EXHIBIT 3
                                                                       ---------



                         2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS

MANAGEMENT'S DISCUSSION AND ANALYSIS

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements in this document or documents incorporated herein by
reference for Canadian Natural Resources Limited (the "Company") may constitute
"forward-looking statements" within the meaning of the United States Private
Litigation Reform Act of 1995. These forward-looking statements can generally be
identified as such because of the context of the statements including words such
as the Company "believes", "anticipates", "expects", "plans", "estimates", or
words of a similar nature.

The forward-looking statements are based on current expectations and are subject
to known and unknown risks, uncertainties and other factors that may cause the
actual results, performance or achievements of the Company, or industry results,
to be materially different from any future results, performance or achievements
expressed or implied by such forward-looking statements. Such factors include,
among others: the general economic and business conditions which will, among
other things, impact demand for and market prices of the Company's products; the
foreign currency exchange rates; the economic conditions in the countries and
regions in which the Company conducts business; the political uncertainty,
including actions of or against terrorists, insurgent groups or other conflict
including conflict between states; the industry capacity; the ability of the
Company to implement its business strategy, including exploration and
development activities; the impact of competition, availability and cost of
seismic, drilling and other equipment; the ability of the Company to complete
its capital programs; the ability of the Company to transport its products to
market; the potential delays or changes in plans with respect to exploration or
development projects or capital expenditures; the operating hazards and other
difficulties inherent in the exploration for and production and sale of crude
oil and natural gas; the availability and cost of financing; the success of
exploration and development activities; the timing and success of integrating
the business and operations of acquired companies; the production levels; the
uncertainty of reserve estimates; the actions by governmental authorities; the
government regulations and the expenditures required to comply with them
(especially safety and environmental laws and regulations); the asset retirement
obligations; and other circumstances affecting revenues and expenses. The impact
of any one factor on a particular forward-looking statement is not determinable
with certainty as such factors are interdependent upon other factors, and
management's course of action would depend upon its assessment of the future
considering all information then available.

Statements relating to "reserves" are deemed to be forward-looking statements as
they involve the implied assessment based on certain estimates and assumptions
that the reserves described can be profitably produced in the future.

Readers are cautioned that the foregoing list of important factors is not
exhaustive. Although the Company believes that the expectations conveyed by the
forward-looking statements are reasonable based on information available to it
on the date such forward-looking statements are made, no assurances can be given
as to future results, levels of activity and achievements. All subsequent
forward-looking statements, whether written or oral, attributable to the Company
or persons acting on its behalf are expressly qualified in their entirety by
these cautionary statements. The Company assumes no obligation to update
forward-looking statements should circumstances or management's estimates or
opinions change.

SPECIAL NOTE REGARDING NON-GAAP FINANCIAL MEASURES

Management's discussion and analysis includes references to financial measures
commonly used in the oil and gas industry, such as cash flow, cash flow per
share and EBITDA (net earnings before interest, taxes, depreciation, depletion
and amortization, asset retirement obligation accretion, unrealized foreign
exchange, stock-based compensation expense and unrealized risk management
activities). These financial measures are not defined by generally accepted
accounting principles ("GAAP") and therefore are referred to as non-GAAP
measures. The non-GAAP measures used by the Company may not be comparable to
similar measures presented by other companies. The Company uses these non-GAAP
measures to evaluate the performance of the Company and its business segments.
The non-GAAP measures should not be considered an alternative to or more
meaningful than net earnings, as determined in accordance with Canadian GAAP, as
an indication of the Company's performance.

MANAGEMENT'S DISCUSSION AND ANALYSIS

Management's discussion and analysis ("MD&A") of the financial condition and
results of operations of the Company should be read in conjunction with the
Company's audited consolidated financial statements and related notes for the
year ended December 31, 2004. The consolidated financial statements have been
prepared in accordance with Canadian GAAP. A reconciliation of Canadian GAAP to
United States GAAP is included in note 17 to the consolidated financial
statements. All dollar amounts are referenced in Canadian dollars, except where
noted otherwise. The calculation of barrels of oil equivalent ("boe") is based
on a conversion ratio of six thousand cubic feet ("mcf") of natural gas to one
barrel ("bbl") of oil to estimate relative energy content. This conversion may
be misleading, particularly when used in isolation, since the 6 mcf:1 bbl ratio
is based on an energy equivalency at the burner tip and does not represent the
value equivalency at the well head. Production volumes are the Company's
interest before royalties, and realized prices exclude the effect of risk
management activities, except where noted otherwise. The following discussion
and analysis refers primarily to the Company's 2004 financial results compared
to 2003, unless otherwise indicated. In addition, this discussion details the
Company's capital program and outlook for 2005. The fourth quarter discussion
and analysis was included in the Company's fourth quarter press release. This
MD&A is dated February 18, 2005.



                                                             CANADIAN NATURAL 39
<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT

OBJECTIVE AND STRATEGY

The Company's objective is to increase cash flow, crude oil and natural gas
production, reserves and net asset value on a per common share basis through the
development of its existing crude oil and natural gas properties and through the
discovery and acquisition of new reserves. The Company accomplishes this by
having a defined growth and value enhancement plan for each of its products and
segments. The Company takes a measured approach to growth and investments and
focuses on creating long-term shareholder wealth. The Company effectively
allocates its capital by maintaining:

o    Balance between its products, namely natural gas, light crude oil, Pelican
     Lake crude oil (1), primary heavy crude oil and thermal heavy crude oil;

o    Balance between near-, mid- and long-term projects;

o    Balance between acquisitions, exploitation and exploration; and

o    Balance between sources of debt and a strong balance sheet.

(1) Pelican Lake crude oil is 14-17 degrees API oil, but receives medium quality
crude netbacks due to low operating costs and low royalty rates.

The Company has expanded its hedging program in an effort to reduce the risk of
volatility in commodity price markets and to underpin the Company's cashflow
through the Horizon Oil Sands Project ("Horizon Project") construction period.

The Company's crude oil marketing strategy includes displacing medium sour crude
oil from PADD II, supporting and participating in pipeline additions,
encouraging the development of projects that add conversion capacity, and
blending strategy.

Cost control is central to the Company's strategy. By controlling costs
consistently throughout all industry cycles, the Company is able to achieve
continued growth. Cost control is attained by area knowledge, by core area
domination and by operating at a high working interest.

Strategic accretive acquisitions are a key component of the Company's strategy.
The Company has used excess cash flows derived from higher than expected
commodity prices to selectively acquire properties generating future cash flows
in its core regions. These targeted acquisitions provide relatively quick
repayment of initial investments and will provide additional free cash flow
during the construction years of the Horizon Project while still achieving
targeted returns. The acquisitions of the Petrovera Partnership ("Petrovera")
and natural gas properties in North America and the acquisition of properties in
the central North Sea meet these reinvestment criteria and further enhance the
Company's abilities to complete the Horizon Project. This expansion of the
conventional asset base also helps reduce the sole project risk exposure
associated with this major oil sands development project.

The Company is committed to maintaining its strong financial position throughout
construction of the Horizon Project. The Company has built the necessary
financial capacity to complete the Horizon Project while at the same time not
compromising delivery of low-risk crude oil and natural gas growth
opportunities.

The year ended December 31, 2004, was another successful year in the execution
of the Company's strategy. Highlights are as follows:

o    Achieved record levels of net earnings;

o    Achieved record levels of cash flow;

o    Achieved record levels of natural gas and crude oil and NGLs production;

o    Achieved the Company's annual production guidance for both natural gas and
     crude oil and NGLs;

o    Completed four strategic acquisitions including:

     o    the acquisition of Petrovera;

     o    the acquisition of natural gas assets located in the Company's core
          region of Northeast British Columbia and an extension of its core
          region in the Foothills area of Northwest Alberta;

     o    the acquisition of light crude oil producing properties in the Central
          North Sea;

     o    the acquisition of certain natural gas properties located in Alberta,
          British Columbia and Saskatchewan;

o    Commenced production from a new phase of the Primrose in-situ thermal crude
     oil development;

o    Filed a public disclosure document for regulatory approval of the Primrose
     East project;

o    Received regulatory approvals for the Horizon Project from the Alberta
     Energy and Utilities Board as well as the Alberta Provincial Cabinet and
     the Canadian Federal Cabinet;

o    Completed the subdivision of its Common Shares on the basis of two for one;

o    Increased the quarterly dividend by 33% to $0.10 per common share; and

o    Purchased 873,400 common shares for a total cost of $33 million under the
     Company's Normal Course Issuer Bid.



40 CANADIAN NATURAL
<PAGE>
                         2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS

NET EARNING AND CASH FLOW FROM OPERATIONS

<TABLE>
<CAPTION>
FINANCIAL HIGHLIGHTS ($ millions, except per common share amounts)                    2004       2003(1)      2002(1)
------------------------------------------------------------------                  -------      -------      -------
<S>                                                                                 <C>          <C>          <C>
Revenue, before royalties                                                           $ 7,547      $ 6,155      $ 4,459
Net earnings                                                                        $ 1,405      $ 1,403      $   539
Per common share     - basic (2)                                                    $  5.24      $  5.23      $  2.11
                     - diluted (2)                                                  $  5.20      $  5.06      $  2.04
Cash flow from operations (4)                                                       $ 3,769      $ 3,160      $ 2,254
Per common share     - basic (2)                                                    $ 14.06      $ 11.77      $  8.82
                     - diluted (2)                                                  $ 13.98      $ 11.53      $  8.50
Capital expenditures, net of dispositions (3)                                       $ 4,633      $ 2,506      $ 4,069
</TABLE>

(1)  Restated for changes in accounting policies (see consolidated financial
     statements note 2).

(2)  Restated to reflect two-for-one share split in May 2004.

(3)  In February 2004, the Company acquired certain resource properties in its
     Northern Plains core region, collectively known as Petrovera, for $471
     million. Strategically, the acquisition fit with the Company's objective of
     dominating its core regions and related infrastructure. The Company
     achieved cost reductions through synergies with its existing facilities,
     including additional throughput in its 100% owned ECHO Pipeline. The
     acquisition is included in the results of operations commencing February
     2004.

     In 2002, the Company paid cash of $850 million and issued 20,016,436 common
     shares to acquire all of the issued and outstanding common shares of Rio
     Alto Exploration Ltd. ("Rio Alto") by way of a plan of arrangement. This
     was a strategic acquisition as it increased the Company's natural gas
     production and added a new natural gas core region in Northwest Alberta.
     The Rio Alto acquisition is included in the results of operations
     commencing July 2002.

(4)  Cash flow from operations is a non-GAAP term that represents net earnings
     adjusted for non-cash items. The Company evaluates its performance and that
     of its business segments based on net earnings and cash flow from
     operations. The Company considers cash flow from operations a key measure
     as it demonstrates the Company's ability and the ability of its business
     segments to generate the cash flow necessary to fund future growth through
     capital investment and to repay debt.

<TABLE>
<CAPTION>
($ millions)                                                     2004        2003         2002
------------------------------------------                     -------     -------      -------
<S>                                                            <C>         <C>          <C>
Net earnings                                                   $ 1,405     $ 1,403      $   539
Non-cash items:
 Depletion, depreciation and amortization                        1,769       1,509        1,298
 Asset retirement obligation accretion                              51          62           68
 Stock-based compensation                                          249         200            -
 Unrealized risk management activities                             (40)          -            -
 Unrealized foreign exchange gain                                  (94)       (343)         (36)
 Deferred petroleum revenue tax (recovery)                         (45)         (9)          10
 Future income tax                                                 474         338          375
                                                               -------     -------      -------
Cash flow from operations                                      $ 3,769     $ 3,160      $ 2,254
                                                               =======     =======      =======
</TABLE>

The Company achieved record levels of net earnings, cash flow from operations
and production in 2004 as a result of strong operational performance combined
with strong commodity prices. The strong operating results are attributable to
the Company following its defined growth strategy and to the strong asset base
the Company has developed over time through organic growth and accretive
acquisitions.

Net earnings increased in 2004 to $1,405 million ($5.24 per common share), up
from $1,403 million ($5.23 per common share) in 2003 (2002 - $539 million or
$2.11 per common share). The increase in net earnings in 2004 is primarily due
to higher commodity prices and higher production volumes. These increases were
offset by increased depletion, depreciation and amortization expense, increased
stock-based compensation expense and decreased foreign exchange gains in 2004.
In addition, net earnings were also impacted by the Company's risk management
activities as a result of an expanded hedging program (see risk management
activities and liquidity and capital resources) and one-time non recurring tax
rate reductions.

Cash flow from operations reached record levels in 2004. Cash flow from
operations increased 19% to $3,769 million ($14.06 per common share), up from
$3,160 million ($11.77 per common share) in 2003 (2002 - $2,254 million or $8.82
per common share). The increase in cash flow from operations resulted primarily
from higher product prices and increased production volumes. In 2004, the
Company's average price per barrel of crude oil and NGLs increased 16% to $37.99
from $32.66 in 2003 (2002 - $31.22). The Company's average natural gas price
increased 5% to $6.50 per mcf from $6.21 per mcf in 2003 (2002 - $3.77 per mcf).

Production volumes before royalties increased 12% to a record 513,835 boe/d, up
from 458,814 boe/d in 2003 (2002 - 420,722 boe/d). The increase in production
volumes was a result of organic growth and accretive acquisitions. Production of
crude oil and NGLs before royalties increased 17% to 282,489 bbl/d, up from
242,392 bbl/d in 2003 (2002 -215,335 bbl/d). Natural gas production before
royalties increased 7% to 1,388 mmcf/d, up from 1,299 mmcf/d in 2003 (2002 -
1,232 mmcf/d).


                                                            CANADIAN NATURAL  41
<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT

<TABLE>
<CAPTION>

OPERATING HIGHLIGHTS                                                                        2004           2003           2002
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>            <C>            <C>
CRUDE OIL AND NGLS ($/bbl, except daily production)
Daily production, before royalties (bbl/d)                                               282,489        242,392        215,335
Sales price (1)                                                                     $      37.99      $   32.66       $  31.22
Royalties                                                                                   3.16           2.77           3.16
Production expense                                                                         10.05          10.28           8.45
                                                                                    ------------      ---------       --------
Netback                                                                             $      24.78      $   19.61       $  19.61
                                                                                    ------------      ---------       --------
NATURAL GAS ($/mcf, except daily production)
Daily production, before royalties (mmcf/d)                                                1,388          1,299          1,232
Sales price (1)                                                                     $       6.50      $    6.21       $   3.77
Royalties                                                                                   1.35           1.32           0.78
Production expense                                                                          0.67           0.60           0.57
                                                                                    ------------      ---------       --------
Netback                                                                             $       4.48      $    4.29       $   2.42
                                                                                    ------------      ---------       --------
BARREL OF OIL EQUIVALENT ($/boe, except daily production)
Daily production, before royalties (boe/d)                                               513,835        458,814        420,722
Sales price (1)                                                                     $      38.45      $   34.84       $  27.02
Royalties                                                                                   5.37           5.20           3.91
Production expense                                                                          7.35           7.15           5.99
                                                                                    ------------      ---------       --------
Netback                                                                             $      25.73      $   22.49       $  17.12
                                                                                    ============      =========       ========
</TABLE>

(1)  Including transportation costs and excluding risk management activities.

