UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549
                                   FORM 10-K/A
                                 AMENDMENT NO. 1

                ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
                       THE SECURITIES EXCHANGE ACT OF 1934

                      FOR THE YEAR ENDED DECEMBER 31, 2003

                          COMMISSION FILE NUMBER 1-6702


                                   NEXEN INC.


                      Incorporated under the Laws of Canada

                                   98-6000202
                      (I.R.S. Employer Identification No.)

                              801 - 7th Avenue S.W.
                        Calgary, Alberta, Canada T2P 3P7
                           Telephone - (403) 699-4000
                           Web site - www.nexeninc.com

           SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:


          Title Exchange                                 Registered On
          --------------                                 -------------
       Common shares, no par value               The New York Stock Exchange
                                                 The Toronto Stock Exchange
       Subordinated Securities, due 2043         The New York Stock Exchange
                                                 The Toronto Stock Exchange


     SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:    None.

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months, and (2) has been subject to such filing requirements
for the past 90 days.

                        Yes    [X]           No  [_]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).

                        Yes    [X]           No  [_]

On June 30, 2003, the aggregate market value of the voting shares held by
non-affiliates of the registrant was approximately Cdn $4.2 billion based on the
Toronto Stock Exchange closing price on that date. On January 31, 2004, there
were 126,738,410 common shares issued and outstanding.

<PAGE>

                                EXPLANATORY NOTE

This Amendment No. 1 on Form 10-K/A (this "Amendment") amends the Annual Report
on Form 10-K for the year ended December 31, 2003 filed on February 20, 2004
(the "Original Filing"). Nexen Inc. (the "Company") has filed this Amendment to
incorporate textual changes in the Executive Summary of 2003 Results section of
Item 7, Management's Discussion and Analysis of Financial Condition and Results
of Operations. Specifically, the changes provide additional information
regarding our finding and development costs and reserves replacement costs as
requested by the Securities and Exchange Commission.

This Amendment has no effect on the Balance Sheet, Statement of Income, and
Statement of Changes in Stockholders' Equity, and more specifically, does not
affect net income, earnings per share, total cash flows, current assets, total
assets, current liabilities, total stockholders' equity or other information as
presented in the Original Filing.

Other information contained herein has not been updated. Therefore, this
Amendment should be read together with other documents that the Company has
filed with the Securities and Exchange Commission subsequent to the filing of
the Original Filing. Information in such reports and documents updates and
supersedes certain information contained in this Amendment. The filing of this
Amendment shall not be deemed an admission that the Original Filing, when made,
included any known, untrue statement of material fact or knowingly omitted to
state a material fact necessary to make a statement not misleading.



<PAGE>

                                TABLE OF CONTENTS

                                                                            PAGE
  PART II
  Item 7.    Management's Discussion and Analysis of Financial Condition
                  and Results of Operations....................................3
  PART IV

  Item 15.   Exhibits, Financial Statement Schedules and Reports on Form 8-K..37


UNLESS WE INDICATE OTHERWISE, ALL DOLLAR AMOUNTS ($) ARE IN CANADIAN DOLLARS,
AND OIL AND GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES ARE PRESENTED
ON A WORKING INTEREST BEFORE-ROYALTIES BASIS. WHERE APPROPRIATE, INFORMATION ON
AN AFTER-ROYALTIES BASIS IS PROVIDED IN TABULAR FORMAT.

<TABLE>
<CAPTION>
Below is a list of terms specific to the oil and gas industry. They are used
throughout the Form 10-K.

<S>                                               <C>
/d            =   per day                         mboe       =   thousand barrels of oil equivalent
bbl           =   barrel                          mmboe      =   million barrels of oil equivalent
mbbls         =   thousand barrels                mcf        =   thousand cubic feet
mmbbls        =   million barrels                 mmcf       =   million cubic feet
mmbtu         =   million British thermal units   bcf        =   billion cubic feet
km            =   kilometre                       WTI        =   West Texas Intermediate
                                                  NGL        =   natural gas liquid
</TABLE>

Oil equivalents are used to convert quantities of natural gas with crude oil by
expressing them in a common unit. To calculate equivalents, we use 1 bbl = 6 mcf
of natural gas.

The noon-day Canadian to US dollar exchange rates for Cdn $1.00, as reported by
the Bank of Canada, were:

(US$)                         DECEMBER 31      AVERAGE        HIGH        LOW
-------------------------------------------------------------------------------
1999                               0.6929       0.6730      0.6929     0.6537
2000                               0.6666       0.6733      0.6973     0.6413
2001                               0.6279       0.6458      0.6695     0.6241
2002                               0.6331       0.6369      0.6618     0.6199
2003                               0.7738       0.7135      0.7738     0.6350

On January 31, 2004, the noon-day exchange rate was US$0.7539 for Cdn $1.00.

Electronic copies of our filings with the Securities and Exchange Commission
(SEC) and the Ontario Securities Commission (OSC) (from November 8, 2002 onward)
are available, free of charge, on our website (www.nexeninc.com). Filings prior
to November 8, 2002 are available free of charge, upon request, by contacting
our investor relations department at (403) 699-5931. As soon as reasonably
practicable, our filings are made available on our website once they are
electronically filed with the SEC or the OSC. Alternatively, the SEC and the OSC
each maintain a website (www.sec.gov and www.sedar.com) that contain our
reports, proxy and information statements and other published information that
have been filed or furnished with the SEC and the OSC.


                                       1
<PAGE>

                                     PART II


ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
         RESULTS OF OPERATIONS


                                TABLE OF CONTENTS

                                                                            PAGE
Executive Summary of 2003 Results..............................................3
Capital Investment.............................................................6
       2003 Capital............................................................7
       2004 Estimated Capital..................................................8
Financial Results
       Year to Year Change in Net Income......................................10
       Oil and Gas
               Production  ...................................................11
               Commodity Prices...............................................13
               Operating Costs................................................15
               Depreciation, Depletion and Amortization.......................16
               Exploration Expense............................................17
       Oil and Gas Marketing..................................................17
       Chemicals .............................................................20
       Corporate Expenses.....................................................21
Outlook for 2004..............................................................22
Liquidity.....................................................................23
Contingencies.................................................................27
Business Risk Management......................................................28
Market Risk Management........................................................31
Critical Accounting Estimates.................................................33
New Accounting Pronouncements.................................................35


THE FOLLOWING SHOULD BE READ IN CONJUNCTION WITH THE CONSOLIDATED FINANCIAL
STATEMENTS INCLUDED IN THIS REPORT. THE CONSOLIDATED FINANCIAL STATEMENTS HAVE
BEEN PREPARED IN ACCORDANCE WITH GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (GAAP)
IN CANADA. THE IMPACT OF THE SIGNIFICANT DIFFERENCES BETWEEN CANADIAN AND UNITED
STATES (US) ACCOUNTING PRINCIPLES ON THE FINANCIAL STATEMENTS IS DISCLOSED IN
NOTE 16 TO THE CONSOLIDATED FINANCIAL STATEMENTS.

UNLESS OTHERWISE NOTED, TABULAR AMOUNTS ARE IN MILLIONS OF CANADIAN DOLLARS. OUR
DISCUSSION AND ANALYSIS OF OUR OIL AND GAS ACTIVITIES WITH RESPECT TO OIL AND
GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES IS PRESENTED ON A WORKING
INTEREST BEFORE-ROYALTIES BASIS. WE MEASURE OUR PERFORMANCE IN THIS MANNER
CONSISTENT WITH OTHER CANADIAN OIL AND GAS COMPANIES. WHERE APPROPRIATE, WE HAVE
PROVIDED INFORMATION ON AN AFTER-ROYALTY BASIS IN TABULAR FORMAT.

NOTE: CANADIAN INVESTORS SHOULD READ THE SPECIAL NOTE TO CANADIAN INVESTORS ON
PAGE 60 OF OUR 2003 FORM 10-K WHICH HIGHLIGHTS DIFFERENCES BETWEEN OUR RESERVE
ESTIMATES AND RELATED DISCLOSURES THAT ARE OTHERWISE REQUIRED BY CANADIAN
REGULATORY AUTHORITIES.


                                       2
<PAGE>

<TABLE>
<CAPTION>
EXECUTIVE SUMMARY OF 2003 RESULTS

(Cdn$ millions)                                                 2003        2002       2001
--------------------------------------------------------------------------------------------
<S>                                                            <C>         <C>        <C>
Net Income                                                       639         452        450
Earnings per Common Share ($/share)                             4.84        3.34       3.40
Cash Flow from Operations (1)                                  1,859       1,383      1,423

Production, before royalties (mboe/d) (2)                        269         269        268
Production, after royalties (mboe/d)                             185         176        184

Capital Expenditures                                           1,494       1,625      1,404
Proved Reserve Additions, net (mmboe) (2)                         38         126        131
Finding and Development Costs (3) before Revisions ($/boe)     11.64       12.41       9.24
Finding and Development Costs (3) after Revisions ($/boe)      29.34       11.15       9.81
Reserves Replacement Costs after Revisions (4) ($/boe)         29.92       11.64       9.80

Net Debt (5)                                                   1,377       1,775      1,460
Net Debt to Cash Flow (times) (6)                                0.8         1.4        1.1
                                                               -----------------------------
</TABLE>

We achieved record financial results in 2003. As the variance table on page 33
shows, the three biggest drivers impacting net income growth were higher-margin
volumes primarily in the US, strong oil and gas prices and exceptional marketing
results. A strengthening Canadian dollar and an impairment charge largely
attributable to heavy oil assets reduced these gains. Overall net income grew
41% over 2002 to $639 million and our cash flow from operations reached a record
$1.9 billion.

Crude oil prices remained strong in 2003 as supply and demand fundamentals
supported higher prices. Instability in the Middle East, growing demand and low
inventory levels kept average WTI at US$31.04/bbl. Natural gas prices peaked
during the first quarter of the year and again in December, tracking weather
patterns in the US. Our marketing group was positioned to take advantage of
these fluctuations, benefiting from price differences between the west and the
east, as well as between the summer and winter months.

The strengthening Canadian dollar relative to the US dollar reduced our net
income by $130 million and cash flow from operations by $250 million. This is
because our foreign revenues and realized commodity prices, referenced in US
dollars, were lower when translated to Canadian dollars. However, we benefit to
the extent that our foreign operating costs and capital expenditures are also
reduced when translated. In addition, most of our fixed-rate debt is denominated
in US dollars so this debt is reduced with a strengthening Canadian dollar.

As a result of certain negative reserve revisions in Canada, our net income
includes a non-cash impairment charge of $175 million, after-tax, of which
almost 90% relates to heavy oil reserves. The revisions resulted from changes to
late field-life economic assumptions, a reduction in proved undeveloped reserves
based on drilling results and geological mapping, and reassessments of expected
future production profiles. The reduction does not affect our production
forecast for 2004. Our Canadian oil and gas properties will continue to be a
significant source of free cash flow for future investment since the future
estimated cash flow from our total conventional Canadian assets is approximately
2.5 times their related carrying value.

----------------------------
(1)  We evaluate our performance and that of our business segments based on
     earnings and cash flow from operations. Cash flow from operations is a
     non-GAAP term that represents cash generated from operating activities
     before changes in non-cash working capital and other. We consider it a key
     measure as it demonstrates our ability and the ability of our business
     segments to generate the cash flow necessary to fund future growth through
     capital investment and repay debt.

     (Cdn$ millions)                                2003       2002       2001
     --------------------------------------------------------------------------
     Cash Flow from Operating Activities            1,469     1,322      1,566
     Changes in Non-Cash Working Capital              320        46       (143)
     Other                                             70        15         --
                                                   ----------------------------
     Cash Flow from Operations                      1,859     1,383      1,423
                                                   ============================

(2)  Production, before royalties and reserves include our working interest
     before royalties. We have presented our working interest before royalties
     as we measure our performance on this basis consistent with other Canadian
     oil and gas companies. We have used our year-end pricing assumptions.

(3)  Finding and Development Costs is defined as oil and gas exploration and
     development expenditures divided by total proved reserves additions on a
     before-royalties basis, prior to acquisitions and dispositions. Proved
     reserves include our working interest before royalties.

(4)  Reserves Replacement Costs is defined as oil and gas exploration and
     development expenditures divided by total proved reserves additions on a
     before-royalties basis, with both including the effects of acquisitions and
     dispositions. Proved reserves include our working interest before
     royalties.

(5)  Long-term debt less net working capital.

(6)  Net debt divided by cash flow from operations after dividends on Preferred
     Securities.

                                       3
<PAGE>

High-margin barrels from Aspen and now Gunnison replaced declining production in
North America and at Buffalo, offshore Australia and Ejulebe, offshore Nigeria -
both of which will be fully depleted in 2004. Canada's production was reduced
mid-year as we disposed of 9,000 boe/d of non-core light oil properties in
southeast Saskatchewan. The revenues and expenses associated with these disposed
properties are segregated as discontinued operations in our financial
statements. The shift from low-margin production in maturing areas to
high-margin production in new growth areas grew overall production after
royalties by 5% despite flat production before royalties. In 2004, we expect
production before royalties to average between 255,000 and 275,000 boe.
Production after royalties will continue to grow with more low-royalty volumes
from Gunnison and Aspen.

In 2003, we continued our strategy of growing long-term value primarily through
grassroots exploration and development. We focused on maximizing returns from
our capital investment program growing value beyond simply adding production
volumes. Targeting higher returns, we have shifted our capital investment away
from higher-cost, maturing North American conventional production into four key
basins with significant growth projects as described in Item 1 of this 10-K.
Below are highlights of our strategic progress in 2003:

One-third of our total $1.5 billion capital budget was invested in the Gulf of
Mexico, now our largest cash flow contributor. We advanced our deep-water
strategy in 2003 by acquiring the remaining 40% interest in Aspen and becoming
operator of our first deep-water project. Aspen's low cost and low royalty
production generated cash netbacks of US$23 per boe, nearly twice our corporate
average. We added to Aspen's high-margin production by bringing our second
deep-water project, Gunnison, on stream ahead of schedule in December 2003.
Production is ramping up at Gunnison through 2004 and we expect to tie-in a
third development well at Aspen, adding to our improving margins. Exploration
continues in 2004 on acreage in the Aspen and Gunnison areas, the eastern Gulf
and the shelf deep-gas trend.

In 2003, we invested $253 million in the Middle East: 87% on development and
exploitation at Masila and the remainder on exploration on Block 51, adjacent to
Masila, and in northern Yemen. Activities at Masila were focussed on maintaining
existing production rates. Extensions to Masila's Heijah and Tawila fields and
appraisal of Block 51 discoveries contributed 63 mmboe of proved reserves in
2003. In 2004, we plan additional delineation drilling on Block 51 to establish
even more reserves. With new production from Block 51 planned for 2005, we
expect to maintain strong production rates from Yemen for several years.

We invested $57 million to continue building our presence offshore West Africa.
On Block 222, offshore Nigeria, three appraisal wells at Usan delivered very
good results. In addition, one appraisal well was drilled at Ukot. A development
plan is being prepared for submission to the Nigerian government. Exploration
will continue on this block as well as on OML-115, offshore Nigeria and Block K,
offshore Equatorial Guinea - both attractive new prospects we acquired during
2003. To date, we have not booked any proved reserves for our Block 222
discoveries. Proved reserves will be booked once commercial development is
approved.

