Lima. Crude supply disruptions associated with hurricanes Gustav,
Hanna and Ike widened spreads for a period but impacted crude oil feedstock availability. Toledo was also limited in its ability to capitalize on wider sweet/sour differentials as production was impacted by planned process unit outages to complete
priority maintenance and turnaround activities.

Pricing for refinery output at the Lima and Toledo refineries is impacted by the New York
Harbor 3:2:1 refining crack spread and the Chicago refining crack spread. Refining crack spreads at Chicago averaged U.S. $11.17/bbl in 2008 compared with U.S. $17.68 in 2007 and the New York Harbor 3:2:1 refining crack spread averaged U.S.
$9.96/bbl in 2008 compared with U.S. $14.15 in 2007. Chicago 3:2:1 crack spreads reached a low of negative U.S. $1.83/bbl during 2008 and the New York Harbor 3:2:1 refining crack spread was as low as U.S. $2.00/bbl. Huskys refining margin was
U.S. $0.46/bbl in 2008 with a Canadian dollar equivalent of negative $0.88. The impact of the weakening Canadian dollar in the fourth quarter and its impact on the translation of losses incurred in the quarter results in an overall negative margin
on translation for the year. This is a result of earnings from the first nine months of 2008 translated at an average rate of U.S. $0.982 per Canadian dollar compared with larger losses in the fourth quarter translated at an average rate of $0.824
U.S. per Canadian dollar.

The market refining crack spread is based on crude feedstock accounted for on a last in first out basis
(LIFO). However, Huskys financial statements are based on first in first out (FIFO) inventory accounting which is in accordance with Canadian GAAP. In a stable commodity price environment, FIFO and LIFO accounting
should not result in significant differences between market benchmarks and individual refinery results. In a rapidly declining commodity price environment as existed in the fourth quarter of 2008, the result is that the cost of crude feedstock
consumed is higher on a FIFO basis than on a LIFO basis as it was acquired in a significantly higher commodity price environment as a result of the time lag between crude feedstock purchase and processing through the refinery.

In addition, the Chicago and the New York Harbor 3:2:1 refining crack spread are based on a product mix that includes only gasoline and distillate. The
output of the Lima and Toledo refineries is approximately 12% other refined products which typically sell for lower prices than gasoline or distillate.

Processing costs for 2008 were impacted by turnaround activity and higher energy costs at Toledo and higher energy and maintenance costs at Lima.



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Downstream Capital Expenditures

Downstream capital expenditures totalled $288 million during 2008.

In Canada, capital expenditures
totalled $155 million, $101 million for retail network remodeling, automation and facility upgrades, $28 million for upgrades and environmental protection at the Prince George and Lloydminster refineries, $19 million for upgrades at the Minnedosa
and Lloydminster ethanol plants and $7 million for asphalt distribution and processing upgrades.

In the United States, capital
expenditures totalled $133 million, $80 million at the Lima Refinery for the front end engineering design for an isocracker debottleneck project and for various environmental protection and facility upgrades. At the BP-Husky Toledo Refinery, capital
expenditures totalled $53 million primarily for facility upgrades and environmental protection.

7.6 Corporate

2008 Income $203 Million, up $417 Million from 2007

Corporate
Earnings Summary



|                                |  |      |      |   |      |   |      |      |  |   |      |  
|------------------------------- |  | ---- | ---- | - | ---- | - | ---- | ---- |  | - | ---- | -
|($ millions) income (expense)   |  | 2008 |      |   | 2007 |   |      | 2006 | 
|Intersegment eliminations  net |  | $    | 61   |   |      | $ | (51  | )    |  | $ | 20   |  
|Administration expenses         |  |      | (47  | ) |      |   | (63  | )    |  |   | (61  | )
|Stock based compensation        |  |      | 33   |   |      |   | (88  | )    |  |   | (138 | )
|Depreciation and amortization   |  |      | (30  | ) |      |   | (25  | )    |  |   | (27  | )
|Interest  net                  |  |      | (144 | ) |      |   | (129 | )    |  |   | (92  | )
|Foreign exchange                |  |      | 335  |   |      |   | 51   |      |  |   | 24   |  
|Income taxes                    |  |      | (5   | ) |      |   | 91   |      |  |   | 117  |  
|                                |  |      |      |   |      |   |      |      |  |   |      |  
|Net earnings (loss)             |  | $    | 203  |   |      | $ | (214 | )    |  | $ | (157 | )
|                                |  |      |      |   |      |   |      |      |  |   |      |  

In 2008, intersegment eliminations were $112 million lower than in 2007 as inventory values
decreased with commodity prices. Foreign exchange gains in 2008 were higher than in 2007 primarily resulting from an increase in the Canadian dollar equivalent of the U.S. dollar denominated contribution receivable that Husky recorded on the
formation of the Sunrise partnership (refer to Section 5.1 of this MD&A and Note 10 to the Consolidated Financial Statements for the year ended December 31, 2008). In addition, net foreign exchange gains were recorded on working
capital, offset by foreign exchange losses on U.S. dollar denominated debt. A recovery of stock-based compensation was recorded in 2008 compared to an expense in 2007 due to the decline in Huskys share price during the year. Interest expense
increased due to a higher average borrowing balance in 2008 and no interest capitalized in 2008 compared with 2007.



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Foreign Exchange Summary



|                                                                     |  |        |       |   |      |        |       |      |  |        |       |  
|-------------------------------------------------------------------- |  | ------ | ----- | - | ---- | ------ | ----- | ---- |  | ------ | ----- | -
|($ millions)                                                         |  | 2008   |       |   | 2007 |        |       | 2006 | 
|(Gain) loss on translation of U.S. dollar denominated long-term debt |  |        |       |   |      |        |       |     
|Realized                                                             |  | $      | (5    | ) |      | $      |      |      |  | $      | (42   | )
|Unrealized                                                           |  |        | 222   |   |      |        | (197  | )    |  |        | 35    |  
|                                                                     |  |        |       |   |      |        |       |      |  |        |       |  
|                                                                     |  |        | 217   |   |      |        | (197  | )    |  |        | (7    | )
|                                                                     |  |        |       |   |      |        |       |      |  |        |       |  
|Cross currency swaps                                                 |  |        |       |   |      |        |       |      |  |        |       |  
|Realized                                                             |  |        |      |   |      |        |      |      |  |        | 47    |  
|Unrealized                                                           |  |        | (83   | ) |      |        | 62    |      |  |        | (43   | )
|                                                                     |  |        |       |   |      |        |       |      |  |        |       |  
|                                                                     |  |        | (83   | ) |      |        | 62    |      |  |        | 4     |  
|                                                                     |  |        |       |   |      |        |       |      |  |        |       |  
|Contribution receivable                                              |  |        | (228  | ) |      |        |      |      |  |        |      |  
|Other (gains) losses                                                 |  |        | (241  | ) |      |        | 84    |      |  |        | (21   | )
|                                                                     |  |        |       |   |      |        |       |      |  |        |       |  
|                                                                     |  | $      | (335  | ) |      | $      | (51   | )    |  | $      | (24   | )
|                                                                     |  |        |       |   |      |        |       |      |  |        |       |  
|U.S./Canadian dollar exchange rates:                                 |  |        |       |   |      |        |       |      |  |        |       |  
|At beginning of year                                                 |  | U.S. $ | 1.012 |   |      | U.S. $ | 0.858 |      |  | U.S. $ | 0.858 |  
|At end of year                                                       |  | U.S. $ | 0.817 |   |      | U.S. $ | 1.012 |      |  | U.S. $ | 0.858 |  
|                                                                     |  |        |       |   |      |        |       |      |  |        |       |  

Foreign Exchange Risk

Huskys results are affected by the exchange rate between 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. The majority of Huskys expenditures are in Canadian dollars. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease the revenues received from
the sale of oil and gas commodities. Correspondingly, a decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of oil and gas commodities.

In addition, 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, as expressed in Canadian dollars, as well as in the related interest expense. At December 31, 2008, 100% or $2.0 billion of the Companys long-term debt was denominated in U.S. dollars (93% or $2.6 billion at
December 31, 2007). The U.S./Cdn exchange rate at the end of 2008 was U.S. $0.817 (2007 U.S. $1.012). The percentage of Huskys long-term debt exposed to the U.S./Cdn exchange rate decreases to 78% when the cross currency swaps are
included. Additionally, U.S. $687 million (2007  $1.5 billion) of the Companys U.S. dollar denominated debt has been designated as a hedge of a net investment and the unrealized foreign exchange gain is recorded in Other Comprehensive
Income, further reducing the long-term debt exposed to the U.S./Cdn exchange rate to 35% (2007  27%).

The contribution receivable
representing BPs obligation to fund capital expenditures of the Sunrise partnership is denominated in U.S. dollars and gains and losses from changes in the value of the Canadian dollar versus the U.S. dollar are recorded in foreign exchange
gains and losses in the current year. At December 31, 2008 the balance of this receivable was U.S. $1.2 billion including accrued interest. Husky has an obligation to fund capital expenditures of the BP-Husky Toledo Refinery and this
contribution payable is denominated in U.S. dollars. Gains and losses from the translation of this obligation are recorded in Other Comprehensive Income as this item relates to a self sustaining foreign operation. At December 31, 2008 the
balance of this obligation was U.S. $1.4 billion including accrued interest. Refer to Section 8.6, Financial Risk and Risk Management.

Consolidated Income Taxes

Consolidated income taxes increased in 2008 to $1.4 billion from $913 million in 2007, an
effective tax rate of 27% for 2008 and 22% for 2007.



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In 2007, a recovery of future income taxes resulted from recording non-recurring tax benefits of $395
million, $365 million due to changes in the tax rate levied by the Federal Government by Bill C-28 and $30 million due to changes from Bill C-52. In 2006, a recovery of future taxes resulted from recording non-recurring tax benefits of $328 million
that arose due to changes in the tax rates for the governments of Canada ($198 million), Alberta ($90 million) and Saskatchewan ($40 million).

The following table shows the effect of non-recurring tax benefits for the periods noted:



|                                               |  |      |       |      |   |       |  |   |      
|---------------------------------------------- |  | ---- | ----- | ---- | - | ----- |  | - | -----
|($ millions)                                   |  | 2008 |       | 2007 |   | 2006 
|Income taxes before tax amendments             |  | $    | 1,396 |      | $ | 1,308 |  | $ | 1,108
|Canadian federal and provincial tax amendments |  |      |      |      |   | 395   |  |   | 328  
|                                               |  |      |       |      |   |       |  |   |      
|Income taxes as reported                       |  | $    | 1,396 |      | $ | 913   |  | $ | 780  
|                                               |  |      |       |      |   |       |  |   |      

Taxable income from Canadian operations is primarily generated through partnerships, with the
related income taxes payable in a future period. Accrued liabilities include $615 million of cash tax payable in 2009. In addition, during 2009 cash tax instalments of $900 million are payable in respect of the 2008 reported earnings but which are
not taxable until 2009.

Corporate Capital Expenditures

Corporate capital expenditures of $47 million in 2008 were primarily for computer hardware, software, office furniture and renovations and equipment and system upgrades. In 2007, corporate capital expenditures were
$44 million.

7.7 Fourth Quarter

Consolidated net earnings during the fourth quarter of 2008, were $232 million, a decrease of $842 million or 78% compared with the fourth quarter of 2007. During the fourth quarter of 2007, Husky recorded a tax
benefit of $365 million that resulted from the substantive enactment of Bill C-28 on December 13, 2007. Aside from the non-recurring tax benefit, net earnings decreased by $477 million or 67% in the fourth quarter of 2008 compared with the same
period in 2007.

Pre-tax earnings from the upstream sector were $446 million in the fourth quarter of 2008, a decrease of $368 million.
Weaker upstream earnings in the fourth quarter of 2008 were due largely to lower crude oil prices realized of $49.02/bbl (average of all products) compared with $63.34/bbl in the fourth quarter of 2007. Production for the fourth quarter of 2008 was
358,400 bbls/day compared with 367,500 bbls/day in the fourth quarter of 2007 primarily due to lower natural gas production in Western Canada. Natural gas prices in the fourth quarter of 2008 averaged $6.84/mcf compared with $5.72 during the same
period in 2007.

Lower pre-tax earnings from upgrading operations were due to lower average upgrading differentials which resulted from
declining synthetic crude oil prices combined with narrowing heavy to light oil differentials. Pre-tax earnings from infrastructure and marketing were also the result of declining commodity prices throughout the fourth quarter of 2008 which result
in lower broker margins.

