##### 



Exhibit 3

HUSKY ENERGY INC.

2002
Managements Discussion
and Analysis





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##### 



MANAGEMENTS DISCUSSION AND ANALYSIS

Managements Discussion and Analysis should be read in
conjunction with the Consolidated Financial Statements and
Auditors Report included in this Annual Report. The
Consolidated Financial Statements have been prepared in
accordance with accounting principles generally accepted in
Canada. The effect of significant differences between
Canadian and United States accounting principles is disclosed
in note 16 of the Consolidated Financial Statements. The
following discussion and analysis refers primarily to 2002
compared with 2001, unless otherwise indicated. An abridged
discussion and analysis of the salient variances between 2001
and 2000 is provided on page 23. All dollar amounts are in
millions of Canadian dollars, unless otherwise indicated.
The calculation of barrels of oil equivalent (boe) and
thousands of cubic feet of gas equivalent (mcfge) are based
on a conversion rate of six thousand cubic feet of natural
gas to one barrel of crude oil. All production volumes
quoted are gross, the Companys working interest share before
royalties, and realized prices include the effect of hedging
gains and losses, unless otherwise indicated.

Managements Discussion and Analysis contains the term cash
flow from operations, which should not be considered an
alternative to, or more meaningful than cash flow from
operating activities as determined in accordance with
generally accepted accounting principles (GAAP) as an
indicator of the Companys financial performance. Huskys
determination of cash flow from operations may not be
comparable to that reported by other companies. Cash flow
from operations generated by each business segment represents
a measurement of financial performance for which each
reporting business segment is responsible. The other items
required to arrive at cash flow from operating activities are
considered to be a corporate responsibility.



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Evaluation of Disclosure Controls and Procedures

The Companys Chief Executive Officer and Chief Financial
Officer (its principal executive officer and principal
financial officer, respectively) have concluded, based on
their evaluation as of a date within 90 days prior to the
filing of this Annual Report (the evaluation date), that
the Companys disclosure controls and procedures are
effective to ensure that information required to be disclosed
by it in reports filed or submitted by it under the
Securities Exchange Act of 1934, as amended, is recorded,
processed, summarized and reported within the time periods
specified in the Security and Exchange Commissions rules and
forms, and includes controls and procedures designed to
ensure that information required to be disclosed by it in
such reports is accumulated and communicated to the Companys
management, including its Chief Executive Officer and Chief
Financial Officer, as appropriate to allow timely decisions
regarding required disclosure.

Changes to Internal Controls and Procedures for Financial Reporting

There have been no significant changes to Huskys internal
controls or in other factors that could significantly affect
these controls subsequent to the evaluation date and the
filing date of this Annual Report.

Forward-Looking Statements

Certain of the statements set forth under Managements
Discussion and Analysis of Financial Condition and Results of
Operations and elsewhere in this Annual Report including
statements which may contain words such as could, expect,
believe, will and similar expressions and statements
relating to matters that are not historical facts are
forward-looking and are based upon Huskys current belief as
to the outcome and timing of such future events. There are
numerous risks and uncertainties that can affect the outcome
and timing of such events, including many factors beyond the
control of Husky. These factors include, but are not limited
to, the matters described under the heading Business
Environment. Should one or more of these risks or
uncertainties occur, or should any of the underlying
assumptions prove incorrect, Huskys actual results and plans
for 2003 and beyond could differ materially from those
expressed in the forward-looking statements.

Overview

Huskys operations are organized into three major business
segments:



| |  |  | The upstream segment includes
the exploration for and the development and
production of crude oil and natural gas in Western
Canada, offshore the Canadian East Coast and offshore
Southern China and other international areas.                                                                                                                                             
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | The midstream segment is
organized into two reportable business segments;
heavy crude oil upgrading operations, and
infrastructure and commodity marketing operations.
The infrastructure and commodity marketing segment
comprises heavy crude oil pipeline and processing
operations, natural gas storage, cogeneration
operations and crude oil and natural gas marketing.
|
| |  |  | The refined products segment
consists of refining of crude oil and marketing of
refined petroleum products including asphalt
products.                                                                                                                                                                                                                                       

Page 1



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|                                                                             |                                            |         |           |          |      |         |    |          |    |         |       |       |      |      |    |    |    |    |       |       |      |      | 
|---------------------------------------------------------------------------- | ------------------------------------------ | ------- | --------- | -------- | ---- | ------- | -- | -------- | -- | ------- | ----- | ----- | ---- | ---- | -- | -- | -- | -- | ----- | ----- | ---- | ---- | 
|Year
ended December 31 ($ millions,
except per share amounts and production) |                                            | 2002    |           | % Change |      | 2001(1) |    | % Change |    | 2000(1)
|                                                                             |                                            |         |           |          |      |         |    |          |    |        
|Net earnings                                                                 |                                            | $       | 804       |          |      |         | 23 |          |    | $       | 654   |       |      |      | 49 |    |    | $  | 438   |      
|                                                                             | Per share                                  |  Basic |           |          | 1.88 |         |    |          | 26 |         |       |       | 1.49 |      |    |    | 16 |    |       |       | 1.28 |     
|                                                                             |                                            |         |  Diluted |          |      | 1.88    |    |          |    | 27      |       |       |      | 1.48 |    |    |    | 16 |       |       |      | 1.28 | 
|Cash flow from operations                                                    |                                            |         | 2,096     |          |      |         | 8  |          |    |         | 1,946 |       |      |      | 39 |    |    |    | 1,399 |      
|                                                                             | Per share                                  |  Basic |           |          | 4.94 |         |    |          | 7  |         |       |       | 4.60 |      |    |    | 8  |    |       |       | 4.26 |     
|                                                                             |                                            |         |  Diluted |          |      | 4.92    |    |          |    | 8       |       |       |      | 4.57 |    |    |    | 7  |       |       |      | 4.26 | 
|Sales and operating revenues, net of royalties                               |                                            |         | 6,384     |          |      |         | (3 | )        |    |         | 6,596 |       |      |      | 30 |    |    |    | 5,066 |      
|Daily production, before royalties                                           |                                            |         |           |          |      |         |    |          |    |         |       |       |      |      |    |    |    |    |       |      
|                                                                             | Light/medium crude oil & NGL (mbbls/day)   |         |           | 125.9    |      |         |    | 12       |    |         |       | 112.0 |      |      |    | 76 |    |    |       | 63.6  |     
|                                                                             | Lloydminster heavy crude oil (mbbls/day)   |         |           | 79.4     |      |         |    | 21       |    |         |       | 65.4  |      |      |    | 22 |    |    |       | 53.5  |     
|                                                                             | Natural gas (mmcf/day)                     |         |           | 569.2    |      |         |    | (1       | )  |         |       | 572.6 |      |      |    | 60 |    |    |       | 358.0 |     
|                                                                             | Barrels of oil equivalent (6:1) (mboe/day) |         |           | 300.2    |      |         |    | 10       |    |         |       | 272.8 |      |      |    | 54 |    |    |       | 176.8 |     



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|(1) |  | 2001 and 2000 amounts as restated. Refer to note 3 of the Consolidated Financial Statements.
|--- |  | --------------------------------------------------------------------------------------------

[Bar graph - Net Earnings]

[Bar graph - Cash Flow from Operations]

[Bar graph - Sales and Operating Revenues]

Consolidated Results Summary

Total consolidated revenue during 2002 was three percent
lower than in 2001 primarily as a result of lower natural gas
prices. The effect of lower natural gas prices was most
noticeable in the infrastructure and marketing segment with
respect to natural gas marketing revenues.

Higher net earnings and cash flow in 2002 compared with 2001
were attributable to increased earnings from:



| |  |  | the upstream business segment                              
| | - |  | -----------------------------------------------------------
|
| |  |  | the commodity marketing and infrastructure business segment

partially offset by lower earnings from:



| |  |  | the upgrading business segment       
| | - |  | -------------------------------------
|
| |  |  | the refined products business segment

Upstream

Earnings from the upstream segment increased by $206 million
to $688 million in 2002 compared with $482 million in 2001
due to:



| |  |  | higher realized oil prices 
| | - |  | ---------------------------
|
| |  |  | higher crude oil production
|
| |  |  | lower natural gas royalties

partially offset by:



| |  |  | lower prices for natural gas
| | - |  | ----------------------------
|
| |  |  | higher operating costs      

Page 2



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Midstream

Earnings from the midstream segment decreased by $95 million
to $161 million in 2002 compared with $256 million in 2001
due to:



| |  |  | narrower upgrading differentials
| | - |  | --------------------------------
|
| |  |  | lower pipeline throughput       

partially offset by:



| |  |  | higher oil and gas commodity marketing income 
| | - |  | ----------------------------------------------
|
| |  |  | higher cogeneration income                    
|
| |  |  | lower energy related upgrading operating costs

Refined Products

Earnings from the refined products segment decreased by $31
million to $32 million in 2002 compared with $63 million in
2001 due to:



| |  |  | lower margins on asphalt sales
| | - |  | ------------------------------

partially offset by:



| |  |  | improved gasoline and distillate margins
| | - |  | ----------------------------------------

Corporate

Corporate charges decreased by $70 million to $77 million in 2002 from $147 million in 2001, due to:



| |  |  | lower foreign exchange losses on translation of U.S. dollar denominated long-term debt
| | - |  | --------------------------------------------------------------------------------------

partially offset by:



| |  |  | higher intersegment profit eliminations
| | - |  | ---------------------------------------
|
| |  |  | higher corporate asset depreciation    
|
| |  |  | higher net interest expense            

Business Environment

Huskys financial results are significantly influenced by its
business environment, in particular, by crude oil and natural
gas prices, the costs to find, develop, produce and deliver
crude oil and natural gas, the demand for and ability to
deliver natural gas, the exchange rate between the Canadian
dollar and the U.S. dollar, refined product margins, the
demand for Huskys pipeline capacity, the demand for refined
petroleum products, government regulation and the cost of
borrowing.

Average Benchmark Prices

|                                             |  |      |       |      |  |      |       |  |  |   |       | 
|-------------------------------------------- |  | ---- | ----- | ---- |  | ---- | ----- |  |  | - | ----- | 
|                                             |  | 2002 |       | 2001 |  | 2000
|                                             |  |      |       |      |  |     
|West Texas Intermediate (WTI) (U.S. $/bbl) |  | $    | 26.08 |      |  | $    | 25.97 |  |  | $ | 30.20 | 
|NYMEX natural gas (U.S. $/mmbtu)             |  | $    | 3.25  |      |  | $    | 4.38  |  |  | $ | 3.91  | 
|AECO natural gas ($/GJ)                      |  | $    | 3.86  |      |  | $    | 5.97  |  |  | $ | 4.76  | 
|WTI/Lloyd blend differential (U.S. $/bbl)    |  | $    | 6.47  |      |  | $    | 10.74 |  |  | $ | 8.20  | 
|U.S./Canadian dollar exchange rate (U.S. $)  |  | $    | 0.637 |      |  | $    | 0.646 |  |  | $ | 0.673 | 

Commodity Prices

Huskys earnings depend largely on the profitability of its
upstream business, which is significantly affected by
fluctuations of oil and gas prices. Commodity prices have
been, and are expected to be, volatile due to a number of
factors beyond Huskys control. The prices received for the
crude oil and NGL sold by Husky are related to the price of
crude oil in world markets. Prices for heavy crude oil and
other lesser quality crudes trade at a discount or
differential to light sweet crude oil.

Average benchmark oil prices were marginally higher during
2002 after rising throughout most of the year. The price for
West Texas Intermediate (WTI) crude oil began the year at
U.S. $21.13/bbl and ended at U.S. $31.21/bbl, averaging U.S.
$26.08/bbl for the year, slightly higher than U.S. $25.97/bbl
in 2001 and significantly less than the U.S. $30.20/bbl in
2000.

The opposite trend occurred for average heavy crude oil
differentials, which averaged U.S. $6.47/bbl for WTI/Lloyd
blend during 2002 compared with U.S. $10.74/bbl during 2001.
The narrower differential tends to improve Huskys financial
results as the Companys crude oil production is weighted
toward heavier gravity crudes. In periods of wider
differentials, Huskys upgrader offsets some of the effect of
lower heavy crude prices. Huskys realized price for
light/medium crude oil and NGL averaged $33.28/bbl in 2002
compared with $27.19/bbl in 2001 and heavy crude oil averaged
$26.09/bbl in 2002 compared with $15.85/bbl in 2001.

Toward the end of 2002 the Organization of Petroleum
Exporting Countries (OPEC) announced cuts to their
production that were intended to keep prices within a U.S.
$22 and $28/bbl price band. OPEC has maintained their
production discipline for the past three years and prices
have fluctuated within the price

Page 3



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band. World crude oil prices increased toward the end of
2002 and into 2003 as a result of a number of events in
addition to OPECs decision to cut actual production: colder
than normal temperatures; uncertainty over the near-term in
respect of Iraq; and, the crippling oil industry strikes in
Venezuela. On February 11, 2003 WTI was U.S. $35.43/bbl.