BUSINESS ENVIRONMENT

<TABLE>
<CAPTION>
                                                                                           2004          2003           2002
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                <C>               <C>             <C>
WTI benchmark price (US$/bbl)                                                       $      41.43      $   31.02       $  26.11
Dated Brent benchmark price (US$/bbl)                                               $      38.28      $   28.83       $  25.01
Differential to LLB blend (US$/bbl)                                                 $      13.44      $    8.55       $   6.50
Condensate benchmark price (US$/bbl)                                                $      41.62      $   31.42       $  26.00
NYMEX benchmark price (US$/mmbtu)                                                   $       6.09      $    5.44       $   3.25
AECO benchmark price (C$/GJ)                                                        $       6.43      $    6.35       $   3.86
US/Canadian dollar average exchange rate (US$)                                            0.7683         0.7135         0.6368
                                                                                          ======         ======         ======
</TABLE>

World crude oil prices remained strong in 2004 due to the strong growth in
world-wide demand, particularly in the United States and Asia. World crude oil
prices have also been impacted by geopolitical uncertainty in several areas of
the world, resulting in concerns around the supply of crude oil. World crude oil
prices have been further impacted by weather related issues causing production
disruptions in the United States Gulf Coast. West Texas Intermediate ("WTI")
averaged US$41.43 per bbl for the year ended December 31, 2004, up 34% compared
to US$31.02 per bbl in 2003 (2002 - US$26.11 per bbl). The impact of the higher
WTI prices on the Company's heavier crude oil production was mitigated by wider
heavy crude oil differentials, which increased 57% to US$13.44 per bbl in 2004,
up from US$8.55 per bbl in 2003 (2002 - US$6.50 per bbl). Realized crude oil
prices were also impacted by the strengthening Canadian dollar.

North American natural gas prices remained strong due to concerns around supply
and the impact of higher crude oil prices. NYMEX natural gas prices increased
12% to average US$6.09 per mmbtu in 2004, up from US$5.44 per mmbtu in 2003
(2002 - US$3.25 per mmbtu). AECO natural gas prices increased 1 % to average
$6.43 per GJ in 2004, up from $6.35 per GJ in 2003 (2002 - $3.86 per GJ).



42 CANADIAN NATURAL
<PAGE>




                         2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS

<TABLE>
<CAPTION>
REVENUE, BEFORE ROYALTIES

PRODUCT PRICES (1)                                                                      2004       2003            2002
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                    <C>        <C>           <C>
CRUDE OIL AND NGLS ($/bbl)

North America                                                                            33.16    $ 29.40       $ 28.77

North Sea                                                                                51.37    $ 42.00       $ 40.32

Offshore West Africa                                                                     49.05    $ 36.47       $ 40.10

Company average                                                                          37.99    $ 32.66       $ 31.22

NATURAL GAS ($/mcf)

North America                                                                            6.61     $  6.34       $  3.79

North Sea                                                                                3.73     $  3.03       $  2.75

Offshore West Africa                                                                     5.25     $  4.37       $  4.82

Company average                                                                          6.50     $  6.21       $  3.77

PERCENTAGE OF REVENUE (excluding midstream revenue)

Crude oil and NGLs                                                                          54%        50%           58%

Natural gas                                                                                 46%        50%           42%
                                                                                          ====       ====          ====

</TABLE>


(1)  Including transportation costs and excluding risk management activities.

Realized crude oil prices increased 16% to average $37.99 per bbl in 2004, up
from $32.66 per bbl in 2003 (2002 - $31.22 per bbl). The increase in realized
crude oil prices is a result of higher benchmark crude oil prices.

The Company's realized natural gas price increased 5% to average $6.50 per mcf
in 2004, up from $6.21 per mcf in 2003 (2002 - $3.77 per mcf).

NORTH AMERICA

North America realized crude oil prices increased 13% to average $33.16 per bbl
in 2004, up from $29.40 per bbl in 2003 (2002 - $28.77 per bbl). The increase in
the realized crude oil price is due mainly to higher world crude oil prices,
partially offset by wider heavy crude oil differentials and the stronger
Canadian dollar.

The Company continues to focus on its crude oil marketing strategy, which
includes development of a blending strategy, supporting pipeline projects that
will provide capacity to transport crude oil to new markets, and working with
PADD II refiners to add incremental heavy crude oil conversion capacity. As part
of an industry initiative to develop new blends of Western Canadian crude oils,
the Company has access to blending capacity of up to 140 mbbl/d. The Company is
contributing 123 mbbl/d of heavy crude oil blends to the Western Canadian Select
("WCS") stream, a new blend of up to 10 different crude oil streams. WCS
resembles a Bow River type crude with distillation cuts approximating a natural
heavy oil with premium quality asphalt characteristics. The new blend has an API
of 19-22 degrees and is expected to grow, with the potential to become a new
benchmark for North American markets in addition to WTI. The Company also
continues to work with refiners to advance expansion of heavy crude oil
conversion capacity, and is working with pipeline companies to develop new
capacity to the Canadian west coast where crude cargos can be sold on a
world-wide basis.

North America realized natural gas prices increased 4% to average $6.61 per mcf
in 2004, up from $6.34 per mcf in 2003 (2002 - $3.79 per mcf). The increase in
natural gas pricing is due to the concerns around supply and the impact of
higher crude oil prices.

A comparison of the price received for the Company's North America production is
as follows:

<TABLE>
<CAPTION>

                                                                                      2004             2003            2002
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                <C>              <C>              <C>
Wellhead price(1)

 Light crude oil and NGLs (C$/bbl)                                                  $ 45.90          $ 37.59          $ 34.92

 Pelican Lake crude oil (C$/bbl)                                                    $ 32.12          $ 28.05          $ 27.56

 Primary heavy crude oil (C$/bbl)                                                   $ 28.99          $ 26.21          $ 27.06

 Thermal heavy crude oil (C$/bbl)                                                   $ 29.00          $ 25.55          $ 25.70

 Natural gas (C$/mcf)                                                               $  6.61          $  6.34          $  3.79
                                                                                    =======          =======          =======

</TABLE>


(1)  Including transportation costs and excluding risk management activities.

NORTH SEA

North Sea realized crude oil prices increased 22% to average $51.37 per bbl in
2004, up from $42.00 per bbl in 2003 (2002 - $40.32 per bbl) due to higher world
crude oil prices.

OFFSHORE WEST AFRICA

Offshore West Africa realized crude oil prices increased 34% to average $49.05
per bbl in 2004, up from $36.47 per bbl in 2003 (2002 - $40.10 per bbl) due to
higher world crude oil prices.


                                       43
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT

ANALYSIS OF CHANGES IN REVENUE, BEFORE ROYALTIES

<TABLE>
<CAPTION>
                                             Changes due to                                CHANGES DUE TO
                          --------------------------------------------------    -----------------------------------
($ millions)              2002    Volumes        Prices    Other      2003      VOLUMES    PRICES     OTHER    2004
-------------------------------------------------------------------------------------------------------------------
<S>                   <C>        <C>        <C>             <C>   <C>        <C>       <C>           <C>    <C>
NORTH AMERICA

Crude oil and NGLs     $ 1,854    $    55    $    44        $ -    $ 1,953    $   342   $   283       $ -    $ 2,578

Natural gas              1,865         56      1,147          -      3,068        207       126         -      3,401
                       -------    -------    -------        ---    -------    -------   -------       ---    -------
                         3,719        111      1,191          -      5,021        549       409         -      5,979
                       -------    -------    -------        ---    -------    -------   -------       ---    -------

NORTH SEA

Crude oil and NGLs         592        265         16          -        873        123       227         -      1,223

Natural gas                 28         19         33          -         80          5         9         -         94
                       -------    -------    -------        ---    -------    -------   -------       ---    -------

                           620        284         49          -        953        128       236         -      1,317
                       -------    -------    -------        ---    -------    -------   -------       ---    -------

OFFSHORE WEST AFRICA

Crude oil and NGLs         100         56        (15)         -        141         13        54         -        208

Natural gas                  2         13         (1)         -         14         (1)        1         -         14
                       -------    -------    -------        ---    -------    -------   -------       ---    -------
                           102         69        (16)         -        155         12        55         -        222
                       -------    -------    -------        ---    -------    -------   -------       ---    -------

SUBTOTAL

Crude oil and NGLs       2,546        376         45          -      2,967        478       564         -      4,009

Natural gas              1,895         88      1,179          -      3,162        211       136         -      3,509
                       -------    -------    -------        ---    -------    -------   -------       ---    -------

                         4,441        464      1,224          -      6,129        689       700         -      7,518

MIDSTREAM                   52          -          -          9         61          -         -         7         68

OTHER                        -          -          -          -          -          -         -         1          1

INTERSEGMENT               (34)         -          -         (1)       (35)         -         -        (5)       (40)
                       -------    -------    -------        ---    -------    -------   -------       ---    -------
ELIMINATIONS (1)

TOTAL                  $ 4,459    $   464    $ 1,224        $ 8    $ 6,155    $   689   $   700         3    $ 7,547
                       -------    -------    -------        ---    -------    -------   -------       ---    -------

</TABLE>

(1) Eliminates internal transportation and electricity charges.

Revenue rose 23% to $7,547 million in 2004, up from $6,155 million in 2003
(2002 - $4,459 million). In 2004, 20% of the Company's crude oil and natural gas
revenue was generated outside of North America, up from 18% in 2003 (2002 -
16%). North Sea accounted for 17% of revenue in 2004 and 16% in 2003 (2002 -
14%), and Offshore West Africa accounted for 3% of revenue in 2004 and 2% in
2003 (2002 - 2%).

The Company's production composition, before royalties, is as follows:

DAILY PRODUCTION, BEFORE ROYALTIES

<TABLE>
<CAPTION>

                                                                                            2004           2003           2002
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                     <C>            <C>            <C>
CRUDE OIL AND NGLS (bbl/d)

North America                                                                            206,225        174,895        169,675

North Sea                                                                                 64,706         56,869         38,876

Offshore West Africa                                                                      11,558         10,628          6,784
                                                                                         -------        -------        -------
                                                                                         282,489        242,392        215,335
                                                                                         -------        -------        -------

NATURAL GAS (mmcf/d)

North America                                                                              1,330          1,245          1,204

North Sea                                                                                     50             46             27

Offshore West Africa                                                                           8              8              1
                                                                                         -------        -------        -------
                                                                                           1,388          1,299          1,232
                                                                                         -------        -------        -------
TOTAL BARREL OF OIL EQUIVALENT (boe/d)                                                   513,835        458,814        420,722
                                                                                         -------        -------        -------

PRODUCT MIX

Light crude oil and NGLs                                                                      24%            25%            21%

Pelican Lake crude oil                                                                         4%             5%             7%

Primary heavy crude oil                                                                       19%            15%            14%

Thermal heavy crude oil                                                                        8%             8%             9%

Natural gas                                                                                   45%            47%            49%
                                                                                         -------        -------        -------
</TABLE>

                                       44
<PAGE>

                         2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS


 DAILY PRODUCTION, NET OF ROYALTIES

<TABLE>
<CAPTION>

                                                                                            2004           2003           2002
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                    <C>            <C>             <C>
CRUDE OIL AND NGLS (bbl/d)

North America                                                                            180,011        152,444        149,485

North Sea                                                                                 64,598         56,928         36,654

Offshore West Africa                                                                      11,221         10,314          6,554
                                                                                         -------        -------        -------

                                                                                         255,830        219,686        192,693
                                                                                         -------        -------        -------

NATURAL GAS (mmcf/d)

North America                                                                              1,048            976            949

North Sea                                                                                     50             46             27

Offshore West Africa                                                                           7              8              1
                                                                                         -------        -------        -------

                                                                                           1,105          1,030            977
                                                                                         -------        -------        -------

TOTAL BARREL OF OIL EQUIVALENT (boe/d)                                                   440,022        391,361        355,611
                                                                                         -------        -------        -------
</TABLE>

Daily production and per barrel statistics are presented throughout the MD&A on
a "before royalty" or "gross" basis. Production net of royalties is presented
above for information purposes only.

The Company's business approach is to maintain large project inventories and
production diversification among each of the commodities it produces; namely
natural gas, light crude oil and NGLs, Pelican Lake crude oil, primary heavy
crude oil and thermal heavy crude oil.

The Company achieved record levels of production on a barrel of oil equivalent
basis in 2004. Production before royalties on a barrel of oil equivalent basis
increased 12% to average 513,835 boe/d in 2004, up from 458,814 boe/d in 2003
(2002 - 420,722 boe/d). The production volumes increased as a result of the
Company's successful capital expenditure program and the acquisition of certain
resource properties in the Company's North America and North Sea segments. Total
crude oil and NGLs production before royalties increased 17% or 40,097 bbl/d to
average 282,489 bbl/d, up from 242,392 bbl/d in 2003 (2002 - 215,335 bbl/d).
Crude oil and NGLs production before royalties in 2004 increased from the
previous year in all segments and was in line with production guidance provided.
Natural gas production before royalties continues to represent the Company's
largest product offering, accounting for 45% of the Company's total production
in 2004 compared to 47% of total production in 2003 (2002 - 49%). Natural gas
production before royalties increased 7% or 89 mmcf/d to average 1,388 mmcf/d,
up from 1,299 mmcf/d in 2003 (2002 - 1,232 mmcf/d). Natural gas production was
in line with production guidance provided.

The Company expects annual production levels before royalties in 2005 to average
1,448 to 1,510 mmcf/d of natural gas and 307 to 335 mbbl/d of crude oil and
NGLs. First quarter 2005 production guidance before royalties is 1,400 to 1,482
mmcf/d of natural gas and 269 to 290 mbbl/d of crude oil and NGLs.

NORTH AMERICA

Crude oil and NGLs production before royalties in North America increased 18% or
31,330 bbl/d to average 206,225 bbl/d in 2004, up from 174,895 bbl/d in 2003
(2002 - 169,675 bbl/d) due to the development of the Primrose thermal crude oil
project and accretive acquisitions.

North American natural gas production before royalties in 2004 increased 7% or
85 mmcf/d to average 1,330 mmcf/d, up from 1,245 mmcf/d in 2003 (2002 - 1,204
mmcf/d). North American production of natural gas increased as a result of
organic growth and accretive property acquisitions. Production of natural gas
was impacted by the shut in of 11 mmcf/d of natural gas in the Athabasca
Wabiskaw-McMurray oil sands area effective July 1, 2004.

NORTH SEA

Crude oil production before royalties from the North Sea increased 14% or 7,837
bbl/d to average 64,706 bbl/d in 2004, up from 56,869 bbl/d in 2003 (2002 -
38,876 bbl/d). The increase in production was due to the ongoing drilling,
recompletion and waterflood optimization program at the Ninian and Murchison
Fields and the acquisition of light crude oil producing properties in the
Central North Sea in the third quarter of 2004. Crude oil production before
royalties in the fourth quarter was down primarily due to an unplanned extended
shutdown on the Ninian North Platform. The shutdown was required to repair a
power turbine used to drive water injection resulting in a loss of pressure to
the reservoir. Remedial work was completed in early 2005 and production is
recovering.

Natural gas production before royalties in the North Sea increased 9% or 4
mmcf/d to average 50 mmcf/d in 2004, up from 46 mmcf/d in 2003 (2002 - 27
mmcf/d). The increase in production was due to the acquisition of properties in
the Central North Sea in the third quarter of 2004 and the increased working
interests acquired in the Banff Field during 2003. The increase was partially
offset by the commencement of the natural gas reinjection program in the Banff
Field in the fourth quarter of 2004. Despite some delays and production
interruptions during commissioning, results to date are positive with full
production benefit expected to commence during the second quarter of 2005.
Natural gas production in the North Sea is expected to decline in 2005 due to
the natural gas reinjection program in the Banff Field.



                                       45
<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT

OFFSHORE WEST AFRICA

Offshore West Africa crude oil production before royalties for the year ended
December 31, 2004 increased 9% or 930 bbl/d to average 11,558 bbl/d, up from
10,628 bbl/d in 2003 (2002 - 6,784 bbl/d) due to the perforation of the upper
zone of the East Espoir Field in the third quarter of 2003 and the completion of
the fourth water injection well and two additional producing wells during 2003.

