##### Table of Contents





2007
   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, 2007
    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 outstanding as of December 31, 2007
  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. Form 40-F. Form 40-F.
  C.
    Reconciliation
    to Accounting Principles Generally Accepted in the United
    States  Form 40-F. Form 40-F.
  D.
    Managements
    Discussion and Analysis  Form 40-F.
  Certificates
  Form 40-F.
  Controls
    and Procedures
  Form 40-F.
  Managements
    Annual Report on Internal Control Over Financial
    Reporting
  Attestation
    of the Registered Public Accounting Firm
  Form 40-F.
  Change in
    Internal Control Over Financial Reporting
  Form 40-F.
  Notice
    Pursuant to Regulation BTR
    Audit
    Committee Financial Expert
  Form 40-F) Form 40-F,
 ii




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www.sedar.com Form 40-F.
  Code
    of Business Conduct and Ethics
  www.huskyenergy.ca
  i.
    amends any provision of its Code of Business Conduct that
    applies to its principal executive officer, principal financial
    officer, principal accounting officer or controller or persons
    performing similar functions that relates to any element of the
    code of ethics definition enumerated in paragraph (9)(b) of
    General Instruction B to
    Form 40-F, orii.
    grants a waiver, including an implicit waiver, from a provision
    of its Code of Business Conduct to any of its principal
    executive officer, principal financial officer, principal
    accounting officer or controller or persons performing similar
    functions that relates to one or more of the items set forth in
    paragraph (9)(b) of General Instruction B to
    Form 40-F,    Principal
    Accountant Fees and Services
  Form 40-F.
  Off-balance
    Sheet Arrangements
  Form 40-F.
  Disclosure
    of Contractual Obligations
  Form 40-F.
  Identification
    of the Audit Committee
    UNDERTAKING
    AND CONSENT TO SERVICE OF PROCESS
  Undertaking
  Form F-9; Form 40-F
  Consent
    to Service of Process
  Form F-X Forms F-9
  Form F-X
 iii




---



##### Table of Contents



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 iv




---



##### Table of Contents



Document
    AForm 40-F
     ANNUAL
    INFORMATION FORM
  For the Year Ended December 31, 2007




---



##### Table of Contents



Husky
    Energy Inc.
  Annual Information
    Form
  For the Year Ended
    December 31, 2007
  March 10, 2008




---



##### 



TABLE OF
    CONTENTS
  PageExchange Rate Information


2Disclosure of Exemption Under National
    Instrument
    51-101


2Corporate Structure


3Husky Energy Inc.


3Intercorporate Relationships


4General Development of Husky


4Three Year History of Husky


4Business Environment Trends


6Description of Huskys Business


7Social and Environmental Policy


7Risk Factors


7Upstream Operations


9Disclosures of Oil and Gas Activities


9Description of Major Properties and Facilities


29Distribution of Oil and Gas Production


45Midstream Operations


46Downstream Operations


50Human Resources


55Dividends


55Description of Capital Structure


55Market for Securities


57Directors and Officers


57Audit Committee


58Legal Proceedings


59Interest of Management and Others in Material
    Transactions


59Transfer Agent and Registrars


60Interests of Experts


60Additional Information


60Abbreviations and Glossary of Terms


61Special Note Regarding Forward-looking
    Statements


66Schedules


68A  Audit Committee Charter


68B  Report on Reserves Data by
    Qualified Reserves Evaluator


72C  Report of Management and Directors
    on Reserves Data and
    Other Information


74D  Independent Engineers Audit
    Opinion


76         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.
 1




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##### Table of Contents



This Annual Information Form contains forward-looking
    information and statements
    within the meaning of applicable securities laws. For a full
    discussion of the forward-looking
    information and statements and the risks to which they are
    subject, see the
    Special Note Regarding Forward-Looking Statements
    on page 66 of this Annual Information Form.
  EXCHANGE
    RATE INFORMATION    Year ended December 312007


2006


2005Year end


0.988



1.165



1.166Low


0.917



1.095



1.151High


1.185



1.179



1.210Average


1.074



1.134



1.211       (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  51-101 51-101). NI 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 paragraphs .103, .106, .107, .108, .112, .160
    through .167, .174 through .184 and .401 through .408;
    SEC Industry Guide 2;
    SEC Item 102 of
    regulation S-K
    (17 CFR 229.102);
    SEC Item 302(b) of
    Regulation S-K
    (17 CFR 229.302(b)); and
    The definitions and disclosures required by SEC
    Regulation S-X
    (CFR 210.4-10).  51-101.
  51-101 51-101
  51-101 51-101
 2




---



##### Table of Contents



51-315 51-101 Standards of Disclosure for Oil and Gas
    Activities. 51-101
      51-101
  www.sedar.com Form 40-F www.sec.gov
 CORPORATE
    STRUCTURE Husky
    Energy Inc.  Business Corporations Act
   3




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##### 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.

DelawareHusky Refining Company

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 Husky Refining CompanyLima Refining Company

DelawareHusky Marketing and Supply Company

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  2005
      2006
           4




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##### Table of Contents



29 06 35 18 50 14
            2007
                 5




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##### Table of Contents



Subsequent
    Events
    Events
    expected to occur during 2008
    Business
    Environment Trends  (1) (1)
    (2)
  (3)
     (1)
    Canadian Crude Oil Production and Supply forecast,
    July 2004, Canadian Association of Petroleum Producers Oil
    Sands Technology Roadmap, January 30, 2004, Alberta
    Chamber of Resources.(2)
    Short-Term Energy Outlook January 8, 2008 Energy
    Information Administration U.S. Department of Energy.(3)
    Short-Term Energy Outlook February 11, 2008 Energy
    Information Agency U.S. Department of Energy. 6




---



##### Table of Contents



DESCRIPTION
    OF HUSKYS BUSINESS           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
   7




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##### Table of Contents



Competition
    Delays
    and cost overruns of capital projects
    
    availability of skilled labour;
    availability of manufacturing capacity, supplies, material and
    equipment;
    regulatory approvals;
    faulty construction and design errors;
    accidents, labour disruptions, bankruptcies and productivity
    issues affecting us directly or indirectly; and
    unexpected changes in the scope of a project.  Business
    interruption of operations
      Foreign
    Exchange Risk
    Environmental
    risks
     8




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##### Table of Contents



clean-up
        Changes
    to government fiscal policy may reduce our cash flow
    UPSTREAM
    OPERATIONS Disclosures
    of Oil and Gas Activities    Production
 2007Western


EastTotal


Canada


Coast


Canada


China


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


138.7



26.4



99.5



125.9



12.7



0.1Medium crude oil


27.1



27.1







27.1







Heavy crude oil & bitumen


106.9



106.9







106.9







Total
    gross(1)


272.7



160.4



99.5



259.9



12.7



0.1Total
    net(1)


233.0



134.6



88.2



222.8



10.1



0.1Natural Gas(mmcf/day)Gross(1)


623.3



623.3







623.3







Net(1)


492.3



492.3







492.3







   9




---



##### Table of Contents



Production (continued)
  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 & bitumen


108.1



108.1







108.1







Total
    gross(1)


247.6



166.9



68.5



235.4



12.1



0.1Total
    net(1)


220.4



143.8



66.5



210.3



10.0



0.1Natural Gas(mmcf/day)Gross(1)


672.3



672.3







672.3







Net(1)


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 & bitumen


106.0



106.0







106.0







Total
    gross(1)


201.7



168.4



17.2



185.6



16.0



0.1Total
    net(1)


175.7



146.0



15.1



161.1



14.5



0.1Natural Gas(mmcf/day)Gross(1)


680.0



680.0







680.0







Net(1)


488.5



488.5







488.5







       (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
 2007Western


EastTotal


Canada


Coast


Canada


China


Libya($ millions)Crude OilLight crude oil and NGL


3,722



626



2,736



3,362



357



3Medium crude oil


504



504







504







Heavy crude oil & bitumen


1,567



1,567







1,567







Total gross


5,793



2,697



2,736



5,433



357



3Total net


4,965



2,421



2,256



4,677



285



3Natural GasGross


1,430



1,430







1,430







Net


1,200



1,200







1,200







Processing/Transportation


64



64







64







   10




---



##### Table of Contents



Revenue (continued)
  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 & bitumen


1,575



1,575







1,575







Total gross


4,889



2,781



1,779



4,560



324



5Total net


4,358



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 & bitumen


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







    Sales
    Prices
  2007Western


EastTotal


Canada


Coast


Canada


China


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


73.54



65.01



75.37



73.18



77.03



82.21Medium crude oil


51.12



51.12







51.12







Heavy crude oil & bitumen


40.19



40.19







40.19







Total crude oil and NGL


58.24



46.12



75.37



57.31



77.03



82.21Natural Gas($/mcf)


6.19



6.19







6.19







   11




---



##### Table of Contents



Sales Prices (continued)
  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 & bitumen


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 & bitumen


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







   Capital
    Expenditures
 2007Western


EastTotal


Canada


Coast


Canada


China


Indonesia


Libya($ millions)Property acquisition


172



172







172











Exploration


564



410



83



493



54



17



Development


1,652



1,449



197



1,646



1



5



2,388



2,031



280



2,311



55



22



   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



1,640



14



5



12,627



2,171



359



2,530



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  12




---



##### Table of Contents



Capital Expenditures (continued)
  Oil
    and Gas
    Netbacks (1)
  2007Western


EastTotal


Canada


Coast


Canada


China


LibyaCrude Oil($/bbl)Light crude oilSales revenue


72.94



61.02



75.37



72.56



77.03



82.21Royalties


9.72



7.87



9.43



9.12



15.63



Operating costs


5.70



13.24



4.07



5.89



3.68



23.12Netback


57.52



39.91



61.87



57.55



57.72



59.09Medium crude oilSales revenue


50.42



50.42







50.42







Royalties


8.89



8.89







8.89







Operating costs


13.92



13.92







13.92







Net back


27.61



27.61







27.61







Heavy crude oil & bitumenSales revenue


40.14



40.14







40.14







Royalties


5.26



5.26







5.26







Operating costs


12.81



12.81







12.81







Netback


22.07



22.07







22.07







Total crude oilSales revenue


57.60



45.13



75.37



56.65



77.03



82.21Royalties


7.87



6.30



9.43



7.49



15.63



Operating costs


9.37



13.07



4.07



9.64



3.68



23.12Netback


40.36



25.76



61.87



39.52



57.72



59.09Natural Gas($/mcf)Sales revenue


6.42



6.42







6.42







Royalties


1.23



1.23







1.23







Operating costs


1.39



1.39







1.39







Netback


3.80



3.80







3.80







Equivalent Unit($boe)Sales revenue


52.41



42.57



75.37



51.54



77.03



82.21Royalties


7.74



6.72



9.43



7.46



15.63



Operating costs


9.09



11.24



4.07



9.28



3.68



23.12Netback


35.58



24.61



61.87



34.80



57.72



59.09       (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.  13




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##### Table of Contents



Oil and Gas
    Netbacks (1) (continued)
  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 oil & bitumenSales 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




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##### 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 oil & bitumenSales 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



Producing
    Wells
  Oil Wells


Natural Gas Wells


TotalGross(1)(2)


Net(1)


Gross(1)(2)


Net(1)


Gross(1)(2)


Net(1)CanadaAlberta


4,090



3,211



5,489



4,274



9,579



7,485Saskatchewan


5,479



4,514



1,192



1,085



6,671



5,599British Columbia


204



58



239



170



443



228Newfoundland


15



6











15



69,788



7,789



6,920



5,529



16,708



13,318InternationalChina


29



12











29



12Libya


2



1











2



131



13











31



13As at December 31, 2007


9,819



7,802



6,920



5,529



16,739



13,331CanadaAlberta


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



6Northwest 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



13,003       (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, 2007, Husky had a royalty interest in
    3,600 wells of which 1,200 were oil producers and 2,400
    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 2007, there were 313 gross, 298 net oil
    wells and 892 gross, 738 net natural gas wells which
    were completed in two or more formations and from which
    production is not commingled.  16




---



##### Table of Contents



Landholdings
  Developed
    Acreage
  Gross


Net(thousands of acres)As at December 31, 2007Western CanadaAlberta


3,102



2,610Saskatchewan


638



574British Columbia


183



115Manitoba






3,923



3,299Northwest Territories and Arctic






Eastern Canada


42



93,965



3,308China


17



7Libya


7



23,989



3,317As 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  17




---



##### Table of Contents



Landholdings (continued)
  Undeveloped
    Acreage
  Gross


Net(thousands of acres)As at December 31, 2007Western CanadaAlberta


4,118



3,600Saskatchewan


1,547



1,404British Columbia


888



610Manitoba


1



16,554



5,615Northwest Territories and Arctic


1,021



396Eastern Canada


2,429



1,56610,004



7,577China


7,372



3,612Indonesia


1,742



1,742Greenland


8,471



5,98427,589



18,915As 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



Drilling
    Activity
  Year ended December 312007


2006


2005Gross


Net


Gross


Net


Gross


NetWestern Canada DrillingExplorationOil


79



79



101



99



89



85Gas


114



92



330



192



392



196Dry


14



12



26



24



36



36207



183



457



315



517



317DevelopmentOil


571



530



590



543



466



433Gas


343



251



565



490



610



551Dry


31



29



25



22



42



39945



810



1,180



1,055



1,118



1,0231,152



993



1,637



1,370



1,635



1,340   Present
    Activities
  Exploratory


DevelopmentGross


Net


Gross


NetWells
    Drilling(1)Western Canada


3



2.25



13



10.34       (1)
    Denotes wells that were drilling at December 31, 2007.  Oil and
    Gas Reserves Disclosures
    Audit
    of Oil and Gas Reserves
   19




---



##### Table of Contents



Proved
    Reserves
  FutureNet Cash FlowsCrude Oil &
    NGL(1)


Natural
    Gas(1)


Before
    Tax(1)(4)Gross(2)


Net(2)


Gross(2)


Net(2)


0%


10%(mmbbls)


(bcf)


($ millions)Proved
    developed(3)


492



415



1,780



1,494



27,003



17,557Proved
    undeveloped(3)(5)


157



137



411



360



6,236



3,425Proved
    total(3)


649



552



2,191



1,854



33,239



20,982       (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, 2007
    were based on the year-end spot NYMEX natural gas price of U.S.
    $7.11/mmbtu and on a spot WTI crude oil price of U.S. $95.98/bbl.(5)
    Estimated future capital expenditures required to gain access to
    proved undeveloped reserves as at December 31, 2007 and
    2006 were as follows:  As at December 31, 2007Total


2008


2009


2010


2011


2012


Thereafter($ millions undiscounted)Western Canada


1,943



713



520



272



119



87



232Eastern Canada


476



198



237



19











222,419



911



757



291



119



87



254   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   (6)
    On December 31, 2007, the date our oil and gas reserves
    were evaluated, the calculated price of Lloydminster heavy crude
    oil was $59.09 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


CoastLight

















LightProved reserves,

Crude Oil


Medium


Heavy


Natural





Light


Crude Oil


Natural


Crude Oil


Naturalbefore
royalties(1)

& 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 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



2,143Revisions


1



4



(8
)


64







26



2







25



64Purchases


1











36



















1



36Sales


(10
)










(23
)


















(10
)


(23
)Discoveries and extensions


8



6



37



189



11



19











81



189Improved recovery


2



1



1



10



















4



10Production


(9
)


(10
)


(38
)


(228
)


(1
)


(36
)


(5
)






(99
)


(228
)End of 2007


159



88



205



2,191



70



116



11







649



2,191       (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


29.2



5.2Foothills Deep Gas area


29.3



5.5Ram River and Kaybob areas


7.1



2.4Northwest Alberta PlainsRainbow Lake area


76.1



7.4Peace River Arch area


4.3



1.5East Central AlbertaNorth area


2.4



0.5South area


2.6



0.8Provost area


37.5



15.4Southern Alberta and SaskatchewanSouth Alberta area


25.2



8.0South Saskatchewan area


63.5



15.2Lloydminster AreaPrimary production


102.9



77.4Thermal production


71.5



18.8Oil Sands


70.3



1.6Other


0.3



0.8522.2



160.5East Coast CanadaTerra Nova


20.7



14.5White Rose


95.1



85.0115.8



99.5ChinaWenchang


10.9



12.7648.9



272.7     Note:
  (1)   Gross crude
    oil and NGL reserves as at December 31, 2007 and average
    2007 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


125.7



50.7Foothills Deep Gas area


424.2



87.1Ram River and Kaybob areas


249.9



77.4Northwest Alberta PlainsRainbow Lake area


434.1



78.0Peace River Arch






1.7Northern Alberta area


167.0



54.4East Central AlbertaProvost area


141.5



44.8North area


198.3



47.0South area


143.9



55.2Southern Alberta and SaskatchewanSouth Alberta area


46.9



22.3South Saskatchewan area


186.3



55.2Lloydminster Area


72.8



41.7Other






7.82,190.6



623.3     Note:
  (1)   Gross natural
    gas reserves as at December 31, 2007 and average daily
    gross production of natural gas.
  Probable
    Oil and Gas
    Reserves (1)
  CanadaWestern CanadaConventional