The price of natural gas is affected by regional supply and
demand factors in North America, particularly those affecting
in the United States such as weather patterns, pipeline
delivery capacity, the availability of alternative sources of
less costly energy supply, inventory levels and general
industry activity levels. Periodic imbalances between supply
and demand for natural gas are common and result in volatile
pricing. The price of natural gas, unlike crude oil, is not
subject to the influence of an organization like OPEC.

Natural gas prices realized by Husky are based either on
fixed price contracts, spot prices or the New York Mercantile
Exchange (NYMEX) or other United States or domestic
regional market prices. The NYMEX near-month price for
natural gas ended 2002 at U.S. $4.79/mmbtu and was U.S.
$5.98/mmbtu on February 11, 2003.

WTI and Husky Realized Crude Oil Price

[Graph]

NYMEX Natural Gas and Husky Realized Natural Gas Price

[Graph]

The margins realized by Husky for refined products are
affected by crude oil price fluctuations, which affect
refinery feedstock costs, and third-party refined product
purchases. Huskys ability to maintain refined product
margins in an environment of higher feedstock costs is
contingent upon its ability to pass higher costs on to its
customers.

The profitability of Huskys heavy oil upgrading operations
is dependent upon the amount by which revenues from the
synthetic crude oil produced exceed the costs of the heavy
oil feedstock plus the related operating costs. An increase
in the price of blended heavy crude oil feedstock which is
not accompanied by an equivalent increase in the price of
synthetic crude oil would reduce the profitability of Huskys

Page 4



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upgrading operations. Husky has significant crude oil
production that trades at a discount to light crude oil, and
any negative effect of a narrower differential on upgrading
operations would be more than offset by a positive effect on
revenues in the upstream segment.

Huskys portfolio of light, medium and heavy crude oil and
natural gas reserves and the efficient operation of its
upgrader, refineries and other infrastructure provide
opportunities to take advantage of any increases in commodity
prices while assisting in managing price volatility.

Foreign Exchange

Huskys results are affected by the exchange rate between the
Canadian and U.S. dollars. The majority of Huskys revenues
are received in U.S. dollars or from the sale of commodities
that receive prices determined by reference to U.S. benchmark
prices. Accordingly, a change in the value of the Canadian
dollar relative to the U.S. dollar has the effect of
increasing or decreasing revenues unlike many of Huskys
expenditures, which are in Canadian dollars. In addition, a
change in the value of the Canadian dollar against the U.S.
dollar will result in an increase or decrease in Huskys U.S.
dollar denominated debt, as expressed in Canadian dollars, as
well as in the related interest expense. At December 31,
2002, 78 percent or $2.1 billion of Huskys long-term debt
and capital securities were denominated in U.S. dollars. At
the end of 2002, U.S. $20 million of forward foreign exchange
collars were in place with an average cap of $1.54 and floor
of $1.49. The terms of the collars range from March 2003 to
September 2004. The U.S./Cdn. exchange rate at the end of
2002 was $1.58. On January 23, 2003, the Company executed an
arrangement under which it swapped its U.S. $150 million
6.875 percent notes due November 2003. The notes were
effectively swapped to $229 million 8.5 percent notes, at an
effective exchange rate of $1.525. Refer to note 15 of the
Consolidated Financial Statements for further disclosure on
the Companys use of derivative financial instruments to
manage foreign currency risk.

Interest Rates

Husky is exposed to interest rate fluctuations on its
floating rate debt and derivative financial instruments with
sensitivity to interest rates. The Company maintains a
portion of its total debt in floating rate facilities. The
Company will occasionally fix its floating rate debt or
create a variable rate for its fixed rate debt using
derivative financial instruments.

At December 31, 2002 substantially all of Huskys outstanding
long-term debt was at fixed rates, however U.S. $535 million
had been swapped to floating rates at an average of London
Inter Bank Offered Rate (LIBOR) plus 1.62 percent. These
arrangements mature as follows:



| |  |  | U.S. $35 million in November 2003 
| | - |  | ----------------------------------
|
| |  |  | U.S. $150 million in November 2006
|
| |  |  | U.S. $200 million in November 2011
|
| |  |  | U.S. $150 million in June 2012    

In January, 2003 Husky unwound the U.S. $35 million swap due
November 2003. The proceeds amounted to $2.0 million and
will be recognized in income over the period to November
2003. In addition $200 million of fixed rate debt was
swapped into floating rate debt at Canadian Bankers
Acceptance Rate (CDOR) plus 1.75 percent until July 2009.

Huskys average effective interest rate during 2002 was 6.70
percent before interest rate swaps and 5.48 percent after
swaps. Refer to note 15 of the Consolidated Financial
Statements for further disclosure on the Companys use of
derivative financial instruments to manage interest rate
risk.

Environmental Regulation

Most aspects of Huskys business are subject to environmental
laws and regulations. Similar to other companies in the oil
and gas industry, Husky incurs costs for preventive and
corrective actions. Changes to regulations could have an
adverse effect on Huskys results of operations and financial
condition.

International Operations

Huskys international operations may be affected by a variety
of factors including political and economic developments,
expropriation, exchange controls, currency fluctuations,
royalty and tax increases, retroactive tax claims, import and
export regulations and other foreign laws or policies
affecting foreign trade or investment.

Page 5



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Risk Management

Husky uses derivative financial instruments when deemed
appropriate to hedge exposure to changes in the price of
crude oil and natural gas and fluctuations in interest rates
and foreign currency exchange rates. Husky does not engage
in transactions involving derivative financial instruments
for trading or other speculative purposes. Refer to note 15
of the Consolidated Financial Statements for further
disclosure on the Companys use of derivative financial
instruments.

Business Plan

Huskys 2003 business plan assumes that:



| |  |  | WTI will average U.S. $24.00/bbl
and the WTI/Lloyd blend differential will average
U.S. $6.25/bbl                                                                                                              
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | NYMEX natural gas price will average U.S. $3.75/mcf                                                                                                                                                            
|
| |  |  | the Canadian dollar will average U.S. $0.65                                                                                                                                                                    
|
| |  |  | U.S. $LIBOR will average 2.50 percent                                                                                                                                                                          
|
| |  |  | Huskys total production will
average 305 to 325 mboe/day. The composition is
estimated to be 120 to 130 bbls/day light crude oil &
NGL, 85 to 90 mbbls/day heavy crude oil and 580 to
620 mmcf/day natural gas

Husky plans to invest capital in the following segments in
2003:

|                                    |                   |          |       |       | 
|----------------------------------- | ----------------- | -------- | ----- | ----- | 
|                                    |                   |          | 2003 
|Year ended December 31 ($ millions) |                   | Estimate
|                                    |                   |         
|Upstream                            |                   |          |       |      
|                                    | Western Canada    |          | $     | 1,040 | 
|                                    | East Coast Canada |          |       | 560   | 
|                                    | International     |          |       | 55    | 
|                                    |                   |          |       |      
|                                    |                   |          | 1,655 |      
|Midstream                           |                   |          | 100   |      
|Refined Products                    |                   |          | 60    |      
|Corporate                           |                   |          | 25    |      
|                                    |                   |          |       |      
|                                    |                   | $        | 1,840 |      
|                                    |                   |          |       |      

Strategic Plan

The 2003 capital program will continue to implement Huskys
long-term strategic plan of increasing reserves and
production in the upstream business segment and expansion and
optimization of the midstream and refined products
businesses.

The light crude oil potential of the Western Canada
Sedimentary Basin, although considerable, is diminishing
since discovery of large accumulations of light crude oil is
becoming less probable. Declining production from Huskys
light and medium crude oil producing properties in Western
Canada is planned to be more than offset by further
exploitation of heavy oil in the Lloydminster region of
Alberta and Saskatchewan, continued development of oil sands
potential in Alberta, production from the White Rose offshore
project and further increases of production from new projects
in China. Activities related to the development of oil sands
in 2003 include submission of an environmental impact
assessment and project application for the Tucker and Kearl,
Alberta in-situ projects and the drilling of more than 200
stratigraphic test wells at Kearl. Activities in China
include evaluation of the newly acquired exploration blocks
in the South China Sea. The White Rose development project
is progressing and a semi-submersible drilling rig has been
secured for development drilling in 2002.

The undiscovered natural gas potential of the Western Canada
Sedimentary Basin is considered to be very good and is
concentrated in the western portion of the basin. Huskys
natural gas production is expected to increase as a result of
exploration and development activities concentrated in the
foothills and deep basin region west of the fifth meridian in
Alberta and British Columbia as well as the northern plains
district of Alberta.

During 2003 Husky intends to invest:



| |  |  | in excess of $1 billion on
upstream capital programs located throughout the
Western Canada Sedimentary Basin
| | - |  | ------------------------------------------------------------------------------------------------------------

Page 6



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| |  |  | approximately $100 million in
the midstream segment primarily for further
debottlenecking of the Lloydminster Upgrader  
| | - |  | ------------------------------------------------------------------------------------------------------------------------
|
| |  |  | approximately $60 million in the
refined products segment primarily for further
upgrading of the marketing outlet system

Husky has implemented a corporate hedging plan to protect
cash flow and earnings in 2003. The most critical aspect of
the plan is to hedge commodity price realizations. The
parameters of the plan are as follows:



| |  |  | crude oil forward sales at a
minimum of U.S. $29.00/bbl                                                                                                                 
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | natural gas forward sales at a
minimum of U.S. $5.00/mmbtu in non-heating or
inventory building months and U.S. $5.25/mmbtu during
heating or inventory draw-down months
|
| |  |  | no more than 50 percent of
annual forecast production will be hedged                                                                                                    

There is no plan currently to hedge the Canadian dollar or
crude oil differentials.

At February 14, 2003 the Company had hedged 26 mmbbls of
crude oil primarily from April through to December 2003 at an
average price of U.S. $29.50/bbl. At February, 14, 2003 the
Company had hedged 37 bcf of natural gas primarily in the
second and third quarters of 2003 at an average price of U.S.
$5.20/mmbtu. This amounts to 34 percent of Huskys estimated
crude oil production and 17 percent of its estimated natural
gas production during 2003. In addition, Husky executed a
put option program for approximately 3.7 mmbbls from July to
December 2003 at a strike price of U.S. $27.00/bbl. The cost
of the program was U.S. $6.1 million.

Results of OperationsUpstream

Upstream Earnings Summary

|                                         |  |      |       |      |  |      |       |  |  |   |       | 
|---------------------------------------- |  | ---- | ----- | ---- |  | ---- | ----- |  |  | - | ----- | 
|Year ended December 31 ($ millions)      |  | 2002 |       | 2001 |  | 2000
|                                         |  |      |       |      |  |     
|Gross revenues                           |  | $    | 3,120 |      |  | $    | 2,667 |  |  | $ | 2,055 | 
|Royalties                                |  |      | 460   |      |  |      | 502   |  |  |   | 351   | 
|Hedging (gain)/loss                      |  |      | (5    | )    |  |      |      |  |  |   | 155   | 
|                                         |  |      |       |      |  |      |       |  |  |   |       | 
|Net revenues                             |  |      | 2,665 |      |  |      | 2,165 |  |  |   | 1,549 | 
|Operating and administrative expenses    |  |      | 729   |      |  |      | 648   |  |  |   | 375   | 
|Depletion, depreciation and amortization |  |      | 851   |      |  |      | 728   |  |  |   | 407   | 
|Income taxes                             |  |      | 397   |      |  |      | 307   |  |  |   | 315   | 
|                                         |  |      |       |      |  |      |       |  |  |   |       | 
|Earnings                                 |  | $    | 688   |      |  | $    | 482   |  |  | $ | 452   | 
|                                         |  |      |       |      |  |      |       |  |  |   |       | 