Natural gas production before royalties in Offshore West Africa remained
constant at 8 mmcf/d in 2004 and 2003 (2002 - 1 mmcf/d).

ROYALTIES

<TABLE>
<CAPTION>

                                                2004         2003           2002
---------------------------------------------------------------------------------
<S>                                        <C>         <C>             <C>
CRUDE OIL AND NGLs ($/bbl)

North America                               $    4.21   $    3.79       $    3.42

North Sea                                   $    0.08   $   (0.03)      $    2.30

Offshore West Africa                        $    1.43   $    1.08       $    1.35

Company average                             $    3.16   $    2.77       $    3.16

NATURAL GAS ($/mcf)

North America                               $    1.40   $    1.38       $    0.80

North Sea                                   $       -   $       -       $       -

Offshore West Africa                        $    0.15   $    0.13       $    0.15

Company average                             $    1.35   $    1.32       $    0.78

COMPANY AVERAGE ($/BOE)                     $    5.37   $    5.20       $    3.91

PERCENTAGE OF REVENUE(1)

Crude oil and NGLs                                 8%          9%             10%

Natural gas                                       21%         21%             21%

Boe                                               14%         15%             14%
</TABLE>


(1) Including transportation costs and excluding risk management activities.

NORTH AMERICA

Crude oil and NGLs royalties in North America increased to $4.21 per bbl, up
from $3.79 per bbl in 2003 (2002 - $3.42 per bbl) due to higher benchmark crude
oil prices.

Natural gas royalties in North America increased to $1.40 per mcf, up from $1.38
per mcf in 2003 (2002 - $0.80 per mcf). Natural gas royalties as a percentage of
revenue fluctuate as a result of fluctuations in natural gas prices and the
strong correlation of royalties to natural gas prices.



NORTH SEA

North Sea crude oil royalties increased to $0.08 per bbl, up from a recovery of
$(0.03) per bbl in 2003 (2002 - $2.30 per bbl).



North Sea government royalties on crude oil were eliminated effective January 1,
2003. The remaining North Sea royalty represents a gross overriding royalty on
the Ninian Field. In 2003, the Company received a refund of royalties previously
provided.

OFFSHORE WEST AFRICA

Offshore West Africa crude oil royalties increased to $1.43 per bbl, up from
$1.08 per bbl in 2003 (2002 - $1.35 per bbl) due to fluctuations in realized
crude oil prices. Offshore West Africa production is governed by the terms of
the Production Sharing Contract ("PSC"). Under the PSC, revenues are divided
into cost recovery revenue and profit revenue. Cost recovery revenue allows the
Company to recover the capital and operating costs carried by the Company on
behalf of the Government State Oil Company. These revenues are reported as sales
revenue. Profit revenue is allocated to the joint venture partners in accordance
with their respective equity interests, after a portion has been allocated to
the Government. The Government's share of revenue attributable to the Company's
equity interest is reported as either royalty expense or current income tax
expense in accordance with the PSC.


                                       46
<PAGE>
                         2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS

PRODUCTION EXPENSE

<TABLE>
<CAPTION>
                                   2004         2003         2002
-----------------------------------------------------------------
<S>                          <C>           <C>         <C>
CRUDE OIL AND NGLs ($/bbl)

North America                 $    8.94    $    9.14    $    6.73

North Sea                     $   14.03    $   14.07    $   15.06

Offshore West Africa          $    7.59    $    8.68    $   13.63

Company average               $   10.05    $   10.28    $    8.45

NATURAL GAS ($/mcf)

North America                 $    0.62    $    0.57    $    0.55

North Sea                     $    2.07    $    1.33    $    1.53

Offshore West Africa          $    1.33    $    1.39    $    1.81

Company average               $    0.67    $    0.60    $    0.57

COMPANY AVERAGE ($/BOE)       $    7.35    $    7.15    $    5.99
</TABLE>

Production expense increased to $7.35 per boe in 2004, up from $7.15 per boe in
2003 (2002 - $5.99 per boe). Crude oil and NGLs production expense decreased to
$10.05 per bbl in 2004, down from $10.28 per bbl in 2003 (2002 - $8.45 per bbl).
Natural gas production expense for the year 2004 increased to $0.67 per mcf, up
from $0.60 per mcf in 2003 (2002 - $0.57 per mcf).

NORTH AMERICA

North American crude oil and NGLs production expense decreased 2% to average
$8.94 per bbl, down from $9.14 per bbl in 2003 (2002 - $6.73 per bbl). The
decrease was primarily due to the impact of a lower steam oil ratio for the
Company's thermal heavy crude oil operations, resulting in a lower cost per
barrel for fuel used in the generation of steam.

North American natural gas production expense per mcf increased 9% to average
$0.62 per mcf, up from $0.57 per mcf in 2003 (2002 - $0.55 per mcf). The
increase is partly due to increased activity in the oil and gas sector in
reaction to higher commodity prices, which resulted in higher production
expense, especially as the labour market tightened, and partly due to increased
production in certain areas such as Northeast British Columbia where the Company
is incurring higher costs associated with third party processing and gathering.
In addition, the cost of steel products increased in 2004 due to increased
global demand.

NORTH SEA

North Sea crude oil production expense decreased in 2004 to $14.03 per bbl, down
from $14.07 per bbl in 2003 (2002 - $15.06 per bbl).

North Sea crude oil production expense varied on a per barrel basis due to the
timing of maintenance work and the changes in production volumes on a relatively
fixed cost base.

OFFSHORE WEST AFRICA

Offshore West Africa crude oil production expense decreased to $7.59 per bbl,
down from $8.68 per bbl in 2003 (2002 - $13.63 per bbl), resulting from
production increases in the Espoir Field. The Espoir Field commenced operations
in the first quarter of 2002.

Offshore West Africa crude oil production expenses are largely fixed in nature
and therefore fluctuate on a per barrel basis from the comparable periods due to
changes in production from the Espoir Field.

MIDSTREAM

<TABLE>
<CAPTION>
($ MILLIONS)                       2004      2003      2002
-----------------------------------------------------------
<S>                                <C>       <C>       <C>
Revenue                             $68       $61       $52

Production expense                   20       $15       $14

Midstream cash flow                  48       $46       $38

Depreciation                          7       $ 7       $ 8

Segment earnings before taxes       $41       $39       $30
</TABLE>


The Company's midstream assets consist of three crude oil pipeline systems and
an 84-megawatt cogeneration plant at Primrose where the Company has a 50%
working interest. Approximately 80% of the Company's heavy crude oil production
was transported to the international mainline liquid pipelines via the 100%
owned and operated ECHO Pipeline, the 62% owned and operated Pelican Lake
Pipeline and the 15% owned Cold Lake Pipeline. The midstream pipeline assets
allow the Company to transport its own production volumes at reduced costs
compared to other transportation alternatives as well as earn third party
revenue. This transportation control enhances the Company's ability to control
the full range of costs associated with the development and marketing of its
heavy crude oil.



                                       47
<PAGE>


MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT

Revenue from the midstream assets increased 11%  to $68 million, up from $61
million in 2003 (2002 - $52 million). The increase in revenue, operating cash
flow and segment earnings before taxes was due to the expansion of the ECHO
Pipeline. The expansion of the ECHO Pipeline was completed in October 2003 and
increased capacity to 72 mbbl/d from 58 mbbl/d.


DEPLETION, DEPRECIATION AND AMORTIZATION(2)

<TABLE>
<CAPTION>
($ millions, except per boe amounts)                                                      2004         2003(1)         2002(1)
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                <C>             <C>              <C>
North America                                                                       $    1,444      $    1,209       $   1,022

North Sea                                                                                  265      $      252       $     188

Offshore West Africa                                                                        53      $       41       $      80

Expense                                                                             $    1,762      $    1,502       $   1,290

  $/boe                                                                             $     9.37      $     8.96       $    8.40
                                                                                    ==========      ==========       =========
</TABLE>

(1)  Restated for changes in accounting policies (see consolidated financial
     statements note 2).

(2)  DD&A excludes depreciation on midstream assets.

Depletion, depreciation and amortization ("DD&A") increased in total and per boe
to $1,762 million or $9.37 per boe, up from $1,502 million or $8.96 per boe in
2003 (2002 - $1,290 million or $8.40 per boe). The increase in DD&A was due to
higher finding and development costs associated with natural gas exploration in
North America, the allocation of the acquisition costs associated with recent
acquisitions, the fair value of future abandonment costs associated with the
acquisition of additional properties in the North Sea, and higher costs to
develop the Company's proved undeveloped reserves. In 2003, DD&A included the
write-off of $12 million of costs associated with the Company's exploration
activity in offshore France. In 2002, DD&A included the write-off of $51 million
as a result of the Company's decision to exit from its interests in Block 19,
Angola, and from the Aje Field, Nigeria.



ASSET RETIREMENT OBLIGATION ACCRETION

<TABLE>
<CAPTION>
($ millions, except per boe amounts)                            2004            2003(1)     2002(1)
---------------------------------------------------------------------------------------------------
<S>                                                          <C>             <C>          <C>
North America                                                 $     28        $     26     $     20

North Sea                                                     $     22        $     36     $     48

Offshore West Africa                                          $      1        $      -     $      -

Expense                                                       $     51        $     62     $     68

  $/boe                                                       $   0.27        $   0.37     $   0.44
                                                              ========        ========     ========
</TABLE>


(1)  Restated for changes in accounting policies (see consolidated financial
     statements note 2).

Accretion expense is the increase in the carrying amount of the asset retirement
obligation due to the passage of time.

ADMINISTRATION EXPENSE

<TABLE>
<CAPTION>

($ millions, except per boe amounts)                                                   2004           2003            2002
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                               <C>               <C>             <C>
Gross cost                                                                         $       315       $    262        $    147

  $/boe                                                                            $      1.68       $   1.57        $   0.96

Net expense                                                                        $       115       $     87        $     61

  $/boe                                                                            $      0.61       $   0.52        $   0.40
                                                                                   ===========       ========        ========
</TABLE>

Gross administration expense increased to $1.68 per boe, up from $1.57 per boe
in 2003 (2002 - $0.96 per boe) mainly due to higher staffing levels associated
with the Company's expanding asset base and costs associated with the Horizon
Project. Gross administration expense also increased as a result of higher costs
related to the assumption of operatorship of certain fields in the North Sea in
2003. Net administration expense, after operator recoveries and capitalized
overhead relating to exploration and development in the North Sea and Offshore
West Africa as well as the Horizon Project, increased to $0.61 per boe in 2004,
up from $0.52 per boe in 2003 (2002 - $0.40 per boe).



                                       48
<PAGE>
                         2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS


STOCK-BASED COMPENSATION


<TABLE>
<CAPTION>
($ millions, except per boe amounts)                                                       2004            2003             2002
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                <C>                <C>               <C>
Stock option plan                                                                   $       249        $    200          $     -

Share bonus plan                                                                             10        $      -          $     -

Stock-based compensation expense                                                    $       259        $    200          $     -

  $/boe                                                                             $      1.37        $   1.20          $     -
                                                                                    ===========        ========          =======


</TABLE>

The Company's Stock Option Plan (the "Option Plan") provides current employees,
officers and directors (the "option holders") with the right to elect to receive
common shares or a direct cash payment in exchange for options surrendered. The
Option Plan balances the need for a long-term compensation program to retain
employees with reducing the impact of dilution on current Shareholders and the
reporting of the expense associated with stock options. Transparency of the cost
of the Option Plan is increased since changes in the fair value of outstanding
stock options are expensed. The cash payment feature provides option holders
with substantially the same benefits and allows them to realize the value of
their options through a simplified administration process.

The Company has recorded a liability at December 31, 2004 of $323 million
compared to $171 million at December 31, 2003 for expected cash settlements of
stock options based on the fair value of the outstanding stock options (the
difference between the exercise price of the stock options and the market price
of the Company's common shares). The liability is revalued to reflect changes in
the market price of the Company's common shares and the net change is recognized
in net earnings.

The stock-based compensation expense relating to the Company's Option Plan in
2004 is $249 million ($168 million after tax), up from $200 million ($136
million after tax) in 2003.

In 2004, the Company paid $80 million for stock options surrendered for cash
settlement compared to $31 million in 2003.

The Share Bonus Plan incorporates share ownership in the Company by its
employees without the granting of stock options or the dilution of current
Shareholders. Under the plan, a cash bonus may be awarded based on the Company's
and the employee's performance and subsequently used by a trustee to acquire
common shares of the Company. The common shares vest to the employee over a
three-year period provided the employee does not leave the employment of the
Company. If the employee leaves the employment of the Company, the unvested
common shares are forfeited under the terms of the plan. In 2004, the Company
recognized $10 million ($6 million after tax) of compensation expense under the
Share Bonus Plan.

INTEREST EXPENSE


<TABLE>
<CAPTION>
($ millions, except per boe amounts and interest rates)                                    2004         2003(1)    2002(1)
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                                <C>               <C>          <C>
Interest expense                                                                    $       189       $    201     $   203

  $/boe                                                                             $      1.01       $   1.20     $  1.26

Average effective interest rate                                                            5.2%           5.8%        5.5%
                                                                                           ===            ===         ===
</TABLE>

(1)  Restated for changes in accounting policies (see consolidated financial
     statements note 2).

Interest expense decreased to $189 million in 2004, down from $201 million in
2003 (2002 - $203 million) due mainly to a lower average effective interest rate
of 5.2%, down from 5.8% in 2003 (2002 - 5.5%). In addition, the strengthening
Canadian dollar reduced the Canadian equivalent interest expense on the
Company's US dollar denominated debt. The Company continues to benefit from the
lower short-term interest rates as its fixed-rate debt accounts for only 43% of
total debt outstanding after interest rates swaps (see note 12 to the
consolidated financial statements) as at December 31, 2004 (2003 - 32%, 2002 -
40%).

Interest expense was impacted by the Company prospectively adopting the Canadian
Institute of Chartered Accountants' ("CICA") Accounting Guideline 13, "Hedging
Relationships" and EIC 128, "Accounting for Trading, Speculative or Non-Hedging
Derivative Financial Instruments." As a result of the adoption of this
accounting guideline, $32 million of realized gains on certain of its fixed to
floating interest rate swaps are included in risk management activities in 2004
(2003 - $35 million, 2002 - $34 million). Interest expense decreased on a total
and boe basis in 2004 from 2003 mainly due to lower borrowing rates.




                                       49
<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT


RISK MANAGEMENT ACTIVITIES

On January 1, 2004, the Company prospectively adopted the CICA's Accounting
Guideline 13, "Hedging Relationships" and EIC 128, "Accounting for Trading,
Speculative or Non-Hedging Derivative Financial Instruments". Financial
instruments that do not qualify as hedges under the Guideline or are not
designated as hedges are recorded at fair value on the Company's consolidated
balance sheet, with subsequent changes in fair value recognized in net earnings.

The Company utilizes various financial instruments to manage its commodity
prices, foreign currency and interest rate exposures. These financial
instruments are not used for trading or speculative purposes.

The Company enters into commodity price contracts to manage anticipated sales of
crude oil and natural gas production in order to protect cash flow for capital
expenditure programs. The Company also enters into foreign currency denominated
financial instruments to manage future US dollar denominated crude oil and
natural gas sales. Gains or losses on these contracts are included in risk
management activities.

The Company enters into interest rate swap agreements to manage its fixed to
floating interest rate mix on long-term debt. The interest rate swap contracts
require the periodic exchange of payments without the exchange of the notional
principal amount on which the payments are based. Gains or losses on interest
rate swap contracts designated as hedges are included in interest expense. Gains
or losses on interest rate contracts not designated as hedges are included in
risk management activities.