Bitumen(2)


East Coast


International


Total(mmbbls)Crude Oil & NGL2007


149



1,765



100



25



2,0392006


144



1,127



79



9



1,3592005


146



903



118



13



1,180Natural Gas(bcf)2007


473











516



9892006


390











93



4832005


407











167



574Barrels of Oil Equivalent(mmboe)2007


228



1,765



100



111



2,2042006


209



1,127



79



25



1,4402005


213



903



118



41



1,275     Notes:
  (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). 23




---



##### Table of Contents



(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 NI
    51-101.  Disclosure
    about Oil and Gas Producing Activities  Statement of
    Financial Accounting Standards No. 69
    Oil
    and Gas Reserves
            Results
    of Operations for Producing
    Activities(1)(2)
  Canada


International


Total2007


2006


2005


2007


2006


2005


2007


2006


2005($ millions except per boe amounts)Oil and gas production revenue


5,998



5,567



4,085



288



274



337



6,286



5,841



4,422Operating costsLease operating expenses


1,292



1,215



925



21



22



18



1,313



1,237



943Production taxes


64



69



56















64



69



56Asset retirement obligation accretion


38



37



28















38



37



281,394



1,321



1,009



21



22



18



1,415



1,343



1,027Depreciation, depletion and amortization


1,563



1,426



1,102



52



50



42



1,615



1,476



1,144Earnings before taxes


3,041



2,820



1,974



215



202



277



3,256



3,022



2,251Income tax


994



982



730



70



72



106



1,064



1,054



836Results of operations


2,047



1,838



1,244



145



130



171



2,192



1,968



1,415Amortization rate per gross boe


11.77



11.24



10.10



11.10



11.24



7.21



11.75



11.24



9.95Amortization rate per net boe


14.06



13.09



12.45



14.01



13.50



7.96



14.05



13.10



12.19     Notes:
  (1)
    The costs in this schedule exclude
    corporate overhead, interest expense and other operating costs,
    which are not directly related to producing activities.(2)
    Under U.S. GAAP, the depreciation,
    depletion and amortization for Canadian producing activities for
    2007 amounted to $1,507 million (2006 
    $1,362 million; 2005  $1,036 million).
    Income taxes for Canadian producing activities under U.S. GAAP
    for 2007 amounted to $1,011 million (2006 
    $1,005 million; 2005  $755 million). 24




---



##### Table of Contents



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


International


Total($ millions)2007Property acquisitionProved


126







126Unproved


46







46Exploration


580



70



650Development


1,559



6



1,565Capitalized interest


6







6Total costs incurred


2,317



76



2,393Less: Proved acquisitions


126







126Capitalized interest


6







6Finding and development costs


2,185



76



2,2612006Property acquisitionProved


97







97Unproved


96







96Exploration


697



77



774Development


1,637



20



1,657Capitalized interest


23







23Total costs incurred


2,550



97



2,647Less: Proved acquisitions


97







97Capitalized interest


23







23Finding and development costs


2,430



97



2,5272005Property acquisitionProved


68







68Unproved


65







65Exploration


390



55



445Development


2,042



23



2,065Capitalized interest


112







112Total costs incurred


2,677



78



2,755Less: Proved acquisitions


68







68Capitalized interest


112







112Finding and development costs


2,497



78



2,575       (1)
    Development costs incurred exclude actual retirement
    expenditures and include asset retirement obligation incurred.
    Asset retirement obligation incurred for 2007 was
    $39 million (2006  $45 million;
    2005  $51 million).         25




---



##### Table of Contents



Prior toWithheld Costs

Total


2007


2006


2005


2005($ millions)Property acquisitionsCanada


67







67







International


63















63130







67







63ExplorationCanada


1,088



426



398



264



International


143



67



70







61,231



493



468



264



6DevelopmentCanada


695



378



317







International


37



4



5



6



22732



382



322



6



22Capitalized interestCanada


104



6



58



39



12,197



881



915



309



92   Capitalized
    Costs Relating to Oil and Gas Producing Activities
  Canada


International


Total($ millions)2007Proved
    properties(1)


20,830



584



21,414Unproved properties


1,954



243



2,19722,784



827



23,611Accumulated DD&A


9,500



456



9,956Net Capitalized
    Costs(2)


13,284



371



13,6552006Proved
    properties(1)


19,087



586



19,673Unproved properties


1,932



165



2,09721,019



751



21,770Accumulated DD&A


8,141



404



8,545Net Capitalized
    Costs(2)


12,878



347



13,2252005Proved
    properties(1)


16,195



528



16,723Unproved properties


2,317



127



2,44418,512



655



19,167Accumulated DD&A


6,729



354



7,083Net Capitalized
    Costs(2)


11,783



301



12,084       (1)
    Capitalized costs related to proved properties include the asset
    retirement obligations. The asset retirement obligations for the
    years presented were as follows:  Canada


International


Total($ millions)2007


454



6



4602006


415



6



4212005


370



6



376  26




---



##### Table of Contents



(2)
    The net capitalized costs for Canadian oil and gas exploration,
    development and producing activities under U.S. GAAP for 2007
    were $12,911 million (2006 
    $12,449 million, 2005  $11,290 million).
    The net capitalized costs for International property
    oil & gas exploration, development and producing
    activities under U.S. GAAP for 2007 were $370 million
    (2006  $346 million, 2005 
    $300 million). Please refer to the
    Form 40-F
    for an explanation of the differences between Canadian and U.S.
    GAAP for oil and gas activities.  Oil
    and Gas Reserve Information
    Canada


International


TotalCrude


Natural


Crude


Natural


Crude


NaturalReserves

Oil & NGL


Gas


Oil & NGL


Gas


Oil & NGL


Gas(mmbbls)


(bcf)


(mmbbls)


(bcf)


(mmbbls)


(bcf)Net proved
    reserves(1)(2)(3)(4)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



1,799Revisions


3



61











3



61Purchases


1



29











1



29Sales


(9
)


(18
)










(9
)


(18
)Improved recovery


4



8











4



8Discoveries and extensions


71



155











71



155Production


(81
)


(180
)


(4
)






(85
)


(180
)End of year 2007


544



1,854



8







552



1,854Net proved developed
    reserves,(1)(2)(3)(4)End 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



1,424End of year 2007


407



1,494



8







415



1,494       (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. 27




---



##### 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

2007


2006


2005


2007


2006


2005


2007


2006


2005($ millions)Future cash inflows


49,383



37,006



40,066



952



900



999



50,335



37,906



41,065Future production costs


12,394



10,915



10,259



136



143



108



12,530



11,058



10,367Future development costs


4,550



3,406



3,171



16



14



14



4,566



3,420



3,185Future income taxes


9,022



6,934



9,000



252



234



272



9,274



7,168



9,272Future net cash flows


23,417



15,751



17,636



548



509



605



23,965



16,260



18,241Annual 10% discount factor


9,039



6,045



7,115



93



93



123



9,132



6,138



7,238Standardized measure of discountedFuture net cash flows


14,378



9,706



10,521



455



416



482



14,833



10,122



11,003       (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. 28




---



##### 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)2007


2006


2005


2007


2006


2005


2007


2006


2005($ millions)Present value at January 1


9,706



10,521



4,745



416



482



460



10,122



11,003



5,205Sales and transfers, net of production costs


(4,696
)


(4,318
)


(3,101
)


(270
)


(257
)


(320
)


(4,966
)


(4,575
)


(3,421
)Net change in sales and transfer prices, net of development and
    production costs


7,380



(1,721
)


5,479



265



126



155



7,645



(1,595
)


5,634Development cost incurred that reduced future development costs


1,772



1,640



2,129



6



20



23



1,778



1,660



2,152Changes in estimated future development costs


(2,157
)


(1,526
)


(2,326
)


(4
)


(19
)


(22
)


(2,161
)


(1,545
)


(2,348
)Extensions, discoveries and improved recovery, net of related
    costs


2,226



1,666



2,027



13







24



2,239



1,666



2,051Revisions of quantity estimates


868



563



2,550



(13
)


(27
)


110



855



536



2,660Accretion of discount


1,422



1,601



762



61



70



68



1,483



1,671



830Sale of reserves in place


(256
)


(19
)


(62
)














(256
)


(19
)


(62
)Purchase of reserves in place


114



65



36















114



65



36Changes in timing of future net cash flows and other


(575
)


263



889







(5
)


(13
)


(575
)


258



876Net change in income taxes


(1,426
)


971



(2,607
)


(19
)


26



(3
)


(1,445
)


997



(2,610
)Net increase (decrease)


4,672



(815
)


5,776



39



(66
)


22



4,711



(881
)


5,798Present value at December 31


14,378



9,706



10,521



455



416



482



14,833



10,122



11,003       (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
     29




---



##### Table of Contents



Lloydminster
    Area
  
 30




---



##### Table of Contents



British
    Columbia Foothills/Northwest Plains
  Rainbow
    Lake District
    2008-2010
        North
    East Shallow Gas District
    High
    Level District
    Ram
    River District
     31




---



##### Table of Contents



non-unit
          Kaybob
    District
  non-unit
    Alberta/British
    Columbia Plains District
  Boundary
    Lake Area
    Valhalla
    and Wapiti Area
  non-unit
 32




---



##### Table of Contents



Kakwa
    Area
    Lynx,
    Copton and Grande Cache Areas
    Foothills
    West District
  Caroline
    Area
      Edson
    Area
    Sikanni
    and Federal Areas
    Graham
    Area
    Grizzly
    Valley and Bullmoose Area
  33-50%
  East
    Central Alberta
  Red
    Deer and Hussar Districts
   33




---



##### Table of Contents



Provost
    District
    Athabasca
    District
  450-900
  Southern
    Alberta and Southern Saskatchewan
  Southern
    Saskatchewan District
        Southern
    Alberta District
   34




---



##### Table of Contents



35




---



##### Table of Contents



Oil
    Sands
  Athabasca,
    Cold Lake and Peace River
    Tucker
    Sunrise
        Saleski/Caribou
     36




---



##### 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



22,672



11,656



YesSunrise  In
    situ(1)


Athabasca



64,034



64,034



YesSouth Sunrise


Athabasca



40,320



40,320



YesMisthae (Drowned, Martin Hills W. & Spur)


Athabasca



28,160



28,160



YesSaleski


Athabasca



241,760



241,760



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


Cold Lake



10,080



10,080



YesPanny (Senex & Welstead)


Peace River



50,560



50,560



YesPeace River (Cadotte Lake)


Peace River



11,840



11,840



YesSawn Lake (Loon)


Peace River



17,280



17,280



Yes653,827



560,170     Notes:
  (1)
    Included in the gross and net amounts are an additional
    6,400 acres of petroleum and natural gas rights held as
    protection acreage for gas over bitumen issues. In 2003, the
    Alberta regulatory authority issued General Bulletin GB
    2003-28 that
    required natural gas wells within certain bitumen prone areas to
    be shut-in. The production of natural gas where natural gas
    reservoirs were believed to be in pressure contact with bitumen
    reserves was deemed to present an unacceptable risk to future
    in-situ bitumen production. Sunrise was formerly named Kearl.(2)
    Husky also has the exclusive right to acquire an additional
    65,280 acres in the Caribou area. 37




---



##### Table of Contents



38




---



##### Table of Contents



Northwest
    Territories
  Stewart D-57 M-38 Creek K-44 Creek B-44 Creek D-57 Creek B-44
  Offshore
    East Coast  Canada
    White
    Rose Oil Field
    SeaRose FPSO
  SeaRose FPSO
    C-30 well K-03 well
   39




---



##### Table of Contents



Terra
    Nova Oil Field
        East
    Coast Exploration
        2-D
 40




---



##### Table of Contents



East
    Coast
  
 41




---



##### Table of Contents



International
    
  South
    China Sea
  Wenchang
  13-1 13-2
 42




---



##### Table of Contents



Block 39/05
  Qionghai 18-1-3 Wenchang 8-1-1
  Block 23/15
  3-D Wushi 17-1-1
  Block 29/26
  Liwan 3-1-1 2-D Liwan 3-1-1 3-D seismic Liwan 3-1
  Block 29/06
  29/06 3-D Block 29/06 3-D
  Block 35/18
    and 50/14
   43




---



##### Table of Contents



3-D
  East
    China Sea
  Block 04/35
    East
    Bawean II, Indonesia
  3-D 3-D
  Madura
    Strait, Indonesia
   44




---



##### Table of Contents



Greenland
  2-D 3-D
  Shatirah,
    Libya
   Distribution
    of Oil and Gas Production  Crude
    Oil and NGLs
     45




---



##### Table of Contents



Natural
    Gas
    Years ended December 31,2007


2006


2005(mmcf/day)Sales to end usersUnited States


338



335



357Canada


208



231



212546



566



569Sales to aggregators


21



26



31Internal
    use(1)


56



80



80623



672



680       (1)
    Husky consumes natural gas for fuel at several of its facilities.    Delivery
    Commitments
    Fixed Price


Market PriceBcf


$/mmbtu


Bcf2008


19



4.91



242009


19



5.18



82010


19



5.46



12011


19



5.77



2012


19



6.05



2013


18



5.85



2014


10



3.84



  MIDSTREAM
    OPERATIONS  Overview
    
    Upgrading  the upgrading of heavy crude oil into
    synthetic light crude oil;
    Infrastructure  pipeline transportation and
    processing of heavy crude oil, storage of crude oil, diluent,
    and natural gas, extraction of NGL from natural gas,
    cogeneration of electrical and thermal energy; and
    Commodity Marketing  the purchase and marketing of
    Huskys and other producers crude oil, natural gas,
    NGLs, sulphur, petroleum coke and electrical power.  Upgrading
    Operations
     46




---



##### Table of Contents



Infrastructure
      Years ended December 31,2007


2006


2005(mbbls/day)Combined pipeline throughput


501



475



474        47




---



##### Table of Contents



HEAVY OIL
    PIPELINE SYSTEMS
  
 48




---



##### Table of Contents



Cogeneration
      Natural
    Gas Storage Facilities
    Commodity
    Marketing
             49




---



##### Table of Contents



DOWNSTREAM
    OPERATIONS  Canada
  Overview
      Branded
    Petroleum Product Outlets and Commercial Distribution
  Distribution
     50




---



##### Table of Contents



BRANDED
    PETROLEUM PRODUCT OUTLETS
  
   51




---



##### Table of Contents



BritishColumbia &














2007



2006Yukon


Alberta


Sask.


