Husky Energy (CVE+A) 40-F Annual report (Canada)

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))

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

(403) 298-6111

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

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

(212) 894-8400

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

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

Title of 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.

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 atwww.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. LAU
Name:	John C.S. Lau
Title:	President & Chief Executive Officer
By:	/s/    JAMES D. GIRGULIS
Name:	James D. Girgulis
Title:	Vice President, Legal & Corporate
	Secretary

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Document A

Form 40-F

Annual Information Form

For the Year Ended December 31, 2008

Husky Energy Inc.

Annual Information Form

For the Year Ended December 31, 2008

February 18, 2009

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 atwww.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 atwww.sec.gov.

CORPORATE STRUCTURE

Husky Energy Inc.

Husky Energy Inc. (“Husky Energy”) was incorporated under theBusiness 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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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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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 atwww.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 CO₂ Network, 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 CO₂ instead 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.

Page 13

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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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

Page 15

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%.

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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	Western Canada	East Coast	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	Western Canada	East Coast	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	Western Canada	East Coast	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.

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Revenue

	2008
	Total	Western Canada	East Coast	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	Western Canada	East Coast	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	Western Canada	East Coast	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	—	—

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Sales Prices

	2008
	Total	Western Canada	East Coast	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	Western Canada	East Coast	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	Western Canada	East Coast	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	—	—

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Capital Expenditures

	2008
	Total	Western Canada	East Coast	Canada	United States	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	Western Canada	East Coast	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	Western Canada	East Coast	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

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Oil and Gas Netbacks⁽¹⁾

	2008
	Total	Western Canada	East Coast	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

	2007
	Total	Western Canada	East Coast	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

	2006
	Total	Western Canada	East Coast	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

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.

Page 24

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

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

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

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 Net Cash Flows Before 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

Reconciliation of Proved Gross Reserves

	Canada												International			Total
	Western Canada										East Coast		Light Crude Oil & NGL		Natural Gas	Crude Oil & NGL		Natural Gas
	Light Crude Oil & NGL		Medium Crude Oil		Heavy Crude Oil		Natural Gas		Bitumen		Light Crude Oil
	(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		2 2,191		70		116		11		—	649		2 2,191
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

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

	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

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

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

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 to 2006
	($ 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
	Crude Oil & NGL		Natural Gas		Crude Oil & NGL		Natural Gas	Crude Oil & NGL		Natural Gas
	(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.

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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.

Page 40

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 Sands Area	Gross Acres	Net Acres	Husky Operator
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 theSeaRose 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 theSeaRose 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.

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 theWest 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. TheWest 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.

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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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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:

	British Columbia & Yukon	Alberta	Sask.	Manitoba	Ontario	2008 Total	2007 Total
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, theBusiness 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 theBusiness 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 theCompanies 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 fees billed by the External 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 of Measure
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 atwww.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.

Page 86

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.

Page 87

• 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.

Page 88

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

Page 89

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 Flows before 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.

Page 90

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

Page 91

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

Page 92

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

Page 93

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

Document B

Form 40-F

Consolidated Financial Statements and

Auditor’s Report to Shareholders

For the Year Ended December 31, 2008

Page 95

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

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

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

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

PAGE 4

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

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.

PAGE 6

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.

PAGE 7

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						Other International						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.

PAGE 9

	Downstream													Corporate and Eliminations(1)									Total
	Canadian Refined Products						U.S. Refining and Marketing
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

PAGE 10

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 atwww.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.

PAGE 11

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

PAGE 12

• 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.

PAGE 13

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.

PAGE 14

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.

PAGE 15

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.

PAGE 16

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.

PAGE 17

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.

PAGE 18

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

PAGE 19

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		Price increase 2013 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.

PAGE 20

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

PAGE 21

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%).

PAGE 22

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

PAGE 23

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.

PAGE 24

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

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.

PAGE 26

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		After 2013		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.