Canadian refined products pre-tax earnings declined due to weak retail gasoline margins and demand for product,
partially offset by higher margins for asphalt. Fourth quarter 2008 ethanol production increased 90% due to the start-up of the Minnedosa ethanol plant, which commenced operations at the end of 2007, however margins declined due to increasing input
costs and declining demand. The U.S. Refining and Marketing results include the Lima, Ohio Refinery which was acquired on July 1, 2007 and 50% of the BP-Husky Toledo, Ohio Refinery which was acquired on March 31, 2008. Pre-tax earnings
were lower in the fourth quarter of 2008 due to dramatically declining crack spreads and inventory write downs of $599 million pre-tax ($382 million after tax) which resulted in losses at both refineries.



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7.8 Results of Operations for 2007 Compared with 2006

Net earnings in 2007 were $3,214 million compared with $2,726 million in 2006. The increase of $488 million was attributable to the following:

Upstream  increase of $301 million due to higher crude oil prices and higher light crude oil production partially offset by lower natural
gas sales volume and prices, higher operating costs and DD&A.

Midstream  increase of $53 million due to wider upgrading
differentials, higher oil and gas commodity marketing earnings and higher pipeline throughput volume partially offset by lower sales volume of synthetic crude oil due to a 49-day plant turnaround.

Downstream  increase of $191 million due to the acquisition of the Lima, Ohio, Refinery, for which results have been included from
July 1, 2007, and increased Canadian downstream earnings from higher retail light oil product and asphalt product margins.

Corporate  expense increased by $57 million due to higher intersegment profit eliminations, higher interest expense and higher staffing costs offset by lower stock-based compensation expense and higher foreign exchange gains.

8. Liquidity and Capital Resources

8.1 Summary of Cash Flow

In 2008, cash flow from operating activities financed the Companys
capital expenditure requirements, dividend payments, and repayment of debt. Husky maintained its strong financial position at December 31, 2008 with debt of $1,957 million offset by cash on hand of $913 million for $1,044 million of net debt at
December 31, 2008. Husky has no long term debt maturing until 2012. In addition, at December 31, 2008 Husky had $1.5 billion in unused committed credit facilities, with an additional $104 million in unused short-term uncommitted credit
facilities.



|                                           |  |                                     |      |      |        |   |      |   |        |      |      |   |        |  
|------------------------------------------ |  | ----------------------------------- | ---- | ---- | ------ | - | ---- | - | ------ | ---- | ---- | - | ------ | -
|                                           |  |                                     |      | 2008 |        |   | 2007 |   |        | 2006 |     
|Cash flow                                  |  | - operating activities ($ millions) |      | $    | 6,802  |   |      | $ | 4,657  |      |      | $ | 5,009  |  
|                                           |  | - financing activities ($ millions) |      | $    | (2,559 | ) |      | $ | 433    |      |      | $ | (1,626 | )
|                                           |  | - investing activities ($ millions) |      | $    | (3,538 | ) |      | $ | (5,324 | )    |      | $ | (3,109 | )
|Debt to capital employed (percent)         |  |                                     | 12.0 |      |        |   | 19.5 |   |        |      | 14.3 |  
|Debt to cash flow from operations (times)  |  |                                     | 0.3  |      |        |   | 0.5  |   |        |      | 0.4  |  
|Corporate reinvestment ratio (percent) (1) |  |                                     | 66   |      |        |   | 86   |   |        |      | 70   |  
|                                           |  |                                     |      |      |        |   |      |   |        |      |      |   |        |  



|(1) | Reinvestment ratio is based on net capital expenditures including corporate acquisitions.
|--- | -----------------------------------------------------------------------------------------

Cash Flow from Operating Activities

In 2008, cash generated from operating activities was $6.8
billion compared with $4.7 billion in 2007. Cash flow from operations was higher in 2008 mainly due to higher crude oil and natural gas prices, which were partially offset by losses in the U.S. downstream business.

Cash Flow from (used for) Financing Activities

In
2008, cash used in financing activities was $2.6 billion. The cash used was mainly due to repayment of long-term debt of $1.3 billion and payment of dividends of $1.5 billion. This was partially offset by an increase in the Companys investment
in working capital of $146 million. In 2007, cash provided by financing activities of $433 million was mainly due to the issuance of long-term debt to acquire the Lima Refinery. The debt issuances and repayments presented in the Consolidated
Statements of Cash Flows include multiple drawings and repayments under revolving debt facilities.



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Cash Flow used for Investing Activities

Cash used in investing activities amounted to $3.5 billion in 2008, a decrease of $1.8 billion over 2007. Cash invested in both years was used primarily
for capital expenditures, with $2.6 billion in 2007 for the acquisition of the Lima Refinery.

8.2 Working Capital Components

Working capital is the amount by which current assets exceed current liabilities. At December 31, 2008, Huskys working
capital was $426 million compared with a working capital deficiency of $51 million at December 31, 2007.



|                                   |  |      |       |      |   |       |        |  |   |      |   |  |                                                             
|---------------------------------- |  | ---- | ----- | ---- | - | ----- | ------ |  | - | ---- | - |  | ------------------------------------------------------------
|($ millions)                       |  | 2008 |       | 2007 |   |       | Change |  |   |     
|Current assets                     |  |      |       |      |   |       |        |  |   |      |   |  |                                                             
|Cash and cash equivalents          |  | $    | 913   |      | $ | 208   |        |  | $ | 705  |   |  | Strong earnings and cash flow                               
|Accounts receivable                |  |      | 1,344 |      |   | 1,622 |        |  |   | (278 | ) |  | Lower crude oil prices                                      
|Inventories                        |  |      | 1,032 |      |   | 1,190 |        |  |   | (158 | ) |  | Lower Lima inventory offset by inclusion of Toledo inventory
|Prepaid expenses                   |  |      | 33    |      |   | 28    |        |  |   | 5    |   |  |                                                             
|                                   |  |      |       |      |   |       |        |  |   |      |   |  |                                                             
|                                   |  |      | 3,322 |      |   | 3,048 |        |  |   | 274  |   |  |                                                             
|Current liabilities                |  |      |       |      |   |       |        |  |   |      |   |  |                                                             
|Accounts payable                   |  |      | 1,608 |      |   | 1,460 |        |  |   | (148 | ) |  | Higher capital accruals                                     
|Accrued interest payable           |  |      | 22    |      |   | 20    |        |  |   | (2   | ) |  |                                                             
|Income taxes payable               |  |      | 419   |      |   | 36    |        |  |   | (383 | ) |  | Higher taxable income                                       
|Other accrued liabilities          |  |      | 847   |      |   | 842   |        |  |   | (5   | ) |  |                                                             
|Long-term debt due within one year |  |      |      |      |   | 741   |        |  |   | 741  |   |  | Repayment of bridge financing                               
|                                   |  |      |       |      |   |       |        |  |   |      |   |  |                                                             
|                                   |  |      | 2,896 |      |   | 3,099 |        |  |   | 203  |   |  |                                                             
|                                   |  |      |       |      |   |       |        |  |   |      |   |  |                                                             
|Working capital (deficiency)       |  | $    | 426   |      | $ | (51   | )      |  | $ | 477  |   |  |                                                             
|                                   |  |      |       |      |   |       |        |  |   |      |   |  |                                                             

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, repay maturing debt and pay dividends. Huskys upstream capital programs are funded principally by cash provided from operating activities and committed credit
facilities. During times of low oil and gas prices, part 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 long term investment plan during periods of low commodity prices. As a result, Husky frequently evaluates its options with respect to sources of long and short-term capital
resources. In addition, from time to time the Company engages in hedging a portion of production to protect cash flow in the event of commodity price declines. Corporate acquisitions, such as the Lima Refinery are financed by issuing investment
grade long-term debt.

At December 31, 2008, outstanding long-term debt totalled $2.0 billion, including amounts due within one year,
compared with $2.8 billion at December 31, 2007. The Company does not have any debt maturing before 2012.

Cash and cash equivalents
at December 31, 2008 totalled $913 million compared with $208 million at the beginning of the year.



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At December 31, 2008, Husky had unused committed long and short-term borrowing credit facilities
totalling $1.5 billion. In addition, a further $270 million of uncommitted short term borrowing facilities were available of which a total of $166 million were used in support of outstanding letters of credit.

The Sunrise Oil Sands Partnership has an unsecured demand credit facility available of $10 million for general purposes. Huskys proportionate share
is $5 million.

In 2008, Husky initiated a cash tender offer to purchase any and all of the U.S. $225 million 8.90% capital securities
outstanding. At the time of expiration of the tender offer, U.S. $214 million or 95% of the capital securities had been tendered. The remaining capital securities were redeemed in 2008.

In 2008, Husky redeemed the 6.95% medium-term notes  Series E due July 14, 2009. The principal amount was $200 million and the redemption
price, including accrued interest, totalled $208 million.

During 2008, Husky repurchased U.S. $63 million of the outstanding U.S. $450
million 6.80% notes due September 2037.

Dividends were declared that aggregated $1.70 per share totalling $1.4 billion in 2008. The Board
of Directors of Husky has established a dividend policy that pays quarterly dividends of $0.30 ($1.20 annually) per common share. The declaration of dividends will be at the discretion of the Board of Directors, which will consider earnings, capital
requirements, the Companys financial condition and other relevant factors.

Capital Structure



|                                                                            |             |                   |           |  |   |      
|--------------------------------------------------------------------------- | ----------- | ----------------- | --------- |  | - | -----
|($ millions)                                                                |             | December 31, 2008
|                                                                            | Outstanding |                   | Available
|Total short-term and long-term debt                                         |             | $                 | 1,957     |  | $ | 1,604
|Common shares, retained earnings and accumulated other comprehensive income |             | $                 | 14,388    |  |   |      
|                                                                            |             |                   |           |  |   |      

Credit Ratings

Huskys senior debt and capital securities have been rated investment grade by several rating agencies. These ratings are disclosed and explained in detail in Huskys Annual Information Form.

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)            |  | Total |        | 2009 |   | 2010-2011 |  | 2012-2013 |       | Thereafter
|Long-term debt and interest on fixed rate debt |  | $     | 3,554  |      | $ | 127       |  | $         | 254   |            | $ | 695   |  | $ | 2,478
|Operating leases                               |  |       | 466    |      |   | 115       |  |           | 187   |            |   | 136   |  |   | 28   
|Firm transportation agreements                 |  |       | 637    |      |   | 144       |  |           | 142   |            |   | 102   |  |   | 249  
|Unconditional purchase obligations (1)         |  |       | 4,402  |      |   | 2,775     |  |           | 1,352 |            |   | 113   |  |   | 162  
|Lease rentals and exploration work agreements  |  |       | 1,020  |      |   | 178       |  |           | 309   |            |   | 219   |  |   | 314  
|Asset retirement obligations (2)               |  |       | 5,232  |      |   | 29        |  |           | 58    |            |   | 52    |  |   | 5,093
|                                               |  |       |        |      |   |           |  |           |       |            |   |       |  |   |      
|                                               |  | $     | 15,311 |      | $ | 3,368     |  | $         | 2,302 |            | $ | 1,317 |  | $ | 8,324
|                                               |  |       |        |      |   |           |  |           |       |            |   |       |  |   |      



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



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

Based on Huskys 2009 commodity price forecast, the Company believes that its
non-cancellable contractual obligations and other commercial commitments and 2009 capital program will be funded by cash flow from operating activities and, to the extent required, by available committed credit facilities and the issuance of
long-term debt. In the event of significantly lower cash flow, Husky would be able to defer certain projected capital expenditures without penalty.

Estimated Obligations Not Included in the Table

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 140 active employees and 458 retirees and their beneficiaries 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 385 active employees in the United States. This pension plan was established effective July 1, 2007
in conjunction with the acquisition of the Lima Refinery. Husky also assumed a post-retirement welfare plan covering the employees at the Lima Refinery. See Note 20 to the Consolidated Financial Statements.

Husky has an obligation to fund a contribution payable of U.S. $1.4 billion to the BP-Husky Toledo Refinery LLC (refer to Note 10 to the Consolidated
Financial Statements) which is payable between December 31, 2008 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.

Other Obligations

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 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 asset retirement obligations. 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

Accounts Receivable Securitization Program

In the ordinary course of business, Husky engages in the securitization of accounts receivable. The securitization program permits the sale of a maximum
of $350 million of accounts receivable on a revolving basis. At December 31, 2008, there were no accounts receivable sold under the program. The securitization agreement expires on March 31, 2009. The accounts receivable are sold to an
unrelated third party and in accordance with the agreement the Company must provide a loss reserve to replace defaulted receivables.



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The securitization program provides Husky with cost-effective short-term funding for general corporate
use. These are accounted for as asset sales. In the event the program is terminated Huskys liquidity would not be substantially reduced.