Manitoba


Ontario


Total



TotalRetail Owned OutletsTravel Centres


10



8



4



2



12



36




36Full Serve


10



12



3



2



1



28




28Full/Self Serve


16



23



5



11



4



59




57Self Serve


18



19



1



1



2



41




40Bulk Distributor


1



9



3



1



1



15




15Other Service Facilities Distributor


3



8



0



1



1



13




1358



79



16



18



21



192




189LeasedTravel Centres


1



0



0



0



0



1




1Full Serve


3



8



5



6



0



22




22Full/Self Serve


10



20



3



4



0



37




38Self Serve


35



25



0



1



0



61




60Bulk Distributor


2



0



0



0



0



2




2Other Service Facilities Distributor


1



3



0



2



2



8




852



56



8



13



2



131




131Independent RetailersTravel Centres


1



2



0



0



4



7




7Full Serve


21



10



8



10



8



57




55Full/Self Serve


15



5



4



1



1



26




35Self Serve


28



44



4



2



0



78




77Bulk Distributor


2



4



2



0



0



8




6Other Service Facilities Distributor


1



2



0



0



3



6




568



67



18



13



16



182




185TotalTravel Centres


12



10



4



2



16



44




44Full Serve


34



30



16



18



9



107




105Full/Self Serve


41



48



12



16



5



122




130Self Serve


81



88



5



4



2



180




177Bulk Distributor


5



13



5



1



1



25




23Other Service Facilities Distributor


5



13



0



3



6



27




26178



202



42



44



39



505




505Cardlocks(1)


26



21



4



5



24



80




73Convenience
    Stores(1)


161



178



34



39



32



444




445Restaurants


11



13



4



2



16



46




46        (1)
    All of these are located at branded petroleum outlets.   52




---



##### Table of Contents



Years ended December 31,2007


2006


2005(mbbls/day)Gasoline


27.8



27.5



28.3Diesel fuel


27.4



26.4



26.5Liquefied petroleum gas


0.9



0.9



0.956.1



54.8



55.7   Prince
    George Refinery
    Lloydminster
    Asphalt Refinery
    Ethanol
    Manufacturing
        Other
    Supply Arrangements
    Asphalt
    Products
       53




---



##### Table of Contents



Years ended December 31,2007


2006


2005(mbbls/day)Asphalt


14.0



14.0



13.8Residual and other


7.8



9.4



8.721.8



23.4



22.5           United
    States
  Refining
    and Marketing
     54




---



##### Table of Contents



HUMAN
    RESOURCES
    December 31,2007


2006Upstream


2,510



2,357Midstream


389



375Refined Products


840



480Corporate


403



3584,142



3,570  DIVIDENDS    2007


2006


2005Cash dividends declared per common share

$
1.33


$
0.75


$
0.825   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

May 4, 2007

Senior Unsecured Debt

Baa2

May 4, 2007

April 25, 2001Capital Securities

Ba1

May 4, 2007

April 25, 2001Standard and Poors:Outlook

Stable

March 9, 2007

July 27, 2006Senior Unsecured Debt

BBB+

March 9, 2007

July 27, 2006Capital Securities

BBB−

March 9, 2007

July 27, 2006Dominion Bond Rating Service:Under ReviewTrend

Positive

November 28, 2007

Senior Unsecured Debt

BBB(high)

November 28, 2007

Capital Securities

BBB

November 28, 2007

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




---



##### Table of Contents



MARKET
    FOR SECURITIES    (1)
  High


Low


Volume(000s)January


39.30



35.40



26,844February


39.25



37.26



27,193March


40.95



35.83



21,468April


42.97



40.11



16,038May


45.44



42.00



21,213June


46.65



41.92



21,989July


45.35



40.13



17,313August


42.80



35.01



23,990September


42.75



38.16



16,926October


44.28



40.18



30,095November


44.35



38.75



26,817December


44.77



39.03



18,642       (1)
    Share prices adjusted to reflect a two for one share split
    effective July 9, 2007. DIRECTORS
    AND OFFICERS    Officers
  Name and Residence

Office or Position

Principal Occupation During Past 5 YearsLAU, JOHN C.S.
     Calgary, Alberta, Canada

President & Chief  Executive Officer and Director

President & Chief Executive Officer of Husky Energy
    Inc. since August 2000.INGRAM, 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.GIRGULIS, JAMES D.
     Calgary, Alberta, Canada

Vice President, Legal & Corporate Secretary

Vice President, Legal & Corporate Secretary of Husky
    since August 2000.  57




---



##### Table of Contents



Conflicts
    of Interest
  and/or Business Corporations Act
  Corporate
    Cease Trade Orders or Bankruptcies
    Companies Creditors Arrangement Act
  Individual
    Penalties, Sanctions or Bankruptcies
   AUDIT
    COMMITTEE  52-110 
   58




---



##### Table of Contents



and/or
        External
    Auditor Service Fees
    Aggregate feesbilled by theExternal Auditor2007


2006($ thousands)Audit fees


1,964



1,853Audit-related fees


154



109Tax fees


77



73All other fees






2,195



2,035   Audit Fees.
  Audit-Related Fees.
  Tax Fees.
  All Other Fees.
     LEGAL
    PROCEEDINGS   INTEREST
    OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS   59




---



##### Table of Contents



TRANSFER
    AGENT AND REGISTRARS    MATERIAL
    CONTRACTS
   INTERESTS
    OF EXPERTS   ADDITIONAL
    INFORMATION      Additional information relating to Husky Energy Inc. is
    available on SEDAR at www.sedar.com
 60




---



##### 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 unitsKms

 kilometresMW

 megawattsAcronymsAPI

 American Petroleum InstituteCNOOC

 Chinese National Offshore Oil CompanyCOGEH

 Canadian Oil and Gas Evaluation HandbookEIA

 Energy Information AdministrationEL

 Exploration LicenceERCB

 Energy Resources Conservation BoardFAS

 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   API°
    gravity
    Barrel
   61




---



##### Table of Contents



Bitumen
    Bulk
    Terminal
  and/or
  Coalbed
    Methane
    Cold
    Production
    Debottleneck
    Delineation
    well
    Developed
    area
    Development
    well
    Diluent
    Dry and
    abandoned well
    Enhanced
    recovery
    Exploration
    licence
   62




---



##### Table of Contents



Exploratory
    well
    Field
  and/or
  Gathering
    System
    Horizontal
    drilling
    Hydrogen
    sulphide
    Infill
    Well
    Liquefied
    petroleum gas
    Metocean
    data
    Miscible
    Flood
    Multiple
    completion well
    Natural
    gas liquids
    Oil
    Battery
    Oil
    Sands
   63




---



##### 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
   64




---



##### Table of Contents



Steam
    Assisted Gravity Drainage
    Step-out
    Well
    Stratigraphic
    test well
    Synthetic
    oil
    Tertiary
    recovery
    Three-D
    Seismic (survey)
    Turnaround
    Undeveloped
    area
  and/or
  Waterflood
    Well
    Abandonment Costs
    Wellhead
    Working
    interest
   65




---



##### 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 66




---



##### Table of Contents




    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  www.sedar.com
   67




---



##### 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
       68




---



##### 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 69




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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. 70




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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.    71




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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, 2007. The reserves data consist of the
    following:  (a)
    proved oil and gas reserve quantities estimated as at
    December 31, 2007 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, 2007:  Discounted Future Net Cash FlowsLocation of Reserves

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


20,317China


651Libya


1420,982     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. 72




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8.
    Oil and gas reserves are estimates only, and not exact
    quantities. In addition, the oil and gas reserves data are based
    on judgments regarding future events, actual results will vary
    and the variations may be material. However, any variations
    should be consistent with the fact that reserves are categorized
    according to the probability of their recovery.     Frederick
    Au-Yeung
  73




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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, 2007 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
    Form
    51-101F1
    containing reserves data and other oil and gas information;(b)
    the filing of
    Form 51-101F2,
    which is the Report on Reserves Data of the Manager of Reservoir
    Engineering; and(c)
    the content and filing of this report.  51-101
     74




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##### Table of Contents



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

March 10, 2008/s/  James
    D. GirgulisJames
    D. GirgulisVice President, Legal & Corporate Secretary

March 10, 2008/s/  R.
    Donald FullertonR.
    Donald FullertonDirector

March 10, 2008/s/  William
    ShurniakWilliam
    ShurniakDirector

March 10, 2008  75




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##### Table of Contents



Schedule D  Husky
    Energy Inc.
  INDEPENDENT
    ENGINEERS AUDIT OPINION
  Husky
    Energy Inc.
             Sincerely,
    P.A.
    Welch
 President & Managing Director
    76




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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, 2007




---



##### Table of Contents



Husky
    Energy Inc.
  Consolidated Financial
    Statements
  For the Year Ended
    December 31, 2007




---



##### Table of Contents



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




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##### Table of Contents



AUDITORS
    REPORT TO THE SHAREHOLDERS
          KPMG
    llp
   llp
     Comments
    by auditors 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 312007


2006


2005(millions of dollars)ASSETSCurrent assetsCash and cash equivalents

$
208


$
442


$
168Accounts receivable (notes 5, 19)


1,622



1,284



856Inventories (note 6)


1,190



428



471Prepaid expenses


28



25



403,048



2,179



1,535Property, plant and equipment, net (notes 1, 7)


17,805



15,550



13,959Goodwill (notes 1, 8)


660



160



160Other assets (notes 12, 19)


184



44



62$
21,697


$
17,933


$
15,716LIABILITIES AND SHAREHOLDERS EQUITYCurrent liabilitiesAccounts payable and accrued liabilities (note 11)

$
2,358


$
2,574


$
2,310Long-term debt due within one year (notes 12, 19)


741



100



2743,099



2,674



2,584Long-term debt (notes 12, 19)


2,073



1,511



1,612Other long-term liabilities (note 13)


918



756



730Future income taxes (note 14)


3,957



3,372



3,270Commitments and contingencies (note 15)Shareholders equityCommon shares (note 16)


3,551



3,533



3,523Retained earnings


8,176



6,087



3,997Accumulated other comprehensive income


(77
)






11,650



9,620



7,520$
21,697


$
17,933


$
15,716     /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 AND COMPREHENSIVE INCOME
  Year ended December 312007


2006


2005(millions of dollars,except per share amounts)Sales and operating revenues, net of royalties

$
15,518


$
12,664


$
10,245Costs and expensesCost of sales and operating expenses (note 13)


9,296



7,169



5,917Selling and administration expenses


219



162



138Stock-based compensation (note 16)


88



138



171Depletion, depreciation and amortization (notes 1, 7)


1,806



1,599



1,256Interest  net (note 12)


130



92



32Foreign exchange (note 12)


(51
)


(24
)


(31
)Other  net (notes 15, 19)


(97
)


22



(50
)11,391



9,158



7,433Earnings before income taxes


4,127



3,506



2,812Income taxes (note 14)Current


347



678



297Future


566



102



512913



780



809Net earnings


3,214



2,726



2,003Other comprehensive incomeDerivatives designated as cash flow hedges, net of tax
    (note 19)


14







Cumulative foreign currency translation adjustment


(175
)






Hedge of net investment, net of tax (note 19)


102







(59
)






Comprehensive income

$
3,155


$
2,726


$
2,003Earnings per shareBasic and diluted (note 16)

$
3.79


$
3.21


$
2.36Weighted average number of common shares outstanding
    (millions)Basic and diluted (note 16)


848.8



848.4



847.9    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 CHANGES IN SHAREHOLDERS EQUITY
  Year ended December 312007


2006


2005(millions of dollars)Common sharesBeginning of year

$
3,533


$
3,523


$
3,506Options and warrants exercised


18



10



17End of year


3,551



3,533



3,523Retained earningsBeginning of year


6,087



3,997



2,694Net earnings


3,214



2,726



2,003Dividends on common shares (note 16)Ordinary


(917
)


(636
)


(276
)Special


(212
)






(424
)Adoption of financial instruments (note 19)


4







End of year


8,176



6,087



3,997Accumulated other comprehensive incomeBeginning of year










Adoption of financial instruments (note 19)


(18
)






Other comprehensive incomeDerivatives designated as cash flow hedges, net of tax
    (note 19)


14







Cumulative foreign currency translation adjustment


(175
)






Hedge of net investment, net of tax (note 19)


102







(59
)






End of year


(77
)






Shareholders equity

$
11,650


$
9,620


$
7,520    The accompanying notes to the consolidated financial
    statements are an integral part of these statements.
 6




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##### Table of Contents



CONSOLIDATED
    STATEMENTS OF CASH FLOWS
  Year ended December 312007


2006


2005(millions of dollars)Operating activitiesNet earnings

$
3,214


$
2,726


$
2,003Items not affecting cashAccretion (note 13)


47



45



33Depletion, depreciation and amortization


1,806



1,599



1,256Future income taxes


566



102



512Foreign exchange


(135
)


(3
)


(37
)Other


(72
)


32



18Settlement of asset retirement obligations (note 13)


(51
)


(36
)


(41
)Change in non-cash working capital (note 9)


(718
)


544



(94
)Cash flow  operating activities


4,657



5,009



3,650Financing activitiesBank operating loans financing  net










(101
)Long-term debt issue


7,222



1,226



3,235Long-term debt repayment


(5,722
)


(1,493
)


(3,401
)Settlement of cross currency swap






(47
)


Debt issue costs


(8
)






Proceeds from exercise of stock options


5



3



6Proceeds from monetization of financial instruments










39Dividends on common shares


(1,129
)


(636
)


(700
)Other






(1
)


(1
)Change in non-cash working capital (note 9)


65



(678
)


255Cash flow  financing activities


433



(1,626
)


(668
)Available for investing


5,090



3,383



2,982Investing activitiesCapital expenditures


(2,931
)


(3,171
)


(3,068
)Corporate acquisition (note 8)


(2,589
)






Asset sales


333



34



74Other


(44
)


(12
)


(31
)Change in non-cash working capital (note 9)


(93
)


40



211Cash flow  investing activities


(5,324
)


(3,109
)


(2,814
)Increase (decrease) in cash and cash equivalents


(234
)


274



168Cash and cash equivalents at beginning of year


442



168



Cash and cash equivalents at end of year

$
208


$
442


$
168    The accompanying notes to the consolidated financial
    statements are an integral part of these statements.
 7




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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 Marketing2007


2006


2005


2007


2006


2005


2007


2006


2005Year ended December 31Sales and operating revenues, net of royalties

$
6,222


$
5,772


$
4,367


$
1,524


$
1,679


$
1,488


$
10,217


$
9,559


$
7,383Costs and expensesOperating, cost of sales, selling and general


1,308



1,321



1,050



1,127



1,273



1,018



9,838



9,258



7,084Depletion, depreciation and amortization


1,615



1,476



1,144



25



24



21



28



24



21Interest  net


































Foreign exchange


































2,923



2,797



2,194



1,152



1,297



1,039



9,866



9,282



7,105Earnings (loss) before income taxes


3,299



2,975



2,173



372



382



449



351



277



278Current income taxes


122



519



215



10



53



16



68



79



(14
)Future income taxes


581



161



434



80



44



120



30



1



110Net earnings (loss)

$
2,596


$
2,295


$
1,524


$
282


$
285


$
313


$
253


$
197


$
182Property, plant and equipment 
    As at December 31Cost

$
23,611


$
21,770


$
19,167


$
1,607


$
1,390


$
1,205


$
842


$
750


$
683Accumulated depletion, depreciation and amortization


9,956



8,545



7,083



480



455



430



298



270



247Net

$
13,655


$
13,225


$
12,084


$
1,127


$
935


$
775


$
544


$
480


$
436Capital expenditures  Year ended
    December 31(1)

$
2,388


$
2,627


$
2,730


$
217


$
184


$
120


$
92


$
68


$
37Goodwill additions  Year ended December 31

$



$



$



$



$



$



$



$



$
Total assets  As at December 31

$
14,395


$
13,920


$
12,887


$
1,405


$
992


$
844


$
1,134


$
1,329


$
866    (1)
    Excludes capitalized costs related to asset retirement
    obligations incurred during the period and corporate
    acquisitions. 8




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##### Table of Contents



Corporate andDownstream


Eliminations(1)


TotalCanadian


U.S.Refined Products


Refining and Marketing2007


2006


2005


2007


2006


2005


2007


2006


2005


2007


2006


2005Year ended December 31Sales and operating revenues, net of royalties

$
2,916


$
2,575


$
2,345


$
2,383


$



$



$
(7,744
)

$
(6,921
)

$
(5,338
)

$
15,518


$
12,664


$
10,245Costs and expensesOperating, cost of sales, selling and general


2,608



2,381



2,169



2,167











(7,542
)


(6,742
)


(5,145
)


9,506



7,491



6,176Depletion, depreciation and amortization


66



48



47



47











25



27



23



1,806



1,599



1,256Interest  net














1











129



92



32



130



92



32Foreign exchange


























(51
)


(24
)


(31
)


(51
)


(24
)


(31
)2,674



2,429



2,216



2,215











(7,439
)


(6,647
)


(5,121
)


11,391



9,158



7,433Earnings (loss) before income taxes


242



146



129



168











(305
)


(274
)


(217
)


4,127



3,506



2,812Current income taxes


17



19



(3
)


28











102



8



83



347



678



297Future income taxes


33



21



50



35











(193
)


(125
)


(202
)


566



102



512Net earnings (loss)

$
192


$
106


$
82


$
105


$



$



$
(214
)

$
(157
)

$
(98
)

$
3,214


$
2,726


$
2,003Property, plant and equipment  As at December 31Cost

$
1,550


$
1,344


$
1,063


$
1,459


$



$



$
338


$
298


$
257


$
29,407


$
25,552


$
22,375Accumulated depletion, depreciation and amortization


590



525



476



46











232



207



180



11,602



10,002



8,416Net

$
960


$
819


$
587


$
1,413


$



$



$
106


$
91


$
77


$
17,805


$
15,550


$
13,959Capital expenditures  Year ended December
    31(2)

$
212


$
285


$
191


$
21


$



$



$
44


$
37


$
21


$
2,974


$
3,201


$
3,099Goodwill additions  Year ended December 31

$



$



$



$
500


$



$



$



$



$



$
500


$



$
Total assets  As at December 31

$
1,335


$
1,114


$
834


$
3,058


$



$



$
370


$
578


$
285


$
21,697


$
17,933


$
15,716     (1)
    Eliminations relate to sales and operating revenues between
    segments recorded at transfer prices based on current market
    prices, and to unrealized intersegment profits in
    inventories.(2)
    Excludes capitalized costs related to asset retirement
    obligations incurred during the period and corporate
    acquisitions.   Geographical
    Financial Information
  OtherCanada


United States


International


Total2007


2006


2005


2007


2006


2005


2007


2006


2005


2007


2006


2005Year ended December 31Sales and operating revenues, net of royalties

$
11,736


$
11,050


$
8,500


$
3,494


$
1,340


$
1,407


$
288


$
274


$
338


$
15,518


$
12,664


$
10,245Capital
    expenditures(1)


2,877



3,104



3,021



21











76



97



78



2,974



3,201



3,099As at December 31Property, plant and equipment, net

$
16,017


$
15,200


$
13,655


$
1,417


$
3


$
3


$
371


$
347


$
301


$
17,805


$
15,550


$
13,959Goodwill(2)


160



160



160



500























660



160



160Total assets


17,983



17,443



15,157



3,240



115



231



474



375



328



21,697



17,933



15,716     (1)
    Excludes capitalized costs related to asset retirement
    obligations incurred during the period and corporate
    acquisitions.(2)
    Changes in goodwill for the U.S. arise from translation of
    goodwill in our self-sustaining U.S. operations. Refer to
    note 8, Corporate Acquisition. 9




---



##### 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
  Form 40-F.
          b) Cash
    and Cash Equivalents
    c) Inventory
    Valuation
  first-in,
  d) Precious
    Metals
    e) Property,
    Plant and Equipment
  i) Oil
    and Gas
  country-by-country
   10




---



##### Table of Contents



addition to the asset retirement
    obligations. In the normal course of operations, retirements of
    oil and gas interests are accounted for by charging the asset
    cost, net of any proceeds, to accumulated depletion or
    depreciation. Gains or losses on the disposition of oil and gas
    properties are not recognized unless the gain or loss changes
    the depletion rate by 20% or more.
      
