##### Table of Contents



2006
   United States
 Securities and Exchange
    Commission
 Washington, D.C.
    20549
  Form 40-F
  o
    Registration Statement pursuant to section 12 of the
    Securities Exchange Act of 1934þ
    Annual report pursuant to section 13(a) or 15(d) of the
    Securities Exchange Act of 1934  For the
    fiscal year ended December 31, 2006
    Commission
    File Number: 001-04307  Husky
    Energy Inc.
 (Exact name of Registrant as
    specified in its charter)
  Alberta, Canada(Province or other
    jurisdiction of
    incorporation or organization)

1311(Primary Standard
    Industrial
    Classification Code Numbers)

Not Applicable(I.R.S. Employer
    Identification Number
    (if applicable))   707-8th 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:
  Form 40-F,
 Form 6-K
   For annual reports, indicate by check mark the information
    filed with this Form:
  þ Annual
    information form

þ Audited
    annual financial statements      Common
    Shares were outstanding as of December 31, 2006
  Rule 12g3-2(b)
  Yes o


No þ     Yes þ


No o   Form 40-F No. 333-137211.




---



##### Table of Contents



Principal
    Documents
  Form 40-F:
  A.
    Annual
    Information Form  Form 40-F.
  B.
    Audited
    Annual Financial Statements  Form 40-F.
  C.
    Managements
    Discussion and Analysis  Form 40-F.
  Controls
    and Procedures
  Form 40-F.
  Audit
    Committee Financial Expert
  Form 40-F) Form 40-F, Form 40-F.
  Code
    of Business Conduct and Ethics
    i.
    amends any provision of its Code of Business Conduct that
    applies to the Registrants 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, orii.
    grants a waiver, including an implicit waiver, from a provision
    of its Code of Business Conduct to any of Huskys 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 as enumerated in paragraph (9)(b) of General
    Instruction B to
    Form 40-F,    Principal
    Accountant Fees and Services
  Form 40-F.
  Off-balance
    Sheet Arrangements
  Form 40-F.
 ii




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##### Table of Contents



Disclosure
    of Contractual Obligations
  Form 40-F.
  UNDERTAKING
    AND CONSENT TO SERVICE OF PROCESS
  Undertaking
  Form 40-F; Form 40-F
  Consent
    to Service of Process
  Forms F-X Forms F-9
  Form F-X
  SIGNATURES
  Form 40-F
    Husky Energy Inc.
  By:
    /s/  John
    C.S. Lau   Title:
    President & Chief Executive Officer  By:
    /s/  James
    D. Girgulis   Title:
    Vice President, Legal & Corporate Secretary iii




---



##### Table of Contents



Document
    AForm 40-F
     ANNUAL
    INFORMATION FORM
  For the Year Ended December 31, 2006




---



##### Table of Contents



Husky
    Energy Inc.
  Annual Information
    Form
  For the Year Ended
    December 31, 2006
  March 13, 2007




---



##### 



TABLE OF
    CONTENTS
  
  PageExchange Rate
    Information


2Disclosure of
    Exemption Under National Instrument 51-101


2Corporate
    Structure


3Intercorporate
    Relationships


4General
    Development of Husky


4Three Year History
    of Husky


4Subsequent
    Events


5Events expected to
    occur during 2007


5Business
    Environment Trends


5Description of
    Huskys Business


6General


6Upstream
    Operations


6Midstream
    Operations


7Refined
    Products


7Social and
    Environmental Policy


7Risk
    Factors


8Upstream
    Operations


10Disclosures of Oil
    and Gas Activities


10Oil and Gas
    Reserves Disclosures


20Statement of
    Financial Accounting Standards No. 69


25Description of
    Major Properties and Facilities


30Distribution of
    Oil and Gas Production


47Midstream
    Operations


47Refined
    Products


50Human
    Resources


54Dividends


55Description of
    Capital Structure


55Market for
    Securities


57Directors and
    Officers


57Audit
    Committee


61Legal
    Proceedings


62Interest of
    Management and Others in Material Transactions


62Transfer Agent
    and Registrars


62Interests of
    Experts


62Additional
    Information


63Abbreviations
    and Glossary of Terms


64Special
    Note Regarding Forward-looking Statements


69Schedules


71A  Audit
    Committee Charter


71B 
    Report on Reserves Data by Qualified Reserves
    Evaluator


75C 
    Report of Management and Directors on Reserves Data and Other
    Information


77D 
    Independent Engineers Audit Opinion


79Consent of KPMGConsent of McDaniel and Associates Consultants Ltd.Certification of CEO Pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934Certification of the CFO Pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934Certification of the CEO 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)Certification of the CFO 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)       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.
  Refer to page 69 Special Note Regarding
    Forward-Looking Statements.
 1




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##### Table of Contents



EXCHANGE
    RATE INFORMATION    Year ended December 312006


2005


2004Year end


1.165



1.166



1.203Low


1.095



1.151



1.178High


1.179



1.210



1.397Average


1.134



1.211



1.302       (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    
    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 paragraph .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).      Notice 51-315 Instrument 51-101 Standards of Disclosure for Oil and Gas
    Activities.
 2




---



##### Table of Contents



www.sedar.com www.sec.gov
 CORPORATE
    STRUCTURE  Husky
    Energy Inc.
  Business Corporations Act Business Corporations Act Business
    Corporations Act
     3




---



##### Table of Contents



INTERCORPORATE
    RELATIONSHIPS    Name

JurisdictionSubsidiaries of Husky Energy
    Inc.Husky Oil Operations Limited

Nova ScotiaSubsidiaries of Husky Oil
    Operations LimitedHusky Oil Limited

Nova ScotiaHusky Energy Marketing Inc.

AlbertaHusky (U.S.A.) Inc.

DelawareHOI Resources Co.

Nova ScotiaCanterra Resources Canada Ltd.
    (formerly 147212 Canada Ltd.)

CanadaSubsidiaries of Husky (U.S.A.)
    Inc.Husky Gas Marketing Inc.

DelawareSubsidiaries of HOI Resources
    Co.Husky Energy International
    Corporation

British ColumbiaSubsidiaries of Husky Energy
    International CorporationHusky Oil China Ltd.

AlbertaHusky Oil (Madura) Ltd.

British Virgin IslandsHusky Oil Overseas Ltd.

Alberta  GENERAL
    DEVELOPMENT OF HUSKY Three
    Year History of Husky  2004
      29/26
      2005
     4




---



##### Table of Contents



2006
                Block 29/06
           Subsequent
    Events   Events
    expected to occur during 2007   5




---



##### Table of Contents



BUSINESS
    ENVIRONMENT TRENDS  (1) (1)
        (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. DESCRIPTION
    OF HUSKYS BUSINESS General           Upstream
    Operations   6




---



##### Table of Contents



Reserves
    and Land Position
    Properties
               Midstream
    Operations   Refined
    Products   7




---



##### Table of Contents



SOCIAL
    AND ENVIRONMENTAL POLICY   RISK
    FACTORS    Adequacy
    of crude oil and natural gas prices
        Demand
    for Huskys other products and services and the cost of
    required inputs
    Huskys
    ability to replace reserves
    Competition
    Huskys
    operations are susceptible to business interruption
   8




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##### Table of Contents



Foreign
    Exchange Risk
    Environmental
    risks
    clean-up
      Uncertainty
    of oil and gas proved reserves estimates
   9




---



##### Table of Contents



UPSTREAM
    OPERATIONS Disclosures
    of Oil and Gas Activities    Production
 2006Western


EastTotal


Canada


Coast


Canada


China


LibyaCrude Oil(mbbls/day)Light crude oil and NGL


111.0



30.3



68.5



98.8



12.1



0.1Medium crude oil


28.5



28.5







28.5







Heavy crude oil


108.1



108.1







108.1







Total gross


247.6



166.9



68.5



235.4



12.1



0.1Total net


220.4



143.8



66.5



210.3



10.0



0.1Natural Gas(mmcf/day)Gross


672.3



672.3







672.3







Net


528.2



528.2







528.2







   2005Western


EastTotal


Canada


Coast


Canada


China


LibyaCrude Oil(mbbls/day)Light crude oil and NGL


64.6



31.3



17.2



48.5



16.0



0.1Medium crude oil


31.1



31.1







31.1







Heavy crude oil


106.0



106.0







106.0







Total gross


201.7



168.4



17.2



185.6



16.0



0.1Total net


175.7



146.0



15.1



161.1



14.5



0.1Natural Gas(mmcf/day)Gross


680.0



680.0







680.0







Net


488.5



488.5







488.5







   10




---



##### Table of Contents



Production (continued)
  2004Western


EastTotal


Canada


Coast


Canada


China


LibyaCrude Oil(mbbls/day)Light crude oil and NGL


66.2



32.7



13.7



46.4



19.7



0.1Medium crude oil


35.0



35.0







35.0







Heavy crude oil


108.9



108.9







108.9







Total gross


210.1



176.6



13.7



190.3



19.7



0.1Total net


183.9



153.0



13.2



166.2



17.6



0.1Natural Gas(mmcf/day)Gross


689.2



689.2







689.2







Net


524.0



524.0







524.0







       (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.  Revenue
 2006Western


EastTotal


Canada


Coast


Canada


China


Libya($ millions)Crude OilLight crude oil and NGL


2,799



691



1,779



2,470



324



5Medium crude oil


515



515







515







Heavy crude oil


1,575



1,575







1,575







Total gross


4,889



2,781



1,779



4,560



324



5Total net


4,357



2,352



1,731



4,083



270



5Natural GasGross


1,601



1,601







1,601







Net


1,319



1,319







1,319







Processing/Transportation


96



69



27



96







   2005Western


EastTotal


Canada


Coast


Canada


China


Libya($ millions)Crude OilLight crude oil and NGL


1,450



686



392



1,078



369



3Medium crude oil


493



493







493







Heavy crude oil


1,203



1,203







1,203







Total gross


3,146



2,382



392



2,774



369



3Total net


2,713



2,020



355



2,375



335



3Natural GasGross


2,000



2,000







2,000







Net


1,594



1,594







1,594







Processing/Transportation


61



58



3



61







   11




---



##### Table of Contents



Revenue (continued)
  2004Western


EastTotal


Canada


Coast


Canada


China


Libya($ millions)Crude OilLight crude oil and NGL


967



474



148



622



343



2Medium crude oil


462



462







462







Heavy crude oil


757



757







757







Total gross


2,186



1,693



148



1,841



343



2Total net


1,824



1,375



139



1,514



308



2Natural GasGross


1,596



1,596







1,596







Net


1,248



1,248







1,248







Processing/Transportation


48



48







48







    Sales
    Prices
  2006Western


EastTotal


Canada


Coast


Canada


China


LibyaCrude Oil($/bbl)Light crude oil and NGL


69.06



62.46



71.18



68.50



73.58



74.96Medium crude oil


49.48



49.48







49.48







Heavy crude oil


39.92



39.92







39.92







Total crude oil and NGL


54.08



45.64



71.18



53.07



73.58



74.96Natural Gas($/mcf)


6.47



6.47







6.47







   2005Western


EastTotal


Canada


Coast


Canada


China


LibyaCrude Oil($/bbl)Light crude oil and NGL


61.56



60.15



62.61



61.02



63.15



69.23Medium crude oil


43.44



43.44







43.44







Heavy crude oil


31.09



31.09







31.09







Total crude oil and NGL


42.75



38.77



62.61



40.97



63.15



69.23Natural Gas($/mcf)


7.96



7.96







7.96







   2004Western


EastTotal


Canada


Coast


Canada


China


LibyaCrude Oil($/bbl)Light crude oil and NGL


48.34



49.35



47.87



49.64



47.66



57.88Medium crude oil


36.13



36.13







36.13







Heavy crude oil


28.66



28.66







28.66







Total crude oil and NGL (before
    hedging)


36.07



33.85



47.87



34.90



47.66



57.88Total crude oil and NGL (after
    hedging)


28.43



26.19



29.45



26.42



47.66



57.88Natural Gas($/mcf)Before hedging


6.25



6.25







6.25







After hedging


6.24



6.24







6.24







   12




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##### Table of Contents



Capital
    Expenditures
 2006Western


EastTotal


Canada


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



1,646



14



5



12,633



2,171



359



2,536



85



11



1   2005Western


EastTotal


Canada


Coast


Canada


China


Indonesia


Libya($ millions)Property acquisition


133



133







133











Exploration


445



324



66



390



55







Development


2,152



1,550



579



2,129



14



8



12,730



2,007



645



2,652



69



8



1   2004Western


EastTotal


Canada


Coast


Canada


China


Indonesia


Libya($ millions)Property
    acquisition(1)


116



54







54







62



Exploration


313



271



24



295



18







Development


1,728



1,208



515



1,723



5







2,157



1,533



539



2,072



23



62



       (1)
    Does not include the acquisition of Temple Exploration Inc. 13




---



##### Table of Contents



Oil
    and Gas
    Netbacks (1)
  2006Western


EastTotal


Canada


Coast


Canada


China


LibyaCrude Oil($/bbl)Light crude
    oilSales revenue


68.51



59.89



71.18



67.87



73.58



74.96Royalties


4.49



7.34



1.95



3.52



12.33



Operating costs


6.96



11.89



5.48



7.36



3.61



18.51Netback


57.06



40.66



63.75



56.99



57.64



56.45Medium crude
    oilSales revenue


48.97



48.97







48.97







Royalties


8.61



8.61







8.61







Operating costs


13.09



13.09







13.09







Net back


27.27



27.27







27.27







Heavy crude
    oilSales 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
    oilSales revenue


53.55



44.90



71.18



52.51



73.58



74.91Royalties


5.28



6.14



1.95



4.92



12.33



Operating costs


9.53



11.60



5.48



9.83



3.61



18.51Netback


38.74



27.16



63.75



37.76



57.64



56.45Natural 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



74.91Royalties


6.19



6.97



1.95



5.99



12.33



Operating costs


8.77



9.79



5.48



8.98



3.61



18.51Netback


34.38



26.15



63.75



33.61



57.64



56.45       (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. 14




---



##### Table of Contents



Oil and Gas
    Netbacks (1) (continued)
  2005Western


EastTotal


Canada


Coast


Canada


China


LibyaCrude Oil($/bbl)Light crude
    oilSales revenue


61.86



60.74



62.61



61.41



63.15



69.23Royalties


7.22



8.66



5.91



7.67



5.93



Operating costs


6.88



9.86



5.14



8.16



2.92



22.73Netback


47.76



42.22



51.56



45.58



54.30



46.50Medium crude
    oilSales revenue


43.67



43.67







43.67







Royalties


7.77



7.77







7.77







Operating costs


10.97



10.97







10.97







Net back


24.93



24.93







24.93







Heavy crude
    oilSales revenue


31.22



31.22







31.22







Royalties


3.75



3.75







3.75







Operating costs


9.90



9.90







9.90







Netback


17.57



17.57







17.57







Total crude
    oilSales revenue


42.83



38.91



62.61



41.08



63.15



69.23Royalties


5.49



5.41



5.91



5.45



5.93



Operating costs


9.13



10.10



5.14



9.65



2.92



22.73Netback


28.21



23.40



51.56



25.98



54.30



46.50Natural Gas($/mcf)Sales revenue


8.02



8.02







8.02







Royalties


1.76



1.76







1.76







Operating costs


1.04



1.04







1.04







Netback


5.22



5.22







5.22







Equivalent Unit($boe)Sales revenue


44.56



42.53



62.61



43.69



63.15



69.23Royalties


7.29



7.45



5.91



7.36



5.93



Operating costs


8.12



8.59



5.14



8.39



2.92



22.73Netback


29.15



26.49



51.56



27.94



54.30



46.50       (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.  15




---



##### Table of Contents



Oil and Gas
    Netbacks (1) (continued)
  2004Western


EastTotal


Canada


Coast


Canada


China


LibyaCrude Oil($/bbl)Light crude
    oilSales revenue


46.95



46.12



47.87



46.63



47.66



57.88Royalties


5.71



7.76



1.80



6.03



4.91



Operating costs


5.82



8.94



3.28



7.29



2.16



16.47Netback before hedging


35.42



29.42



42.79



33.31



40.59



41.41Medium crude
    oilSales revenue


36.20



36.20







36.20







Royalties


6.10



6.10







6.10







Operating costs


10.07



10.07







10.07







Netback before hedging


20.03



20.03







20.03







Heavy crude
    oilSales revenue


28.73



28.73







28.73







Royalties


3.38



3.38







3.38







Operating costs


9.33



9.33







9.33







Netback before hedging


16.02



16.02







16.02







Total crude
    oilSales revenue


35.72



33.48



47.87



34.50



47.66



57.88Royalties


4.58



4.75



1.80



4.54



4.91



Operating costs


8.36



9.41



3.28



8.97



2.16



16.47Netback before hedging


22.78



19.32



42.79



20.99



40.59



41.41Netback after hedging


15.64



12.25



24.37



13.11



40.59



41.41Natural Gas($/mcf)Sales revenue


6.25



6.25







6.25







Royalties


1.44



1.44







1.44







Operating costs


0.89



0.89







0.89







Netback before hedging


3.92



3.92







3.92







Netback after hedging


3.91



3.91







3.91







Equivalent Unit($boe)Sales revenue


36.34



35.01



47.87



35.60



47.66



57.88Royalties


5.96



6.22



1.80



6.03



4.91



Operating costs


7.32



7.85



3.28



7.66



2.16



16.47Netback


23.06



20.94



42.79



21.91



40.59



41.41       (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.  16




---



##### Table of Contents



Producing
    Wells
  Oil Wells


Natural Gas Wells


TotalGross(1)(2)


Net(1)


Gross(1)(2)


Net(1)


Gross(1)(2)


Net(1)CanadaAlberta


4,390



3,395



5,385



4,235



9,775



7,630Saskatchewan


5,076



4,118



1,084



1,028



6,160



5,146British Columbia


203



57



219



150



422



207Newfoundland


21



6











21



6North West Territories


5



1



5



1



10



29,695



7,577



6,693



5,414



16,388



12,991InternationalChina


27



11











27



11Libya


2



1











2



129



12











29



12As at December 31,
    2006


9,724



7,589



6,693



5,414



16,417



13,003CanadaAlberta


4,308



3,341



4,658



3,794



8,966



7,135Saskatchewan


4,567



3,644



922



826



5,489



4,470British Columbia


224



78



183



122



407



200Manitoba


17



4











17



4Newfoundland


5



1



5



1



10



2Northwest Territories


9,121



7,068



5,768



4,743



14,889



11,811InternationalChina


24



10











24



10Libya


2



1











2



126



11











26



11As at December 31,
    2005


9,147



7,079



5,768



4,743



14,915



11,822       (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, 2006 Husky had a royalty interest in
    4,047 wells of which 1,605 were oil producers and 2,442
    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 2006, there were 210 gross, 188 net oil
    wells and 416 gross, 353 net natural gas wells which
    were completed in two or more formations and from which
    production is not commingled.  17