Our $96 million investment in the Long Lake project in the Athabasca oil sands
allowed us to continue detailed engineering, implement a SAGD pilot, and obtain
regulatory approval for the commercial project in 2003. With Board sanctioning
of the commercial project in February 2004, we have booked 200 million barrels
of proved reserves in 2004. Only 3 million barrels of proved reserves were
booked in 2003 related to the SAGD pilot. Construction of commercial facilities
will begin this summer. In 2003, we also invested $173 million in Syncrude's
Stage 3 expansion, which together with base operations added 26 million barrels
of proved reserves at a cost of $7.38 per boe. We expect this expansion to be
completed in 2005, adding 8,000 barrels per day of new production to Nexen.

Beyond these four basins, capital was invested in our core assets in Canada and
the shallow-water Gulf, in Colombia and in our chemicals operations as we expand
our Brandon facility and transfer sodium chlorate capacity there from our Taft,
Louisiana plant. In Canada, our exploration and development programs in Canada
added 16 mmboe of conventional proved reserves.

Overall, we added 38 mmboe of net proved reserves as follows:

(mmboe)
-------------------------------------------------------------------------------
Additions (Extensions and Discoveries)                                     111
Acquisitions (Aspen)                                                        24
Dispositions (primarily southeast Saskatchewan)                            (30)
Revisions (primarily in Canada)                                            (67)
                                                                         ------
                                                                            38
                                                                         ======


                                       4
<PAGE>

Additions of 111 mmboe of proved reserves replaced 113% of our production at a
finding and development (F&D) cost of $11.64 per boe. Our F&D costs have trended
upwards over the past few years given the long-lead times associated with our
new growth projects. These projects consume large amounts of capital and
mismatches are created in the timing of reserve recognition. Over their lives
these projects are expected to generate attractive returns and low full-cycle
F&D costs.

The preceding F&D cost measure of $11.64 per boe does not take into
consideration negative reserve additions. This measure was calculated by
dividing the capital expenditures incurred during the year as determined in
accordance with Canadian generally accepted accounting principles by the reserve
volumes added from extensions and discoveries during the year. The calculation
included our oil and gas and Syncrude activities and used before-royalty reserve
volumes. However, it does not include other changes in reserves during the year
relating to negative revisions, acquisitions and dispositions. Additional
information on our F&D and reserves replacement costs (RRC) is as follows:

<TABLE>
<CAPTION>
                                                     YEAR ENDED DECEMBER 31, 2003
                                                        RESERVE ADDITIONS
                                           CAPITAL       BEFORE ROYALTIES      REPORTED MEASURES
-------------------------------------------------------------------------------------------------
                                   (Cdn$ millions)                (mmboe)             (Cdn$/boe)

<S>                                <C>                          <C>                    <C>
F&D (before revision)                        1,276                    111                  11.64
Reserves revision                               --                    (67)
                                   ---------------------------------------
F&D (after revision)                         1,276                     44                  29.34
Acquisition                                    164                     24                   6.68
Dispositions                                  (279)                   (30)                  9.46
                                   ---------------------------------------
RRC                                          1,161                     38                  29.92
                                   ==============================================================
</TABLE>

Note:

Reported Measures may differ from the results achieved by dividing Capital by
Reserve Additions Before Royalties due to rounding.

<TABLE>
<CAPTION>
The comparable measures calculated on an after-royalty basis are as follows.

                                                     YEAR ENDED DECEMBER 31, 2003
                                                        RESERVE ADDITIONS
                                           CAPITAL        AFTER ROYALTIES      REPORTED MEASURES
-------------------------------------------------------------------------------------------------
                                   (Cdn$ millions)                (mmboe)             (Cdn$/boe)

<S>                                <C>                          <C>                    <C>
F&D (before revision)                        1,276                     76                  16.85
Revision                                        --                    (42)
                                   ---------------------------------------
F&D (after revision)                         1,276                     34                  38.02
Acquisition                                    164                     22                   7.39
Dispositions                                  (279)                   (25)                 11.16
                                   ---------------------------------------
RRC                                          1,161                     31                  36.76
                                   ==============================================================
</TABLE>

Note:

Reported Measures may differ from the results achieved by dividing Capital by
Reserve Additions After Royalties due to rounding.

The comparable measures derived from the information included in the FAS 69
disclosures in our 2003 Form 10-K, which uses capital expenditures determined in
accordance with United States GAAP, excludes our Syncrude activities and is
prepared on an after-royalty basis, are as follows.

<TABLE>
<CAPTION>
                                                     YEAR ENDED DECEMBER 31, 2003
                                                        RESERVE ADDITIONS
                                           CAPITAL        AFTER ROYALTIES      REPORTED MEASURES
-------------------------------------------------------------------------------------------------
                                   (Cdn$ millions)                (mmboe)             (Cdn$/boe)

<S>                                <C>                          <C>                    <C>
F&D (before revision)                        1,266                     54                  23.45
Revision                                        --                    (47)
                                   ---------------------------------------
F&D (after revision)                         1,266                      7                 180.85
Acquisition                                    164                     22                   7.39
Dispositions                                  (279)                   (25)                 11.16
                                   ---------------------------------------
RRC                                          1,151                      4                 287.85
                                   ==============================================================
</TABLE>

Note:

Reported Measures may differ from the results achieved by dividing Capital by
Reserve Additions After Royalties due to rounding.


                                       5
<PAGE>

Readers should refer to Note 16 in the Consolidated Financial Statements
included in our 2003 Form 10-K for a description of the differences between
Canadian and U.S. GAAP as it pertains to the determination of costs incurred.

We also provide the following additional information as requested by the
Securities and Exchange Commission (SEC).

The reserve additions (before royalties) of 111 million boe from extensions and
discoveries related primarily to development drilling on the Masila block in
Yemen (32 million), exploration success and commencement of development
activities on Block 51 in Yemen (31 million), the Stage 3 expansion at Syncrude
(26 million) and development drilling in Canada (16 million). The additions on
Block 51 were recognized as proved undeveloped reserves (PUDs) for which
additional development capital was planned for 2004 and early 2005 to bring the
reserves into production.

The net negative reserve revisions of 67 million boe occurred primarily in
Canada (60 million) and Yemen (11 million), offset by positive revisions of 4
million elsewhere. In Canada, 30 million resulted from changes in the estimated
future production profiles of certain properties, 17 million from a reduction in
PUDs based on drilling results and new geological mapping, and 13 million was
attributable to changes in late field-life economic assumptions primarily
related to changes in year-end Canadian dollar prices and our estimates of
future operating costs. In Yemen, we reduced our estimate of the Masila block
reserves based on drilling results and new geological mapping.

Reserves were also added from the acquisition of the remaining 40% working
interest in our producing Aspen field. Reserves dispositions occurred primarily
in connection with the sale of certain of our light oil properties in southeast
Saskatchewan.

Our strategy is to focus a larger portion of our future capital spending on
areas where we see the opportunity to grow and create value - the Athabasca oil
sands, the deep-waters and deep Shelf gas in the U.S. Gulf of Mexico, the North
Sea, offshore West Africa and the Middle East. As a result, we expect our future
proved reserve additions to come primarily from these areas, although these
areas typically have longer cycle times. As we transition to these areas, our
activities on our mature properties in western Canada, the U.S. Shelf and the
Masila block in Yemen will focus largely on converting PUDs to producing status,
generally resulting in fewer proved reserve additions.

Readers are cautioned that F&D and RRC metrics prepared using annual capital
expenditures and changes in proved reserves may be misleading as they do not
represent full cycle costs due to differences in the timing of recognition of
reserves. In some cases, reserves may be recognized even though the majority of
the capital required to develop the reserves to bring them into production is
yet to be incurred. Conversely, capital incurred during the year may include
costs to develop proved reserves that were recognized in previous years.
Management does not focus on annual F&D and RRC metrics; instead, management
looks to longer term historical trends and full cycle F&D and RRC metrics
relative to related netbacks to assess the efficiency and effectiveness of our
capital programs.

In 2003, we took steps to improve our liquidity and financial flexibility to
ensure we are able to fund our multi-year development projects. Record cash
flow, disposition proceeds and a strong Canadian dollar reduced net debt and
preferred securities by $758 million. Net debt and preferred securities at
year-end was 1.0 times cash flow. We also took advantage of the low interest
rate environment and issued US$960 million of public debt, enabling us to fund
debt maturities, retire our preferred securities and reduce future financing
costs.

Going forward, we are well positioned for growth. Our 2004 oil and gas capital
program of $1.7 billion will continue to support progress on our major
development projects and fund an active exploration program, half of which is
directed to US exploration. Strong commodity prices are likely to continue
partially offset by the impact of a strong Canadian dollar on our US-dollar
denominated revenues. Removing the impact of price and exchange rate
fluctuations, we expect our improving margins in the US to grow our cash flow
from operations by 10% year-over-year.

CAPITAL INVESTMENT

(Cdn$ millions)                                        2003       2002     2001
--------------------------------------------------------------------------------
Capital Investment
    New Growth Exploration                              329        259      411
    New Growth Development                              358        626      110
    Core Asset Development                              589        592      641
    Property Acquisition                                164          4      122
                                                      --------------------------
Total Oil & Gas                                       1,440      1,481    1,284
    Chemicals, Marketing and Other                       54        144      120
                                                      --------------------------
Total                                                 1,494      1,625    1,404
                                                      ==========================

Our capital programs are focused on maximizing returns on every dollar of
capital invested. Investment dollars are allocated between:


                                       6
<PAGE>

o    core assets for short-term growth and free cash flow to fund ongoing
     capital programs;
o    development projects that convert our discoveries into new production
     and cash flow; and
o    exploration projects for longer-term growth.

Given our exploration success over the past several years, we have made
significant investments in major development projects in our four key basins. In
2001, we invested in new development projects at Aspen and Gunnison in the
deep-water Gulf of Mexico and Syncrude's Stage 3 expansion. In 2002, we
continued developing these projects and began scoping out our Long Lake project.
We also made discoveries at Usan offshore Nigeria. In 2003, the first of these
projects, Aspen came onstream. We converted the discoveries on Block 51 in Yemen
into a development project. Late in 2003, our second deep-water project at
Gunnison came onstream, with cash netbacks that are twice our corporate average.

While our deep-water Gulf investments are already contributing high-value
production, driving our corporate margins, our growth projects in the other
basins have yet to contribute production and cash flow. Most of these are
long-lead time projects, with three to five years between discovery and first
production. Although these large capital investments have yet to generate cash
flow, the capital invested is not at risk. Over their lives, these projects are
expected to generate attractive returns and low full-cycle finding and
development costs.

The results of our capital programs are detailed below.

2003 CAPITAL

In 2003, we invested over $1.4 billion in oil and gas with:

o    41% in core assets to maintain existing production levels;
o    36% in new growth development projects, and;
o    23% in new growth exploration projects.

(CDN$ MILLIONS)                    DEVELOPMENT   EXPLORATION    OTHER     TOTAL
--------------------------------------------------------------------------------
Oil and Gas
    United States                          249           147      164       560
    Yemen                                  219            34       --       253
    Nigeria                                 --            35       --        35
    Canada                                 259            51       --       310
    Syncrude                               195            --       --       195
    Other Countries                         25            62       --        87
                                  ----------------------------------------------
                                           947           329      164     1,440

Chemicals                                   --            --       24        24
Marketing, Corporate and Other              --            --       30        30
                                  ----------------------------------------------
Total Capital                              947           329      218     1,494
                                   =============================================

In 2004, we plan to invest almost $1.7 billion in oil and gas with:

o  35% in core assets to maintain existing production levels;
o  45% in new growth development projects, and;
o  20% in new growth exploration projects.


                                       7
<PAGE>

2004 ESTIMATED CAPITAL

(CDN$ MILLIONS)                   DEVELOPMENT    EXPLORATION    OTHER     TOTAL
--------------------------------------------------------------------------------
Oil and Gas
    United States                         175            158       --       333
    Yemen                                 397             23       --       420
    Nigeria                                19             59       --        78
    Canada                                130             52       --       182
    Long Lake Synthetic                   391              9       --       400
    Syncrude                              182             --       --       182
    Other Countries                        17             60       --        77
                                 -----------------------------------------------
                                        1,311            361       --     1,672

Chemicals                                  --             --       53        53
Marketing, Corporate and Other             --             --       41        41
                                 -----------------------------------------------
Total Capital                           1,311            361       94     1,766
                                  ==============================================

GULF OF MEXICO

ASPEN

Our deep-water Gulf of Mexico strategy began paying off in 2003. After bringing
Aspen on-stream in December 2002, a record 19 months after discovery, we
acquired the remaining 40% interest in March 2003 from BP for $164 million. With
100% interest in Aspen, we are now deep-water operators and control the timing
of future exploration and development on our acreage in the Greater Aspen area.
Aspen's production has low royalties and operating costs, resulting in
high-margin production that has already recovered approximately 55% of our
investment of US$374 million. A third development well is drilling at Aspen.


GUNNISON

In 2003, production from our second deep-water project at Gunnison, discovered
in 2000, came on-stream. Gunnison's SPAR production facility was completed and
moved from Finland to the Gulf mid-summer. We installed the remaining equipment
on the production platform, and completed and tied-in the subsea wells.
Production came on-stream in December 2003. Gunnison will deliver equally
attractive returns as Aspen, with its low royalties and operating costs.


EXPLORATION

In 2003, we drilled three exploration wells in the Gulf, including a deep-water
dry hole at Santa Rosa. Under our first exploration venture with Shell, we have
recently finished drilling the Shark prospect on the shelf in search of natural
gas in deep shelf sands. No commercial hydrocarbons were encountered and the
well is temporarily abandoned while we evaluate the data collected from the well
bore.

In 2003, we entered into a second exploration venture with Shell to jointly
explore a 1,116 square mile area of the deep-water eastern Gulf of Mexico. The
area includes 124 blocks located in Mississippi Canyon and Desoto Canyon. Under
this exploration venture, we drilled the Shiloh-1 well on Desoto Canyon 269 to a
total depth of over 24,000 feet. At Shiloh, we encountered hydrocarbons in
non-commercial quantities so the well was written off. We have acquired
additional acreage in the area and will continue drilling in hopes of proving-up
commercial quantities in the region.

In 2004, almost half our exploration capital will be invested in the Gulf of
Mexico. Our plans include five high-potential exploration wells: two deep shelf
gas prospects on the shelf, Crested Butte offsetting Aspen, a well in Garden
Banks, and another in the eastern Gulf of Mexico.


MIDDLE EAST

MASILA

Our primary focus at Masila is to maintain production rates. During 2003, we
invested $219 million to drill 94 development wells, construct new facilities,
increase water handling capabilities, and perform additional workovers to
maintain production rates. We plan to spend US$176 million in 2004 on
development projects in the Masila field to drill 90 wells and complete facility
enhancements to partially offset the field's natural decline.


                                       8
<PAGE>

BLOCK 51

In 2003, we enjoyed exploration success with discoveries in the Baishir al Khair
Field (BAK) at BAK-A (formerly Tammum) and BAK-B (formerly Amir). Seven
appraisal wells were drilled, encountering oil in the Qishn and Saar horizons,
and we began commercial development late in the year. Initial development
includes completing the seven wells drilled, ten new development wells, a
central processing facility, a gathering system and a tieback to our Masila
export system. Based on drilling results to date, we expect to develop in excess
of 60 million barrels of reserves and add between 20,000 and 25,000 barrels per
day of production capacity in early 2005. The field has additional potential
that will be quantified by a 3D seismic program and further delineation drilling
in 2004. We are continuing to explore the Block and plan to drill at least six
exploration wells in 2004.


EXPLORATION

In addition to Block 51, we drilled the Husan El Kradis (HEK-1R) exploration
well 25 kilometres northwest of BAK-B to test for oil in fractured basement;
however, the well was dry. Further exploration is planned in the area.