Standby
Letters of Credit

In addition, from time to time, Husky issues letters of credit in connection with transactions in which the
counterparty requires such security.

Derivative Instruments

Husky utilizes derivative financial instruments in order to manage unacceptable risk. The derivative financial instruments currently outstanding are listed and discussed in Section 8.6, Financial Risk and
Risk Management.

8.5 Transactions with Related Parties and Major Customers

TransAlta Power, L.P. is an indirect subsidiary of Cheung Kong Infrastructure Holdings Ltd., which is majority owned by Hutchison Whampoa Limited, which
owns 100% of U.F. Investments (Barbados) Ltd., a 34.58% shareholder in Husky. TransAlta Power, L.P. is a 49.99% owner of TransAlta Cogeneration, L.P., the Companys partner in the Meridian cogeneration plant in Lloydminster, Saskatchewan. Husky
sells natural gas to the Meridian cogeneration plant and other cogeneration plants owned by TransAlta Power, L.P. The Company received the market price or negotiated medium-term contracts based on market-related terms for these commodities. During
2008, Husky sold $125 million of natural gas to TransAlta Power, L.P.

Husky did not have any customers that constituted more than 10% of
total sales and operating revenues during 2008.

8.6 Financial Risk and Risk Management

Husky is exposed to market risks related to the volatility of commodity prices, foreign exchange rates, interest rates, credit risk and changes in fiscal,
monetary and other financial policies related to royalties, taxes and others. Refer to Section 6, The 2008 Business Environment. From time to time, the Company will use derivative instruments to manage its exposure to these risks.

The global financial and economic crisis which developed in 2008 has increased the risk associated with timely access to debt capital and
banking markets and the current market instability may have an impact on Huskys ability to borrow in the capital markets at acceptable rates.

Commodity Price Risk Management

Husky uses derivative commodity instruments from time to time 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.

Foreign Currency Risk
Management

At December 31, 2008, Husky had the following cross currency debt swaps in place:



| |  |  | U.S. $150 million at 6.25% swapped at $1.41 to $211 million at 7.41% until June 15, 2012.
| | - |  | -----------------------------------------------------------------------------------------



| |  |  | U.S. $75 million at 6.25% swapped at $1.19 to $89 million at 5.65% until June 15, 2012.
| | - |  | ---------------------------------------------------------------------------------------



| |  |  | U.S. $50 million at 6.25% swapped at $1.17 to $59 million at 5.67% until June 15, 2012.
| | - |  | ---------------------------------------------------------------------------------------



| |  |  | U.S. $75 million at 6.25% swapped at $1.17 to $88 million at 5.61% until June 15, 2012.
| | - |  | ---------------------------------------------------------------------------------------



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At December 31, 2008, Husky had the following freestanding derivatives in place where it had entered
into forward purchases of U.S. dollars (refer to Note 22 to the Consolidated Financial Statements):



| |  |  | U.S. $98 million bought at $0.9860 for $97 million from January 2008 to June 2011.
| | - |  | ----------------------------------------------------------------------------------



| |  |  | U.S. $98 million bought at $0.9777 for $96 million from January 2008 to June 2011.
| | - |  | ----------------------------------------------------------------------------------

At December 31, 2008, the cost of a U.S. dollar in Canadian currency was $1.22.

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,
as expressed in Canadian dollars, as well as in the related interest expense. At December 31, 2008, 100% or $2.0 billion of Huskys long-term debt was denominated in U.S. dollars. The percentage of the Companys long-term debt exposed
to the U.S./Canadian exchange rate decreases to 78% when cross currency swaps are considered.

Effective July 1, 2007, Huskys
U.S. $1.5 billion of debt financing related to the Lima acquisition was designated as a hedge of the net investment in the U.S. refining operations, which are considered self-sustaining. During the second quarter of 2008, the Company repaid bridge
financing of U.S. $750 million. In the third quarter of 2008, Husky repurchased U.S. $43 million of bonds that were classified as a net investment hedge. In October, an additional U.S. $20 million were repurchased. As a result, the net investment
hedge is limited to the remaining U.S. $687 million. As at December 31, 2008, foreign exchange losses arising from the translation of the debt were $165 million, net of tax of $27 million, which was recorded in Other Comprehensive
Income.

Interest Rate Risk Management

In 2008, interest rate risk management activities resulted in a decrease to interest expense of less than $1 million.

Husky has
interest rate swaps on $200 million of long-term debt effective February 8, 2002 whereby 6.95% was swapped for CDOR + 175 bps until July 14, 2009. During 2008, these swaps resulted in an offset to interest expense amounting to $1 million.
The interest rate swaps were discontinued as a fair value hedge on August 29, 2008 given the $200 million medium-term notes were redeemed. For the remainder of 2008, the fair value changes were included in other expenses.

The amortization of previous interest rate swap terminations resulted in an additional $5 million offset to interest expense in 2008.

Cross currency swaps resulted in an addition to interest expense of $6 million in 2008.

Credit and Contract Risk

Husky actively manages its exposure to credit and contract execution risk
from both a customer and a supplier perspective.

8.7 Outstanding Share Data

Authorized:



| |  |  | unlimited number of common shares
| | - |  | ---------------------------------



| |  |  | unlimited number of preferred shares
| | - |  | ------------------------------------



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Issued and outstanding: February 12, 2009



|                                 |  |             |  | 
|-------------------------------- |  | ----------- |  | 
|      common shares             |  | 849,361,278 |  | 
|      preferred shares          |  | none        |  | 
|      stock options             |  | 30,557,694  |  | 
|      stock options exercisable |  | 7,179,605   |  | 

At February 12, 2009, 50.4 million common shares were reserved for issuance under the
stock option plan. Options awarded under the stock option plan have a maximum term of five years and vest evenly over the first three years.

9. Application of Critical Accounting Estimates

Huskys Consolidated Financial Statements have been prepared in accordance
with Canadian Generally Accepted Accounting Principles (GAAP). Significant accounting policies are disclosed in Note 3 to the Consolidated Financial Statements. Certain of the Companys accounting policies require subjective
judgment about uncertain circumstances. The following discussion highlights the nature and potential effect of these estimates. The emergence of new information and changed circumstances may result in actual results or changes to estimated amounts
that differ materially from current estimates.

Full Cost Accounting for Oil and Gas Activities

The indicated change in the following estimates will result in a corresponding increase in the amount of DD&A expense charged to income in a given
period:

An increase in:



| |  |  | estimated costs to develop the proved undeveloped reserves;
| | - |  | -----------------------------------------------------------



| |  |  | estimated fair value of the ARO related to the oil and gas properties; and
| | - |  | --------------------------------------------------------------------------



| |  |  | estimated impairment of costs excluded from the DD&A calculation.
| | - |  | -----------------------------------------------------------------

A decrease in:



| |  |  | previously estimated proved oil and gas reserves; and
| | - |  | -----------------------------------------------------



| |  |  | estimated proved reserves added compared to capital invested.
| | - |  | -------------------------------------------------------------

Depletion Expense

All costs associated with exploration and development are capitalized on a
country-by-country basis. The aggregate of capitalized costs, net of accumulated DD&A, plus the estimated costs required to develop the proved undeveloped reserves, less estimated salvage values, is charged to income over the life of the proved
reserves using the unit of production method.

Withheld Costs

Costs related to unproved properties and major development projects are excluded from costs subject to depletion until proved reserves have been determined or their value is impaired. Impairment is transferred to
costs being depleted or, if the properties are located in a cost centre where there is no reserve base, the impairment is charged directly to earnings.



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Ceiling Test

Each cost centres capitalized costs are tested for recoverability at least yearly. The test compares the estimated undiscounted future net cash flows from proved oil and gas reserves based on forecast prices and costs to the carrying
amount of a cost centre. If the future cash flows are lower than the carrying costs, the cost centre is written down to its fair value. Fair value is estimated using present value techniques, which incorporate risks and other uncertainties as well
as the future value of reserves when determining estimated cash flows.

Impairment of Long-lived Assets

Impairment is indicated if the carrying value of the long-lived asset or oil and gas cost centre is not recoverable by the future undiscounted cash flows.
If impairment is indicated, the amount by which the carrying value exceeds the estimated fair value of the long-lived asset is charged to earnings.

Fair Value of Derivative Instruments

Periodically Husky utilizes financial derivatives to manage market risk. Effective
January 1, 2007, Husky adopted CICA section 3855, Financial Instruments  Recognition and Measurement, section 3865, Hedges, section 1530, Comprehensive Income and section 3861, Financial
Instruments  Disclosure and Presentation. These standards provide the recognition, measurement and disclosure requirements for financial instruments and hedge accounting. Refer to Note 19 in the Consolidated Financial Statements.

The estimation of the fair value of commodity derivatives incorporates forward prices and adjustments for quality or location. The
estimate of fair value for interest rate and foreign currency hedges is determined primarily through forward market prices and compared with quotes from financial institutions. The estimation of fair value for the Companys embedded derivative
and the forward purchases of U.S. dollars to partially offset the fluctuations in foreign exchange related to the embedded derivative is determined using forward market prices.

Asset Retirement Obligation

Husky has significant obligations to remove tangible assets and restore
land after operations cease and Husky retires or relinquishes the asset. The Companys ARO primarily relates to the upstream business. The retirement of upstream assets consists primarily of plugging and abandoning wells, removing and disposing
of surface and subsea equipment and facilities and restoration of land to a state required by regulation or contract. Estimating the ARO requires us to estimate costs that are many years in the future. Restoration technologies and costs are
constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

Inherent in the calculation
of the ARO are numerous assumptions and judgments 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 result in changes to the ARO.

Employee Future Benefits

The determination of the cost of the post-retirement health and dental care plan and defined benefit pension plan reflects a number of assumptions that
affect the expected future benefit payments. These assumptions 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 are used for the purposes of calculating the expected return on plan assets.



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Legal, Environmental Remediation and Other Contingent Matters

Husky is required to both determine whether a loss is probable based on judgment and interpretation of laws and regulations and determine that the loss
can reasonably be estimated. When the loss is determined it is charged to earnings. Husky must continually monitor known and potential contingent matters and make appropriate provisions by charges to earnings when warranted by circumstances.

Income Tax Accounting

The
determination of the Companys income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. 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.

Business
Combinations

Under the purchase method, the acquiring company includes the fair value of the various assets and liabilities of the
acquired entity on its balance sheet. The determination of fair value necessarily involves many assumptions. In some circumstances the fair value of an asset is determined by estimating the amount and timing of future cash flow associated with that
asset. The actual amounts and timing of cash flow may differ materially and may possibly lead to an impairment charged to earnings.

Goodwill

In combination with purchase accounting, any excess of the purchase price over fair value is recorded as goodwill. Since goodwill
results from the culmination of purchase accounting, described above, it too is inherently imprecise. Goodwill must be assessed annually for impairment and necessarily requires the judgmental determination of the fair value of assets and
liabilities.

10. New and Pending Accounting Standards

New

Inventories

Effective January 1, 2008, the Company adopted the Canadian Institute of Chartered Accountants (CICA) section 3031, Inventories, which replaced CICA section 3030 of the same name. The new
guidance provides additional measurement and disclosure requirements and requires the Company to reverse previous impairment write-downs. The transitional provisions of section 3031 provided entities with the option of applying this guidance
retrospectively and restating prior periods in accordance with section 1506, Accounting Changes or adjusting opening retained earnings and not restating prior periods. The adoption of this standard did not have an impact on the
Companys financial statements.

Financial InstrumentsDisclosure and Presentation

Effective January 1, 2008, the Company adopted CICA section 3862, Financial InstrumentsDisclosures and CICA section 3863,
Financial InstrumentsPresentation, which replaced CICA section 3861, Financial InstrumentsDisclosure and Presentation. Section 3862 outlines the disclosure requirements for financial instruments and
non-financial derivatives. This guidance prescribes an increased importance on risk disclosures associated with recognized and unrecognized financial instruments and how such risks are managed. Specifically, section 3862 requires disclosure of the
significance of financial instruments on the Companys financial position. In addition, the guidance outlines revised requirements for the disclosure of qualitative and quantitative information regarding exposure to risks arising from financial
instruments.



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The presentation requirements under section 3863 are relatively unchanged from section 3861.

Capital Disclosures

Effective January 1,
2008, the Company adopted CICA section 1535, Capital Disclosures. This new guidance requires disclosure about the Companys objectives, policies and processes for managing capital. These disclosures include a description of what the
Company manages as capital, the nature of externally imposed capital requirements, how the requirements are incorporated into the Companys management of capital, whether the requirements have been complied with, or consequence of
non-compliance and an explanation of how the Company is meeting its objectives for managing capital. In addition, quantitative disclosures regarding capital are required.