---



##### Table of Contents



Landholdings
  Developed
    Acreage
  Gross


Net(thousands of acres)As at December 31,
    2006Western CanadaAlberta


3,235



2,709Saskatchewan


592



531British Columbia


185



114Manitoba






4,012



3,354Northwest Territories and
    Arctic


7



1Eastern Canada


35



44,054



3,359China


17



7Libya


7



24,078



3,368As at December 31,
    2005Western CanadaAlberta


3,146



2,633Saskatchewan


577



517British Columbia


182



112Manitoba






3,905



3,262Northwest Territories and
    Arctic


7



1Eastern Canada


35



43,947



3,267China


17



7Libya


7



23,971



3,276   Undeveloped
    Acreage
  Gross


Net(thousands of acres)As at December 31,
    2006Western CanadaAlberta


4,358



3,841Saskatchewan


1,654



1,513British Columbia


906



639Manitoba


1



16,919



5,994Northwest Territories and
    Arctic


884



239Eastern Canada


2,591



1,78610,394



8,019China


7,637



3,742Indonesia


1,742



1,74219,773



13,503 18




---



##### Table of Contents



Gross


Net(thousands of acres)Landholdings (continued)Undeveloped
    AcreageAs at December 31,
    2005Western CanadaAlberta


4,518



3,998Saskatchewan


1,715



1,577British Columbia


862



615Manitoba


2



27,097



6,192Northwest Territories and
    Arctic


664



180Eastern Canada


3,722



2,92711,483



9,299China


5,590



2,739Indonesia


690



69017,763



12,728    Drilling
    Activity
  Year ended December 312006


2005


2004Gross


Net


Gross


Net


Gross


NetWestern Canada
    DrillingExplorationOil


101



99



89



85



45



39Gas


330



192



392



196



234



180Dry


26



24



36



36



34



33457



315



517



317



313



252DevelopmentOil


590



543



466



433



552



499Gas


565



490



610



551



807



740Dry


25



22



42



39



57



531,180



1,055



1,118



1,023



1,416



1,2921,637



1,370



1,635



1,340



1,729



1,544   Present
    Activities
  Exploratory


DevelopmentGross


Net


Gross


NetWells
    Drilling(1)Western Canada


8



7



14



13East Coast










2



18



7



16



14       (1)
    Denotes wells that were drilling at December 31, 2006. 19




---



##### Table of Contents



Oil and
    Gas Reserves Disclosures    Audit
    of Oil and Gas Reserves
    Proved
    Reserves
  Future Net CashFlows BeforeCrude Oil &
    NGL(1)


Natural
    Gas(1)


Tax(1)(4)Gross(2)


Net(2)


Gross(2)


Net(2)


0%


10%(mmbbls)


(bcf)


($ millions)Proved
    developed(3)


518



454



1,703



1,424



20,135



13,158Proved
    undeveloped(3)(5)


129



113



440



375



3,293



1,668Proved
    total(3)


647



567



2,143



1,799



23,428



14,826       (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)
    The discounted future net cash flows at December 31, 2006
    were based on the year-end spot NYMEX natural gas price of
    U.S. $5.51/mmbtu and on a spot WTI crude oil price of
    U.S. $60.85/bbl.(5)
    Estimated future capital expenditures required to gain access to
    proved undeveloped reserves as at December 31, 2006 and
    2005 were as follows:  As at December 31, 2006Total


2007


2008


2009


2010


2011


Thereafter($ millions undiscounted)Western Canada


1,725



558



573



263



100



96



135Eastern Canada


























1,725



558



573



263



100



96



135   As at December 31, 2005Total


2006


2007


2008


2009


2010


ThereafterWestern Canada


1,428



545



353



191



116



56



167Eastern Canada


109



87



















221,537



632



353



191



116



56



189   (6)
    On December 31, 2006, the date our oil and gas reserves
    were evaluated, the calculated price of Lloydminster heavy crude
    oil was $39.17 per barrel. Our heavy crude oil reserves
    were economic at that price and no negative price revision
    resulted. 20




---



##### Table of Contents



Reconciliation
    of Proved Gross Reserves
  Canada


International


TotalEastWestern Canada


Coast








LightProved reserves,

Light Crude


Medium


Heavy


Natural





Light


Crude Oil


Natural


Crude Oil


Naturalbefore
    royalties(1)

Oil & NGL


Crude Oil


Crude Oil


Gas


Bitumen


Crude Oil


& NGL


Gas


& NGL


Gas(mmbbls)


(mmbbls)


(mmbbls)


(bcf)


(mmbbls)


(mmbbls)


(mmbbls)


(bcf)


(mmbbls)


(bcf)End of 2003


173



94



227



2,059







26



24







544



2,059Revisions


1



1



(114
)


(23
)






(1
)


3







(110
)


(23
)Purchases


1











23



















1



23Sales










(1
)


(14
)


















(1
)


(14
)Discoveries and extensions


7



2



32



372







24











65



372Improved recovery


1



2



1



4







3











7



4Production


(12
)


(13
)


(40
)


(252
)






(5
)


(7
)






(77
)


(252
)End of 2004


171



86



105



2,169







47



20







429



2,169Revisions


3



9



121



(65
)






9



2







144



(65
)Purchases










7



3



















7



3Sales






(3
)


(4
)


(9
)


















(7
)


(9
)Discoveries and extensions


4



3



27



277



48



16



1







99



277Improved recovery


1



7







9







23











31



9Production


(12
)


(11
)


(39
)


(248
)






(6
)


(6
)






(74
)


(248
)End of 2005


167



91



217



2,136



48



89



17







629



2,136Revisions


(3
)


(1
)


(2
)


(87
)


(1
)


31



2







26



(87
)Purchases


1



1







25



















2



25Sales


(1
)










(3
)


















(1
)


(3
)Discoveries and extensions


7



5



37



314



13















62



314Improved recovery


6



1







3







12











19



3Production


(11
)


(10
)


(39
)


(245
)






(25
)


(5
)






(90
)


(245
)End of 2006


166



87



213



2,143



60



107



14







647



2,143       (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. 21




---



##### Table of Contents



Reserves
    and Production by Principal Area
  GrossCrude Oil and
    NGL(1)

Proved Reserves


Production(mmbbls)


(mbbls/day)CanadaWestern CanadaBritish Columbia and
    FoothillsAlberta and BC Plains area


29.9



5.9Foothills Deep Gas area


28.2



6.1Ram River and Kaybob areas


6.2



2.4Northwest Alberta
    PlainsRainbow Lake area


78.3



7.6Peace River Arch area


12.4



3.3East Central AlbertaNorth area


2.3



0.6South area


6.8



2.2Provost area


29.4



14.3Southern Alberta and
    SaskatchewanSouth Alberta area


24.0



8.2South Saskatchewan area


63.9



15.9Lloydminster AreaPrimary production


116.1



80.1Thermal production


68.7



19.6Oil Sands


60.1



0.0Other


0.1



0.7526.4



166.9East Coast CanadaTerra Nova


21.2



4.7White Rose


85.8



63.8107.0



68.5ChinaWenchang


13.3



12.1Other


0.3



0.1647.0



247.6       (1)
    Gross crude oil and NGL reserves as at December 31, 2006
    and average 2006 daily gross production of crude oil and
    NGL. 22




---



##### Table of Contents



GrossNatural
    Gas(1)

Proved Reserves


Production(bcf)


(mmcf/day)CanadaWestern CanadaBritish Columbia and
    FoothillsAlberta and BC Plains area


147.6



55.5Foothills Deep Gas area


336.9



92.1Ram River and Kaybob areas


245.5



73.3Northwest Alberta
    PlainsRainbow Lake area


446.4



89.0Peace River Arch


126.0



41.8Northern Alberta area


39.5



21.1East Central AlbertaProvost area


74.2



24.2North area


197.1



51.3South area


222.1



74.4Southern Alberta and
    SaskatchewanSouth Alberta area


47.9



25.5South Saskatchewan area


186.4



65.5Lloydminster Area


73.2



50.5Other






8.12,142.8



672.3       (1)
    Gross natural gas reserves as at December 31, 2006 and
    average 2006 daily gross production of natural gas. 23




---



##### Table of Contents



Probable
    Oil and Gas
    Reserves (1)
  Crude Oil
    & NGL
  CanadaWestern CanadaConventional


Bitumen


East Coast


International


Total(mmbbls)2006


144



1,127



79



9



1,3592005


146



903



118



13



1,1802004


113



79



156



13



361   Natural
    Gas
  CanadaWestern CanadaConventional


International


Total(bcf)2006


390



93



4832005


407



167



5742004


388



167



555   Barrels
    of Oil Equivalent
  CanadaWestern CanadaConventional


Bitumen


East Coast


International


Total(mmboe)2006


209



1,127



79



25



1,4402005


213



903



118



41



1,2752004


177



79



156



41



453       (1)
    The probable reserves presented have been prepared, using
    constant prices and costs, in accordance with NI 51-101.(2)
    Bitumen reserves were based on constant prices calculated in
    accordance with the Canadian Securities Administrators 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 (the
    Staff Notice). Bitumen reserves at December 31,
    2004 remain classified as probable reserves because the pricing
    formula in the Staff Notice results in an economically viable
    price as at that date whereas 37 mmbbls of heavy oil reserves
    were subtracted from probable reserves due to low
    December 31, 2004 heavy oil prices under the constant
    pricing calculation applicable to heavy oil, which differed from
    the bitumen calculation. See Disclosure of Exemption under
    National Instrument 51-101 for further discussion.(3)
    Proved and probable bitumen reserves are included under the
    caption Western Canada.(4)
    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 certain undertakings made in an exemption order
    granted to Husky pursuant to Part 8 of the Companion Policy
    to NI 51-101. 24




---



##### Table of Contents



Statement
    of Financial Accounting Standards No. 69 
    Disclosure about Oil and Gas Producing Activities    Oil
    and Gas Reserves
            Results
    of Operations for Producing Activities
  Results of operations for

Canada


International


Totalproducing
    activities(1)(2)

2006


2005


2004


2006


2005


2004


2006


2005


2004($ millions except per boe amounts)Oil and gas production revenue


5,567



4,085



2,866



274



337



310



5,841



4,422



3,176Operating costsLease operating expenses


1,215



925



874



22



18



17



1,237



943



891Production taxes


69



56



56















69



56



56Asset retirement obligation
    accretion


37



28



23















37



28



231,321



1,009



953



22



18



17



1,343



1,027



970Depreciation, depletion and
    amortization


1,426



1,102



1,018



50



42



59



1,476



1,144



1,077Earnings before taxes


2,820



1,974



895



202



277



234



3,022



2,251



1,129Income tax


982



730



349



72



106



92



1,054



836



441Results of operations


1,838



1,244



546



130



171



142



1,968



1,415



688Amortization rate per gross boe


11.24



10.10



9.11



11.24



7.21



8.19



11.24



9.95



9.06Amortization rate per net boe


13.09



12.45



10.97



13.50



7.96



9.13



13.10



12.19



10.85       (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 2006 amounted to
    $1,362 million (2005  $1,036 million;
    2004  $981 million). Income taxes for Canadian
    producing activities under U.S. GAAP for 2006 amounted to
    $1,005 million (2005  $755 million;
    2004  $364 million). 25




---



##### Table of Contents



Costs
    Incurred in Oil and Gas Property Acquisition, Exploration and
    Development Activities
  Canada


International


Total($ millions)2006Property acquisitionProved


97







97Unproved


96







96Exploration


697



77



774Development


1,637



20



1,657Capitalized interest


23







23Total costs
    incurred(1)


2,550



97



2,647Less: Proved acquisitions


97







97Capitalized interest


23







23Finding and development costs


2,430



97



2,527Note:(1) Asset retirement
    obligation incurred


45







452005Property acquisitionProved


68







68Unproved


65







65Exploration


390



55



445Development


2,042



23



2,065Capitalized interest


112







112Total costs
    incurred(1)


2,677



78



2,755Less: Proved acquisitions


68







68Capitalized interest


112







112Finding and development costs


2,497



78



2,575Note:(1) Asset retirement
    obligation incurred


51







512004Property acquisitionProved(2)


101







101Unproved(3)


91



62



153Exploration


295



18



313Development


1,712



4



1,716Capitalized interest


75







75Total costs
    incurred(3)


2,274



84



2,358Less: Proved acquisitions


101







101Capitalized interest


75







75Finding and development costs


2,098



84



2,182Notes:(1) Corporate acquisitions


98







98(2) Corporate acquisitions


40







40(3) Asset retirement
    obligation incurred


90



(1
)


89      26




---



##### Table of Contents



Prior toWithheld Costs

Total


2006


2005


2004


2004($ millions)Property acquisitionsCanada


154



97



57



International


63











63217



97



57



63ExplorationCanada


798



398



288



30



82International


70



70











868



468



288



30



82DevelopmentCanada


881



478



399



4



International


33



5



6







22914



483



405



4



22Capitalized interestCanada


98



58



39



12,097



1,106



789



98



104   Capitalized
    Costs Relating to Oil and Gas Producing Activities
  Canada


International


Total($ millions)2006Proved properties


19,087



586



19,673Unproved properties


1,932



165



2,09721,019



751



21,770Accumulated DD&A


8,141



404



8,545Net Capitalized
    Costs(1)


12,878



347



13,2252005Proved properties


16,195



528



16,723Unproved properties


2,317



127



2,44418,512



655



19,167Accumulated DD&A


6,729



354



7,083Net Capitalized
    Costs(1)


11,783



301



12,0842004Proved properties


13,624



458



14,082Unproved properties


2,399



129



2,52816,023



587



16,610Accumulated DD&A


5,722



311



6,033Net Capitalized
    Costs(1)


10,301



276



10,577       (1)
    The net capitalized costs for Canadian oil and gas exploration,
    development and producing activities under U.S. GAAP for 2006
    was $12,449 million (2005  $11,290 million,
    2004  $9,721 million). The net capitalized costs
    for International property oil and gas exploration, 27




---



##### Table of Contents



development and producing
    activities under U.S. GAAP for 2006 was $346 million (2005
     $300 million, 2004  $274 million).
    Please refer to note 19 to the Consolidated Financial
    Statements for an explanation of the differences between
    Canadian and U.S. GAAP for oil and gas activities.  Oil
    and Gas Reserve Information
    Canada


International


TotalCrude


Natural


Crude


Natural


Crude


NaturalOil & NGL


Gas


Oil & NGL


Gas


Oil & NGL


GasReserves

(mmbbls)


(bcf)


(mmbbls)


(bcf)


(mmbbls)


(bcf)Net proved
    reserves(1)(2)(3)(4)End of year 2003


463



1,717



22







485



1,717Revisions


(105
)


(54
)


2







(103
)


(54
)Purchases


1



17











1



17Sales


(1
)


(12
)










(1
)


(12
)Improved recovery


6



3











6



3Discoveries and extensions


55



309











55



309Production


(62
)


(192
)


(6
)






(68
)


(192
)End of year 2004


357



1,788



18







375



1,788Revisions


129



(75
)


2







131



(75
)Purchases


6



2











6



2Sales


(7
)


(7
)










(7
)


(7
)Improved recovery


29



6











29



6Discoveries and extensions


94



230



1







95



230Production


(59
)


(173
)


(5
)






(64
)


(173
)End of year 2005


549



1,771



16







565



1,771Revisions


9



(71
)










9



(71
)Purchases


2



21











2



21Sales






(2
)














(2
)Improved recovery


16



2











16



2Discoveries and extensions


56



267











56



267Production


(77
)


(189
)


(4
)






(81
)


(189
)End of year 2006


555



1,799



12







567



1,799Net proved developed
    reserves,(1)(2)(3)(4)End of year 2003


372



1,423



23







395



1,423End of year 2004


299



1,436



18







317



1,436End of year 2005


327



1,413



15







342



1,413End of year 2006


442



1,424



12







454



1,424       (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. 28




---



##### Table of Contents



Standardized
    Measure of Discounted Future Net Cash Flows Relating to Proved
    Oil and Gas Reserves
          Canada(1)


International(1)


Total(1)Standardized Measure

2006


2005


2004


2006


2005


2004


2006


2005


2004($ millions)Future cash inflows


37,006



40,066



22,681



900



999



979



37,906



41,065



23,660Future production and development
    costs


14,321



13,430



9,353



157



122



148



14,478



13,552



9,501Future income taxes


6,934



9,000



4,871



234



272



266



7,168



9,272



5,137Future net cash flows


15,751



17,636



8,457



509



605



565



16,260



18,241



9,022Annual 10% discount factor


6,045



7,115



3,712



93



123



105



6,138



7,238



3,817Standardized measure of discountedFuture net cash flows


9,706



10,521



4,745



416



482



460



10,122



11,003



5,205       (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. 29




---



##### Table of Contents



Changes
    in Standardized Measure of Discounted Future Net Cash Flows
    Relating
    to Proved Oil and Gas Reserves
  Canada(1)


International(1)


Total(1)2006


2005


2004


2006


2005


2004


2006


2005


2004($ millions)Present value at January 1


10,521



4,745



5,420



482



460



418



11,003



5,205



5,838Sales and transfers, net of
    production costs


(4,318
)


(3,101
)


(1,952
)


(257
)


(320
)


(294
)


(4,575
)


(3,421
)


(2,246
)Net change in sales and transfer
    prices, net of development and production costs


(1,672
)


5,585



555



126



155



197



(1,546
)


5,740



752Extensions, discoveries and
    improved recovery, net of related costs


1,666



2,027



958







24







1,666



2,051



958Revisions of quantity estimates


553



2,310



(1,318
)


(22
)


110



85



531



2,420



(1,233
)Accretion of discount


1,601



762



877



70



68



61



1,671



830



938Sale of reserves in place


(19
)


(62
)


(20
)














(19
)


(62
)


(20
)Purchase of reserves in place


65



36



45















65



36



45Changes in timing of future net
    cash flows and other


338



826



(233
)


(9
)


(13
)


17



329



813



(216
)Net change in income taxes


971



(2,607
)


413



26



(2
)


(24
)


997



(2,609
)


389Net increase (decrease)


(815
)


5,776



(675
)


(66
)


22



42



(881
)


5,798



(633
)Present value at December 31


9,706



10,521



4,745



416



482



460



10,122



11,003



5,205       (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    Lloydminster
    Heavy Oil and Gas
     30




---



##### Table of Contents



Lloydminster
    Area
  
   British
    Columbia Foothills/Northwest Plains
  Rainbow
    Lake District
    oil-in-place oil-in-place
 31




---



##### Table of Contents



17 mbbls/day
      Slave
    Lake District
    High
    Level District
    Athabasca
    District
    Ram
    River District
       32




---



##### Table of Contents



Kaybob
    District
      Alberta/British
    Columbia Plains District
  Boundary
    Lake Area
    Valhalla
    and Wapiti Area
    Kakwa
    Area
   33




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##### Table of Contents



Lynx,
    Copton and Grande Cache Areas
    Foothills
    West District
  Caroline
    Area
      Edson
    Area
    Sikanni
    and Federal Areas
    Graham
    Area
    East
    Central Alberta
  Athabasca
    District
    Red
    Deer and Hussar Districts
   34




---



##### Table of Contents



Provost
    District
    Southern
    Alberta and Southern Saskatchewan
  Southern
    Saskatchewan District
        Southern
    Alberta District
   35




---



##### Table of Contents



36




---



##### Table of Contents



Oil
    Sands
  Athabasca,
    Cold Lake and Peace River
    Tucker
    Sunrise
        Saleski/Caribou
     37




---



##### Table of Contents



Oil
    Sands Leases
  Oil Sands


Gross


Net


HuskyGeneral Location Name

Area


Acres


Acres


OperatorSouth Athabasca 
    overriding royalty


Athabasca



35,601







NoSouth Athabasca


Athabasca



22,032



11,656



YesSunrise  In
    situ(1)