OFFSHORE WEST AFRICA

NIGERIA

In 2003, we focused on developing our Usan and Ukot discoveries on Block
OPL-222. We drilled three appraisal wells at Usan and announced a significant
extension of that field. An additional appraisal well at Ukot was also drilled.
The operator is preparing a field development plan for submission to the
Nigerian government for approval and we expect first production around 2008. In
2004, we plan additional exploration drilling to test the Block's remaining
potential.

In December 2003, as part of our initiative to expand our position in West
Africa, we were assigned an interest in OML-115 offshore Nigeria. We commenced a
program to acquire 410 km2 of 3D seismic data over the block and plan to drill
one exploration well in 2004.


EQUATORIAL GUINEA

We acquired a 25% interest in Block K located 100 km offshore. The Block is on
trend with the 300-million barrel Ceiba field and other discoveries on Block G
to the north. In 2004, we plan to drill two wells to assess Equatorial Guinea's
ability to contribute to the growth of our West Africa region.


ATHABASCA OIL SANDS

SYNCRUDE

In 2003, the Stage 3 expansion proceeded as expected. The Aurora 2 bitumen train
was completed and successfully placed in production. The upgrader expansion at
Mildred Lake is 35% complete, on-track for start-up in 2005. We expect the Stage
3 expansion to increase our share of production to over 25,000 barrels per day.
Due to higher engineering, manufacturing and construction costs, the estimated
costs of the Stage 3 expansion have increased from initial estimates of $4.1
billion ($296 million net) to $5.7 billion ($412 million net). Activities in
2004 will also focus on replacing bitumen production capacity that will be lost
when the southwest quadrant of the Mildred Lake Base Mine is depleted.


SYNTHETIC OIL AT LONG LAKE

The Long Lake project is progressing rapidly. In 2003, we commenced pilot
testing of SAGD technology at Long Lake, obtained Alberta Energy Utilities Board
approval and completed more than 15% of the detailed engineering.

On February 12, 2004, our Board of Directors approved the Phase 1 commercial
development plan. The project will develop approximately 10% of our Athabasca
bitumen resource, upgrading this bitumen into high-quality light, sweet
synthetic crude oil. As a result of the approval, we have booked 200 million
barrels of proved reserves in 2004.

In 2004, we expect to continue with detailed engineering, order long-lead time
equipment and commence construction at Long Lake to meet a 2006 start-up date
for bitumen production and a 2007 start-up date for synthetic crude oil
production. Gross capital costs are expected to total $3.4 billion.


OTHER EXPLORATION AND CORE ASSET DEVELOPMENT

CANADA - CONVENTIONAL

As our conventional assets in Western Canada mature, we are focusing on projects
that provide the highest return on invested capital. In 2003, we sold over 9,000
barrels of daily production at attractive prices. We've also continued our
transition to new sources of production growth such as synthetic crude oil and
coal bed methane.

CANADA - EXPLORATION


                                       9
<PAGE>

We increased our coal bed methane (CBM) land holdings and proceeded with our
Corbett pilot, drilling 24 wells. In 2004, we will significantly expand the size
of our CBM pilot project at Corbett and expect to decide on commerciality by
year-end. We will test four other Upper Mannville CBM prospects and drill a
number of gas exploration well in the Alberta foothills.


COLOMBIA

In 2003, we drilled 31 development wells to increase production rates and test
the viability of a waterflood program on the Guando field. In 2004, we plan to
drill 24 development wells and implement a full-field waterflood at Guando.

We continued exploration in Colombia. One exploration well drilled on the Andino
Block tested wet and was abandoned.


CHEMICALS

During 2003, we focused on increasing reliability and cost reduction at all of
our manufacturing facilities. We also began relocating the assets from our Taft
facility in Louisiana to Brandon, Manitoba, the lowest-cost sodium chlorate
production facility in North America. In 2004, we expect to complete our Brandon
expansion including the relocation and installation of the Taft assets. Upon
completion of this expansion, the Brandon plant will be the largest sodium
chlorate plant in the world.


MARKETING, CORPORATE AND OTHER

Capital spending in 2003 and planned spending in 2004 includes systems
development, computer hardware and software, office equipment and leasehold
improvements.


FINANCIAL RESULTS

<TABLE>
<CAPTION>
YEAR TO YEAR CHANGE IN NET INCOME

(Cdn$ millions)                                                   2003 VS 2002   2002 VS 2001
----------------------------------------------------------------------------------------------
<S>                                                               <C>            <C>
NET INCOME FOR 2002 AND 2001                                              452              450
                                                                  ============================
    Favourable (unfavourable) variances:

    Cash Items:
      Production volumes, net of royalties:
        Crude oil                                                          92               30
        Natural gas                                                        41              (18)
      Change in inventory - crude oil sales, net of royalties             (25)              --
      Realized commodity prices:
        Crude oil                                                          41              183
        Natural gas                                                       234             (113)
      Oil and gas operating expense:
        Conventional                                                       37              (63)
        Synthetic                                                         (14)               5
      Marketing contribution                                               96              (23)
      Chemicals contribution                                               (5)               1
      General and administrative                                          (38)             (16)
      Interest expense                                                      4                3
      Current income taxes                                                 13               (7)
      Other                                                                --              (22)
                                                                  ----------------------------
    Total Cash Variance                                                   476              (40)

    Non-Cash Items:
      Depreciation, depletion and amortization:
        Oil and Gas                                                      (327)             (80)
        Other                                                              (5)             (10)
      Exploration expense                                                 (19)              79
      Future income taxes                                                  28               79
      Other                                                                34              (26)
                                                                  ----------------------------
    Total Non-Cash Variance                                              (289)              42

                                                                  ----------------------------
NET INCOME FOR 2003 AND 2002                                              639              452
                                                                  ============================
</TABLE>

Significant variances in net income are explained in the sections that follow.

                                       10
<PAGE>

<TABLE>
<CAPTION>
OIL AND GAS

PRODUCTION

                                             2003                             2002                             2001
-----------------------------------------------------------------------------------------------------------------------------
                                      Before          After          Before            After          Before           After
                                   Royalties      Royalties       Royalties        Royalties       Royalties       Royalties
                                 --------------------------------------------------------------------------------------------
<S>                                <C>            <C>             <C>              <C>             <C>             <C>
Oil and Liquids (mbbls/d)
    Yemen                              116.8           57.5           118.0             55.8           118.3            55.5
    Canada (1)                          46.3           35.4            56.3             43.4            58.0            48.3
    United States                       28.3           25.0             9.9              8.2            10.0             8.3
    Australia                            6.1            5.6            12.8             10.3            10.2             9.6
    Other Countries                      5.4            4.6             8.9              5.2             6.2             5.3
    Syncrude                            15.3           15.2            16.6             16.5            16.1            15.5
                                 --------------------------------------------------------------------------------------------
                                       218.2          143.3           222.5            139.4           218.8           142.5
                                 --------------------------------------------------------------------------------------------
Natural Gas (mmcf/d)
    Canada (1)                           158            125             167              128             174             147
    United States                        145            122             112               93             121              99
                                 --------------------------------------------------------------------------------------------
                                         303            247             279              221             295             246
                                 --------------------------------------------------------------------------------------------

Total (mboe/d)                           269            185             269              176             268             184
                                 ============================================================================================
</TABLE>

Note:

(1)  Includes the following production from discontinued operations. See Note 9
     to our Consolidated Financial Statements.

     (mboe/d)                                       2003       2002       2001
     --------------------------------------------------------------------------
     Production
       Before Royalties                              6.2       10.5       11.0
       After Royalties                               4.6        7.8        8.0
                                                   ----------------------------

2003 VS 2002 - 5% PRODUCTION GROWTH AFTER ROYALTIES ADDED $133 MILLION TO NET
INCOME

Production after royalties grew 5%, with new low-royalty deep-water
production from Aspen and more recently Gunnison, and more cost recovery barrels
from Masila in Yemen. At Masila, we received a greater percentage of gross
production to recover costs we incurred on the government's behalf.

Production before royalties was flat compared to 2002 as growth in our US
deep-water production was partially offset by dispositions in Canada, expected
production declines offshore Nigeria and Australia, and maturing conventional
assets. We expect 2004 production before royalties to average between 255,000
and 275,000 boe - similar to 2003 levels. Production after royalties will
continue to grow with more low-royalty volumes from Gunnison and Aspen.

MASILA BLOCK IN YEMEN

Production before royalties decreased slightly in 2003 consistent with the
overall decline in the field's base production. As Masila matures, we continue
to drill more development wells, perform more workovers and expand our water
handling capacity to manage the declines. Late in 2003, our expanded drilling
and workover efforts successfully increased production to 120,000 barrels per
day (net to us).

While the field's total production decreased in 2003, our share of production
after royalties grew due to the cost recovery mechanism in our production
sharing contract. We are entitled to recover the costs we have incurred on the
government's behalf (up to a 40% limit) through additional production volumes.
As recent development drilling, facilities expansion and infrastructure
modifications have increased our pool of recoverable costs, we receive a larger
portion of total production to recover these costs.


CANADA

Given the maturity of the Western Canadian Sedimentary Basin, production
additions are shrinking and declines are increasing. Our conventional Canadian
assets are no exception. We aggressively managed our assets by developing them
where we could add value or by selling them at attractive prices where we could
not. Our conventional volumes in Canada fell 12% excluding the sale of our
non-core properties in southeast Saskatchewan. We are investing the free cash
flow from our Canadian assets in more profitable, multi-year development
projects.


                                       11
<PAGE>

Crude oil production was down 18%. On August 28, 2003, we sold 9,000 boe/d of
non-core, light oil properties in the Williston Basin of southeast Saskatchewan
for net proceeds of $268 million. The remaining decrease was due to base
declines on our heavy oil properties as water cuts increased at Marsden and
wells at Edam sanded up.

Our natural gas volumes fell 5% as new production from drilling did not offset
the natural decline in our gas properties.

We expect conventional production to decline modestly in 2004 as our asset base
matures. However, this trend will reverse as our Long Lake project starts up
with the production of bitumen in 2006 and synthetic crude oil in 2007.


GULF OF MEXICO

A full year of deep-water Aspen production increased US production rates 84% to
record levels in 2003. Production adds and optimization activities at Eugene
Island 295 and Vermilion 76 offset declines on the shelf.

Aspen came on-stream and began delivering high-margin barrels in December 2002.
We then acquired the remaining 40% interest in late March 2003. This acquisition
contributed 8,000 boe per day at a cash return of $33.11 per boe in 2003. We
locked-in a portion of our return on the acquisition by selling approximately
60% of the acquired production forward to March 2004 at a weighted average price
of US$29.50 per boe. The forward sale of 10% of the acquired reserves
effectively pays for 70% of the purchase price.

Late in 2003, additional deep-water production came on-stream at Gunnison. Three
subsea wells were tied-in and were producing 7,200 boe per day at year-end. Our
total deep-water production for the year was 24,000 boe per day.

Our shelf production was consistent with 2002 levels as we optimized production
where possible. We restored production at hurricane-damaged Eugene Island 295
ahead of schedule in February 2003 and continued to deliver solid rates from our
Vermilion 76 development. These gains were offset, in part, by lower performance
at Eugene Island 18 and West Cameron 170.

We expect the deep-water Gulf of Mexico to remain our fastest growing area in
2004 with Gunnison production increasing to 17,000 boe per day. We estimate our
US production levels will reach over 70,000 boe per day by the end of the year.


OTHER COUNTRIES

Our production at Buffalo offshore Australia and at Ejulebe offshore Nigeria
declined as expected throughout 2003 as both fields approach the end of their
economic life. We expect final production from both in 2004.

Colombia production grew 131% with 31 new development wells. Our pilot test
confirmed the viability of a waterflood and we are moving to full-field
waterflood in 2004. We expect to see volumes increase by 50% in 2004.


SYNCRUDE

Production decreased 8% in 2003 as an extra turnaround was completed during the
year. A 37-day unplanned coker turnaround reduced volumes in the fourth quarter
to 14,800 bbls per day. The turnaround delivered greater operational reliability
immediately as we exited 2003 at 19,900 bbls per day. We expect the benefits of
this turnaround to continue and do not anticipate a coker turnaround in 2004.


2002 VS 2001 - HIGHER PRODUCTION ADDED $12 MILLION TO NET INCOME

Production from our core assets in Yemen, Canada and the US remained largely
stable year over year. On-going development activities at Masila in Yemen, at
Hay in Canada and on the shelf in the US Gulf of Mexico helped maintain
production rates. In the US, poor weather in the third and fourth quarters,
including tropical storm Isidore and Hurricane Lili caused the temporary shut-in
of production, a 6-week delay at Aspen and damage to our Eugene Island 295
production platform. All production, except Eugene Island 295, was restored in
the fourth quarter of 2002. Aspen's first well came on-stream in early December
2002 and the second well in late December.

Our non-core assets made significant contributions during the year. At Buffalo
offshore Australia a successful two-well infill drilling program contributed
7,500 boe per day of incremental production. Ejulebe offshore Nigeria
contributed a 27% increase as the reservoir continued to perform better than
anticipated. Both Buffalo and Ejulebe were declining at year-end as they were
approaching the end of their expected lives.


                                       12
<PAGE>

<TABLE>
<CAPTION>
COMMODITY PRICES

                                                             2003          2002        2001
--------------------------------------------------------------------------------------------
<S>                                                      <C>             <C>         <C>
CRUDE OIL
    West Texas Intermediate (US$/bbl)                       31.04         26.09       25.97
                                                         -----------------------------------

    Differentials (US$/bbl):
    Masila                                                   3.03          1.41        3.29
    Heavy Oil                                                8.63          6.49       10.68
    Mars                                                     3.53          2.51        4.89

    Producing Assets (Cdn$/bbl)
    Yemen                                                   39.45         38.80       35.05
    Canada                                                  32.37         31.13       24.86
    United States                                           37.68         38.88       38.35
    Syncrude                                                43.36         40.89       39.90
    Australia                                               43.14         40.30       38.71
    Other Countries                                         38.22         38.96       37.37

    Corporate Average (Cdn$/bbl)                            38.04         37.13       33.10
                                                         -----------------------------------

NATURAL GAS
    New York Mercantile Exchange (US$/mmbtu)                 5.60          3.37        4.00
    AECO (Cdn$/mcf)                                          6.35          3.84        5.97
                                                         -----------------------------------

    Producing Assets (Cdn$/mcf)
    Canada                                                   5.64          3.57        5.02
    United States                                            8.16          5.29        6.66

    Corporate Average (Cdn$/mcf)                             6.85          4.25        5.69
                                                         -----------------------------------

AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe)               38.63         35.14       33.28
                                                         -----------------------------------

AVERAGE FOREIGN EXCHANGE RATE
    Canadian to US Dollar                                  0.7135        0.6369      0.6458
                                                         -----------------------------------
</TABLE>

2003 VS 2002 - HIGHER REALIZED PRICES ADDED $275 MILLION TO NET INCOME

Both crude oil and natural gas commodity prices reached near record levels in
2003 as supply and demand fundamentals supported strong prices. The positive
impact of strong crude oil and natural gas reference prices was offset in part
by the strengthening Canadian dollar and widening crude oil differentials.

All of our oil sales and most of our gas sales are denominated in or referenced
to US dollars. As a result, the strengthening Canadian dollar relative to the US
dollar reduced our realized crude oil price by $4.50 per bbl and our realized
natural gas price by $0.80 per mcf. In total, our net sales decreased $280
million from 2002 levels with the strengthening of the Canadian dollar. The
Canadian to US dollar exchange rate closed the year at 77(cent).