Pending

Goodwill and Intangible Assets

In February 2008, the CICA issued CICA section 3064, Goodwill and Intangible Assets, which will replace CICA section 3062 of the same name. As
a result of issuing this guidance, CICA section 3450, Research and Development Costs, and Emerging Issues Committee Abstract No. 27, Revenues and Expenditures during the Pre-Operating Period, will be withdrawn. This new
guidance requires recognizing all goodwill and intangible assets in accordance with CICA section 1000, Financial Statement Concepts. Section 3064 will eliminate the current practice of recognizing items as assets that do not meet
the section 1000 definition and recognition criteria.

As of January 1, 2009, the Company will retroactively adopt CICA section 3064.
This adoption will result in a reduction of retained earnings at January 1, 2007 of $9 million, a reduction of earnings after tax of $3 million and $13 million for the years ended December 31, 2008 and 2007, respectively, and a reduction
to assets of $36 million and $31 million as at December 31, 2008 and 2007, respectively.

Business Combinations

In December 2008, the CICA issued section 1582 Business Combinations, which will replace CICA section 1581 of the same name. Under this
guidance, the purchase price used in a business combination is based on the fair value of shares exchanged at their market price at the date of the exchange. Currently the purchase price used is based on the market price of the shares for a
reasonable period before and after the date the acquisition is agreed upon and announced. This new guidance generally requires all acquisition costs to be expensed, which currently are capitalized as part of the purchase price. Contingent
liabilities are to be recognized at fair value at the acquisition date and remeasured at fair value through earnings each period until settled. Currently only contingent liabilities that are resolved and payable are included in the cost to acquire
the business. In addition, negative goodwill is required to be recognized immediately in earnings, unlike the current requirement to eliminate it by deducting it from non-current assets in the purchase price allocation. Section 1582 will be
effective for Husky on January 1, 2011 with prospective application.

International Financial Reporting Standards

In January 2006, the Canadian Accounting Standards Board (AcSB) adopted a strategic plan for the direction of accounting standards in Canada.
In February 2008, as part of its strategic plan, the AcSB confirmed that Canadian publicly accountable entities will be required to report under International Financial Reporting Standards (IFRS), which will replace Canadian GAAP for
years beginning on or after January 1, 2011. An omnibus exposure draft was issued by the AcSB in the second quarter of 2008, which incorporates IFRS into the CICA Handbook and prescribes the transitional provisions for adopting IFRS.



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The Company commenced its IFRS transition project in 2008, which includes four key phases:



| |  |  | Project awareness and engagement  This phase includes identifying and engaging the appropriate members for the core IFRS transition team,
steering committee and other representatives as required. In addition, this phase includes communicating the key project requirements and objectives to the areas of the organization that will be impacted by IFRS conversion, including the
Companys senior executive management team, Board of Directors and Audit Committee.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Diagnostic This phase includes an assessment of the differences between current Canadian GAAP and IFRS, focusing on the areas which will have
the most significant impact to Husky. A preliminary conversion roadmap has been prepared as part of this phase.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Design, planning and solution development  This phase focuses on determining the specific impacts to the Company based on the application of the
IFRS requirements. This includes the design and development of detailed solutions and work plans by each key area to address implementation requirements. In addition, impact analysis will be performed on all areas of the business, including tax and
information technology systems. Accounting policies will be finalized, first-time adoption exemptions will be considered, draft financial statements and disclosures will be prepared and a detailed implementation plan and timeline will be developed.
This phase also includes the development of a training plan.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Implementation  This phase includes implementing the required changes necessary for IFRS compliance. The focus of this phase is the finalization
of IFRS conversion impacts, approval and implementation of accounting and tax policies, implementation and testing of new processes, systems and controls, execution of customized training programs and preparation of opening IFRS balances.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Corporate governance over the project has been established and a steering committee and project team have been formed.
This committee is comprised of members of senior executive management and is responsible for final approval of project recommendations and deliverables to the Audit Committee and Board. Due to the scope of the IFRS project, the Company ensured that
the appropriate stakeholders have been engaged by establishing a project advisory committee, which includes representatives from each area of the organization that will be significantly impacted. Husky has also engaged an external advisor to assist
with the IFRS conversion process.

The Company has completed the diagnostic assessment phase by performing comparisons of the differences
between Canadian GAAP and IFRS. The Company has determined that the most significant impact of IFRS conversion is to property, plant and equipment. IFRS does not prescribe specific oil and gas accounting guidance other than for costs associated with
the exploration and evaluation phase. The Company currently follows full cost accounting as prescribed in Accounting Guideline (AcG) 16, Oil and Gas Accounting  Full Cost. Conversion to IFRS may have a significant
impact on how the Company accounts for costs pertaining to oil and gas activities, in particular those related to the pre-exploration and development phases. In addition, the level at which impairment tests are performed and the impairment testing
methodology will differ under IFRS. IFRS conversion will also result in other impacts, some of which may be significant in nature. These impacts continue to be assessed by the Company. At this time, the impact on the Companys financial
position and results of operations is not reasonably determinable or estimable for any of the IFRS conversion impacts identified.

The
Company is currently completing the design, planning and solution development phase. Project team members have been working in conjunction with representatives from the various operational areas to evaluate the specific impacts of IFRS conversion to
Husky and to develop recommendations and accounting policies. Communication, training and education are a critical aspect of the Companys IFRS conversion project therefore training and education sessions will continue throughout each phase of
the project.

In September 2008, the International Accounting Standards Board (IASB) issued an exposure draft which proposes
additional exemptions for entities adopting IFRS for the first-time. One of these proposed exemptions relates to companies using the full cost method of accounting. If the exposure draft is finalized, this exemption



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will allow entities to allocate their oil and gas asset balance as determined under full cost accounting to the IFRS categories of exploration and evaluation
assets and development and producing properties. This exemption would relieve entities from significant adjustments resulting from retrospective adoption of IFRS. The Company intends to utilize this exemption if it is approved and finalized as part
of IFRS. Husky is also evaluating other first-time adoption exemptions available upon initial transition which give relief from retrospective application of IFRS.

In addition, the Company is monitoring the IASBs active projects and all changes to IFRS prior to January 1, 2011 will be incorporated as required.

11. Reader Advisories

11.1 Forward-looking Statements

Certain statements in this document are forward-looking statements or 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 Company is hereby providing cautionary statements identifying important factors that could cause the Companys 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 result,
are expected to, will continue, is anticipated, estimated, intend, plan, projection, could, vision, goals, objective
and outlook) are not historical facts and may be forward-looking and may involve estimates, assumptions and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking
statements. In particular, forward-looking statements include: the Companys general strategic plans, the Companys response to the current global economic environment, the Companys integrated oil sands joint development including
the Sunrise oil sands project schedule and phased development and Toledo refinery modifications, Huskys White Rose oil field drilling, development and production plans and East Coast exploration programs, the schedule of Huskys offshore
China drilling programs, the schedule for the Liwan projects facility design, the Companys development plans for the Madura BD field in Indonesia, East Bawean II drilling programs, the Gull Lake project startup date, the planned total
depth for the Gray 31-23 well and the Toledo operational integrity and plant performance program. Accordingly, any such forward-looking statements are qualified in their entirety by reference to, and are accompanied by, the factors discussed
throughout this document. Among the key factors that have a direct bearing on Huskys results of operations are the nature of the Companys involvement in the business of exploration for, and development and production of crude oil and
natural gas reserves and the fluctuation of the exchange rates between the Canadian and United States dollar.

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.

The Companys Annual Report to shareholders 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 which are incorporated herein by reference.

Further, any forward-looking statement speaks only as of the date on which such
statement is made, and, except as required by applicable law, 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.



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11.2 Oil and Gas Reserve Reporting

Disclosure of Proved Oil and Gas Reserves and Other Oil and Gas Information

Huskys disclosure of proved oil and gas reserves and other information about its oil and gas activities has been made based on reliance of an exemption granted by Canadian Securities Administrators. The
exemption permits Husky to make these disclosures in accordance with requirements in the United States. These requirements and, consequently, the information presented may differ from Canadian requirements under National Instrument 51-101,
Standards of Disclosure for Oil and Gas Activities. The proved oil and gas reserves disclosed in this document have been evaluated using the United States standards contained in Rule 4-10 of Regulation S-X of the Securities Exchange Act
of 1934 and Guide 2 of the Securities Act Industry Guides. The probable oil and gas reserves disclosed in this document have been evaluated in accordance with the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101. Please refer
to Disclosure of Exemption under National Instrument 51-101 in the Annual Information Form for the year ended December 31, 2008 filed with securities regulatory authorities for further information.

The Company uses the terms barrels of oil equivalent (boe) and thousand cubic feet of gas equivalent (mcfge), which are
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 terms boe and mcfge 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 well head.

Cautionary Note to U.S. Investors

The United States Securities and Exchange Commission (SEC) permits U.S. oil and gas companies, in their filings with the SEC, to disclose
only proved reserves, that is reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of
the date the estimate is made. Husky uses certain terms in this document such as probable reserves that the SECs guidelines strictly prohibit in filings with the SEC by U.S. oil and gas companies. U.S. investors should refer to
Huskys Annual Report on Form 40-F available from the Company or the SEC for further reserve disclosure.

11.3 Non-GAAP
Measures

Disclosure of non-GAAP Measurements

Husky uses measurements primarily based on GAAP and also on secondary non-GAAP measurements. The non-GAAP measurements included in this report are: Cash flow from operations, Operating netback, Return on equity,
Return on capital employed, Debt to capitalization and Corporate reinvestment ratio. None of these measurements is used to enhance the Companys reported financial performance or position. These are useful complementary measurements in
assessing Huskys financial performance, efficiency and liquidity. They are common in the reports of other companies but may differ by definition and application. Except as described below, the definitions of these measurements are found in
Section 11.4, Additional Reader Advisories.

Disclosure of Cash Flow from Operations

Husky uses the term cash flow from operations, which should not be considered an alternative to, or more meaningful than cash flow
 operating activities as determined in accordance with generally accepted accounting principles, as an indicator of financial performance. Cash flow from operations or earnings is presented in the Companys financial reports to
assist management and investors in analyzing operating performance by business in the stated period. Huskys determination of cash flow from operations may not be comparable to that reported by other companies. Cash flow from operations equals
net earnings plus items not affecting cash which include accretion, depletion, depreciation and amortization, future income taxes, foreign exchange and other non-cash items.



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The following table shows the reconciliation of cash flow from operations to cash flowoperating
activities for the years ended December 31:



|                                               |  |      |       |   |      |   |       |      |  |   |       |  
|---------------------------------------------- |  | ---- | ----- | - | ---- | - | ----- | ---- |  | - | ----- | -
|($ millions)                                   |  | 2008 |       |   | 2007 |   |       | 2006 | 
|Non-GAAP    Cash flow from operations          |  | $    | 5,970 |   |      | $ | 5,426 |      |  | $ | 4,501 |  
|Settlement of asset retirement obligations     |  |      | (56   | ) |      |   | (51   | )    |  |   | (36   | )
|Change in non-cash working capital             |  |      | 888   |   |      |   | (718  | )    |  |   | 544   |  
|                                               |  |      |       |   |      |   |       |      |  |   |       |  
|GAAP            Cash flowoperating activities |  | $    | 6,802 |   |      | $ | 4,657 |      |  | $ | 5,009 |  
|                                               |  |      |       |   |      |   |       |      |  |   |       |  

Disclosure of Operating Netback

Operating netback is a common non-GAAP metric used in the oil and gas industry. This measurement helps management and investors to evaluate the specific
operating performance by product at the oil and gas lease level. It is equal to product revenue less transportation costs, royalties and lease operating costs divided by either a barrel of oil equivalent or a mcf of gas equivalent.

11.4 Additional Reader Advisories

Intention of Managements Discussion and Analysis

This MD&A is intended to provide an explanation of financial and
operational performance compared with prior periods and the Companys prospects and plans. It provides additional information that is not contained in the Companys financial statements.

Review by the Audit Committee

This MD&A was
reviewed by the Audit Committee and approved by Huskys Board of Directors on February 17, 2009. Any events subsequent to that date could conceivably 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 2008, which contain MD&A and Consolidated Financial Statements, and Huskys Annual Information Form filed separately with Canadian regulatory agencies and Form 40-F filed with the SEC, the U.S.
regulatory agency. These documents are available at www.sedar.com, at www.sec.gov and www.huskyenergy.com.

Use of Pronouns and
Other Terms

Husky and the Company refer to Husky Energy Inc. on a consolidated basis.