The Company enters into cross currency swap agreements to manage its fixed to
floating interest rate mix on long-term debt. The cross currency swap contracts
require the periodic exchange of payments with the exchange at maturity of
notional principal amounts on which the payments are based. Gains or losses on
cross currency swap contracts designated as hedges are included in interest
expense.

Gains or losses on the termination of financial instruments that have been
accounted for as hedges are deferred under other long-term assets or liabilities
on the consolidated balance sheets and amortized into net earnings in the period
in which the underlying hedged transaction is recognized. In the event a
designated hedged item is sold, extinguished or matures prior to the termination
of the related derivative instrument, any unrealized gain or loss is recognized
in net earnings.

Adoption of this Guideline and EIC 128 had the following effects on the
Company's consolidated financial statements:


<TABLE>
<CAPTION>
($ millions)                                                                               2004            2003           2002
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                <C>                <C>            <C>
REALIZED LOSS (GAIN)

Crude oil and NGLs financial instruments                                            $       501        $     95       $    114

Natural gas financial instruments                                                             5              88              3

Interest rate swaps                                                                         (32)           (35)           (34)
                                                                                    -----------       ---------       --------
                                                                                    $       474        $    148        $    83
                                                                                    -----------       ---------       --------
UNREALIZED LOSS (GAIN)

Crude oil and NGLs financial instruments                                            $       (47)       $      -        $     -

Natural gas financial instruments                                                              -              -              -

Interest rate swaps                                                                           7               -              -
                                                                                    -----------       ---------       --------
                                                                                    $       (40)       $      -        $     -
                                                                                    -----------       ---------       --------
TOTAL                                                                               $       434        $    148        $    83
                                                                                    ===========        ========        =======

</TABLE>

The effect of the realized loss from crude oil and NGLs and natural gas
financial instruments was to reduce the Company's average realized prices as
follows:

<TABLE>
<CAPTION>
                                                                                           2004            2003           2002
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                <C>               <C>             <C>
Crude oil and NGLs($/bbl)                                                           $      4.85       $    1.07       $   1.46

Natural gas ($/mcf)                                                                 $      0.01       $    0.19       $   0.01
                                                                                    ===========       =========       ========
</TABLE>

The effect of the realized gain on interest rate swaps on the Company's interest
expense was:

<TABLE>
<CAPTION>
($ millions, except interest rates)                                                        2004         2003(1)        2002(1)
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                <C>               <C>              <C>
Interest expense as per the financial statements                                    $       189       $    201         $   203

Less: realized risk management gain                                                         (32)           (35)           (34)
                                                                                    ------------      ---------       --------
                                                                                    $       157        $    166       $    169
                                                                                    ===========       =========       ========

Average effective interest rate                                                             4.4%           4.8%           4.8%
                                                                                    ===========       =========       ========
</TABLE>

(1)  Restated for changes in accounting policies (see consolidated financial
     statements note 2).



                                       50
<PAGE>


                         2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS


FOREIGN EXCHANGE

<TABLE>
<CAPTION>
($ millions)                                                                               2004          2003(1)       2002(1)
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                <C>                <C>           <C>
Realized foreign exchange loss                                                      $         3        $     8       $       4

Unrealized foreign exchange gain                                                            (94)          (343)           (36)

Total                                                                               $       (91)       $  (335)      $    (32)
                                                                                    ===========        =======       ========

</TABLE>

(1)  Restated for changes in accounting policies (see consolidated financial
     statements note 2).

The majority of the unrealized foreign exchange gain is related to the
fluctuation of the Canadian dollar in relation to the US dollar. The Canadian
dollar ended the year 2004 at US$0.8308 compared to US$0.7738 at December 31,
2003 (December 31, 2002 - US$0.6331).

The majority of the Company's borrowings are denominated in US dollars. At
December 31, 2004, the Company's US dollar denominated debt amounted to US$2,969
million compared to US$2,045 million in 2003 (2002 - US$2,048 million). US
dollar denominated debt represented 77% of total debt outstanding at December
31, 2004 (2003 - 85%, 2002 - 77%). Due to the higher proportion of US dollar
denominated debt outstanding, the Company's net earnings are more sensitive to
fluctuations in the Canadian dollar.

In order to mitigate a portion of the volatility associated with the Canadian
dollar, the Company has designated certain US dollar denominated debt as a hedge
against its net investment in US dollar based self-sustaining foreign
operations. Accordingly, translation gains and losses on this US dollar
denominated debt are included in the foreign currency translation adjustment in
shareholders' equity in the consolidated balance sheets.

The Company's realized product prices are sensitive to currency exchange rates.
Recent increases in the value of the Canadian dollar in relation to the US
dollar had a negative impact on the Company's commodity prices realized (see
Sensitivity Analysis).



TAXES


<TABLE>
<CAPTION>
($ millions, except income tax rates)             2004        2003        2002
------------------------------------------------------------------------------
<S>                                             <C>         <C>         <C>
TAXES OTHER THAN INCOME TAX

Current                                          $ 210       $ 116       $  53

Deferred                                           (45)      $  (9)      $  10

Total                                            $ 165       $ 107       $  63

CURRENT INCOME TAX

North America - Current income tax               $  89       $  43       $   -

North America - Large Corporations Tax           $  11       $  16       $  21

North Sea                                        $   2       $  23       $ (19)

Offshore West Africa                             $  13       $  10       $   6

Other                                            $   1       $   -       $   -

Total                                            $ 116       $  92       $   8

FUTURE INCOME TAX (1)                            $ 474       $ 338       $ 375

EFFECTIVE INCOME TAX RATE (1)                     29.6%       23.5%       41.6%
                                                  ====        ====        ====
</TABLE>

(1)  Restated for changes in accounting policies (see consolidated financial
     statements note 2).

Taxes other than income tax consist of current and deferred petroleum revenue
tax ("PRT"), other international taxes and provincial capital taxes and
surcharges. PRT is charged on certain fields in the North Sea at the rate of 50%
of net operating income after certain deductions including abandonment
expenditures. Taxes other than income tax increased to $165 million or $0.88 per
boe in 2004, up from $107 million or $0.64 per boe in 2003 (2002 - $63 million
or $0.41 per boe). The increase in taxes other than income tax was mainly due to
the higher netback earned in the North Sea as a result of higher crude oil
prices and higher production levels. North Sea PRT accounts for $145 million or
$0.77 per boe in 2004 compared to $97 million or $0.58 per boe in 2003 (2002 -
$51 million or $0.33 per boe).

Taxable income from the conventional crude oil and natural gas business in
Canada is generated by partnerships and the related income taxes will be payable
in the following year. Current income taxes have been provided on the basis of
the corporate structure and available income tax deductions and will vary
depending upon the amount of capital expenditures incurred in Canada and the way
it is deployed. No current income tax provision was required for North America
in 2002.

The Company is liable for the payment of Federal Large Corporations Tax ("LCT").
LCT decreased to $11 million or $0.09 per boe from $16 million or $0.14 per boe
(2002 - $21 million or $0.11 per boe) as a result of the Company being taxable
and a partial offset available in the calculation of the Federal corporate
surtax. In addition, the LCT rate was reduced from 0.225% to 0.2% in 2004 as
part of the phased elimination of LCT over five years.




                                       51
<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT


It is anticipated that, based on the current availability of approximately $4.5
billion of tax pools in Canada at the end of 2004 and current commodity strip
prices, the Company will be cash taxable in Canada in 2005 in the amount of $200
million to $300 million.

Current income tax in the North Sea decreased to $2 million or $0.01 per boe,
down from $23 million or $0.14 per boe in 2003 (2002 - recovery of $19 million
or $0.13 per boe). The decrease in the current income tax expense was due to tax
pools acquired in the recent acquisition being immediately deductible. The North
Sea current income tax was also impacted by changes in the tax rules in the
North Sea. In 2002, a supplementary charge of 10% on profits from UK North Sea
crude oil and natural gas production was introduced. The North Sea supplementary
charge, which took effect April 17, 2002, is in addition to the corporate income
tax rate of 30% and excludes any deduction for financing costs. In addition, the
first year capital allowance rate for plant and machinery expenditures was
increased to 100% from the previous rate of 25%.

The Company's future income tax provision for 2004 increased to $474 million
($2.53 per boe), up from $338 million ($2.02 per boe) in 2003 (2002 - $375
million or $2.45 per boe). In 2004 the North America future income tax liability
was reduced by $66 million as a result of a reduction in the Alberta corporate
income tax rate (2003 - $31 million, 2002 - $21 million). In 2003, the Federal
Government introduced legislation to reduce the corporate income tax rate on
income from resource activities over a five-year period starting January 1,
2003, bringing the resource industry in line with the general corporate income
tax rate. As part of the corporate income tax rate reduction, the legislation
also provides for the elimination of the existing 25% resource allowance and the
introduction of a deduction for actual provincial and other crown royalties
paid. As a result of the Federal tax rate reductions, the future income tax
liability in North America was decreased by $247 million in 2003.

In 2002, the future income tax liability in the North Sea was increased by $34
million as a result of the introduction of a 10% supplementary charge on profits
from North Sea crude oil and natural gas production.

The following table shows the effect of non-recurring benefits on income taxes:



<TABLE>
<CAPTION>
($ millions, except income tax rates)                                                     2004             2003           2002
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                <C>                <C>            <C>
Income tax as reported

Current income tax                                                                  $       116        $     92       $      8

Future income tax expense(1)                                                        $       474        $    338       $    375
                                                                                    -----------        --------       --------
                                                                                    $       590        $    430       $    383

Alberta corporate tax rate reduction                                                $        66        $     31       $     21

Federal corporate tax rate reduction                                                $         -        $    247       $      -

UK supplementary tax on profits                                                     $         -        $      -       $    (34)
                                                                                    -----------        --------       --------
Total                                                                               $       656        $    708       $    370
                                                                                    ===========        ========       ========
Expected effective income tax rate                                                        32.9%           38.6%          40.2%
                                                                                    ===========        ========       ========

</TABLE>

(1)  Restated for changes in accounting policies (see consolidated financial
     statements note 2).

CAPITAL EXPENDITURES

<TABLE>
<CAPTION>
($ millions)                                         2004        2003       2002
--------------------------------------------------------------------------------
<S>                                                <C>         <C>       <C>
EXPENDITURES ON PROPERTY, PLANT AND EQUIPMENT

Net property acquisitions(1)                        $1,835        336      2,833

Land acquisition and retention                         120        154        114

Seismic evaluations                                     89         77         63

Well drilling, completion and equipping              1,394      1,194        626

Pipeline and production facilities                     821        522        292
                                                    ------      -----      -----
TOTAL NET RESERVE REPLACEMENT EXPENDITURES           4,259      2,283      3,928

Horizon Oil Sands Project                              291        152         68

Midstream                                               16         11         20

Abandonments                                            32         40         43

Head office                                             35         20         10
                                                    ------      -----      -----
TOTAL NET CAPITAL EXPENDITURES                      $4,633      2,506      4,069
                                                    ======      =====      =====

BY SEGMENT

North America                                       $3,355      1,769      3,420

North Sea                                              608        338        323

Offshore West Africa                                   296        176        185

Horizon Project                                        291        152         68

Midstream                                               16         11         20

Abandonments                                            32         40         43

Head office                                             35         20         10
                                                    ------      -----      -----
TOTAL                                               $4,633      2,506      4,069
                                                    ======      =====      =====
</TABLE>

(1)  Includes Business Combinations.



                                       52
<PAGE>

                         2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS

The Company's strategy is focused on building a diversified asset base that is
balanced between various products. The capital expenditures program continues to
reflect this strategy.

In 2004, capital expenditures were $4,633 million, including the acquisition of
Petrovera, compared to $2,506 million in 2003 (2002 - $4,069 million including
the acquisition of Rio Alto). The increase in capital expenditures was a result
of property acquisitions made in the North America and North Sea segments. The
Company continues to make significant progress on its larger, future-growth
projects while maintaining its focus on existing assets.

The Company's drilling activity decreased 19% with the drilling of 1,449 net
wells compared to 1,793 net wells drilled in 2003 (2002 - 900 net wells). The
Company drilled 689 net natural gas wells, down 11 % from the 777 net wells in
2003 (2002 - 162 net wells) and 328 net crude oil wells, down 28% from the 458
net wells in 2003 (2002 - 264 net wells). In addition, during 2004 the Company
drilled 336 net stratigraphic test/service wells primarily on the oil sands
leases in the Horizon Project and in the Northern Plains core region, down 24%
from the 440 net wells in 2003 (2002 - 447 net wells), and 96 net wells that
were dry and abandoned, down 19% from the 118 net wells in 2003 (2002 - 27 net
wells). The total number of wells drilled decreased from the prior year due to
the reallocation of capital resulting from the strategic acquisitions completed
in 2004. The Company achieved an overall success rate of 91%, excluding
stratigraphic test and service wells. These excellent results reflect the
disciplined approach that the Company takes in its exploitation and development
programs and the strength of its asset base.

NORTH AMERICA

North America accounted for 80% of the total capital expenditures in 2004
compared to 79% in 2003 (2002 - 86%).

In 2004, the Company drilled 689 net natural gas wells, including 163 net wells
in the Northern Plains core region, 221 net wells in the Southern Plains core
region targeting shallow gas, 138 net wells in Northwest Alberta and 167 net
wells in Northeast British Columbia. The Company also drilled 317 net crude oil
wells in 2004. These wells were concentrated in the Company's Northern Plains
crude oil region where 238 net heavy crude oil wells were drilled. Included in
this figure were 58 net high-pressure horizontal thermal crude oil wells that
were drilled and completed at Primrose as part of the 2004 development strategy
of the area.

As part of the development of the Company's heavy crude oil resources, the
Company is continuing with its Primrose thermal project, which includes the
Primrose North expansion project and drilling additional wells in the Primrose
South project to augment existing production. At Primrose South, production was
commissioned from the two new phases that commenced construction in 2003. The
Primrose North expansion continues to be on track and on budget with total
capital expenditures of approximately $300 million expected to be incurred,
leading to first oil of 30 mbbl/d in 2006.

Late in the third quarter, the Company filed a public disclosure document for
regulatory approval of its Primrose East project, a new facility located about
15 kilometres from its existing Primrose South steam plant and 25 kilometres
from its Wolf Lake central processing facility. Once completed, Primrose East
will be fully integrated with existing operations at Wolf Lake, Primrose South
and Primrose North. The Company currently expects to complete its regulatory
application by late 2005 with a regulatory decision expected in late 2006.

The Pelican Lake enhanced crude oil recovery project continues on track. The
waterflood has provided initial production increases as expected and has shown
positive waterflood response. The waterflood project will be expanded in 2005
and the Company plans to enhance the process by use of a polymer flood. The
polymer flood pilot will commence during 2005 with three injectors and five
producers.

In February 2004, the Company acquired certain resource properties in its
Northern Plains core region, collectively known as Petrovera, for $471 million.
Strategically, the acquisition fit with the Company's objective of dominating
its core regions and related infrastructure. The Company achieved cost
reductions through synergies with its existing facilities, including additional
throughput in its 100% owned ECHO Pipeline. The acquisition is included in the
results of operations commencing February 2004.

In the second quarter of 2004, the Company completed the acquisition of certain
resource properties located in Northeast British Columbia and Northwest Alberta
for $280 million. These properties include a further ownership interest in the
Ladyfern natural gas field. In addition, the Company acquired undeveloped pools
with significant natural gas potential in deeper zones and will add a new
exploration base in the Alberta Foothills.