                                       13
<PAGE>

CRUDE OIL REFERENCE PRICES

Supply and demand fundamentals consistently supported strong reference prices
throughout 2003. WTI opened and closed the year around US$33 per bbl, with highs
of approximately US$38 per barrel and lows around US$25 per barrel.



                                [GRAPHIC OMITTED]

                 [2003 WTI MONTHLY AVERAGE LINE CHART OMITTED]



Overall, the higher average WTI prices were supported by:

o    ongoing concerns over the security and stability of Iraqi production;
o    higher political risk in the Middle East;
o    labour disputes, and the resulting and threatened supply disruptions, in
     Nigeria and Venezuela;
o    OPEC's determination to hold production quotas in support of their price
     band;
o    growing demand in Asia, particularly China and India;
o    low crude oil and product inventories in North America; and,
o    the decline in value of the US dollar relative to other major world
     currencies.

These factors, along with speculation around their severity and duration,
created volatility in world crude oil prices. In 2004, analysts expect crude oil
prices to fall to between US$25 to US$28, as non-OPEC supply from Russia and
Iraq grows. An OPEC production cut, escalated Middle East risk or a
greater-than-expected economic recovery would put upward pressure on these
forecasts.

CRUDE OIL DIFFERENTIALS

Crude oil differentials widened in 2003 largely in response to the overall
strength of WTI.

Our Masila differential continued to track the Brent/WTI spread. Despite the
strength in WTI during the year, the Brent differential actually remained
relatively narrow. Brent prices strengthened with high demand in Europe during
the exceptionally warm summer months and growing demand in Asia late in the
year. Unexpected platform turnarounds in the North Sea reduced supply, causing
the Brent/WTI differential to narrow even further. We expect the Masila
differential to remain around US$3 per bbl in 2004.

The wider heavy oil differential was largely due to an overall increase in
supply from new Canadian heavy oil projects and some temporary decreases in
demand from unexpected refinery turnarounds and the August blackout in parts of
eastern North America. The heavy oil differential is expected to remain around
US$8 per bbl in 2004.

The Mars differential impacts the pricing of our Aspen production and averaged
US$3.53 per bbl. Again, despite the strength in WTI, the Mars differential was
relatively narrow in 2003. The pricing of Mars blend is directly affected by the
pricing of sour blends. The instability of Iraqi supply and OPEC production cuts
improved the pricing of sour blends and allowed the Mars differential to remain
narrow.


                                       14
<PAGE>

NATURAL GAS REFERENCE PRICES

North American natural gas prices were exceptionally strong during both the
first quarter of 2003 and December 2003. Natural gas prices reached almost US$10
per mcf in the first quarter, but more notably did not dip below US$4.40 per mcf
throughout the rest of the year.



                                [GRAPHIC OMITTED]


                [2003 NYMEX MONTHLY AVERAGE LINE CHART OMITTED]



Extended cold weather last winter and resulting low storage inventory levels
were the major reason for the initial price increase early in the year. Fears of
cold weather in the east increased gas prices in December. This also caused the
NYMEX/AECO basis to widen significantly late in the year as weather forecasts in
the west were suggesting above normal temperatures. We expect natural gas prices
to decline to around US$4.25 per mmbtu in 2004.


2002 VS 2001 - HIGHER REALIZED PRICES ADDED $70 MILLION TO NET INCOME

WTI contributed little to cash flow growth in 2002, however narrow crude oil
differentials contributed around $180 million. At the beginning of 2002, WTI was
US$19.73 per barrel and strengthened to close the year at US$31.20 per barrel.
Low inventory levels in Europe kept the Brent/WTI differential narrow throughout
most of the year. Given that our Masila crude tends to price off Brent, the
Masila differential remained narrow along with the Brent/WTI spread. The heavy
oil differential was narrow due to the unexpected disruption of heavy oil supply
from Venezuela late in 2002. Lower natural gas prices reduced net income by $113
million. Natural gas prices fell in the first part of 2002 as inventories were
high, but increased late in the year as cold weather hit the eastern US.

<TABLE>
<CAPTION>
OPERATING COSTS

(Cdn$/boe)                                    2003                            2002                             2001
-----------------------------------------------------------------------------------------------------------------------------
                                       Before         After          Before            After          Before           After
                                    Royalties(1)  Royalties       Royalties(1)     Royalties       Royalties(1)    Royalties
                                 --------------------------------------------------------------------------------------------
<S>                                 <C>           <C>             <C>              <C>             <C>             <C>
Conventional Oil and Gas
    Yemen                                2.16          4.37            1.95             4.13            1.62            3.47
    Canada                               6.00          7.76            5.70             7.45            4.87            5.82
    United States                        4.49          5.19            9.09            10.87            6.01            7.31
    Australia                           18.60         20.21            9.76            12.14           13.50           14.38
    Other Countries                      7.47          9.01            6.21            10.69            8.07            9.94
    Average Conventional                 4.17          6.24            4.60             7.24            3.92            5.88
                                 --------------------------------------------------------------------------------------------

Synthetic Crude Oil
    Syncrude                            21.96         22.18           18.10            18.21           19.43           20.29
Average Oil and Gas                      5.19          7.56            5.42             8.26            4.88            7.10
                                 --------------------------------------------------------------------------------------------
</TABLE>

Note:

(1)  Operating costs per boe are our total oil and gas operating costs divided
     by our working interest production before royalties. We use production
     before royalties to monitor our performance consistent with other Canadian
     oil and gas companies.


                                       15
<PAGE>

2003 VS 2002 - LOWER OIL AND GAS OPERATING COSTS INCREASED NET INCOME BY
$23 MILLION

Conventional unit operating costs decreased with the addition of low-cost
production from Aspen in the Gulf of Mexico and the strengthening of the
Canadian dollar relative to the US dollar. Increased workover and maintenance
activity in Yemen and higher water handling costs in Canada partially offset
this decrease.

Low-cost Aspen production reduced US operating costs by 50% and lowered our
corporate average unit operating costs by approximately $0.40 per boe. Aspen
production costs are about $1.05 per boe, $3.12 per boe lower than our corporate
average for conventional production as most of the costs in our deep-water are
capital related. Gunnison will produce at similar attractive operating costs.

The strengthening Canadian dollar decreased US-dollar denominated operating
costs, lowering our corporate average unit operating costs by approximately
$0.25 per boe. Higher repairs, increased maintenance and workover activity
resulted in a US$0.40 per barrel increase in Yemen operating costs. We expect
ongoing maintenance and workover activities at Masila to keep operating costs
around US$1.70 per barrel. As well, unit operating costs offshore Australia and
Nigeria increased as fixed costs were spread over declining production volumes.

Syncrude operating costs increased 21% due to higher natural gas input costs and
increased turnaround and maintenance activity in 2003. Lower volumes also
increased unit operating costs as more than 95% of the operating costs are
fixed.


2002 VS 2001 - HIGHER OIL AND GAS OPERATING COSTS REDUCED NET INCOME BY
$58 MILLION

Conventional operating costs increased $0.68 per equivalent barrel due to
industry cost pressures in Canada, increased workover and repair activity on the
shelf in the Gulf of Mexico and increased water-handling and waterflood costs in
Yemen. As well, weather-related shut-ins and storm damage in the Gulf of Mexico
and one time flood-related costs in Yemen contributed to the increase. In
Australia, per-unit operating costs decreased significantly as fixed costs were
spread over more barrels.

<TABLE>
<CAPTION>
DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A)

(Cdn$/boe)                                   2003                             2002                             2001
-----------------------------------------------------------------------------------------------------------------------------
                                       Before         After          Before            After          Before           After
                                    Royalties(2)  Royalties       Royalties(2)     Royalties       Royalties(2)    Royalties
                                 --------------------------------------------------------------------------------------------
Conventional Oil and Gas
<S>                                 <C>           <C>             <C>              <C>             <C>             <C>
    Yemen                                3.96          8.03            3.47             7.34            2.56            5.48
    Canada (1)                           9.10         11.76            8.22            10.72            7.14            8.53
    United States                       10.80         12.47           12.74            15.38           10.59           12.85
    Australia                           13.31         14.46           10.45            12.99           16.61           17.69
    Other Countries                     17.09         22.47           13.22            22.90           15.11           18.62
    Average Conventional                 7.37         11.04            6.84            10.81            5.97            8.98
                                 --------------------------------------------------------------------------------------------

Synthetic Crude Oil
    Syncrude                             2.50          2.53            2.13             2.17            2.03            2.13
Average Oil and Gas                      7.09         10.33            6.55            10.01            5.73            8.40
                                 --------------------------------------------------------------------------------------------
</TABLE>

Notes:

(1)  DD&A per boe excludes the impairment charge described in Note 4 of the
     Consolidated Financial Statements.

(2)  DD&A per boe is our DD&A for oil and gas operations divided by our working
     interest production before royalties. We use production before royalties to
     monitor our performance consistent with other Canadian oil and gas
     companies.


2003 VS 2002 - HIGHER OIL AND GAS DD&A REDUCED NET INCOME BY $327 MILLION

Conventional depletion rates increased with higher 2002 finding and development
costs and our changing production mix, as more capital-intensive properties like
Aspen contribute growing volumes. These properties, however, deliver
higher-margin returns making them a valuable part of our portfolio. We also
experienced higher depletion rates offshore Nigeria and Australia, as we prepare
to abandon these fields in 2004.

The strengthening Canadian dollar offset these increases as our depletion from
International and the US is denominated in US dollars. This lowered our
corporate average rate by approximately $0.48 per boe.

Our DD&A expense for 2003 includes an impairment charge of $269 million ($175
million after-tax) largely attributable to reserve revisions to Canadian heavy
oil properties. These reserve revisions were the result of changes to late
field-life assumptions with respect to estimated future operating costs, changes
to proved undeveloped reserves based on drilling results and geological mapping
and reassessments of future estimated production profiles.


                                       16
<PAGE>

2002 VS 2001 - HIGHER OIL AND GAS DD&A REDUCED NET INCOME BY $80 MILLION

Conventional depletion rates increased with higher 2001 finding and development
costs in Canada, Yemen and the Gulf of Mexico and our changing production mix. A
decrease in rates in Australia, resulting from successful infill drilling,
partially offset these increases.

<TABLE>
<CAPTION>
EXPLORATION EXPENSE

(Cdn$ millions)                                               2003        2002         2001
--------------------------------------------------------------------------------------------
<S>                                                           <C>         <C>          <C>
Seismic                                                         62          75           77
Unsuccessful Drilling                                           70          61          133
Other                                                           68          45           50
                                                           ---------------------------------
Total Exploration Expense                                      200         181          260
                                                           =================================

Total Exploration Capital                                      329         259          411

Exploration Expense as a % of Exploration Capital (%)           61          70           63
                                                           ---------------------------------
</TABLE>

2003 VS 2002 - HIGHER EXPLORATION EXPENSE REDUCED NET INCOME $19 MILLION

Exploration expense grew consistent with an increase in our 2003 exploration
capital spending. Overall, our exploration program delivered excellent results
from the Gulf of Mexico, OPL-222 offshore Nigeria and Block 51 in Yemen.

Dry hole and seismic costs in the Gulf of Mexico accounted for over 40% of our
exploration expense. Exploration in the Gulf yielded some promising results at
Shiloh. At Shiloh, we found hydrocarbons but not commercial quantities, so the
well costs were written off. We still plan to actively pursue this prospect,
have acquired additional acreage in the area and hope to prove-up commercial
quantities in the region. We were unsuccessful at Santa Rosa but continue to
pursue opportunities in the area.

Dry hole costs also included three wells in the Alberta foothills of Canada, the
Andino-1 well in Colombia, the Escargot well offshore Brazil and the HEK well in
Yemen on Block 51. In addition, we acquired seismic over a number of prospects.


2002 VS 2001 - LOWER EXPLORATION EXPENSE ADDED $79 MILLION TO NET INCOME

Exploration expense was lower in 2002 as we spent less on exploration capital,
focusing our efforts on developing earlier exploration successes. Unsuccessful
exploration wells included Block 59 in Yemen, Fusa in Colombia, Block BC-20
offshore Brazil and Fergana in the Gulf of Mexico.

<TABLE>
<CAPTION>
OIL AND GAS MARKETING

(Cdn$ millions)                                                                         2003           2002            2001
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                                    <C>            <C>            <C>
    Revenue                                                                              568            496            438
    Transportation                                                                      (398)          (423)          (342)
    Other                                                                                 (1)            --             --
                                                                                    ----------------------------------------
Net Revenue                                                                              169             73             96
                                                                                    ========================================

Marketing contribution to Income from Continuing Operations before Income Tax            111             35             59
                                                                                    ----------------------------------------

Physical Sales Volumes (excluding intra-segment transactions)
    Crude Oil (mboe/d)                                                                   479            412            400
    Natural Gas (mmcf/d)                                                               3,301          2,865          2,499

Value-at-Risk
    Year-end                                                                              21             19             19
    High                                                                                  31             28             24
    Low                                                                                   14             12              6
    Average                                                                               20             17             13
                                                                                    ----------------------------------------
</TABLE>


                                       17
<PAGE>

2003 VS 2002 - RECORD NET MARKETING REVENUE INCREASED NET INCOME BY $96 MILLION

Marketing delivered record financial results growing their cash flow by 132%
over 2002. This achievement was driven primarily by exceptional results from our
gas marketing and trading group, supplemented by steady profits from our crude
oil trading and marketing group.

Our natural gas group successfully positioned themselves to benefit from price
differences between western Canada and eastern North America, and between summer
and winter months. We also added transportation and storage capacity to our
contract base. Added transportation capacity allowed us to take advantage of
price differences between receipt and delivery points while added storage
allowed us to take advantage of varying seasonal demand in the summer and winter
months.

The continued exit of competitors from the market in 2003 enabled us to acquire
contracts on favourable terms, including storage and transportation contracts
and natural gas contracts.

We also successfully mitigated earlier volatility related to our storage
positions by implementing a hedge accounting strategy. Until October 25, 2002,
mark-to-market gains on our storage positions were included in net income. New
accounting rules required us to exclude these gains from our results in 2003
until the inventory was sold despite having futures contracts in place that
locked-in the profit on our stored volumes. At the beginning of the third
quarter, we designated certain futures contracts as accounting hedges of the
future sale of our stored volumes. As a result, recognition of the
mark-to-market gain or loss on the futures contracts is deferred until the
inventory is sold. See Note 5 to the Consolidated Financial Statements for
further details.


2002 VS 2001 - LOWER NET MARKETING REVENUE REDUCED NET INCOME BY $23 MILLION

Marketing delivered solid results in 2002 despite having fewer opportunities.
Less price volatility in 2002 resulted in smaller margins. This was offset
somewhat by an increase in our marketed volumes, as there were fewer competitors
in the market.

COMPOSITION OF NET MARKETING REVENUE

(Cdn$ millions)                                             2003         2002
------------------------------------------------------------------------------

Derivative Energy Contracts                                  148           58
Non-Derivative Energy Contracts                               21           15
                                                     -------------------------
                                                             169           73
                                                     =========================

DERIVATIVE ENERGY CONTRACTS

Our marketing operation engages in crude oil and natural gas marketing
activities to enhance prices from the sale of our own production, and for energy
marketing and trading. We enter into contracts to purchase and sell crude oil
and natural gas. These contracts expose us to commodity price risk between the
time contracted volumes are purchased and sold. We actively manage this risk by
using physical purchases and sales, energy-related futures, forwards, swaps and
options, and by balancing physical and financial contracts in terms of volumes,
timing of performance and delivery obligations. However, net open positions may
exist, or we may establish them to take advantage of market conditions.