    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.    
    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
    f) Impairment
    or Disposal of Long-lived Assets
      g) Goodwill
    h) Derivative
    Financial Instruments and Hedging Activities
  i) Financial
    Instruments
   11




---



##### Table of Contents




    is a derivative, except for those derivatives that have been
    designated as effective hedging instruments;
    has been acquired or incurred principally for the purpose of
    selling or repurchasing in the near future; or
    is part of a portfolio of financial instruments that are managed
    together and for which there is evidence of a recent actual
    pattern of short-term profit taking.    ii) Derivative
    Instruments and Hedging Activities
                         12




---



##### Table of Contents



iii) Embedded
    Derivatives
      iv) Comprehensive
    Income
    i) Employee
    Future Benefits
        j) Future
    Income Taxes
    k) Non-monetary
    Transactions
    l) Revenue
    Recognition
    m) Foreign
    Currency Translation
      n) Stock-based
    Compensation
     13




---



##### Table of Contents



the market price of the
    Companys common shares and the net change is recognized in
    earnings. When stock options are surrendered for cash, the cash
    settlement paid reduces the outstanding liability. When stock
    options are exercised for common shares, consideration paid by
    the stock option holders and the previously recognized liability
    associated with the stock options are recorded as share capital.
    Accrued compensation for an option that is forfeited is adjusted
    to earnings by decreasing the compensation cost in the period of
    forfeiture.
  o) Earnings
    per Share
      p) Reclassification
    Note 4
  Pending
    Accounting Pronouncements
  a) Financial
    Instruments  Disclosures and Presentation
      b) Capital
    Disclosures
    c) Inventories
  last-in,
  Note 5
  Accounts
    Receivable
  2007


2006


2005Trade receivables

$
1,599


$
1,286


$
854Allowance for doubtful accounts


(10
)


(10
)


(10
)Derivatives due within one year


22







Other


11



8



12$
1,622


$
1,284


$
856  14




---



##### Table of Contents



Sale of
    Accounts Receivable
      Note 6
  Inventories
  2007


2006


2005Crude oil

$
539


$
119


$
167Natural gas


192



193



207Refined petroleum products


409



89



74Materials, supplies and other


50



27



23$
1,190


$
428


$
471   Note 7
  Property,
    Plant and Equipment
        2007


2006


2005Canada

$
1,954


$
1,932


$
2,317International


243



165



127$
2,197


$
2,097


$
2,444     Price increaseCanada

2008


2009


2010


2011


2012


2012 to 2027(percent)Crude oil ($/bbl)

$
61.56


$
55.73


$
51.07


$
48.13


$
46.99



3Natural gas ($/mcf)


6.59



6.72



6.63



6.73



6.86



2   Note 8
  Corporate
    Acquisition
   15




---



##### Table of Contents



U.S. $


Cdn $Net assets acquiredWorking capital

$
4


$
4Property, plant and equipment


1,455



1,542Goodwill
    (1)


506



536Other assets


25



26Other long-term liabilities


(86
)


(91
)1,904



2,017Feedstock and product inventory acquired


540



572Total

$
2,444


$
2,589    (1)
    Allocated to U.S. Refining and Marketing in the
    Companys downstream segment. For U.S. income tax
    purposes, goodwill is deductible and amortized over a
    15-year
    period. Refer to note 1, Segmented Financial
    Information.  Note 9
  Cash
    Flows  Change in Non-cash Working
    Capital
  a) Change
    in non-cash working capital was as follows:
  2007


2006


2005Decrease (increase) in non-cash working capitalAccounts receivable

$
(345
)

$
(428
)

$
(410
)Inventories


(212
)


43



(197
)Prepaid expenses


1



14



17Accounts payable and accrued liabilities


(190
)


277



962Change in non-cash working capital

$
(746
)

$
(94
)

$
372Relating to:Operating activities

$
(718
)

$
544


$
(94
)Financing activities


65



(678
)


255Investing activities


(93
)


40



211   b) Other
    cash flow information:
  2007


2006


2005Cash taxes paid

$
926


$
215


$
154Cash interest paid


162



147



147   Note 10
  Bank
    Operating Loans
    Note 11
  Accounts
    Payable and Accrued Liabilities
  2007


2006


2005Trade payables

$
23


$
74


$
7Accrued liabilities


1,743



1,322



1,338Dividend payable


280



212



530Stock-based compensation


159



234



130Current income taxes


36



615



164Other


117



117



141$
2,358


$
2,574


$
2,310  16




---



##### Table of Contents



Note 12
  Long-term
    Debt
  Cdn $ Amount


U.S. $ DenominatedMaturity


2007


2006


2005


2007


2006


2005Long-term debt6.85% medium-term notes  Series B


2007


$



$



$
100


$



$



$
6.95% medium-term notes  Series E


2009



203



200



200











6.25% notes


2012



395



466



467



400



400



4007.55% debentures


2016



198



233



233



200



200



2006.20% notes


2017



296











300







6.15% notes


2019



296



350



350



300



300



3008.90% capital securities


2028



223



262



262



225



225



2256.80% notes


2037



445











450







Debt issue costs






(20
)


















Unwound interest rate swaps






37



















$
2,073


$
1,511


$
1,612


$
1,875


$
1,125


$
1,125Long-term debt due within one yearBridge financing


2008


$
741


$



$



$
750


$



$
6.85% medium-term notes  Series B


2007







100















7.125% notes


2006











175











1508.45% senior secured bonds


2006











99











85$
741


$
100


$
274


$
750


$



$
235     2007


2006


2005Long-term debt

$
151


$
130


$
144Short-term debt


6



5



4157



135



148Amount capitalized


(19
)


(33
)


(114
)138



102



34Interest income


(8
)


(10
)


(2
)$
130


$
92


$
32     2007


2006


2005Gain on translation of U.S. dollar denominated long-term debt

$
(197
)

$
(7
)

$
(51
)Cross currency swaps


62



4



14Other (gains) losses


84



(21
)


6$
(51
)

$
(24
)

$
(31
)   Credit
    Facilities
          Notes and
    Debentures
  25-month
 17




---



##### Table of Contents



and/or
        Note 13
  Other
    Long-term Liabilities
  2007


2006


2005Asset retirement obligations

$
662


$
622


$
557Cross currency swaps
    (1)


107



40



40Interest rate swaps






37



42Employee future benefits


69



30



27Capital lease


36







Stock-based compensation


13



4



46Other


31



23



18$
918


$
756


$
730    (1)
    Refer to note 19, Financial Instruments and Risk
    Management.  Asset
    Retirement Obligations
      2007


2006


2005Asset retirement obligations at beginning of year

$
622


$
557


$
509Liabilities incurred


57



35



63Liabilities disposed


(13
)


(1
)


(7
)Liabilities settled


(51
)


(36
)


(41
)Revisions






22



Accretion
    (1)


47



45



33Asset retirement obligations at end of year

$
662


$
622


$
557   (1)
    Accretion is included in cost of sales and operating
    expenses. 18




---



##### Table of Contents



Note 14
  Income
    Taxes
    2007


2006


2005Earnings (loss) before income taxesCanada

$
3,763


$
3,276


$
2,553United States


95



15



(6
)Other foreign jurisdictions


269



215



2654,127



3,506



2,812Statutory income tax rate (percent)


32.7



35.7



38.4Expected income tax


1,350



1,252



1,080Effect on income tax of:Royalties, lease rentals and mineral taxes payable to the crown






10



105Resource allowance on Canadian production income






(35
)


(133
)Change in statutory tax rate


(395
)


(328
)


(4
)Rate benefit on partnership earnings


(53
)


(97
)


(69
)Capital gains and losses


(24
)


(1
)


(140
)Foreign jurisdictions


8



(6
)


(14
)Non-deductible capital taxes






(17
)


15Other  net


27



2



(31
)Income tax expense

$
913


$
780


$
809       2007


2006


2005Future tax liabilitiesProperty, plant and equipment

$
4,081


$
3,607


$
3,487Foreign exchange gains taxable on realization


131



48



60Other temporary differences


1



1



24,213



3,656



3,549Future tax assetsAsset retirement obligations


186



194



195Loss carry forwards






2



Provincial royalty rebates






2



7Other temporary differences


70



86



77256



284



279$
3,957


$
3,372


$
3,270   Note 15
  Commitments
    and Contingencies
  20-year
 19




---



##### Table of Contents



After2008


2009


2010


2011


2012


2012


TotalLong-term debt and interest

$
1,104


$
323


$
106


$
107


$
488


$
2,254


$
4,382Operating leases


218



285



268



161



64



28



1,024Firm transportation agreements


165



100



68



36



33



147



549Unconditional purchase obligations


2,564



1,189



283



115



46



39



4,236Lease rentals and exploration work agreements


175



105



121



141



91



215



848Engineering and construction commitments


71























71$
4,297


$
2,002


$
846


$
560


$
722


$
2,683


$
11,110       Note 16
  Share
    Capital
        Common
    Shares
    Number of Shares


AmountDecember 31, 2004


847,472,828


$
3,506Options and warrants exercised


777,328



17December 31, 2005


848,250,156



3,523Options exercised


286,862



10December 31, 2006


848,537,018



3,533Options exercised


423,292



18December 31, 2007


848,960,310


$
3,551   Stock
    Options
     20




---



##### Table of Contents



Number of


Weighted


Weighted Average


OptionsOptions


Average


Contractual


Exercisable(thousands)


Exercise Prices


Life (years)


(thousands)December 31, 2004


19,929


$
11.30



4



2,834Granted


1,339


$
24.07



5Exercised for common shares


(718
)

$
7.92



1Surrendered for cash


(4,886
)

$
9.52



2Forfeited


(1,094
)

$
12.05



3December 31, 2005


14,570


$
12.91



3



3,066Granted


1,804


$
35.71



4Exercised for common shares


(287
)

$
11.15



2Surrendered for cash


(3,902
)

$
11.97



2Forfeited


(529
)

$
21.41



3December 31, 2006


11,656


$
16.40



3



4,463Granted


26,926


$
41.65



4Exercised for common shares


(423
)

$
11.84



1Surrendered for cash


(5,147
)

$
13.40



2Forfeited


(2,881
)

$
40.41



4December 31, 2007


30,131


$
37.18



4



4,494   As at December 31, 2007

Outstanding Options


Options ExercisableNumber of


Weighted


Weighted Average


Number of


WeightedOptions


Average


Contractual


Options


AverageRange of Exercise Price

(thousands)


Exercise Prices


Life (years)


(thousands)


Exercise Prices$7.23 - $9.99


44


$
7.26







44


$
7.26$10.00 - $10.99


27


$
10.32



1



27


$
10.32$11.00 - $12.99


3,832


$
11.74



1



3,832


$
11.74$13.00 - $19.99


130


$
15.92



2



84


$
15.39$20.00 - $29.99


455


$
26.17



3



205


$
26.43$30.00 - $39.99


1,258


$
35.89



3



302


$
36.46$40.00 - $42.57


24,385


$
41.65



4






$
30,131


$
37.18



4



4,494


$
14.09   Warrants
    Dividends
    Note 17
  Employee
    Future Benefits
  a)  Canada
   21




---



##### Table of Contents



Defined
    Benefit Pension Plan
    2007


2006


2005Discount rate (percent)


5.0



5.0



5.8Long-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



7.5         Benefit
    Obligation
  2007


2006


2005Benefit obligation, beginning of year

$
149


$
138


$
124Current service cost


2



3



2Interest cost


7



7



7Benefits paid


(8
)


(7
)


(6
)Actuarial losses






8



11Benefit obligation, end of year

$
150


$
149


$
138   Fair
    Value of Plan Assets
  2007


2006


2005Fair value of plan assets, beginning of year

$
132


$
108


$
96Contributions


10



13



11Benefits paid


(8
)


(7
)


(6
)Expected return on plan assets


10



8



7Gain on plan assets


(3
)


10



Fair value of plan assets, end of year

$
141


$
132


$
108   Funded
    Status of Plan
  2007


2006


2005Fair value of plan assets

$
141


$
132


$
108Benefit obligation


(150
)


(149
)


(138
)Excess obligation


(9
)


(17
)


(30
)Unrecognized past service costs


3



3



1Unrecognized losses


32



33



40Accrued benefit asset

$
26


$
19


$
11         2007


2006


2005U.S. common equities


1
%


1
%



%Canadian common equities


30



30



29International equity mutual funds


27



30



28Canadian government bonds


14



16



18Canadian corporate bonds


4



3



3International fixed income


2







Canadian fixed income mutual funds


20



19



20Cash and receivables


2



1



2Total


100
%


100
%


100
%  22




---



##### Table of Contents



Post-retirement
    Health and Dental Care Plan
      Benefit
    Obligation
  2007


2006


2005Benefit obligation, beginning of year

$
49


$
33


$
25Current service cost


4



2



2Interest cost


2



2



1Benefits paid


(1
)






Actuarial losses






12



5Benefit obligation, end of year

$
54


$
49


$
33   Funded
    Status of Plan
  2007


2006


2005Benefit obligation

$
(54
)

$
(49
)

$
(33
)Unrecognized losses


17



19



6Accrued benefit liability

$
(37
)

$
(30
)

$
(27
)     1%


1%Increase


DecreaseEffect on total service and interest cost components

$
2


$
(1
)Effect on post-retirement benefit obligation

$
12


$
(9
)   Pension
    Expense and Post-retirement Health and Dental Care
    Expense
    Pension
    Expense
  2007


2006


2005Defined benefit pension planEmployer current service cost

$
2


$
3


$
2Interest cost


7



7



7Expected return on plan assets


(10
)


(8
)


(7
)Amortization of net actuarial losses


3



3



32



5



5Defined contribution pension plan


18



16



14Total expense

$
20


$
21


$
19   Post-retirement
    Health and Dental Care Expense
  2007


2006


2005Employer current service cost

$
4


$
2


$
2Interest cost


2



2



1Amortization of net actuarial losses


1







Total expense

$
7


$
4


$
3  23




---



##### Table of Contents



Future
    Benefit Payments
    Defined Benefit


Post-retirement HealthPension Plan


and Dental Care Plan2008

$
8


$
12009


9



12010


9



12011


9



12012


10



22013 - 2017


52



10   b) United
    States
  Defined
    Benefit Pension Plan
      Post-retirement
    Welfare Plan
      Note 18
  Related
    Party Transactions
    Note 19
  Financial
    Instruments and Risk Management
        December 31, 2006


Adoption


January 1, 2007(As Reported)


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
)  24




---



##### Table of Contents



Carrying
    Values and Estimated Fair Values of Financial Assets and
    Liabilities
      2007


2006


2005Carrying


Fair


Carrying


Fair


Carrying


FairValue


Value


Value


Value


Value


ValueLong-term debt

$
2,814


$
2,903


$
1,611


$
1,671


$
1,886


$
1,995   Commodity
    Price Risk Management
  Natural
    Gas Contracts
    Volumes


Fair(mmcf)


ValuePhysical purchase contracts


32,930


$
6Physical sale contracts


(32,930
)

$
(5
)     Natural
    Gas Production
    Power
    Consumption
    Interest
    Rate Risk Management
    Debt

Amount


Swap Maturity


Swap Rate (percent)