Standard Comparisons in this Document

Unless
otherwise indicated, comparisons of results are for the years ended December 31, 2008 and 2007 and Huskys financial position as at December 31, 2008 and at December 31, 2007.

Reclassifications and Materiality for Disclosures

Certain prior year amounts have been reclassified to conform to current year presentation. Materiality for disclosures is determined on the basis of whether the information omitted or misstated would cause a reasonable investor to change
their decision to buy, sell or hold the securities of Husky.



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Additional Reader Guidance

Unless otherwise indicated:



| |  |  | Financial information is presented in accordance with GAAP in Canada. Significant differences between Canadian and United States GAAP are disclosed in the U.S. GAAP
reconciliation contained in Form 40-F and available at www.sedar.com.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Currency is presented in millions of Canadian dollars (C$).
| | - |  | -------------------------------------------------------------



| |  |  | 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 30o API and above.
| | - |  | -------------------------------------



| |  |  | Medium crude oil is 21o API and above but below 30o API.
| | - |  | --------------------------------------------------------



| |  |  | Heavy crude oil is above 10o API but below 21o API.
| | - |  | ---------------------------------------------------



| |  |  | Bitumen is 10o API and below.
| | - |  | -----------------------------

Abbreviations



|          |  |                                                          
|--------- |  | ---------------------------------------------------------
|bbls      |  | barrels                                                  
|bps       |  | basis points                                             
|mbbls     |  | thousand barrels                                         
|mbbls/day |  | thousand barrels per day                                 
|mmbbls    |  | million barrels                                          
|mcf       |  | thousand cubic feet                                      
|mmcf      |  | million cubic feet                                       
|mmcf/day  |  | million cubic feet per day                               
|bcf       |  | billion cubic feet                                       
|tcf       |  | trillion cubic feet                                      
|boe       |  | barrels of oil equivalent                                
|mboe      |  | thousand barrels of oil equivalent                       
|mboe/day  |  | thousand barrels of oil equivalent per day               
|mmboe     |  | million barrels of oil equivalent                        
|mcfge     |  | thousand cubic feet of gas equivalent                    
|GAAP      |  | Generally Accepted Accounting Principles                 
|GJ        |  | gigajoule                                                
|mmbtu     |  | million British Thermal Units                            
|mmlt      |  | million long tons                                        
|MW        |  | megawatt                                                 
|NGL       |  | natural gas liquids                                      
|WTI       |  | West Texas Intermediate                                  
|NYMEX     |  | New York Mercantile Exchange                             
|NIT       |  | NOVA Inventory Transfer                                  
|LIBOR     |  | London Interbank Offered Rate                            
|CDOR      |  | Certificate of Deposit Offered Rate                      
|SEDAR     |  | System for Electronic Document Analysis and Retrieval    
|FPSO      |  | Floating production, storage and offloading vessel       
|FEED      |  | Front-end engineering design                             
|OPEC      |  | Organization of Petroleum Exporting Countries            
|SAGD      |  | Steam-assisted gravity drainage                          
|MD&A      |  | Managements Discussion and Analysis                     
|CNLOPB    |  | Canada-Newfoundland and Labrador Offshore Petroleum Board



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Terms



|                               |  |                                                                                                                                                                                                                
|------------------------------ |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Bitumen                        |  | A naturally occurring viscous mixture consisting mainly of pentanes and heavier hydrocarbons. It is more viscous than 10 degrees API                                                                           
|Brent Crude Oil                |  | Prices which are dated less than 15 days prior to loading for delivery                                                                                                                                         
|Capital Employed               |  | Short and long-term debt and shareholders equity                                                                                                                                                              
|Capital Expenditures           |  | Includes capitalized administrative expenses and capitalized interest but does not include proceeds or other assets                                                                                            
|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 and change in non-cash working capital                                                                        
|Coal Bed Methane               |  | Methane (CH4), the principal component of natural gas, is adsorbed in the pores of coal seams                                                                                                                  
|Corporate Reinvestment Ratio   |  | Net capital expenditures (capital expenditures net of proceeds from asset sales) plus corporate acquisitions (net assets acquired) divided by cash flow from operations                                        
|Debt to Capitalization         |  | Total debt divided by total debt and shareholders equity                                                                                                                                                      
|Design Rate Capacity           |  | Maximum continuous rated output of a plant based on its design                                                                                                                                                 
|Embedded Derivative            |  | Implicit or explicit term(s) in a contract that affects some or all of the cash flows or the value of other exchanges required by the contract                                                                 
|Feedstock                      |  | Raw materials which are processed into petroleum products                                                                                                                                                      
|Front End Engineering Design   |  | Preliminary engineering and design planning, which among other things, identifies project objectives, scope, alternatives, specifications, risks, costs, schedule and
economics                                
|Glory Hole                     |  | An excavation in the seabed where the wellheads and other equipment are situated to protect them from scouring icebergs                                                                                        
|Gross/Net Acres/Wells          |  | Gross refers to the total number of acres/wells in which an 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 pay to meet its interest payment obligation. It is equal to earnings before income taxes and interest divided by interest paid before deduction
of capitalized interest
|NOVA Inventory Transfer        |  | Exchange or transfer of title of gas that has been received into the NOVA pipeline system but not yet delivered to a connecting pipeline                                                                       
|Polymer                        |  | A substance which has a molecular structure built up mainly or entirely of many similar units bonded together                                                                                                  
|Return on Capital Employed     |  | Net earnings plus after tax interest expense divided by average capital employed                                                                                                                               
|Return on Shareholders Equity |  | Net earnings divided by 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 accumulated other comprehensive income                                                                                                                                           
|Total Debt                     |  | Long-term debt including current portion and bank operating loans                                                                                                                                              



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Proved reserves have been estimated in accordance with the SEC definition set out in Rule
4-10(a) of Regulation S-X under the Securities Exchange Act of 1934 as follows: Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids, which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.

Proved Developed reserves are those reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and
mechanisms of primary recovery are included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved Undeveloped reserves are those reserves that are expected to be recovered from new wells on undrilled acreage, or
from existing wells for which a relatively major expenditure is required for recompletion. Inclusion of reserves on undrilled acreage is limited to those drilling units offsetting productive units that are reasonably certain of production when
drilled. Proved reserves for other undrilled units are included only if it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed
to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

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 and probable reserves.

11.5 Controls and Procedures

Disclosure Controls and Procedures

Huskys management, with the participation of the Chief Executive Officer and the Chief Financial Officer, have evaluated the effectiveness of
Huskys disclosure controls and procedures (as defined in the rules of the SEC and the Canadian Securities Administrators (CSA)) as at December 31, 2008, and have concluded that such disclosure controls and procedures are
effective to ensure that information required to be disclosed by Husky in reports that it files or submits under the Securities Exchange Act of 1934 and Canadian securities laws is (i) recorded, processed, summarized and reported within the
time periods specified in SEC rules and forms and Canadian securities laws and (ii) accumulated and communicated to Huskys management, including its principal executive officer and principal financial officer, to allow timely decisions
regarding required disclosure.

Managements Annual Report on Internal Control over Financial Reporting

The following report is provided by management in respect of Huskys internal controls over financial reporting (as defined in the rules of the SEC
and the CSA):



| | 1) | Huskys management is responsible for establishing and maintaining adequate internal control over financial reporting for Husky. All internal control systems, no matter how
well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
| | -- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 2) | Huskys management has used the Committee of Sponsoring Organizations of the Treadway Commission (COSO) framework to evaluate the effectiveness of Huskys
internal control over financial reporting.
| | -- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| | 3) | As at December 31, 2008, management assessed the effectiveness of Huskys internal control over financial reporting and concluded that such internal control over financial
reporting is effective and that there are no material weaknesses in Huskys internal control over financial reporting that have been identified by management.
| | -- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 4) | KPMG LLP, who has audited the Consolidated Financial Statements of Husky for the year ended December 31, 2008, has also issued a report on internal controls under Auditing
Standard No. 5 of the Public Company Accounting Oversight Board (United States).
| | -- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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, 2008, that have
materially affected, or are reasonably likely to materially affect its internal control over financial reporting.



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12. Selected Quarterly Financial & Operating Information