Athabasca



64,034



64,034



YesMisthae (Drowned, Martin Hills W.
    & Spur)


Athabasca



28,160



28,160



YesSaleski


Athabasca



239,200



239,200



YesHoole  overriding
    royalty


Athabasca



47,040







NoBeaverdam


Cold Lake



11,520



11,520



YesCaribou(2)


Cold Lake



35,840



35,840



YesLobstick


Cold Lake



37,120



37,120



YesTucker(3)


Cold Lake



11,360



11,360



YesPanny (Senex & Welstead)


Peace River



47,360



47,360



YesPeace River (Cadotte Lake)


Peace River



11,840



11,840



YesSawn Lake (Loon)


Peace River



20,480



20,480



Yes612,227



518,570       (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.(3)
    Included in the gross and net amounts are an additional 1,280
    acres of petroleum and natural gas rights held as protection
    acreage for gas over bitumen issues. 38




---



##### Table of Contents



39




---



##### Table of Contents



Offshore
    East Coast  Canada
    White
    Rose Oil Field
              Terra
    Nova Oil Field
     40




---



##### Table of Contents



East
    Coast Exploration
      3-D
 41




---



##### Table of Contents



East
    Coast
  
 42




---



##### Table of Contents



International
    
  South
    China Sea
  Wenchang
   43




---



##### Table of Contents



Block
    39/05
  39/05
  Block
    23/15
  3-D
  Block
    29/26
  2-D 3-D
  Block
    29/06
  3-D 3-D
  Block
    35/18 and 50/14
  50/14 block 3-D
 44




---



##### Table of Contents



East
    China Sea
  Block
    04/35
    East
    Bawean II, Indonesia
  3-D 3-D
  Madura
    Strait, Indonesia
    45




---



##### Table of Contents



46




---



##### Table of Contents



Shatirah,
    Libya
   DISTRIBUTION
    OF OIL AND GAS PRODUCTION  Crude
    Oil and NGL
      Natural
    Gas
    Years ended December 31,2006


2005


2004(mmcf/day)Sales to end usersUnited States


335



357



407Canada


231



212



187566



569



594Sales to aggregators


26



31



34Internal
    use (1)


80



80



61672



680



689       (1)
    Husky consumes natural gas for fuel at several of its facilities.    Delivery
    Commitments
    Fixed Price


Market PriceBcf


$/mmbtu


Bcf2007


20



4.64



472008


19



4.89



242009


19



5.15



82010


19



5.44



12011


19



5.75



2012


19



6.02



2013


18



5.83



2014


10



3.80



  MIDSTREAM
    OPERATIONS  Overview
    
    Upgrading  the upgrading of heavy crude oil into
    synthetic light crude oil; 47




---



##### Table of Contents




    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,
    NGL, sulphur, petroleum coke and electrical power.  Upgrading
    Operations
        Infrastructure
      Years ended December 31,2006


2005


2004(mbbls/day)Combined pipeline throughput


475



474



492        48




---



##### Table of Contents



Heavy Oil
    Pipeline Systems
  
 49




---



##### Table of Contents



Cogeneration
      Natural
    Gas Storage Facilities
    Commodity
    Marketing
         REFINED
    PRODUCTS  Overview
     50




---



##### Table of Contents



Branded
    Petroleum Product Outlets and Commercial
    Distribution
  Distribution
      Branded
    Petroleum Product Outlets
  Branded
    Petroleum Outlets
  
 51




---



##### Table of Contents



BritishColumbia &














2006



2005Retail Owned Outlets

Yukon


Alberta


Sask.


Manitoba


Ontario


Total



TotalTravel Centres


10



8



4



2



13



37




36Full Serve


7



11



2



1



3



24




31Full/Self Serve


21



31



8



13



9



82




61Self Serve


22



12



1



1



5



41




33Bulk Distributor


1



7



3



1



1



13




14Other Service Facilities


2



7



0



1



1



11




1063



76



18



19



32



208




185LeasedTravel Centres


1



0



0



0



0



1




1Full Serve


2



6



3



5



0



16




20Full/Self Serve


30



21



4



4



0



41




46Self Serve


0



21



0



1



0



52




54Bulk Distributor


2



0



0



0



0



2




3Other Service Facilities


2



4



0



3



2



11




1049



52



7



13



2



123




134Independent RetailersTravel Centres


1



1



0



0



4



6




6Full Serve


18



10



6



9



9



52




66Full/Self Serve


18



5



3



1



1



28




29Self Serve


26



41



3



2



1



73




83Bulk Distributor


3



4



2



0



0



6




7Other Service Facilities


1



2



0



0



3



6




5
























67



63



14



12



18



174




196TotalTravel Centres


12



9



4



2



17



44




43Full Serve


27



27



11



15



12



92




117Full/Self Serve


51



57



15



18



10



151




136Self Serve


87



74



4



4



6



166




170Bulk Distributor


6



11



5



1



1



24




24Other Service Facilities


5



13



0



4



6



28




25179



191



39



44



52



505




515Cardlocks(1)


26



18



4



6



21



73




73Convenience
    Stores(1)


183



185



40



44



50



502




479Restaurants


11



13



4



2



16



46




45       (1)
    All of these are located at branded petroleum outlets. 52




---



##### Table of Contents



Years ended December 31,2006


2005


2004(mbbls/day)Gasoline


27.5



28.3



28.3Diesel fuel


26.4



26.5



23.9Liquefied petroleum gas


0.9



0.9



1.154.8



55.7



53.3   Prince
    George Refinery
    Lloydminster
    Asphalt Refinery
    Ethanol
    Manufacturing
        Other
    Supply Arrangements
  20.6 mbbls/day
  Asphalt
    Products
     53




---



##### Table of Contents



28 mbbls/day.
    Years ended December 31,2006


2005


2004(mbbls/day)Asphalt


14.0



13.8



14.0Residual and other


9.4



8.7



8.823.4



22.5



22.8          HUMAN
    RESOURCES    December 31,2006


2005Upstream


2,357



2,172Midstream


375



345Refined Products


480



442Corporate and business support


358



3303,570



3,289  54




---



##### Table of Contents



DIVIDENDS    2006


2005


2004Cash dividends declared per common
    share

$
1.50


$
1.65


$
1.00   Dividend
    Policy and Restrictions
    Business Corporations Act
 DESCRIPTION
    OF CAPITAL STRUCTURE  Common
    Shares
    Preferred
    Shares
   55




---



##### Table of Contents



Credit
    Ratings Summary
  Rating

Last Review

Last Rating ChangeMoodys:Outlook

Stable

August 29, 2005

Senior Unsecured Debt

Baa2

August 29, 2005

April 25, 2001Capital Securities

Ba1

August 29, 2005

April 25, 2001Standard and
    Poors:Outlook

Stable

July 27, 2006

July 27, 2006Senior Unsecured Debt

BBB+

July 27, 2006

July 27, 2006Capital Securities

BBB−

July 27, 2006

July 27, 2006Dominion Bond Rating
    Service:Trend

Stable

September 20, 2006

Senior Unsecured Debt

BBB(high)

September 20, 2006

Capital Securities

BBB

September 20, 2006

Fitch:Senior Unsecured Debt

BBB+

May 5, 2006

Capital Securities

BBB−

May 5, 2006

     Moodys
    Standard
    and Poors
    Dominion
    Bond Rating Service
    Fitch
   56




---



##### Table of Contents



MARKET
    FOR SECURITIES      High


Low


Volume(000s)January


71.56



59.63



12,680February


74.50



65.00



14,628March


73.15



68.92



12,236April


75.64



64.54



10,479May


68.58



58.00



15,243June


71.00



62.40



13,951July


77.94



68.67



8,555August


83.00



74.50



9,450September


77.44



66.31



12,782October


72.98



66.20



17,930November


79.05



70.40



14,428December


80.45



74.92



9,530  DIRECTORS
    AND OFFICERS    Directors
  Name and Residence

Office or Position

Principal Occupation During Past 5 YearsLI, VICTOR T.K.
     Hong Kong

Co-Chairman and Director

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); Executive Director and Chairman of CK Life
    Sciences Intl., (Holdings) Inc. (a biotechnology company)
    and Cheung Kong Infrastructure Holdings Limited
    (an infrastructure development company); Executive Director
    of Hongkong Electric Holdings Limited (a holding company); and a
    director of The Hongkong and Shanghai Banking Corporation
    Limited.Mr. Li is a member of the Standing Committee of the 10th   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 Executive Committee of the Commission on Strategic Development of the Hong Kong Special Administrative Region.FOK, CANNING K.N.
     Hong Kong

Co-Chairman and Director

Mr. Fok is Group Managing Director
    and Executive Director of Hutchison Whampoa Limited. 57




---



##### Table of Contents



Name and Residence

Office or Position

Principal Occupation During Past 5 YearsMr. Fok is also a director and
    Chairman of Hutchison Telecommunications International Limited
    (a public investment holding company), Hutchison Harbour
    Ring Limited (an investment holding company),
    Hutchison Telecommunications (Australia) Limited
    (a telecommunications company), Partner Communications
    Company Ltd. (a telecommunications company) and Hongkong
    Electric Holdings Limited; Deputy Chairman and a director of
    Cheung Kong Infrastructure Holdings Limited; and a director of
    Cheung Kong (Holdings) Limited. Mr. Fok was also a Non Executive
    Director of Panvas Gas Holdings Limited from
    2002  2006 and a director of Hanny Holdings
    Limited from 1992  2005.FULLERTON, R. DONALD
     Toronto, Ontario, Canada

Director

Mr. Fullerton is retired and
    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; CIBC from
    1974 to 2004; Hollinger Inc. from 1992 to 2003; and Westcoast
    Energy Inc. from 1993 to 2003.GLYNN, MARTIN J.G.
     St. Andrews, Scotland

Director

Mr. Glynn was a director of HSBC
    Bank USA N.A. from 2000 and President and Chief Executive
    Officer 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.KINNEY, BRENT D.
     Dubai, United Arab Emirates

Director

Mr. Kinney is a director and Chief
    Executive Officer of Sky Petroleum Inc. (a public petroleum
    company).Mr. Kinney is also a director of Dragon Oil plc, Western Cooper Corporation (a mineral exploration company) and Benchmark Energy Ltd. (an oil and gas exploration company). Mr. Kinney was also a director of Aurado Energy Inc. from 2003 to 2004.KLUGE, HOLGER
     Toronto, Ontario, Canada

Director

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 from 2000 to 2005; and Loring Ward
    International Limited (a financial planning company) from
    2004 to 2005.KOH, POH CHAN
     Hong Kong

Director

Ms. Koh is Finance Director,
    Harbour Plaza Hotel Management (International) Ltd. (a hotel
    management company).KWOK, EVA L.
     Vancouver, British Columbia Canada

Director

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 Bank of Montreal Group of 58




---



##### Table of Contents



Name and Residence

Office or Position

Principal Occupation During Past 5 YearsCompanies, CK Life Sciences
    Intl., (Holdings) Inc. and Cheung Kong Infrastructure
    Holdings Limited. Mrs. Kwok is also a director of the Li Ka
    Shing (Canada) Foundation.Mrs.   Kwok was a director of Air   Canada from 1998 to 2003; Telesystem International Wireless Inc. from 2002 to 2003; and Shoppers Drug Mart Corporation from 2004 to 2006.KWOK, STANLEY T.L.
     Vancouver, British Columbia, Canada

Director

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.LAU, JOHN C.S.
     Calgary, Alberta, Canada

President & Chief Executive
    Officer and Director

Mr. Lau is the President &
    Chief Executive Officer of Husky Energy Inc.SHAW, WAYNE E.
     Toronto, Ontario, Canada

Director

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.SHURNIAK, WILLIAM
     Limerick, Saskatchewan, Canada

Deputy Chairman and Director

Mr. Shurniak is a Non-Executive
    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.SIXT, FRANK J.
     Hong Kong

Director

Mr. Sixt is Group Finance Director
    and Executive Director of Hutchison Whampoa Limited.Mr. Sixt is also the Chairman and
    director of TOM Online Inc. and TOM Group Limited; Executive
    Director of Cheung Kong Infrastructure Holdings Limited and
    Hongkong Electric Holdings Limited; a director of Hutchison
    Telecommunications International Limited, Cheung Kong (Holdings)
    Limited, Hutchison Telecommunications (Australia) Limited and
    Partner Communications Company Ltd. Mr. Sixt is also a director
    of the Li Ka Shing (Canada) Foundation.  59




---



##### Table of Contents



Officers
  Name and Residence

Office or Position

Principal Occupation During Past 5 YearsINGRAM, DONALD R.
    Calgary, Alberta, Canada

Senior Vice President, Midstream
    & Refined Products

Senior Vice President, Midstream
    and Refined Products of Husky since August 2000.PEABODY, ROBERT J.
    Calgary, 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.BARLOW, L. GEOFFREY
    Calgary, Alberta, Canada

Vice President & Chief
    Financial Officer

Vice President & Chief
    Financial Officer of Husky since March 1, 2007. Mr. Barlow
    was Vice President & Controller of Husky Oil Operations from
    2003 to 2007 and Controller from 2000 to 2003.GIRGULIS, JAMES D.
    Calgary, Alberta, Canada

Vice President, Legal &
    Corporate Secretary

Vice President, Legal &
    Corporate Secretary of Husky since August 2000.     Business Corporations Act
    Conflicts
    of Interest
  Business Corporations Act
  Corporate
    Cease Trade Orders or Bankruptcies
   60




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##### Table of Contents



Companies Creditors Arrangement Act
  Individual
    Penalties, Sanctions or Bankruptcies
     AUDIT
    COMMITTEE                External
    Auditor Service Fees
  llp
  Aggregate feesbilled by theExternal Auditor2006


2005($ thousands)Audit fees


1,700



447Audit-related fees


109



27Tax fees


73



160All other fees


153



4762,035



1,110  61




---



##### Table of Contents



Audit Fees.
  Audit-Related Fees.
  Tax Fees.
  All Other Fees.
    llp
 LEGAL
    PROCEEDINGS   INTEREST
    OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS     TRANSFER
    AGENT AND REGISTRARS   INTERESTS
    OF EXPERTS   62




---



##### Table of Contents



ADDITIONAL
    INFORMATION      Additional information relating to Husky Energy Inc. is
    available on SEDAR at www.sedar.com
 63




---



##### Table of Contents



ABBREVIATIONS
    AND GLOSSARY OF TERMS    Units
    of Measure
  bbl

 barrelbbls

 barrelsmbbls

 thousand barrelsmmbbls

 million barrelsbbls/day

 barrels per calendar
    daymbbls/day

 thousand barrels per
    calendar dayboe

 barrels of oil
    equivalentboe/day

 barrels of oil
    equivalent per calendar daymcf

 thousand cubic feetmmcf

 million cubic feetbcf

 billion cubic feetmmcf/day

 million cubic feet per
    calendar daymcfge

 thousand cubic feet of
    gas equivalentlt

 long tonmlt

 thousand long tonslt/day

 long tons per calendar
    daymlt/day

 thousand long tons per
    calendar daymmbtu

 million British
    thermal unitsMW

 megawattsAcronymsAEUB

 Alberta Energy and
    Utilities BoardAPI

 American Petroleum
    InstituteCNOOC

 Chinese National
    Offshore Oil CompanyCOGEH

 Canadian Oil and Gas
    Evaluation HandbookEIA

 Energy Information
    AdministrationEL

 Exploration LicenceFAS

 Financial Accounting
    StatementFASB

 Financial Accounting
    Standards BoardFPSO

 Floating production,
    storage and offloading vesselLLB

 Lloydminster BlendNGL

 Natural gas liquidsNWT

 Northwest TerritoriesNYMEX

 New York Mercantile
    ExchangeOPEC

 Organization of
    Petroleum Exporting CountriesPSC

 Production Sharing
    ContractSAGD

 Steam assisted gravity
    drainageSDL

 Significant Discovery
    LicenseSEC

 Securities and
    Exchange Commission of the United StatesSEDAR

 System for Electronic
    Document Analysis and RetrievalWCSB

 Western Canada
    Sedimentary BasinWTI

 West Texas
    Intermediate crude oil   APIo
    gravity
    Barrel
   64




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##### Table of Contents



Bitumen
    Bulk
    Terminal
    CoalBed
    Methane
    Cold
    Production
    Debottlenecking
    Delineation
    well
    Developed
    area
    Development
    well
    Diluent
    Dry and
    abandoned well
    Enhanced
    recovery
    Exploration
    licence
   65




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##### Table of Contents



Exploratory
    well
    Field
    Gathering
    System
    Horizontal
    drilling
    Hydrogen
    sulphide
    Infill
    Well
    Liquefied
    petroleum gas
    Miscible
    Flood
    Multiple
    completion well
    Natural
    gas liquids (NGL)
    Oil
    Battery
    Oil
    Sands
   66




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##### Table of Contents



Overriding
    royalty interests
    Primary
    recovery
    Production
    Sharing Contract
    Raw
    gas
    Secondary
    recovery
    Seismic
    (survey)
    Service
    well
    Significant
    discovery licence
    Sour
    gas
    Specific
    Gravity
   Degrees API =

141.5Specific gravity @ F60
    degrees

−131.5   Spot
    Price
   67




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##### Table of Contents



Steam
    Assisted Gravity Drainage
    Step-out
    Well
    Stratigraphic
    test well
    Synthetic
    oil
    Tertiary
    recovery
    Three-D
    Seismic (survey)
    Turnaround
    Undeveloped
    area
    Waterflood
    Well
    Abandonment Costs
    Wellhead
    Working
    interest
   68




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##### Table of Contents



SPECIAL
    NOTE REGARDING FORWARD-LOOKING STATEMENTS      
    fluctuations in commodity prices
    the accuracy of our oil and gas reserve estimates and estimated
    production levels as they are affected by our success at
    exploration and development drilling and related activities and
    estimated decline rates
    the uncertainties resulting from potential delays or changes in
    plans with respect to exploration or development projects or
    capital expenditures
    changes in general economic, market and business conditions
    fluctuations in supply and demand for our products
    fluctuations in the cost of borrowing
    our use of derivative financial instruments to hedge exposure to
    changes in commodity prices and fluctuations in interest rates
    and foreign currency exchange rates
    political and economic developments, expropriations, royalty and
    tax increases, retroactive tax claims and changes to import and
    export regulations and other foreign laws and policies in the
    countries in which we operate
    our ability to receive timely regulatory approvals
    the integrity and reliability of our capital assets
    the cumulative impact of other resource development projects
    the maintenance of satisfactory relationships with unions,
    employee associations and joint venturers
    competitive actions of other companies, including increased
    competition from other oil and gas companies or from companies
    that provide alternate sources of energy
    actions by governmental authorities, including changes in
    environmental and other regulations that may impose restriction
    in areas where we operate
    the ability and willingness of parties with whom we have
    material relationships to fulfill their obligations
    the occurrence of unexpected events such as fires, blowouts,
    freeze-ups, equipment failures and other similar events
    affecting us or other parties whose operations or assets
    directly or indirectly affect us and that may or may not be
    financially recoverable 69




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www.sedar.com
   70




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##### Table of Contents



Schedule A  Husky
    Energy Inc.
  AUDIT
    COMMITTEE CHARTER    Composition
    Responsibility
    (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.        Authority
      non-audit
 71




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##### Table of Contents



Meetings
    Specific
    Duties
    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.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.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 72