Net Revenue Variance Analysis

|                             |                |       |           |           |         |     |         |       |   |       |     |      |   |   |    |    |   |   |       |       |  
|---------------------------- | -------------- | ----- | --------- | --------- | ------- | --- | ------- | ----- | - | ----- | --- | ---- | - | - | -- | -- | - | - | ----- | ----- | -
|                             |                |       | Light/    |           | Lloyd-  |     |         |       |   |       |     |      |   |   |    |    |  
|                             |                |       | Medium    |           | minster |     |         |       |   |       |     |      |   |   |    |    |  
|                             |                |       | Crude Oil |           | Heavy   |     | Natural |       |   |       |     |      |   |   |   
|($ millions)                 |                | & NGL |           | Crude Oil |         | Gas |         | Other |   | Total
|                             |                |       |           |           |         |     |         |       |   |      
|Year ended December 31, 2000 |                |       |           |           |         |     |         |       |   |       |     |      |   |   |    |    |   |   |       |      
|Net revenues                 |                | $     | 632       |           |         | $   | 357     |       |   | $     | 534 |      |   | $ | 26 |    |   | $ | 1,549 |      
|                             | Price changes  |       |           | (348      | )       |     |         | (253  | ) |       |     | 59   |   |   |    | (8 | ) |   |       | (550  | )
|                             | Volume changes |       |           | 632       |         |     |         | 114   |   |       |     | 404  |   |   |    |   |   |   |       | 1,150 |  
|                             | Royalties      |       |           | (52       | )       |     |         | 29    |   |       |     | (128 | ) |   |    |   |   |   |       | (151  | )
|                             | Hedging        |       |           | 49        |         |     |         | 102   |   |       |     | 4    |   |   |    |   |   |   |       | 155   |  
|                             | Processing     |       |           |          |         |     |         |      |   |       |     |     |   |   |    | 12 |   |   |       | 12    |  
|                             |                |       |           |           |         |     |         |       |   |       |     |      |   |   |    |    |   |   |       |      
|Year ended December 31, 2001 |                |       |           |           |         |     |         |       |   |       |     |      |   |   |    |    |   |   |       |      
|Net revenues                 |                |       | 913       |           |         |     | 349     |       |   |       | 873 |      |   |   | 30 |    |   |   | 2,165 |      
|                             | Price changes  |       |           | 276       |         |     |         | 297   |   |       |     | (342 | ) |   |    | 8  |   |   |       | 239   |  
|                             | Volume changes |       |           | 138       |         |     |         | 81    |   |       |     | (7   | ) |   |    |   |   |   |       | 212   |  
|                             | Royalties      |       |           | (16       | )       |     |         | (56   | ) |       |     | 113  |   |   |    |   |   |   |       | 41    |  
|                             | Hedging        |       |           | 5         |         |     |         |      |   |       |     |     |   |   |    |   |   |   |       | 5     |  
|                             | Processing     |       |           |          |         |     |         |      |   |       |     |     |   |   |    | 3  |   |   |       | 3     |  
|                             |                |       |           |           |         |     |         |       |   |       |     |      |   |   |    |    |   |   |       |      
|Year ended December 31, 2002 |                |       |           |           |         |     |         |       |   |       |     |      |   |   |    |    |   |   |       |      
|Net revenues                 |                | $     | 1,316     |           |         | $   | 671     |       |   | $     | 637 |      |   | $ | 41 |    |   | $ | 2,665 |      
|                             |                |       |           |           |         |     |         |       |   |       |     |      |   |   |    |    |   |   |       |      

Page 7



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##### 



Daily Production, Before Royalties

|                                           |  |      |       |      |  |      |       |  |  |  |       | 
|------------------------------------------ |  | ---- | ----- | ---- |  | ---- | ----- |  |  |  | ----- | 
|Year ended December 31                     |  | 2002 |       | 2001 |  | 2000
|                                           |  |      |       |      |  |     
|Light/medium crude oil & NGL (mbbls/day)   |  |      | 125.9 |      |  |      | 112.0 |  |  |  | 63.6  | 
|Lloydminster heavy crude oil (mbbls/day)   |  |      | 79.4  |      |  |      | 65.4  |  |  |  | 53.5  | 
|Natural gas (mmcf/day)                     |  |      | 569.2 |      |  |      | 572.6 |  |  |  | 358.0 | 
|Barrels of oil equivalent (6:1) (mboe/day) |  |      | 300.2 |      |  |      | 272.8 |  |  |  | 176.8 | 

Average Realized Prices

|                                            |  |      |       |      |  |      |       |  |  |   |       | 
|------------------------------------------- |  | ---- | ----- | ---- |  | ---- | ----- |  |  | - | ----- | 
|Year ended December 31                      |  | 2002 |       | 2001 |  | 2000
|                                            |  |      |       |      |  |     
|Light/medium crude oil & NGL ($/bbl)        |  | $    | 33.16 |      |  | $    | 27.19 |  |  | $ | 35.88 | 
|Hedging (gain)/loss                         |  |      | (0.12 | )    |  |      |      |  |  |   | 2.46  | 
|                                            |  |      |       |      |  |      |       |  |  |   |       | 
|Light/medium crude oil & NGL price realized |  | $    | 33.28 |      |  | $    | 27.19 |  |  | $ | 33.42 | 
|                                            |  |      |       |      |  |      |       |  |  |   |       | 
|Lloydminster heavy crude oil ($/bbl)        |  | $    | 26.09 |      |  | $    | 15.85 |  |  | $ | 26.45 | 
|Hedging (gain)/loss                         |  |      |      |      |  |      |      |  |  |   | 5.19  | 
|                                            |  |      |       |      |  |      |       |  |  |   |       | 
|Lloydminster heavy crude oil price realized |  | $    | 26.09 |      |  | $    | 15.85 |  |  | $ | 21.26 | 
|                                            |  |      |       |      |  |      |       |  |  |   |       | 
|Natural gas price ($/mcf)                   |  | $    | 3.83  |      |  | $    | 5.47  |  |  | $ | 5.18  | 
|Hedging (gain)/loss                         |  |      |      |      |  |      |      |  |  |   | 0.02  | 
|                                            |  |      |       |      |  |      |       |  |  |   |       | 
|Natural gas price realized                  |  | $    | 3.83  |      |  | $    | 5.47  |  |  | $ | 5.16  | 
|                                            |  |      |       |      |  |      |       |  |  |   |       | 

Product Mix

|                                                       |  |      |     |      |  |      |     |   |  |  |     |  
|------------------------------------------------------ |  | ---- | --- | ---- |  | ---- | --- | - |  |  | --- | -
|Year ended December 31                                 |  | 2002 |     | 2001 |  | 2000
|                                                       |  |      |     |      |  |     
|Percentage of upstream sales revenues, after royalties |  |      |     |      |  |      |     |   |  |  |     |  
|Light/medium crude oil & NGL                           |  |      | 49  | %    |  |      | 42  | % |  |  | 40  | %
|Lloydminster heavy crude oil                           |  |      | 25  | %    |  |      | 16  | % |  |  | 23  | %
|Natural gas                                            |  |      | 26  | %    |  |      | 42  | % |  |  | 37  | %
|                                                       |  |      |     |      |  |      |     |   |  |  |     |  
|                                                       |  |      | 100 | %    |  |      | 100 | % |  |  | 100 | %
|                                                       |  |      |     |      |  |      |     |   |  |  |     |  

Royalty Rates

|                                                        |  |      |    |      |  |      |    |   |  |  |    |  
|------------------------------------------------------- |  | ---- | -- | ---- |  | ---- | -- | - |  |  | -- | -
|Year ended December 31                                  |  | 2002 |    | 2001 |  | 2000
|                                                        |  |      |    |      |  |     
|Percentage of upstream sales revenues, before royalties |  |      |    |      |  |      |    |   |  |  |    |  
|Light/medium crude oil & NGL                            |  |      | 15 | %    |  |      | 19 | % |  |  | 20 | %
|Lloydminster heavy crude oil                            |  |      | 11 | %    |  |      | 8  | % |  |  | 15 | %
|Natural gas                                             |  |      | 18 | %    |  |      | 23 | % |  |  | 19 | %
|Total                                                   |  |      | 15 | %    |  |      | 19 | % |  |  | 19 | %

2002 compared with 2001

Huskys earnings from the upstream segment increased by $206
million (43 percent) to $688 million in 2002 from $482
million in 2001.

Page 8



---



##### 



Huskys total revenues from upstream operations were $3,120
million in 2002 compared with $2,667 million in 2001 as a
result of:



| |  |  | higher sales volume and price realization for crude oil
| | - |  | -------------------------------------------------------

the effect of which was offset partially by:



| |  |  | lower natural gas prices
| | - |  | ------------------------

Higher production volumes of crude oil were due to:



| |  |  | the ongoing Lloydminster heavy oil development programs                        
| | - |  | -------------------------------------------------------------------------------
|
| |  |  | Terra Nova and Wenchang commencing production in January and July, respectively

Operating costs per unit of production increased three
percent in 2002 compared with 2001 as a result of:



| |  |  | light/medium crude oil
properties under secondary and tertiary recovery
schemes in Western Canada
| | - |  | -------------------------------------------------------------------------------------------------
|
| |  |  | extensive shallow gas production
in Western Canada                                               

partially offset by:



| |  |  | lower unit operating costs at
Terra Nova, Wenchang and at the heavy oil operations
at Lloydminster
| | - |  | --------------------------------------------------------------------------------------------------

Depletion, depreciation and amortization (DD&A) increased
to $7.76/boe in 2002 from $7.31/boe in 2001 and resulted
from:



| |  |  | higher maintenance capital for
properties under secondary and tertiary recovery and
shallow natural gas and offshore operations requiring
large infrastructure capital
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------

Income taxes increased in 2002 compared with 2001 reflecting
higher pre-tax earnings offset in part by rate reductions in
British Columbia and Alberta.

Daily production, before Royalties

[Bar Graph - Total]

[Bar Graph - Light-Medium Crude Oil and NGL]

[Bar Graph - Lloydminster Heavy Crude Oil]

[Bar Graph - Natural Gas]

Page 9



---



##### 



Operating Netbacks(1)

Western Canada

Light/Medium Crude Oil Netbacks(2)

|                                 |  |      |       |      |  |      |       |  |  |   |       | 
|-------------------------------- |  | ---- | ----- | ---- |  | ---- | ----- |  |  | - | ----- | 
|Year ended December 31 (per boe) |  | 2002 |       | 2001 |  | 2000
|                                 |  |      |       |      |  |     
|Sales revenues                   |  | $    | 31.10 |      |  | $    | 27.39 |  |  | $ | 35.68 | 
|Royalties                        |  |      | 5.25  |      |  |      | 4.87  |  |  |   | 6.42  | 
|Hedging (gain)/loss              |  |      | (0.15 | )    |  |      |      |  |  |   | 2.46  | 
|Operating costs                  |  |      | 8.50  |      |  |      | 7.47  |  |  |   | 6.23  | 
|                                 |  |      |       |      |  |      |       |  |  |   |       | 
|Netback                          |  | $    | 17.50 |      |  | $    | 15.05 |  |  | $ | 20.57 | 
|                                 |  |      |       |      |  |      |       |  |  |   |       | 

Lloydminster Heavy Crude Oil Netbacks(2)

|                                 |  |      |       |      |  |      |       |  |  |   |       | 
|-------------------------------- |  | ---- | ----- | ---- |  | ---- | ----- |  |  | - | ----- | 
|Year ended December 31 (per boe) |  | 2002 |       | 2001 |  | 2000
|                                 |  |      |       |      |  |     
|Sales revenues                   |  | $    | 26.02 |      |  | $    | 16.00 |  |  | $ | 26.45 | 
|Royalties                        |  |      | 2.97  |      |  |      | 1.27  |  |  |   | 3.00  | 
|Hedging (gain)/loss              |  |      |      |      |  |      |      |  |  |   | 5.19  | 
|Operating costs                  |  |      | 7.03  |      |  |      | 7.60  |  |  |   | 6.15  | 
|                                 |  |      |       |      |  |      |       |  |  |   |       | 
|Netback                          |  | $    | 16.02 |      |  | $    | 7.13  |  |  | $ | 12.11 | 
|                                 |  |      |       |      |  |      |       |  |  |   |       | 

Natural Gas Netbacks(3)

|                                   |  |      |      |      |  |      |      |  |  |   |      | 
|---------------------------------- |  | ---- | ---- | ---- |  | ---- | ---- |  |  | - | ---- | 
|Year ended December 31 (per mcfge) |  | 2002 |      | 2001 |  | 2000
|                                   |  |      |     
|Sales revenues                     |  | $    | 3.96 |      |  | $    | 5.39 |  |  | $ | 5.28 | 
|Royalties                          |  |      | 0.82 |      |  |      | 1.30 |  |  |   | 1.18 | 
|Hedging (gain)/loss                |  |      |     |      |  |      |     |  |  |   | 0.02 | 
|Operating costs                    |  |      | 0.70 |      |  |      | 0.58 |  |  |   | 0.49 | 
|                                   |  |      |      |      |  |      |      |  |  |   |      | 
|Netback                            |  | $    | 2.44 |      |  | $    | 3.51 |  |  | $ | 3.59 | 
|                                   |  |      |      |      |  |      |      |  |  |   |      | 

Total Western Canada Upstream Netbacks(2)

|                                 |  |      |       |      |  |      |       |  |  |   |       | 
|-------------------------------- |  | ---- | ----- | ---- |  | ---- | ----- |  |  | - | ----- | 
|Year ended December 31 (per boe) |  | 2002 |       | 2001 |  | 2000
|                                 |  |      |       |      |  |     
|Sales revenues                   |  | $    | 27.04 |      |  | $    | 26.42 |  |  | $ | 31.41 | 
|Royalties                        |  |      | 4.45  |      |  |      | 5.04  |  |  |   | 5.42  | 
|Hedging (gain)/loss              |  |      | (0.05 | )    |  |      |      |  |  |   | 2.40  | 
|Operating costs                  |  |      | 6.55  |      |  |      | 6.08  |  |  |   | 5.27  | 
|                                 |  |      |       |      |  |      |       |  |  |   |       | 
|Netback                          |  | $    | 16.09 |      |  | $    | 15.30 |  |  | $ | 18.32 | 
|                                 |  |      |       |      |  |      |       |  |  |   |       | 