Segmented Operational Information



|                                        |  |      |       |      |   |        |  |    |        |    |   |       |  |    |       |    |   |       |  |   |       |  |   |      
|--------------------------------------- |  | ---- | ----- | ---- | - | ------ |  | -- | ------ | -- | - | ----- |  | -- | ----- | -- | - | ----- |  | - | ----- |  | - | -----
|                                        |  | 2008 |       | 2007
|                                        |  | Q4   |       | Q3   |   | Q2     |  | Q1 |        | Q4 |   | Q3    |  | Q2 |       | Q1
|Upstream                                |  |      |       |      |   |        |  |    |        |    |   |       |  |    |       |    |   |       |  |   |       |  |   |      
|Daily production, before royalties      |  |      |       |      |   |        |  |    |        |    |   |       |  |    |       |    |   |       |  |   |       |  |   |      
|Light crude oil & NGL (mbbls/day)       |  |      | 125.9 |      |   | 121.7  |  |    | 123.6  |    |   | 120.5 |  |    | 129.7 |    |   | 133.3 |  |   | 144.3 |  |   | 147.8
|Medium crude oil (mbbls/day)            |  |      | 26.6  |      |   | 26.9   |  |    | 27.0   |    |   | 26.9  |  |    | 27.0  |    |   | 26.7  |  |   | 26.8  |  |   | 27.5 
|Heavy crude oil & bitumen (mbbls/day)   |  |      | 110.7 |      |   | 107.6  |  |    | 105.5  |    |   | 104.3 |  |    | 107.8 |    |   | 106.5 |  |   | 105.4 |  |   | 108.0
|                                        |  |      |       |      |   |        |  |    |        |    |   |       |  |    |       |    |   |       |  |   |       |  |   |      
|                                        |  |      | 263.2 |      |   | 256.2  |  |    | 256.1  |    |   | 251.7 |  |    | 264.5 |    |   | 266.5 |  |   | 276.5 |  |   | 283.3
|Natural gas (mmcf/day)                  |  |      | 571.1 |      |   | 598.3  |  |    | 618.0  |    |   | 590.4 |  |    | 617.8 |    |   | 620.1 |  |   | 615.7 |  |   | 640.0
|Total production (mboe/day)             |  |      | 358.4 |      |   | 355.9  |  |    | 359.1  |    |   | 350.1 |  |    | 367.5 |    |   | 369.9 |  |   | 379.1 |  |   | 390.0
|Average sales prices                    |  |      |       |      |   |        |  |    |        |    |   |       |  |    |       |    |   |       |  |   |       |  |   |      
|Light crude oil & NGL ($/bbl)           |  | $    | 58.43 |      | $ | 114.85 |  | $  | 121.71 |    | $ | 95.20 |  | $  | 83.43 |    | $ | 76.00 |  | $ | 72.28 |  | $ | 64.88
|Medium crude oil ($/bbl)                |  | $    | 47.02 |      | $ | 103.60 |  | $  | 101.87 |    | $ | 74.30 |  | $  | 55.37 |    | $ | 54.55 |  | $ | 48.15 |  | $ | 46.40
|Heavy crude oil & bitumen ($/bbl)       |  | $    | 38.83 |      | $ | 95.55  |  | $  | 89.35  |    | $ | 63.91 |  | $  | 41.13 |    | $ | 43.64 |  | $ | 38.19 |  | $ | 37.63
|Natural gas ($/mcf)                     |  | $    | 6.84  |      | $ | 8.66   |  | $  | 9.14   |    | $ | 7.04  |  | $  | 5.72  |    | $ | 5.18  |  | $ | 6.91  |  | $ | 6.94 
|Operating costs ($/boe)                 |  | $    | 10.84 |      | $ | 11.20  |  | $  | 10.91  |    | $ | 10.75 |  | $  | 9.61  |    | $ | 9.60  |  | $ | 8.84  |  | $ | 8.34 
|Operating netbacks (1)                  |  |      |       |      |   |        |  |    |        |    |   |       |  |    |       |    |   |       |  |   |       |  |   |      
|Light crude oil ($/boe)(2)              |  | $    | 39.42 |      | $ | 76.03  |  | $  | 79.73  |    | $ | 65.39 |  | $  | 61.39 |    | $ | 53.66 |  | $ | 59.13 |  | $ | 56.14
|Medium crude oil ($/boe) (2)            |  | $    | 23.95 |      | $ | 67.32  |  | $  | 65.34  |    | $ | 44.88 |  | $  | 29.99 |    | $ | 28.81 |  | $ | 26.95 |  | $ | 24.67
|Heavy crude oil & bitumen ($/boe)(2)    |  | $    | 18.09 |      | $ | 62.22  |  | $  | 60.66  |    | $ | 40.33 |  | $  | 21.56 |    | $ | 25.11 |  | $ | 20.37 |  | $ | 21.11
|Natural gas ($/mcfge)(3)                |  | $    | 3.94  |      | $ | 5.33   |  | $  | 6.23   |    | $ | 4.50  |  | $  | 3.60  |    | $ | 3.05  |  | $ | 4.32  |  | $ | 4.24 
|Total ($/boe) (2)                       |  | $    | 27.31 |      | $ | 58.99  |  | $  | 60.85  |    | $ | 45.43 |  | $  | 36.01 |    | $ | 33.68 |  | $ | 36.91 |  | $ | 35.70
|Net wells drilled (4)                   |  |      |       |      |   |        |  |    |        |    |   |       |  |    |       |    |   |       |  |   |       |  |   |      
|Exploration       Oil                   |  |      | 34    |      |   | 10     |  |    | 3      |    |   | 23    |  |    | 23    |    |   | 23    |  |   | 13    |  |   | 20   
|Gas                                     |  |      | 15    |      |   | 11     |  |    | 4      |    |   | 49    |  |    | 20    |    |   | 13    |  |   | 3     |  |   | 56   
|Dry                                     |  |      | 2     |      |   | 2      |  |    |       |    |   | 19    |  |    |      |    |   | 2     |  |   | 1     |  |   | 9    
|                                        |  |      |       |      |   |        |  |    |        |    |   |       |  |    |       |    |   |       |  |   |       |  |   |      
|                                        |  |      | 51    |      |   | 23     |  |    | 7      |    |   | 91    |  |    | 43    |    |   | 38    |  |   | 17    |  |   | 85   
|                                        |  |      |       |      |   |        |  |    |        |    |   |       |  |    |       |    |   |       |  |   |       |  |   |      
|Development    Oil                      |  |      | 190   |      |   | 211    |  |    | 73     |    |   | 104   |  |    | 143   |    |   | 203   |  |   | 54    |  |   | 130  
|Gas                                     |  |      | 78    |      |   | 88     |  |    | 17     |    |   | 87    |  |    | 56    |    |   | 54    |  |   | 4     |  |   | 137  
|Dry                                     |  |      | 20    |      |   | 13     |  |    |       |    |   | 3     |  |    | 10    |    |   | 7     |  |   | 2     |  |   | 10   
|                                        |  |      |       |      |   |        |  |    |        |    |   |       |  |    |       |    |   |       |  |   |       |  |   |      
|                                        |  |      | 288   |      |   | 312    |  |    | 90     |    |   | 194   |  |    | 209   |    |   | 264   |  |   | 60    |  |   | 277  
|                                        |  |      |       |      |   |        |  |    |        |    |   |       |  |    |       |    |   |       |  |   |       |  |   |      
|                                        |  |      | 339   |      |   | 335    |  |    | 97     |    |   | 285   |  |    | 252   |    |   | 302   |  |   | 77    |  |   | 362  
|                                        |  |      |       |      |   |        |  |    |        |    |   |       |  |    |       |    |   |       |  |   |       |  |   |      
|Success ratio (percent)                 |  |      | 94    |      |   | 96     |  |    | 100    |    |   | 92    |  |    | 96    |    |   | 97    |  |   | 96    |  |   | 95   
|                                        |  |      |       |      |   |        |  |    |        |    |   |       |  |    |       |    |   |       |  |   |       |  |   |      
|Midstream                               |  |      |       |      |   |        |  |    |        |    |   |       |  |    |       |    |   |       |  |   |       |  |   |      
|Synthetic crude oil sales (mbbls/day)   |  |      | 58.2  |      |   | 69.1   |  |    | 51.6   |    |   | 55.6  |  |    | 66.5  |    |   | 55.1  |  |   | 32.9  |  |   | 57.8 
|Upgrading differential ($/bbl)          |  | $    | 27.48 |      | $ | 26.09  |  | $  | 30.12  |    | $ | 28.53 |  | $  | 36.74 |    | $ | 30.41 |  | $ | 30.41 |  | $ | 24.11
|Pipeline throughput (mbbls/day)         |  |      | 493   |      |   | 494    |  |    | 539    |    |   | 504   |  |    | 497   |    |   | 506   |  |   | 506   |  |   | 493  
|                                        |  |      |       |      |   |        |  |    |        |    |   |       |  |    |       |    |   |       |  |   |       |  |   |      
|Canadian Refined Products               |  |      |       |      |   |        |  |    |        |    |   |       |  |    |       |    |   |       |  |   |       |  |   |      
|Refined products sales volumes          |  |      |       |      |   |        |  |    |        |    |   |       |  |    |       |    |   |       |  |   |       |  |   |      
|Light oil products (million litres/day) |  |      | 7.5   |      |   | 8.3    |  |    | 7.9    |    |   | 7.9   |  |    | 8.5   |    |   | 9.0   |  |   | 8.6   |  |   | 8.9  
|Asphalt products (mbbls/day)            |  |      | 21.4  |      |   | 33.9   |  |    | 23.0   |    |   | 17.8  |  |    | 24.5  |    |   | 25.9  |  |   | 19.5  |  |   | 17.3 
|Refinery throughput                     |  |      |       |      |   |        |  |    |        |    |   |       |  |    |       |    |   |       |  |   |       |  |   |      
|Lloydminster refinery (mbbls/day)       |  |      | 28.8  |      |   | 27.3   |  |    | 26.4   |    |   | 22.0  |  |    | 28.8  |    |   | 29.0  |  |   | 18.5  |  |   | 24.7 
|Prince George refinery (mbbls/day)      |  |      | 10.7  |      |   | 7.9    |  |    | 10.5   |    |   | 11.4  |  |    | 11.6  |    |   | 10.8  |  |   | 8.4   |  |   | 11.1 
|Refinery utilization (percent)          |  |      | 99    |      |   | 88     |  |    | 92     |    |   | 84    |  |    | 101   |    |   | 100   |  |   | 67    |  |   | 90   
|                                        |  |      |       |      |   |        |  |    |        |    |   |       |  |    |       |    |   |       |  |   |       |  |   |      



|(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) | Western Canada.
|--- | ---------------



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##### Table of Contents

Segmented Financial Information



|                                               |  |          |           |           |                              |   |        |  |    |        |    |   |        |    |   |       |   |    |   |       |  |   |       |  |   |       |  |   |       |   |  |   |       |   |  |   |       |   |  |   |      
|---------------------------------------------- |  | -------- | --------- | --------- | ---------------------------- | - | ------ |  | -- | ------ | -- | - | ------ | -- | - | ----- | - | -- | - | ----- |  | - | ----- |  | - | ----- |  | - | ----- | - |  | - | ----- | - |  | - | ----- | - |  | - | -----
|                                               |  | Upstream |           | Midstream
|                                               |  |          | Upgrading |           | Infrastructure and Marketing
|($ millions)                                   |  | Q4       |           |           | Q3                           |   | Q2     |  | Q1 |        | Q4 |   |        | Q3 |   | Q2    |   | Q1 |   | Q4    |  |   | Q3    |  |   | Q2    |  |   | Q1   
|2008                                           |  |          |           |           |                              |   |        |  |    |        |    |   |        |    |   |       |   |    |   |       |  |   |       |  |   |       |  |   |       |   |  |   |       |   |  |   |       |   |  |   |      
