UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                    -----------------------------------------
                             WASHINGTON, D.C. 20549
                                    FORM 10-K

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

                      FOR THE YEAR ENDED DECEMBER 31, 2004

                          COMMISSION FILE NUMBER 1-6702


                                 [LOGO OMITTED]

                                   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
    Preferred 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, 2004, the aggregate market value of the voting shares held by
non-affiliates of the registrant was approximately Cdn $6.7 billion based on the
Toronto Stock Exchange closing price on that date. On January 31, 2005, there
were 129,415,565 common shares issued and outstanding.


<PAGE>


                                TABLE OF CONTENTS

PART I                                                                      PAGE
    Items 1 and 2.  Business and Properties ..............................     2
    Item 3.         Legal Proceedings.....................................    24
    Item 4.         Submission of Matters to a Vote of Security Holders...    24

PART II
    Item 5.         Market for the Registrant's Common Shares and
                         Related Stockholder Matters......................    25
    Item 6.         Selected Financial Data...............................    26
    Item 7.         Management's Discussion and Analysis of Financial
                         Condition and Results of Operations..............    28
    Item 7A.        Quantitative and Qualitative Disclosures About
                         Market Risk......................................    68
    Item 8.         Financial Statements and Supplementary Financial
                         Information......................................    74
    Item 9.         Changes in and Disagreements with Accountants on
                         Accounting and Financial Disclosure..............   119
    Item 9A.        Controls and Procedures...............................   119

PART III
    Item 10.        Directors and Executive Officers of the Registrant....   123
    Item 11.        Executive Compensation................................   127
    Item 12.        Security Ownership of Certain Beneficial Owners
                         and Management...................................   136
    Item 13.        Certain Relationships and Related Transactions........   137
    Item 14.        Principal Accounting Fees and Services ...............   137

PART IV
    Item 15.        Exhibits, Financial Statement Schedules and
                         Reports on Form 8-K..............................   138

SPECIAL NOTE TO CANADIAN INVESTORS - see page 72

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. VOLUMES AND RESERVES
INCLUDE SYNCRUDE OPERATIONS UNLESS OTHERWISE STATED.

<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
MW     =  megawatt                         NGL   =  natural gas liquid
</TABLE>

In this 10-K, we refer to oil and gas in common units called barrel of oil
equivalent (boe). A boe is derived by converting six thousand cubic feet of gas
to one barrel of oil (6 mcf/1 bbl). This conversion may be misleading,
particularly if used in isolation, since the 6 mcf/1 bbl ratio is based on an
energy equivalency at the burner tip and does not represent the value
equivalency at the well head.

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
--------------------------------------------------------------------------------
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
2004                                0.8308       0.7683       0.8493     0.7159

On January 31, 2005, the noon-day exchange rate was US$0.8078 for Cdn $1.00.

Electronic copies of our filings with the Securities 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.

<PAGE>

OPERATIONS

[GRAPHIC OMITTED]
[Graphic Image: Scott Platform, UK North Sea]





                                       1
<PAGE>

PART I


ITEMS 1 AND 2.  BUSINESS AND PROPERTIES


                                TABLE OF CONTENTS
                                                                            PAGE
About Us.......................................................................3
Strategy.......................................................................4
Understanding the Oil and Gas Business.........................................4
Oil and Gas Operations.........................................................4
       Gulf of Mexico - United States..........................................5
       North Sea - United Kingdom..............................................7
       Middle East - Yemen.....................................................9
       Offshore West Africa...................................................11
       Other International....................................................12
       Western Canada.........................................................13
       Athabasca Oil Sands ...................................................15
Reserves, Production and Related Information..................................17
Syncrude Mining Operations....................................................19
Oil and Gas Marketing.........................................................21
Chemicals.....................................................................22
Additional Factors Affecting Business.........................................23
       Government Regulations.................................................23
       Environmental Regulations..............................................23
Employees.....................................................................24



                                       2
<PAGE>

ABOUT US

Nexen Inc. (Nexen, we or our) is an independent, Canadian-based, global energy
and chemicals company. Previously Canadian Occidental Petroleum Ltd., we were
formed in Canada in 1971 from the reorganization of two Occidental Petroleum
Corporation (Occidental) subsidiaries. We combined their Canadian crude oil,
natural gas, sulphur and chemical operations. We've grown from producing 10,700
boe/d before royalties with revenues of $26 million in 1971 to 249,600 boe/d
before royalties (including Syncrude production) and revenues of $3.9 billion in
2004. We achieved this growth through exploration success and strategic
acquisitions. Through over 30 years of operations, we have been profitable every
year, but one, and have been paying quarterly dividends consecutively since
1975.