Terra Nova Light/Medium Crude Oil Netbacks

|                                 |  |      |       |      |  |      |   |  |  |   |   | 
|-------------------------------- |  | ---- | ----- | ---- |  | ---- | - |  |  | - | - | 
|Year ended December 31 (per boe) |  | 2002 |       | 2001 |  | 2000
|                                 |  |      |      
|Sales revenues                   |  | $    | 35.47 |      |  | $    |  |  |  | $ |  | 
|Royalties                        |  |      | 0.36  |      |  |      |  |  |  |   |  | 
|Operating costs                  |  |      | 3.62  |      |  |      |  |  |  |   |  | 
|                                 |  |      |       |      |  |      |   |  |  |   |   | 
|Netback                          |  | $    | 31.49 |      |  | $    |  |  |  | $ |  | 
|                                 |  |      |       |      |  |      |   |  |  |   |   | 



---

|(1) |  | 2001 and 2000 amounts as restated. Refer to note 3 of
the Consolidated Financial Statements.
|--- |  | --------------------------------------------------------------------------------------------
|   
|(2) |  | Includes associated co-products converted to boe.                                           
|   
|(3) |  | Includes associated co-products converted to mcfge.                                         
|   

Page 10



---



##### 



Wenchang Light/Medium Crude Oil Netbacks

|                                 |  |      |       |      |  |      |   |  |  |   |   | 
|-------------------------------- |  | ---- | ----- | ---- |  | ---- | - |  |  | - | - | 
|Year ended December 31 (per boe) |  | 2002 |       | 2001 |  | 2000
|                                 |  |      |       |      |  |     
|Sales revenues                   |  | $    | 44.36 |      |  | $    |  |  |  | $ |  | 
|Royalties                        |  |      | 2.65  |      |  |      |  |  |  |   |  | 
|Operating costs                  |  |      | 2.15  |      |  |      |  |  |  |   |  | 
|                                 |  |      |       |      |  |      |   |  |  |   |   | 
|Netback                          |  | $    | 39.56 |      |  | $    |  |  |  | $ |  | 
|                                 |  |      |       |      |  |      |   |  |  |   |   | 

Total Upstream Netbacks(1)

|                                 |  |      |       |      |  |      |       |  |  |   |       | 
|-------------------------------- |  | ---- | ----- | ---- |  | ---- | ----- |  |  | - | ----- | 
|Year ended December 31 (per boe) |  | 2002 |       | 2001 |  | 2000
|                                 |  |      |       |      |  |     
|Sales revenues                   |  | $    | 28.12 |      |  | $    | 26.42 |  |  | $ | 31.41 | 
|Royalties                        |  |      | 4.20  |      |  |      | 5.04  |  |  |   | 5.42  | 
|Hedging (gain)/loss              |  |      | (0.05 | )    |  |      |      |  |  |   | 2.40  | 
|Operating costs                  |  |      | 6.24  |      |  |      | 6.08  |  |  |   | 5.27  | 
|                                 |  |      |       |      |  |      |       |  |  |   |       | 
|Netback                          |  | $    | 17.73 |      |  | $    | 15.30 |  |  | $ | 18.32 | 
|                                 |  |      |       |      |  |      |       |  |  |   |       | 



---

|(1) |  | Includes associated co-products converted to boe.
|--- |  | -------------------------------------------------

Upstream Capital Expenditures

|                                    |                   |      |       |      |  |      |       |     |  |   |     |     | 
|----------------------------------- | ----------------- | ---- | ----- | ---- |  | ---- | ----- | --- |  | - | --- | --- | 
|Year ended December 31 ($ millions) |                   | 2002 |       | 2001 |  | 2000
|                                    |                   |      |       |      |  |     
|Exploration                         |                   |      |       |      |  |      |       |     |  |   |     |    
|                                    | Western Canada    |      | $     | 304  |  |      | $     | 236 |  |   | $   | 118 | 
|                                    | East Coast Canada |      |       | 41   |  |      |       | 81  |  |   |     | 63  | 
|                                    | International     |      |       | 9    |  |      |       | 5   |  |   |     |    | 
|                                    |                   |      |       |      |  |      |       |     |  |   |     |    
|                                    |                   |      | 354   |      |  |      | 322   |     |  |   | 181 |    
|                                    |                   |      |       |      |  |      |       |     |  |   |     |    
|Development                         |                   |      |       |      |  |      |       |     |  |   |     |    
|                                    | Western Canada    |      |       | 730  |  |      |       | 786 |  |   |     | 301 | 
|                                    | East Coast Canada |      |       | 417  |  |      |       | 110 |  |   |     | 131 | 
|                                    | International     |      |       | 66   |  |      |       | 99  |  |   |     | 87  | 
|                                    |                   |      | 1,213 |      |  |      | 995   |     |  |   | 519 |    
|                                    |                   |      |       |      |  |      |       |     |  |   |     |    
|                                    |                   | $    | 1,567 |      |  | $    | 1,317 |     |  | $ | 700 |    
|                                    |                   |      |       |      |  |      |       |     |  |   |     |    

Western Canada

Capital expenditures reflect exploration and exploitation of
properties in central and southern Alberta, southern
Saskatchewan, the foothills, deep basin and northern region
of Alberta and north eastern British Columbia and the
increasing pace of development in the Lloydminster heavy oil
area. Many of the properties located in Alberta and
Saskatchewan are crude oil properties under secondary
pressure maintenance schemes or shallow natural gas
properties, which require extensive optimization and
rationalization.

Capital expenditures in the Lloydminster heavy oil areas of
Alberta and Saskatchewan in the last two years were $273
million and $324 million, respectively. Husky drilled 369
wells in the Lloydminster area in 2002 compared with 490
wells in 2001 resulting in 327 and 415 oil well completions
and 25 and 39 natural gas well completions in 2002 and 2001,
respectively. In 2002, expansion of the heavy oil thermal
project at Bolney/Celtic, Saskatchewan continued. Capital
spending on the project totalled $36 million and productive
capacity had been increased from 3,000 bbls/day to 5,000
bbls/day by year-end. Capital spending for the natural gas
development in the Shackleton area of southern Saskatchewan
totalled $61 million and 2002 exit production volume was
approximately 30 mmcf/day.

Exploration spending in Western Canada increased by $68
million to $304 million in 2002 from $236 million in 2001 and
$118 million in 2000. Exploration spending remains focused
on natural gas prone areas in the deep basin areas of western
Alberta and the foothills and northern plains of Alberta and
British Columbia.

Page 11



---



##### 



East Coast Canada

Huskys 2002 capital spending in the Jeanne dArc Basin
totalled $458 million. Capital spending on the White Rose
development project amounted to $395 million (including $24
million of capitalized interest). The Terra Nova oil field
development was commissioned in January 2002. Additional
development capital spending for Terra Nova amounted to $22
million during the year. The remaining $41 million was for
other Jeanne dArc Basin exploration.

International

Internationally, Huskys capital expenditures totalled $75
million during 2002, $66 million of which was spent on the
Wenchang oil field development in the South China Sea.
Wenchang was commissioned in July 2002. The remainder was
spent on an exploration program in the South China Sea, which
began in late 2002. The Qionghai 18-1-3 well in the South
China Sea was plugged and abandoned in January 2003 without
testing and the Wenchang 8-1-1 was plugged and abandoned
without testing in February, 2003.

Reserve Additions

The efficient replacement of the Companys oil and gas
productive capacity is the fundamental key to the growth of
value. During the three years ended December 31, 2002, Husky
has replaced an average of 120 percent of production on a boe
basis, exclusive of acquisitions and divestitures. Over the
three years ended December 31, 2002 reserves were added at an
average cost of $10.12/boe.

During 2002, extensions of proved acreage and improved
recovery added 44 mmbbls to proved reserves of crude oil and
NGL, 19 mmbbls of which was from Terra Nova. Technical
revisions added 12 mmbbls to crude oil and NGL reserves,
primarily from Bolney/Celtic. Net divestitures amounted to 11
mmbbls. During 2002 discoveries, extensions and improved
recovery added 387 bcf to proved reserves of natural gas. The
larger additions were 133 bcf from Boyer in northern Alberta,
82 bcf from Shackleton in southern Saskatchewan and 36 bcf
from discoveries in Kiskiu and Ansell in the Alberta
foothills and deep basin. Net divestitures of non-core
properties amounted to 13 bcf and technical revisions
amounted to negative 37 bcf.

At December 31, 2002, the present value of future net cash
flows after tax from the Companys proved oil and gas
reserves, based on prices and costs in effect at year-end and
discounted at 10 percent, was $7.2 billion compared with $2.8
billion at the end of 2001.

McDaniel & Associates Consultants Ltd., an independent firm
of oil and gas reserves evaluation engineers was engaged to
evaluate 65 percent of Huskys proved oil and gas reserves.
The firms aggregate proved reserve estimates were
approximately 10 percent lower than Huskys estimates which
are set out below.

Summary of Reserves

Light/Medium Crude Oil & NGL Reserves

|                                |  |       |     |      |  |       |     |     |  |       |     |     |  |  |     |  |  |  |     |  |  |  |     | 
|------------------------------- |  | ----- | --- | ---- |  | ----- | --- | --- |  | ----- | --- | --- |  |  | --- |  |  |  | --- |  |  |  | --- | 
|                                |  | 2002  |     | 2001 |  | 2000 
|                                |  |       |     |      |  |      
|Year ended December 31 (mmbbls) |  | Gross |     | Net  |  | Gross |     | Net |  | Gross |     | Net
|                                |  |       |     |      |  |       |     |     |  |       |     |    
|Proved developed                |  |       | 323 |      |  |       | 280 |     |  |       | 329 |     |  |  | 287 |  |  |  | 338 |  |  |  | 283 | 
|Proved undeveloped              |  |       | 65  |      |  |       | 52  |     |  |       | 101 |     |  |  | 89  |  |  |  | 102 |  |  |  | 88  | 
|                                |  |       |     |      |  |       |     |     |  |       |     |     |  |  |     |  |  |  |     |  |  |  |     | 
|Total proved                    |  |       | 388 |      |  |       | 332 |     |  |       | 430 |     |  |  | 376 |  |  |  | 440 |  |  |  | 371 | 
|                                |  |       |     |      |  |       |     |     |  |       |     |     |  |  |     |  |  |  |     |  |  |  |     | 

Lloydminster Heavy Crude Oil Reserves

|                                |  |       |     |      |  |       |     |     |  |       |     |     |  |  |     |  |  |  |     |  |  |  |     | 
|------------------------------- |  | ----- | --- | ---- |  | ----- | --- | --- |  | ----- | --- | --- |  |  | --- |  |  |  | --- |  |  |  | --- | 
|                                |  | 2002  |     | 2001 |  | 2000 
|                                |  |       |     |      |  |      
|Year ended December 31 (mmbbls) |  | Gross |     | Net  |  | Gross |     | Net |  | Gross |     | Net
|                                |  |       |     |      |  |       |     |     |  |       |     |    
|Proved developed                |  |       | 116 |      |  |       | 109 |     |  |       | 96  |     |  |  | 92  |  |  |  | 65  |  |  |  | 63  | 
|Proved undeveloped              |  |       | 65  |      |  |       | 60  |     |  |       | 73  |     |  |  | 72  |  |  |  | 49  |  |  |  | 47  | 
|                                |  |       |     |      |  |       |     |     |  |       |     |     |  |  |     |  |  |  |     |  |  |  |     | 
|Total proved                    |  |       | 181 |      |  |       | 169 |     |  |       | 169 |     |  |  | 164 |  |  |  | 114 |  |  |  | 110 | 
|                                |  |       |     |      |  |       |     |     |  |       |     |     |  |  |     |  |  |  |     |  |  |  |     | 

Page 12



---



##### 



Natural Gas Reserves

|                             |  |       |       |      |  |       |       |     |  |       |       |     |  |  |       |  |  |  |       |  |  |  |       | 
|---------------------------- |  | ----- | ----- | ---- |  | ----- | ----- | --- |  | ----- | ----- | --- |  |  | ----- |  |  |  | ----- |  |  |  | ----- | 
|                             |  | 2002  |       | 2001 |  | 2000 
|                             |  |       |       |      |  |      
|Year ended December 31 (bcf) |  | Gross |       | Net  |  | Gross |       | Net |  | Gross |       | Net
|                             |  |       |       |      |  |       |       |     |  |       |       |    
|Proved developed             |  |       | 1,547 |      |  |       | 1,273 |     |  |       | 1,577 |     |  |  | 1,342 |  |  |  | 1,580 |  |  |  | 1,276 | 
|Proved undeveloped           |  |       | 548   |      |  |       | 440   |     |  |       | 389   |     |  |  | 332   |  |  |  | 329   |  |  |  | 269   | 
|                             |  |       |       |      |  |       |       |     |  |       |       |     |  |  |       |  |  |  |       |  |  |  |       | 
|Total proved                 |  |       | 2,095 |      |  |       | 1,713 |     |  |       | 1,966 |     |  |  | 1,674 |  |  |  | 1,909 |  |  |  | 1,545 | 
|                             |  |       |       |      |  |       |       |     |  |       |       |     |  |  |       |  |  |  |       |  |  |  |       | 