|Sales and operating revenues, net of royalties |  | $        | 1,295     |           |                              | $ | 2,341  |  | $  | 2,424  |    | $ | 1,829  |    | $ | 445   |   |    | $ | 859   |  | $ | 648   |  | $ | 483   |  | $ | 2,456 |   |  | $ | 4,077 |   |  | $ | 3,909 |   |  | $ | 3,102
|Costs and expenses                             |  |          |           |           |                              |   |        |  |    |        |    |   |        |    |   |       |   |    |   |       |  |   |       |  |   |       |  |   |       |   |  |   |       |   |  |   |       |   |  |   |      
|Operating, cost of sales, selling and general  |  |          | 455       |           |                              |   | 431    |  |    | 328    |    |   | 413    |    |   | 373   |   |    |   | 761   |  |   | 546   |  |   | 374   |  |   | 2,408 |   |  |   | 4,014 |   |  |   | 3,779 |   |  |   | 2,991
|Depletion, depreciation and amortization       |  |          | 394       |           |                              |   | 369    |  |    | 352    |    |   | 390    |    |   | 9     |   |    |   | 9     |  |   | 7     |  |   | 6     |  |   | 8     |   |  |   | 8     |   |  |   | 7     |   |  |   | 8    
|Interestnet                                   |  |          |          |           |                              |   |       |  |    |       |    |   |       |    |   |      |   |    |   |      |  |   |      |  |   |      |  |   |      |   |  |   |      |   |  |   |      |   |  |   |     
|Foreign exchange                               |  |          |          |           |                              |   |       |  |    |       |    |   |       |    |   |      |   |    |   |      |  |   |      |  |   |      |  |   |      |   |  |   |      |   |  |   |      |   |  |   |     
|                                               |  |          |           |           |                              |   |        |  |    |        |    |   |        |    |   |       |   |    |   |       |  |   |       |  |   |       |  |   |       |   |  |   |       |   |  |   |       |   |  |   |      
|                                               |  |          | 849       |           |                              |   | 800    |  |    | 680    |    |   | 803    |    |   | 382   |   |    |   | 770   |  |   | 553   |  |   | 380   |  |   | 2,416 |   |  |   | 4,022 |   |  |   | 3,786 |   |  |   | 2,999
|                                               |  |          |           |           |                              |   |        |  |    |        |    |   |        |    |   |       |   |    |   |       |  |   |       |  |   |       |  |   |       |   |  |   |       |   |  |   |       |   |  |   |      
|Earnings (loss) before income taxes            |  |          | 446       |           |                              |   | 1,541  |  |    | 1,744  |    |   | 1,026  |    |   | 63    |   |    |   | 89    |  |   | 95    |  |   | 103   |  |   | 40    |   |  |   | 55    |   |  |   | 123   |   |  |   | 103  
|Current income taxes                           |  |          | 123       |           |                              |   | 197    |  |    | 99     |    |   | 166    |    |   | 21    |   |    |   | 27    |  |   | 14    |  |   | 22    |  |   | 37    |   |  |   | 31    |   |  |   | 28    |   |  |   | 30   
|Future income taxes                            |  |          | (19       | )         |                              |   | 265    |  |    | 406    |    |   | 143    |    |   | (2    | ) |    |   |      |  |   | 14    |  |   | 9     |  |   | (25   | ) |  |   | (14   | ) |  |   | 9     |   |  |   | 1    
|                                               |  |          |           |           |                              |   |        |  |    |        |    |   |        |    |   |       |   |    |   |       |  |   |       |  |   |       |  |   |       |   |  |   |       |   |  |   |       |   |  |   |      
|Net earnings (loss)                            |  | $        | 342       |           |                              | $ | 1,079  |  | $  | 1,239  |    | $ | 717    |    | $ | 44    |   |    | $ | 62    |  | $ | 67    |  | $ | 72    |  | $ | 28    |   |  | $ | 38    |   |  | $ | 86    |   |  | $ | 72   
|                                               |  |          |           |           |                              |   |        |  |    |        |    |   |        |    |   |       |   |    |   |       |  |   |       |  |   |       |  |   |       |   |  |   |       |   |  |   |       |   |  |   |      
|Capital expenditures (2)                       |  | $        | 1,174     |           |                              | $ | 983    |  | $  | 625    |    | $ | 798    |    | $ | 23    |   |    | $ | 26    |  | $ | 28    |  | $ | 22    |  | $ | 58    |   |  | $ | 21    |   |  | $ | 5     |   |  | $ | 10   
|Goodwill additions                             |  | $        |          |           |                              | $ |       |  | $  |       |    | $ |       |    | $ |      |   |    | $ |      |  | $ |      |  | $ |      |  | $ |      |   |  | $ |      |   |  | $ |      |   |  | $ |     
|Total assets                                   |  | $        | 15,653    |           |                              | $ | 14,724 |  | $  | 14,708 |    | $ | 13,114 |    | $ | 1,349 |   |    | $ | 1,481 |  | $ | 1,497 |  | $ | 1,434 |  | $ | 1,486 |   |  | $ | 1,802 |   |  | $ | 1,300 |   |  | $ | 1,322
|                                               |  |          |           |           |                              |   |        |  |    |        |    |   |        |    |   |       |   |    |   |       |  |   |       |  |   |       |  |   |       |   |  |   |       |   |  |   |       |   |  |   |      
|2007                                           |  |          |           |           |                              |   |        |  |    |        |    |   |        |    |   |       |   |    |   |       |  |   |       |  |   |       |  |   |       |   |  |   |       |   |  |   |       |   |  |   |      
|Sales and operating revenues, net of royalties |  | $        | 1,568     |           |                              | $ | 1,496  |  | $  | 1,593  |    | $ | 1,565  |    | $ | 530   |   |    | $ | 406   |  | $ | 229   |  | $ | 359   |  | $ | 2,617 |   |  | $ | 2,524 |   |  | $ | 2,521 |   |  | $ | 2,555
|Costs and expenses                             |  |          |           |           |                              |   |        |  |    |        |    |   |        |    |   |       |   |    |   |       |  |   |       |  |   |       |  |   |       |   |  |   |       |   |  |   |       |   |  |   |      
|Operating, cost of sales, selling and general  |  |          | 358       |           |                              |   | 332    |  |    | 295    |    |   | 323    |    |   | 358   |   |    |   | 305   |  |   | 186   |  |   | 278   |  |   | 2,509 |   |  |   | 2,423 |   |  |   | 2,445 |   |  |   | 2,461
|Depletion, depreciation and amortization       |  |          | 396       |           |                              |   | 413    |  |    | 407    |    |   | 399    |    |   | 8     |   |    |   | 7     |  |   | 4     |  |   | 6     |  |   | 7     |   |  |   | 7     |   |  |   | 7     |   |  |   | 7    
|Interestnet                                   |  |          |          |           |                              |   |       |  |    |       |    |   |       |    |   |      |   |    |   |      |  |   |      |  |   |      |  |   |      |   |  |   |      |   |  |   |      |   |  |   |     
|Foreign exchange                               |  |          |          |           |                              |   |       |  |    |       |    |   |       |    |   |      |   |    |   |      |  |   |      |  |   |      |  |   |      |   |  |   |      |   |  |   |      |   |  |   |     
|                                               |  |          |           |           |                              |   |        |  |    |        |    |   |        |    |   |       |   |    |   |       |  |   |       |  |   |       |  |   |       |   |  |   |       |   |  |   |       |   |  |   |      
|                                               |  |          | 754       |           |                              |   | 745    |  |    | 702    |    |   | 722    |    |   | 366   |   |    |   | 312   |  |   | 190   |  |   | 284   |  |   | 2,516 |   |  |   | 2,430 |   |  |   | 2,452 |   |  |   | 2,468
|                                               |  |          |           |           |                              |   |        |  |    |        |    |   |        |    |   |       |   |    |   |       |  |   |       |  |   |       |  |   |       |   |  |   |       |   |  |   |       |   |  |   |      
|Earnings (loss) before income taxes            |  |          | 814       |           |                              |   | 751    |  |    | 891    |    |   | 843    |    |   | 164   |   |    |   | 94    |  |   | 39    |  |   | 75    |  |   | 101   |   |  |   | 94    |   |  |   | 69    |   |  |   | 87   
|Current income taxes                           |  |          | 41        |           |                              |   | 56     |  |    | 3      |    |   | 22     |    |   | 5     |   |    |   | 4     |  |   |      |  |   | 1     |  |   | 18    |   |  |   | 5     |   |  |   | 29    |   |  |   | 16   
|Future income taxes                            |  |          | (91       | )         |                              |   | 179    |  |    | 252    |    |   | 241    |    |   | 22    |   |    |   | 25    |  |   | 10    |  |   | 23    |  |   | 2     |   |  |   | 25    |   |  |   | (8    | ) |  |   | 11   
|                                               |  |          |           |           |                              |   |        |  |    |        |    |   |        |    |   |       |   |    |   |       |  |   |       |  |   |       |  |   |       |   |  |   |       |   |  |   |       |   |  |   |      
|Net earnings (loss)                            |  | $        | 864       |           |                              | $ | 516    |  | $  | 636    |    | $ | 580    |    | $ | 137   |   |    | $ | 65    |  | $ | 29    |  | $ | 51    |  | $ | 81    |   |  | $ | 64    |   |  | $ | 48    |   |  | $ | 60   
|                                               |  |          |           |           |                              |   |        |  |    |        |    |   |        |    |   |       |   |    |   |       |  |   |       |  |   |       |  |   |       |   |  |   |       |   |  |   |       |   |  |   |      
|Capital expenditures (2)                       |  | $        | 706       |           |                              | $ | 545    |  | $  | 520    |    | $ | 617    |    | $ | 44    |   |    | $ | 51    |  | $ | 74    |  | $ | 48    |  | $ | 15    |   |  | $ | 36    |   |  | $ | 5     |   |  | $ | 36   
|Goodwill additions                             |  | $        |          |           |                              | $ |       |  | $  |       |    | $ |       |    | $ |      |   |    | $ |      |  | $ |      |  | $ |      |  | $ |      |   |  | $ |      |   |  | $ |      |   |  | $ |     
|Total assets                                   |  | $        | 14,395    |           |                              | $ | 14,085 |  | $  | 13,974 |    | $ | 14,168 |    | $ | 1,405 |   |    | $ | 1,354 |  | $ | 1,193 |  | $ | 1,177 |  | $ | 1,134 |   |  | $ | 1,016 |   |  | $ | 1,147 |   |  | $ | 1,057