In the fourth quarter of 2004, the Company completed the acquisition of certain
resource properties located in Alberta, British Columbia and Saskatchewan for
$703 million. The acquisition also includes over 510,000 net acres of unproven
land. The acquisition has been included in operations effective December 2004.
The acquisition fits the Company's strategy of dominating its core regions and
related infrastructure, as the vast majority of the properties acquired are
located within its core regions. The acquisition extends the Company's Northern
Plains core region into the light crude oil operating area of Dawson.

During the fourth quarter, the Company increased capital spending levels
directed toward natural gas drilling in an effort to reduce pressures of a tight
2005 winter drilling season by starting earlier. This effort included a detailed
and sequential drilling program that facilitated the procurement of better
drilling rigs and crews for the winter season, both of which are an integral
part of cost control. Certain portions of the drilling program were delayed due
to warmer than expected weather through mid-December; however, the Company still
expects to complete the majority of its plan.



                                       53
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT



Midstream
The Cold Lake Pipeline Limited Partnership, in which the Company has a 15%
working interest, completed the construction of new facilities to allow shipment
of up to 60,000 bbl/d of DilSynBit product. The new DilSynBit product will
include light synthetic oil as a blending component to dilute the heavy,
tar-like Cold Lake bitumen. The DilSynBit project will involve construction of
two 80,000 barrel storage tanks, pumping facilities and metering equipment on
the Cold Lake system.


Horizon
The third phase of the front-end engineering for the Horizon Project,
Engineering Design Specification ("EDS"), was completed and ongoing detail work
continues. The EDS provided sufficient definition for a lump sum inquiry for the
detailed Engineering, Procurement and Construction ("EPC") of the various
project components. The EDS also provided a detailed cost estimate and the basis
upon which management made the final recommendation to the Board of Directors
for sanction of the Horizon Project. The Company received regulatory approvals
from the Alberta Energy and Utilities Board as well as the Alberta Provincial
Cabinet and the Federal Cabinet in the first quarter of 2004. In the fourth
quarter, site preparation work continued as well as work on the construction of
onsite access roads, camps and the installation of deep underground facilities
such as electrical, natural gas, water and sewage. In addition, clarification of
bid documents occurred, resulting in the Company being able to obtain
approximately 68% of Phase 1 costs on a fixed cost basis. The current estimate
for Phase 1 construction costs now totals approximately $6.8 billion, including
a contingency reserve of $700 million. The total cost for all three phases of
the Horizon Project is now expected to be approximately $10.8 billion.

On February, 9, 2005, the Board of Directors unanimously authorized management
to proceed with Phase 1 of the Horizon Project.

North Sea
The Company continued with its planned program of infill drilling,
recompletions, workovers and waterflood optimizations. During 2004, the Company
commenced development drilling of the Lyell Field and the infill drilling
program at the Ninian Field continued. In addition, one production and one
injection well were completed at the Columba B terrace, and the Playfair well
was completed in the fourth quarter with a production rate of 5 mbbl/d and
sufficient associated natural gas to provide the Murchison Platform energy
needs, thereby reducing production costs.

During the third quarter of 2004, the Company acquired certain light crude oil
producing properties in the Central North Sea. The acquired properties comprise
operated interests in T-Block (Tiffany, Toni and Thelma Fields) and B-Block
(Balmoral, Stirling and Glamis Fields), together with associated production
facilities, including a fixed platform Floating Production Vessel ("FPV") and
adjacent exploration acreage. The Company equity interests in the producing
fields acquired are:

T-Block                 Tiffany, Toni and Thelma                100.00%
B-Block                 Balmoral                                 70.20%
                        Glamis                                   75.29%
                        Stirling                                 68.68%

The Company continued with the implementation of the natural gas reinjection
project at the Banff Field in the Central North Sea, with reinjection commencing
in November 2004. The project is expected to increase the overall reservoir
recovery of crude oil, but will result in reductions in natural gas volumes.

Offshore West Africa
Offshore West Africa capital expenditures include the development of the Baobab
Field where drilling is ongoing. To date, production testing on four producer
wells has met or exceeded expectations. In addition, the Floating Production,
Storage and Offtake Vessel ("FPSO") has been completed and is now moored on
location. During the fourth quarter of 2004, the Acajou North exploration well
was drilled to delineate the extent of the previously drilled Acajou discovery.
The result of this well did not yield sufficient hydrocarbons to merit a stand
alone development at Acajou. However, this field is being evaluated for future
tie-back to East Espoir. At Zaizou, an exploration well spudded late in the
fourth quarter was unsuccessful and the data obtained from this well is
currently being used to trace the pattern of oil migration in the area to help
identify future exploration targets.

The planned development of the nearby West Espoir Field was sanctioned by
partners with various components out for bid. The development is progressing on
schedule and is expected to commence production in mid 2006 through existing
FPSO facilities.

Finally, additional review of seismic and geological data on Block 16 located
offshore Angola indicates that while significant upside remains a possibility,
its risk level is outside the normal operating parameters of the Company. As a
result, the Company continues to evaluate alternatives for its holdings in the
Block.


                                       54
<PAGE>
                         2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS



Liquidity and capital resources

<TABLE>
<CAPTION>
($ millions, except ratios)                                         2004     2003(1)     2002(1)
---------------------------                                     --------    --------    --------
<S>                                                             <C>         <C>         <C>
Working capital deficit (2)                                     $   652     $   505     $    14
Long-term debt                                                  $ 3,538     $ 2,748     $ 4,200
                                                                -------     -------     -------
Shareholders' equity
Share capital                                                   $ 2,408     $ 2,353     $ 2,304
Retained earnings                                                 4,922       3,650       2,424
Foreign currency translation adjustment                              (6)          3          26
                                                                -------     -------     -------
Total                                                           $ 7,324     $ 6,006     $ 4,754
                                                                =======     =======     =======
Debt to cash flow (2)(3)                                            1.0x        0.9x        1.9x
Debt to EBITDA (2)(3)                                               0.9x        0.8x        1.7x
Debt to book capitalization (2)                                    33.8%       32.8%       47.1%
Debt to market capitalization (2)                                  21.4%       25.1%       40.3%
After tax return on average common shareholders' equity (3)        21.4%       25.6%       13.0%
After tax return on average capital employed (2)(3)                15.3%       17.1%        8.8%
</TABLE>

------------
(1)  Restated for changes in accounting policies (see consolidated financial
     statements note 2).
(2)  Includes current portion of long-term debt.
(3)  Based on trailing 12-month activity.


At December 31, 2004, the working capital deficit amounted to $652 million and
includes the current portion of other long-term liabilities of $260 million,
consisting of stock based compensation of $243 million and the mark to market
valuation of certain Risk Management financial derivative instruments of $17
million. The settlement of the stock-based compensation liability is dependant
upon the surrender of vested stock options for cash settlement by employees and
the value of the Company's share price at the time of surrender. The settlement
of the Risk Management financial derivative instruments is primarily dependant
upon the underlying crude oil and natural gas prices at the time of settlement
of the financial derivative instrument, as compared to the value at December 31,
2004.

The Company is committed to maintaining its strong financial position throughout
construction of the Horizon Project. In 2004, strong operational results and
strong commodity prices enabled the Company to maintain debt levels at 33.8% of
book capitalization. The Company has built the necessary financial capacity to
complete the Horizon Project while at the same time not compromising delivery of
low-risk conventional oil and natural gas growth opportunities. The financing of
the first phase of the Horizon Project development will be guided by the
competing principles of retaining as much direct ownership interest as possible
while maintaining a strong balance sheet. Existing proved development projects,
which have largely been funded prior to December 31, 2004, such as Baobab,
Primrose and West Espoir provide identified growth in production volumes in 2005
and 2006, and will generate incremental free cash flows during the period 2005
to 2008 with which to finance the Horizon Project.

In January 2005, the Board of Directors of the Company authorized an expanded
hedging program for the Company in an effort to reduce the risk of volatility in
commodity price markets and to underpin the Company's cash flow through the
Horizon Project construction period. This expanded program allows for up to 75%
of the near 12 months estimated production, up to 50% of the following 13 to 24
months estimated production and up to 25% of production expected in months 25 to
48 to be hedged. This revised hedging program allows the Company to have greater
stability in its free cash flow and enhances the Company's financial flexibility
during the Horizon Project construction years. The Company currently has collar
hedges covering approximately 71% and 45% of estimated 2005 and 2006 crude oil
production respectively. Similarly, approximately 67% and 35% of estimated 2005
and 2006 natural gas production has been hedged. The Company may also look to
offload capital commitments through the acceptance of complementary business
partners, or potentially, project joint venture partners.


                                       55
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT


Long-term debt
Long-term debt at December 31, 2004, increased $790 million from the prior year.
The debt to EBITDA ratio increased to 0.9x and the debt to book capitalization
increased to 33.8% compared to a debt to EBITDA ratio of 0.8x and a debt to book
capitalization of 32.8% in 2003. These ratios are currently below the Company's
guidelines for balance sheet management of debt to EBITDA of 1.5x to 2.0x and
debt to book capitalization of 40% to 45%.

At December 31, 2004, the Company had:

o    $2.8 billion of available unused bank credit facilities;

o    A fixed / floating interest rate mix of 43% / 57%;

o    77% of borrowings denominated in US dollars; and

o    85% of total long-term debt as non-bank based borrowing with a weighted
     average maturity of 16 years.


In December 2004, the Company issued US$350 million of debt securities maturing
December 2014, bearing interest at 4.90% and US$350 million of debt securities
maturing February 2035, bearing interest at 5.85%. Proceeds from the securities
issued were used to repay bankers' acceptances under the Company's bank credit
facilities. The Company has entered into certain interest rate swap contracts to
convert the fixed rate interest coupon into a floating interest rate on the
securities due December 2014.

The Company filed a short form prospectus in May 2003 that allows for the issue
of up to US$2 billion of debt securities in the United States until June 2005.
Currently the Company has US$1.3 billion remaining under the $2 billion shelf
prospectus. If issued, these securities will bear interest as determined at the
date of issuance. In addition, the Company maintains a shelf prospectus in
Canada for the offering of up to $1 billion of medium-term notes in Canada. If
issued, these securities will bear interest as determined at the date of
issuance.

Future offerings under the shelf prospectuses will provide flexibility to the
Company's debt investment base, extend maturities and provide balance in the
fixed to floating interest rate mix.

As at December 31, 2004, the Company had unsecured bank credit facilities of
$3,425 million compared to $1,925 million at the close of 2003 (2002 - $2,275
million).

In December 2004, the Company executed a $1,500 million, 5-year revolving credit
facility, with three, one-year extension options.

The ratings of the Company's debt securities and its relationships with
principal banks are extremely important to the Company as it continues to expand
and grow. Hence, the Company's management will continually undertake to maintain
a strong balance sheet and financial position. The Company's debt securities are
rated "Baa1" by Moody's Investor Services Inc., "BBB+" by Standard & Poors
Corporation and "BBB(high)" by Dominion Bond Rating Services Limited.

Share capital
Shareholders of the Company approved a subdivision or share split of its issued
and outstanding common shares on a two-for-one basis at the Company's Annual and
Special Meeting held on May 6, 2004.

The Company is authorized to issue an unlimited number of common shares. As at
December 31, 2004, there were 268,181,000 common shares outstanding. As at
February 18, 2005 there were 268,221,000 common shares outstanding. In addition,
the Company is authorized to issue 200,000 Class 1 preferred shares. There were
no preferred shares outstanding during these periods.

During 2004, the Company issued 1,591,000 common shares from the exercise of
stock options for proceeds of $24 million.

During 2003, the Company issued 5,381,000 common shares from the exercise of
stock options for proceeds of $89 million.

In 2002, the Company issued 20 million common shares at an attributed value of
$522 million as part of the consideration to acquire Rio Alto. A further
5,046,000 common shares were issued from the exercise of stock options
throughout 2002 for proceeds of $82 million.

In January 2005, the Company renewed its Normal Course Issuer Bid allowing it to
purchase up to 13,409,006 common shares or 5% of the Company's outstanding
common shares on the date of announcement, during the 12-month period beginning
January 24, 2005 and ending January 23, 2006.

As at December 31, 2004, the Company had purchased 873,400 common shares for a
total cost of $33 million at an average purchase price of $38.01 per common
share pursuant to a Normal Course Issuer Bid that has been in place since
January 24, 2004.


                                       56
<PAGE>
                         2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS



The Company declared dividends on common shares in the amount of $107 million or
$0.40 per common share in 2004, up from $81 million or $0.30 per common share in
2003 (2002 - $64 million, $0.25 per common share).

In February 2005, the Company's Board of Directors approved an increase in the
annual dividend paid by the Company to $0.45 per common share for 2005. The
12.5% increase recognizes the stability of the Company's cash flow and provides
a return to Shareholders. This is the fifth consecutive year in which the
Company has paid dividends and the fourth consecutive year of an increase in the
distribution paid to its Shareholders. In February 2004, the Company's Board of
Directors approved an increase in the annual dividend paid by the Company to
$0.40 per common share in 2004, up from the previous level of $0.30 per common
share.

Commitments and off balance sheet arrangements
In the normal course of business, the Company has entered into various
contractual arrangements and commitments that will have an impact on the
Company's future operations. These contractual obligations and commitments
relate primarily to debt repayments, operating leases relating to office space
and offshore production and storage vessels, firm commitments for gathering,
processing and transmission services. The following table summarizes the
Company's commitments as at December 31, 2004:

<TABLE>
<CAPTION>
($ millions)                              2005      2006      2007      2008      2009     Thereafter
------------                             ------    ------    ------    ------    ------    ----------
<S>                                      <C>       <C>       <C>       <C>       <C>         <C>
Natural gas transportation               $  194    $  147    $  100    $   78    $   37      $  168
Crude oil transportation and pipeline    $   11    $    9    $   11    $   12    $   13      $  154
Offshore equipment operating lease       $  110    $   48    $   48    $   48    $   48      $  184
Baobab Project                           $   99    $    -    $    -    $    -    $    -      $    -
Offshore drilling and other              $  125    $    8    $    -    $    -    $    -      $    -
Electricity                              $   26    $   28    $   20    $   13    $    8      $   34
Office lease                             $   21    $   21    $   22    $   23    $   24      $   30
Processing                               $    5    $    2    $    -    $    -    $    -      $    -
Horizon Project                          $   99    $    -    $    -    $    -    $    -      $    -
Long-term debt                           $  194    $    -    $  162    $   37    $   69      $2,713
</TABLE>


Subsequent event
On February 9, 2005, the Company's Board of Directors unanimously authorized the
Company to proceed with Phase 1 of the Horizon Oil Sands Project. The Horizon
Project is designed as a phased development and includes two components: the
mining of bitumen and an onsite upgrader. Phase 1 production is targeted to
begin at 110,000 bbl/d of 34 degree API light sweet, synthetic crude oil
("SCO"). Phase 2 would increase production to 155,000 bbl/d of SCO. Phase 3
would further increase production to 232,000 bbl/d of SCO. Total expected
capital costs for all three phases of development are estimated at $10.8
billion. Capital costs for the first phase of the Horizon Project are estimated
at $6.8 billion including a contingency reserve of $700 million, with $1.4
billion to be incurred in 2005, and $2.2 billion, $2.0 billion and $1.2 billion
to be incurred in 2006, 2007 and 2008, respectively.