Barrels of Oil Equivalent

|                               |  |       |     |      |  |       |     |     |  |       |     |     |  |  |     |  |  |  |     |  |  |  |     | 
|------------------------------ |  | ----- | --- | ---- |  | ----- | --- | --- |  | ----- | --- | --- |  |  | --- |  |  |  | --- |  |  |  | --- | 
|                               |  | 2002  |     | 2001 |  | 2000 
|                               |  |       |     |      |  |      
|Year ended December 31 (mmboe) |  | Gross |     | Net  |  | Gross |     | Net |  | Gross |     | Net
|                               |  |       |     |      |  |       |     |     |  |       |     |    
|Proved developed               |  |       | 697 |      |  |       | 601 |     |  |       | 688 |     |  |  | 603 |  |  |  | 666 |  |  |  | 559 | 
|Proved undeveloped             |  |       | 221 |      |  |       | 185 |     |  |       | 239 |     |  |  | 216 |  |  |  | 206 |  |  |  | 180 | 
|                               |  |       |     |      |  |       |     |     |  |       |     |     |  |  |     |  |  |  |     |  |  |  |     | 
|Total proved                   |  |       | 918 |      |  |       | 786 |     |  |       | 927 |     |  |  | 819 |  |  |  | 872 |  |  |  | 739 | 
|                               |  |       |     |      |  |       |     |     |  |       |     |     |  |  |     |  |  |  |     |  |  |  |     | 

Reserve Life Index(1)

|                               |  |      |      |      |  |      |      |  |  |  |      | 
|------------------------------ |  | ---- | ---- | ---- |  | ---- | ---- |  |  |  | ---- | 
|Year ended December 31 (years) |  | 2002 |      | 2001 |  | 2000
|                               |  |      |      |      |  |     
|Light/medium crude oil & NGL   |  |      | 8.5  |      |  |      | 10.5 |  |  |  | 10.2 | 
|Lloydminster heavy crude oil   |  |      | 6.2  |      |  |      | 7.0  |  |  |  | 5.4  | 
|Natural gas                    |  |      | 10.0 |      |  |      | 9.4  |  |  |  | 9.0  | 
|Barrels of oil equivalent      |  |      | 8.4  |      |  |      | 9.3  |  |  |  | 8.7  | 



---

|(1) |  | Includes total proved reserves.
|--- |  | -------------------------------

Gross Proved Reserves

[Bar Graph - Light Medium Crude Oil and NGL]

[Bar Graph - Lloydminster Heavy Crude Oil]

[Bar Graph - Natural Gas]

Finding and Development Costs

Total(1)

|                                               |  |           |         |      |  |      |         |      |  |   |         |  |  |   |       | 
|---------------------------------------------- |  | --------- | ------- | ---- |  | ---- | ------- | ---- |  | - | ------- |  |  | - | ----- | 
|Year ended December 31                         |  | 2000-2002 |         | 2002 |  | 2001 |         | 2000
|                                               |  |           |         |      |  |      |         |     
|Total
capitalized costs ($ millions)           |  | $         | 3,314.9 |      |  | $    | 1,505.1 |      |  | $ | 1,172.0 |  |  | $ | 637.8 | 
|Proved reserve additions and revisions (mmboe) |  |           | 327.6   |      |  |      | 114.5   |      |  |   | 120.4   |  |  |   | 92.7  | 
|Average cost per boe                           |  | $         | 10.12   |      |  | $    | 13.14   |      |  | $ | 9.73    |  |  | $ | 6.88  | 



---

|(1) |  | Excludes acquisitions/divestitures.
|--- |  | -----------------------------------

Page 13



---



##### 



Western Canada(2)

|                                               |  |           |         |      |  |      |       |      |  |   |       |  |  |   |       | 
|---------------------------------------------- |  | --------- | ------- | ---- |  | ---- | ----- | ---- |  | - | ----- |  |  | - | ----- | 
|Year ended December 31                         |  | 2000-2002 |         | 2002 |  | 2001 |       | 2000
|                                               |  |           |         |      |  |      |       |     
|Total capitalized costs ($ millions)           |  | $         | 2,298.7 |      |  | $    | 978.5 |      |  | $ | 920.1 |  |  | $ | 400.1 | 
|Proved reserve additions and revisions (mmboe) |  |           | 256.9   |      |  |      | 94.8  |      |  |   | 112.9 |  |  |   | 49.2  | 
|Average cost per boe                           |  | $         | 8.95    |      |  | $    | 10.32 |      |  | $ | 8.15  |  |  | $ | 8.13  | 



---

|(2) |  | Excludes oil sands and acquisitions/divestitures.
|--- |  | -------------------------------------------------

Production Replacement

Total

|                                                                                       |  |           |       |      |  |      |       |      |  |  |       |  |  |  |       | 
|-------------------------------------------------------------------------------------- |  | --------- | ----- | ---- |  | ---- | ----- | ---- |  |  | ----- |  |  |  | ----- | 
|Year ended December 31                                                                 |  | 2000-2002 |       | 2002 |  | 2001 |       | 2000
|                                                                                       |  |           |       |      |  |      |       |     
|Production (mmboe)                                                                     |  |           | 273.9 |      |  |      | 109.6 |      |  |  | 99.6  |  |  |  | 64.7  | 
|Proved reserve additions and revisions (mmboe)                                         |  |           | 327.6 |      |  |      | 114.5 |      |  |  | 120.4 |  |  |  | 92.7  | 
|Production replacement ratio (excluding
acquisitions/divestitures) (percent)           |  |           | 120   |      |  |      | 104   |      |  |  | 121   |  |  |  | 143   | 
|Proved reserve additions and revisions
(including acquisitions/divestitures)(mmboe)(1) |  |           | 372.6 |      |  |      | 100.9 |      |  |  | 154.5 |  |  |  | 117.2 | 
|Production replacement ratio (including
acquisitions/divestitures) (percent)(1)        |  |           | 136   |      |  |      | 92    |      |  |  | 155   |  |  |  | 181   | 

Western Canada(2)

|                                                                                       |  |           |       |      |  |      |       |      |  |  |       |  |  |  |      | 
|-------------------------------------------------------------------------------------- |  | --------- | ----- | ---- |  | ---- | ----- | ---- |  |  | ----- |  |  |  | ---- | 
|Year ended December 31                                                                 |  | 2000-2002 |       | 2002 |  | 2001 |       | 2000
|                                                                                       |  |           |       |      |  |      |       |     
|Production (mmboe)                                                                     |  |           | 264.3 |      |  |      | 100.2 |      |  |  | 99.5  |  |  |  | 64.6 | 
|Proved reserve additions and revisions (mmboe)                                         |  |           | 256.9 |      |  |      | 94.8  |      |  |  | 112.9 |  |  |  | 49.2 | 
|Production replacement ratio (excluding
acquisitions/divestitures) (percent)           |  |           | 97    |      |  |      | 95    |      |  |  | 113   |  |  |  | 76   | 
|Proved reserve additions and revisions
(including acquisitions/divestitures)(mmboe)(1) |  |           | 301.9 |      |  |      | 81.2  |      |  |  | 147.0 |  |  |  | 73.7 | 
|Production replacement ratio (including
acquisitions/divestitures) (percent)(1)        |  |           | 114   |      |  |      | 81    |      |  |  | 148   |  |  |  | 114  | 



---

|(1) |  | Excludes 2000 Renaissance acquisition.
|--- |  | --------------------------------------
|   
|(2) |  | Excludes oil sands.                   

Recycle Ratio

The recycle ratio measures the efficiency of Huskys capital
program by comparing the cost of finding and developing
proved reserves with the netback from production. The ratio
is calculated by dividing the netback by the proved finding
and development cost on a boe basis. Netback is defined as
upstream net sales revenues less operating and administrative
costs per boe of production.

Total

|                                            |  |           |       |      |  |      |       |      |  |   |       |  |  |   |       | 
|------------------------------------------- |  | --------- | ----- | ---- |  | ---- | ----- | ---- |  | - | ----- |  |  | - | ----- | 
|Year ended December 31                      |  | 2000-2002 |       | 2002 |  | 2001 |       | 2000
|                                            |  |           |       |      |  |      |       |     
|Netback ($/boe)                             |  | $         | 16.89 |      |  | $    | 17.66 |      |  | $ | 15.23 |  |  | $ | 18.15 | 
|Proved finding and development cost ($/boe) |  | $         | 10.12 |      |  | $    | 13.14 |      |  | $ | 9.73  |  |  | $ | 6.88  | 
|Recycle ratio                               |  |           | 1.67  |      |  |      | 1.34  |      |  |   | 1.57  |  |  |   | 2.64  | 

Page 14



---



##### 



Western Canada(1)

|                                            |  |           |       |      |  |      |       |      |  |   |       |  |  |   |       | 
|------------------------------------------- |  | --------- | ----- | ---- |  | ---- | ----- | ---- |  | - | ----- |  |  | - | ----- | 
|Year ended December 31                      |  | 2000-2002 |       | 2002 |  | 2001 |       | 2000
|                                            |  |           |       |      |  |      |       |     
|Netback ($/boe)                             |  | $         | 16.29 |      |  | $    | 16.07 |      |  | $ | 15.21 |  |  | $ | 18.30 | 
|Proved finding and development cost ($/boe) |  | $         | 8.95  |      |  | $    | 10.32 |      |  | $ | 8.15  |  |  | $ | 8.13  | 
|Recycle ratio                               |  |           | 1.82  |      |  |      | 1.56  |      |  |   | 1.87  |  |  |   | 2.25  | 



---

|(1) |  | Excludes oil sands.
|--- |  | -------------------

Western Canada Drilling

|                               |     |       |       |      |     |       |       |      |     |       |       |     |     |  |       |     |     |  |     |     |    |  |     |     |    | 
|------------------------------ | --- | ----- | ----- | ---- | --- | ----- | ----- | ---- | --- | ----- | ----- | --- | --- |  | ----- | --- | --- |  | --- | --- | -- |  | --- | --- | -- | 
|                               |     |       |       | 2002 |     | 2001  |       | 2000
|                               |     |       |       |      |     |       |       |     
|Year ended December 31 (wells) |     | Gross |       | Net  |     | Gross |       | Net  |     | Gross |       | Net
|                               |     |       |       |      |     |       |       |      |     |       |       |    
|Exploration                    | Oil |       |       | 21   |     |       |       | 20   |     |       |       | 78  |     |  |       | 76  |     |  |     | 16  |    |  |     | 13  |   
|                               |     | Gas   |       |      | 139 |       |       |      | 131 |       |       |     | 102 |  |       |     | 90  |  |     |     | 30 |  |     |     | 20 | 
|                               |     | Dry   |       |      | 15  |       |       |      | 14  |       |       |     | 36  |  |       |     | 34  |  |     |     | 9  |  |     |     | 9  | 
|                               |     |       |       |      |     |       |       |      |     |       |       |     |     |  |       |     |     |  |     |     |    |  |     |     |   
|                               |     |       |       | 175  |     |       |       | 165  |     |       |       | 216 |     |  |       | 200 |     |  |     | 55  |    |  |     | 42  |   
|                               |     |       |       |      |     |       |       |      |     |       |       |     |     |  |       |     |     |  |     |     |    |  |     |     |   
|Development                    | Oil |       |       | 497  |     |       |       | 453  |     |       |       | 594 |     |  |       | 542 |     |  |     | 411 |    |  |     | 363 |   
|                               |     | Gas   |       |      | 485 |       |       |      | 453 |       |       |     | 251 |  |       |     | 221 |  |     |     | 92 |  |     |     | 70 | 
|                               |     | Dry   |       |      | 58  |       |       |      | 55  |       |       |     | 68  |  |       |     | 63  |  |     |     | 30 |  |     |     | 28 | 
|                               |     |       |       |      |     |       |       |      |     |       |       |     |     |  |       |     |     |  |     |     |    |  |     |    
|                               |     |       | 1,040 |      |     |       | 961   |      |     |       | 913   |     |     |  | 826   |     |     |  | 533 |     |    |  | 461 |    
|                               |     |       |       |      |     |       |       |      |     |       |       |     |     |  |       |     |     |  |     |     |    |  |     |    
|Total                          |     |       | 1,215 |      |     |       | 1,126 |      |     |       | 1,129 |     |     |  | 1,026 |     |     |  | 588 |     |    |  | 503 |    
|                               |     |       |       |      |     |       |       |      |     |       |       |     |     |  |       |     |     |  |     |     |    |  |     |    