|(1) | Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices, and to unrealized intersegment profits in
inventories.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | Excludes capitalized costs related to asset retirement obligations incurred during the period and the Lima acquisition and the BP joint venture transaction.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------



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##### Table of Contents

|                                               |  |                           |       |                             |                               |   |       |       |  |    |       |    |    |       |    |    |       |    |    |    |       |    |  |   |       |  |   |       |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|---------------------------------------------- |  | ------------------------- | ----- | --------------------------- | ----------------------------- | - | ----- | ----- |  | -- | ----- | -- | -- | ----- | -- | -- | ----- | -- | -- | -- | ----- | -- |  | - | ----- |  | - | ----- | - |  | - | ------ | - |  | - | ------ | - |  | - | ------ | - |  | - | ------ | - |  | - | ------ | - |  | - | ------ | - |  | - | ------ | - |  | - | ------ | -
|                                               |  | Downstream                |       |                             | Corporate and Eliminations(1) |   |       | Total | 
|                                               |  | Canadian Refined Products |       | U.S. Refining and Marketing |                               |   | Q4    |       |  | Q3 |       |    | Q2 |       |    | Q1 |       |    | Q4 |    |       | Q3 |  |   | Q2    |  |   | Q1    |  
|($ millions)                                   |  | Q4                        |       |                             | Q3                            |   |       | Q2    |  | Q1 |       | Q4 |    |       | Q3 |    |       | Q2 |    | Q1 |       |    |  |   |       |  |   |       |  
|2008                                           |  |                           |       |                             |                               |   |       |       |  |    |       |    |    |       |    |    |       |    |    |    |       |    |  |   |       |  |   |       |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|Sales and operating revenues, net of royalties |  | $                         | 673   |                             |                               | $ | 1,187 |       |  | $  | 982   |    | $  | 722   |    | $  | 1,474 |    |    | $  | 2,446 |    |  | $ | 2,553 |  | $ | 1,329 |   |  | $ | (1,642 | ) |  | $ | (3,195 | ) |  | $ | (3,317 | ) |  | $ | (2,379 | ) |  | $ | 4,701  |   |  | $ | 7,715  |   |  | $ | 7,199  |   |  | $ | 5,086  |  
|Costs and expenses                             |  |                           |       |                             |                               |   |       |       |  |    |       |    |    |       |    |    |       |    |    |    |       |    |  |   |       |  |   |       |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|Operating, cost of sales, selling and general  |  |                           | 636   |                             |                               |   | 1,130 |       |  |    | 912   |    |    | 659   |    |    | 2,263 |    |    |    | 2,456 |    |  |   | 2,262 |  |   | 1,296 |   |  |   | (1,788 | ) |  |   | (3,323 | ) |  |   | (3,050 | ) |  |   | (2,419 | ) |  |   | 4,347  |   |  |   | 5,469  |   |  |   | 4,777  |   |  |   | 3,314  |  
|Depletion, depreciation and amortization       |  |                           | 20    |                             |                               |   | 21    |       |  |    | 20    |    |    | 20    |    |    | 50    |    |    |    | 42    |    |  |   | 43    |  |   | 19    |   |  |   | 8      |   |  |   | 8      |   |  |   | 7      |   |  |   | 7      |   |  |   | 489    |   |  |   | 457    |   |  |   | 436    |   |  |   | 450    |  
|Interest  net                                 |  |                           |      |                             |                               |   |      |       |  |    |      |    |    |      |    |    | 1     |    |    |    | 1     |    |  |   |      |  |   | 1     |   |  |   | 30     |   |  |   | 28     |   |  |   | 41     |   |  |   | 45     |   |  |   | 31     |   |  |   | 29     |   |  |   | 41     |   |  |   | 46     |  
|Foreign exchange                               |  |                           |      |                             |                               |   |      |       |  |    |      |    |    |      |    |    |      |    |    |    |      |    |  |   |      |  |   |      |   |  |   | (275   | ) |  |   | (76    | ) |  |   | 6      |   |  |   | 10     |   |  |   | (275   | ) |  |   | (76    | ) |  |   | 6      |   |  |   | 10     |  
|                                               |  |                           |       |                             |                               |   |       |       |  |    |       |    |    |       |    |    |       |    |    |    |       |    |  |   |       |  |   |       |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|                                               |  |                           | 656   |                             |                               |   | 1,151 |       |  |    | 932   |    |    | 679   |    |    | 2,314 |    |    |    | 2,499 |    |  |   | 2,305 |  |   | 1,316 |   |  |   | (2,025 | ) |  |   | (3,363 | ) |  |   | (2,996 | ) |  |   | (2,357 | ) |  |   | 4,592  |   |  |   | 5,879  |   |  |   | 5,260  |   |  |   | 3,820  |  
|                                               |  |                           |       |                             |                               |   |       |       |  |    |       |    |    |       |    |    |       |    |    |    |       |    |  |   |       |  |   |       |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|Earnings (loss) before income taxes            |  |                           | 17    |                             |                               |   | 36    |       |  |    | 50    |    |    | 43    |    |    | (840  | )  |    |    | (53   | )  |  |   | 248   |  |   | 13    |   |  |   | 383    |   |  |   | 168    |   |  |   | (321   | ) |  |   | (22    | ) |  |   | 109    |   |  |   | 1,836  |   |  |   | 1,939  |   |  |   | 1,266  |  
|Current income taxes                           |  |                           | 8     |                             |                               |   | 7     |       |  |    | 7     |    |    | 6     |    |    | (33   | )  |    |    | (28   | )  |  |   | 59    |  |   | (22   | ) |  |   | 20     |   |  |   | 32     |   |  |   | 27     |   |  |   | 23     |   |  |   | 176    |   |  |   | 266    |   |  |   | 234    |   |  |   | 225    |  
|Future income taxes                            |  |                           | (7    | )                           |                               |   | 4     |       |  |    | 8     |    |    | 7     |    |    | (273  | )  |    |    | 9     |    |  |   | 30    |  |   | 27    |   |  |   | 27     |   |  |   | 34     |   |  |   | (125   | ) |  |   | (33    | ) |  |   | (299   | ) |  |   | 298    |   |  |   | 342    |   |  |   | 154    |  
|                                               |  |                           |       |                             |                               |   |       |       |  |    |       |    |    |       |    |    |       |    |    |    |       |    |  |   |       |  |   |       |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|Net earnings (loss)                            |  | $                         | 16    |                             |                               | $ | 25    |       |  | $  | 35    |    | $  | 30    |    | $  | (534  | )  |    | $  | (34   | )  |  | $ | 159   |  | $ | 8     |   |  | $ | 336    |   |  | $ | 102    |   |  | $ | (223   | ) |  | $ | (12    | ) |  | $ | 232    |   |  | $ | 1,272  |   |  | $ | 1,363  |   |  | $ | 887    |  
|                                               |  |                           |       |                             |                               |   |       |       |  |    |       |    |    |       |    |    |       |    |    |    |       |    |  |   |       |  |   |       |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|Capital expenditures (2)                       |  | $                         | 63    |                             |                               | $ | 45    |       |  | $  | 28    |    | $  | 19    |    | $  | 70    |    |    | $  | 22    |    |  | $ | 34    |  | $ | 7     |   |  | $ | 14     |   |  | $ | 7      |   |  | $ | 14     |   |  | $ | 12     |   |  | $ | 1,402  |   |  | $ | 1,104  |   |  | $ | 734    |   |  | $ | 868    |  
|Goodwill additions                             |  | $                         |      |                             |                               | $ |      |       |  | $  |      |    | $  |      |    | $  |      |    |    | $  |      |    |  | $ |      |  | $ |      |   |  | $ |       |   |  | $ |       |   |  | $ |       |   |  | $ |       |   |  | $ |       |   |  | $ |       |   |  | $ |       |   |  | $ |       |  
|Total assets                                   |  | $                         | 1,381 |                             |                               | $ | 1,562 |       |  | $  | 1,630 |    | $  | 1,396 |    | $  | 5,383 |    |    | $  | 5,507 |    |  | $ | 5,404 |  | $ | 6,574 |   |  | $ | 1,270  |   |  | $ | 1,216  |   |  | $ | 757    |   |  | $ | 551    |   |  | $ | 26,522 |   |  | $ | 26,292 |   |  | $ | 25,296 |   |  | $ | 24,391 |  
|                                               |  |                           |       |                             |                               |   |       |       |  |    |       |    |    |       |    |    |       |    |    |    |       |    |  |   |       |  |   |       |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|2007                                           |  |                           |       |                             |                               |   |       |       |  |    |       |    |    |       |    |    |       |    |    |    |       |    |  |   |       |  |   |       |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|Sales and operating revenues, net of royalties |  | $                         | 758   |                             |                               | $ | 831   |       |  | $  | 709   |    | $  | 618   |    | $  | 1,340 |    |    | $  | 1,043 |    |  | $ |      |  | $ |      |   |  | $ | (2,053 | ) |  | $ | (1,949 | ) |  | $ | (1,889 | ) |  | $ | (1,853 | ) |  | $ | 4,760  |   |  | $ | 4,351  |   |  | $ | 3,163  |   |  | $ | 3,244  |  
|Costs and expenses                             |  |                           |       |                             |                               |   |       |       |  |    |       |    |    |       |    |    |       |    |    |    |       |    |  |   |       |  |   |       |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|Operating, cost of sales, selling and general  |  |                           | 699   |                             |                               |   | 717   |       |  |    | 620   |    |    | 572   |    |    | 1,234 |    |    |    | 933   |    |  |   |      |  |   |      |   |  |   | (1,982 | ) |  |   | (1,969 | ) |  |   | (1,801 | ) |  |   | (1,790 | ) |  |   | 3,176  |   |  |   | 2,741  |   |  |   | 1,745  |   |  |   | 1,844  |  
|Depletion, depreciation and amortization       |  |                           | 19    |                             |                               |   | 16    |       |  |    | 15    |    |    | 16    |    |    | 25    |    |    |    | 22    |    |  |   |      |  |   |      |   |  |   | 7      |   |  |   | 6      |   |  |   | 7      |   |  |   | 5      |   |  |   | 462    |   |  |   | 471    |   |  |   | 440    |   |  |   | 433    |  
|Interest  net                                 |  |                           |      |                             |                               |   |      |       |  |    |      |    |    |      |    |    |      |    |    |    | 1     |    |  |   |      |  |   |      |   |  |   | 40     |   |  |   | 46     |   |  |   | 22     |   |  |   | 21     |   |  |   | 40     |   |  |   | 47     |   |  |   | 22     |   |  |   | 21     |  
|Foreign exchange                               |  |                           |      |                             |                               |   |      |       |  |    |      |    |    |      |    |    |      |    |    |    |      |    |  |   |      |  |   |      |   |  |   | 6      |   |  |   | (20    | ) |  |   | (36    | ) |  |   | (1     | ) |  |   | 6      |   |  |   | (20    | ) |  |   | (36    | ) |  |   | (1     | )
|                                               |  |                           |       |                             |                               |   |       |       |  |    |       |    |    |       |    |    |       |    |    |    |       |    |  |   |       |  |   |       |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|                                               |  |                           | 718   |                             |                               |   | 733   |       |  |    | 635   |    |    | 588   |    |    | 1,259 |    |    |    | 956   |    |  |   |      |  |   |      |   |  |   | (1,929 | ) |  |   | (1,937 | ) |  |   | (1,808 | ) |  |   | (1,765 | ) |  |   | 3,684  |   |  |   | 3,239  |   |  |   | 2,171  |   |  |   | 2,297  |  
|                                               |  |                           |       |                             |                               |   |       |       |  |    |       |    |    |       |    |    |       |    |    |    |       |    |  |   |       |  |   |       |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|Earnings (loss) before income taxes            |  |                           | 40    |                             |                               |   | 98    |       |  |    | 74    |    |    | 30    |    |    | 81    |    |    |    | 87    |    |  |   |      |  |   |      |   |  |   | (124   | ) |  |   | (12    | ) |  |   | (81    | ) |  |   | (88    | ) |  |   | 1,076  |   |  |   | 1,112  |   |  |   | 992    |   |  |   | 947    |  
|Current income taxes                           |  |                           | 4     |                             |                               |   | (2    | )     |  |    | 7     |    |    | 8     |    |    | 14    |    |    |    | 14    |    |  |   |      |  |   |      |   |  |   | 28     |   |  |   | 22     |   |  |   | 27     |   |  |   | 25     |   |  |   | 110    |   |  |   | 99     |   |  |   | 66     |   |  |   | 72     |  
|Future income taxes                            |  |                           | (16   | )                           |                               |   | 33    |       |  |    | 14    |    |    | 2     |    |    | 16    |    |    |    | 19    |    |  |   |      |  |   |      |   |  |   | (41    | ) |  |   | (37    | ) |  |   | (63    | ) |  |   | (52    | ) |  |   | (108   | ) |  |   | 244    |   |  |   | 205    |   |  |   | 225    |  
|                                               |  |                           |       |                             |                               |   |       |       |  |    |       |    |    |       |    |    |       |    |    |    |       |    |  |   |       |  |   |       |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|Net earnings (loss)                            |  | $                         | 52    |                             |                               | $ | 67    |       |  | $  | 53    |    | $  | 20    |    | $  | 51    |    |    | $  | 54    |    |  | $ |      |  | $ |      |   |  | $ | (111   | ) |  | $ | 3      |   |  | $ | (45    | ) |  | $ | (61    | ) |  | $ | 1,074  |   |  | $ | 769    |   |  | $ | 721    |   |  | $ | 650    |  
|                                               |  |                           |       |                             |                               |   |       |       |  |    |       |    |    |       |    |    |       |    |    |    |       |    |  |   |       |  |   |       |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  
|Capital expenditures (2)                       |  | $                         | 52    |                             |                               | $ | 77    |       |  | $  | 43    |    | $  | 40    |    | $  | 16    |    |    | $  | 5     |    |  | $ |      |  | $ |      |   |  | $ | 20     |   |  | $ | 8      |   |  | $ | 11     |   |  | $ | 5      |   |  | $ | 853    |   |  | $ | 722    |   |  | $ | 653    |   |  | $ | 746    |  
|Goodwill additions                             |  | $                         |      |                             |                               | $ |      |       |  | $  |      |    | $  |      |    | $  |      |    |    | $  | 500   |    |  | $ |      |  | $ |      |   |  | $ |       |   |  | $ |       |   |  | $ |       |   |  | $ |       |   |  | $ |       |   |  | $ | 500    |   |  | $ |       |   |  | $ |       |  
|Total assets                                   |  | $                         | 1,335 |                             |                               | $ | 1,212 |       |  | $  | 1,304 |    | $  | 1,180 |    | $  | 3,058 |    |    | $  | 2,915 |    |  | $ |      |  | $ |      |   |  | $ | 370    |   |  | $ | 136    |   |  | $ | 351    |   |  | $ | 199    |   |  | $ | 21,697 |   |  | $ | 20,718 |   |  | $ | 17,969 |   |  | $ | 17,781 |  
|                                               |  |                           |       |                             |                               |   |       |       |  |    |       |    |    |       |    |    |       |    |    |    |       |    |  |   |       |  |   |       |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |   |  |   |        |  



|(1) | Eliminations relate to sales and operating revenues between segments recorded at transfer prices based on current market prices, and to unrealized intersegment profits in
inventories.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | Excludes capitalized costs related to asset retirement obligations incurred during the period and the Lima acquisition and the BP joint venture transaction.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------



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Segmented Capital Expenditures



|                               |  |      |       |      |   |       |  |    |     |    |   |     |  |    |     |    |   |     |  |   |     |  |   |    
|------------------------------ |  | ---- | ----- | ---- | - | ----- |  | -- | --- | -- | - | --- |  | -- | --- | -- | - | --- |  | - | --- |  | - | ---
|                               |  | 2008 |       | 2007
|($ millions)                   |  | Q4   |       | Q3   |   | Q2    |  | Q1 |     | Q4 |   | Q3  |  | Q2 |     | Q1
|Upstream                       |  |      |       |      |   |       |  |    |     |    |   |     |  |    |     |    |   |     |  |   |     |  |   |    
|Western Canada                 |  | $    | 815   |      | $ | 574   |  | $  | 497 |    | $ | 675 |  | $  | 594 |    | $ | 451 |  | $ | 433 |  | $ | 553
|East Coast Canada and Frontier |  |      | 237   |      |   | 306   |  |    | 93  |    |   | 93  |  |    | 87  |    |   | 73  |  |   | 62  |  |   | 59 
|Northwest United States        |  |      | 10    |      |   | 50    |  |    |    |    |   |    |  |    |    |    |   |    |  |   |    |  |   |   
|International                  |  |      | 112   |      |   | 53    |  |    | 35  |    |   | 30  |  |    | 25  |    |   | 21  |  |   | 25  |  |   | 5  
|                               |  |      |       |      |   |       |  |    |     |    |   |     |  |    |     |    |   |     |  |   |     |  |   |    
|                               |  |      | 1,174 |      |   | 983   |  |    | 625 |    |   | 798 |  |    | 706 |    |   | 545 |  |   | 520 |  |   | 617
|Midstream                      |  |      |       |      |   |       |  |    |     |    |   |     |  |    |     |    |   |     |  |   |     |  |   |    
|Upgrader                       |  |      | 23    |      |   | 26    |  |    | 28  |    |   | 22  |  |    | 44  |    |   | 51  |  |   | 74  |  |   | 48 
|Infrastructure and Marketing   |  |      | 58    |      |   | 21    |  |    | 5   |    |   | 10  |  |    | 15  |    |   | 36  |  |   | 5   |  |   | 36 
|                               |  |      |       |      |   |       |  |    |     |    |   |     |  |    |     |    |   |     |  |   |     |  |   |    
|                               |  |      | 81    |      |   | 47    |  |    | 33  |    |   | 32  |  |    | 59  |    |   | 87  |  |   | 79  |  |   | 84 
|Downstream                     |  |      |       |      |   |       |  |    |     |    |   |     |  |    |     |    |   |     |  |   |     |  |   |    
|Canadian Refined Products      |  |      | 63    |      |   | 45    |  |    | 28  |    |   | 19  |  |    | 52  |    |   | 77  |  |   | 43  |  |   | 40 
|U.S. Refining and Marketing    |  |      | 70    |      |   | 22    |  |    | 34  |    |   | 7   |  |    | 16  |    |   | 5   |  |   |    |  |   |   
|                               |  |      |       |      |   |       |  |    |     |    |   |     |  |    |     |    |   |     |  |   |     |  |   |    
|                               |  |      | 133   |      |   | 67    |  |    | 62  |    |   | 26  |  |    | 68  |    |   | 82  |  |   | 43  |  |   | 40 
|Corporate                      |  |      | 14    |      |   | 7     |  |    | 14  |    |   | 12  |  |    | 20  |    |   | 8   |  |   | 11  |  |   | 5  
|                               |  |      |       |      |   |       |  |    |     |    |   |     |  |    |     |    |   |     |  |   |     |  |   |    
|                               |  | $    | 1,402 |      | $ | 1,104 |  | $  | 734 |    | $ | 868 |  | $  | 853 |    | $ | 722 |  | $ | 653 |  | $ | 746
|                               |  |      |       |      |   |       |  |    |     |    |   |     |  |    |     |    |   |     |  |   |     |  |   |    

Note: Excludes capitalized costs related to asset retirement obligations incurred during the period and the
Lima acquisition and the BP joint venture transaction.



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|            |  |                                                                                                                                                             
|----------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit No. |  | Description                                                                                                                                                 
|23.1        |  | Consent of KPMG LLP, independent accountants.                                                                                                               
|            | 
|23.2        |  | Consent of McDaniel and Associates Consultants Ltd., independent engineers.                                                                                 
|            | 
|31.1        |  | Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934.                                       
|            | 
|31.2        |  | Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934.                                       
|            | 
|32.1        |  | Certification of Chief Executive Officer pursuant to Rule 13(a)-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) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).