Fair Value6.95% medium-term notes

$
200



July 14, 2009



CDOR + 175 bps


$
3       Embedded
    Derivative
    Foreign
    Currency Risk Management
   25




---



##### Table of Contents



CanadianDebt

Swap Amount


Equivalent


Swap Maturity


Interest Rate


Fair Value(percent)6.25% notes

U.S. $
150


$
212



June 15, 2012



7.41


$
(75
)6.25% notes

U.S. $
75


$
90



June 15, 2012



5.65


$
(13
)6.25% notes

U.S. $
50


$
59



June 15, 2012



5.67


$
(8
)6.25% notes

U.S. $
75


$
88



June 15, 2012



5.61


$
(11
)           Date

Forward Purchases


Canadian Equivalent


Fair ValueOctober 5, 2007

U.S. $
119


$
117


$
2October 11, 2007

U.S. $
119


$
116


$
2October 29, 2007

U.S. $
119


$
115


$
4       Unrecognized
    Gains (Losses) on Derivative Instruments
    2006


2005Interest rate risk managementInterest rate swaps

$
5


$
7Foreign currency risk managementForeign exchange contracts


(26
)


(32
)   Credit
    Risk
        Note 20
  Proposed
    Transaction with BP
   26




---



##### Table of Contents



Document
    C
 Form 40-F
     RECONCILIATION
    TO ACCOUNTING PRINCIPLES GENERALLY ACCEPTED
    IN THE UNITED STATES




---



##### Table of Contents



Report of
    Independent Registered Public Accounting Firm on
    Reconciliation
    to Accounting Principles Generally Accepted in the United
    States
  To
    the Board of Directors of Husky Energy Inc.
  Form 40-F. Form 40-F.
    KPMG
    llp
   llp
  
 1




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##### Table of Contents



Reconciliation
    to Accounting Principles Generally Accepted in the United
    States
    Consolidated
    Statements of Earnings
  2007


2006


2005($ millions, except pershare amounts)Net earnings under Canadian GAAP

$
3,214


$
2,726


$
2,003Adjustments:Full cost accounting (a)


56



64



66Related income taxes


(17
)


(20
)


(23
)Energy trading contracts (c)






4



Related income taxes






(1
)


Stock-based compensation (d)


(43
)


(10
)


Related income taxes


13



3



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


3,223



2,766



2,046Cumulative effect of change in accounting principle, net of tax
    (d)






11



Net earnings under U.S. GAAP

$
3,223


$
2,777


$
2,046Weighted average number of common shares outstanding under U.S.
    GAAP (millions)Basic and diluted


848.8



848.4



847.9Earnings per share before cumulative effect of change in
    accounting principle under U.S. GAAPBasic and diluted

$
3.80


$
3.26


$
2.41Earnings per share under U.S. GAAPBasic and diluted

$
3.80


$
3.27


$
2.41   Condensed
    Consolidated Balance Sheets
  2007


2006


2005Canadian


U.S.


Canadian


U.S.


Canadian


U.S.GAAP


GAAP


GAAP


GAAP


GAAP


GAAP($ millions)Current assets (b)(c)

$
3,048


$
3,048


$
2,179


$
2,190


$
1,535


$
1,591Property, plant and equipment, net (a)


17,805



17,431



15,550



15,120



13,959



13,465Other assets (g)


844



838



204



185



222



223$
21,697


$
21,317


$
17,933


$
17,495


$
15,716


$
15,279Current liabilities (b)(c)(d)(g)(h)

$
3,099


$
3,125


$
2,674


$
2,696


$
2,584


$
2,685Long-term debt (b)


2,073



2,093



1,511



1,557



1,612



1,670Other long-term liabilities (b)(d)(g)


918



955



756



749



730



688Future income taxes (a)(b)(c)(d)(g)(h)


3,957



3,806



3,372



3,210



3,270



3,089Share capital (d)(e)(f)


3,551



3,785



3,533



3,767



3,523



3,757Retained earnings


8,176



7,666



6,087



5,572



3,997



3,431Accumulated other comprehensive incomeDerivatives designated as cash flow hedges, net of tax (b)


(4
)


(4
)






(18
)






(21
)Cumulative foreign currency translation


(175
)


(175
)














Hedge of net investment, net of tax


102



102















Minimum pension liability, net of tax (g)






















(20
)Pension accounting (g)














(38
)






Pension obligation (g)






(36
)














$
21,697


$
21,317


$
17,933


$
17,495


$
15,716


$
15,279  2




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##### Table of Contents



Condensed
    Consolidated Statements of Retained Earnings and Accumulated
    Other Comprehensive Income
  2007


2006


2005Canadian


U.S.


Canadian


U.S.


Canadian


U.S.GAAP


GAAP


GAAP


GAAP


GAAP


GAAP($ millions)Retained earnings, beginning of year

$
6,087


$
5,572


$
3,997


$
3,431


$
2,694


$
2,085Net earnings


3,214



3,223



2,726



2,777



2,003



2,046Adoption of financial instruments (b)


4



















Dividends on common shares


(1,129
)


(1,129
)


(636
)


(636
)


(700
)


(700
)Retained earnings, end of year

$
8,176


$
7,666


$
6,087


$
5,572


$
3,997


$
3,431Accumulated other comprehensive income, beginning of year

$



$
(56
)

$



$
(41
)

$



$
(35
)Adoption of financial instruments (b)


(18
)


















Derivatives designated as cash flow hedges, net of tax (b)


14



14







3







(1
)Cumulative foreign currency translation


(175
)


(175
)














Hedge of net investment, net of tax


102



102















Minimum pension liability, net of tax (g)














(5
)






(5
)Reversal of minimum pension liability, net of tax (g)














25







Pension accounting (g)














(38
)






Pension obligation (g)






2















Accumulated other comprehensive income, end of year

$
(77
)

$
(113
)

$



$
(56
)

$



$
(41
)   Condensed
    Consolidated Statements of Earnings and Comprehensive
    Income
  2007


2006


2005Canadian


U.S.


Canadian


U.S.


Canadian


U.S.GAAP


GAAP


GAAP


GAAP


GAAP


GAAP($ millions)Sales and operating revenues (b)(c)

$
15,518


$
14,072


$
12,664


$
10,790


$
10,245


$
8,445Costs and expenses (excluding depletion, depreciation and
    amortization) (b)(c)(d)


9,408



8,005



7,422



5,554



6,112



4,312Accretion expense


47



47



45



45



33



33Depletion, depreciation and amortization (a)


1,806



1,750



1,599



1,535



1,256



1,190Interest  net


130



130



92



92



32



32Earnings before income taxes


4,127



4,140



3,506



3,564



2,812



2,878Income taxes (a)(c)(d)


913



917



780



798



809



832Earnings before cumulative effect of change in accounting
    principle


3,214



3,223



2,726



2,766



2,003



2,046Cumulative effect of change in accounting principle, net of tax
    (d)














11







Net earnings


3,214



3,223



2,726



2,777



2,003



2,046Other comprehensive income (b)(g)


(59
)


(57
)






2







6Comprehensive income

$
3,155


$
3,166


$
2,726


$
2,779


$
2,003


$
2,052       (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
    $52 million (2006  $60 million;
    2005  $62 million), before tax of
    $16 million (2006  $19 million;
    2005  $21 million).    (b)
    Effective January 1, 2007, the Company adopted the new
    Canadian GAAP standards relating to financial instruments. These
    standards have been adopted prospectively. This new guidance
    substantially harmonizes Canadian GAAP with U.S. GAAP, with
    the exception of the treatment of debt issue costs. Under the
    new Canadian GAAP requirements, unamortized debt issue costs are
    offset against the related long-term debt. Under U.S. GAAP,
    debt issue costs are deferred in other assets. At
    December 31, 2007, $20 million was reclassified from
    long term-debt to other assets for U.S. GAAP purposes. 3




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##### Table of Contents



(c)
    Prior to the adoption of the new Canadian standards for
    financial instruments, Canadian GAAP differed from
    U.S. GAAP with regards to natural gas purchase and sales
    contracts. Previously under Canadian GAAP, the impact of energy
    trading contracts was recorded as the contracts settled. Under
    the new Canadian standards for financial instruments, natural
    gas purchase and sale contracts related to energy trading
    activities are recorded at fair value, consistent 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
    U.S. GAAP, at December 31, 2006, the Company recorded
    additional assets and liabilities of $6 million
    (2005  $49 million) and nil (2005 
    $48 million), respectively, and included the unrealized
    gain, net of tax of $3 million (2005  gain of
    less than $1 million), in earnings for the year. For
    U.S. GAAP, unlike Canadian GAAP, these gains and losses
    continue to be netted against sales and operating revenues.(d)
    In January 2006, the Company adopted the fair value accounting
    provisions under FAS 123(R), Share-Based
    Payment. Under FAS 123(R) awards that are classified
    as liabilities are re-measured based on the awards fair
    value at each reporting date until settlement. Under
    FAS 123 awards classified as liabilities were measured at
    their intrinsic value. FAS 123(R) was adopted using the
    modified prospective application method. The related cumulative
    effect of the change in accounting principle to net earnings at
    January 1, 2006 was an increase of $16 million, before
    tax of $5 million. The change resulted in a decrease to
    current liabilities of $12 million and long-term
    liabilities of $4 million and an increase to future income
    tax liability of $5 million. There was no impact on the
    Companys cash flow as a result of adoption of
    FAS 123(R).      2007


2006Initial expected life (years)


3.5



3.5Expected annual dividend per share

$
1.32


$
1.00Range of expected volatilities used (%)


21.4 - 27.1



19.1 - 29.4Weighted-average expected volatility (%)


25.5



27.6Range of risk-free interest rates used (%)


3.7 - 3.9



3.9 - 4.2       (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)
    In December 2006, the Company adopted FAS 158,
    Employers Accounting for Defined Benefit Pension and
    Other Post-retirement Plans. This standard requires the
    Company to recognize the overfunded or underfunded status of a
    defined benefit post-retirement plan as an asset or liability.
    The funded status is measured as the difference between the fair
    value of a plans assets and its benefit obligations.
    Changes in this funded status are recognized through
    comprehensive income in the year in which the change occurs. The
    additional minimum liability previously recorded under
    FAS 87 has been eliminated. There is no impact to earnings
    recognition under the new requirement. 4




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##### Table of Contents



Before





AfterFAS 158


Adoption


FAS 158Adoption


Adjustment


Adoption($ millions)Consolidated Balance SheetsAssetsOther assets  prepaid pension asset

$
19


$
(19
)

$
Liabilities and Shareholders EquityAdditional minimum liability


36



(36
)


Other long-term liabilities  pension payable


30



(30
)


Current liabilities  unfunded status of plan






8



8Other long-term liabilities  unfunded status of plan






58



58Future income taxes


3,216



(6
)


3,210Accumulated other comprehensive income


(43
)


(13
)


(56
)             ($ millions)Balance at January 1, 2007

$
Additions based on tax positions related to the current year


30Balance at December 31, 2007

$
30         Tax Year

Jurisdiction1998 - 2007

Federal  Canada Revenue Agency (Alberta and Ontario)1999 - 2007

Internal Revenue Service  United States   Additional
    U.S. GAAP Disclosures
  Corporate
    Acquisitions
    Accounting
    for Derivative Instruments and Hedging Activities
     5




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##### Table of Contents



Stock
    Option Plan
    Depletion,
    Depreciation and Amortization
    2007


2006


2005Depletion, depreciation and amortization per boe

$
11.34


$
10.75


$
9.38   Accounting
    for Certain Hybrid Financial Instruments
    Accounting
    for Servicing of Financial Assets
    Accounting
    for Planned Major Maintenance Activities
  accrue-in-advance
  New
    Accounting Standards not yet Implemented
  Fair
    Value Measurement
   6




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##### Table of Contents



Employers
    Accounting for Defined Benefit Pension and Other Post-Retirement
    Plans
    Business
    Combinations and Non-Controlling Interests
   7




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##### Table of Contents



Document
    D
 Form 40-F
     Managements
    Discussion and Analysis
   February 21,
    2008




---



##### Table of Contents



Husky
    Energy Inc.
  Managements Discussion
    and Analysis
  For the Year Ended
    December 31, 2007
  February 21,
    2008.




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##### Table of Contents



MANAGEMENTS
    DISCUSSION AND ANALYSIS
  February 21, 2008
  TABLE OF
    CONTENTS
  Page1.

Financial Summary

21.1  Financial Position

21.2  Financial Performance

21.3  Selected Annual Information

32.

Huskys Businesses

33.

Capability to Deliver Results

33.1  Upstream

33.2  Midstream

43.3  Downstream

43.4  Corporate

44.

Strategic Plan

44.1  Upstream

44.2  Midstream

54.3  Downstream

54.4  Financial Objective

55.

Key  Performance Drivers

65.1  Across Segments

65.2  Upstream

65.3  Midstream

75.4  Downstream

75.5  Corporate

86.

The 2007 Business Environment

86.1  Risk Factors

86.2  Commodity Prices and Margins

96.3  Sensitivities by Segment for 2007 Results

117.

Results of Operations

127.1  Segment Earnings

127.2  Summary of Quarterly Results

137.3  Fourth Quarter

137.4  Upstream

147.5  Midstream

237.6  Downstream

257.7  Corporate

277.8  Results of Operations for 2006 Compared with 2005

288.

Liquidity and Capital Resources

288.1  Summary of Cash Flow

288.2  Working Capital Components

298.3  Cash Requirements

318.4  Off-Balance Sheet Arrangements

328.5  Transactions with Related Parties and Major
    Customers

328.6  Financial Risk and Risk Management

338.7  Outstanding Share Data

349.

Application of Critical Accounting Estimates

3410.

New and Pending Accounting Standards

3611.

Reader Advisories

3611.1  Forward-looking Statements

3611.2  Oil and Gas Reserve Reporting

3711.3  Non-GAAP Measures

3811.4  Additional Reader Advisories

3811.5  Controls and Procedures

4112.

Selected Quarterly Financial & Operating Information

42


1




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##### Table of Contents



1.
    FINANCIAL
    SUMMARY  1.1
    FINANCIAL
    POSITION  
  1.2
    FINANCIAL
    PERFORMANCE  
  Total
    Shareholder Returns
    Husky common shares


S&P/TSX energy index


S&P/TSX composite index2003


43%



24%



24%2004


46%



29%



12%2005


72%



61%



22%2006


32%



3%



15%2007


14%



5%



7%Five year average


40%



23%



16%Five year cumulative return


441%



178%



109%  2




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##### Table of Contents



1.3
    SELECTED
    ANNUAL INFORMATION  2007


2006


2005($ millions, except where indicated)Sales and operating revenues, net of royalties

$
15,518


$
12,664


$
10,245Segmented earningsUpstream

$
2,596


$
2,295


$
1,524Midstream


535



482



495Downstream


297



106



82Corporate and eliminations


(214
)


(157
)


(98
)Net earnings

$
3,214


$
2,726


$
2,003Per share  basic/diluted

$
3.79


$
3.21


$
2.36Dividends per common share

$
1.08


$
0.75


$
0.325Special dividend per common share

$
0.25


$



$
0.50Total assets

$
21,697


$
17,933


$
15,716Long-term debt excluding current portion

$
2,073


$
1,511


$
1,612Return on equity (percent)


30.2



31.8



29.2Return on average capital employed (percent)


25.7



27.0



22.8   2.
    HUSKYS
    BUSINESSES  upstream business segment (upgrading business
    segment), (infrastructure and marketing
    business segment) (Canadian refined products
    business segment) (U.S. refining and marketing
    business segment)
  3.
    CAPABILITY
    TO DELIVER RESULTS    3.1
    UPSTREAM  
    substantial position in the Alberta oil sands. The initial
    stages of the development of this asset include the Tucker oil
    sands project that is currently operating and the Sunrise
    project that is in the early development phase;
    leading position and extensive expertise in the exploration and
    production of heavy oil by both cold production and thermal
    recovery methods in Western Canada;
    large base of producing properties in Western Canada that have
    responded well to the application of increasingly sophisticated
    exploitation techniques;
    expertise and experience exploring and developing the
    significant natural gas potential in the deep basin, foothills,
    and northwest plains of Alberta and British Columbia;
    harsh weather offshore exploration, development and production
    expertise as demonstrated by the successful White Rose
    development offshore the East Coast of Canada. In addition to
    the White Rose oil field, we hold an interest in Terra Nova and
    a large portfolio of significant discovery and exploration
    licenses offshore Newfoundland and Labrador and offshore
    Greenland;
    large position offshore China that includes an interest in the
    Wenchang oil field and large portfolio of exploration blocks. By
    exploration, the Company discovered Chinas largest deep
    water natural gas field in 2006; and
    offshore Indonesia we hold significant discovery and exploration
    licenses. The Madura natural gas and natural gas liquids
    discovery is the current focus for development. 3