[GRAPHIC OMITTED]
[Margin Text: Nexen - an independent, Canadian-based global energy and chemicals
company.]

In the 1970s, we expanded our Western Canadian assets and entered the US Gulf of
Mexico. We finished this decade with production of approximately 11,000 boe/d
before royalties and revenues of $126 million.

In the 1980s, we acquired Canada-Cities Service, Ltd. in 1983, which doubled our
size, and included an interest in the Syncrude Joint Venture, our entry into the
Athabasca oil sands. Acquisitions of Cities Offshore Production Co. in 1984, and
Moore McCormack Energy, Inc. in 1988, further increased our presence in the Gulf
of Mexico. We finished this decade with production of approximately 68,600 boe/d
before royalties and revenues of $591 million.

In the 1990s, we had two defining moments: discovering oil on the Masila block
in Yemen and acquiring Wascana Energy Inc. The first of 17 fields at Masila was
discovered in 1991, and Masila has produced over 825 million barrels since
start-up. Our 1997 purchase of Wascana Energy Inc. almost tripled our Canadian
production, with our Hay discovery in northern B.C. increasing this further. In
1998, we entered Australia with an interest in the offshore Buffalo field and
entered Nigeria as the operator of the Ejulebe field. Also in 1998, we
discovered Ukot on OPL-222, offshore Nigeria, the first of several discoveries
to date on the block. We finished this decade with production of approximately
239,200 boe/d before royalties and revenues of $1.7 billion.

[GRAPHICS OMITTED]
[Margin Graphic: Chart of Production before royalties 1971 - 2004]
[Margin Graphic: Chart of Revenues 1971 - 2004.]

So far in the 21st century, we have made a number of discoveries and two
strategic acquisitions. In 2000, we discovered Gunnison in the deep-water Gulf
of Mexico and Guando in Colombia. In that same year, we agreed with Ontario
Teachers' Pension Plan Board (Teachers) and Occidental, to purchase Occidental's
29% interest in us. Teachers purchased 20.2 million common shares and we
repurchased the remaining 20 million common shares for $605 million. We also
exchanged our oil and gas operations in Ecuador for Occidental's 15% interest in
our chemicals operations. In addition, we changed our name to Nexen Inc. The
following year, we discovered Aspen in the deep-water Gulf and signed a joint
venture agreement with OPTI Canada Inc. to develop, produce and upgrade bitumen
at Long Lake. On OPL-222, offshore Nigeria, we discovered Usan, the second
discovery on the block, in 2002. In 2003, we discovered two fields on Block 51
in Yemen. In December 2004, we acquired EnCana Corporation's U.K. subsidiary,
providing us with strategic operatorship of the Buzzard discovery and the
producing Scott and Telford fields in the North Sea. Now in 2005, we are
developing major projects and continuing an active exploration program for
future growth.

For financial reporting purposes, we report on four main segments:

o        Oil and Gas
o        Syncrude
o        Oil and Gas Marketing and
o        Chemicals

Our Oil and Gas operations are broken down geographically into the US Gulf of
Mexico, North Sea, Canada, Yemen and Other International (Colombia, offshore
West Africa, and Australia). Results from our Long Lake Project are included in
Canada. Syncrude is our 7.23% interest in the Syncrude Joint Venture. Marketing
includes our growing crude oil, natural gas and power marketing business in
North America and southeast Asia. Chemicals includes operations in North America
and Brazil that manufacture, market and distribute sodium chlorate, caustic soda
and chlorine.

Production, revenues, net income, capital expenditures and identifiable assets
for these segments appears in Note 18 to the Consolidated Financial Statements
and in Management's Discussion and Analysis of Financial Condition and Results
of Operations (MD&A) in this report.


                                       3
<PAGE>

STRATEGY

Our goal is to grow long-term value for shareholders. We define value growth
as increasing reserves, production and cash flow over the long term, measured on
a debt-adjusted per share basis. This basis reflects the true growth realized by
our shareholders. To accomplish this, we are creating sustainable businesses
through exploration, technology application, strategic acquisitions and capital
discipline.

[GRAPHIC OMITTED]
[Margin text: Our goal is to grow long-term value for shareholders.]

As conventional basins in North America mature, we are transitioning our
operations towards major projects in mature basins, exploration in less mature
basins and exploitation of unconventional resources. Projects are focussed in
the North Sea, Athabasca oil sands, Gulf of Mexico, offshore West Africa and the
Middle East - basins we believe have attractive fiscal terms and significant
remaining opportunity.