Consistent with our management practices, we account for all derivative energy
contracts that are not designated as a hedge using mark-to-market accounting,
and record the net gain or loss from their revaluation in marketing and other
income. The fair value of these instruments is recorded as accounts receivable
or payable. They are classified as long-term or short-term based on their
anticipated settlement date.

We value derivative energy trading contracts daily using:

o    actively quoted markets such as the New York Mercantile Exchange and the
     International Petroleum Exchange; and
o    other external sources such as the Natural Gas Exchange, independent price
     publications and over-the-counter broker quotes.


                                       18
<PAGE>

FAIR VALUE OF DERIVATIVE ENERGY CONTRACTS

At December 31, 2003, the fair value of our derivative energy contracts not
designated as hedges totalled $106 million (2002 - $3 million). The following
table shows the valuation methods underlying these contracts together with
details of contract maturity:

<TABLE>
<CAPTION>
(Cdn$ millions)                                                                        MATURITY
------------------------------------------------------------------------------------------------------------------------------
                                                         Less than                                      More than
                                                          one year       1-3 years       4-5 years        5 years       Total
                                                        ----------------------------------------------------------------------
<S>                                                      <C>             <C>             <C>            <C>             <C>
Prices
    Actively Quoted Markets                                     (9)             1               --            --           (8)
    From Other External Sources                                 77             30                9            (2)         114
    Based on Models and Other Valuation Methods                 --             --               --            --           --
                                                        ----------------------------------------------------------------------
Total                                                           68             31                9            (2)         106
                                                        ======================================================================
</TABLE>

More than 64% of the unrealized gain is related to contracts that will settle in
2004. Contract maturities vary from a single day up to six years. Those maturing
beyond one year are primarily from natural gas related positions. The relatively
short maturity position of our contracts lowers our portfolio risk.

At December 31, 2003, the unrecognized losses on our derivative energy contracts
accounted for as hedges of the future sale of our inventory totalled $11
million. The following table shows the valuation methods underlying these
contracts together with details of contract maturity:

<TABLE>
<CAPTION>
(Cdn$ millions)                                                                        MATURITY
------------------------------------------------------------------------------------------------------------------------------
                                                         Less than                                      More than
                                                          one year       1-3 years       4-5 years        5 years       Total
                                                        ----------------------------------------------------------------------
<S>                                                      <C>             <C>             <C>            <C>             <C>
Price
    Actively Quoted Markets                                    (11)            --               --            --          (11)
    From Other External Sources                                 --             --               --            --           --
    Based on Models and Other Valuation Models                  --             --               --            --           --
                                                        ----------------------------------------------------------------------
Total                                                          (11)            --               --            --          (11)
                                                        ======================================================================
</TABLE>

Our accounting policy does not permit us to record income on transportation and
storage contracts using option valuation methods.

<TABLE>
<CAPTION>
CHANGES IN FAIR VALUE OF DERIVATIVE ENERGY CONTRACTS

                                                                                                   Contracts
                                                               Contracts        Contracts       Entered into
                                                          Outstanding at     Entered into        During Year
                                                            Beginning of       and Closed    and Outstanding
(Cdn$ millions)                                                     Year      During Year     at End of Year         Total
---------------------------------------------------------------------------------------------------------------------------
<S>                                                       <C>                <c>             <c>                 <C>
Fair Value at December 31, 2002                                        3               --                 --             3
Change in Fair Value of Contracts                                      6               53                 89           148
Net Losses (Gains) on Contracts Closed                                 2              (53)                --           (51)
Derivative Energy Contracts Acquired                                  --               --                  6             6
Changes in Valuation Techniques and Assumptions 1                     --               --                 --            --
                                                          -----------------------------------------------------------------
Fair Value at December 31, 2003                                       11               --                 95           106
                                                          -----------------------------------------------------------------
Unrecognized Losses on Hedges of Future Sale
    of Inventory at December 31, 2003                                 --               --                (11)          (11)
                                                          -----------------------------------------------------------------
Total Outstanding at December 31, 2003                                11               --                 84            95
                                                          =================================================================
</TABLE>

Note:

(1)  Our valuation methodology has been applied consistently year over year.


                                       19
<PAGE>

<TABLE>
<CAPTION>
TOTAL CARRYING VALUE OF DERIVATIVE ENERGY CONTRACTS

(Cdn$ millions)                                                                                        2003            2002
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                                            <C>              <C>
Current Assets                                                                                          102              42
Non Current Assets                                                                                       63              14
                                                                                               -----------------------------
   Total Derivative Energy Contract Assets                                                              165              56
                                                                                               =============================

Current Liabilities                                                                                      34              46
Non Current Liabilities                                                                                  25               7
                                                                                               -----------------------------
   Total Derivative Energy Contract Liabilities                                                          59              53
                                                                                               =============================

Total Derivative Energy Contract Net Assets (1)                                                         106               3
                                                                                               =============================
</TABLE>

Note:

(1)  Does not include effective hedges. We recognize gains and losses on
     effective hedges in the same period as the hedged item.

Unrecognized losses on forward contracts for the future sale of oil and gas
production are disclosed in Note 5 of the Consolidated Financial Statements.


NON-DERIVATIVE ENERGY CONTRACTS

We enter into fee for service contracts related to transportation and storage of
third party oil and gas. We also earn income from our power generation facility.
We earned $21 million from our non-derivative energy activities in 2003 (2002 -
$15 million).


<TABLE>
<CAPTION>
CHEMICALS

(Cdn$ millions)                                                                         2003           2002            2001
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                                  <C>             <C>            <C>
Net Sales                                                                                375            367            373
Sales Volumes (thousand short tons)
    Sodium chlorate                                                                      478            454            457
    Chlor-alkali                                                                         396            375            365

Operating Profit (1)                                                                      95            100             99
Operating Margin (%)                                                                      25             27             27

Chemicals contribution to Income from Continuing Operations before Income Taxes           28             27             47

Capacity Utilization (%)                                                                  95             85             89
                                                                                     ---------------------------------------
</TABLE>

Note:

(1)  Total revenues less operating costs, transportation and other.


2003 VS 2002 - LOWER CHEMICALS OPERATING PROFIT REDUCED NET INCOME BY $5 MILLION

Many of the challenges we successfully managed in 2002 were replaced with new
challenges in 2003. Strong North American demand for chlor-alkali and sodium
chlorate helped boost sales volumes and prices in 2003. In North America, we
manufacture our products in Canada. Most of our sales, however, are into US
markets. As the Canadian dollar strengthened, our US-dollar denominated revenues
declined, lowering our operating profit by $13 million.

Higher natural gas prices in North America put pressure on electricity costs. To
deal with these cost pressures, we idled our Taft plant, our highest electricity
cost facility, and relocated the assets to Brandon. Our cost savings from idling
the plant were offset by product we purchased from other suppliers to satisfy
southeastern US customers. Once the assets are installed at Brandon, we expect
the savings to flow to our bottom line. The installation of the Taft assets at
Brandon should be completed in 2004 eliminating our need for purchased product.


2002 VS 2001 - CHEMICALS OPERATING PROFIT ADDS $1 MILLION TO NET INCOME

We faced many challenges in 2002. Slow economic recovery in North America placed
downward pressure on sodium chlorate volumes and eroded market prices. Also,
increasing energy costs in Louisiana put pressure on our Taft plant.

During 2002, margins remained strong due to lower overall energy costs and the
shifting of production from higher-cost to lower-cost facilities following the
expansion of our Brandon and Brazil facilities. The expansion of these plants
increased our depreciation.


                                       20
<PAGE>

<TABLE>
<CAPTION>
CORPORATE EXPENSES

GENERAL AND ADMINISTRATIVE

(Cdn$ millions)                                                                         2003           2002            2001
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                                  <C>            <C>            <C>
General and Administrative Expenses                                                      190            152            136
                                                                                     ---------------------------------------
</TABLE>


2003 VS 2002 - HIGHER COSTS AND LOWER RECOVERIES REDUCED NET INCOME BY $38
MILLION

Approximately 75% of the G&A increase relates to higher variable compensation:

o    Record 2003 results increased bonus compensation by $16 million; and
o    Strong stock prices at year-end increased the value of our employee stock
     appreciation rights and related expense by $13 million.

The continued expansion of our marketing group also increased our staffing costs
in 2003.


2002 VS 2001 - HIGHER COSTS REDUCED NET INCOME BY $16 MILLION

Approximately 70% of the increase was due to higher staffing levels associated
with our record capital investment program and growth in our marketing
operations. The remainder resulted from increased pension expense due to poor
equity market performance, higher building lease costs and incremental expenses
associated with our stock appreciation rights plan.

<TABLE>
<CAPTION>
INTEREST

(Cdn$ millions)                                                                         2003           2002            2001
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                                  <C>             <C>            <C>
Interest                                                                                 148            140            112
    Less: Capitalized Interest                                                            43             31             --
                                                                                     ---------------------------------------
Net Interest Expense                                                                     105            109            112
                                                                                     =======================================

Effective Rate (%)                                                                       7.2            7.1            7.6
                                                                                     ---------------------------------------
</TABLE>


2003 VS 2002 - LOWER INTEREST EXPENSE INCREASED NET INCOME BY $4 MILLION

Total interest costs increased $20 million due to:

o    Full-year impact of our 30-year notes issued in March 2002, and;
o    US$960 million issuance of new fixed-rate debt in November 2003.

This increase was offset by the strengthening Canadian dollar, which lowered
our US-dollar denominated interest expense by $10 million.

Net interest expense decreased as capitalized interest related to major
development projects costs continued to grow. Capitalized interest is expected
to increase in 2004 as we proceed with major development projects at Long Lake
and Syncrude.


2002 VS 2001 - LOWER INTEREST EXPENSE ADDED $3 MILLION TO NET INCOME

Higher borrowing rate on our new 30-year notes increased interest costs by $28
million. We continued to capitalize interest on our major development projects
resulting in lower net interest expense.

<TABLE>
<CAPTION>
INCOME TAXES

(Cdn$ millions)                                                                         2003           2002            2001
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                                  <C>             <C>            <C>
Current                                                                                  210            223            216
Future                                                                                   (40)           (12)            67
                                                                                     ---------------------------------------
                                                                                         170            211            283
                                                                                     =======================================

Effective Rate (%)                                                                        22             34             40
                                                                                     ---------------------------------------
</TABLE>


                                       21
<PAGE>

2003 VS 2002 - EFFECTIVE TAX RATE DECLINES FROM 34% TO 22%

The 2003 effective tax rate fell primarily due to a reduction in tax rates for
Canadian resource activities that resulted in a recovery of future income taxes
of $76 million during the second quarter. The effective tax rate for 2004 is
expected to be 33%.

The majority of our 2003 current income taxes were paid in Yemen. Current taxes
include cash taxes in Yemen of $201 million (2002 - $207 million; 2001 - $191
million). During 2003 and 2002, federal and provincial capital taxes were
payable in Canada. In 2003, current income taxes also include alternative
minimum tax in the United States.


2002 VS 2001 - EFFECTIVE TAX RATE DECLINES FROM 40% TO 34%

Rate decreased due to:

o    lower federal and provincial statutory tax rates for Canadian non-oil and
     gas operations;
o    higher portions of income coming from international operations where rates
     are lower; and
o    non-taxable capital gain on the sale of our Moose Jaw operations.


GAIN OR LOSS ON DISPOSITION OF ASSETS

There was no gain or loss on the 2003 sale of our southeast Saskatchewan
properties as described in Note 9 to the Consolidated Financial Statements. The
net loss in 2002 includes a gain of $13 million on the sale of our asphalt
operation in Moose Jaw, Saskatchewan and a loss of $21 million on the sale of a
non-operated property by our Canadian oil and gas business segment.

<TABLE>
<CAPTION>
OTHER INCOME

(Cdn$ millions)                                                                         2003           2002            2001
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                                  <C>             <C>            <C>
Foreign Exchange Gain (Loss)                                                               6             (3)            --
Business Interruption Insurance Proceeds                                                  12             --             --
Interest Income                                                                            9              7             17
Other                                                                                     15              4             20
                                                                                     ---------------------------------------
                                                                                          42              8             37
                                                                                     =======================================
</TABLE>

The business interruption insurance proceeds received in 2003 relate to damage
sustained in the Gulf of Mexico during tropical storm Isidore and hurricane Lili
in the third and fourth quarters of 2002.


OUTLOOK FOR 2004

Our largest ever-capital program of $1.8 billion will focus on advancing our
major development programs and high-quality exploration in four key basins. Our
solid capital structure and surplus liquidity will support this program. In
2004, we plan to invest almost $1.7 billion in oil and gas with:

o    35% in core assets to maintain existing production levels;
o    45% in new growth development projects, and;
o    20% in new growth exploration projects.

Details of our 2004 capital investment program are included in the Capital
Investment section in the MD&A. This program is consistent with our strategy to
grow reserves and production primarily through the drill bit.


                                       22
<PAGE>

DAILY PRODUCTION

Approximately 45% of our cash flow from core assets will be reinvested in those
assets to deliver production between 255,000 and 275,000 boe per day in 2004.
The remaining 55% of cash flow will be invested in new growth projects.

<TABLE>
<CAPTION>
                                                                   2004 ESTIMATED PRODUCTION
                                                           ---------------------------------------
(mboe/d)                                                  BEFORE ROYALTIES        AFTER ROYALTIES
--------------------------------------------------------------------------------------------------
<S>                                                        <C>                    <C>
Gulf of Mexico (1)                                               60  -  65               55 -  57
Yemen, Masila                                                   110  - 118               58 -  62
Canada Conventional (2)                                          57  -  65               46 -  53
Syncrude                                                         16  -  18               16 -  17
Other International                                               7  -   9                6 -   8
                                                           ----------------=----------------------
Total                                                           255  - 275              180 - 195
                                                           =======================================
</TABLE>

Notes:

(1)  US natural gas production is estimated to comprise 45% of total US
     equivalent production in 2004.
(2)  Canadian natural gas production is estimated to comprise 33% of total
     Canadian equivalent production in 2004.

Our net production growth will be modest in 2004, as over half our cash flow is
invested in major growth projects coming on-stream in 2005 and beyond. Many of
these projects have low or no royalties, lower costs and ultimately higher
returns than our current producing assets. This changing production mix will
improve profitability, even if oil prices trend lower.

We expect to generate around $1.3 billion in cash flow from operations in 2004
assuming the following:

<TABLE>
-------------------------------------------------------------------------------------------------
<S>                                                                                       <C>
WTI (US$/bbl)                                                                              25.00
NYMEX natural gas (US$/mmbtu)                                                               4.25
US to Canadian dollar exchange rate                                                         0.75

Changes in actual commodity prices and exchange rates will impact our annual
cash flow from operations as follows:

<CAPTION>
(Cdn$ millions)
-------------------------------------------------------------------------------------------------
<S>                                                                                       <C>
WTI - US $1 change                                                                            53
NYMEX natural gas - US $0.50 change                                                           60
Exchange rate - $0.01 change                                                                  21
</TABLE>

In a price-neutral environment, cash flow from operations would grow by
approximately 10% over 2003 and we would see 11% growth in our corporate cash
netback.