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##### Table of Contents



3.2
    MIDSTREAM  
    reliable heavy oil upgrading facility located in the
    Lloydminster heavy oil producing region with a throughput
    capacity of 82 mbbls/day;
    reliable and efficient heavy oil pipeline systems well
    integrated in the Lloydminster producing region;
    participation in two cogeneration power facilities having a
    combined 295 MW of capacity, both of which support local plant
    operations;
    natural gas storage in excess of 37 bcf, owned and leased;
    large scale petroleum marketer balancing the needs of both
    customers and suppliers; and
    large scale supplier of crude oil and natural gas feedstock for
    our plants and facilities.  3.3
    DOWNSTREAM  
    160 mbbls/day full product spectrum refinery at Lima, Ohio,
    U.S.A.;
    major regional marketer with 505 retail marketing locations
    including bulk plants and travel centers with strategic land
    positions in Western Canada;
    refinery in Prince George, British Columbia with 12 mbbls/day
    capacity of low sulphur gasoline and ultra low sulphur diesel;
    largest producer of ethanol in Western Canada with a combined
    260 million litre per year capacity at plants located in
    Lloydminster, Saskatchewan and Minnedosa, Manitoba;
    largest marketer of paving asphalt in Western Canada with a 28
    mbbls/day capacity asphalt refinery located in Lloydminster,
    integrated with the local heavy oil production transportation
    and upgrading infrastructure;
    strong product niche in the areas of quality products such as
    our ethanol enhanced  Mother Natures Fuel,
    Diesel Max, Chevron lubricants and our Black Max polymer
    modified asphalt;
    full retail network provides for substantial opportunities for
    ancillary non-fuel income streams, including convenience stores,
    restaurants, service bays and carwashes; and
    modern retail technology, with a proven new Husky Market design
    concept.  3.4
    CORPORATE    
    Section 8. Liquidity and Capital Resources
    Section 11.5 Controls and Procedures  4.
    STRATEGIC
    PLAN        4.1
    UPSTREAM  
    continue the development of our large holdings in the Alberta
    oil sands through in-situ recovery methods such as SAGD and
    other thermal recovery schemes;
    in Western Canada focus on natural gas exploration in the
    foothills and deep basin, and tight gas and coalbed methane in
    the plains region. Increase recovery from mature fields through
    enhanced recovery techniques. Explore in the central Mackenzie
    region of the Northwest Territories; 4




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##### Table of Contents




    optimize heavy oil production through cold production, thermal
    recovery techniques and other enhanced recovery techniques;
    maximize the value of the White Rose asset through the
    development of satellite tieback oil pools. Participate in the
    continuing development of Terra Nova. Pursue exploration
    opportunities and evaluate options to develop natural gas
    discoveries in the region;
    optimize production from the Wenchang oil field offshore China
    by pursuing infill and optimization opportunities;
    delineate the Liwan discovery offshore China and continue
    exploration in the surrounding area to complete the evaluation
    of Block 29/26. Continue exploration of our extensive acreage
    position offshore China and advance development options for
    Liwan discovery;
    advance the development of the Madura field offshore Indonesia
    and continue exploration on the Madura and East Bawean II
    production sharing contracts; and
    explore offshore Greenland, leveraging the experience we have
    gained off the East Coast of Canada.  4.2
    MIDSTREAM  
    continue to enhance and expand our infrastructure in the
    Lloydminster area and optimize the integration of the upgrader,
    pipeline, asphalt refinery, cogeneration and ethanol facilities;
    further expand the Companys natural gas business;
    enhance and expand our terminalling infrastructure and services
    to meet the requirements associated with growing bitumen and
    heavy oil development;
    position the Company with greenhouse gas management strategies
    including participation in industry initiatives, carbon offset
    opportunities and identification of carbon credit and trading
    opportunities; and
    identify and pursue logistics opportunities to meet the
    requirements associated with the Sunrise development and
    downstream initiatives.  4.3
    DOWNSTREAM  
    look at opportunities to expand asphalt production in
    Lloydminster;
    optimize synergies by integrating Lloydminster asphalt refinery
    outputs with that of the upgrader creating new refined products;
    maximize revenues by producing ethanol efficiently and
    effectively and marketing it profitably;
    construction of strategically located new outlets, enhancement
    of nonfuel income streams, upgrading of existing petroleum
    outlets and the sale of nonperforming locations;
    modernize, automate and upgrade existing petroleum outlets and
    technology used in operations;
    pursue mergers, joint venture or form partnerships in the light
    oil business outside of Western Canada;
    reconfigure and expand the Lima, Ohio refinery to improve
    operations and profitability by processing heavier crudes and
    bitumen blends; and
    reconfigure and expand the Toledo, Ohio refinery to accommodate
    Sunrise production as its primary feedstock.  4.4
    FINANCIAL
    OBJECTIVE      
    maintain debt to capitalization ratio of less than 40%; and
    maintain debt to cash flow from operations of less than two
    times. 5




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##### Table of Contents



5.
    KEY
    PERFORMANCE DRIVERS    5.1
    ACROSS
    SEGMENTS  Integrated
    Oil Sands Joint Development
    5.2
    UPSTREAM  White
    Rose Development and Delineation
      East
    Coast Exploration
  3-D
  Tucker
    Oil Sands Project
    Sunrise
    Oil Sands Project
    Caribou
    Saleski
   6




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##### Table of Contents



McMullen
    Oil Sands Acquisition
    Northwest
    Territories Exploration
    China
    Exploration
      Indonesia
    Exploration and Development
  3-D
  Land
    Acquisition Offshore Greenland
    2-D
  5.3
    MIDSTREAM  Lloydminster
    Pipeline
    Lloydminster
    Upgrader Expansion
    5.4
    DOWNSTREAM  Acquisition
    of the Lima Refinery in Ohio
   7




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##### Table of Contents



Ethanol
    5.5
    CORPORATE    6.
    THE 2007
    BUSINESS ENVIRONMENT  6.1
    RISK
    FACTORS    
    crude oil and natural gas prices;
    the price differential between light and heavy crude oil and
    demand related to various crude oil qualities;
    the price differential between refined products and crude oil
    (Crack Spread);
    the availability of incremental reserves of oil and gas, whether
    sourced from exploration, improved recovery or acquisitions;
    the availability of prospective drilling rights;
    the costs to acquire exploration rights, undertake geological
    studies, appraisal drilling and project development;
    the availability and cost of labour, material and equipment to
    efficiently, effectively and safely undertake capital projects;
    the costs to operate properties, plants and equipment in an
    efficient, reliable and safe manner;
    potential actions of governments, regulatory authorities and
    other stakeholders in the jurisdictions where we have operations;
    prevailing climatic conditions in our operating locations;
    the economic conditions of the markets in which we conduct
    business;
    regulations to deal with climate change issues;
    changes to government fiscal policies;
    the exchange rate between the Canadian and U.S. dollar;
    changes in workforce demographics; and
    the cost and availability of capital. 8




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##### Table of Contents



6.2
    COMMODITY
    PRICES AND MARGINS  Average Benchmarks

2007


2006


2005UpstreamWTI crude oil  (U.S. $/bbl)


72.31



66.22



56.56Brent crude oil  (U.S. $/bbl)


72.52



65.14



54.38Canadian light crude 0.3% sulphur  ($/bbl)


77.07



73.29



69.28Lloyd heavy crude oil @ Lloydminster  ($/bbl)


40.75



39.92



31.07NYMEX natural gas  (U.S. $/mmbtu)


6.86



7.23



8.62NIT natural gas  ($/GJ)


6.26



6.62



8.04Midstream heavy crude oil upgradingWTI/Lloyd crude blend differential  (U.S. $/bbl)


23.81



22.00



21.01DownstreamNew York Harbor 3:2:1 crack spread  (U.S. $/bbl)


14.15



9.80



9.50Cross segmentU.S./Canadian dollar exchange rate  (U.S. $)


0.931



0.882



0.826                9




---



##### Table of Contents



Crude
    Oil
  
    Natural
    Gas
  
   10




---



##### Table of Contents



6.3
    SENSITIVITIES
    BY SEGMENT FOR 2007 RESULTS    2007





Effect on Pre-tax


Effect onSensitivity Analysis

Average


Increase


Cash
    Flow(6)


Net
    Earnings(6)($ millions)


($/share)(7)


($ millions)


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

$
72.31


U.S. $
1.00/bbl



92



0.11



63



0.07NYMEX benchmark natural gas
    price(1)

$
6.86


U.S. $
0.20/mmbtu



33



0.04



23



0.03WTI/Lloyd crude blend
    differential(2)

$
23.81


U.S. $
1.00/bbl



(30
)


(0.04
)


(21
)


(0.02
)Exchange rate (U.S. $ per
    Cdn $)(3)

$
0.931


U.S. $
0.01



(72
)


(0.08
)


(52
)


(0.06
)DownstreamLight oil margins

$
0.05


Cdn $
0.005/litre



16



0.02



10



0.01Asphalt margins

$
18.24


Cdn $
1.00/bbl



8



0.01



5



0.01New York Harbor 3:2:1 crack
    spread(4)

$
14.15


U.S. $
1.00/bbl



24



0.03



15



0.02ConsolidatedYear-end translation of U.S. $ debt (U.S. $ per Cdn $)

$
1.012
(5)

U.S.$
0.01











18



0.02     (1)
    Includes decrease in earnings related to natural gas consumption.(2)
    Includes impact of upstream and midstream upgrading operations
    only.(3)
    Assumes no foreign exchange gains or losses on U.S. dollar
    denominated long-term debt and other monetary items.(4)
    The stated effect has been limited to the 6 month period
    from July 1, 2007, the effective acquisition date of the
    Lima refinery.(5)
    U.S./Canadian dollar exchange rate at December 31, 2007.(6)
    Excludes derivatives.(7)
    Based on 849.0 million common shares outstanding as of
    December 31, 2007. 11




---



##### Table of Contents



7.
    RESULTS
    OF OPERATIONS    
  7.1
    SEGMENT
    EARNINGS  Midstream


DownstreamInfrastructure


Canadian


U.S.


Corporateand


Refined


Refining and


andSegment Earnings

Upstream


Upgrading


Marketing


Products


Marketing


Eliminations


Total($ millions)2007Earnings (loss) before income taxes

$
3,299


$
372


$
351


$
242


$
168


$
(305
)

$
4,127Net earnings (loss)


2,596



282



253



192



105



(214
)


3,214Capital
    expenditures(1)


2,388



217



92



212



21



44



2,9742006Earnings (loss) before income taxes


2,975



382



277



146







(274
)


3,506Net earnings (loss)


2,295



285



197



106







(157
)


2,726Capital
    expenditures(1)


2,627



184



68



285







37



3,2012005Earnings (loss) before income taxes


2,173



449



278



129







(217
)


2,812Net earnings (loss)


1,524



313



182



82







(98
)


2,003Capital
    expenditures(1)


2,730



120



37



191







21



3,099    (1)
    Excludes capitalized costs related to asset retirement
    obligations incurred during the period and corporate
    acquisitions. 12




---



##### Table of Contents



7.2
    SUMMARY
    OF QUARTERLY RESULTS  (GRAPH)

(GRAPH)(GRAPH)

(GRAPH)   7.3
    FOURTH
    QUARTER   13




---



##### Table of Contents



7.4
    UPSTREAM  2007
    EARNINGS $2,596 MILLION, UP $301 MILLION FROM 2006
  Production
  
  Upstream
    Results of Operations
  Upstream Earnings
    Summary

2007


2006


2005($ millions)Gross revenues

$
7,287


$
6,586


$
5,207Royalties


1,065



814



840Net revenues


6,222



5,772



4,367Operating and administration expenses


1,409



1,321



1,050Depletion, depreciation and amortization


1,615



1,476



1,144Other(1)


(101
)






Income taxes


703



680



649Earnings

$
2,596


$
2,295


$
1,524     (1)
    Embedded derivative described below.  Revenue
        14




---



##### Table of Contents



Operating
    Costs
          Depletion,
    Depreciation and Amortization
    (DD&A)
  country-by-country
       15




---



##### Table of Contents



Embedded
    Derivative
    Average Sales Prices

2007


2006


2005Crude oil($/bbl)Light crude oil & NGL

$
73.54


$
69.06


$
61.56Medium crude oil


51.12



49.48



43.44Heavy crude oil & bitumen


40.19



39.92



31.09Total average


58.24



54.08



42.75Natural gas($/mcf)Average

$
6.19


$
6.47


$
7.96   Upstream Revenue Mix

2007


2006


2005Percentage of upstream net revenuesCrude oilLight crude oil & NGL


51%



45%



29%Medium crude oil


7%



7%



9%Heavy crude oil & bitumen


22%



24%



24%Natural gas


20%



24%



38%100%



100%



100%   
  16




---



##### Table of Contents



2007


2006


2005Netbacks

$


%(1)


$


%(1)


$


%(1)TotalCrude oil equivalent (per
    boe)(2)Gross price


52.41







49.34







44.69Royalties


7.74



15



6.19



12



7.29



17Net sales price


44.67







43.15







37.40Operating
    costs(3)


9.09



17



8.77



18



8.12



1835.58







34.38







29.28DD&A


11.75



22



11.24



23



9.95



22Administration expenses &
    other(3)


(0.17
)






0.48



1



0.20



Earnings before income taxes


24.00



46



22.66



46



19.13



43CanadaCrude oil equivalent (per
    boe)(2)Gross price


51.54







48.48







43.69Royalties


7.46



14



6.00



12



7.36



17Net sales price


44.08







42.48







36.33Operating
    costs(3)


9.28



18



9.01



19



8.39



19Operating netback


34.80







33.47







27.94Western CanadaCrude oil (per
    boe)(2)Light crude oilGross price


61.02







59.84







60.64Royalties


7.87



13



7.34



12



8.66



14Net sales price


53.15







52.50







51.98Operating
    costs(3)


13.24



22



11.89



20



9.86



16Operating netback


39.91







40.61







42.12Medium crude oilGross price


50.42







48.97







43.67Royalties


8.89



18



8.61



18



7.77



18Net sales price


41.53







40.36







35.90Operating
    costs(3)


13.92



28



13.09



27



10.97



25Operating netback


27.61







27.27







24.93Heavy crude oil & bitumenGross price


40.14







39.91







31.22Royalties


5.26



13



5.16



13



3.75



12Net sales price


34.88







34.75







27.47Operating
    costs(3)


12.81



32



11.10



28



9.90



32Operating netback


22.07







23.65







17.57Natural gas (per
    mcfge)(4)Gross price


6.42







6.65







8.02Royalties


1.23



19



1.37



21



1.76



22Net sales price


5.19







5.28







6.26Operating
    costs(3)


1.39



22



1.18



18



1.04



13Operating netback


3.80







4.10







5.22 17




---



##### Table of Contents



2007


2006


2005Netbacks (continued)

$


%(1)


$


%(1)


$


%(1)East CoastLight crude oil (per
    boe)(2)Gross price


75.37







71.18







62.61Royalties(5)


9.43



13



1.95



3



5.91



9Net sales price


65.94







69.23







56.70Operating
    costs(3)


4.07



5



5.48



8



5.14



8Operating netback


61.87







63.75







51.56InternationalLight crude oil (per
    boe)(2)Gross price


77.07







73.60







63.15Royalties


15.50



20



12.17



17



5.93



9Net sales price


61.57







61.43







57.22Operating
    costs(3)


3.84



5



3.81



5



2.92



5Operating netback


57.73







57.62







54.30     (1)
    Percent of gross price.(2)
    Includes associated co-products converted to boe.(3)
    Operating costs exclude accretion, which is included in
    administration expenses & other.(4)
    Includes associated co-products converted to mcfge.(5)
    During the third quarter of 2007, White Rose royalties increased
    to 16% because the project, off the East Coast, achieved payout
    status for Tier 1 royalties.  Daily Gross
    Production

2007


2006


2005Crude oil  (mbbls/day)Western CanadaLight crude oil & NGL


26.5



30.4



31.4Medium crude oil


27.1



28.5



31.1Heavy crude oil & bitumen


106.9



108.1



106.0160.5



167.0



168.5East Coast CanadaWhite Rose  light crude oil


85.0



63.8



4.8Terra Nova  light crude oil


14.5



4.7



12.4ChinaWenchang  light crude oil & NGL


12.7



12.1



16.0272.7



247.6



201.7Natural gas  (mmcf/day)


623.3



672.3



680.0Total  (mboe/day)


376.6



359.7



315.0   2008
    Production Guidance
  Year ended


OriginalGuidance


December 31


GuidanceGross Production

2008


2007


2007Crude oil & NGL  (mbbls/day)Light crude oil & NGL


139 - 148



139



128 - 135Medium crude oil


28 - 29



27



28 - 30Heavy crude oil & bitumen


114 - 124



107



122 - 130281 - 301



273



278 - 295Natural gas  (mmcf/day)


625 - 655



623



670 - 690Total barrels of oil equivalent  (mboe/day)