Undeveloped Land Holdings

|                                            |                  |       |        |       |      |       |        |       |  |  |        |       |  |  |        |       | 
|------------------------------------------- | ---------------- | ----- | ------ | ----- | ---- | ----- | ------ | ----- |  |  | ------ | ----- |  |  | ------ | ----- | 
|                                            |                  |       | 2002   |       | 2001
|                                            |                  |       |        |       |     
|Year ended December 31 (thousands of acres) |                  | Gross |        | Net   |      | Gross |        | Net  
|                                            |                  |       |        |       |      |       |        |      
|Western Canada                              |                  |       |        |       |      |       |        |       |  |  |        |       |  |  |        |      
|                                            | Alberta          |       |        | 5,416 |      |       |        | 4,907 |  |  |        | 5,980 |  |  |        | 5,373 | 
|                                            | Saskatchewan     |       |        | 2,098 |      |       |        | 1,986 |  |  |        | 2,066 |  |  |        | 1,921 | 
|                                            | British Columbia |       |        | 314   |      |       |        | 273   |  |  |        | 188   |  |  |        | 141   | 
|                                            | Manitoba         |       |        | 13    |      |       |        | 13    |  |  |        | 76    |  |  |        | 75    | 
|                                            |                  |       |        |       |      |       |        |       |  |  |        |       |  |  |        |      
|                                            |                  |       | 7,841  |       |      |       | 7,179  |       |  |  | 8,310  |       |  |  | 7,510  |      
|Northwest Territories and Arctic            |                  |       | 463    |       |      |       | 175    |       |  |  | 1,538  |       |  |  | 409    |      
|Eastern Canada                              |                  |       | 2,414  |       |      |       | 2,104  |       |  |  | 1,878  |       |  |  | 1,471  |      
|                                            |                  |       |        |       |      |       |        |       |  |  |        |       |  |  |        |      
|Total Canada                                |                  |       | 10,718 |       |      |       | 9,458  |       |  |  | 11,726 |       |  |  | 9,390  |      
|International                               |                  |       | 4,464  |       |      |       | 2,066  |       |  |  | 1,425  |       |  |  | 697    |      
|                                            |                  |       |        |       |      |       |        |       |  |  |        |       |  |  |        |      
|Total                                       |                  |       | 15,182 |       |      |       | 11,524 |       |  |  | 13,151 |       |  |  | 10,087 |      
|                                            |                  |       |        |       |      |       |        |       |  |  |        |       |  |  |        |      

Page 15



---



##### 



Results of
OperationsMidstream

Upgrading Earnings Summary

|                                                            |  |      |       |      |  |      |       |   |  |   |       | 
|----------------------------------------------------------- |  | ---- | ----- | ---- |  | ---- | ----- | - |  | - | ----- | 
|Year ended December 31 ($ millions, except where indicated) |  | 2002 |       | 2001 |  | 2000
|                                                            |  |      |       |      |  |     
|Gross margin                                                |  | $    | 246   |      |  | $    | 428   |   |  | $ | 321   | 
|Operating costs                                             |  |      | 154   |      |  |      | 192   |   |  |   | 158   | 
|Other expenses (recoveries)                                 |  |      | (6    | )    |  |      | (12   | ) |  |   | 5     | 
|DD&A                                                        |  |      | 18    |      |  |      | 17    |   |  |   | 16    | 
|Income taxes                                                |  |      | 26    |      |  |      | 73    |   |  |   | 54    | 
|                                                            |  |      |       |      |  |      |       |   |  |   |       | 
|Earnings                                                    |  | $    | 54    |      |  | $    | 158   |   |  | $ | 88    | 
|                                                            |  |      |       |      |  |      |       |   |  |   |       | 
|Upgrader throughput(1)(mbbls/day)                           |  |      | 65.4  |      |  |      | 71.7  |   |  |   | 70.0  | 
|Synthetic crude oil sales (mbbls/day)                       |  |      | 59.3  |      |  |      | 59.5  |   |  |   | 60.6  | 
|Upgrading differential ($/bbl)                              |  | $    | 10.81 |      |  | $    | 17.91 |   |  | $ | 13.77 | 
|Unit operating cost(2)($/bbl)                               |  | $    | 6.48  |      |  | $    | 7.35  |   |  | $ | 6.17  | 



---

|(1) |  | Throughput includes diluent returned to the field.
|--- |  | --------------------------------------------------
|   
|(2) |  | Based on throughput.                              

|                                                  |                                      |   |     |      |  
|------------------------------------------------- | ------------------------------------ | - | --- | ---- | -
|Upgrading Earnings Variance Analysis ($ millions)
|                                                  |                                      |   |    
|Year ended December 31, 2000                      |                                      | $ | 88  |     
|                                                  | Volume                               |   |     | (8   | )
|                                                  | Differential                         |   |     | 115  |  
|                                                  | Operating costs  energy related     |   |     | (29  | )
|                                                  | Operating costs  non-energy related |   |     | (5   | )
|                                                  | Other                                |   |     | 17   |  
|                                                  | DD&A                                 |   |     | (1   | )
|                                                  | Income taxes                         |   |     | (19  | )
|                                                  |                                      |   |     |     
|Year ended December 31, 2001                      |                                      |   | 158 |     
|                                                  | Volume                               |   |     | (1   | )
|                                                  | Differential                         |   |     | (181 | )
|                                                  | Operating costs  energy related     |   |     | 39   |  
|                                                  | Operating costs  non-energy related |   |     | (1   | )
|                                                  | Other                                |   |     | (6   | )
|                                                  | DD&A                                 |   |     | (1   | )
|                                                  | Income taxes                         |   |     | 47   |  
|                                                  |                                      |   |     |     
|Year ended December 31, 2002                      |                                      | $ | 54  |     
|                                                  |                                      |   |     |     

Infrastructure and Marketing Earnings Summary

|                                                            |                                    |      |     |      |  |      |     |     |  |   |     |    | 
|----------------------------------------------------------- | ---------------------------------- | ---- | --- | ---- |  | ---- | --- | --- |  | - | --- | -- | 
|Year ended December 31 ($ millions, except where indicated) |                                    | 2002 |     | 2001 |  | 2000
|                                                            |                                    |      |     |      |  |     
|Gross margin                                                |                                    |      |     |      |  |      |     |     |  |   |     |    | 
|                                                            | Pipeline                           |      | $   | 55   |  |      | $   | 86  |  |   | $   | 87 | 
|                                                            | Other infrastructure and marketing |      |     | 147  |  |      |     | 111 |  |   |     | 30 | 
|                                                            |                                    |      |     |      |  |      |     |     |  |   |     |   
|                                                            |                                    |      | 202 |      |  |      | 197 |     |  |   | 117 |   
|Other expenses                                              |                                    |      | 10  |      |  |      | 10  |     |  |   | 1   |   
|DD&A                                                        |                                    |      | 20  |      |  |      | 17  |     |  |   | 15  |   
|Income taxes                                                |                                    |      | 65  |      |  |      | 72  |     |  |   | 45  |   
|                                                            |                                    |      |     |      |  |      |     |     |  |   |     |   
|Earnings                                                    |                                    | $    | 107 |      |  | $    | 98  |     |  | $ | 56  |   
|                                                            |                                    |      |     |      |  |      |     |     |  |   |     |   
|Aggregate pipeline throughput (mbbls/day)                   |                                    |      | 457 |      |  |      | 537 |     |  |   | 528 |   
|                                                            |                                    |      |     |      |  |      |     |     |  |   |     |   

Page 16



---



##### 



2002 compared with 2001

Total midstream earnings decreased by $95 million (37
percent) to $161 million in 2002 from $256 million in 2001
due to:



| |  |  | upgrading differential narrowing to average $10.81/bbl in 2002 versus $17.91/bbl in 2001
| | - |  | ----------------------------------------------------------------------------------------

partially offset by:



| |  |  | lower energy related operating costs
| | - |  | ------------------------------------

Lower throughput in 2002 compared with 2001 was due to a
plant turnaround in June and subsequent operational problems.
However synthetic crude oil sales in 2002 were augmented by
sales of third party product.

Infrastructure and marketing operations earnings increased nine percent in 2002 due to:



| |  |  | improved crude oil and natural gas commodity margins
| | - |  | ----------------------------------------------------
|
| |  |  | higher cogeneration income                          

partially offset by:



| |  |  | reduced heavy crude pipeline throughput
| | - |  | ---------------------------------------

Lower income taxes in 2002 compared with 2001 related to
lower pre-tax earnings and rate reductions in British
Columbia and Alberta and federal rate reductions for
non-resource income.

[Bar Graph - Upgrader Throughput]

[Bar Graph - Pipeline Throughput]

Midstream Capital Expenditures

Midstream capital expenditures in 2002 were primarily for
upgrader, pipeline and cogeneration plant upgrades and
upgrader debottlenecking front-end engineering.

|                                    |  |      |    |      |  |      |     |  |  |   |    | 
|----------------------------------- |  | ---- | -- | ---- |  | ---- | --- |  |  | - | -- | 
|Year ended December 31 ($ millions) |  | 2002 |    | 2001 |  | 2000
|                                    |  |      |    |      |  |     
|Upgrader                            |  | $    | 41 |      |  | $    | 47  |  |  | $ | 12 | 
|Infrastructure and marketing        |  |      | 17 |      |  |      | 58  |  |  |   | 47 | 
|                                    |  |      |    |      |  |      |     |  |  |   |    | 
|                                    |  | $    | 58 |      |  | $    | 105 |  |  | $ | 59 | 
|                                    |  |      |    |      |  |      |     |  |  |   |    | 

Page 17



---



##### 



Results of OperationsRefined
Products

Refined Products Earnings Summary

|                                                            |                                         |      |     |      |  |      |     |      |  |   |     |      | 
|----------------------------------------------------------- | --------------------------------------- | ---- | --- | ---- |  | ---- | --- | ---- |  | - | --- | ---- | 
|Year ended December 31 ($ millions, except where indicated) |                                         | 2002 |     | 2001 |  | 2000
|                                                            |                                         |      |     |      |  |     
|Gross margin                                                |                                         |      |     |      |  |      |     |      |  |   |     |     
|                                                            | Fuel sales                              |      | $   | 81   |  |      | $   | 69   |  |   | $   | 55   | 
|                                                            | Ancillary sales                         |      |     | 26   |  |      |     | 27   |  |   |     | 26   | 
|                                                            | Asphalt sales                           |      |     | 45   |  |      |     | 106  |  |   |     | 38   | 
|                                                            |                                         |      |     |      |  |      |     |      |  |   |     |     
|                                                            |                                         |      | 152 |      |  |      | 202 |      |  |   | 119 |     
|Operating and other expenses                                |                                         |      | 64  |      |  |      | 59  |      |  |   | 60  |     
|DD&A                                                        |                                         |      | 34  |      |  |      | 31  |      |  |   | 28  |     
|Income taxes                                                |                                         |      | 22  |      |  |      | 49  |      |  |   | 15  |     
|                                                            |                                         |      |     |      |  |      |     |      |  |   |     |     
|Earnings                                                    |                                         | $    | 32  |      |  | $    | 63  |      |  | $ | 16  |     
|                                                            |                                         |      |     |      |  |      |     |      |  |   |     |     
|Number of fuel outlets                                      |                                         |      | 571 |      |  |      | 580 |      |  |   | 579 |     
|Refined product sales volume                                |                                         |      |     |      |  |      |     |      |  |   |     |     
|                                                            | Light oil products (million litres/day) |      |     | 7.7  |  |      |     | 7.6  |  |   |     | 7.4  | 
|                                                            | Asphalt products (mbbls/day)            |      |     | 20.8 |  |      |     | 21.4 |  |   |     | 20.2 | 
|Refinery throughput                                         |                                         |      |     |      |  |      |     |      |  |   |     |     
|                                                            | Lloydminster refinery (mbbls/day)       |      |     | 22.0 |  |      |     | 23.7 |  |   |     | 23.4 | 
|                                                            | Prince George refinery (mbbls/day)      |      |     | 10.1 |  |      |     | 10.2 |  |   |     | 9.2  | 

2002 compared with 2001

Total refined products earnings decreased by $31 million (49
percent) to $32 million in 2002 from $63 million in 2001.
Earnings from asphalt product operations were lower in 2002
due to higher heavy crude oil feedstock costs. Light oil
refined product earnings increased primarily due to improved
fuel margins.

[Bar Graph - Light Oil Products]

[Bar Graph - Prince George Refinery]

[Bar Graph - Asphalt Products]

[Bar Graph - Lloydminster Refinery]

Page 18



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##### 



Refined Products Capital Expenditures

In 2002, capital expenditures of $28 million were directed
toward marketing outlet improvements, the remainder was spent
on refinery maintenance.