Oil and natural gas reserves
Canadian Natural retains qualified independent reserve evaluators, Sproule
Associates Limited ("Sproule"), and Ryder Scott Company ("Ryder Scott"), to
evaluate 100% of the Company's proved and probable oil and natural gas reserves
and prepare Evaluation Reports on the Company's total reserves. Sproule
evaluated the North American assets and Ryder Scott evaluated the international
assets and a portion of the North American assets. Canadian Natural has been
granted an exemption from the National Instrument 51-101 - Standards of
Disclosure for Oil and Gas Activities ("NI 51-101") which prescribes the
standards for the preparation and disclosure of reserves and related information
for companies listed in Canada. This exemption allows the Company to substitute
United States Securities and Exchange Commission ("SEC") requirements for
certain disclosures required under NI 51-101. The primary difference between the
two standards is the additional requirement under NI 51-101 to disclose proved
and probable reserves and future net revenues using forecast prices and costs.
Canadian Natural has elected to disclose proved reserves using constant prices
and costs as mandated by the SEC and has also provided proved and probable
reserves under the same parameters as voluntary additional information. Another
difference between the two standards is in the definition of proved reserves;
however, as discussed in the Canadian Oil and Gas Evaluation Handbook ("COGEH"),
the standards which NI 51-101 employs, the difference in estimated proved
reserves based on constant pricing and costs between the two standards is not
material.

Canadian Natural has significant oil reserves that are considered heavy with a
gravity of less than 20 degrees. Heavy crude oil sells at a discount to light
crude oil using the benchmark West Texas Intermediate, which has an API gravity
of approximately 40 degrees, because it requires upgrading before it can be
processed by conventional refineries. There is a finite capacity for upgrading
in North America, which is often reached when heavy crude oil from other
countries enters the North American market. Heavy crude oil requires blending
with condensate or light synthetic crude oil ("diluent") in order for it to be
transported in a pipeline. During the winter, heavy crude oil requires a higher
proportion of diluent because of the cold temperatures. Heavy crude oil is also
processed into asphalt, which is typically in demand during the spring to fall
paving months.

As a result of these factors, prices for heavy crude oil are historically low in
December. Exacerbating this trend was reduced demand for heavy crude oil due to
refinery turnarounds and other operational issues. During 2004 the price of
heavy crude oil averaged US$30.40 per barrel but on December 31, 2004, the date
the Company's oil and natural gas reserves were evaluated, the calculated price
of Hardisty 12 degree API heavy crude oil was less. As a result, 30 mmbbl of net
proved heavy crude oil reserves did not produce positive cash flow and, in
accordance with SEC regulations, were debooked. Notwithstanding the economics at
December 31, 2004, the current price of heavy crude oil has returned to a price
sufficient to return the reserves subtracted by negative revision to the proved
reserve category.


                                       57
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT



Horizon oil sands mining reserves are not part of Canadian Natural's year-end
reserves disclosure. Horizon reserves were evaluated as at February 9, 2005.
Gilbert Laustsen Jung Associates Ltd. ("GLJ"), an independent qualified reserves
evaluator, was retained by the Reserves Committee of Canadian Natural's Board of
Directors to evaluate reserves associated with the Horizon Project incorporating
both the mining and upgrading projects. These reserves were evaluated under SEC
Industry Guide 7.

The Board of Directors of the Company has a Reserves Committee, which has met
with and carried out independent due diligence procedures with each of Sproule,
Ryder Scott and GLJ as to the Company's reserves.

Additional reserve disclosure is contained in the supplementary oil and gas
information and the Company's Annual Information Form.

Risks and uncertainties
The Company is exposed to several operational risks inherent in exploring,
developing, producing and marketing crude oil and natural gas. These inherent
risks include: economic risk of finding and producing reserves at a reasonable
cost; financial risk of marketing reserves at an acceptable price given current
market conditions; cost of capital risk associated with securing the needed
capital to carry out the Company's operations; risk of fluctuating foreign
exchange rates; risk of carrying out operations with minimal environmental
impact; risk of governmental policies, social instability or other political,
economic or diplomatic developments in its international operations; and credit
risk of non-payment for sales contracts or non-performance by counterparties to
contracts.

The Company uses a variety of means to help minimize these risks. The Company
maintains a comprehensive insurance program to reduce risk to an acceptable
level and to protect it against significant losses. Operational control is
enhanced by focusing efforts on large core regions with high working interests
and by assuming operatorship of all key facilities. Product mix is diversified,
ranging from the production of natural gas to the production of crude oil of
various grades. The Company believes this diversification reduces price risk
when compared with over-leverage to one commodity. Sales of crude oil and
natural gas are aimed at various markets to ensure that undue exposure to any
one market does not exist. Financial instruments are utilized to help ensure
targets are met and to manage commodity prices, foreign currency rates and
interest rate exposure. The Company minimizes credit risks by entering into
sales contracts and financial derivatives with only highly rated entities and
financial institutions. In addition, the Company reviews its exposure to
individual companies on a regular basis, and where appropriate ensures that
parental guarantees or letters of credit are in place to minimize the impact in
the event of default.

The Company's current position with respect to its financial instruments is
detailed in note 12 to the consolidated financial statements. The arrangements
and policies concerning the Company's financial instruments are under constant
review and may change depending upon the prevailing market conditions.

The Company's capital structure mix is also monitored on a continual basis to
ensure that it optimizes flexibility, minimizes cost and offers the greatest
opportunity for growth. This includes the determination of a reasonable level of
debt and any interest rate exposure risk that may exist.

The Company continues to employ an Environmental Management Plan (the "Plan") to
ensure the welfare of its employees, the communities in which it operates, and
the environment as a whole. Environmental protection is of fundamental
importance and is undertaken in accordance with guiding principles approved by
the Company's Board of Directors. A detailed copy of the Company's Plan is
presented to, and reviewed by, the Board of Directors annually. The Plan is
updated quarterly at the Directors' meetings.

Environment
The Company's environmental management plan and operating guidelines focus on
minimizing the impact of field operations while meeting regulatory requirements
and corporate standards. The Company, as part of this plan, has implemented a
proactive program that includes:

o    An annual internal environmental compliance audit and inspection program of
     the Company's operating facilities;

o    An aggressive suspended well inspection program to support future
     development or eventual abandonment;

o    Appropriate reclamation and decommissioning standards for wells and
     facilities ready for abandonment;

o    An effective surface reclamation program;

o    A progressive due diligence program related to groundwater monitoring;

o    A rigorous program related to preventing and reclaiming spill sites;

o    A solution gas reduction and conservation program; and

o    A program to replace the majority of fresh water for steaming with brackish
     water.

The Company has also established stringent operating standards in four areas:

o    Using water-based, environmentally friendly drilling muds whenever
     possible;

o    Implementing cost effective ways of reducing greenhouse natural gas
     emissions per unit of production;


                                       58
<PAGE>
2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS



o    Exercising care with respect to all waste produced through effective waste
     management plans; and

o    Minimizing produced water volumes onshore and offshore through
     cost-effective measures.

In 2004, the Company's capital expenditures included $32 million for abandonment
expenditures, down from $40 million in 2003 (2002 - $43 million).

Estimated future site restoration liability

<TABLE>
<CAPTION>
($ millions)                                                   2004        2003
------------                                                -------     -------
<S>                                                         <C>         <C>
North America                                               $ 1,776     $ 1,491
North Sea                                                     1,263         764
Offshore West Africa                                             24          26
                                                            -------     -------
                                                              3,063       2,281
North Sea PRT recovery                                         (601)       (331)
                                                            -------     -------
                                                            $ 2,462     $ 1,950
                                                            =======     =======
</TABLE>

The estimate of the future site restoration liability is based on estimates of
future costs to abandon and restore the wells, production facilities and
offshore production platforms. There are numerous factors that affect these
costs including such things as the number of wells drilled, well depth and the
specific environmental legislation. The estimated costs are based on engineering
estimates using current costs and technology in accordance with present
legislation and industry practice. It is important to note that the future
abandonment costs to be incurred by the Company in the North Sea will result in
an estimated recovery of PRT of $601 million (2003 - $331 million, 2002 - $305
million), as abandonment costs are an allowable deduction in determining PRT and
may be carried back to reclaim PRT previously paid. The PRT recovery reduces the
net abandonment liability of the Company to $2,462 million (2003 - $1,950
million, 2002 - $1,681 million). The Company's strategy in the North Sea
consists of developing commercial hubs around its core operated properties with
the goal of increasing production, lowering costs and extending the economic
lives of its production facilities, thereby delaying the eventual abandonment
dates.

Kyoto Protocol
In December 2002, the Canadian Federal Government ratified the Kyoto Protocol
("Kyoto"). The Company continues to work with departments of the Federal and
Provincial governments as legislation and regulatory mechanisms to address the
issue of climate change develop. The Federal Government has addressed the
uncertainty around the ratification and implementation of Kyoto by providing the
oil and gas sector with limits on the cost for large industrial emitters until
2012. For long-term, capital intensive investments, such as the Horizon Project,
it is essential for the Company to understand the cost implications associated
with the climate change policies beyond 2012. To address these concerns, the
Federal Government outlined eight principles that would guide them in its
negotiations and policies for the post 2012 years. On the basis of these
principles, the Company continued to work on the development plan of the Horizon
Project. Accordingly, the Company will continue to develop strategies that will
enable it to deal with the risks and opportunities associated with new climate
change policies. In addition, the Company will work with relevant parties to
ensure that new policies encourage innovation, energy efficiency, targeted
research and development while not impacting Canada's competitive position.

Critical accounting estimates
The preparation of financial statements requires Management to make judgements,
assumptions and estimates in the application of generally accepted accounting
principles that have a significant impact on the financial results of the
Company. Actual results could differ from those estimates. A comprehensive
discussion of the Company's significant accounting policies is contained in note
1 to the consolidated financial statements. The following is a discussion of the
accounting estimates that are critical in determining the Company's financial
results.

Full cost accounting
The Company follows the full cost method of accounting for oil and natural gas
properties and equipment as prescribed by the CICA. Accordingly, all costs
relating to the exploration for and development of oil and natural gas reserves
are capitalized and accumulated in country-by-country cost centres. The
capitalized costs and future capital costs related to each cost centre from
which there is production are depleted on the unit-of-production method based on
the estimated proved reserves of that country. The carrying amount of oil and
natural gas properties in each cost centre may not exceed their recoverable
amount ("the ceiling test"). The recoverable amount is calculated as the
undiscounted cash flow using proved reserves and estimated future prices and
costs. If the carrying amount of a cost centre exceeds its recoverable amount,
then an impairment loss equal to the amount by which the carrying amount of the
properties exceeds their fair value is charged against net earnings. Fair value
is calculated as the cash flow from those properties using proved and probable
reserves and expected future prices and costs, discounted at a risk-free
interest rate. Proceeds on disposal of properties are ordinarily deducted from
such costs without recognition of profit or loss except where such disposal
constitutes a significant portion of the Company's reserves in that country.

The alternate acceptable method of accounting for oil and natural gas properties
and equipment is the successful efforts method. A major difference in applying
the successful efforts method is that exploratory dry holes and geological and
geophysical exploration costs would be charged against net earnings in the year
incurred rather than being capitalized to property, plant and equipment. In
addition, under this method cost centres are defined based on reserve pools
rather than by country.


                                       59
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT



Oil and natural gas reserves
The Company retains qualified independent reserves evaluators to evaluate the
Company's proved and probable oil and natural gas reserves. In 2004, 100% of the
Company's reserves were evaluated by qualified independent reserves evaluators.

The estimation of reserves involves the exercise of judgement. Forecasts are
based on engineering data, future prices, expected future rates of production
and the timing of future capital expenditures, all of which are subject to many
uncertainties and interpretations. The Company expects that over time its
reserve estimates will be revised upward or downward based on updated
information such as the results of future drilling, testing and production
levels. Reserve estimates can have a significant impact on net earnings, as they
are a key component in the calculation of depletion, depreciation and
amortization. A revision to the reserve estimate could result in a higher or
lower DD&A charge to net earnings. Downward revisions to reserve estimates could
also result in a write-down of oil and natural gas property, plant and equipment
carrying amounts under the ceiling test.

Asset retirement obligation
The fair value of asset retirement obligations related to long-term assets are
recognized as a liability in the period in which they are incurred. Retirement
costs equal to the fair value of the asset retirement obligations are
capitalized as part of the cost of associated capital assets and are are
amortized to expense through depletion over the life of the asset. The fair
value of the asset retirement obligation is estimated by discounting the
expected future cash flows to settle the asset retirement obligation at the
Company's credit-adjusted risk-free interest rate. In subsequent periods, the
asset retirement obligation is adjusted for the passage of time and for any
changes in the amount or timing of the underlying future cash flows. Differences
between actual and estimated costs to settle the asset retirement obligation,
timing of cash flows to settle the obligation and future inflation rates could
result in gains or losses on the settlement of the asset retirement obligations.

Risk management activities
Financial instruments that do not qualify as hedges under Accounting Guideline
13 or are not designated as hedges are recorded at fair value on the Company's
consolidated balance sheet, with subsequent changes in fair value recognized in
net earnings.

The Company utilizes various financial instruments to manage its commodity
prices, foreign currency and interest rate exposures. These financial
instruments are not used for trading purposes.

The Company enters into commodity price contracts to manage anticipated sales of
crude oil and natural gas production in order to protect cash flow for capital
expenditure programs. The Company also enters into foreign currency denominated
financial instruments to manage future US dollar denominated crude oil and
natural gas sales. Gains or losses on these contracts are included in risk
management activities.

The Company enters into interest rate swap agreements to manage its fixed to
floating interest rate mix on long-term debt. The interest rate swap contracts
require the periodic exchange of payments without the exchange of the notional
principle amount on which the payments are based. Gains or losses on interest
rate swap contracts designated as hedges are included in interest expense. Gains
or losses on interest rate contracts not designated as hedges are included in
risk management activities.

The Company enters into cross currency swap agreements to manage its currency
exposure on long-term debt. The cross currency swap contracts require the
periodic exchange of payments with the exchange at maturity of notional
principal amounts on which the payments are based. Gains or losses on cross
currency swap contracts designated as hedges are included in interest expense.

Gains or losses on the termination of financial instruments that have been
accounted for as hedges are deferred under non-current assets or liabilities on
the consolidated balance sheets and amortized into net earnings in the period in
which the underlying hedged transaction is recognized. In the event a designated
hedged item is sold, extinguished or matures prior to the termination of the
related derivative instrument, any unrealized gain or loss is recognized in net
earnings.

Purchase price allocations
The costs of corporate and asset acquisitions are allocated to the acquired
assets and liabilities based on their fair value at the time of acquisition. The
determination of fair value requires Management to make assumptions and
estimates regarding future events. The allocation process is inherently
subjective and impacts the amount assigned to individually identifiable assets
and liabilities. As a result, the purchase price allocation impacts the
Company's reported assets and liabilities and future net earnings due to the
impact on future DD&A expense and impairment tests.

Production sharing contractual arrangements
The Company's operations outside of North America and the North Sea are governed
by production sharing contracts ("PSC"). Under the PSC, the Company and its
working interest partners typically bear all the risks and costs for
exploration, development and production. In exchange, if exploration is
successful, the Company is given the opportunity to recover its investment and
production expenses from the sale of crude oil and natural gas production ("cost
oil"). The Company is also entitled to a share of the excess of what is required
to recover the Company's investment and production expenses ("profit oil"), the
allocation of which varies from contract to contract. Together the cost oil and
profit oil represent the Company's entitlement. The Company records production,
sales and reserves based on its working interest ownership. The PSC stipulates
that income taxes are to be paid out of the respective national oil company
share of production. The difference between the Company's working interest
ownership and its annual entitlement is accounted for either a royalty expense
or current income tax expense in accordance with the PSC.