In addition to strong cash flow from our oil & gas operations, we expect solid
performance from our chemicals and marketing businesses in 2004. Our chemicals
operations anticipate improved cash flow from growing production and lower unit
costs as we continue to consolidate production at our low-cost facility in
Brandon. Our marketing group also anticipates another profitable year as they
continue to increase their presence in core markets in the US midwest and
eastern Canada.


LIQUIDITY

SOURCES AND USES OF CASH

Our business strategy is focused on value-based growth through full-cycle
exploration and development, supplemented by strategic acquisitions when
appropriate. We rely on operating cash flows to fund capital requirements and
provide liquidity. We build our opportunity portfolio to provide a balance of
short-term, mid-term, and longer-term growth. This enables us to generate
ongoing sustainable operating cash flows as shown below:

<TABLE>
<CAPTION>
(Cdn$ millions)                                                    2003           2002           2001        2000        1999
------------------------------------------------------------------------------------------------------------------------------
<S>                                                         <C>              <C>            <C>         <C>           <C>
Cash Flow from Operations                                         1,859          1,383          1,423       1,569         780
Capital Expenditures                                             (1,494)        (1,625)        (1,404)       (915)       (612)
                                                            ------------------------------------------------------------------
                                                                    365           (242)           19          654         168
                                                            ==================================================================

WTI (US$/bbl)                                                     31.04          26.09          25.97       30.21       19.24
NYMEX natural gas (US$/mmbtu)                                      5.60           3.37           4.00        4.31        2.31
                                                            ------------------------------------------------------------------
</TABLE>


                                       23
<PAGE>

The capital investment in our oil and gas operations is primarily funded by our
cash flow from operations. Although this spending is mostly discretionary, we
rely on prudent capital investment to generate future operating cash flows.
Given the long cycle time of some of our development projects, particularly
internationally, and the volatility of commodity prices, it is not unusual, in
any given year for capital expenditures to exceed our cash flow.

In 1998 and 1999, commodity prices were low and we reduced our capital
investment. In 2000, commodity prices improved, allowing us to generate
sufficient cash flow from operations to buy back 20 million common shares. In
2001 and 2002, we began to invest significantly in two deep-water Gulf of Mexico
prospects (Aspen and Gunnison), our Syncrude expansion and our Long Lake
project. In 2003, Aspen contributed significantly to our cash flow from
operations and in 2004, we expect additional significant contributions from
Gunnison. We anticipate cash flows from the Syncrude expansion and Long Lake to
commence in 2006 and 2007, respectively.

Given the cyclical nature of the upstream oil and gas business, we manage our
capital structure so that we are well positioned from a liquidity perspective
throughout both positive and negative commodity price cycles. Our capital
structure is characterized by a modest level of absolute debt, a long term to
maturity and undrawn committed credit facilities.

<TABLE>
<CAPTION>
CAPITAL STRUCTURE

(Cdn$ millions)                                                                               2003          2002
-----------------------------------------------------------------------------------------------------------------
<S>                                                                                      <C>             <C>
Bank Debt                                                                                       --            --
Senior Public Debt                                                                           2,776         1,844
                                                                                     -----------------------------
                                                                                             2,776         1,844
Less: Cash                                                                                   1,087            59
Less: Non-Cash Working Capital (1)                                                             312            10
                                                                                     -----------------------------
Net Debt (2)                                                                                 1,377         1,775
Preferred and Subordinated Securities                                                          364           724
                                                                                     -----------------------------
Net Debt, including Preferred and Subordinated Securities                                    1,741         2,499
                                                                                     =============================

Shareholders' Equity (3),(4)                                                                 2,418         2,348
                                                                                     ============== ==============
</TABLE>

Notes:

(1)  Excludes current portion of long-term debt.
(2)  Long-term debt less net working capital.
(3)  Included in shareholders' equity are preferred and subordinated securities
     of $364 million (2002 - $724 million). Under US generally accepted
     accounting principles, these are considered long-term debt.
(4)  At January 31, 2004, there were 126,738,410 common shares and US$460
     million of unsecured subordinated securities outstanding. These
     subordinated securities may be redeemed by the issuance of common shares at
     our option after November 8, 2008. The number of shares to be issued will
     depend upon the common share price on the redemption date.

We significantly enhanced our capital structure in 2003:

<TABLE>
<S>                                                     <C>
SHAREHOLDERS' EQUITY                                    Continued to strengthen with record net income in 2003.

US$500 MILLION OF 5.05% DEBT                            Issued in November 2003 and maturing in 10 years. Proceeds were used to
                                                        repay US$225 million of long term debt early in February 2004, and to fund
                                                        a portion of our 2004 capital investment program.

US$460 MILLION OF 7.35% SUBORDINATED DEBENTURES         Issued in November 2003 and maturing in 40 years. Proceeds were partially
                                                        used to redeem our 2047 preferred securities in December 2003 and our 2048
                                                        preferred securities in early February 2004.

COMMITTED BANK FACILITIES OF $1,656 MILLION             All undrawn at year-end with 75% of the facilities available to the end of
                                                        2008 and the remainder to the end of 2007.

US$1 BILLION UNIVERSAL DEBT SHELF PROSPECTUS            Available until October 2005 in the US and Canada.

FAVOURABLE DEBT MATURITIES                              Pre-financed our 2004 debt maturity. Our remaining maturities over the
                                                        next five years are minimal. The average term to maturity of our debt is
                                                        20 years.
</TABLE>


                                       24
<PAGE>

<TABLE>
<CAPTION>
CHANGE IN WORKING CAPITAL

                                                                                                                  INCREASE/
(Cdn$ millions)                                                                           2003          2002     (DECREASE)
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>              <C>         <C>
Cash and Short-Term Investments                                                          1,087            59         1,028
Accounts Receivable                                                                      1,423           988           435
Inventories and Supplies                                                                   270           256            14
Accounts Payable and Accrued Liabilities                                                (1,404)       (1,194)         (210)
Other                                                                                       23           (40)           63
                                                                                    ----------------------------------------
                                                                                         1,399            69         1,330
                                                                                    ========================================
</TABLE>

Cash and short-term investments increased with our fourth quarter financing
activities. We received proceeds of US$960 million when we issued US$500 million
of notes and US$460 million of subordinated debentures in November 2003. We used
US$701 million of this cash to redeem US$259 million of preferred securities in
December 2003, US$217 million of preferred securities in early February 2004 and
US$225 million of senior notes in early February 2004. Accounts receivable
increased in part because there was no sale of receivables at the end of 2003
compared to the sale of $178 million at the end of 2002. The remainder of the
increase was due to higher commodity prices and growth in our marketing business
offset by the strengthening of the Canadian dollar relative to the US dollar.

The increase in other was related to the prepayment of natural gas storage
inventory in December.


NET DEBT

Our net debt levels are directly related to our operating cash flows and our
capital expenditure activities. During the year, we successfully reduced net
debt, including preferred and subordinated securities, by $758 million:

<TABLE>
<CAPTION>
(Cdn$ millions)                                                                           2003          2002
-------------------------------------------------------------------------------------------------------------
<S>                                                                                   <C>            <C>
Capital Expenditures                                                                     1,494         1,625
Cash Flow from Operations                                                               (1,859)       (1,383)
                                                                                    -------------------------
                                                                                          (365)          242
Dividends on Preferred Securities and Common Shares                                        104           109
Foreign Exchange Translation of US-dollar Debt and Cash                                   (281)           --
Proceeds on Disposition of Assets                                                         (293)          (49)
Issue of Common Shares                                                                      73            51
Other                                                                                        4           (38)
                                                                                    -------------------------
Increase (Decrease) in Net Debt, including Preferred and Subordinated Securities          (758)          315
                                                                                    =========================
</TABLE>

The reduction in net debt has a positive impact on our leverage metrics:

<TABLE>
<CAPTION>
                                                                                          2003          2002           2001
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>             <C>          <C>
Net Debt, including Preferred Securities and Subordinated Securities,
    to Cash Flow (1) (times)                                                               1.0           1.9            1.6
Interest Coverage (2) (times)                                                             13.3          10.7           13.7
Fixed Charge Coverage (3) (times)                                                          9.5           7.2            8.4
                                                                                    ----------------------------------------
</TABLE>

Notes:

(1)  Cash flow comprises cash flow from operations after dividends on Preferred
     Securities.

(2)  Cash flow from operations before interest expense divided by total
     interest.

(3)  Cash flow from operations before interest expense divided by total interest
     plus dividends on Preferred Securities.

Our net debt and preferred securities are equal to 1.0 times our 2003 cash flow
from operations after dividends on preferred securities. This, together with our
coverage ratios, provides us with sufficient financial flexibility and liquidity
to pursue our business strategy.


                                       25
<PAGE>

FUTURE LIQUIDITY

Our future liquidity is primarily dependent on cash flows generated from our
operations, our capital investment programs and the flexibility of our capital
structure. Assuming WTI of US$25 per bbl for 2004, we expect our 2004 capital
investment program and dividend requirements to exceed our cash flow from
operations by almost $550 million.

Our cash flow from operations is sensitive to changes in commodity prices and
exchange rates. For 2004, we expect cash flow from operations of $1.3 billion,
assuming the following:

-------------------------------------------------------------------------------
WTI (US$/bbl)                                                            25.00
NYMEX natural gas (US$/mmbtu)                                             4.25
US to Canadian dollar exchange rate                                       0.75

Changes in commodity prices and exchange rates will impact our cash flow from
operations and our borrowing requirements. The impact of a variance, in any one
of the above assumptions, on our cash flow from operations is described in the
Outlook for 2004 section in the MD&A.

If we change our capital investment program, we may draw more or less on our
cash balances and our available facilities. We are currently entering a 4-year
period of investing in major development projects as we move forward with our
projects at Long Lake in Canada and on Block 51 in Yemen.

Given our stable operating cash flows, strong cash position and undrawn
committed credit facilities, we do not anticipate any problems in funding our
capital programs, dividend requirements, and debt repayments or in meeting the
obligations that arise from our day-to-day operations. In 2003, we declared
common share dividends of $0.325 per common share (2002 - $0.30, 2001 - $0.30).
We expect to declare common share dividends of $0.40 per common share in 2004.

CONTRACTUAL OBLIGATIONS, COMMITMENTS AND GUARANTEES

We have assumed various contractual obligations and commitments in the normal
course of our operations and financing activities. These obligations and
commitments have been considered when assessing our cash requirements in the
above discussion of future liquidity.

<TABLE>
<CAPTION>
(Cdn$ millions)                                                                  Payments (1)
------------------------------------------------------------------------------------------------------------------------------
                                                                  Less than                                         More than
                                                    Total            1 year         1-3 years     4-5 years           5 years
                                               -------------------------------------------------------------------------------
<S>                                            <C>                <C>               <C>           <C>               <C>
Long-Term Debt (1)                                     2,776             291               98           275             2,112
Preferred and Subordinated Securities (1)                364             331               --            --                33
Operating Leases (2)                                     217              33               58            35                91
Transportation and Storage Commitments (2)               580             212              172            85               111
Work Commitments                                          81              64               17            --                 -
Dismantlement and Site Restoration                       514              18               28            32               436
Other                                                      1               1               --            --                 -
                                               -------------------------------------------------------------------------------
Total                                                  4,533             950              373           427             2,783
                                               ===============================================================================
</TABLE>

Notes:

(1)  Payment obligations are not discounted and do not include related interest,
     accretion or dividends. At December 31, 2003, we had cash and short-term
     investments of $1,087 million.
(2)  Payments for operating leases and transportation commitments are deducted
     from our cash flow from operations.

Contractual obligations include both financial and non-financial obligations.
Financial obligations represent known future cash payments that we are required
to make under existing contractual arrangements, such as debt and lease
arrangements. Non-financial obligations represent contractual obligations to
perform specified activities such as work commitments. Commercial commitments
represent contingent obligations that become payable only if certain pre-defined
events occur.

o    Long-term debt amounts are included in our December 31, 2003 Consolidated
     Balance Sheet. The amount due in 2004 has been included in our current
     liabilities. Under US GAAP, $331 million of preferred securities and $33
     million of subordinated securities would be included in long-term debt.
o    Operating leases include leases for office space, rail cars, vehicles, the
     lease of the FPSO in Australia, and our processing agreement with Shell
     that allows our Aspen production to flow through Shell's processing
     facilities at the Bullwinkle platform. The terms of the processing
     agreement give Shell an annual option to take payment in cash or in kind.
     For 2004, Shell has elected to take payment in kind so the 2004 obligation
     has been excluded from this table.
o    Our marketing operation manages various natural gas transportation and
     storage commitments on behalf of our Canadian oil and gas business and a
     number of third-party customers.


                                       26
<PAGE>

o    Work commitments include non-discretionary capital spending related to
     drilling and seismic commitments in our international operations and
     development commitments at Syncrude. The remainder of our 2004 capital
     investment is discretionary.
o    We have $514 million of future dismantlement and site restoration
     obligations. As of December 31, 2003, $197 million of these obligations
     have been provided for on our balance sheet (including $18 million of
     current liabilities). The timing of any payments is difficult to determine
     with certainty and the table has been prepared using our best estimates.
o    We have unfunded obligations under our defined benefit pension and post
     retirement benefit plans of $84 million. Our unfunded obligation is $43
     million and our share of Syncrude's unfunded obligation is $41 million. Our
     $43 million obligation includes $29 million that is unfunded as a result of
     statutory limitations. These obligations are backed by letters of credit.
     During 2003, we contributed $16 million to our defined benefit pension
     plan. Post year-end positive equity markets have helped restore our defined
     benefit plan to a fully funded position.
o    We have excluded our normal purchase arrangements as they are discretionary
     and are reflected in our expected cash flow from operations and our capital
     expenditures for 2004.

From time to time we enter into contracts that require us to indemnify parties
against possible claims, particularly when these contracts relate to the sale of
assets. On occasion, we provide indemnifications to the purchaser. Generally, a
maximum obligation is not stated. Because the obligation is stated, the overall
maximum amount cannot be reasonably estimated. We have not made any significant
payments related to these indemnifications. Our Risk Management Committee
actively monitors our exposure to the above risks and obtains insurance coverage
to satisfy potential or future claims as necessary. We believe these matters
would not have a material adverse effect on our liquidity, financial condition
or results.

CREDIT RATINGS

Currently, our senior debt is rated BBB by Standard & Poor's, Baa2 by Moody's
Investor Service, Inc. and BBB by Dominion Bond Rating Service. In addition, all
rating agencies currently rate our outlook as stable. Our strong financial
results, ample liquidity and financial flexibility continue to support our
credit rating.

FINANCIAL ASSURANCE PROVISIONS IN COMMERCIAL CONTRACTS

The commercial agreements our marketing division enters into often include
financial assurance provisions that allow Nexen and our counterparties to
effectively manage credit risk. The agreements normally require posting
collateral (in the form of either cash or a letter of credit) if a buyer's
credit rating drops below investment grade, indicating their creditworthiness
has deteriorated. Based on the contracts in place and commodity prices at
December 31, 2003, we would be required to post collateral of $321 million if we
were downgraded to non-investment grade. This obligation is reflected in our
balance sheet. The posting of collateral merely accelerates the payment of such
amounts. Our committed undrawn credit facilities of $1.7 billion adequately
cover any potential collateral requirements. Just as we may be required to post
collateral in the event of a downgrade below investment grade, we have similar
provisions in many of our customer contracts that allow us to demand certain
customers post collateral with us if they are downgraded to non-investment
grade.

OFF-BALANCE SHEET ARRANGEMENTS

None.

CONTINGENCIES

See Note 10 to the Consolidated Financial Statements in Item 8, which is
incorporated herein by reference for a discussion of our contingencies.