385 - 410



377



390 - 410   18




---



##### Table of Contents



Upstream
Capital
Expenditure(1)

2007


2006


2005($ millions)ExplorationWestern Canada

$
456


$
497


$
389East Coast Canada and Frontier


84



79



66International


70



77



55610



653



510DevelopmentWestern Canada


1,575



1,675



1,618East Coast Canada


197



279



579International


6



20



231,778



1,974



2,220$
2,388


$
2,627


$
2,730    (1)
    Excludes capitalized costs related to asset retirement
    obligations incurred during the period and corporate
    acquisitions.  2007


2006


2005Western Canada
    Drilling

Gross


Net


Gross


Net


Gross


Net(wells)ExplorationOil


79



79



101



99



89



85Gas


114



92



330



192



392



196Dry


14



12



26



24



36



36207



183



457



315



517



317DevelopmentOil


571



530



590



543



466



433Gas


343



251



565



490



610



551Dry


31



29



25



22



42



39945



810



1,180



1,055



1,118



1,023Total


1,152



993



1,637



1,370



1,635



1,340   Upstream
    Capital Expenditure  Canada
         19




---



##### Table of Contents



Upstream
    Capital Expenditure  International
    2008
    Upstream Capital Program
  ($ millions)Western Canada  oil and gas

$
1,670
    oil sands


300East Coast Canada and Frontier


650International


430$
3,050                Oil
    and Gas Reserves
  51-101 51-101.
  20




---



##### Table of Contents



51-101, www.sedar.com Form 40-F www.sec.gov www.huskyenergy.ca
      
  21




---



##### Table of Contents



Canada


International


TotalEastWestern Canada


CoastLightCrude


Medium


Heavy








Light








CrudeOil


Crude


Crude





Natural


Crude


Light


Natural


Oil


Natural


EquivalentReconciliation of Proved Reserves

& NGL


Oil


Oil


Bitumen


Gas


Oil


Crude 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, 2006


166



87



213



60



2,143



107



14







647



2,143



1,004Technical revisions


1



4



(8
)






64



26



2







25



64



36Purchase of reserves in place


1















36















1



36



7Sale of reserves in place


(10
)














(23
)














(10
)


(23
)


(14
)Discoveries, extensions and improved recovery


10



7



38



11



199



19











85



199



118Production


(9
)


(10
)


(38
)


(1
)


(228
)


(36
)


(5
)






(99
)


(228
)


(137
)Proved reserves at December 31, 2007


159



88



205



70



2,191



116



11







649



2,191



1,014Proved and probable reserves At December 31, 2007


213



105



282



1,835



2,664



216



37



516



2,688



3,180



3,218At December 31, 2006


219



102



289



1,187



2,533



186



23



93



2,006



2,626



2,444   Canada


International


TotalEastWestern Canada


CoastLightCrude





Heavy








Light





CrudeOil &


Medium


Crude





Natural


Crude


Light


Oil &


Natural


EquivalentReconciliation of Proved Developed Reserves

NGL


Crude Oil


Oil


Bitumen


Gas


Oil


Crude 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, 2006


147



79



135



47



1,703



97



13



518



1,703



802Revision of previous estimate


3



9



16



1



180



33



3



65



180



95Purchase of reserves in place


















30















30



5Sale of reserves in place


(9
)














(22
)










(9
)


(22
)


(13
)Improved recovery


4



2



11







117











17



117



36Production


(9
)


(10
)


(38
)


(1
)


(228
)


(36
)


(5
)


(99
)


(228
)


(137
)Proved developed reserves at December 31, 2007


136



80



124



47



1,780



94



11



492



1,780



788   22




---



##### Table of Contents



7.5
    MIDSTREAM  2007
    EARNINGS $535 MILLION, UP $53 MILLION FROM 2006
    Upgrader
    Pipelines  
  Upgrading
    Earnings Summary
   23




---



##### Table of Contents



Upgrading Earnings
    Summary

2007


2006


2005($ millions, exceptwhere indicated)Gross margin

$
614


$
624


$
692Operating costs


221



224



228Other recoveries


(4
)


(6
)


(6
)Depreciation and amortization


25



24



21Income taxes


90



97



136Earnings

$
282


$
285


$
313Upgrader
    throughput(1)(mbbls/day)


61.4



71.0



66.6Synthetic crude oil sales  (mbbls/day)


53.1



62.5



57.5Upgrading differential  ($/bbl)

$
30.73


$
26.16


$
30.70Unit margin  ($/bbl)

$
31.67


$
27.35


$
33.01Unit operating
    cost(2)($/bbl)

$
9.83


$
8.65


$
9.38    (1)
    Throughput includes diluent returned to the field.(2)
    Based on throughput.  
  Infrastructure
    and Marketing Earnings Summary
    24




---



##### Table of Contents



Infrastructure and Marketing
    Earnings Summary

2007


2006


2005($ millions, except where indicated)Gross marginPipeline

$
115


$
104


$
92Other infrastructure and marketing


278



208



217393



312



309Other expenses


14



11



10Depreciation and amortization


28



24



21Income taxes


98



80



96Earnings

$
253


$
197


$
182Aggregate pipeline throughput (mbbls/day)


501



475



474   Midstream
    Capital Expenditure
      7.6
    DOWNSTREAM  2007
    EARNINGS $297 MILLION, UP $191 MILLION FROM 2006
        Canadian
    Refined Products
  
 25




---



##### Table of Contents



Downstream
    Earnings Summaries
  Canadian Refined Products
    Earnings Summary

2007


2006


2005($ millions, except where indicated)Gross marginFuel sales

$
188


$
138


$
126Ancillary sales


42



36



34Asphalt sales


160



94



91390



268



251Operating and other expenses


82



74



75Depreciation and amortization


66



48



47Income taxes


50



40



47Earnings

$
192


$
106


$
82Number of fuel outlets


505



505



515Refined products sales volumeLight oil products (million litres/day)


8.7



8.7



8.9Light oil products per outlet (thousand litres/day)


13.2



12.9



12.7Asphalt products (mbbls/day)


21.8



23.4



22.5Refinery throughputPrince George refinery (mbbls/day)


10.5



9.0



9.7Lloydminster refinery (mbbls/day)


25.3



27.1



25.5Ethanol production (thousand litres/day)


324.6



59.7



25.6   U.S. Refining and Marketing
    Earnings Summary

2007($ millions, exceptwhere indicated)Gross refining margin

$
310Processing costs


93Operating and other expenses


1Interest  net


1Depreciation and amortization


47Income taxes


63Earnings

$
105Selected operating data:Refinery throughput  (mbbls/day)Crude oil


135Other feedstock


9Yield  (mbbls/day)Gasoline


82Middle distillates


47Other fuel and feedstock


16Margins  ($/bbl crude throughput)Gross refining margin


12.42Unit operating costs  ($/bbl of yield)


3.48Refined product sales  (mbbls/day)Gasoline


81Middle distillates


46Other fuel and feedstock


13   Downstream
    Capital Expenditure
   26




---



##### Table of Contents



7.7
    CORPORATE  2007
    EXPENSE $214 MILLION, UP $57 MILLION FROM 2006
    Corporate Earnings
    Summary

2007


2006


2005($ millions) income (expense)Intersegment eliminations  net

$
(51
)

$
20


$
(50
)Administration expenses


(151
)


(199
)


(143
)Depreciation and amortization


(25
)


(27
)


(23
)Interest  net


(129
)


(92
)


(32
)Foreign exchange


51



24



31Income taxes


91



117



119Earnings (expense)

$
(214
)

$
(157
)

$
(98
)   Foreign Exchange
    Summary

2007


2006


2005($ millions)(Gain) loss on translation of U.S. dollar denominated long-term
    debtRealized





$







$
(42
)





$
(13
)Unrealized






(197
)






35







(38
)(197
)






(7
)






(51
)Cross currency swapsRealized














47







Unrealized






62







(43
)






1462







4







14Other (gains) losses






84







(21
)






6$
(51
)





$
(24
)





$
(31
)U.S./Canadian dollar exchange rates:At beginning of year


U.S.


$
0.858



U.S.


$
0.858



U.S.


$
0.831At end of year


U.S.


$
1.012



U.S.


$
0.858



U.S.


$
0.858   Foreign
    Exchange Risk
     27




---



##### Table of Contents



Consolidated
    Income Taxes
        2007


2006


2005($ millions)Income taxes before tax amendments

$
1,308


$
1,108


$
813Canadian federal and provincial tax amendments


395



328



4Income taxes as reported

$
913


$
780


$
809   Corporate
    Capital Expenditure
    7.8
    RESULTS
    OF OPERATIONS FOR 2006 COMPARED WITH 2005    Upstream 
  Midstream 
  Downstream 
  Corporate 
  8.
    LIQUIDITY
    AND CAPITAL RESOURCES  8.1 SUMMARY
    OF CASH FLOW
  2007


2006


2005Cash flow  operating activities
    ($ millions)

$
4,657


$
5,009


$
3,650
    financing activities ($ millions)

$
433


$
(1,626
)

$
(668
)
    investing activities ($ millions)

$
(5,324
)

$
(3,109
)

$
(2,814
)Debt to capital employed (percent)


19.5



14.3



20.1Corporate reinvestment
    ratio(1)


0.9



0.7



0.8     (1)
    Reinvestment ratio is based on net capital expenditures
    including corporate acquisitions. 28




---



##### Table of Contents



Cash
    Flow from Operating Activities
    Cash
    Flow from (used for) Financing Activities
    Cash
    Flow used for Investing Activities
    8.2
    WORKING
    CAPITAL COMPONENTS    2007


2006


Change($ millions)Current assetsCash and cash equivalents

$
208


$
442


$
(234
)

Tax paymentAccounts receivable


1,622



1,284



338


Inclusion of Lima receivablesInventories


1,190



428



762


Inclusion of Lima inventoryPrepaid expenses


28



25



33,048



2,179



869Current liabilitiesAccounts payable


1,460



1,268



(192
)

Inclusion of Lima payables offset by lower capital accrualsAccrued interest payable


20



27



7Income taxes payable


36



615



579


Tax payment and deferred earningsOther accrued liabilities


842



664



(178
)

Higher accruals due to Lima and increase in dividend offset by
    lower stock-based compensation in 2007Long-term debt due within one year


741



100



(641
)

Bridge financing for Lima acquisition3,099



2,674



(425
)Working capital

$
(51
)

$
(495
)

$
444   Sources
    and Uses of Cash
   29




---



##### Table of Contents



10-year 30-year
        two-for-one two-for-one
      30




---



##### Table of Contents



December 31, 2007Outstanding


AvailableCapital Structure

(U.S. $)


(Cdn $)


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

$



$



$
197Long-term bank debtSyndicated credit facility










1,250Bilateral credit facilities










150Bridge facility


750



741Medium-term
    notes(1)






200Capital securities


225



223U.S. public notes


1,650



1,6302,625



2,794



1,597Fair value
    adjustment(1)






3Debt issue
    costs(2)






(20
)Unwound interest rate
    swaps(3)






37Total short-term and long-term debt

$
2,625


$
2,814


$
1,597Common shares, retained earnings and accumulated other
    comprehensive income





$
11,650     (1)
    The carrying value of the medium-term notes has been adjusted to
    fair value to meet the accounting requirements for a fair value
    hedge. Refer to Note 19 to the Consolidated Financial
    Statements.(2)
    Debt issue costs have been reclassified to long-term debt with
    the adoption of financial instruments. Previously these deferred
    costs were included in other assets. Refer to Note 12 to
    the Consolidated Financial Statements.(3)
    The unamortized portion of the gain on previously unwound
    interest rate swaps that would be designated as fair value
    hedges is required to be included in the carrying value of
    long-term debt with the adoption of financial instruments. Refer
    to Note 12 to the Consolidated Financial Statements.  Credit
    Ratings
    8.3
    CASH
    REQUIREMENTS  Contractual
    Obligations and Other Commercial Commitments
    2009-


2011-Contractual
    Obligations

Total


2008


2010


2012


ThereafterPayments due by period ($ millions)Long-term debt and interest on fixed rate debt

$
4,382


$
1,104


$
429


$
595


$
2,254Operating leases


1,024



218



553



225



28Firm transportation agreements


549



165



168



69



147Unconditional purchase
    obligations(1)


4,236



2,564



1,472



161



39Lease rentals and exploration work agreements


848



175



226



232



215Engineering and construction commitments


71



71











$
11,110


$
4,297


$
2,848


$
1,282


$
2,683     (1)
    Includes purchase of refined petroleum products, processing
    services, distribution services, insurance premiums and natural
    gas purchases.   31




---



##### Table of Contents



Estimated
    Obligations Not Included in the Table
  
    Asset retirement obligations (ARO)    
    Employee future benefits    Other
    Obligations
    8.4
    OFF-BALANCE
    SHEET ARRANGEMENTS  Accounts
    Receivable Securitization Program
      Standby
    Letters of Credit
    Derivative
    Instruments
    8.5
    TRANSACTIONS
    WITH RELATED PARTIES AND MAJOR CUSTOMERS     32




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##### Table of Contents



8.6
    FINANCIAL
    RISK AND RISK MANAGEMENT    Commodity
    Price Risk Management
    Power
    Consumption
    Foreign
    Currency Risk Management
    
    U.S. $150 million at 6.250% swapped at $1.41 to
    $212 million at 7.41% until June 15, 2012.
    U.S. $75 million at 6.250% swapped at $1.19 to
    $90 million at 5.65% until June 15, 2012.
    U.S. $50 million at 6.250% swapped at $1.17 to
    $59 million at 5.67% until June 15, 2012.
    U.S. $75 million at 6.250% swapped at $1.17 to
    $88 million at 5.61% until June 15, 2012.              Interest
    Rate Risk Management
         33




---



##### Table of Contents



8.7 OUTSTANDING
    SHARE DATA
    
    unlimited number of common shares
    unlimited number of preferred shares    


common shares


849,018,162


preferred shares


none


stock options


30,195,824


stock options exercisable


4,021,714
     9.
    APPLICATION
    OF CRITICAL ACCOUNTING ESTIMATES    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
  country-by-country
  Withheld
    Costs
    Ceiling
    Test
   34




---



##### Table of Contents



IMPAIRMENT
    OF LONG-LIVED ASSETS
    FAIR
    VALUE OF DERIVATIVE INSTRUMENTS
      ASSET
    RETIREMENT OBLIGATION
  sub-sea
    LEGAL,
    ENVIRONMENTAL REMEDIATION AND OTHER CONTINGENT MATTERS
    INCOME
    TAX ACCOUNTING
    BUSINESS
    COMBINATIONS
    GOODWILL
   35




---



##### Table of Contents



10.
    NEW AND
    PENDING ACCOUNTING STANDARDS  NEW
  Financial
    Instruments
    Accounting
    Changes
    PENDING
  Financial
    Instruments  Disclosures and
    Presentation
    Capital
    Disclosures
    11.
    READER
    ADVISORIES  11.1
    FORWARD-LOOKING
    STATEMENTS   36




---



##### Table of Contents




    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.    11.2
    OIL AND
    GAS RESERVE REPORTING  DISCLOSURE
    OF PROVED OIL AND GAS RESERVES AND OTHER OIL AND GAS
    INFORMATION
  51-101, Rule 4-10 Regulation S-X 51-101. 51-101
   37




---



##### Table of Contents



CAUTIONARY
    NOTE TO U.S. INVESTORS
  Form 40-F
  11.3
    NON-GAAP MEASURES      2007


2006


2005($ millions)Non-GAAPCash flow from operations

$
5,426


$
4,501


$
3,785Settlement of asset retirement obligations


(51
)


(36
)


(41
)Change in non-cash working capital


(718
)


544



(72
)GAAPCash flow  operating activities

$
4,657


$
5,009


$
3,672     11.4
    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 www.sedar.com www.sec.gov www.huskyenergy.ca
  Use of
    Pronouns and Other Terms
    Standard
    Comparisons in this Document
   38




---



##### Table of Contents



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 the U.S. GAAP reconciliation
    contained in
    Form 40-F
    and available at www.sedar.com.
    Currency is presented in millions of Canadian dollars
    (C$).
    Gross production and reserves are Huskys working interest
    prior to deduction of royalty volume.
    Prices are presented before the effect of hedging.
    Light crude oil is
    30o
    API and above.
    Medium crude oil is
    21o
    API and above but below
    30o
    API.
    Heavy crude oil is above
    10o
    API but below
    21o
    API.
    Bitumen is
    10o
    API and below. 39




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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
    equivalentGAAP
    
    Generally Accepted Accounting
    PrinciplesGJ
    
    gigajoulemmbtu
    
    million British Thermal
    Unitsmmlt
    
    million long tonsMW
    
    megawattNGL
    
    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 CountriesSAGD
    
    Steam-assisted gravity
    drainageMD&A
    
    Managements Discussion and
    AnalysisCNLOPB
    
    Canada-Newfoundland and Labrador
    Offshore Petroleum Board


TERMS
 Bitumen
    
    A naturally occurring viscous
    mixture consisting mainly of pentanes and heavier hydrocarbons.
    It is more viscous than 10 degrees APIBrent Crude Oil
    