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##### Table of Contents



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.
    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. 73




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##### Table of Contents



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.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.    74




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##### Table of Contents



Schedule B
  Husky
    Energy Inc.
  REPORT ON
    RESERVES DATA BY QUALIFIED RESERVES EVALUATOR     1.
    Our staff has evaluated Huskys oil and gas reserves data
    as at December 31, 2006. The reserves data consist of the
    following:  (a)
    proved oil and gas reserve quantities estimated as at
    December 31, 2006 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, 2006:  Discounted Future Net Cash FlowsLocation of Reserves

(before income taxes, 10% discount rate)($ millions)Canada


14,219China


596Libya


1114,826     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. 75




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##### Table of Contents



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.     Preston
    Kraft
  76




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##### Table of Contents



Schedule C
  Husky
    Energy Inc.
  REPORT OF
    MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER
    INFORMATION    (1)
    proved oil and gas reserve quantities estimated as at
    December 31, 2006 using constant prices and costs; and(2)
    the related standardized measure of discounted future net cash
    flows.      (a)
    reviewed the Companys procedures for providing information
    to the internal and external qualified oil and gas reserves
    evaluators;(b)
    met with the internal and, if applicable, external qualified oil
    and gas reserves evaluator(s) to determine whether any
    restrictions placed by management affect the ability of the
    internal qualified reserves evaluator to report without
    reservation; and(c)
    reviewed the reserves data with management and the internal
    qualified oil and gas reserves evaluator.    (a)
    the content and filing with securities regulatory authorities of
    the reserves data and other oil and gas information;(b)
    the filing of the Report on Reserves Data of the Manager of
    Reservoir Engineering; and(c)
    the content and filing of this report.       77




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##### Table of Contents



/s/  John
    C. S. LauJohn
    C. S. LauPresident & Chief Executive Officer

March 13, 2007/s/  James
    D. GirgulisJames
    D. GirgulisVice President, Legal & Corporate Secretary

March 13, 2007/s/  R.
    Donald
    FullertonR.
    Donald FullertonDirector

March 13, 2007/s/  Wayne
    E. ShawWayne
    E. ShawDirector

March 13, 2007  78




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##### Table of Contents



Schedule D
  Husky
    Energy Inc.
  INDEPENDENT
    ENGINEERS AUDIT OPINION  January 23,
    2007
  Husky
    Energy Inc.
             Sincerely,
    P.A.
    Welch
 President & Managing Director
 79




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##### Table of Contents



Document
    B
 Form 40-F
     CONSOLIDATED
    FINANCIAL STATEMENTS AND
 AUDITORS REPORT TO SHAREHOLDERS
  For the Year Ended December 31, 2006




---



##### Table of Contents



MANAGEMENTS
    REPORT
          llp llp
  John
    C. S. Lau
    1




---



##### Table of Contents



AUDITORS
    REPORT TO THE SHAREHOLDERS
          KPMG
    llp
   llp
  
  Comments
    by Auditor for US Readers on Canada/US Reporting
    Differences
    KPMG
    llp
   llp
  
 2




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##### Table of Contents



REPORT OF
    INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
                KPMG
    llp
   llp
  
 3




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##### Table of Contents



CONSOLIDATED
    BALANCE SHEETS
  As at December 312006


2005


2004(millions of dollars)ASSETSCurrent assetsCash and cash equivalents

$
442


$
168


$
Accounts receivable
    (note 4)


1,284



856



446Inventories (note 5)


428



471



274Prepaid expenses


25



40



522,179



1,535



772Property, plant and equipment, net
    (notes 1, 6)


15,550



13,959



12,193Goodwill (note 7)


160



160



160Other assets (note 11)


44



62



108$
17,933


$
15,716


$
13,233LIABILITIES AND
    SHAREHOLDERS EQUITYCurrent liabilitiesBank operating loans
    (note 9)

$



$



$
101Accounts payable and accrued
    liabilities (note 10)


2,574



2,310



1,439Long-term debt due within one year
    (note 11)


100



274



562,674



2,584



1,596Long-term debt
    (note 11)


1,511



1,612



2,047Other long-term liabilities
    (note 12)


756



730



632Future income taxes
    (note 13)


3,372



3,270



2,758Commitments and contingencies
    (note 14)Shareholders equityCommon shares (note 15)


3,533



3,523



3,506Retained earnings


6,087



3,997



2,6949,620



7,520



6,200$
17,933


$
15,716


$
13,233     /s/
    John C. S. Lau

/s/
    R.D. FullertonJohn C. S. Lau

R.D. FullertonDirector

Director    The accompanying notes to the consolidated financial
    statements are an integral part of these statements.
 4




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##### Table of Contents



CONSOLIDATED
    STATEMENTS OF EARNINGS
  Year ended December 312006


2005


2004(millions of dollars,except per share amounts)Sales and operating revenues, net
    of royalties

$
12,664


$
10,245


$
8,440Costs and expensesCost of sales and operating
    expenses (note 12)


7,169



5,917



5,706Selling and administration expenses


162



138



135Stock-based compensation
    (note 15)


138



171



67Depletion, depreciation and
    amortization (notes 1, 6)


1,599



1,256



1,179Interest  net
    (note 11)


92



32



60Foreign exchange
    (note 11)


(24
)


(31
)


(120
)Other  net


22



(50
)


89,158



7,433



7,035Earnings before income taxes


3,506



2,812



1,405Income taxes (note 13)Current


678



297



302Future


102



512



97780



809



399Net earnings

$
2,726


$
2,003


$
1,006Earnings per share
    (note 15) Basic and diluted

$
6.43


$
4.72


$
2.37    CONSOLIDATED
    STATEMENTS OF RETAINED EARNINGS
  Year ended December 312006


2005


2004(millions of dollars)Beginning of year

$
3,997


$
2,694


$
2,156Net earnings


2,726



2,003



1,006Dividends on common shares
    (note 15)Ordinary


(636
)


(276
)


(195
)Special






(424
)


(229
)Stock-based
    compensation  retroactive adoption
    (note 15)










(44
)End of year

$
6,087


$
3,997


$
2,694   The accompanying notes to the consolidated financial
    statements are an integral part of these statements.
 5




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##### Table of Contents



CONSOLIDATED
    STATEMENTS OF CASH FLOWS
  Year ended December 312006


2005


2004(millions of dollars)Operating activitiesNet earnings

$
2,726


$
2,003


$
1,006Items not affecting cashAccretion (note 12)


45



33



27Depletion, depreciation and
    amortization


1,599



1,256



1,179Future income taxes


102



512



97Foreign exchange


(3
)


(37
)


(124
)Other


32



18



12Settlement of asset retirement
    obligations


(36
)


(41
)


(40
)Change in non-cash working capital
    (note 8)


544



(94
)


147Cash flow  operating
    activities


5,009



3,650



2,304Financing activitiesBank operating loans
    financing  net






(101
)


(4
)Long-term debt issue


1,226



3,235



2,200Long-term debt repayment


(1,493
)


(3,401
)


(1,937
)Settlement of cross currency swap


(47
)






Debt issue costs










(5
)Proceeds from exercise of stock
    options


3



6



18Proceeds from monetization of
    financial instruments






39



8Dividends on common shares


(636
)


(700
)


(424
)Other


(1
)


(1
)


Change in non-cash working capital
    (note 8)


(678
)


255



337Cash flow  financing
    activities


(1,626
)


(668
)


193Available for investing


3,383



2,982



2,497Investing activities Capital
    expenditures


(3,171
)


(3,068
)


(2,349
)Corporate acquisitions










(102
)Asset sales


34



74



36Other


(12
)


(31
)


(19
)Change in non-cash working capital
    (note 8)


40



211



(63
)Cash flow  investing
    activities


(3,109
)


(2,814
)


(2,497
)Increase in cash and cash
    equivalents


274



168



Cash and cash equivalents at
    beginning of year


168







Cash and cash equivalents at end
    of year

$
442


$
168


$
    The accompanying notes to the consolidated financial
    statements are an integral part of these statements.
 6




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##### Table of Contents



NOTES TO
    THE CONSOLIDATED FINANCIAL STATEMENTS
  Except where
    indicated and per share amounts, all dollar amounts are in
    millions.
  Note
    1  Segmented Financial Information
  Upstream


MidstreamInfrastructureUpgrading


and Marketing2006


2005


2004


2006


2005


2004


2006


2005


2004Year ended December 31Sales and operating revenues, net
    of royalties

$
5,772


$
4,367


$
3,120


$
1,679


$
1,488


$
1,058


$
9,559


$
7,383


$
6,126Costs and expensesOperating, cost of sales, selling
    and
    general


1,321



1,050



967



1,273



1,018



884



9,258



7,084



5,914Depletion, depreciation and
    amortization


1,476



1,144



1,077



24



21



19



24



21



21Interest  net


































Foreign exchange


































2,797



2,194



2,044



1,297



1,039



903



9,282



7,105



5,935Earnings (loss) before income taxes


2,975



2,173



1,076



382



449



155



277



278



191Current income taxes


519



215



211



53



16







79



(14
)


31Future income taxes


161



434



152



44



120



43



1



110



32Net earnings (loss)

$
2,295


$
1,524


$
713


$
285


$
313


$
112


$
197


$
182


$
128Capital employed  As at
    December 31(2)

$
9,482


$
8,741


$
7,628


$
553


$
510


$
481


$
843


$
390


$
426Property, plant and
    equipment 
    As at December 31CostCanada

$
21,019


$
18,512


$
16,023


$
1,390


$
1,205


$
1,084


$
750


$
683


$
647International


751



655



587























$
21,770


$
19,167


$
16,610


$
1,390


$
1,205


$
1,084


$
750


$
683


$
647Accumulated depletion, depreciation
    and amortizationCanada

$
8,141


$
6,729


$
5,722


$
455


$
430


$
409


$
270


$
247


$
226International


404



354



311























$
8,545


$
7,083


$
6,033


$
455


$
430


$
409


$
270


$
247


$
226NetCanada

$
12,878


$
11,783


$
10,301


$
935


$
775


$
675


$
480


$
436


$
421International


347



301



276























$
13,225


$
12,084


$
10,577


$
935


$
775


$
675


$
480


$
436


$
421Capital expenditures 
    Year ended
    December 31(3)

$
2,627


$
2,730


$
2,157


$
184


$
120


$
62


$
68


$
37


$
31Total assets  As at
    December
    31(4)Canada

$
13,540


$
12,559


$
10,750


$
992


$
844


$
708


$
1,329


$
866


$
746International


380



328



275























$
13,920


$
12,887


$
11,025


$
992


$
844


$
708


$
1,329


$
866


$
746    (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)
    Defined as short- and long-term debt and shareholders
    equity.(3)
    Excludes capitalized costs related to asset retirement
    obligations incurred during the period and corporate
    acquisitions.(4)
    Includes goodwill on corporate acquisitions related to Upstream. 7




---



##### Table of Contents



Refined Products


Corporate and
    Eliminations(1)


Total2006


2005


2004


2006


2005


2004


2006


2005


2004Year ended December 31Sales and operating revenues, net
    of royalties

$
2,575


$
2,345


$
1,797


$
(6,921
)

$
(5,338
)

$
(3,661
)

$
12,664


$
10,245


$
8,440Costs and expensesOperating, cost of sales, selling
    and general


2,381



2,169



1,694



(6,742
)


(5,145
)


(3,543
)


7,491



6,176



5,916Depletion, depreciation and
    amortization


48



47



38



27



23



24



1,599



1,256



1,179Interest  net














92



32



60



92



32



60Foreign exchange














(24
)


(31
)


(120
)


(24
)


(31
)


(120
)2,429



2,216



1,732



(6,647
)


(5,121
)


(3,579
)


9,158



7,433



7,035Earnings (loss) before income taxes


146



129



65



(274
)


(217
)


(82
)


3,506



2,812



1,405Current income taxes


19



(3
)


11



8



83



49



678



297



302Future income taxes


21



50



13



(125
)


(202
)


(143
)


102



512



97Net earnings (loss)

$
106


$
82


$
41


$
(157
)

$
(98
)

$
12


$
2,726


$
2,003


$
1,006Capital employed  As at
    December 31(2)

$
561


$
481


$
360


$
(208
)

$
(716
)

$
(491
)

$
11,231


$
9,406


$
8,404Property, plant and
    equipment 
    As at December 31CostCanada

$
1,344


$
1,063


$
878


$
298


$
257


$
232


$
24,801


$
21,720


$
18,864International


























751



655



587$
1,344


$
1,063


$
878


$
298


$
257


$
232


$
25,552


$
22,375


$
19,451Accumulated depletion, depreciation
    and amortizationCanada

$
525


$
476


$
432


$
207


$
180


$
158


$
9,598


$
8,062


$
6,947International


























404



354



311$
525


$
476


$
432


$
207


$
180


$
158


$
10,002


$
8,416


$
7,258NetCanada

$
819


$
587


$
446


$
91


$
77


$
74


$
15,203


$
13,658


$
11,917International


























347



301



276$
819


$
587


$
446


$
91


$
77


$
74


$
15,550


$
13,959


$
12,193Capital expenditures 
    Year ended
    December 31(3)

$
285


$
191


$
106


$
37


$
21


$
23


$
3,201


$
3,099


$
2,379Total assets  As at
    December 31(4)Canada

$
1,114


$
834


$
625


$
578


$
285


$
129


$
17,553


$
15,388


$
12,958International


























380



328



275$
1,114


$
834


$
625


$
578


$
285


$
129


$
17,933


$
15,716


$
13,233  8




---



##### Table of Contents



Note 2
  Nature
    of Operations and Organization
            Note 3
  Significant
    Accounting Policies
  a) Principles
    of Consolidation and the Preparation of Financial
    Statements
          b) Cash
    and Cash Equivalents
    c) Inventory
    Valuation
    d) Property,
    Plant and Equipment
  i) Oil
    and Gas
  country-by-country
        
    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
    the costs of major development projects, less impairment. 9




---



##### Table of Contents




    the fair value of proved and probable reserves; 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
    iii) Asset
    Retirement Obligations
    iv) Capitalized
    Interest
    e) Impairment
    or Disposal of Long-lived Assets
      f) Goodwill
    g) Derivative
    Financial Instruments
             10




---



##### Table of Contents



h) Employee
    Future Benefits
      i) Future
    Income Taxes
    j) Non-monetary
    Transactions
    k) Revenue
    Recognition
    l) Foreign
    Currency Translation
    m) Stock-based
    Compensation
     11




---



##### Table of Contents



n) Earnings
    per Share
    in-the-money
  o) Reclassification
    Note 4
  Accounts
    Receivable
  2006


2005


2004Trade receivables

$
1,286


$
854


$
448Allowance for doubtful accounts


(10
)


(10
)


(10
)Other


8



12



8$
1,284


$
856


$
446   Sale of
    Accounts Receivable
      Note 5
  Inventories
  2006


2005


2004Crude oil and refined petroleum
    products

$
208


$
241


$
159Natural gas


193



207



100Materials, supplies and other


27



23



15$
428


$
471


$
274   Note 6
  Property,
    Plant and Equipment
        2006


2005


2004Canada

$
1,932


$
2,317


$
2,399International


165



127



129$
2,097


$
2,444


$
2,528     Price increaseCanada

2007


2008


2009


2010


2011


2011 to 2026(percent)Crude oil ($/bbl)

$
56.91


$
51.90


$
44.90


$
41.60


$
42.58



68Natural gas ($/mcf)


7.71



7.70



7.18



6.86



6.87



35    12




---



##### Table of Contents



Note 7
  Corporate
    Acquisition
      Net assets acquiredWorking capital

$
(17
)Property, plant and equipment


138Goodwill (1)


20Future income taxes


(39
)$
102    (1)
    Allocated to the Companys upstream segment and not
    deductible for income tax purposes. Refer to note 1,
    Segmented Financial Information.  Note 8
  Cash
    Flows  Change in Non-cash Working
    Capital
  a) Change
    in non-cash working capital was as follows:
  2006


2005


2004Decrease (increase) in non-cash
    working capitalAccounts receivable

$
(428
)

$
(410
)

$
209Inventories


43



(197
)


(77
)Prepaid expenses


14



17



(12
)Accounts payable and accrued
    liabilities


277



962



301Change in non-cash working capital

$
(94
)

$
372


$
421Relating to:Operating activities

$
544


$
(94
)

$
147Financing activities


(678
)


255



337Investing activities


40



211



(63
)   b) Other
    cash flow information:
  2006


2005


2004Cash taxes paid

$
215


$
154


$
213Cash interest paid


147



147



143   Note 9
  Bank
    Operating Loans
    Note 10
  Accounts
    Payable and Accrued Liabilities
  2006


2005


2004Trade payables

$
74


$
7


$
51Accrued liabilities


1,221



1,247



760Dividend payable


212



530



280Commodity contract settlements










50Stock-based compensation


234



130



49Current income taxes


615



164



119Other


218



232



130$
2,574


$
2,310


$
1,439  13




---



##### Table of Contents



Note 11
  Long-term
    Debt
  Cdn $ Amount


U.S. $ DenominatedMaturity


2006


2005


2004


2006


2005


2004Long-term debtSyndicated credit facility





$



$



$
70


$



$



$
Bilateral credit facilities














40











6.85% medium-term notes 
    Series B


2007



100



100



100











6.95% medium-term notes 
    Series E


2009



200



200



200











6.25% notes


2012



466



467



481



400



400



4007.55% debentures


2016



233



233



241



200



200



2006.15% notes


2019



350



350



361



300



300



3008.90% capital securities


2028



262



262



271



225



225



2257.125% notes










175



181







150



1508.45% senior secured bonds










99



140







85



117Private placement notes














18











15Total long-term debt






1,611



1,886



2,103


$
1,125


$
1,360


$
1,407Amount due within one year






(100
)


(274
)


(56
)$
1,511


$
1,612


$
2,047     2006


2005


2004Long-term debt

$
130


$
144


$
133Short-term debt


5



4



3135



148



136Amount capitalized


(33
)


(114
)


(75
)102



34



61Interest income


(10
)


(2
)


(1
)$
92


$
32


$
60     2006


2005


2004Gain on translation of U.S. dollar
    denominated long-term debt

$
(7
)

$
(51
)

$
(150
)Cross currency swaps


4



14



27Other losses


(21
)


6



3$
(24
)

$
(31
)

$
(120
)     Credit
    Facilities
      Notes and
    Debentures
  25-month
       14




---



##### Table of Contents



Note 12
  Other
    Long-term Liabilities
  2006


2005


2004Asset retirement obligations

$
622


$
557


$
509Cross currency swaps


40



40



68Interest rate swaps


37



42



18Employee future benefits


30



27



23Stock-based compensation


4



46



14Other


23



18



$
756


$
730


$
632   Asset
    Retirement Obligations
      2006


2005


2004Asset retirement obligations at
    beginning of year

$
557


$
509


$
432Liabilities incurred


35



63



13Liabilities disposed


(1
)


(7
)


Liabilities settled


(36
)


(41
)


(40
)Revisions


22







77Accretion


45



33



27Asset retirement obligations at end
    of year

$
622


$
557


$
509  15




---



##### Table of Contents



Note 13
  Income
    Taxes
    2006


2005


2004Earnings before income taxesCanadian

$
3,276


$
2,553


$
1,165Foreign jurisdictions


230



259



2403,506



2,812



1,405Statutory income tax rate
    (percent)