                                       27
<PAGE>

BUSINESS RISK MANAGEMENT

The oil and gas industry is highly competitive, particularly in the following
areas:

o    searching for and developing new sources of crude oil and natural gas
     reserves;
o    constructing and operating crude oil and natural gas pipelines and
     facilities; and
o    transporting and marketing crude oil, natural gas and other petroleum
     products.

Our competitors include major integrated oil and gas companies and numerous
other independent oil and gas companies.

The pulp and paper chemicals market is also highly competitive. Key success
factors are:

o    price and product quality; and
o    logistics and reliability of supply.

We are one of the largest producers of sodium chlorate in North America and have
continent-wide supply capability.


OPERATIONAL RISK

Acquiring, developing and exploring for oil and natural gas involves many risks.
These include:

o    encountering unexpected formations or pressures;
o    premature declines of reservoirs;
o    blow-outs, well bore collapse, equipment failures and other accidents;
o    craterings and sour gas releases;
o    uncontrollable flows of oil, natural gas or well fluids;
o    adverse weather conditions; and
o    environmental risks.

Although we maintain insurance according to customary industry practice, we
cannot fully insure against all of these risks. Losses resulting from the
occurrence of these risks may have a material adverse impact.

Our future crude oil and natural gas reserves and production, and therefore our
operating cash flows and results of operations, are highly dependent upon our
success in exploiting our current reserve base and acquiring or discovering
additional reserves. Without reserve additions, our existing reserves and
production will decline over time as reserves are produced. The business of
exploring for, developing or acquiring reserves is capital intensive. If cash
flow from operations is insufficient and external sources of capital become
limited or unavailable, our ability to make the necessary capital investments to
maintain and expand our oil and natural gas reserves could be impaired.


UNCERTAINTY OF RESERVE ESTIMATES

Oil and gas reserves are integral to assessing our expected future financial
performance, preparing our financial statements and making investment decisions.
There are numerous uncertainties inherent in estimating quantities of proved oil
and natural gas reserves, including many factors beyond our control. The
reserves included in this Form 10-K represent estimates only.

To estimate the economically recoverable oil and natural gas reserves and
related future net cash flows, we incorporate many factors and assumptions
including:

o    expected reservoir characteristics based on geological, geophysical and
     engineering assessments;
o    future production rates based on historical performance and expected future
     operating and investment activities;
o    future oil and gas prices and quality differentials;
o    assumed effects of regulation by governmental agencies; and
o    future development and operating costs.

We believe these factors and assumptions are reasonable based on the information
available to us at the time we prepared the estimates. However, actual results
could vary considerably, which could cause material variances in:

o    estimated quantities of proved oil and natural gas reserves in aggregate
     and for any particular group of properties;
o    reserve classification based on risk of recovery;
o    future net revenues, including production, revenues, taxes, and development
     and operating expenditures; and
o    financial results including the annual rate of depletion and recognition of
     property impairments.


                                       28
<PAGE>

Management is responsible for estimating the quantities of proved oil and
natural gas reserves and preparing related disclosures. Estimates and related
disclosures are prepared in accordance with SEC requirements, generally accepted
industry practices in the US as promulgated by the Society of Petroleum
Engineers, and the standards of the Canadian Oil and Gas Evaluation Handbook
modified to reflect SEC requirements.

Reserve estimates for each property are prepared at least annually by the
property's reservoir engineer. They are reviewed by engineers familiar with the
property and by divisional management. Senior management, including our CEO, CFO
and Board-appointed internal qualified reserves evaluator, meet with divisional
reserves personnel to review the estimates and any changes from previous
estimates.

The internal qualified reserves evaluator assesses whether our reserves
estimates and the Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein, included in the Supplementary Financial Information, have been
prepared in accordance with our reserve standards. His opinion stating that the
reserves information has, in all material respects, been prepared according to
our reserves standards is included in an exhibit to Form 10-K.

We also have at least 80% of our reserve estimates audited annually by
independent qualified reserves consultants. Given that the reserves estimates
are based on numerous assumptions and interpretations, differences in estimates
prepared by us and an independent reserves consultant within 10% are considered
immaterial. Differences greater than 10% are resolved.

The Board of Directors has established a Reserves Review Committee (Reserves
Committee) to assist the Board and the Audit and Conduct Review Committee to
oversee the annual review of our oil and gas reserves and related disclosures.
The Reserves Committee is comprised of three or more directors, the majority of
whom are independent, and each being familiar with estimating oil and gas
reserves. The Reserves Committee meets with management periodically to review
the reserves process, results and related disclosures. The Reserves Committee
appoints and meets with each of the internal qualified reserves evaluator and
independent reserves consultants independent of management to review the scope
of their work, whether they have had access to sufficient information, the
nature and satisfactory resolution of any material differences of opinion, and
in the case of the independent reserves consultants, their independence.

The Reserves Committee has reviewed Nexen's procedures for preparing the reserve
estimates and related disclosures. It has reviewed the information with
management, and met with the internal qualified reserves evaluator and the
independent qualified reserves consultants. As a result of this, the Reserves
Committee is satisfied that the internally-generated reserves are reliable and
free of material misstatement. Based on the recommendation of the Reserves
Committee, the Board has approved the reserves estimates and related disclosures
in the Form 10-K.

The estimated discounted future net cash flows from estimated proved reserves
included in the Supplementary Financial Information in the Form 10-K are based
on prices and costs as of the date of the estimate. Actual future prices and
costs may be materially higher or lower. Actual future net cash flows will also
be affected by factors such as actual production levels and timing, and changes
in governmental regulation or taxation, and may differ materially from estimated
cash flows. See the Critical Accounting Estimates section of this MD&A where we
discuss the impact of changes in our reserve estimates.

POLITICAL RISK

We operate in numerous countries, some of which may be considered politically
and economically unstable. Our operations and related assets are subject to the
risks of actions by governmental authorities, insurgent groups or terrorists. We
conduct our business and financial affairs to protect against political, legal,
regulatory and economic risks applicable to operations in the various countries
where we operate. However, there can be no assurance that we will be successful
in protecting ourselves from the impact of these risks.

Our Masila operations are important to Yemen, providing 50% of the country's oil
production. We are a responsible member of the Yemeni community; we build
relationships with its members and involve them in key decisions that impact
their lives. We also ensure that they benefit from our presence in their country
beyond the revenue they receive from the production we operate. Our strong
relationship with the people and Government of Yemen has allowed us to operate
there without interruptions for almost 14 years and we anticipate this
continuing.

Our practices have enabled us to operate successfully, not only in Yemen, but
also in other parts of the world. We have developed excellent practices to
manage the risks successfully.

ENVIRONMENTAL RISK

Environmental risks inherent in the oil and gas and chemicals industries are
becoming increasingly sensitive as related laws and regulations become more
stringent worldwide. Many of these laws and regulations require us to remove or
remedy the effect of our activities on the environment at present and former
operating sites, including dismantling production facilities and remediating
damage caused by the disposal or release of specified substances.


                                       29
<PAGE>

We manage our environmental risks through a comprehensive and sophisticated
Safety, Environmental and Social Responsibility (SESR) Management System that
meets or exceeds ISO14001 criteria and those of similar management systems.
Overall guidance and direction is provided by the SESR Committee of the Board of
Directors. In addition, senior management, including the CEO and CFO, regularly
meets with SESR management to review and approve SESR policies and procedures,
provide strategic direction, review performance and ensure that corrective
action is taken when necessary. We develop and implement proactive and
preventative measures designed to reduce or eliminate future environmental
liabilities, we are prudent and responsible in our management of existing
environmental liabilities, and we continuously seek opportunities for
performance improvement. We also maintain an ongoing awareness of external
trends, demands, commitments, events or uncertainties that may reasonably have a
material effect on revenues from continuing operations. These actions provide
assurance that we meet or exceed appropriate environmental standards worldwide.

o    At December 31, 2003, $197 million has been provided in the Consolidated
     Financial Statements for future dismantlement and site restoration costs,
     currently estimated at $514 million for our oil and gas and chemicals
     facilities.
o    During 2003, we recorded a provision for future dismantlement and site
     restoration costs of $38 million (2002 - $43 million; 2001 - $45 million).
o    Actual site remediation expenditures for the year were $21 million (2002 -
     $20 million; 2001 - $24 million). We anticipate actual site remediation
     expenditures in 2004 to approximate 2003 levels.
o    We perform periodic internal and external assessments of our operations and
     adjust our estimates and annual provision accordingly.
o    During 2002, we conducted an external audit of our management system for
     safety, environment and social responsibility issues. In general, the
     review was very positive and the few minor recommendations for improvement
     are being implemented.
o    During 2003, we commenced an external operational audit to confirm whether
     our management system for safety, environment and social responsibility
     issues is actually being followed. This work is continuing into 2004, but
     initial reports are very positive.

CLIMATE CHANGE

The Kyoto Protocol, an agreement to reduce the concentration of certain man-made
gases (Green House Gases or GHG) that may be contributing to climate change, was
signed by approximately 160 countries since 1997. Canada ratified the Kyoto
Protocol in December 2002, but it will not come into effect until it is ratified
by Russia. The Kyoto Protocol obliges the Annex 1 countries to meet national
targets. Canada's target is an emission reduction of 6% below 1990 levels during
the First Commitment period of 2008 to 2012. Economic modeling studies have
shown that if emission reductions are met through domestic action in Annex I
countries alone, there will be severe negative impacts to those countries'
economies, and in particular those such as Canada whose economies are resource
and energy intensive. The US government's decision to withdraw from the Kyoto
Protocol has serious implications for Canada in the context of a continental or
hemispheric energy market.

The Canadian government has addressed the uncertainty around ratification and
implementation of the Kyoto Protocol by providing the oil and gas sector with
limits on cost (a cap of $15 per tonne) and volume (a cap of 55 megatonnes for
large industrial emitters) as well as its position on long-term high capital
cost projects. However, the government has yet to enact national legislation
that will detail the obligations of Canadian industry with respect to emission
reduction and management, and it is uncertain at this time when those
obligations will be determined. The financial markets have viewed these
developments favourably and have issued various analyses in the aftermath of
these announcements indicating that implementation of GHG-related legislation
should not adversely affect the development of new energy projects such as the
oilsands.

For years, Nexen has been assessing the impact of climate change developments on
our various business interests. We have created a senior management committee
(The Climate Change Steering Group) to: consider national and international
developments; hear from leading experts with respect to science, business and
risk issues; and, consider investment opportunities. As well, Nexen continues to
work closely with the Canadian and Alberta governments to assess the impact of
regulatory options and provide information on our business to assist governments
in their policy deliberations. Nexen maintains a wide range of business contacts
to ensure that a full slate of options is available to the corporation in order
to meet the obligations that may be imposed by future legislation.

Nexen is a Gold level reporter in Canada's Voluntary Challenge and Registry
(VCR); our 2002 VCR report includes the observation that we have voluntarily
reduced our direct emissions by almost 2 million tons of (CO2) equivalent since
we started reporting in 1996. As well, progress has been made toward reduction
of our energy inputs per unit of production. In 2003, we initiated another gas
gathering project in heavy oil. We are still assessing our 2003 performance and
it will be reported to the VCR.


                                       30
<PAGE>

Nexen has looked to GHG emission reduction and to offset investments. In 1995,
we started capturing, compressing and selling methane gas from our Canadian
heavy oil operation instead of venting it to the atmosphere. As a Canadian-based
international oil and gas exploration and production company, we have worked
closely with the Canadian Clean Development Mechanism/Joint Implementation
Office of the Department of Foreign Affairs and International Trade to ensure
that Canadian companies get access to low cost/high quality carbon offset
investments. Nexen has entered into discussions with the management of several
GHG investment pools and continues to evaluate the opportunities associated with
biological and geological sequestration of (CO2) and the capture of methane from
landfills. We continue to investigate carbon-offset opportunities in each of our
core countries in the belief that there may be synergies between our oil and gas
activities and carbon investments. We continuously review the feasibility of new
and ongoing projects with respect to current social, political and economic
factors and will continue to take into account the policy and requirements with
respect to GHG when conducting these reviews.

We are committed to the principles of full disclosure and will keep our
stakeholders apprised of how these issues affect us. Since emission levels
applicable to our business operations have not been determined and there are no
reliable estimates of the costs of achieving those levels, premature disclosure
would be speculative and any financial estimates would be based on arbitrary
assumptions of emission levels; however, Canadian government assurances of cost
and volume limits suggest that incremental risks and liabilities attributable to
addressing climate change policies are manageable. Finally, any indirect risks
and liabilities attributable to GHG are too remote and unquantifiable at this
time.

MARKET RISK MANAGEMENT

We are exposed to normal market risks inherent in the oil and gas and chemicals
business, including commodity price risk, foreign-currency rate risk, interest
rate risk and credit risk. We manage our operations to minimize our exposure, as
described in Note 5 to the Consolidated Financial Statements, which is
incorporated by reference here.

<TABLE>
<CAPTION>
SENSITIVITIES

(Cdn$ millions)                                                                               Cash Flow           Net Income
-----------------------------------------------------------------------------------------------------------------------------
<S>                                                                                           <C>                 <C>
Estimated 2004 impact:
    Crude Oil - US$1.00/bbl change in WTI                                                            53                   41
    Natural Gas - US$0.50/mcf change                                                                 60                   38
    Foreign Exchange - $0.01 change in US to Cdn Dollar                                              21                    9
                                                                                            ---------------------------------
</TABLE>

COMMODITY PRICE RISK

Commodity price risk related to conventional and synthetic crude oil prices is
our most significant market risk exposure. Crude oil prices and quality
differentials are influenced by worldwide factors such as OPEC actions,
political events and supply and demand fundamentals.

To a lesser extent we are also exposed to natural gas price movements. Natural
gas prices are generally influenced by oil prices and North American supply and
demand, and to a lesser extent local market conditions.

NON-TRADING ACTIVITIES

The majority of our production is sold under short-term contracts, exposing us
to short-term price movements. Other energy contracts we enter into also expose
us to commodity price risk between the time we purchase and sell contracted
volumes. From time to time, we actively manage these risks by using commodity
futures, forwards, swaps and options.

In March 2003, we sold WTI and NYMEX gas forward contracts for the next 12
months to lock-in part of the return on the remaining 40% interest acquired in
the Aspen field. The forward contracts fix our oil and gas prices at the
contract prices for the hedged volumes, less applicable price differentials as
follows:

<TABLE>
<CAPTION>
                                                                     Hedged                                           Average
                                                                    Volumes                        Term                 Price
------------------------------------------------------------------------------------------------------------------------------
                                                                                                                        (US$)
<S>                                                          <C>                <C>                             <C>
Fixed WTI Price                                                 5,000 bbls/d    April 2003 - March 2004             28.50/bbl
Fixed NYMEX Price                                            12,000 mmbtu/d     April 2003 - March 2004            5.35/mmbtu
</TABLE>

During 2002 and 2001, we purchased fixed-to-floating swaps to modify the terms
of certain fixed-price natural gas contracts as we prefer to receive an
index-based price for our natural gas. Under the terms of these contracts, we
were required to deliver four million cubic feet per day of natural gas to
counterparties at prices ranging from $3.06 to $6.08 per mcf. On settlement, we
received or paid cash for the difference between the contract and floating rates
on the affected volumes. These swaps expired in 2003.