                                       60
<PAGE>
                         2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS



New accounting standards

Full cost accounting
Effective January 1, 2004, the Company prospectively adopted the CICA's
Accounting Guideline 16 "Oil and Gas Accounting - Full Cost". The Guideline
modifies the ceiling test, which limits the aggregate capitalized costs that may
be carried forward to future periods. Specific new guidance was provided on
several issues, including the frequency of conducting cost centre impairment
tests, the testing for cost centre recoverability and the method of determining
fair value. The Guideline recommends that cost centre impairment tests should be
conducted at each annual balance sheet date. Recovery of costs is tested by
comparing the carrying amount of the oil and natural gas assets to their
recoverable amount calculated as the undiscounted cash flows from those assets
using proved reserves and expected future prices and costs. If the carrying
amount exceeds the recoverable amount, then impairment should be recognized on
the amount by which the carrying amount of the assets exceeds the fair value of
the assets, calculated as the present value of expected cash flows using proved
and probable reserves and expected future prices and costs. The adoption of this
standard had no effect on the Company's consolidated financial statements for
the year ended December 31, 2004.

Asset retirement obligations
Effective January 1, 2004, the Company retroactively adopted the CICA's Section
3110, "Asset Retirement Obligations". The Section requires the recognition of a
liability for the fair value of the asset retirement obligation related to
long-term assets. Retirement costs equal to the fair value of the asset
retirement obligation are capitalized as part of the cost of the associated
capital asset and amortized to expense through depletion over the life of the
asset. In subsequent periods, the asset retirement obligation is adjusted for
the passage of time and for any changes in the amount or timing of the
underlying future cash flows. This new standard was adopted retroactively and
prior period comparative balances have been restated. Adoption of the standard
had the following effects on the Company's consolidated balance sheet as at
December 31, 2003:

<TABLE>
<CAPTION>
($ millions)                                                   December 31, 2003
------------                                                   -----------------
<S>                                                                      <C>
Consolidated balance sheet
   Increase property, plant and equipment                                $  445
   Decrease future site restoration liability                            $ (447)
   Increase asset retirement obligation                                  $  897
   Increase future income tax liability                                  $    3
   Decrease foreign currency translation adjustment                      $  (14)
   Increase retained earnings                                            $    6
</TABLE>


Adoption of the standard had the following effects on the Company's consolidated
statements of earnings and retained earnings:

<TABLE>
<CAPTION>
                                                                  Year Ended
($ millions)                                            2004            2003        2002
------------                                          ------          ------      ------
<S>                                                   <C>             <C>         <C>
Increase opening retained earnings                    $    6          $   10      $   41
Decrease depletion, depreciation and amortization     $ (120)         $  (56)     $  (16)
Increase asset retirement obligation accretion        $   51          $   62      $   68
Increase (decrease) future income tax expense         $   28          $   (2)     $  (21)
</TABLE>


The Company's pipelines and co-generation plant have indeterminant lives and
therefore the fair values of the related asset retirement obligations cannot be
reasonably determined. The asset retirement obligation for these assets will be
recorded in the year in which the lives of the assets are determinable.

Risk management activities
On January 1, 2004, the Company prospectively adopted the CICA's Accounting
Guideline 13, "Hedging Relationships" and EIC 128, "Accounting for Trading,
Speculative or Non-Hedging Derivative Financial Instruments". Guideline 13 and
EIC 128 require that financial instruments that are not designated as hedges be
recorded on the Company's consolidated balance sheet at fair value on the date
thereof, with subsequent changes in fair value recorded in earnings on a
quarterly reporting basis. Adoption of Guideline 13 and EIC 128 resulted in the
Company recognizing an unrealized mark-to-market gain of $40 million ($27
million, net of tax) for the year ended December 31, 2004 relating to its
financial instruments. The unrealized gain assumes that all unsettled derivative
financial instruments were settled on December 31, 2004 and were valued based on
market conditions existing at that point in time. As a result of the adoption of
this standard, the Company expects the volatility in its net earnings to
increase, which is directly attributable to the corresponding volatility in
crude oil and natural gas prices and the unsettled derivative financial
instruments. The Guideline had the following effects on the Company's
consolidated financial statements:

<TABLE>
<CAPTION>
($ millions)                                                     January 1, 2004
------------                                                     ---------------
<S>                                                                         <C>
Consolidated balance sheet
   Increase derivative financial instruments asset                          $ 40
   Increase deferred revenue                                                $ 40
</TABLE>

                                       61
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT



Preferred Securities
Effective December 31, 2004, the Company early adopted changes to the CICA's
Section 3860, "Financial Instruments - Presentation and Disclosure" that relate
to contractual obligations that may be settled by delivery of the Company's
common shares. Under the new rules, these obligations must be classified as
liabilities on the Company's consolidated balance sheets. Previously, these
obligations were classified as equity. These changes have been adopted
retroactively and prior periods have been restated. Adoption of the changes had
the following effects on the Company's consolidated financial statements:

<TABLE>
<CAPTION>
($ millions)                                                  2004       2003       2002
------------                                                ------     ------     ------
<S>                                                         <C>        <C>        <C>
Increase long-term debt                                     $   96     $  103     $  126
Decrease preferred securities                               $  (96)    $ (103)    $ (126)
Increase interest expense                                   $    9     $    9     $   10
Increase foreign exchange gain                              $    7     $   23     $    1
(Decrease) increase future income tax expense               $   (1)    $    1     $   (4)
Decrease dividend on preferred securities, net of tax       $   (5)    $   (5)    $   (6)
Decrease revaluation of preferred securities, net of tax    $   (4)    $  (18)    $   (1)
</TABLE>


Impairment of long-lived assets
Effective January 1, 2004, the Company prospectively adopted the CICA's Section
3063 "Impairment of Long-lived Assets". The Section establishes standards for
the recognition, measurement and disclosure of the impairment of long-lived
assets. The Section addresses when impairment should be recognized and how to
measure the amount of impairment. An impairment loss is recognized when the
carrying amount of a long-lived asset exceeds its fair value calculated as the
sum of the undiscounted cash flows expected to result from its use and eventual
disposition. An impairment loss is measured as the amount by which the
long-lived assets' carrying amount exceeds its fair value. Adoption of the
Section had no effect on the Company's consolidated financial statements for the
year ended December 31, 2004.

Variable interest entities ("VIE's")
Effective January 1, 2004, the Company retroactively adopted the CICA's
Accounting Guideline 15, "Consolidation of Variable Interest Entities" without
restating prior periods. The Guideline requires the Company to identify VIE's in
which they have an interest, determine whether they are the primary beneficiary
of such entities and, if so, consolidate them. The primary beneficiary is the
enterprise that will absorb or receive the majority of the VIE's expected
losses, expected residual returns, or both. A VIE is an entity where (1) its
equity investment at risk is insufficient to permit the entity to finance its
activities without additional subordinated support from others, (2) the equity
investors lack either voting control, an obligation to absorb expected losses or
the right to receive expected residual returns, and (3) it does not meet
specified exemption criteria. The adoption of this Guideline had no impact on
the Company's consolidated financial statements.

Financial instruments
In January 2005, the CICA issued Section 3855 "Financial Instruments -
Recognition and Measurement". This Section prescribes when a financial asset,
financial liability, or non-financial derivative is to be recognized on the
balance sheet and at what amount - sometimes using fair value; other times using
cost-based measures. This Section also specifies how financial instruments gains
and losses are to be presented. This Section applies to interim and annual
financial statements relating to fiscal years beginning on or after October 31,
2006. Earlier adoption is permitted only as of the beginning of a fiscal year
ending on or after December 31, 2004. The Company plans to adopt this Section on
January 1, 2007. Transitional provisions for this Section are complex and vary
based on the type of financial instruments under consideration. The effect on
the Company's consolidated financial statements cannot be reasonably determined
at this time.

Hedges
In January 2005, the CICA issued Section 3865 "Hedges". This Section expands on
existing Accounting Guideline 13, "Hedging Relationships", and Section 1650
"Foreign Currency Translation", by specifying how hedge accounting is applied
and what disclosures are necessary when it is applied. This Section applies to
interim and annual financial statements relating to fiscal years beginning on or
after October 31, 2006. Earlier adoption is permitted only as of the beginning
of a fiscal year ending on or after December 31, 2004. The Company plans to
adopt this Section on January 1, 2007. Retroactive application of this Section
is not permitted. The effect on the Company's consolidated financial statements
cannot be reasonably determined at this time.

Comprehensive Income
In January 2005, the CICA issued Section 1530 "Comprehensive Income". This
Section introduces new standards for reporting and display of comprehensive
income. Comprehensive income is the change in equity (net assets) of a company
during a reporting period from transactions and other events and circumstances
from non-owner sources. It includes all changes in equity during a period except
those resulting from investments by owners and distributions to owners. This
Section applies to interim and annual financial statements relating to fiscal
years beginning on or after October 31, 2006. Earlier adoption is permitted only
as of the beginning of a fiscal year ending on or after December 31, 2004. The
Company plans to adopt this Section on January 1, 2007. Financial statements of
prior periods are required to be restated for certain comprehensive income
items. In addition, a company is encouraged, but not required to present
reclassification adjustments, in comparative financial statements provided for
earlier periods. The effect on the Company's consolidated financial statements
cannot be reasonably determined at this time.


                                       62
<PAGE>
                         2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS



Equity
In January 2005, the CICA issued Section 3251 "Equity". This Section replaces
Section 3250 "Surplus". It establishes standards for the presentation of equity
and changes in equity during a reporting period. This Section applies to interim
and annual financial statements relating to fiscal years beginning on or after
October 31, 2006. Earlier adoption is permitted only as of the beginning of a
fiscal year ending on or after December 31, 2004. The Company plans to adopt
this Section on January 1, 2007. Financial statements of prior periods are
required to be restated for certain specified adjustments. For all other items,
comparative financial statements are presented are not restated, but an
adjustment to the opening balance of accumulated other comprehensive income may
be required. In addition, a company is encouraged, but not required to present
reclassification adjustments, in comparative financial statements provided for
earlier periods. The effect on the Company's consolidated financial statements
cannot be reasonably determined at this time.

Outlook
The Company continues its strategy of maintaining a large portfolio of varied
projects, which enables the Company over an extended period of time to provide
consistent growth in production and high shareholder returns. Annual budgets are
developed, scrutinized throughout the year and changed if necessary in the
context of project returns, product pricing expectations, and balance in project
risk and time horizons. The Company maintains a high ownership level and
operatorship level in all of its properties and can therefore control the
nature, timing and extent of capital expenditures in each of its project areas.

The Company expects production levels in 2005 to average 1,448 to 1,510 mmcf/d
of natural gas and 307,000 to 335,000 bbl/d of crude oil and NGLs. First quarter
2005 production guidance for natural gas is 1,400 to 1,482 mmcf/d of natural gas
and 269,000 to 290,000 bbl/d of crude oil and NGLs.

The budgeted capital expenditures in 2005 are currently expected to be as
follows:

<TABLE>
<CAPTION>
($ millions)                                                         2005 Budget
------------                                                         -----------
<S>                                                                      <C>
North America natural gas                                                $ 1,350
North America crude oil and NGLs                                             910
North Sea crude oil and NGLs                                                 420
Offshore West Africa crude oil and NGLs                                      400
Property acquisitions and midstream                                           50
                                                                         -------
                                                                           3,130
Horizon Oil Sands Project                                                  1,372
                                                                         -------
Total                                                                    $ 4,502
                                                                         =======
</TABLE>


North America natural gas
In 2005, the Company expects to drill approximately 1,033 net natural gas wells,
690 net crude oil wells and 199 stratigraphic test/service wells. The 2005 North
American natural gas program will be highlighted by expanded drilling programs
in the Northwest Alberta and Northeast British Columbia core regions as shown
below:

<TABLE>
<CAPTION>
(number of wells)                                                    2005 Budget
-----------------                                                    -----------
<S>                                                                        <C>
Northeast British Columbia                                                   240
Northwest Alberta                                                            194
Northern Plains                                                              205
Southern Plains                                                              394
                                                                           -----
Total                                                                      1,033
                                                                           =====
</TABLE>


Drilling in 2005 reflects higher activity levels targeting the shallow Notikewin
zone in Northeast British Columbia as well as increased Cardium drilling in
Northwest Alberta. Drilling of shallow gas and coal bed methane wells will
increase in the Southern Plains core region. Conventional drilling will also
increase in the Northern Plains core region. During 2005, approximately 90 wells
targeting deep natural gas are budgeted, including nine in the Foothills area.
The Foothills area drilling increases reflect both increased focus on the area
as well as new drilling targets identified on assets acquired during the first
half of 2004.


                                       63
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT



North America crude oil and NGLs
The 2005 drilling program consists of:

<TABLE>
<CAPTION>
(number of wells)                                                    2005 Budget
-----------------                                                    -----------
<S>                                                                        <C>
Conventional heavy crude oil                                                 398
Thermal heavy crude oil                                                      105
Light crude oil                                                              101
Pelican Lake crude oil                                                        67
                                                                           -----
Total                                                                        671
                                                                           =====
</TABLE>


The 2005 drilling program consists of 398 conventional heavy crude oil wells,
105 thermal heavy crude oil wells, 101 light crude oil wells and 67 Pelican Lake
crude oil wells. The Company continues the disciplined development of its heavy
crude oil resources. Conventional heavy crude oil drilling will increase,
reflecting favourable crude oil prices as well as new opportunities identified
in the property acquisitions made during 2004. Due to the nature of heavy crude
oil production patterns, where production volumes ramp up during the first
months of production, much of the production resulting from the expanded drill
program will not be realized until late 2005.

In 2005, the Company expects to continue its Primrose thermal crude oil
expansion plans. The two new phases that commenced production in mid 2004
significantly enhance the economics of this project and are a positive indicator
for future pads that will be drilled. Production from this project is subject to
the cycling of steam injection and crude oil production and is expected to
remain at similar levels to the 2004 production.

The Pelican Lake waterflood test program continues and will be expanded to
additional lands in the area. The Company will also be piloting the use of
polymer flood on a portion of the field in an effort to further enhance field
recoveries.

As a result of the above activities, North America 2005 crude oil and NGLs
production is expected to increase slightly from 2004 levels.

Based upon the capital expenditure budget, the Company expects to incur Canadian
current income tax expense in 2005 of $200 to $300 million.

The Horizon Oil Sands Project
The Horizon Project is designed as a phased development and includes two
components: the mining of bitumen and an onsite upgrader. Phase 1 production is
planned to begin at 110,000 bbl/d of 34 degree API light, sweet synthetic crude
oil ("SCO"). Phase 2 will increase production to 155,000 bbl/d of SCO. Phase 3
will further increase production to 232,000 bbl/d of SCO. The phased approach
provides the Company with improved cost and project controls including labour
and materials management, and directionally mitigates the effects of growth on
local infrastructure.

Total expected capital costs for all three phases of the development are
estimated at $10.8 billion. Capital costs for Phase 1 of the Horizon Project are
estimated at $6.8 billion including a contingency reserve of $700 million with
$1.4 billion to be incurred in 2005, and $2.2 billion, $2.0 billion and $1.2
billion to be incurred in 2006, 2007 and 2008, respectively.

Extensive front end design and the high degree of project definition have
enabled the Company to obtain approximately 68% of Phase 1 costs on a fixed
price basis. The high degree of up front project engineering and pre-planning
will also reduce the risks associated with scope changes.

On February, 9, 2005, the Board of Directors unanimously authorized management
to proceed with Phase 1 of the Horizon Project.

North Sea
The capital budget in 2005 for the North Sea is $420 million and includes the
drilling of approximately 12 net platform wells while continuing the successful
workover and recompletion program. The Company will also conduct a mobile
drilling program in which four subsea wells will be drilled at Nadia, Thelma
(two) and Columba E. These wells, with the exception of Nadia, are step-out
development wells on existing proved properties. The Nadia well is an
exploration of new terraces in the Ninian/Columba area. Average crude oil
production is expected to increase from 2004 production levels; however, natural
gas volumes will be lower as natural gas sales at the Banff Field are diverted
to reinjection.