    Prices which are dated less than
    15 days prior to loading for deliveryCapital 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 seamsCorporate Reinvestment Ratio
    
    Net capital expenditures
    (capital expenditures net of proceeds from asset sales) plus
    corporate acquisitions (net assets acquired) divided by cash
    flow from operationsDebt to Capital Employed
    
    Total debt divided by total debt
    and shareholders equityDesign Rate Capacity
    
    Maximum continuous rated output
    of a plant based on its designEmbedded Derivative
    
    Implicit or explicit term(s) in
    a contract that affects some or all of the cash flows or the
    value of other exchanges required by the contractFeedstock
    
    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 economicsGlory Hole
    
    An excavation in the seabed
    where the wellheads and other equipment are situated to protect
    them from scouring icebergsGross/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
    royaltiesInterest Coverage Ratio
    
    A calculation of a
    companys ability to pay to meet its interest payment
    obligation. It is equal to earnings before income taxes and
    interest divided by interest paid before deduction of
    capitalized interestNOVA 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 togetherReturn on Capital Employed
    
    Net earnings plus after tax
    interest expense divided by average capital employedReturn on Shareholders
    Equity
    
    Net earnings divided by average
    shareholders equitySeismic
    
    A method by which the physical
    attributes in the outer rock shell of the earth are determined
    by measuring, with a seismograph, the rate of transmission of
    shock waves through the various rock formationsShareholders Equity
    
    Shares, retained earnings and
    accumulated other comprehensive incomeTotal Debt
    
    Long-term debt including current
    portion and bank operating loans Proved reserves have been estimated in accordance
    with the SEC definition set out in
    Rule 4-10(a)
    of
    Regulation S-X
    under the Securities Exchange Act of 1934 as follows: Proved oil
    and gas reserves are the estimated quantities of crude oil,
    natural gas and natural gas liquids, which geological and
    engineering data demonstrate with reasonable certainty to be
    recoverable in future years from known reservoirs under existing
    economic and operating conditions. Prices include consideration
    of changes in existing prices provided only by contractual
    arrangements, but not on escalations based upon future
    conditions.
 Proved Developed reserves are those reserves that
    can be expected to be recovered through existing wells with
    existing equipment and operating methods. Additional oil and gas
    expected to be obtained through the application of fluid
    injection or other improved recovery techniques for
    supplementing the natural forces and mechanisms of primary
    recovery are included as proved developed reserves only after
    testing by a pilot project or after the operation of an
    installed program has confirmed through production response that
    increased recovery will be achieved.
 Proved Undeveloped reserves are those reserves
    that are expected to be recovered from new wells on undrilled
    acreage, or from existing wells for which a relatively major
    expenditure is required for recompletion. Inclusion of reserves
    on undrilled acreage is limited to those drilling units
    offsetting productive units that are reasonably certain of
    production when drilled. Proved reserves for other undrilled
    units are included only if it can be demonstrated with certainty
    that there is continuity of production from the existing
    productive formation. Estimates for proved undeveloped reserves
    are not attributed to any acreage for which an application of
    fluid injection or other improved recovery technique is
    contemplated, unless such techniques have been proved effective
    by actual tests in the area and in the same reservoir.
 Probable reserves are those additional reserves
    that are less certain to be recovered than proved reserves. It
    is equally likely that the actual remaining quantities recovered
    will be greater or less than the sum of the estimated proved and
    probable reserves.
 40




---



##### Table of Contents



11.5
    CONTROLS
    AND PROCEDURES  Disclosure
    Controls and Procedures
    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, 2007, management assessed the
    effectiveness of Huskys internal control over financial
    reporting and concluded that such internal control over
    financial reporting is effective and that there are no material
    weaknesses in Huskys internal control over financial
    reporting that have been identified by management.    4)
    KPMG LLP, who has audited the Consolidated Financial Statements
    of Husky for the year ended December 31, 2007, has also
    issued a report on internal controls under Auditing Standard
    No. 5 of the Public Company Accounting Oversight Board
    (United States).  Changes
    in Internal Control over Financial Reporting
   41




---



##### Table of Contents



12.
    SELECTED
    QUARTERLY FINANCIAL & OPERATING INFORMATION  Segmented
    Operational Information
  2007


2006Q4


Q3


Q2


Q1


Q4


Q3


Q2


Q1UpstreamDaily production, before royaltiesLight crude oil & NGL (mbbls/day)


129.7



133.3



144.3



147.8



128.2



117.2



97.7



100.5Medium crude oil (mbbls/day)


27.0



26.7



26.8



27.5



28.0



28.1



28.5



29.4Heavy crude oil & bitumen (mbbls/day)


107.8



106.5



105.4



108.0



109.5



107.9



105.6



109.5264.5



266.5



276.5



283.3



265.7



253.2



231.8



239.4Natural gas (mmcf/day)


617.8



620.1



615.7



640.0



662.2



669.1



672.8



685.4Total production (mboe/day)


367.5



369.9



379.1



390.0



376.1



364.7



344.0



353.6Average sales pricesLight crude oil & NGL ($/bbl)

$
83.43


$
76.00


$
72.28


$
64.88


$
62.55


$
74.05


$
73.74


$
67.04Medium crude oil ($/bbl)

$
55.37


$
54.55


$
48.15


$
46.40


$
43.99


$
57.35


$
58.42


$
38.39Heavy crude oil & bitumen ($/bbl)

$
41.13


$
43.64


$
38.31


$
37.62


$
35.46


$
49.62


$
48.12


$
26.73Natural gas ($/mcf)

$
5.72


$
5.18


$
6.91


$
6.94


$
6.19


$
5.69


$
5.95


$
8.06Operating costs ($/boe)

$
9.61


$
9.60


$
8.84


$
8.34


$
9.51


$
8.45


$
8.24


$
8.78Operating
    netbacks(1)Light crude oil
    ($/boe)(2)

$
61.39


$
53.66


$
59.13


$
56.14


$
51.66


$
61.86


$
60.40


$
54.86Medium crude oil
    ($/boe)(2)

$
29.99


$
28.81


$
26.95


$
24.67


$
21.02


$
33.34


$
35.06


$
19.72Heavy crude oil & bitumen
    ($/boe)(2)

$
21.56


$
25.11


$
20.37


$
21.11


$
18.94


$
32.01


$
31.30


$
12.65Natural gas
    ($/mcfge)(3)

$
3.60


$
3.05


$
4.32


$
4.24


$
3.73


$
3.55


$
3.98


$
5.16Total
    ($/boe)(2)

$
36.01


$
33.68


$
36.91


$
35.70


$
31.00


$
38.46


$
37.34


$
30.89Net wells
    drilled(4)Exploration       Oil


23



23



13



20



29



41



7



22Gas


20



13



3



56



42



46



18



86Dry






2



1



9



2



5



3



1443



38



17



85



73



92



28



122Development    Oil


143



203



54



130



209



174



57



103Gas


56



54



4



137



159



115



23



193Dry


10



7



2



10



5



6



2



9209



264



60



277



373



295



82



305252



302



77



362



446



387



110



427Success ratio (percent)


96



97



96



95



98



97



95



95MidstreamSynthetic crude oil sales (mbbls/day)


66.5



55.1



32.9



57.8



64.1



65.7



56.9



63.4Upgrading differential ($/bbl)

$
36.74


$
30.41


$
30.41


$
24.11


$
23.81


$
23.75


$
22.73


$
34.82Pipeline throughput (mbbls/day)


497



506



506



493



465



457



480



500Canadian Refined ProductsRefined products sales volumesLight oil products (million litres/day)


8.5



9.0



8.6



8.9



8.6



9.1



8.6



8.6Asphalt products (mbbls/day)


24.5



25.9



19.5



17.3



21.0



30.0



24.9



17.7Refinery throughputLloydminster refinery (mbbls/day)


28.8



29.0



18.5



24.7



28.1



27.9



25.4



27.1Prince George refinery (mbbls/day)


11.6



10.8



8.4



11.1



11.2



11.6



3.7



9.3Refinery utilization (percent)


101



100



67



90



98



99



73



91     (1)
    Operating netbacks are Huskys average prices less
    royalties and operating costs on a per unit basis.(2)
    Includes associated co-products converted to boe.(3)
    Includes associated co-products converted to mcfge.(4)
    Western Canada. 42




---



##### Table of Contents





Segmented
    Financial Information
  MidstreamUpstream


Upgrading


Infrastructure and MarketingQ4


Q3


Q2


Q1


Q4


Q3


Q2


Q1


Q4


Q3


Q2


Q1($ millions)2007Sales and operating revenues, net of royalties

$
1,568


$
1,496


$
1,593


$
1,565


$
530


$
406


$
229


$
359


$
2,617


$
2,524


$
2,521


$
2,555Costs and expensesOperating, cost of sales, selling and general


358



332



295



323



358



305



186



278



2,509



2,423



2,445



2,461Depletion, depreciation and amortization


396



413



407



399



8



7



4



6



7



7



7



7Interest  net














































Foreign exchange














































754



745



702



722



366



312



190



284



2,516



2,430



2,452



2,468Earnings (loss) before income taxes


814



751



891



843



164



94



39



75



101



94



69



87Current income taxes


41



56



3



22



5



4







1



18



5



29



16Future income taxes


(91
)


179



252



241



22



25



10



23



2



25



(8
)


11Net earnings (loss)

$
864


$
516


$
636


$
580


$
137


$
65


$
29


$
51


$
81


$
64


$
48


$
60Capital
    expenditures(2)

$
706


$
545


$
520


$
617


$
44


$
51


$
74


$
48


$
15


$
36


$
5


$
36Goodwill additions

$



$



$



$



$



$



$



$



$



$



$



$
Total assets

$
14,395


$
14,085


$
13,974


$
14,168


$
1,405


$
1,354


$
1,193


$
1,177


$
1,134


$
1,016


$
1,147


$
1,0572006Sales and operating revenues, net of royalties

$
1,434


$
1,600


$
1,451


$
1,287


$
385


$
485


$
404


$
405


$
2,377


$
2,451


$
2,267


$
2,464Costs and expensesOperating, cost of sales, selling and general


373



329



308



311



293



399



319



262



2,300



2,396



2,190



2,372Depletion, depreciation and amortization


389



382



354



351



6



6



6



6



7



6



5



6Interest  net














































Foreign exchange














































762



711



662



662



299



405



325



268



2,307



2,402



2,195



2,378Earnings (loss) before income taxes


672



889



789



625



86



80



79



137



70



49



72



86Current income taxes


62



158



156



143



(31
)


31



29



24



22



18



20



19Future income taxes


157



123



(189
)


70



58



(5
)


(29
)


20



2



(2
)


(9
)


10Net earnings (loss)

$
453


$
608


$
822


$
412


$
59


$
54


$
79


$
93


$
46


$
33


$
61


$
57Capital
    expenditures(2)

$
704


$
612


$
554


$
757


$
65


$
44


$
38


$
37


$
27


$
29


$
11


$
1Goodwill additions

$



$



$



$



$



$



$



$



$



$



$



$
Total assets

$
13,920


$
13,531


$
13,443


$
13,237


$
992


$
943


$
912


$
858


$
1,329


$
1,093


$
718


$
763     (1)
    Eliminations relate to sales and operating revenues between
    segments recorded at transfer prices based on current market
    prices, and to unrealized intersegment profits in inventories.(2)
    Excludes capitalized costs related to asset retirement
    obligations incurred during the period and corporate
    acquisitions. 43




---



##### Table of Contents








Segmented
    Financial Information (continued)
  DownstreamCanadian Refined Products


U.S. Refining and Marketing


Corporate and
    Eliminations(1)


TotalQ4


Q3


Q2


Q1


Q4


Q3


Q2


Q1


Q4


Q3


Q2


Q1


Q4


Q3


Q2


Q1($ millions)2007Sales and operating revenues, net of royalties

$
758


$
831


$
709


$
618


$
1,340


$
1,043


$



$



$
(2,053
)

$
(1,949
)

$
(1,889
)

$
(1,853
)

$
4,760


$
4,351


$
3,163


$
3,244Costs and expensesOperating, cost of sales, selling and general


699



717



620



572



1,234



933











(1,982
)


(1,969
)


(1,801
)


(1,790
)


3,176



2,741



1,745



1,844Depletion, depreciation and amortization


19



16



15



16



25



22











7



6



7



5



462



471



440



433Interest  net






















1











40



46



22



21



40



47



22



21Foreign exchange


































6



(20
)


(36
)


(1
)


6



(20
)


(36
)


(1
)718



733



635



588



1,259



956











(1,929
)


(1,937
)


(1,808
)


(1,765
)


3,684



3,239



2,171



2,297Earnings (loss) before income taxes


40



98



74



30



81



87











(124
)


(12
)


(81
)


(88
)


1,076



1,112



992



947Current income taxes


4



(2
)


7



8



14



14











28



22



27



25



110



99



66



72Future income taxes


(16
)


33



14



2



16



19











(41
)


(37
)


(63
)


(52
)


(108
)


244



205



225Net earnings (loss)

$
52


$
67


$
53


$
20


$
51


$
54


$



$



$
(111
)

$
3


$
(45
)

$
(61
)

$
1,074


$
769


$
721


$
650Capital
    expenditures(2)

$
52


$
77


$
43


$
40


$
16


$
5


$



$



$
20


$
8


$
11


$
5


$
853


$
722


$
653


$
746Goodwill additions

$



$



$



$



$



$
500


$



$



$



$



$



$



$



$
500


$



$
Total assets

$
1,335


$
1,212


$
1,304


$
1,180


$
3,058


$
2,915


$



$



$
370


$
136


$
351


$
199


$
21,697


$
20,718


$
17,969


$
17,7812006Sales and operating revenues, net of royalties

$
579


$
776


$
674


$
546


$



$



$



$



$
(1,691
)

$
(1,876
)

$
(1,756
)

$
(1,598
)

$
3,084


$
3,436


$
3,040


$
3,104Costs and expensesOperating, cost of sales, selling and general


550



724



596



511



















(1,671
)


(1,837
)


(1,705
)


(1,529
)


1,845



2,011



1,708



1,927Depletion, depreciation and amortization


14



11



13



10



















10



6



5



6



426



411



383



379Interest  net


































24



19



22



27



24



19



22



27Foreign exchange


































8



5



(32
)


(5
)


8



5



(32
)


(5
)564



735



609



521



















(1,629
)


(1,807
)


(1,710
)


(1,501
)


2,303



2,446



2,081



2,328Earnings (loss) before income taxes


15



41



65



25



















(62
)


(69
)


(46
)


(97
)


781



990



959



776Current income taxes


2



5



3



9



















(1
)


(2
)


2



9



54



210



210



204Future income taxes


3



8



10























(35
)


(26
)


(12
)


(52
)


185



98



(229
)


48Net earnings (loss)

$
10


$
28


$
52


$
16


$



$



$



$



$
(26
)

$
(41
)

$
(36
)

$
(54
)

$
542


$
682


$
978


$
524Capital
    expenditures(2)

$
83


$
59


$
79


$
64


$



$



$



$



$
14


$
10


$
7


$
6


$
893


$
754


$
689


$
865Goodwill additions

$



$



$



$



$



$



$



$



$



$



$



$



$



$



$



$
Total assets

$
1,114


$
1,070


$
998


$
883


$



$



$



$



$
578


$
687


$
257


$
114


$
17,933


$
17,324


$
16,328


$
15,855     (1)
    Eliminations relate to sales and operating revenues between
    segments recorded at transfer prices based on current market
    prices, and to unrealized intersegment profits in inventories.(2)
    Excludes capitalized costs related to asset retirement
    obligations incurred during the period and corporate
    acquisitions. 44




---



##### Table of Contents





Segmented
    Capital Expenditures
  2007


2006Q4


Q3


Q2


Q1


Q4


Q3


Q2


Q1($ millions)UpstreamWestern Canada

$
594


$
451


$
433


$
553


$
630


$
465


$
397


$
680East Coast Canada and Frontier


87



73



62



59



66



104



115



73International


25



21



25



5



8



43



42



4706



545



520



617



704



612



554



757MidstreamUpgrader


44



51



74



48



65



44



38



37Infrastructure and Marketing


15



36



5



36



27



29



11



159



87



79



84



92



73



49



38DownstreamCanadian Refined Products


52



77



43



40



83



59



79



64U.S. Refining and Marketing


16



5























68



82



43



40



83



59



79



64Corporate


20



8



11



5



14



10



7



6$
853


$
722


$
653


$
746


$
893


$
754


$
689


$
865      45




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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 and Acting 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 and Acting 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).