PAGE 27

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 of Shares	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 of Options (thousands)		Weighted Average Exercise Prices		Weighted Average Contractual Life (years)	Options Exercisable (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 of Options (thousands)	Weighted Average Exercise Prices		Weighted Average Contractual Life (years)	Number of Options (thousands)	Weighted Average Exercise Prices
$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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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 Health and 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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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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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
	Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value
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)		Fair Value
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)		Fair Value
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.

PAGE 35

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

Debt	Swap Amount		Canadian Equivalent		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.

PAGE 36

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 than 1 Year		1 to less than 2 Years		2 to less than 5 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

PAGE 38

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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Document C

Form 40-F

Reconciliation to Accounting Principles Generally Accepted

in the United States

PAGE 1

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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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 under U.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)	Canadian GAAP			U.S. GAAP			Canadian GAAP			U.S. GAAP			Canadian GAAP		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)	Canadian GAAP			U.S. GAAP			Canadian GAAP			U.S. GAAP			Canadian GAAP			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 of tax(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 of tax(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)	Canadian GAAP		U.S. GAAP		Canadian GAAP			U.S. GAAP			Canadian GAAP		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.

PAGE 5

(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

PAGE 7

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

PAGE 8

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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Document D

Form 40-F

Management’s Discussion and Analysis

February 18, 2009

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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1. Financial Summary

1.1 Financial Position

1.2 Financial Performance

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.

	Husky common shares		S&P/ TSX energy index		S&P/TSX composite index
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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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;

PAGE 4

• 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 theSeaRose 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

TheWest 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

PAGE 9

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, CO₂ injection began at the Company’s second cold solvent pilot project. This pilot project is designed to test oil recovery and production rates utilizing CO₂ and 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;

PAGE 10

• 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

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

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	2008 Average		Increase		Effect on Pre-tax Cash 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 and Eliminations			Total
($ millions)			Upgrading		Infrastructure and Marketing		Canadian Refined Products		U.S. Refining and Marketing
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

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.

PAGE 17

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	Guidance 2009	Year ended December 31 2008	Original Guidance 2008
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.

PAGE 18

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.

PAGE 19

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

PAGE 20

(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

PAGE 21

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

PAGE 22

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.

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 atwww.sedar.com or Husky’s Form 40-F available atwww.sec.gov or on the Company’s website atwww.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

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.

PAGE 24

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.

Note: Based on year end prices.

PAGE 25

Reconciliation of Proved Reserves

(constant prices and costs before royalties)	Canada												International
	Western Canada										East Coast					Total
	Light Crude Oil & NGL		Medium Crude Oil		Heavy Crude Oil		Bitumen		Natural Gas		Light Crude Oil		Light Crude Oil		Natural Gas	Crude Oil & NGL		Natural Gas		Equivalent Units
	(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

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 and costs before royalties)	Canada						International
	Western Canada					East Coast			Total
	Light Crude Oil & NGL	Medium Crude Oil	Heavy Crude Oil	Bitumen	Natural Gas	Light Crude Oil	Light Crude Oil	Natural Gas	Crude Oil & NGL	Natural Gas	Equivalent Units
	(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 costs before royalties)	Canada												International		Total
	Western Canada										East Coast
	Light Crude Oil & NGL		Medium Crude Oil		Heavy Crude Oil		Bitumen		Natural Gas		Light Crude Oil		Light Crude Oil		Crude Oil & NGL		Natural Gas		Equivalent Units
	(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

PAGE 27

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 and costs before royalties)	Canada						International
	Western Canada					East Coast		Total
	Light Crude Oil & NGL	Medium Crude Oil	Heavy Crude Oil	Bitumen	Natural Gas	Light Crude Oil	Light Crude Oil	Crude Oil & NGL	Natural Gas	Equivalent Units
	(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

PAGE 28

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.

PAGE 29

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.

PAGE 37

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 websitewww.sedar.com and the EDGAR websitewww.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 atwww.sedar.com, atwww.sec.gov andwww.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 atwww.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.

PAGE 52

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.

PAGE 53

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.

PAGE 54

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.

PAGE 55

	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.

PAGE 56

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.

PAGE 57

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).