Offshore West Africa
In 2005, the capital budget for Offshore West Africa is set at $400 million, of
which the Company anticipates $210 million to be spent on finalizing the
development of the Baobab Field in Cote d'Ivoire and $100 million to be spent
developing the West Espoir Field. The remainder will be spent on various
exploration activities.

At East Espoir, an additional four wells are scheduled for drilling in early
2005 as a result of additional testing and evaluation that revealed a larger
quantity of crude oil in place, based upon reservoir studies and production
history to date. These new producer wells will effectively exploit this
additional potential and could increase the recoverable resources from the
field.

Average production is expected to increase as a result of the commissioning of
the Baobab Field in mid 2005 as well as a result of the drilling of additional
producer wells in East Espoir.

Sensitivity analysis
The following table is indicative of the annualized sensitivities of cash flow
and net earnings from changes in certain key variables. The analysis is based on
business conditions and production volumes during the fourth quarter of 2004.
Each separate item in the sensitivity analysis shows the effect of an increase
in that variable only; all other variables are held constant.


                                       64
<PAGE>
                         2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS



<TABLE>
<CAPTION>
                                         Cash flow from     Cash flow from
                                             operations         operations   Net earnings       Net earnings
                                           ($ millions)   ($/share, basic)   ($ millions)   ($/share, basic)
                                           ------------   ----------------   ------------   ----------------
<S>                                          <C>              <C>              <C>              <C>
Price changes
Crude oil - WTI US$1.00/bbl (1)
   Excluding financial derivatives           $       96       $       0.36     $       68       $       0.25
   Including financial derivatives           $       80       $       0.30     $       43       $       0.16
Natural gas - AECO C$0.10/mcf (1)
   Excluding financial derivatives           $       37       $       0.14     $       24       $       0.09
   Including financial derivatives           $       33       $       0.12     $       21       $       0.08
Volume changes
Crude oil - 10,000 bbl/d                     $       73       $       0.27     $       34       $       0.13
Natural gas - 10 mmcf/d                      $       18       $       0.07     $        7       $       0.03
Foreign currency rate change
$0.01 change in C$ in relation to US$ (1)
   Excluding financial derivatives           $       56       $       0.21     $       12       $       0.05
   Including financial derivatives           $  55 - 58       $0.21 - 0.22     $  12 - 13       $0.04 - 0.05
Interest rate change - 1%                    $       13       $       0.05     $       13       $       0.05
</TABLE>

------------
(1)  For details of financial instruments in place, see consolidated financial
     statements note 12.


Daily production by segment, before royalties

<TABLE>
<CAPTION>
                                           Q1         Q2         Q3         Q4       2004       2003       2002
                                      -------    -------    -------    -------    -------    -------    -------
<S>                                   <C>        <C>        <C>        <C>        <C>        <C>        <C>
Crude oil and NGLs (bbl/d)
North America                         192,151    203,741    214,336    214,493    206,225    174,895    169,675
North Sea                              57,099     60,105     71,517     69,971     64,706     56,869     38,876
Offshore West Africa                   12,036     11,552     11,409     11,240     11,558     10,628      6,784
                                      -------    -------    -------    -------    -------    -------    -------
Total                                 261,286    275,398    297,262    295,704    282,489    242,392    215,335
                                      =======    =======    =======    =======    =======    =======    =======
Natural gas (mmcf/d)
North America                           1,230      1,389      1,336      1,365      1,330      1,245      1,204
North Sea                                  54         55         53         40         50         46         27
Offshore West Africa                       10          8          7          5          8          8          1
                                      -------    -------    -------    -------    -------    -------    -------
Total                                   1,294      1,452      1,396      1,410      1,388      1,299      1,232
                                      =======    =======    =======    =======    =======    =======    =======

Barrels of oil equivalent (boe/d)
North America                         397,194    435,238    436,986    442,072    427,936    382,315    370,337
North Sea                              66,127     69,175     80,393     76,560     73,093     64,469     43,391
Offshore West Africa                   13,623     12,930     12,567     12,113     12,806     12,030      6,994
                                      -------    -------    -------    -------    -------    -------    -------
Total                                 476,944    517,343    529,946    530,745    513,835    458,814    420,722
                                      =======    =======    =======    =======    =======    =======    =======
</TABLE>


Per unit results

<TABLE>
<CAPTION>
                                           Q1         Q2         Q3         Q4       2004       2003       2002
                                      -------    -------    -------    -------    -------    -------    -------
<S>                                   <C>        <C>        <C>        <C>        <C>        <C>        <C>
Crude oil and NGLs ($/bbl)
Sales price (1)                       $ 34.21    $ 36.72    $ 43.50    $ 36.92    $ 37.99    $ 32.66    $ 31.22
Royalties                                2.91       3.15       3.59       2.95       3.16       2.77       3.16
Production expense                       9.58       9.92      10.21      10.41      10.05      10.28       8.45
                                      -------    -------    -------    -------    -------    -------    -------
Netback                               $ 21.72    $ 23.65    $ 29.70    $ 23.56    $ 24.78    $ 19.61    $ 19.61
                                      =======    =======    =======    =======    =======    =======    =======
Natural gas ($/mcf)
Sales price (1)                       $  6.31    $  6.64    $  6.24    $  6.77    $  6.50    $  6.21    $  3.77
Royalties                                1.27       1.38       1.39       1.34       1.35       1.32       0.78
Production expense                       0.65       0.66       0.71       0.68       0.67       0.60       0.57
                                      -------    -------    -------    -------    -------    -------    -------
Netback                               $  4.39    $  4.60    $  4.14    $  4.75    $  4.48    $  4.29    $  2.42
                                      =======    =======    =======    =======    =======    =======    =======
Barrels of oil equivalent ($/boe)
Sales price (1)                       $ 35.88    $ 38.20    $ 40.92    $ 38.51    $ 38.45    $ 34.84    $ 27.02
Royalties                                5.03       5.55       5.68       5.21       5.37       5.20       3.91
Production expense                       7.02       7.12       7.59       7.61       7.35       7.15       5.99
                                      -------    -------    -------    -------    -------    -------    -------
Netback                               $ 23.83    $ 25.53    $ 27.65    $ 25.69    $ 25.73    $ 22.49    $ 17.12
                                      =======    =======    =======    =======    =======    =======    =======
</TABLE>
------------
(1)  Including transportation costs and excluding risk management activities.


                                       65
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT



Netback analysis

<TABLE>
<CAPTION>
($/boe, except daily production)                     2004         2003         2002
                                                 --------     --------     --------
<S>                                              <C>          <C>          <C>
Daily production, before royalties (boe/d)        513,835      458,814      420,722
Sales price (1)                                  $  38.45     $  34.84     $  27.02
Royalties                                            5.37         5.20         3.91
Production expense                                   7.35         7.15         5.99
                                                 --------     --------     --------
Netback                                             25.73        22.49        17.12
Midstream contribution                              (0.26)       (0.28)       (0.25)
Administration                                       0.61         0.52         0.40
Share bonus plan                                     0.05            -            -
Interest                                             1.01         1.20         1.26
Realized risk management activities loss             2.52         1.09         0.54
Realized foreign exchange loss                       0.02         0.05         0.02
Taxes other than income tax - current                1.12         0.69         0.35
Current income tax - North America                   0.47         0.14            -
Current income tax - Large Corporations Tax          0.05         0.06         0.14
Current income tax - North Sea                       0.01         0.26        (0.13)
Current income tax - Offshore West Africa            0.07         0.09         0.04
Current income tax - other                           0.01          -              -
                                                 --------     --------     --------
Cash flow                                        $  20.05     $  18.67     $  14.75
                                                 ========     ========     ========
</TABLE>
------------
(1)  Including transportation costs and excluding risk management activities.


Quarterly financial information

<TABLE>
<CAPTION>
($ millions, except per share amounts)         Q1          Q2          Q3          Q4       Total
                                          -------     -------     -------     -------     -------
<S>                                       <C>         <C>         <C>         <C>         <C>
2004
Revenue                                   $ 1,638     $ 1,865     $ 2,075     $ 1,969     $ 7,547
Net earnings                              $   258     $   259     $   311     $   577     $ 1,405
Per common share - basic                  $  0.96     $  0.97     $  1.16     $  2.15     $  5.24
                 - diluted                $  0.96     $  0.97     $  1.13     $  2.13     $  5.20
Cash flow from operations                 $   848     $   930     $ 1,041     $   950     $ 3,769
Per common share - basic                  $  3.16     $  3.47     $  3.88     $  3.54     $ 14.06
                 - diluted                $  3.14     $  3.47     $  3.85     $  3.52     $ 13.98

2003
                                          $ 1,840     $ 1,502     $ 1,454     $ 1,359     $ 6,155
Net earnings (1)                          $   427     $   525     $   201     $   250     $ 1,403
Per common share - basic (1)(2)           $  1.60     $  1.96     $  0.75     $  0.93     $  5.23
                 - diluted (1)(2)         $  1.52     $  1.89     $  0.74     $  0.91     $  5.06
Cash flow from operations                 $   906     $   762     $   758     $   734     $ 3,160
Per common share - basic (2)              $  3.38     $  2.84     $  2.81     $  2.74     $ 11.77
                 - diluted (2)            $  3.27     $  2.79     $  2.78     $  2.71     $ 11.53
</TABLE>
------------
(1)  Restated for changes in accounting policies (see consolidated financial
     statements note 2).

(2)  Restated to reflect two-for-one share split in May 2004.


                                       66
<PAGE>
                         2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS



The following discussion highlights some of the more significant factors that
impacted the net earnings in the eight most recently completed quarters.

In the first quarter of 2004, the Company acquired certain resource properties,
collectively known as Petrovera, in its Northern Plains core region.

In the second quarter of 2004, the Company completed the acquisition of certain
resource properties located in Northeast British Columbia and Northwest Alberta.
These properties include further ownership in the Ladyfern natural gas field.

In the third quarter of 2004, the Company acquired certain light crude oil
producing properties in the Central North Sea. The acquired properties comprise
operated interests in T-Block (Tiffany, Toni and Thelma Fields) and B-Block
(Balmoral, Stirling and Glamis Fields).

In the fourth quarter of 2004, the Company completed the acquisition of certain
resource properties located in Alberta, British Columbia and Saskatchewan. The
acquisition extends the Company's Northern Plains core region into the light
crude oil operating area of Dawson. The Company issued US$350 million of debt
securities maturing 2014, bearing interest at 4.90% and US$350 million of debt
securities maturing 2035, bearing interest at 5.85%.

In the second quarter of 2003, the Canadian Government introduced several income
tax changes, including rate reductions, for the resource industry. In addition,
the Province of Alberta reduced corporate income tax rates. As a result of these
changes, the future income tax liability was decreased by $247 million. Also, in
the second quarter of 2003, the Company modified its employee stock option plan
to provide for a cash payment option. A charge of $72 million after taxes ($105
million before taxes) was recognized to represent the mark-to-market liability
of the plan for all earned options as at June 30, 2003.


Trading and share statistics

<TABLE>
<CAPTION>
                                                                                              2004           2003
                                         Q1            Q2            Q3            Q4        Total          Total
                                  ---------     ---------     ---------     ---------     --------      ---------
<S>                               <C>           <C>           <C>           <C>           <C>           <C>
TSX-C$
Trading volume (thousands)           69,449        80,934        65,017        87,612       303,012       295,351
Share price ($/share)
   High                           $   38.25     $   40.85     $   51.04     $   55.15      $  55.15     $   33.61
   Low                            $   31.91     $   35.08     $   39.75     $   45.80      $  31.91     $   22.60
   Close                          $   36.35     $   40.05     $   50.50     $   51.25      $  51.25     $   32.69
Market capitalization at
   December 31 ($ millions)                                                                $ 13,744     $   8,742

Shares outstanding (thousands)                                                              268,181       267,463
-----------------------------------------------------------------------------------------------------------------
NYSE - US$
Trading volume (thousands)           11,775        16,418        13,255        21,286        62,734        23,458
Share price ($/share)
   High                           $   28.94     $   30.54     $   40.31     $   44.74     $   44.74     $   25.70
   Low                            $   23.88     $   25.88     $   29.72     $   37.12     $   23.88     $   14.63
   Close                          $   27.82     $   29.90     $   39.83     $   42.77     $   42.77     $   25.22
Market capitalization at
   December 31 ($ millions)                                                               $  11,470     $   6,745
Shares outstanding (thousands)                                                              268,181       267,463
</TABLE>


                                       67
<PAGE>
CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT



Management's Report

The accompanying consolidated financial statements and all information in the
annual report are the responsibility of management. The consolidated financial
statements have been prepared by management in accordance with the accounting
policies in the notes to the consolidated financial statements. Where necessary,
management has made informed judgements and estimates in accounting for
transactions which were not complete at the balance sheet date. In the opinion
of management, the financial statements have been prepared in accordance with
Canadian generally accepted accounting principles appropriate in the
circumstances. The financial information elsewhere in the annual report has been
reviewed to ensure consistency with that in the consolidated financial
statements.

Management maintains appropriate systems of internal control. Policies and
procedures are designed to give reasonable assurance that transactions are
appropriately authorized, assets are safeguarded from loss or unauthorized use
and financial records are properly maintained to provide reliable information
for preparation of financial statements.

PricewaterhouseCoopers LLP, an independent firm of Chartered Accountants, has
been engaged, as approved by a vote of the shareholders at the Company's most
recent Annual General Meeting, to examine the consolidated financial statements
in accordance with generally accepted auditing standards in Canada and provide
an independent professional opinion. Their report is presented with the
consolidated financial statements.

The Board of Directors (the "Board") is responsible for ensuring that management
fulfills its responsibilities for financial reporting and internal controls. The
Board exercises this responsibility through the Audit Committee of the Board.
This committee, which is comprised of non-management directors, meets with
management and the external auditors to satisfy itself that management
responsibilities are properly discharged and to review the consolidated
financial statements before they are presented to the Board for approval. The
consolidated financial statements have been approved by the Board on the
recommendation of the Audit Committee.



/s/ John G. Langille      /s/ Douglas A. Proll        /s/ Randall S. Davis
--------------------      ----------------------      -------------------------
JOHN G. LANGILLE CA       DOUGLAS A. PROLL CA         RANDALL S. DAVIS CA
President & Director      Senior Vice President,      Vice President, Financial
                          Finance                     Accounting & Controls
February 18, 2005



Auditors' Report

To the Shareholders of Canadian Natural Resources Limited,

We have audited the consolidated balance sheets of Canadian Natural Resources
Limited as at December 31, 2004 and 2003 and the consolidated statements of
earnings, retained earnings and cash flows for each of the years in the three
year period ended December 31, 2004. These consolidated financial statements are
the responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audits.

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

In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the Company as at December 31, 2004
and 2003 and the results of its operations and its cash flows for each of the
years in the three year period ended December 31, 2004 in accordance with
Canadian generally accepted accounting principles.



/s/ PricewaterhouseCoopers LLP
---------------------------------
Chartered Accountants                                   Calgary, Alberta, Canada
                                                        February 18, 2005


Comments by Auditor for U.S. readers on Canada-U.S. Reporting Differences

In the United States, reporting standards for auditors require the addition of
an explanatory paragraph (following the opinion paragraph) when there is a
change in accounting principles that has a material effect on the comparability
of the Company's consolidated financial statements, such as the change described
in Note 2 to the consolidated financial statements. Our report to the
shareholders dated February 18, 2005 is expressed in accordance with Canadian
reporting standards which do not require a reference to such a change in
accounting principles in the Auditors' report when the change is properly
accounted for and adequately disclosed in the consolidated financial statements.


/s/ PricewaterhouseCoopers LLP
---------------------------------
Chartered Accountants                                   Calgary, Alberta, Canada
                                                        February 18, 2005



                                       68