                                       31
<PAGE>

MARKETING AND TRADING ACTIVITIES

Our marketing operation is involved in the marketing and trading of crude oil
and natural gas, through the use of both physical and financial contracts
(energy trading activities). These activities expose us to commodity price risk.
Open positions exist where not all contracted purchases and sales have been
matched, in order to take advantage of market movements. These net open
positions allow us to generate income, but also expose us to risk of loss due to
fluctuating market prices (market risk) and credit exposure. We control the
level of market risk through daily monitoring of our energy-trading portfolio
relative to:

o    prescribed limits for Value-at-Risk (VaR);
o    nominal size of commodity positions;
o    stop loss limits; and
o    stress testing.

VaR is a statistical estimate that is reliable when normal market conditions
prevail. Our VaR calculation estimates the maximum probable loss given a 95%
confidence level that we would incur if we were to unwind our outstanding
positions over a two-day period. We estimate VaR using the Variance-Covariance
method based on historical commodity price volatility and correlation inputs.
Our estimate is based upon the following key assumptions:

o    changes in commodity prices are normally distributed;
o    price volatility remains stable; and
o    price correlation relationships remain stable.

If a severe market shock occurred, the key assumptions underlying our VaR
estimate could be violated and the potential loss could be greater than our
estimate. There were no changes in the methodology we used to estimate VaR in
2003.

Stress testing complements our VaR estimate. It is used to ensure that we are
not exposed to large losses, not captured by VaR, which might result from
infrequent but extreme market conditions.

Our Board of Directors has approved formal risk management policies for our
energy trading activities. Market and credit risks are monitored daily by a risk
group that operates independently and ensures compliance with our risk
management policies. The Finance Committee of the Board of Directors and our
Risk Management Committee monitor our exposure to the above risks and review the
results of energy trading activities regularly.

FOREIGN-CURRENCY RATE RISK

A substantial portion of our operations are denominated in or referenced to US
dollars. These activities include:

o    prices received for sales of crude oil, natural gas and certain chemicals
     products;
o    capital spending and expenses related to our oil and gas and chemicals
     operations outside Canada; and
o    short-term and long-term borrowings.

We manage our exposure to fluctuations between the US and Canadian dollar by
matching our expected net cash flows and borrowings in the same currency. Net
revenue from our foreign operations and our US-dollar borrowings are generally
used to fund US-dollar capital expenditures and debt repayments. Since the
timing of cash inflows and outflows is not necessarily interrelated,
particularly for capital expenditures, we maintain revolving US-dollar borrowing
facilities that can be used or repaid depending on expected net cash flows. We
designate our long-term US-dollar borrowings as a hedge against our US-dollar
net investment in foreign operations.

We do not have any material exposure to highly inflationary foreign currencies.

We occasionally use derivative instruments to effectively convert cash flows
from Canadian to US dollars and vice versa. Information regarding our foreign
currency net investments, borrowings and related derivative instruments is
provided in Note 5 to the Consolidated Financial Statements.

INTEREST RATE RISK

We are exposed to fluctuations in short-term interest rates from our
floating-rate debt and, to a lesser extent, derivative instruments, as their
market value is sensitive to interest rate fluctuations. We maintain a portion
of our debt capacity in revolving, floating-rate bank facilities with the
remainder issued in fixed-rate borrowings. To minimize our exposure to interest
rate fluctuations, we occasionally use derivative instruments as described in
Note 5 to the Consolidated Financial Statements.

At December 31, 2003, we had no floating-rate debt outstanding (2002 - $nil;
2001 - $424 million).


                                       32
<PAGE>

CREDIT RISK

Credit risk is the risk of loss if customers or counterparties do not fulfill
their contractual obligations. Most of our receivables are with customers in the
energy industry requiring our products on an ongoing basis. These customers are
subject to normal industry credit risk. This concentration of risk within the
energy industry is mitigated through our broad domestic and international
customer base. It is also possible that derivative instrument counterparties
will not fulfill their contractual obligations. We take the following measures
to reduce this risk:

o    we assess the financial strength of our customer and counterparty base
     through a rigorous credit process;
o    we limit the total exposure extended to individual counterparties, and may
     require collateral from some counterparties;
o    we routinely monitor credit risk exposures, including sector, geographic
     and corporate concentrations of credit, and report these to our Risk
     Management Committee and the Finance Committee of the Board;
o    we set credit limits based on counterparty credit ratings and internal
     models, which are based primarily on company and industry analysis;
o    we review counterparty credit limits regularly; and
o    we use standard agreements that allow for netting of positive and negative
     exposures associated with a single counterparty.

We believe these measures minimize our overall credit risk. However, there can
be no assurance that these processes will protect us against all losses from
non-performance. At December 31, 2003:

o    90% of our counterparty exposures were investment grade; and
o    only five customers individually made up greater than 5% of our exposure
     from energy trading activities. All were investment grade.

CRITICAL ACCOUNTING ESTIMATES

As an oil and gas producer, there are a number of critical estimates underlying
the accounting policies we apply when preparing our Consolidated Financial
Statements. These critical estimates are discussed below.

OIL AND GAS ACCOUNTING - RESERVES DETERMINATION

We follow the successful efforts method of accounting for our oil and gas
activities, as described in Note 1 to our Consolidated Financial Statements.
Successful efforts accounting depends on the estimated reserves we believe are
recoverable from our oil and gas properties. The process of estimating reserves
is complex. It requires significant judgements and decisions based on available
geological, geophysical, engineering and economic data. These estimates may
change substantially as additional data from ongoing development activities and
production performance becomes available and as economic conditions impacting
oil and gas prices and costs change. Our reserve estimates are based on current
production forecasts, prices and economic conditions. See Business Risk
Management for a complete discussion of our reserves estimation process.

Reserve estimates are critical to many of our accounting estimates, including:

o    Determining whether or not an exploratory well has found economically
     producible reserves. If successful, we capitalize the costs of the well,
     and if not, we expense the costs immediately. In 2003, $70 million of our
     total $180 million spent on exploration drilling was expensed in the year.
     If none of our drilling had been successful, our net income would have
     decreased by $72 million after tax.
o    Calculating our unit-of-production depletion and asset retirement
     obligation rates. Both proved and proved developed reserve (1) estimates
     are used to determine rates that are applied to each unit-of-production in
     calculating our depletion expense and our provision for dismantlement and
     site restoration. Proved reserves are used where a property is acquired and
     proved developed reserves are used where a property is drilled and
     developed. In 2003, oil and gas depletion, before impairment charges, and
     oil and gas dismantlement and site restoration costs of $636 million and
     $34 million, respectively, were recorded in depletion, depreciation and
     amortization expense. If our reserve estimates changed by 10%, our
     depletion, depreciation and amortization expense would have changed by
     approximately $50 million, after tax, assuming no other changes to our
     reserve profile.

----------------

(1)  "Proved" oil and gas reserves are the estimated quantities of natural gas,
     crude oil, condensate and natural gas liquids that geological and
     engineering data demonstrate with reasonable certainty can be recoverable
     in future years from known reservoirs under existing economic and operating
     conditions. Reservoirs are considered "proved" if economic producability is
     supported by either actual production or a conclusive formation test.
     "Proved developed" oil and gas reserves are reserves that can be expected
     to be recovered through existing wells with existing equipment and
     operation methods.


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<PAGE>

o    Assessing, when necessary, our oil and gas assets for impairment. Estimated
     future undiscounted cash flows are determined using proved reserves. The
     critical estimates used to assess impairment, including the impact of
     changes in reserve estimates, are discussed below.

As circumstances change and additional data becomes available, our reserve
estimates also change, possibly materially impacting net income. Estimates made
by our engineers are reviewed and revised, either upward or downward, as
warranted by the new information. Revisions are often required due to changes in
well performance, prices, economic conditions and governmental restrictions.

Although we make every reasonable effort to ensure that our reserve estimates
are accurate, reserve estimation is an inferential science. As a result, the
subjective decisions, new geological or production information and a changing
environment may impact these estimates. Revisions to our reserve estimates can
arise from changes in year-end oil and gas prices, and reservoir performance.
Such revisions can be either positive or negative. Reserves information is shown
in the Supplementary Financial Information set out in Item 8 of this Form 10-K.

It would take a very significant decrease in our proved reserves to limit our
ability to borrow money under our term credit facilities, as previously
described in Liquidity.

OIL AND GAS ACCOUNTING - IMPAIRMENT

We evaluate our oil and gas properties for impairment if an adverse event or
change occurs. Among other things, this might include falling oil and gas
prices, a significant revision to our reserve estimates, changes in operating
costs, or significant or adverse political changes. If one of these occurs, we
estimate undiscounted future cash flows for affected properties to determine if
they are impaired. If the undiscounted future cash flows for a property are less
than the carrying amount of that property, we calculate its fair value using a
discounted cash flow approach. The property is then written down to its fair
value.

We assessed our oil and gas properties for impairment following the 2003
revisions to our reserve estimates. As a result of this assessment, it was
determined that certain Canadian oil and gas properties were impaired. These
properties were written down to their fair value which resulted in an impairment
charge of $175 million, after-tax. See Note 4 to the Consolidated Financial
Statements for further information.

Our cash flow estimates for purposes of our impairment assessments require
assumptions about two primary elements - future prices and reserves.

Our estimates of future prices require significant judgements about highly
uncertain future events. Historically, oil and gas prices have exhibited
significant volatility - over the last five years, prices for WTI and NYMEX gas
have ranged from US$10/bbl to US$38/bbl and US$2/mmbtu to US$10/mmbtu,
respectively. Our forecasts for oil and gas revenues are based on prices derived
from a consensus of future price forecasts amongst industry analysts and our own
assessments. Our estimates of future cash flows generally assume our long-term
price forecast and forecast operating costs. Given the significant assumptions
required and the possibility that actual conditions will differ, we consider the
assessment of impairment to be a critical accounting estimate. A change in this
estimate would impact all except our chemicals business.

If we decreased our long-term forecast for WTI crude oil prices by
US$1.00-1.50/bbl, our initial assessment of impairment indicators would not
change. Although oil and gas prices fluctuate a great deal in the short-term,
they are typically stable over a longer-time horizon. This mitigates the
potential for impairment.

It is difficult to determine and assess the impact of a decrease in our proved
reserves on our impairment tests. The relationship between the reserve estimate
and the estimated undiscounted cash flows, and the nature of the
property-by-property impairment test, is complex. As a result, we are unable to
provide a reasonable sensitivity analysis of the impact that a reserve estimate
decrease would have on our assessment of impairment. We do, however, have
confidence in our reserve estimates.

Any impairment charges would lower our net income.


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NEW ACCOUNTING PRONOUNCEMENTS

CANADIAN PRONOUNCEMENTS

In December 2001, the Canadian Institute of Chartered Accountants (CICA) issued
Accounting Guideline 13, HEDGING RELATIONSHIPS (AcG-13). AcG-13 establishes
certain conditions for when hedge accounting may be applied. The guideline is
effective for fiscal years beginning on or after July 1, 2003. Adoption of
AcG-13 is not expected to have a material impact on our financial position or
results of operations as we are already in compliance with Financial Accounting
Standards Board (FASB) Statement No. 133, ACCOUNTING FOR DERIVATIVE INSTRUMENTS
AND HEDGING ACTIVITIES.

In September 2002, the CICA approved Section 3063, IMPAIRMENT OF LONG-LIVED
ASSETS (S.3063). S.3063 establishes standards for the recognition, measurement
and disclosure of the impairment of long-lived assets, and applies to long-lived
assets held for use. An impairment loss is recognized when the carrying amount
of a long-lived asset is not recoverable and exceeds its fair value. S.3063 is
effective for fiscal years beginning on or after April 1, 2003. Adoption of
S.3063 is not expected to have a material impact on our financial position or
results of operations.

In December 2002, the CICA approved Section 3110, ASSET RETIREMENT OBLIGATIONS
(S.3110). S.3110 requires liability recognition for retirement obligations
associated with our property, plant and equipment. These obligations are
initially measured at fair value, which is the discounted future value of the
liabilities. This fair value is capitalized as part of the cost of the related
assets and amortized to expense over their useful life. The liabilities accrete
until we expect to settle the retirement obligations. S.3110 is effective for
fiscal years beginning on or after January 1, 2004. The impact on our
consolidated balance sheet at January 1, 2004, will be as follows:

(Cdn$ millions)                                            Increase/(Decrease)
-------------------------------------------------------------------------------
Property, Plant and Equipment                                              81
Asset Retirement Obligation                                               126
Future Income Tax Liability                                               (16)
Retained Earnings                                                         (29)

In February 2003, the CICA issued Accounting Guideline 14, DISCLOSURE OF
GUARANTEES (AcG-14). AcG-14 establishes the disclosures required for obligations
we may have under certain guarantees that we have issued. The disclosure
requirements are effective for interim and annual periods beginning on or after
January 1, 2003. We adopted FASB Interpretation No. 45, GUARANTOR'S ACCOUNTING
AND DISCLOSURE REQUIREMENTS FOR GUARANTEES, INCLUDING INDIRECT GUARANTEES OF
INDEBTEDNESS TO OTHERS, the US equivalent of AcG-14 for the year ended December
31, 2002. We have disclosed our guarantees in Note 10. There were no material
guarantees outstanding at December 31, 2003.

In November 2003, the CICA approved an amendment to Section 3860, FINANCIAL
INSTRUMENTS - DISCLOSURE AND PRESENTATION, to clarify the difference between an
equity and liability instrument. An equity instrument exists only when an
instrument is settled in shares. This amendment is effective for fiscal years
beginning on or after November 1, 2004. Once adopted, our preferred and
subordinated securities would be reclassified from equity to long term debt, and
the dividends paid would be classified as interest expense. Adoption of this
amendment at December 31, 2003, would increase long term debt by $313 million,
decrease preferred and subordinated securities by $364 million and increase the
cumulative translation adjustment by $51 million.

The following standards or revisions issued by the CICA do not impact us:

o    Section 1100, GENERAL ACCOUNTING PRINCIPLES effective for years beginning
     on or after October 31, 2003.
o    Section 1400, GENERAL STANDARDS OF FINANCIAL STATEMENT PRESENTATION
     effective for years beginning on or after October 31, 2003.
o    Accounting Guideline 15, CONSOLIDATION OF VARIABLE INTEREST ENTITIES,
     effective for annual and interim periods beginning on or after January 1,
     2004.

US PRONOUNCEMENTS

The following standards issued by the FASB do not impact us:

o    Statement No. 149, AMENDMENT OF STATEMENT 133 ON DERIVATIVE INSTRUMENTS AND
     HEDGING ACTIVITIES, effective for contracts entered into or modified after
     June 30, 2003 and for hedging relationships designated after June 30, 2003.
o    Interpretation No. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES,
     effective for financial statements issued after January 31, 2003.


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                                     PART IV

ITEM 15.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

The exhibits filed with this Amendment No. 1 to the Annual Report on Form 10-K/A
are listed on the Exhibit Index below.


EXHIBITS

*31.1    Certification of Chief Executive Officer pursuant to Section 302 of
         the Sarbanes-Oxley Act of 2002.

*31.2    Certification of Chief Financial Officer pursuant to Section 302 of
         the Sarbanes-Oxley Act of 2002.

*32.1    Certification of periodic report by Chief Executive Officer pursuant
         to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the
         Sarbanes-Oxley Act of 2002.

*32.2    Certification of periodic report by Chief Financial Officer pursuant
         to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the
         Sarbanes-Oxley Act of 2002.



*       Filed herewith





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<PAGE>

                             SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Company has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized, on March 1, 2005.


                                  NEXEN INC.


                                  By: /s/ Charles W. Fischer
                                      --------------------------
                                      Charles W. Fischer
                                      President, Chief Executive Officer
                                      and Director (Principal Executive Officer)





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