35.7



38.4



39.3Expected income tax


1,252



1,080



552Effect on income tax of:Royalties, lease rentals and
    mineral taxes payable to the crown


10



105



153Resource allowance on Canadian
    production income


(35
)


(133
)


(156
)Rate benefit on partnership earnings


(97
)


(69
)


(42
)Change in statutory tax rate


(328
)


(4
)


(40
)Non-deductible capital taxes


(17
)


15



20Capital gains and losses


(1
)


(140
)


(23
)Foreign jurisdictions


(6
)


(14
)


(13
)Other  net


2



(31
)


(52
)Income tax expense

$
780


$
809


$
399     2006


2005


2004Future tax liabilitiesProperty, plant and equipment

$
3,607


$
3,487


$
2,949Foreign exchange gains taxable on
    realization


48



60



56Other temporary differences


1



2



53,656



3,549



3,010Future tax assetsAsset retirement obligations


194



195



180Loss carry forwards


2







11Provincial royalty rebates


2



7



14Other temporary differences


86



77



47284



279



252$
3,372


$
3,270


$
2,758   Note 14
  Commitments
    and Contingencies
  20-year
    After2007


2008


2009


2010


2011


2011


TotalOperating leases

$
93


$
208


$
286


$
283


$
167


$
96


$
1,133Firm transportation agreements


169



122



80



62



46



147



626Unconditional purchase
    obligations (1)


2,144



970



938



74



62



13



4,201Lease rentals and exploration work
    agreements


148



74



73



108



70



167



640Engineering and construction
    commitments


140























140$
2,694


$
1,374


$
1,377


$
527


$
345


$
423


$
6,740     (1)
    Approximately 72% of the total unconditional purchase
    obligations are in respect of processing and refined product
    purchase contracts. 16




---



##### Table of Contents



Note 15
  Share
    Capital
        Common
    Shares
    Number of Shares


AmountDecember 31, 2003


422,175,742


$
3,457Stock-based
    compensation  adoption






23Options and warrants exercised


1,560,672



26December 31, 2004


423,736,414



3,506Options and warrants exercised


388,664



17December 31, 2005


424,125,078



3,523Options exercised


143,431



10December 31, 2006


424,268,509


$
3,533   Stock
    Options
        Number of


Weighted


Weighted Average


OptionsOptions


Average


Contractual


Exercisable(thousands)


Exercise Prices


Life (years)


(thousands)December 31, 2003


4,597


$
13.88



2



3,564Granted


8,200


$
25.10



4Exercised for common shares


(1,350
)

$
13.11



1Surrendered for cash


(1,269
)

$
13.32



1Forfeited


(214
)

$
22.73



4December 31, 2004


9,964


$
22.61



4



1,417Granted


670


$
48.14



5Exercised for common shares


(359
)

$
15.84



1Surrendered for cash


(2,443
)

$
19.05



2Forfeited


(547
)

$
24.10



3December 31, 2005


7,285


$
25.81



3



1,533Granted


902


$
71.42



4Exercised for common shares


(144
)

$
22.31



2Surrendered for cash


(1,951
)

$
23.95



2Forfeited


(264
)

$
42.82



3December 31, 2006


5,828


$
32.81



3



2,232  17




---



##### Table of Contents



As at December 31, 2006

Outstanding Options


Options ExercisableWeighted


Weighted





WeightedNumber of


Average


Average


Number of


AverageOptions


Exercise


Contractual


Options


ExerciseRange of Exercise Price

(thousands)


Prices


Life (years)


(thousands)


Prices$13.96 - $14.99


64


$
14.60



1



64


$
14.60$15.00 - $22.99


96


$
19.87



2



96


$
19.87$23.00 - $23.99


4,164


$
23.83



2



1,882


$
23.83$24.00 - $39.99


294


$
32.22



3



95


$
31.69$40.00 - $55.99


378


$
52.17



4



95


$
52.90$56.00 - $76.74


832


$
72.04



4






$
5,828


$
32.81



3



2,232


$
24.96   Warrants
    Earnings
    per Common Share
  2006


2005


2004Net earnings

$
2,726


$
2,003


$
1,006Weighted average number of common
    shares outstandingBasic (millions)


424.2



424.0



423.4Effect of dilutive stock options
    and warrants










0.9Weighted average number of common
    shares outstandingDiluted (millions)


424.2



424.0



424.3Earnings per shareBasic and diluted

$
6.43


$
4.72


$
2.37   Stock-based
    Compensation
      2004Weighted average fair value per
    option

$
5.67Risk-free interest rate
    (percent)


3.1Volatility (percent)


21Expected life (years)


5Expected annual dividend per share

$
0.44   Dividends
   18




---



##### Table of Contents



Contributed
    Surplus
    2004December 31, 2003

$
Stock-based
    compensation  adoption


21Stock-based compensation cost


1Stock options exercised


(6
)Modification of stock option
    plan  June 1, 2004


(16
)December 31, 2004

$
   Note 16
  Employee
    Future Benefits
    Defined
    Benefit Pension Plan
    2006


2005


2004Discount rate (percent)


5.0



5.8



6.0Long-term rate of increase in
    compensation levels (percent)


5.0



5.0



5.0Long-term rate of return on plan
    assets (percent)


7.5



7.5



8.0         Benefit
    Obligation
  2006


2005


2004Benefit obligation, beginning of
    year

$
138


$
124


$
118Current service cost


3



2



2Interest cost


7



7



7Benefits paid


(7
)


(6
)


(6
)Actuarial losses


8



11



3Benefit obligation, end of year

$
149


$
138


$
124   Fair
    Value of Plan Assets
  2006


2005


2004Fair value of plan assets,
    beginning of year

$
108


$
96


$
85Contributions


13



11



10Benefits paid


(7
)


(6
)


(6
)Expected return on plan assets


8



7



7Gain on plan assets


10







1Foreign exchange losses










(1
)Fair value of plan assets, end of
    year

$
132


$
108


$
96   Funded
    Status of Plan
  2006


2005


2004Fair value of plan assets

$
132


$
108


$
96Benefit obligation


(149
)


(138
)


(124
)Excess obligation


(17
)


(30
)


(28
)Unrecognized past service costs


3



1



1Unrecognized losses


33



40



32Accrued benefit asset

$
19


$
11


$
5  19




---



##### Table of Contents



2006


2005


2004U.S. common equities


1
%



%


15
%Canadian common equities


30



29



25International equity mutual funds


30



28



11Canadian government bonds


16



18



25Canadian corporate bonds


3



3



16Canadian fixed income mutual funds


19



20



Cash and receivables


1



2



8Total


100
%


100
%


100
%         Post-retirement
    Health and Dental Care Plan
      Benefit
    Obligation
  2006


2005


2004Benefit obligation, beginning of
    year

$
33


$
25


$
23Current service cost


2



2



2Interest cost


2



1



1Benefits paid










(1
)Actuarial losses


12



5



Benefit obligation, end of year

$
49


$
33


$
25   Funded
    Status of Plan
  2006


2005


2004Benefit obligation

$
(49)


$
(33)


$
(25)Unrecognized losses


19



6



2Accrued benefit liability

$
(30
)

$
(27
)

$
(23
)     1%


1%Increase


DecreaseEffect on total service and
    interest cost components

$
1


$
(1)Effect on post-retirement benefit
    obligation

$
11


$
(8
)  20




---



##### Table of Contents



Pension
    Expense and Post-retirement Health and Dental Care
    Expense
    Pension
    Expense
  2006


2005


2004Defined benefit pension planEmployer current service cost

$
3


$
2


$
2Interest cost


7



7



7Expected return on plan assets


(8
)


(7
)


(7
)Amortization of net actuarial losses


3



3



25



5



4Defined contribution pension plan


16



14



12Total expense

$
21


$
19


$
16   Post-retirement
    Health and Dental Care Expense
  2006


2005


2004Employer current service cost

$
2


$
2


$
2Interest cost


2



1



1Total expense

$
4


$
3


$
3   Future
    Benefit Payments
    Defined Benefit


Post-retirement HealthPension Plan


and Dental Care Plan2007

$
8


$
12008


8



12009


9



12010


10



12011


9



12012 - 2016


51



9   Note 17
  Related
    Party Transactions
    Note 18
  Financial
    Instruments and Risk Management
  Carrying
    Values and Estimated Fair Values of Financial Assets and
    Liabilities
      2006


2005


2004Carrying


Fair


Carrying


Fair


Carrying


FairValue


Value


Value


Value


Value


ValueLong-term debt

$
1,611


$
1,671


$
1,886


$
1,995


$
2,103


$
2,296  21




---



##### Table of Contents



Recognized
    Gains (Losses) on Derivative Instruments
    2006


2005


2004Commodity price risk managementPower consumption

$
6


$
4


$
3Natural gas






(17
)


(1
)Crude oil










(560
)Interest rate risk management


1



13



22Foreign exchange risk management


(3
)


1



(13
)   Unrecognized
    Gains (Losses) on Derivative Instruments
  2006


2005


2004Commodity price risk managementPower consumption

$



$



$
(1
)Natural gas










(9
)Interest rate risk managementInterest rate swaps


5



7



52Foreign currency risk management
    Foreign exchange contracts


(26
)


(32
)


(30
)   Commodity
    Price Risk Management
  Natural
    Gas and Crude Oil Production
    Power
    Consumption    Notional Volumes(MW)


Term


PriceFixed price purchase


20.0



Apr. to Jun. 2007


$
63.63/MWh   Natural
    Gas Contracts    Volumes


Unrecognized(mmcf)


Gain (Loss)Physical purchase contracts


25,509


$
5Physical sale contracts


(25,509
)

$
1   Interest
    Rate Risk Management
    Debt

Amount


Swap Maturity


Swap Rate (percent)6.95% medium-term notes

$
200



July 14, 2009



CDOR + 175 bps     Foreign
    Currency Risk Management
   22




---



##### Table of Contents



CanadianDebt

Swap Amount


Equivalent


Swap Maturity


Interest Rate(percent)6.25% notes

U.S. $
150


$
212



June 15, 2012



7.416.25% notes

U.S. $
75


$
90



June 15, 2012



5.656.25% notes

U.S. $
50


$
59



June 15, 2012



5.676.25% notes

U.S. $
75


$
88



June 15, 2012



5.61     Credit
    Risk
        New CICA
    Handbook Sections for Financial Instruments
            December 31, 2006





January 1, 2007(As Reported)


Adoption Adjustment


(As Restated)Consolidated Balance SheetsAssetsAccounts receivable

$
1,284


$
6


$
1,290Prepaid expenses


25



(2
)


23Other assets


44



(7
)


37Liabilities and Shareholders
    EquityAccounts payable and accrued
    liabilities


2,574



(5
)


2,569Long-term debt due within one year


100



(2
)


98Long-term debt


1,511



34



1,545Other long-term liabilities


756



(10
)


746Future income taxes


3,372



(6
)


3,366Retained earnings


6,087



4



6,091Accumulated other comprehensive
    income






(18
)


(18
)  23




---



##### Table of Contents



Note 19
  Reconciliation
    to Accounting Principles Generally Accepted in the United
    States
    Consolidated
    Statements of Earnings
  2006


2005


2004Net earnings under Canadian GAAP

$
2,726


$
2,003


$
1,006Adjustments:Full cost accounting (a)


64



66



37Related income taxes


(20
)


(23
)


(13
)Energy trading contracts (c)


4







(1
)Related income taxes


(1
)






Stock-based compensation (d)


(10
)






2Related income taxes


3







Earnings before cumulative effect
    of change in accounting principle under U.S. GAAP


2,766



2,046



1,031Cumulative effect of change in
    accounting principle, net of tax (d)


11







Net earnings under U.S. GAAP

$
2,777


$
2,046


$
1,031Weighted average number of common
    shares outstanding under U.S. GAAP (millions)Basic


424.2



424.0



423.4Diluted


424.2



424.0



424.3Earnings per share before
    cumulative effect of change in accounting principle under
    U.S. GAAPBasic

$
6.52


$
4.83


$
2.44Diluted

$
6.52


$
4.83


$
2.43Earnings per share under U.S. GAAPBasic

$
6.55


$
4.83


$
2.44Diluted

$
6.55


$
4.83


$
2.43   Condensed
    Consolidated Balance Sheets
  2006


2005


2004Canadian


U.S.


Canadian


U.S.


Canadian


U.S.GAAP


GAAP


GAAP


GAAP


GAAP


GAAPCurrent assets (b)(c)

$
2,179


$
2,190


$
1,535


$
1,591


$
772


$
830Property, plant and equipment,
    net (a)


15,550



15,120



13,959



13,465



12,193



11,633Other assets (g)


204



185



222



223



268



269$
17,933


$
17,495


$
15,716


$
15,279


$
13,233


$
12,732Current liabilities (b)(c)(g)

$
2,674


$
2,696


$
2,584


$
2,685


$
1,596


$
1,649Long-term debt (b)


1,511



1,557



1,612



1,670



2,047



2,124Other long-term liabilities (b)(g)


756



749



730



688



632



614Future income taxes
    (a)(b)(c) (g)


3,372



3,210



3,270



3,089



2,758



2,555Share capital (d)(e)(f)


3,533



3,767



3,523



3,757



3,506



3,740Retained earnings


6,087



5,572



3,997



3,431



2,694



2,085Accumulated other comprehensive
    income Cash flow hedges, net of tax (b)






(18
)






(21
)






(20
)Minimum pension liability, net of
    tax (g)














(20
)






(15
)Pension accounting 
    adoption of FAS 158 (g)






(38
)














$
17,933


$
17,495


$
15,716


$
15,279


$
13,233


$
12,732  24




---



##### Table of Contents



Condensed
    Consolidated Statements of Retained Earnings and Accumulated
    Other Comprehensive Income
  2006


2005


2004Canadian


U.S.


Canadian


U.S.


Canadian


U.S.GAAP


GAAP


GAAP


GAAP


GAAP


GAAPRetained earnings, beginning of year

$
3,997


$
3,431


$
2,694


$
2,085


$
2,156


$
1,478Net earnings


2,726



2,777



2,003



2,046



1,006



1,031Dividends on common shares


(636
)


(636
)


(700
)


(700
)


(424
)


(424
)Stock-based
    compensation  retroactive adoption (d)


















(44
)


Retained earnings, end of year

$
6,087


$
5,572


$
3,997


$
3,431


$
2,694


$
2,085Accumulated other comprehensive
    income, beginning of year

$



$
(41
)

$



$
(35
)

$



$
(91
)Cash flow hedges, net of
    tax (b)






3







(1
)






56Minimum pension liability, net of
    tax (g)






(5
)






(5
)






Reversal of minimum pension
    liability, net of tax  adoption of FAS 158 (g)






25















Pension accounting 
    adoption of FAS 158 (g)






(38
)














Accumulated other comprehensive
    income, end of year

$



$
(56
)

$



$
(41
)

$



$
(35
)   Condensed
    Consolidated Statements of Earnings and Comprehensive
    Income
  2006


2005


2004Canadian


U.S.


Canadian


U.S.


Canadian


U.S.GAAP


GAAP


GAAP


GAAP


GAAP


GAAPSales and operating
    revenues (b)(c)

$
12,664


$
10,790


$
10,245


$
8,445


$
8,440


$
7,038Costs and expenses (excluding
    depletion, depreciation and amortization) (b)(c) (d)


7,422



5,554



6,112



4,312



5,769



4,366Accretion expense


45



45



33



33



27



27Depletion, depreciation and
    amortization (a)


1,599



1,535



1,256



1,190



1,179



1,142Interest  net


92



92



32



32



60



60Earnings before income taxes


3,506



3,564



2,812



2,878



1,405



1,443Income taxes (a)(b)(c)


780



798



809



832



399



412Earnings before cumulative effect
    of change in accounting principle


2,726



2,766



2,003



2,046



1,006



1,031Cumulative effect of change in
    accounting principle, net of tax (d)






11















Net earnings


2,726



2,777



2,003



2,046



1,006



1,031Other comprehensive
    income (b)(g)






2







6







(56
)Comprehensive income

$
2,726


$
2,779


$
2,003


$
2,052


$
1,006


$
975       (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 $60 million (2005  $62 million;
    2004  $76 million), before tax of
    $19 million (2005  $21 million;
    2004  $27 million).    (b)
    The Company records all derivative instruments as assets and
    liabilities on the balance sheet based on their fair values as
    required under Statement of Financial Accounting Standards
    (FAS) No. 133, Accounting for Derivative
    Instruments and Hedging Activities. At December 31,
    2006, the Company recorded additional assets and liabilities for
    U.S. GAAP purposes of $5 million (2005 
    $7 million; 2004  $52 million) and
    $31 million (2005  $39 million;
    2004  $93 million), respectively, for the fair
    values of derivative financial instruments. The Company also
    recorded a gain of nil, net of tax (2005  gain of
    less than $1 million; 2004  loss of less than
    $1 million), in revenue for U.S. GAAP purposes with respect
    to derivatives designated as fair value hedges relating to
    commodity price risk. In addition, the amount included in other
    comprehensive income was decreased by $3 million net of tax
    (2005  increased by $1 million; 2004 
    decreased by $51 million), for changes in the fair values
    of the derivatives designated as hedges of cash flows relating
    to commodity price risk, foreign exchange risk and the transfer
    to income of amounts applicable to cash flows occurring in 2006.
    In 2004, the Company unwound its long-dated foreign exchange
    forwards. The unrealized gain of $5 million, before tax was
    deferred in other comprehensive income and recognized in 2005
    when the underlying transactions 25




---



##### Table of Contents



took place. In 2005 and 2003 the
    Company unwound interest rate swaps that were fair value hedges
    of debt for proceeds of $37 million and $44 million,
    respectively. Under Canadian GAAP, the proceeds received have
    been recorded to current and long-term liabilities and are being
    deferred over the life of the debt. For U.S. GAAP purposes, the
    balance in the current and long-term liabilities has been
    reclassified to long-term debt consistent with fair value hedge
    treatment.  (c)
    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. Under
    Canadian GAAP, the impact of energy trading contracts is
    recorded as they settle. Under U.S. GAAP, at December 31,
    2006, the Company recorded additional assets and liabilities of
    $6 million (2005  $49 million;
    2004  $4 million) and nil (2005 
    $48 million; 2004  $3 million),
    respectively, and included the resulting unrealized gain, net of
    tax of $3 million (2005  gain of less than
    $1 million; 2004  loss of $1 million), in
    earnings for the year. Under U.S. GAAP, gains and losses on
    energy trading contracts have been netted against sales and
    operating revenues.(d)
    Effective January 1, 2004, under Canadian GAAP, the Company
    adopted fair value accounting for stock-based compensation
    retroactively without restatement, which is consistent with the
    recommendations in FAS 123, Accounting for Stock-based
    Compensation  Transition and Disclosure.        2006Initial expected life (years)


3.5Expected annual dividend per share

$
2.00       (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.(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)
    Under FAS 87, Employers Accounting for
    Pensions, the Company amortized the portion of the
    unrecognized gains or losses that exceeded 10% of the greater of
    the projected 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 or a calculated value
    that recognizes changes in fair value over not more than five
    years. An additional minimum liability was recognized if the
    unfunded accumulated benefit obligation exceeded the unfunded
    pension cost already recognized. If an additional minimum
    liability was recognized, an amount equal to the unrecognized
    prior service cost was recognized as an intangible asset and any
    excess was reported in other comprehensive income.     26




---



##### Table of Contents



Before





AfterFAS 158


Adoption


FAS 158Adoption


Adjustment


AdoptionConsolidated Balance SheetsAssetsOther assets  prepaid
    pension asset

$
19


$
(19
)

$
Liabilities and Shareholders
    Equity Additional minimum liability


36



(36
)


Long-term liability 
    pension payable


30



(30
)


Current liability 
    unfunded status of plan






8



8Long-term liability 
    unfunded status of plan






58



58Future income taxes


3,216



(6
)


3,210Accumulated other comprehensive
    income


(43
)


(13
)


(56
)     Additional
    U.S. GAAP Disclosures
  Corporate
    Acquisitions
    Accounting
    for Derivative Instruments and Hedging Activities
        Stock
    Option Plan
    Depletion,
    Depreciation and Amortization
    2006


2005


2004Depletion, depreciation and
    amortization per boe

$
10.75


$
9.38


$
8.76   Accounting
    for Inventory Costs
   27




---



##### Table of Contents



Accounting
    for Exchanges of Nonmonetary Assets
      Accounting
    Changes and Error Corrections
    Accounting
    for Certain Hybrid Financial Instruments
    Accounting
    for Servicing of Financial Assets
    Fair
    Value Measurement
    Accounting
    for Uncertainty in Income Taxes
    Accounting
    for Purchases and Sales of Inventory with the Same
    Counterparty
  EITF 04-13, EITF 04-13 work-in-progress
 28




---



##### Table of Contents



same line of business is not an
    exchange transaction to facilitate sales to customers. These
    nonmonetary exchanges are required to be recognized at fair
    value if reasonably determinable and the transaction has
    commercial substance. All other nonmonetary exchanges of
    inventory within the same line of business are to be recognized
    at the carrying amount of the inventory transferred.
    EITF 04-13
    is effective for new arrangements entered into, and
    modifications or renewals of existing arrangements, beginning in
    the first interim or annual reporting period beginning after
    March 15, 2006. The application of
    EITF 04-13
    did not have a material impact on the financial statements.
  Quantifying
    Financial Statement Misstatements
   29




---



##### Table of Contents



Document
    C
 Form 40-F
     MANAGEMENTS
    DISCUSSION AND ANALYSIS
  February 26, 2007




---



##### 



MANAGEMENTS
    DISCUSSION AND ANALYSIS
  February 26, 2007
  TABLE OF
    CONTENTS
  Page1.