Results of OperationsCorporate

Interest

Interest expense less interest income and capitalized
interest was $104 million in 2002 compared with $101 million
in 2001. Interest capitalized in 2002 was $26 million
compared with $51 million in 2001 reflecting the completion
of the Terra Nova development project and the resultant
cessation of interest being capitalized to the project.
Interest continued to be capitalized to the White Rose
development project in 2002. Interest income was $1 million
in both 2002 and 2001. Total interest paid on short- and
long-term debt in 2002 was $131 million compared with $153
million in 2001 reflecting lower interest rates in 2002.
Huskys effective interest rate for 2002 after the effect of
swaps was 5.48 percent compared with 6.86 percent during
2001.

Foreign Exchange

Foreign exchange losses during 2002 comprised $13 million of
cash losses and $11 million of non-cash realized losses on
long-term debt offset by $11 million of unrealized gains on
long-term debt. Foreign exchange cash losses were related to
other monetary items, primarily foreign exchange collars.

In June 2002, U.S. $400 million of 10-year debt securities
were issued. The Canadian dollar equivalent on issue was
$617 million based on an exchange rate of $1.5432. On
December 31, 2002 the exchange rate was $1.5796 generating a
loss of approximately $15 million, and offsetting gains on
other U.S. dollar denominated debt.

Effective January 1, 2002, due to a change in Canadian
generally accepted accounting principles, foreign exchange
gains and losses on long-term monetary items are no longer
deferred and amortized but, as is the practice in the United
States, are reflected in earnings in the period they occur.
Results from prior periods have been restated to reflect this
change. The U.S./Canadian exchange rates expressed in
Canadian dollars at December 31, 2002, 2001, 2000 and 1999
were $1.5796, $1.5926, $1.5002 and $1.4433, respectively.

Income Taxes

Income tax expense in 2002 amounted to $420 million,
substantially unchanged from 2001. Income tax in 2002
reflected the effect of the British Columbia and Alberta
corporate income tax rate reductions and a reduction of the
federal corporate income tax rate for non-resource income.
Current taxes in 2002 comprised $41 million on Wenchang
earnings, $18 million of capital tax and the remainder for
other taxes.

At December 31, 2002 Huskys tax pools consisted of the
following:

|                                            |  |   |       | 
|------------------------------------------- |  | - | ----- | 
|($ millions)                                |  |  
|                                            |  |   |       | 
|Canadian Development Expense                |  | $ | 960   | 
|Canadian Oil and Gas Property Expense       |  |   | 942   | 
|Foreign Exploration and Development Expense |  |   | 247   | 
|Undepreciated Capital Costs                 |  |   | 1,515 | 
|Other                                       |  |   | 36    | 
|                                            |  |   |       | 
|                                            |  | $ | 3,700 | 
|                                            |  |   |       | 

Corporate Capital Expenditures

Corporate capital expenditures amounted to $23 million in
2002 and $22 million in 2001 and were primarily for computer
hardware and software and office furniture and equipment.

Sensitivity Analysis

The following table shows the effect on net earnings and cash
flow of changes in certain key variables. The analysis is
based on business conditions and production volumes during
2002. Each separate item in the sensitivity analysis assumes
the others are held constant. While these sensitivities are
applicable for the period and magnitude of changes on which
they are based, they may not be applicable in other periods,
under other economic circumstances or greater magnitudes of
change.

Page 19



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##### 



Sensitivity Analysis

|                                      |  |                   |  |                             |     |                        |  |              |       |              |  |  |     |   |  |  |       |  
|------------------------------------- |  | ----------------- |  | --------------------------- | --- | ---------------------- |  | ------------ | ----- | ------------ |  |  | --- | - |  |  | ----- | -
|Item                                  |  | Increase          |  | Effect on Pre-tax Cash Flow |     | Effect on Net Earnings
|                                      |  |                   |  |                             |     |                       
|                                      |  |                   |  | ($ millions)                |     | ($/share)(6)           |  | ($ millions) |       | ($/share)(6)
|WTI benchmark crude oil price(1)      |  | U.S. $1.00/bbl    |  |                             | 101 |                        |  |              | 0.24  |              |  |  | 64  |   |  |  | 0.15  |  
|NYMEX benchmark natural gas price(2)  |  | U.S. $0.20/mmbtu  |  |                             | 39  |                        |  |              | 0.09  |              |  |  | 23  |   |  |  | 0.05  |  
|Light/heavy crude oil differential(3) |  | Cdn. $1.00/bbl    |  |                             | (28 | )                      |  |              | (0.07 | )            |  |  | (17 | ) |  |  | (0.04 | )
|Light oil margins                     |  | Cdn. $0.005/litre |  |                             | 14  |                        |  |              | 0.03  |              |  |  | 8   |   |  |  | 0.02  |  
|Asphalt margins                       |  | Cdn. $1.00/bbl    |  |                             | 8   |                        |  |              | 0.02  |              |  |  | 5   |   |  |  | 0.01  |  
|Exchange rate (U.S. $ per Cdn. $)(4)  |  | U.S. $0.01        |  |                             | (41 | )                      |  |              | (0.10 | )            |  |  | (26 | ) |  |  | (0.06 | )
|Interest rate(5)                      |  | 1%                |  |                             | (12 | )                      |  |              | (0.03 | )            |  |  | (8  | ) |  |  | (0.02 | )



---

|(1) |  | Excludes the impact of hedging. Hedged
oil volumes at December 31, 2002 were immaterial.                                                                                                                                                                                                                                                                                                                           
|--- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Includes decrease in earnings related
to natural gas consumption.                                                                                                                                                                                                                                                                                                                                                  
|   
|(3) |  | Includes impact of upstream and
upgrading operations only.                                                                                                                                                                                                                                                                                                                                                         
|   
|(4) |  | Assumes no foreign exchange gains or
losses on U.S. $ denominated long-term debt and other
monetary items. In 2002 a new accounting standard
eliminates the deferral of foreign exchange gains and
losses on long-term monetary items. The impact of the
Canadian dollar strengthening by U.S. $0.01 would be an
increase of $19 million in net earnings based on December
31, 2002 U.S. $ denominated debt levels.
|   
|(5) |  | Interest rate sensitivity based on
annual weighted obligations.                                                                                                                                                                                                                                                                                                                                                    
|   
|(6) |  | Based on December 31, 2002 common
shares outstanding of 417.9 million.                                                                                                                                                                                                                                                                                                                                             

Liquidity and Capital Resources

Financial Ratios

|                                   |                                     |      |      |        |   |      |      |        |   |  |      |       |  
|---------------------------------- | ----------------------------------- | ---- | ---- | ------ | - | ---- | ---- | ------ | - |  | ---- | ----- | -
|Year ended December 31             |                                     | 2002 |      | 2001   |   | 2000
|                                   |                                     |      |      |        |   |     
|Cash flow                          |  operating activities ($ millions) |      | $    | 1,892  |   |      | $    | 1,930  |   |  | $    | 1,209 |  
|                                   |  financing activities ($ millions) |      | $    | 3      |   |      | $    | (423   | ) |  | $    | (558  | )
|                                   |  investing activities ($ millions) |      | $    | (1,589 | ) |      | $    | (1,507 | ) |  | $    | (651  | )
|Debt to capital employed (percent) |                                     |      | 31.8 |        |   |      | 32.8 |        |   |  | 37.4 |      
|Debt to cash flow from operations  |                                     |      | 1.1  |        |   |      | 1.1  |        |   |  | 1.7  |      
|Corporate reinvestment ratio(1)    |                                     |      | 0.8  |        |   |      | 0.8  |        |   |  | 0.6  |      



---

|(1) |  | Capital and investment expenditures divided by cash flow
from operations.
|--- |  | -------------------------------------------------------------------------

In 2002 cash generated by operating activities was $1,892
million, a decrease of $38 million from the $1,930 million
recorded in 2001 and an increase of $683 million from the
$1,209 million in 2000. Lower cash from operating activities
in 2002 was primarily due to higher accounts receivable and
inventories. Cash used in investing activities amounted to
$1,589 million in 2002, an increase of $82 million from the
$1,507 million in 2001 and an increase of $938 million from
the $651 million in 2000.

In 2002 cash provided from financing activities comprised
$972 million from the issuance of long-term debt and $9
million of proceeds from the exercise of stock options. Cash
utilized by financing activities in 2002 comprised $778
million for debt repayment, $151 million for dividends on
common shares, $31 million for return on capital securities
payment, $9 million for debt issue costs and a change of $9
million in non-cash working capital.

In 2001 financing activities utilized a net $423 million
comprising debt repayments, net of issues, of $290 million,
dividends of $150 million, return on capital securities
payment of $30 million and reduction of site restoration
provision of $4 million partially offset by a change of $42
million in non-cash working capital and proceeds of $9
million from the exercise of stock options.

In 2002 investing activities comprised $1,695 million for
capital expenditures and acquisition costs partially offset
by asset sales of $93 million and other adjustments of $13
million. In 2001 investing activities comprised $1,598
million of capital expenditures and acquisition costs
partially offset by asset sales of $67 million and other
adjustments of $24 million.

Page 20



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##### 



Cash and cash equivalents at December 31, 2002 totalled $306
million compared with a nil balance at the beginning of the
year. During January 2003, $200 million of the cash was
utilized to settle the accounts under the Companys
receivable sales agreement outstanding at the end of the
year. Total debt, net of cash and cash equivalents was
$2,079 million at December 31, 2002.

Financing Activities

As at December 31, 2002 Huskys outstanding long-term debt
totalled $2,385 million, including amounts due within one
year, compared with $2,092 million at December 31, 2001.

At December 31, 2002 there were no drawings under the
Companys $940 million revolving syndicated credit facility.
Interest rates on this facility vary and are based on
Canadian prime, Bankers Acceptance, U.S. LIBOR or U.S. base
rate, depending on the borrowing option selected, credit
ratings assigned by certain rating agencies to the Companys
senior unsecured debt and whether the facility is revolving
or non-revolving.

At December 31, 2002 the Company had utilized in support of
letters of credit $12 million of its $195 million in
short-term credit facilities. The interest rates applicable
to these facilities vary and are based on Canadian prime,
Bankers Acceptance, money market rates or U.S. dollar
equivalents.

Effective June 14, 2002, the Company issued U.S. $400 million
of 6.25 percent notes under a U.S. $1 billion base shelf
prospectus dated June 6, 2002. See note 9 of the Consolidated
Financial Statements.

Effective January 23, 2003 the Company swapped the U.S. $150
million 6.875 percent notes due November 2003 to $229 million
8.5 percent debt due November 2003. This transaction
effectively fixes the exchange rate on the U.S. notes at
$1.525. As a result there will be no future foreign exchange
gains or losses on these notes up to their maturity date.

The Company has an agreement to sell up to $200 million of
net trade receivables on a continual basis. The agreement
calls for purchase discounts, based on Canadian commercial
paper rates, to be paid on an ongoing basis. The average
effective rate in 2002 was approximately 2.8 percent (2001 
4.7 percent). The Company has potential exposure to an
immaterial amount of credit loss under this agreement. As at
December 31, 2002 $200 million of net trade receivables had
been sold.

The Company believes that, based on its current forecast for
commodity prices for 2003, together with the corporate
hedging plan its capital program of $1.8 billion will be
funded by operating activities and, to the extent required,
available lines of credit. In the event of significantly
lower cash flow the Company is able to defer certain of its
capital spending programs without penalty.

The Company declared dividends aggregating $0.36 per share
($151 million) in 2002. The board of directors of Husky has
established a dividend policy that pays quarterly dividends
of $0.09 ($0.36 annually) per common share. However, there
can be no assurance that further dividends will be declared.
The declaration of dividends will be at the discretion of the
Board of Directors which will consider earnings, capital
requirements, financial condition of the Company and other
relevant factors.

At December 31, 2002 Husky had the following credit ratings:

|                                   |  |            |  |                                  |  |  |  | 
|---------------------------------- |  | ---------- |  | -------------------------------- |  |  |  | 
|                                   |  | Rating     |  | Debt Rated                      
|                                   |  |            |  |                                 
|Standard and Poors Rating Service |  | BBB        |  | Senior unsecured debt           
|                                   |  | BB+        |  | Capital securities              
|                                   |  | BBB        |  | 8.45% senior secured bonds      
|Moodys Investor Service           |  | Baa2       |  | Senior unsecured debt           
|                                   |  | Ba1        |  | Capital securities              
|                                   |  | Baa2       |  | 8.45% senior secured bonds      
|Dominion Bond Rating Service       |  | BBB (high) |  | Senior unsecured long-term notes
|                                   |  | BBB        |  | Capital securities              

SIGNIFICANT ACCOUNTING POLICIES

The preparation of financial statements in accordance with
generally accepted accounting principles requires that
management make appropriate decisions with respect to the
selection of accounting policies and in formulating estimates
and assumptions that affect the reported amount of assets,
liabilities, revenues and expenses. The following is included
in Managements Discussion and Analysis to aid the reader in
assessing the critical accounting policies and practices of
the Company and the likelihood of materially different
results being reported depending on managements assumptions
and changes in prevailing conditions which

Page 21



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##### 



affect the application of these policies and practices.
Significant accounting policies are disclosed in note 3 of
the Consolidated Financial Statements. Inherent in the
application of a number of these policies is the requirement
of management to make certain assumptions and interpretations
that affect the determination of assets, liabilities,
revenues and expenses. Accordingly, the emergence of new
information and changed circumstances can cause material
changes in reported financial results.