Financial and
    Operational Overview

21.1  Huskys
    Business

21.2  Financial
    Overview

31.3  Selected
    Annual Information

41.4  Selected
    Quarterly Information

41.5  Major
    Events in 2006

42.

Capability to
    Deliver Results

52.1  Upstream

52.2  Midstream

62.3  Refined
    Products

62.4  Key
    Performance Drivers and Measures

62.5  The
    Business Environment in 2006

83.

Strategy

103.1  Strategic
    Imperatives

103.2  Major
    Projects

124.

Results of
    Operations

144.1  Upstream

144.2  Midstream

234.3  Refined
    Products

254.4  Corporate

264.5  2005
    Compared with 2004

285.

2007
    Outlook

295.1  General
    Economy

295.2  2007
    Capital Program

295.3  Upstream

305.4  Midstream

315.5  Refined
    Products

316.

Liquidity and
    Capital Resources

316.1  Summary
    of Cash Flow

316.2  Working
    Capital Components

326.3  Cash
    Requirements

346.4  Off-Balance
    Sheet Arrangements

356.5  Transactions
    with Related Parties and Major Customers

356.6  Financial
    Risk and Risk Management

356.7  Outstanding
    Share Data

367.

Application of
    Critical Accounting Estimates

367.1  Full
    Cost Accounting for Oil and Gas Activities

377.2  Impairment
    of Long-lived Assets

377.3  Fair
    Value of Derivative Instruments

377.4  Asset
    Retirement Obligations

387.5  Legal,
    Environmental Remediation and Other Contingent Matters

387.6  Income
    Tax Accounting

387.7  Business
    Combinations

387.8  Goodwill

387.9  Variable
    Interest Entities

398.

New Accounting
    Standards

398.1  Canadian
    Accounting

398.2  U.S.
    Accounting

399.

Pending Accounting
    Standards

409.1  Canadian
    Accounting Pronouncements

409.2  U.S.
    Accounting Pronouncements

4110.

Forward-looking
    Statements

4211.

Oil and Gas Reserve
    Reporting

4312.

Non-GAAP
    Measures

4313.

Additional Reader
    Advisories

4414.

Controls and
    Procedures

44    1




---



##### Table of Contents



1.
    FINANCIAL
    AND OPERATIONAL OVERVIEW  1.1
    HUSKYS
    BUSINESS  Core
    Businesses
    Upstream
    
    the Western Canada Sedimentary Basin;
    the oil sands regions of Alberta;
    the Jeanne dArc Basin off the East Coast of Canada;
    the Mackenzie Valley in the Northwest Territories;
    the South China Sea and the East China Sea; and
    the Madura Strait and north east Java Sea, offshore Indonesia.  
  Midstream
  
    heavy oil upgrader located at Lloydminster, Saskatchewan with a
    current throughput capacity of approximately 76 mbbls/day
    yielding 65 mbbls/day of synthetic crude oil and
    11 mbbls/day of diluent;
    pipeline systems with combined capacity in excess of
    500 mbbls/day in the heavy oil producing regions between
    Cold Lake, Alberta south through Lloydminster to Hardisty,
    Alberta; and
    crude oil and natural gas storage facilities, cogeneration and
    commodity marketing.  Refined
    Products
  
    505 retail and wholesale locations from the West Coast of Canada
    to the eastern border of Ontario;
    a recently upgraded 12 mbbls/day full slate refinery in
    Prince George, British Columbia; 2




---



##### Table of Contents




    a 28 mbbls/day asphalt refinery in Lloydminster, Alberta
    and Western Canada asphalt marketing and distribution system; and
    ethanol plants at Lloydminster, Saskatchewan and Minnedosa,
    Manitoba with current combined annual capacity of
    140 million litres. The Minnedosa, Manitoba ethanol plant
    expansion in 2007 will increase combined annual capacity to
    260 million litres.  1.2
    FINANCIAL
    OVERVIEW  Financial
    Position
  
  Financial
    Performance
  
 3




---



##### Table of Contents



1.3
    SELECTED
    ANNUAL INFORMATION  2006


2005


2004($ millions, except where indicated)Sales and operating revenues, net
    of royalties

$
12,664


$
10,245


$
8,440Segmented earningsUpstream

$
2,295


$
1,524


$
713Midstream


482



495



240Refined Products


106



82



41Corporate and eliminations


(157
)


(98
)


12Net earnings

$
2,726


$
2,003


$
1,006Per shareBasic and diluted

$
6.43


$
4.72


$
2.37Dividends per common share

$
1.50


$
0.65


$
0.46Special dividend per common share

$



$
1.00


$
0.54Total assets

$
17,933


$
15,716


$
13,233Long-term debt excluding current
    portion

$
1,511


$
1,612


$
2,047Return on equity (percent)


31.8



29.2



17.0Return on average capital employed
    (percent)


27.0



22.8



13.0   1.4
    SELECTED
    QUARTERLY INFORMATION  2006


2005Q4


Q3


Q2


Q1


Q4


Q3


Q2


Q1($ millions, except where indicated)Sales and operating revenues, net
    of royalties

$
3,084


$
3,436


$
3,040


$
3,104


$
3,207


$
2,594


$
2,350


$
2,094Net earnings


542



682



978



524



669



556



394



384Per shareBasic and diluted


1.28



1.61



2.31



1.24



1.58



1.31



0.93



0.91Cash flow from operations


1,207



1,224



1,103



967



1,197



944



828



816Per shareBasic and diluted


2.84



2.88



2.60



2.28



2.82



2.23



1.95



1.93Share priceHigh


80.45



83.00



75.64



74.50



65.79



69.95



50.75



40.49Low


66.20



66.31



58.00



59.63



50.50



47.37



35.12



32.30Close (end of period)


78.04



71.96



70.06



70.65



59.00



64.57



48.73



36.33Shares traded (thousands)


41,889



30,786



39,674



39,543



38,731



34,521



46,988



46,370Dividends declared per common share


0.50



0.50



0.25



0.25



0.25



0.14



0.14



0.12Special dividend per common share


















1.00











Weighted average number of common
    shares outstanding (thousands)Basic and diluted


424,264



424,234



424,179



424,147



424,120



424,049



423,891



423,791   1.5
    MAJOR
    EVENTS IN 2006  East
    Coast
  
    completed sixth production well in November 2006, which
    increased White Rose productive capacity to approximately
    125 mbbls/day. During December 2006 total field production
    at White Rose averaged 116 mbbls/day (Huskys working
    interest share was 85 mbbls/day), an increase of 17% from
    November; and
    increased our holdings in the Jeanne dArc Basin with the
    acquisition of two exploration licences totalling 38,585 acres
    and increased our working interest in Significant Discovery
    Licences 1040 and 1008 with a farm-in. 4




---



##### Table of Contents



Oil
    Sands
  
    completed construction of the 100% working interest
    steam-assisted gravity drainage (SAGD) in-situ
    Tucker Oil Sands project. With a design rate capacity of 30
    mbbls/day of bitumen, the project will be ramped up to its
    capacity over the next two years. Proved reserves at
    December 31, 2006 were 60 mmbbls of bitumen; and
    increased our Saleski, Alberta oil sands holdings to 239,200
    acres.  Ethanol
  
    completed construction of Lloydminster ethanol plant. With a
    design rate capacity of 130 million litres of ethanol per
    year, the plant will participate in providing ethanol blending
    feedstock for the emerging market for ethanol blended gasoline.  Refining
  
    completed the second phase of the Prince George refinery clean
    fuels project to produce low-sulphur diesel and gasoline and
    increased productive capacity to 12 mbbls/day.  International
  
    increased our holdings in the South China Sea with an award of
    three exploration blocks totalling 16,871 square kilometres;
    natural gas discovery in the South China Sea at Liwan
    3-1-1; and
    increased our holdings in the north east Java Sea with the East
    Bawean II block.  Corporate
  
    redeemed the 8.45% senior secured bonds, due 2012, which had an
    outstanding balance of U.S. $85 million;
    received an improved credit rating from Standard and Poors
    Rating Service to BBB+ with a stable outlook; and
    renewed the shelf prospectus, which facilitates the issue of up
    to U.S. $1 billion of debt securities in the U.S. capital
    markets until October 2008.  2.
    CAPABILITY
    TO DELIVER RESULTS    2.1
    UPSTREAM    
    a large base of producing properties in Western Canada that
    generally respond well to increasingly sophisticated
    exploitation techniques and, we expect, will continue to provide
    a large proportion of cash flow necessary to undertake current
    and future major growth projects;
    significant natural gas potential in the deep basin, foothills
    and northwest plains;
    a dominant presence and extensive experience in the heavy oil
    producing areas in the Lloydminster region of Alberta and
    Saskatchewan;
    a recently developed SAGD oil sands project and substantial
    long-term growth potential in a number of the oil sands regions
    of Alberta;
    two major offshore producing oil fields in the Jeanne dArc
    Basin off the East Coast of Canada, combined with a large
    portfolio of significant discovery licences and exploration
    licences;
    significant opportunities to tie-back production from satellite
    fields to the existing White Rose production;
    increasing experience and number of developable projects and
    potential prospects in Southeast Asia; and
    the financial capacity to enhance our portfolio value through
    acquisitions. 5




---



##### Table of Contents




    increasing costs driven by the high level of oil and gas
    industry activity;
    labour market skills shortages;
    a highly competitive environment for materials, equipment and
    services;
    increasing difficulty and cost of managing the natural
    production declines of our properties in the Western Canada
    Sedimentary Basin;
    susceptibility of large complex operations to reliability issues
    and significant loss of cash flow during down-time;
    increasing activities of opposing special interest groups;
    increasing political pressure to implement fiscal regimes that
    might divert material cash flow available for
    investment; and
    increasing uncertainty of environmental issues that may delay,
    prevent or increase the costs of oil and gas development.  2.2
    MIDSTREAM    
    a modern, reliable heavy oil upgrading facility located in the
    Lloydminster heavy oil producing region, currently completing a
    number of debottlenecking projects and capable of major
    expansion;
    reliable heavy oil pipeline systems in the Lloydminster heavy
    oil producing region currently being expanded;
    participation in electrical/thermal cogeneration that can be
    utilized in our plant operations; and
    a commodity marketer capable of acting as a market balancer to
    both customer and supplier.    
    increasingly heavier crude feedstock requiring expansion and
    modification of our upgrader; and
    competition for pipeline capacity in heavy crude oil producing
    regions.  2.3
    REFINED
    PRODUCTS    
    an established niche market with prime marketing outlet
    locations and strategic land position;
    recently upgraded low sulphur gasoline and diesel fuel refinery
    in north central British Columbia;
    growing economies of scale for our increasing ethanol production;
    position as largest manufacturer of paving asphalt in Western
    Canada; and
    modern asphalt manufacturing facilities at Lloydminster, Alberta.    
    limited access to refining facilities sufficient to supply our
    refined product requirements;
    increased competition as motor fuel and related products are
    increasingly being offered by other industry retailers; and
    higher asphalt distribution costs as a result of plant locations
    and lack of asphalt distribution network in the United States
    and Eastern Canada.  2.4
    KEY
    PERFORMANCE DRIVERS AND MEASURES    
    find and develop proved reserves of crude oil and natural gas at
    a cost that is competitive with the industry; and
    acquire developed and undeveloped properties which complement
    our portfolio and provide enhanced potential for future
    sustainable growth. 6




---



##### Table of Contents




    competitively optimize production through effective exploitation
    techniques;
    make selective acquisitions and divestitures;
    maintain costs among the industrys lowest cost quartile
    performers;
    manage our operations in a safe and environmentally responsible
    manner;
    continue to proceed with the development of our major expansion
    projects in the Jeanne dArc Basin, the Alberta oil sands,
    the Madura Strait natural gas and NGL project;
    delineate our oil discovery in the Mackenzie Valley region of
    the Northwest Territories;
    delineate our natural gas prospect in the South China Sea; and
    complete the optimization and expansion assessment of the
    Lloydminster Upgrader.        Husky Common Shares


S&P/TSX Energy Index


S&P/TSX Composite Index(%)


(%)


(%)2002


0.00



(14.00
)


11.002003


43.00



24.42



24.322004


45.45



12.15



28.262005


72.12



22.50



59.892006


32.40



14.59



1.14Five-year average


36.51



10.93



23.47Five-year return


374.00



68.00



187.00   Revenue
    Performance
    Cost
    Performance
    Capital
    Performance
    People
    Performance
   7




---



##### Table of Contents



Health,
    Safety and Environmental Performance
    2.5
    THE
    BUSINESS ENVIRONMENT IN 2006    
    crude oil and natural gas prices;
    the price differential between light and discounted heavy crude
    oil and demand related to various crude oil qualities;
    the cost to find, develop, produce and deliver crude oil and
    natural gas;
    the availability of new proved reserves of oil and gas, sourced
    from exploration, improved recovery and acquisitions;
    potential actions of governments and regulatory authorities in
    the jurisdictions where we have operations;
    prevailing climatic conditions in our operating and marketing
    locations; and
    the exchange rate between the Canadian and U.S. dollar.  Average Benchmark Prices and U.S. Exchange Rate

2006


2005


2004WTI crude oil  (U.S.
    $/bbl)


66.22



56.56



41.40Brent crude
    oil  (U.S. $/bbl)


65.14



54.38



38.21Canadian par light crude 0.3%
    sulphur  ($/bbl)


73.29



69.28



52.91Lloyd heavy crude oil @
    Lloydminster  ($/bbl)


39.92



31.07



28.75NYMEX natural
    gas  (U.S. $/mmbtu)


7.23



8.62



6.14NIT natural
    gas  ($/GJ)


6.62



8.04



6.44WTI/Lloyd crude blend
    differential  (U.S. $/bbl)


22.00



21.01



13.65U.S./Canadian dollar exchange
    rate  (U.S. $)


0.882



0.826



0.769        8




---



##### Table of Contents



Crude
    Oil
  WTI
    and Husky Average Crude Oil Prices
  ($/bbl)
 
    Natural
    Gas
  NYMEX
    Natural Gas, NIT Natural Gas and Husky Average Natural Gas
    Prices
  (US$)
 
   9




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##### Table of Contents



SENSITIVITIES
    BY SEGMENT FOR 2006 RESULTS
    2006





Effect on Pre-tax


Effect onSensitivity Analysis

Average


Increase


Cash Flow


Net Earnings($ millions)


($/share)(5)


($ millions)


($/share)(5)Upstream and
    MidstreamWTI benchmark crude oil price

$
66.22


U.S. $
1.00/bbl



90



0.21



60



0.14NYMEX benchmark natural gas
    price(1)

$
7.23


U.S. $
0.20/mmbtu



37



0.09



24



0.06WTI/Lloyd crude blend
    differential(2)

$
19.95


U.S. $
1.00/bbl



(30
)


(0.07
)


(20
)


(0.05
)Exchange rate (U.S. $ per
    Cdn $)(3)

$
0.882


U.S. $
0.01



(69
)


(0.16
)


(47
)


(0.11
)Refined ProductsLight oil margins

$
0.04


Cdn $
0.005/litre



16



0.04



11



0.02Asphalt margins

$
9.88


Cdn $
1.00/bbl



9



0.02



6



0.01ConsolidatedYear-end translation of
    U.S. $ debt (U.S. $ per Cdn $)

$
0.858
(4)

U.S. $
0.01











9



0.02     (1)
    Includes decrease in earnings related to natural gas consumption.(2)
    Includes impact of upstream and upgrading operations only.(3)
    Assumes no foreign exchange gains or losses on U.S. dollar
    denominated long-term debt and other monetary items.(4)
    U.S./Canadian dollar exchange rate at December 31, 2006.(5)
    Based on December 31, 2006 common shares outstanding of
    424.3 million.  3.
    STRATEGY  3.1
    STRATEGIC
    IMPERATIVES  Strategic
    Objective and Measures
    Strategic
    Plans
  .
 10