The following assessment of significant accounting policies
is not meant to be exhaustive. Materially different results
might occur from the application of the entire series of
accounting policies to which the Company might be subject.
Additionally, the Company might realize different results
from the application of new accounting standards promulgated
by various rule-making bodies.

Proved Oil and Gas Reserves

Proved oil and gas reserves are the estimated quantities of
crude oil, natural gas liquids including condensate and
natural gas that geological and engineering data demonstrate
with reasonable certainty can be recovered in future years
from known reservoirs under existing economic and operating
conditions. Reserves are considered proved if they can be
produced economically as demonstrated by either actual
production or conclusive formation tests. Reserves which
must be produced through the application of enhanced recovery
techniques are included in the proved category only after
successful testing by a pilot project or operation of an
installed program in the same reservoir that provides support
for the engineering analysis on which the project was based.
Proved developed reserves are expected to be produced through
existing wells and with existing facilities and operating
methods.

The estimates are made using all available geological and
reservoir data as well as historical production data.
Estimates are reviewed and revised as appropriate. Revisions
occur as a result of changes in prices, costs, fiscal
regimes, reservoir performance or a change in the Companys
plans. The effect of changes in proved oil and gas reserves
on the financial results and position of the Company is
described under the heading Full Cost Accounting for Oil and
Gas Activities.

Full Cost Accounting for Oil and Gas Activities

Depletion Expense

The Company uses the Full Cost Method of accounting for
exploration and development activities. In accordance with
this method of accounting, all costs associated with
exploration and development are capitalized whether
successful or not. The aggregate of net capitalized costs,
estimated future development costs and estimated removal and
site restoration costs is amortized using the unit of
production method based on estimated proved oil and gas
reserves.

An increase in estimated proved oil and gas reserves will
result in a corresponding reduction in depletion expense. A
decrease in estimated future development costs will result in
a corresponding reduction in depletion expense.

Withheld Costs

Certain costs related to unproved properties and major
development projects may be excluded from costs subject to
depletion until proved reserves have been determined or their
value is impaired. These properties are reviewed quarterly
and any impairment is transferred to the costs being depleted
or, if the properties are located in a cost centre where
there is no reserve base, the impairment is charged directly
to earnings.

Ceiling Test

The Full Cost Method of accounting requires the calculation
of a ceiling test which limits the net capital costs carried
to an amount that is equal to or less than the estimated
future net cash inflows from the Companys oil and gas
properties, including net cost less impairment of unproved
properties. The test is a cost recovery test and is not
intended to represent an estimate of fair market value. The
test is performed quarterly. If the net carrying cost of the
oil and gas properties exceeds the indicated limit then the
difference is charged to earnings.

Impairment of Long-lived Assets

In addition to testing the permitted limits of oil and gas
asset carrying costs, the Company is required to review the
carrying value of all other property, plant and equipment for
potential impairment. The review for impairment compares the
carrying cost to the estimated fair value of the long-lived
asset and if the carrying cost exceeds the fair value the
difference is charged to earnings.

Asset Retirement Obligations

The Company is required to provide for future removal and
site restoration costs, net of expected recoveries. The
Company must estimate these costs in accordance with existing
laws, contracts or other policies and

Page 22



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##### 



must estimate the expected recoveries, which is generally the
salvage value or residual value of an asset. These estimated
net costs are charged to earnings and the appropriate
liability account over the expected service life of the
asset. When the future removal and site restoration costs
cannot be reasonably determined, a contingent liability may
exist. Contingent liabilities are charged to earnings when
management is able to determine the amount and the likelihood
of the future obligation.

Legal, Environmental Remediation and Other Contingent Matters

The Company is required to both determine whether a loss is
probable based on judgement and interpretation of laws and
regulations and determine that the loss can reasonably be
estimated. When the loss is determined it is charged to
earnings. The Companys management must continually monitor
known and potential contingent matters and make appropriate
provisions by charges to earnings when warranted by
circumstance.

Income Tax Accounting

The determination of the Companys income and other tax
liabilities requires interpretation of complex laws and
regulations often involving multiple jurisdictions. All tax
filings are subject to audit and potential reassessment after
the lapse of considerable time. Accordingly, actual income
tax liability may differ significantly from that estimated
and recorded by management.

New Accounting Standards

In June 2001 the Financial Accounting Standards Board issued
Statement No. 143 Accounting for Asset Retirement
Obligations. Financial Accounting Statement (FAS) 143
requires an entity to record the fair value of a liability
for an asset retirement obligation in the period in which it
is incurred. When initially recorded, the liability is added
to the related property, plant and equipment, subsequently
increasing depletion, depreciation and amortization expense.
In addition, the liability is accreted for the change in
present value in each period. Upon adoption of FAS 143 the
Company will adjust its existing future removal and site
restoration liability using the cumulative-effect approach.
FAS 143 is effective for fiscal years commencing on or after
January 1, 2003. The Canadian Institute of Chartered
Accountants issued an exposure draft entitled Asset
Retirement Obligations in April 2002 that is substantially
the same as FAS 143 and is effective for fiscal years
beginning on or after January 1, 2004.

The Company has estimated that the cumulative effect will be
an increase of the future removal and site restoration
liability of $58 million, an increase of related net
property, plant and equipment of $56 million, a decrease to
the future income tax liability of $1 million and a decrease
in retained earnings of $1 million.

RESULTS OF OPERATIONS FOR 2001 COMPARED WITH 2000

Upstream

The increase in upstream revenues for 2001 was due to:



| |  |  | higher production of crude oil and natural gas from the acquisition of Renaissance
| | - |  | ----------------------------------------------------------------------------------
|
| |  |  | heavy oil exploitation programs in the Lloydminster heavy oil area                
|
| |  |  | higher realized natural gas prices                                                

partially offset by:



| |  |  | lower crude oil and NGL prices
| | - |  | ------------------------------

Operating costs per unit of production increased 13 percent in 2001 as a result of:



| |  |  | increased production of heavier gravity crude oil                                                              
| | - |  | ---------------------------------------------------------------------------------------------------------------
|
| |  |  | the operation of mature properties
under waterflood and a higher proportion of low pressure
shallow natural gas

Total DD&A per boe was $7.31 in 2001 compared with $6.28 in
2000. The increase in the DD&A rate was primarily due to a
full year of operations for the Renaissance properties.

Midstream

Higher earnings in 2001 was primarily due to wider upgrading
differentials and improved crude oil and natural gas
commodity marketing volumes and margins partially offset by
higher energy related operating costs.

Page 23



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##### 



Refined Products

Asphalt product operations accounted for most of the improved
earnings in 2001 due to the lower cost feedstock and
increased sales volume.

Corporate

Capitalized interest was primarily in respect of Terra Nova
and White Rose projects. Interest paid in 2000 included $9
million in respect of the partial redemption of the Husky
Terra Nova 8.45 percent senior secured bonds. Huskys
average interest rate in 2001 was approximately 6.9 percent
compared with 7.5 percent in 2000.

QUARTERLY FINANCIAL SUMMARY

|                                                                 |                         |    |        |         |      |    |        |         |  |    |        |         |  |    |        |         |  |   |        |         |  |   |        |         |  |   |        |         |  |   |        |         | 
|---------------------------------------------------------------- | ----------------------- | -- | ------ | ------- | ---- | -- | ------ | ------- |  | -- | ------ | ------- |  | -- | ------ | ------- |  | - | ------ | ------- |  | - | ------ | ------- |  | - | ------ | ------- |  | - | ------ | ------- | 
|                                                                 |                         |    | 2002   |         | 2001
|                                                                 |                         |    |        |         |     
|($ millions, except where indicated)                             |                         | Q4 |        | Q3      |      | Q2 |        | Q1      |  | Q4 |        | Q3      |  | Q2 |        | Q1     
|                                                                 |                         |    |        |         |      |    |        |         |  |    |        |         |  |    |        |        
|Sales and operating revenues,
net of royalties                   |                         | $  | 1,697  |         |      | $  | 1,669  |         |  | $  | 1,659  |         |  | $  | 1,359  |         |  | $ | 1,615  |         |  | $ | 1,470  |         |  | $ | 1,731  |         |  | $ | 1,780  |        
|Net earnings                                                     |                         | $  | 242    |         |      | $  | 173    |         |  | $  | 263    |         |  | $  | 126    |         |  | $ | 45     |         |  | $ | 118    |         |  | $ | 299    |         |  | $ | 192    |        
|Net earnings per share                                           |                         |    |        |         |      |    |        |         |  |    |        |         |  |    |        |         |  |   |        |         |  |   |        |         |  |   |        |         |  |   |        |        
|                                                                 |  Basic                 |    | $      | 0.57    |      |    | $      | 0.38    |  |    | $      | 0.64    |  |    | $      | 0.29    |  |   | $      | 0.09    |  |   | $      | 0.25    |  |   | $      | 0.74    |  |   | $      | 0.42    | 
|                                                                 |  Diluted               |    | $      | 0.57    |      |    | $      | 0.38    |  |    | $      | 0.64    |  |    | $      | 0.29    |  |   | $      | 0.09    |  |   | $      | 0.24    |  |   | $      | 0.73    |  |   | $      | 0.42    | 
|Cash flow from operations                                        |                         | $  | 635    |         |      | $  | 590    |         |  | $  | 498    |         |  | $  | 373    |         |  | $ | 287    |         |  | $ | 478    |         |  | $ | 561    |         |  | $ | 620    |        
|Cash flow from operations per share                              |                         |    |        |         |      |    |        |         |  |    |        |         |  |    |        |         |  |   |        |         |  |   |        |         |  |   |        |         |  |   |        |        
|                                                                 |  Basic                 |    | $      | 1.50    |      |    | $      | 1.39    |  |    | $      | 1.18    |  |    | $      | 0.88    |  |   | $      | 0.67    |  |   | $      | 1.13    |  |   | $      | 1.33    |  |   | $      | 1.47    | 
|                                                                 |  Diluted               |    | $      | 1.50    |      |    | $      | 1.39    |  |    | $      | 1.17    |  |    | $      | 0.87    |  |   | $      | 0.66    |  |   | $      | 1.12    |  |   | $      | 1.32    |  |   | $      | 1.46    | 
|Share price                                                      |                         |    |        |         |      |    |        |         |  |    |        |         |  |    |        |         |  |   |        |         |  |   |        |         |  |   |        |         |  |   |        |        
|                                                                 |  High                  |    | $      | 17.20   |      |    | $      | 17.00   |  |    | $      | 17.98   |  |    | $      | 17.80   |  |   | $      | 20.25   |  |   | $      | 20.95   |  |   | $      | 17.30   |  |   | $      | 15.80   | 
|                                                                 |  Low                   |    | $      | 15.43   |      |    | $      | 14.00   |  |    | $      | 15.85   |  |    | $      | 14.20   |  |   | $      | 15.06   |  |   | $      | 14.65   |  |   | $      | 13.10   |  |   | $      | 13.20   | 
|                                                                 |  Close (end of period) |    | $      | 16.47   |      |    | $      | 16.70   |  |    | $      | 16.66   |  |    | $      | 17.10   |  |   | $      | 16.47   |  |   | $      | 17.85   |  |   | $      | 16.22   |  |   | $      | 13.25   | 
|Shares traded (thousands)                                        |                         |    | 20,478 |         |      |    | 30,620 |         |  |    | 31,159 |         |  |    | 34,383 |         |  |   | 59,251 |         |  |   | 46,993 |         |  |   | 25,333 |         |  |   | 25,280 |        
|Number of weighted average common
shares outstanding (thousands) |                         |    |        |         |      |    |        |         |  |    |        |         |  |    |        |         |  |   |        |         |  |   |        |         |  |   |        |         |  |   |        |        
|                                                                 |  Basic                 |    |        | 417,748 |      |    |        | 417,497 |  |    |        | 417,393 |  |    |        | 416,939 |  |   |        | 416,545 |  |   |        | 416,025 |  |   |        | 415,878 |  |   |        | 415,805 | 
|                                                                 |  Diluted               |    |        | 419,567 |      |    |        | 419,136 |  |    |        | 419,558 |  |    |        | 418,951 |  |   |        | 419,367 |  |   |        | 419,153 |  |   |        | 418,337 |  |   |        | 417,555 | 

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