---



##### Table of Contents



Upstream
    Strategies
  
    manage declining production in Western Canada through field and
    facility optimization, increased multi-zone development,
    increase applications of enhanced oil recovery techniques,
    property consolidation, development of new core areas and
    exploitation of non-conventional natural gas reservoirs;
    continue to explore for liquid rich natural gas reserves in the
    less mature, high-impact but technically challenging areas in
    the foothills, deep basin and northern plains;
    continue with exploration in the Central Mackenzie Valley and
    complete delineation and evaluation of the Stewart Creek natural
    gas discovery in conjunction with the Summit Creek natural gas
    and liquids discovery 26 kilometres northwest of Stewart Creek;
    continued delineation and development of the White Rose area
    satellite prospects and on our portfolio of significant
    discovery licences off the East Coast and also continue to
    explore for oil and gas on our large portfolio of exploration
    licences in the Jeanne dArc Basin offshore Newfoundland
    and Labrador;
    expand the productive capacity of the SeaRose FPSO to 140
    mbbls/day;
    continue to study development options for natural gas export
    from the Jeanne dArc Basin;
    continue to explore for oil and gas offshore China, delineate
    and evaluate the Liwan natural gas discovery on Block 29/26 in
    the Pearl River Mouth Basin;
    development of our Indonesian natural gas and NGL BD field in
    the East Java Sea and exploration on the Madura Strait and East
    Bawean II blocks;
    continue development of our large holdings in the Alberta oil
    sands area through in-situ recovery methods such as SAGD and
    other thermally based recovery techniques; and
    take advantage of acquisition opportunities to enhance our
    current core properties and create new ones.  Midstream
    Strategies
  
    continue to enhance performance of our upgrader and integrate
    the operation of the upgrader, asphalt refinery, cogeneration
    and ethanol facilities;
    complete front-end engineering design to expand the upgrader to
    150 mbbls/day;
    further expansion and integration of pipelines and facilities;
    expand natural gas storage capacity; and
    development of an integrated
    CO2
    strategy.  Refined
    Products Strategies
  
    continue to integrate Lloydminster asphalt refinery output with
    the upgrader;
    expand ethanol production in Western Canada;
    continue to pursue initiatives that promote asphalt standards
    and thereby recognize Huskys asphalt quality; and
    increase throughput per outlet through technology, new products
    and services.  Financial
    Objective and Strategies
    
    maintain debt to capitalization ratio of less than 40%; and
    maintain debt to cash flow from operations of less than two
    times.   11




---



##### Table of Contents



3.2
    MAJOR
    PROJECTS  UPSTREAM
  Western
    Canada Enhanced Oil Recovery
    East
    Coast Canada Exploration and Delineation
  
    In November 2006, we completed drilling of the North Amethyst
    K-15 delineation well in the Significant Discovery Licence
    (SDL) 1044 southwest of White Rose. The results were
    encouraging and analysis is continuing on this reservoir. Our
    working interest in SDL 1044 is 72.5%.
    In October 2006, we completed drilling of the West Bonne Bay
    F-12 delineation well and the F-12Z side track well in the SDL
    1040 block, which is adjacent to the Terra Nova field.
    Preliminary results indicate hydrocarbons in the Upper Hibernia
    Reservoir. Further analysis will determine more about the
    resources in this reservoir. Our working interest in SDL 1040 is
    27.78%.
    In June 2006, we completed drilling of the White Rose O-28
    delineation well and the O-28X side track well in the SDL 1024
    adjacent to the western border of the White Rose South Avalon
    field. The results were encouraging and an additional
    delineation well to determine the areal extent of the reservoir
    is planned for 2007. Our working interest in SDL 1024 is 72.5%.
    A 3-D
    seismic program was shot on Exploration Licence 1067, northwest
    of the White Rose oil field, covering 270 square kilometres and
    on Exploration Licence 1011 in the Fortune area, southwest of
    White Rose, covering 625 square kilometres. Our 2007 exploration
    and delineation drilling program currently includes three
    locations in the Jeanne dArc Basin.
    At Terra Nova, we are currently participating in a delineation
    well in the Far East Block.  White
    Rose
    Tucker
    Oil Sands Project
    Sunrise
    Oil Sands Project
      Caribou
    Lake and Saleski
     12




---



##### Table of Contents



Northwest
    Territories Exploration
    China
    Exploration
    3-D
  3-D
  mid-2008
  Indonesia
    Natural Gas Development
  3-D
  MIDSTREAM
  Lloydminster
    Upgrader
    Lloydminster
    Pipeline
  24-inch
  REFINED
    PRODUCTS
  Lloydminster
    and Minnedosa Ethanol Plants
   13




---



##### Table of Contents



4.
    RESULTS
    OF OPERATIONS    Segmented
    Earnings
  
  4.1
    UPSTREAM  2006
    EARNINGS $2,295 MILLION, UP $771 MILLION FROM 2005
  Earnings
    Summary and 2006 Variance Analysis
    
    higher sales volume of light crude oil from White Rose;
    higher crude oil prices; and
    lower natural gas royalties.    
    lower natural gas prices and sales volume;
    lower sales volume of light crude oil from Terra Nova and
    Wenchang;
    higher operating costs;
    higher depletion, depreciation and amortization; and
    higher income taxes.  14




---



##### Table of Contents



Upstream Earnings
    Summary

2006


2005


2004($ millions)Gross revenues

$
6,586


$
5,207


$
4,392Royalties


814



840



711Hedging loss










561Net revenues


5,772



4,367



3,120Operating and administration
    expenses


1,321



1,050



967Depletion, depreciation and
    amortization


1,476



1,144



1,077Income taxes


680



649



363Earnings

$
2,295


$
1,524


$
713   
  Operating
    costs
         15




---



##### Table of Contents



Depletion,
    Depreciation and Amortization
    (DD&A)
  country-by-country
        Production
  
  Daily Production, before
    Royalties

2006


2005


2004Light crude oil & NGL
    (mbbls/day)


111.0



64.6



66.2Medium crude oil (mbbls/day)


28.5



31.1



35.0Heavy crude oil & bitumen
    (mbbls/day)


108.1



106.0



108.9Total crude oil & NGL
    (mbbls/day)


247.6



201.7



210.1Natural gas (mmcf/day)


672.3



680.0



689.2Barrels of oil equivalent
    (6:1)(mboe/day)


359.7



315.0



325.0   Average Sales Prices

2006


2005


2004Crude oil($/bbl)Light crude oil & NGL

$
69.06


$
61.56


$
48.34Medium crude oil


49.48



43.44



36.13Heavy crude oil


39.92



31.09



28.66Total average


54.08



42.75



36.07Total average after hedging


54.08



42.75



28.43Natural gas($/mcf)Average

$
6.47


$
7.96


$
6.25Average after hedging


6.47



7.96



6.24  16




---



##### Table of Contents



Upstream Revenue Mix
    (1)

2006


2005


2004Percentage of upstream sales
    revenues, after royaltiesLight crude oil & NGL


45



29



27Medium crude oil


7



9



11Heavy crude oil & bitumen


24



24



27Natural gas


24



38



35Total


100



100



100   Effective Royalty Rates
    (1)

2006


2005


2004Percentage of upstream sales
    revenues, after royaltiesLight crude oil & NGL


8



14



13Medium crude oil


18



18



18Heavy crude oil


13



12



12Bitumen


1







Natural gas


18



20



22Total


13



16



16     (1)
    Before commodity hedging.  
 17




---



##### Table of Contents



Operating
    Netbacks
  Western Canada


East Coast


International


Total2006


2005


2004


2006


2005


2004


2006


2005


2004


2006


2005


2004Light Crude Oil(per boe)(1)Sales price

$
59.89


$
60.74


$
46.12


$
71.18


$
62.61


$
47.87


$
73.60


$
63.15


$
47.66


$
68.51


$
61.86


$
46.95Royalties


7.34



8.66



7.76



1.95



5.91



1.80



12.17



5.93



4.91



4.49



7.22



5.71Operating costs


11.89



9.86



8.94



5.48



5.14



3.28



3.81



2.92



2.16



6.96



6.88



5.8240.66



42.22



29.42



63.75



51.56



42.79



57.62



54.30



40.59



57.06



47.76



35.42Medium Crude Oil(per boe)(1)Sales price


48.97



43.67



36.20



























48.97



43.67



36.20Royalties


8.61



7.77



6.10



























8.61



7.77



6.10Operating costs


13.09



10.97



10.07



























13.09



10.97



10.0727.27



24.93



20.03



























27.27



24.93



20.03Heavy Crude Oil(per boe)(1)Sales price


39.91



31.22



28.73



























39.91



31.22



28.73Royalties


5.16



3.75



3.38



























5.16



3.75



3.38Operating costs


11.10



9.90



9.33



























11.10



9.90



9.3323.65



17.57



16.02



























23.65



17.57



16.02Total Crude Oil(per boe)(1)Sales price


44.90



38.91



33.48



71.18



62.61



47.87



73.60



63.15



47.66



53.55



42.83



35.72Royalties


6.14



5.41



4.75



1.95



5.91



1.80



12.17



5.93



4.91



5.28



5.49



4.58Operating costs


11.60



10.10



9.41



5.48



5.14



3.28



3.81



2.92



2.16



9.53



9.13



8.3627.16



23.40



19.32



63.75



51.56



42.79



57.62



54.30



40.59



38.74



28.21



22.78Natural Gas(per
    mcfge)(2)Sales price


6.65



8.02



6.25



























6.65



8.02



6.25Royalties


1.37



1.76



1.44



























1.37



1.76



1.44Operating costs


1.18



1.04



0.89



























1.18



1.04



0.894.10



5.22



3.92



























4.10



5.22



3.92Equivalent Unit(per boe)(1)Sales price


42.91



42.53



35.01



71.18



62.61



47.87



73.60



63.15



47.66



49.34



44.69



36.34Royalties


6.97



7.45



6.22



1.95



5.91



1.80



12.17



5.93



4.91



6.19



7.29



5.96Operating costs


9.79



8.59



7.85



5.48



5.14



3.28



3.81



2.92



2.16



8.77



8.12



7.32$
26.15


$
26.49


$
20.94


$
63.75


$
51.56


$
42.79


$
57.62


$
54.30


$
40.59


$
34.38


$
29.28


$
23.06     (1)
    Includes associated co-products converted to boe.(2)
    Includes associated co-products converted to mcfge.   Oil and
    Gas Reserves
  
 18




---



##### Table of Contents



www.sedar.com Form 40-F www.sec.gov www.huskyenergy.ca
    Crude Oil andNatural Gas

Proved Developed


Proved Undeveloped


Total Proved


Proved and ProbableReserves
    Summary(1)

2006


2005


2004


2006


2005


2004


2006


2005


2004


2006


2005


2004(constant prices and costs before royalties)Crude oil (mmbbls)Light & NGL


257



226



191



30



47



47



287



273



238



428



462



465Medium


79



80



80



8



11



6



87



91



86



102



105



96Heavy


135



140



91



78



77



14



213



217



105



289



291



150Bitumen


47











13



48







60



48







1,187



951



79518



446



362



129



183



67



647



629



429



2,006



1,809



790Natural gas (bcf)


1,703



1,710



1,745



440



426



424



2,143



2,136



2,169



2,626



2,709



2,724Total (mmboe)


802



731



653



202



254



138



1,004



985



791



2,444



2,260



1,244     (1)
    Refer to Section 13 for Oil and Gas Reserves definitions.  2006
    Reserve Additions
    Additions
    of Crude Oil and NGL
        Additions
    of Natural Gas
   19




---



##### Table of Contents



Canada


International


TotalWestern Canada


EastLight














CoastCrude


Medium


Heavy








Light


Light





CrudeOil &


Crude


Crude





Natural


Crude


Crude


Natural


Oil &


Natural


EquivalentReconciliation of Proved Reserves

NGL


Oil


Oil


Bitumen


Gas


Oil


Oil


Gas


NGL


Gas


Units(mmbbls)


(mmbbls)


(mmbbls)


(mmbbls)


(bcf)


(mmbbls)


(mmbbls)


(bcf)


(mmbbls)


(bcf)


(mmboe)(constant prices and costs before royalties)Proved reserves at
    December 31, 2005


167



91



217



48



2,136



89



17







629



2,136



985Technical revisions


(3
)


(1
)


(2
)


(1
)


(87
)


31



2







26



(87
)


11Purchase of reserves in place


1



1











25















2



25



6Sale of reserves in place


(1
)














(3
)














(1
)


(3
)


(1
)Discoveries, extensions and
    improved recovery


13



6



37



13



317



12











81



317



134Production


(11
)


(10
)


(39
)






(245
)


(25
)


(5
)






(90
)


(245
)


(131
)Proved reserves at
    December 31, 2006


166



87



213



60



2,143



107



14







647



2,143



1,004Proved and probable
    reservesAt December 31, 2006


219



102



289



1,187



2,533



186



23



93



2,006



2,626



2,444At December 31, 2005


225



105



291



951



2,542



207



30



167



1,809



2,709



2,260  20




---



##### Table of Contents



Canada


International


TotalEastWestern Canada


CoastLightCrude


Medium


Heavy








Light


Light


CrudeOil &


Crude


Crude





Natural


Crude


Crude


Oil &


Natural


EquivalentReconciliation of Proved Developed Reserves

NGL


Oil


Oil


Bitumen


Gas


Oil


Oil


NGL


Gas


Units(mmbbls)


(mmbbls)


(mmbbls)


(mmbbls)


(bcf)


(mmbbls)


(mmbbls)


(mmbbls)


(bcf)


(mmboe)(constant prices and costs before royalties)Proved developed reserves at
    December 31, 2005


151



80



140







1,710



59



16



446



1,710



731Revision of previous estimate


2



6



17



47



63



58



2



132



63



142Purchase of reserves in place


1



1











14











2



14



4Sale of reserves in place


(1
)














(3
)










(1
)


(3
)


(1
)Improved recovery


5



2



17







164



5







29



164



57Production


(11
)


(10
)


(39
)






(245
)


(25
)


(5
)


(90
)


(245
)


(131
)Proved developed reserves at
    December 31, 2006


147



79



135



47



1,703



97



13



518



1,703



802   Upstream
    Capital Expenditures
  Capital
    Expenditures(1)

2006


2005


2004($ millions)ExplorationWestern Canada

$
497


$
389


$
322East Coast Canada and Frontier


79



66



24International


77



55



18653



510



364DevelopmentWestern Canada


1,675



1,618



1,211East Coast Canada


279



579



515International


20



23



671,974



2,220



1,793$
2,627


$
2,730


$
2,157    (1)
    Excludes capitalized costs related to asset retirement
    obligations incurred during the period and corporate
    acquisitions.  2006


2005


2004Western Canada
    Drilling

Gross


Net


Gross


Net


Gross


Net(wells)ExplorationOil


101



99



89



85



45



39Gas


330



192



392



196



234



180Dry


26



24



36



36



34



33457



315



517



317



313



252DevelopmentOil


590



543



466



433



552



499Gas


565



490



610



551



807



740Dry


25



22



42



39



57



531,180



1,055



1,118



1,023



1,416



1,292Total


1,637



1,370



1,635



1,340



1,729



1,544  21




---



##### Table of Contents



Canada
                International
  3-D
     22




---



##### Table of Contents



4.2
    MIDSTREAM  2006
    EARNINGS $482 MILLION, DOWN $13 MILLION FROM
    2005
    Upgrader
  
    Upgrading
    Earnings Summary and 2006 Variance Analysis
  Upgrading Earnings
    Summary

2006


2005


2004($ millions, exceptwhere indicated)Gross margin

$
624


$
692


$
383Operating costs


224



228



214Other recoveries


(6
)


(6
)


(5
)Depreciation and amortization


24



21



19Income taxes


97



136



43Earnings

$
285


$
313


$
112Upgrader
    throughput(1)  (mbbls/day)


71.0



66.6



64.6Synthetic crude oil
    sales  (mbbls/day)


62.5



57.5



53.7Upgrading
    differential  ($/bbl)

$
26.16


$
30.70


$
17.79Unit
    margin  ($/bbl)

$
27.35


$
33.01


$
19.48Unit operating
    cost(2)  ($/bbl)

$
8.65


$
9.38


$
9.07    (1)
    Throughput includes diluent returned to the field.(2)
    Based on throughput. 23




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##### Table of Contents



Upgrading
    Earnings Variance Analysis
  ($
    millions)
  
  Upgrading
    Differential
    Infrastructure
    and Marketing Earnings Summary and 2006 Variance
    Analysis
    Infrastructure and Marketing
    Earnings Summary

2006


2005


2004($ millions, exceptwhere indicated)Gross marginPipeline

$
104


$
92


$
84Other infrastructure and marketing


208



217



136312



309



220Other expenses


11



10



8Depreciation and amortization


24



21



21Income taxes


80



96



63Earnings

$
197


$
182


$
128Aggregate pipeline
    throughput  (mbbls/day)


475



474



492  24




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##### Table of Contents



Midstream
    Capital Expenditures
    4.3
    REFINED
    PRODUCTS  2006
    EARNINGS $106 MILLION, UP $24 MILLION FROM
    2005
    Light
    Oil Product Marketing
    Asphalt
    Products  
    
    higher margins for gasoline and distillates;
    higher ancillary income;
    higher sales volume of asphalt products;
    lower administrative costs; and
    lower income taxes.    
    higher depreciation; and
    lower sales volume of gasoline and distillates. 25




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##### Table of Contents



Earnings
    Summary and Variance Analysis
  Refined Products Earnings
    Summary

2006


2005


2004($ millions, exceptwhere indicated)Gross marginFuel sales

$
138


$
126


$
93Ancillary sales


36



34



30Asphalt sales


94



91



51268



251



174Operating and other expenses


74



75



71Depreciation and amortization


48



47



38Income taxes


40



47



24Earnings

$
106


$
82


$
41Number of fuel outlets


505



515



531Refined products sales volumeLight oil
    products  (million litres/day)


8.7



8.9



8.4Light oil products per
    outlet  (thousand litres/day)


12.9



12.7



11.7Asphalt
    products  (mbbls/day)


23.4



22.5



22.8Refinery throughput Prince George
    refinery  (mbbls/day)


9.0



9.7



9.8Lloydminster
    refinery  (mbbls/day)


27.1



25.5



25.3Ethanol
    production  (thousand litres/day)


59.7



25.6



26.0   Refined
    Products Margins
    Refined
    Products Capital Expenditures
    Integration
    4.4
    CORPORATE  2006
    EXPENSE $157 MILLION, UP $59 MILLION FROM
    2005
    
    lower capitalized interest consistent with the commissioning of
    major projects;
    2005 expenses offset by proceeds of a one-time litigation
    settlement, similar proceeds absent in 2006; and
    increased administration expenses consistent with higher staff
    levels.    
    lower intersegment profit eliminations;
    lower stock-based compensation; and
    lower debt costs.  26




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##### Table of Contents



Corporate Earnings
    Summary

2006


2005


2004($ millions) income(expense)Intersegment
    eliminations  net

$
20


$
(50
)

$
(14
)Administration expenses


(35
)


(19
)


(27
)Stock-based compensation


(138
)


(171
)


(67
)Accretion


(3
)


(2
)


(2
)Other  net


(23
)


49



(8
)Depreciation and amortization


(27
)


(23
)


(24
)Interest on debt


(125
)


(146
)


(135
)Interest capitalized


33



114



75Foreign exchange


24



31



120Income taxes


117



119



94Earnings (loss)

$
(157
)

$
(98
)

$
12   Foreign Exchange
    Summary

2006


2005


2004($ millions)(Gain) loss on translation of
    U.S. dollar denominated long-term debt Realized





$
(42
)





$
(13
)





$
(10
)Unrealized






35







(38
)






(140
)(7
)






(51
)






(150
)Cross currency swapsRealized






47















Unrealized






(43
)






14







274







14







27Other (gains) losses






(21
)






6







3$
(24
)





$
(31
)





$
(120
)U.S./Canadian dollar exchange
    rates:At beginning of year


U.S.


$
0.858



U.S.


$
0.831



U.S.


$
0.774At end of year


U.S.


$
0.858



U.S.


$
0.858



U.S.


$
0.831   Foreign
    Exchange Risk
      Corporate
    Capital Expenditures
    Consolidated
    Income Taxes
   27




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##### Table of Contents



2006


2005


2004($ millions)Income taxes before tax amendments

$
1,108


$
813


$
439Canadian federal and provincial
    tax amendments


328



4



40Income taxes as reported

$
780


$
809


$
399   Huskys Canadian Tax
    Pools

2006


2005


2004($ millions)Canadian exploration expense

$
117


$
78


$
Canadian development expense


2,136



2,033



1,616Canadian oil and gas property
    expense


666



721



557Foreign exploration and
    development expense


252



240



212Undepreciated capital costs


4,644



4,249



3,269Other


21



27



22$
7,836


$
7,348


$
5,676   4.5
    2005
    COMPARED WITH 2004      Upstream
  
    higher crude oil and natural gas prices; and
    absence of commodity price hedging loss in 2005.    
    lower sales volume of crude oil and natural gas;
    higher operating costs and DD&A;
    higher royalties; and
    higher income taxes.  Midstream
  
    wider upgrading differential;
    higher sales volume of synthetic crude oil;
    higher income from oil and gas commodity marketing;
    higher heavy crude oil tariffs;
    higher Lloyd blend marketing margins;
    higher crude oil and NGL trading; and
    higher cogeneration income. 28




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##### Table of Contents




    lower heavy crude oil pipeline throughput;
    higher energy and non-energy related unit operating costs; and
    higher income taxes.  Refined Products
  
    higher marketing margins and sales volume for gasoline and
    distillates;
    higher marketing margins of asphalt products; and
    higher restaurant and convenience store income.    
    slightly lower sales volume of asphalt products;
    higher depreciation and amortization; and
    higher income taxes.  Corporate
  
    higher intersegment profit eliminated;
    higher stock-based compensation;
    higher interest costs;
    lower foreign exchange gains on translation of U.S. dollar
    denominated debt; and
    provision for retrospective insurance premiums in respect of
    past claims on a mutual insurance consortium.    
    proceeds from a litigation settlement; and
    higher capitalized interest resulting from a higher capital base
    for the White Rose and Tucker projects.  5.
    2007
    OUTLOOK  5.1
    GENERAL
    ECONOMY    5.2
    2007
    CAPITAL PROGRAM    2007
    Estimate(1)($ millions)UpstreamWestern Canada  oil and
    gas

$
1,840
    oil sands


330East Coast Canada


290International


1602,620Midstream


380Refined Products


140Corporate


40$
3,180     (1)
    Excludes capitalized administrative costs and capitalized
    interest. 29




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##### Table of Contents



5.3
    UPSTREAM  Production Outlook

2007


2006 ActualLight crude oil &
    NGL  (mbbls/day)


128 - 135



111Medium crude
    oil  (mbbls/day)


28 - 30



29Heavy crude oil &
    bitumen  (mbbls/day)


122 - 130



108Total crude oil &
    NGL  (mbbls/day)


278 - 295



248Natural
    gas  (mmcf/day)


670 - 690



672Barrels of oil equivalent
    (6:1)  (mboe/day)


390 - 410



360   Western
    Canada Conventional
        Oil
    Sands
    
    complete a downstream solution that addresses infrastructure,
    upgrading and refining;
    ramp up production at Tucker to an average of 12 to 18 mbbls/day
    of bitumen during 2007;
    complete Sunrise front-end engineering design and sanction by
    the fourth quarter of 2007;
    commence preliminary design and evaluation of a small project in
    the Caribou Lake oil sands area; and
    commence submission of a pilot project to test various recovery
    techniques over the next few years in the Saleski oil sands area.    Canada 
    East Coast and Northwest Territories
       30




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##### Table of Contents



China and
    Indonesia
      5.4
    MIDSTREAM    5.5
    REFINED
    PRODUCTS    6.
    LIQUIDITY
    AND CAPITAL RESOURCES  6.1
    SUMMARY
    OF CASH FLOW  2006


2005


2004($ millions, exceptwhere indicated)Cash flow  operating
    activities

$
5,009


$
3,650


$
2,304
    financing activities

$
(1,626
)

$
(668
)

$
193
    investing activities

$
(3,109
)

$
(2,814
)

$
(2,497
)Debt to capital
    employed (percent)


14.3



20.1



25.8Corporate reinvestment
    ratio (percent)(1)


70



80



110     (1)
    Reinvestment ratio is based on net capital expenditures
    including corporate acquisitions.  Cash
    Flow from Operating Activities
    Cash Flow
    from (used for) Financing Activities
      Cash
    Flow used for Investing Activities
   31




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##### Table of Contents



6.2
    WORKING
    CAPITAL COMPONENTS    2006


2005


Change($ millions)Current assetsCash and cash equivalents

$
442


$
168


$
274


Excess cash generated by White RoseAccounts receivable


1,284



856



428


Repaid securitization program;
    higher crude oil pricesInventories


428



471



(43
)

Lower crude oil feedstock volumes
    in 2006Prepaid expenses


25



40



(15
)

Primarily Tucker construction
    advance in 20052,179



1,535



644Current liabilitiesAccounts payable


1,268



1,213



(55
)

Increased White Rose activity;
    refined product purchases in 2006Accrued interest payable


27



41



14


Lower long-term debt due to
    repaymentsIncome taxes payable


615



164



(451
)

2006 White Rose earnings; 2005
    deferred earningsOther accrued liabilities


664



892



228


Special dividend in 2005; higher
    stock-based compensation liability in 2006Long-term debt due within one year


100



274



174


Repayment of 7.125% notes and
    8.45% bonds2,674



2,584



(90
)Working capital

$
(495
)

$
(1,049
)

$
554   Sources
    and Uses of Cash
   32




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##### Table of Contents



Sources and Uses of Cash (continued)
    Sources and Uses of
    Cash

2006


2005


2004($ millions)Cash sourcedCash flow from
    operations(1)

$
4,501


$
3,785


$
2,197Debt issue


1,226



3,235



2,200Asset sales


34



74



36Proceeds from exercise of stock
    options


3



6



18Proceeds from monetization of
    financial instruments






39



85,764



7,139



4,459Cash usedCapital expenditures


3,171



3,068



2,349Corporate acquisitions










102Debt repayment


1,493



3,502



1,941Special dividend on common shares






424



229Ordinary dividends on common shares


636



276



195Settlement of asset retirement
    obligations


36



41



40Settlement of cross currency swap


47







Other


13



32



245,396



7,343



4,880Net cash (deficiency)


368



(204
)


(421
)Increase (decrease) in non-cash
    working capital


(94
)


372



421Increase in cash and cash
    equivalents


274



168



Cash and cash
    equivalents  beginning of year


168







Cash and cash
    equivalents  end of year

$
442


$
168


$
     (1)
    Cash flow from operations represents net earnings plus items not
    affecting cash, which include accretion, depletion, depreciation
    and amortization, future income taxes and foreign exchange.  December 31, 2006Outstanding


AvailableCapital Structure

(U.S. $)


(Cdn $)


(Cdn $)($ millions)Short-term bank debt

$



$



$
201Long-term bank debt Syndicated
    credit facility










1,020Bilateral credit facility










150Medium-term notes






300Capital securities


225



262U.S. public notes


900



1,049Total short-term and long-term debt

$
1,125


$
1,611


$
1,371Common shares and retained earnings





$
9,620        33




---



##### Table of Contents



Sources and Uses of Cash (continued)
               Credit
    Ratings
    6.3
    CASH
    REQUIREMENTS  Contractual
    Obligations and Other Commercial Commitments
    Contractual ObligationsPayments due by period

Total


2007


2008-2009


2010-2011


Thereafter($ millions)Long-term debt and interest

$
2,296


$
209


$
638


$
136


$
1,313Operating leases


1,133



93



494



450



96Firm transportation agreements


626



169



202



108



147Unconditional purchase
    obligations(1)


4,201



2,144



1,908



136



13Lease rentals and exploration work
    agreements


640



148



147



178



167Engineering and construction
    commitments


140



140











$
9,036


$
2,903


$
3,389


$
1,008


$
1,736     (1)
    Includes purchase of refined petroleum products, processing
    services, distribution services, insurance premiums and natural
    gas purchases. Approximately 72% of the total unconditional
    purchase obligations are in respect of processing and refined
    product purchase contracts.  Estimated
    Obligations Not Included in the Table
  
    Asset retirement obligations (ARO)Husky currently includes such obligations in the amortizing base
    of its oil and gas properties. Effective January 1, 2004,
    with the adoption of the Canadian Institute of Chartered
    Accountants (CICA) section 3110, Asset
    Retirement Obligations, Husky records a separate liability
    for the fair value of its ARO. See Note 12 to the
    Consolidated Financial Statements. 34




---



##### Table of Contents




    Employee future benefitsHusky has a defined contribution pension plan and a
    post-retirement health and dental care plan for its employees.
    In addition, Husky has a defined benefit pension plan for
    approximately 180 active employees and 480 retirees and
    beneficiaries. In 1991, admittance to the defined benefit
    pension plan ended after the majority of members transferred to
    the newly created defined contribution pension plan. See
    Note 16 to the Consolidated Financial Statements.  Other
    Obligations
    6.4
    OFF-BALANCE
    SHEET ARRANGEMENTS    Accounts
    Receivable Securitization Program
      Standby
    Letters of Credit
    Derivative
    Instruments
    6.5
    TRANSACTIONS
    WITH RELATED PARTIES AND MAJOR CUSTOMERS      6.6
    FINANCIAL
    RISK AND RISK MANAGEMENT    Commodity
    Price Risk Management
    Power
    Consumption
   35




---



##### Table of Contents



Foreign
    Currency Risk Management
    
    U.S. $150 million at 6.25% swapped at $1.41 to
    $212 million at 7.41% until June 15, 2012.
    U.S. $75 million at 6.25% swapped at $1.19 to
    $90 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.        Interest
    Rate Risk Management
          6.7
    OUTSTANDING
    SHARE DATA    
    unlimited number of common shares
    unlimited number of preferred shares    


common shares


424,289,808


preferred shares


none


stock options


5,605,630


stock options exercisable


2,243,766
     7.
    APPLICATION
    OF CRITICAL ACCOUNTING ESTIMATES     36




---



##### Table of Contents



7.1
    FULL COST
    ACCOUNTING FOR OIL AND GAS ACTIVITIES      
    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.    
    previously estimated proved oil and gas reserves; and
    estimated proved reserves added compared to capital invested.  Depletion
    Expense
    Withheld
    Costs
    Ceiling
    Test
    7.2
    IMPAIRMENT
    OF LONG-LIVED ASSETS    7.3
    FAIR
    VALUE OF DERIVATIVE INSTRUMENTS       37




---



##### Table of Contents



7.4
    ASSET
    RETIREMENT OBLIGATIONS        7.5
    LEGAL,
    ENVIRONMENTAL REMEDIATION AND OTHER CONTINGENT MATTERS    7.6
    INCOME
    TAX ACCOUNTING    7.7
    BUSINESS
    COMBINATIONS    7.8
    GOODWILL   38




---



##### Table of Contents



7.9
    VARIABLE
    INTEREST ENTITIES      8.
    NEW
    ACCOUNTING STANDARDS  8.1
    CANADIAN
    ACCOUNTING  Non-monetary
    Transactions
    8.2
    U.S.
    ACCOUNTING  Accounting
    for Defined Benefit Pension Plans and Other Post-retirement
    Benefit Plans
    Accounting
    for Purchases and Sales of Inventory with the Same
    Counterparty
  work-in-progress
 39




---



##### Table of Contents



Quantifying
    Financial Statement Misstatements
    9.
    PENDING
    ACCOUNTING STANDARDS  9.1
    CANADIAN
    ACCOUNTING PRONOUNCEMENTS  Financial
    instruments
    
    Section 1530, Comprehensive Income;
    Section 3855, Financial Instruments 
    Recognition and Measurement; and
    Section 3865, Hedges.          Financial
    Instruments  Disclosures and
    Presentation
   40




---



##### Table of Contents



Capital
    Disclosures
    Accounting
    Changes
    Determining
    the Variability to be Considered in Applying
    AcG-15
    
    when an entity is a variable interest entity;
    which interests are variable interests in the entity; and
    which party, if any, is the primary beneficiary of the variable
    interest entity.    9.2
    U.S.
    ACCOUNTING PRONOUNCEMENTS  Fair
    Value Measurement
    Accounting
    for Uncertainty in Income Taxes
   41




---



##### Table of Contents



Accounting
    for Planned Major Maintenance Activities
    10.
    FORWARD-LOOKING
    STATEMENTS      
    adequacy of and fluctuations in oil and natural gas prices;
    demand for our products and services and the cost of required
    inputs;
    our ability to replace our reserves;
    competitive actions of other companies, including increased
    competition from other oil and gas companies or from companies
    that provide alternate sources of energy;
    the occurrence of unexpected events such as fires, blowouts,
    freeze-ups, equipment failures, natural disasters and other
    similar events affecting us or other parties whose operations or
    assets directly or indirectly affect us and that may or may not
    be financially recoverable;
    actions by governmental authorities, including changes in
    environmental and other regulations that may impose restrictions
    in areas where we operate; and
    the accuracy of our oil and gas reserve estimates and estimated
    production levels as they are affected by our success at
    exploration and development drilling and related activities and
    estimated decline rates. 42




---



##### Table of Contents



11.
    OIL AND
    GAS RESERVE REPORTING  DISCLOSURE
    OF PROVED OIL AND GAS RESERVES AND OTHER OIL AND GAS
    INFORMATION
  (NI 51-101). Rule 4-10 Regulation S-X NI 51-101.
    CAUTIONARY
    NOTE TO U.S. INVESTORS
  Form 40-F
  12.
    NON-GAAP
    MEASURES  DISCLOSURE
    OF CASH FLOW FROM OPERATIONS
    2006


2005


2004($ millions)Non-GAAPCash flow from operations

$
4,501


$
3,785


$
2,197Settlement of asset retirement
    obligations


(36
)


(41
)


(40
)Change in non-cash working capital


544



(72
)


169GAAPCash flow  operating
    activities

$
5,009


$
3,672


$
2,326  43




---



##### Table of Contents



13.
    ADDITIONAL
    READER ADVISORIES  Intention
    of Managements Discussion and Analysis
    Review
    by the Audit Committee
    Additional
    Husky Documents Filed with Securities Commissions
  Form 40-F
  Use of
    Pronouns and Other Terms
    Standard
    Comparisons in this Document
    Reclassifications
    and Materiality for Disclosures
    Additional
    Reader Guidance
    
    Financial information is presented in accordance with GAAP in
    Canada. Significant differences between Canadian and United
    States GAAP are disclosed in Note 19 to the Consolidated
    Financial Statements.
    Currency is presented in millions of Canadian dollars.
    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.  14.
    CONTROLS
    AND PROCEDURES  Disclosure
    Controls and Procedures
   44




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##### Table of Contents



Managements
    Annual Report on Internal Control Over Financial
    Reporting
    (1)
    Huskys management is responsible for establishing and
    maintaining adequate internal control over financial reporting
    for Husky. All internal control systems, no matter how well
    designed, have inherent limitations. Therefore, even those
    systems determined to be effective can provide only reasonable
    assurance with respect to financial statement preparation and
    presentation.(2)
    Huskys management has used the Committee of Sponsoring
    Organizations of the Treadway Commission (COSO)
    framework to evaluate the effectiveness of Huskys internal
    control over financial reporting.(3)
    As at December 31, 2006, 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 no material weaknesses
    in Huskys internal control over financial reporting have
    been identified by management.(4)
    KPMG llp, who has
    audited the Consolidated Financial Statements of Husky for the
    year ended December 31, 2006, has also issued a report on
    Huskys financial statements and internal controls under
    Auditing Standard No. 2 of the Public Company Accounting
    Oversight Board (United States). This report is located with
    Huskys Consolidated Financial Statements and
    Auditors Report to Shareholders for the Year Ended
    December 31, 2006.  Changes
    in Internal Control over Financial Reporting
   45




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##### Table of Contents



ABBREVIATIONS
  bbls
    
    barrelsbps
    
    basis pointsmbbls
    
    thousand barrelsmbbls/day
    
    thousand barrels per
    daymmbbls
    
    million barrelsmcf
    
    thousand cubic feetmmcf
    
    million cubic feetmmcf/day
    
    million cubic feet per
    daybcf
    
    billion cubic feettcf
    
    trillion cubic feetboe
    
    barrels of oil
    equivalentmboe
    
    thousand barrels of oil
    equivalentmboe/day
    
    thousand barrels of oil
    equivalent per daymmboe
    
    million barrels of oil
    equivalentmcfge
    
    thousand cubic feet of gas
    equivalentGJ
    
    gigajoulemmbtu
    
    million British Thermal
    Unitsmmlt
    
    million long tonsMW
    
    megawattMWh
    
    megawatt hourNGL
    
    natural gas liquidsWTI
    
    West Texas
    IntermediateNYMEX
    
    New York Mercantile
    ExchangeNIT
    
    NOVA Inventory
    TransferLIBOR
    
    London Interbank Offered
    RateCDOR
    
    Certificate of Deposit Offered
    RateSEDAR
    
    System for Electronic Document
    Analysis and RetrievalFPSO
    
    Floating production, storage and
    offloading vesselFEED
    
    Front-end engineering
    designOPEC
    
    Organization of Petroleum
    Exporting CountriesWCSB
    
    Western Canada Sedimentary
    BasinSAGD
    
    Steam-assisted gravity
    drainage  TERMS
 Bitumen
    
    A naturally occurring viscous
    mixture consisting mainly of pentanes and heavier hydrocarbons.
    It is more viscous than 10 degrees APICarbonate
    
    Sedimentary rock primarily
    composed of calcium carbonate (limestone) or calcium magnesium
    carbonate (dolomite) which forms many petroleum
    reservoirsCapital Employed
    
    Short- and long-term debt and
    shareholders equityCapital Expenditures
    
    Includes capitalized
    administrative expenses and capitalized interest but does not
    include proceeds or other assetsCapital Program
    
    Capital expenditures not
    including capitalized administrative expenses or capitalized
    interestCash Flow from Operations
    
    Earnings from operations plus
    non-cash charges before settlement of asset retirement
    obligations and change in non-cash working capitalCoalbed Methane
    
    Methane (CH4), the principal
    component of natural gas, is adsorbed in the pores of coal
    seamsDated Brent
    
    Prices which are dated less than
    15 days prior to loading for deliveryDesign Rate Capacity
    
    Maximum continuous rated output
    of a plant based on its designDiluent
    
    A light liquid hydrocarbon,
    usually condensate, added to heavy oil to permit transportation
    through a pipelineEquity
    
    Shares and retained
    earningsFeedstock
    
    Raw materials which are
    processed into petroleum productsFront-end Engineering Design
    
    Preliminary engineering and
    design planning, which among other things, identifies project
    objectives, scope, alternatives, specifications, risks, costs,
    schedule and economicsGross/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
    companyGross Reserves/Production
    
    A companys working
    interest share of reserves/production before deduction of
    royaltiesHectare
    
    One hectare is equal to 2.47
    acresNear-month Prices
    
    Prices quoted for contracts for
    settlement during the next monthNOVA 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 pipelinePolymer
    
    A substance which has a
    molecular structure built up mainly or entirely of many similar
    units bonded togetherSection
    
    Area that is one square mile or
    640 acresSurfactant
    
    A substance that tends to reduce
    the surface tension of a liquid in which it is
    dissolvedTotal Debt
    
    Long-term debt including current
    portion and bank operating loans  Oil and
    Gas Reserves definitions
 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 then 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.




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##### Table of Contents



Exhibit No.

Description23
.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).