[GRAPHIC OMITTED]
[Margin text: We are transitioning our operations towards major projects in
 generally less mature basins and unconventional resources.]

Our major projects typically have an extended period of time between sanctioning
and first production due to their location and scale. These time lags cause
non-linear growth year-over-year and significant up-front capital investment
prior to realizing any production or revenues. We fund projects by maximizing
cash flow from our producing assets, using various financial instruments, and
selling non-core assets into attractive markets. We intend to dispose
approximately $1.5 billion of assets in 2005 to help pay for our North Sea
acquisition.

We also continue an active exploration program for future growth. We primarily
explore in areas where we have existing production or infrastructure, or we have
had recent exploration success.

In creating sustainable businesses, we are committed to good corporate
governance and social responsibility. We believe companies that follow
sustainable business practices outperform those with narrower priorities. We
foster dialogue with stakeholders about our operational opportunities and
challenges, from exploration to production to reclamation. Our goal is to help
stakeholders become engaged participants in a continuing consultation process,
while balancing their multiple, and sometimes conflicting, goals.


UNDERSTANDING THE OIL AND GAS BUSINESS

The oil and gas industry is highly competitive. With strong global demand for
energy, there is intense competition to find and develop new sources of supply.
Yet, barrels from different reservoirs around the world do not have equal value.
Their value depends on the costs to find, develop and produce the oil or gas,
the fiscal terms of the host regime and the price products command at market
based on quality and marketing efforts. Our goal is to extract the maximum value
from each barrel of oil equivalent, so every dollar of capital we invest
generates an attractive return.

Numerous factors can affect this. Changes in crude oil and natural gas prices
can significantly affect our net income and cash generated from operating
activities. Consequently, these prices may also affect the carrying value of our
oil and gas properties and how much we invest in oil and gas exploration and
development. We attempt to mitigate these impacts by investing in projects that
we believe will generate positive returns at low commodity prices.

We also have a broad customer base for our crude oil and natural gas.
Alternative customers are generally available, and the loss of any one customer
is not expected to have a significant adverse effect on the price of our
products or our revenues. Oil and gas producing operations are generally not
seasonal. However, demand for certain of our products can have a seasonal
component, which can impact price. In particular, heavy oil generally
experiences higher demand in the summer months for its use in road construction
and natural gas generally experiences higher demand in the winter heating
months.

We manage our operations on a country-by-country basis reflecting differences in
the regulatory and competitive environments and risk factors associated with
each country.

OIL AND GAS OPERATIONS
[GRAPHIC OMITTED]
[Graphic-World map showing location of oil and gas operations around the world]

We have oil and gas operations in Western Canada, the US Gulf of Mexico, Yemen,
the North Sea, offshore West Africa, Colombia and Australia. We also have
operations in Canada's Athabasca oil sands which produce synthetic crude oil. We
operate most of our production, and continue to develop new growth opportunities
in each area, by actively exploring and applying technology.

[GRAPHIC OMITTED]
[Margin graphic: Pie chart 2004 production before royalties by area]


                                       4
<PAGE>

GULF OF MEXICO - UNITED STATES (US)

The Gulf of Mexico is Nexen's fastest growing region, with over 30,000 boe/d
before royalties of high margin production added from our deep-water Aspen and
Gunnison fields in the past two years.

[GRAPHICS OMITTED]
[Margin caption: In the US, we've added 30,000 boe/d before royalties of
 high-margin production in the last two years.]

[Graphic: Gulf of Mexico map with Nexen's producing and exploration blocks]

Large discoveries, high success rates, production infrastructure and attractive
fiscal terms make the deep-water Gulf of Mexico one of the world's most
prospective sources for oil and gas. The deep-water prospects generally have
multiple productive horizons and high production rates, which reduces risk and
improves economics. Technology to find, drill, and develop discoveries is
rapidly progressing and becoming more cost effective. And, the deep-water Gulf
is relatively close to infrastructure and continental US markets, allowing
discoveries to be brought on stream in a reasonable period of time.

Our strategy in the Gulf is to explore for new reserves, acquire assets with
potential, and exploit our existing asset base. We focus our exploration program
on three strategic areas:

o        deep-shelf gas prospects;
o        deep-water prospects near existing infrastructure; and
o        deep-water, sub-salt plays with potential to become new core areas.

These areas are relatively under-explored, have potential for large discoveries,
and have attractive fiscal terms. The shorter-cycle times for shelf gas and
deep-water prospects near infrastructure complement the longer-cycle times for
deep-water, sub-salt plays.

When we first entered the deep-water, we partnered with large experienced
operators to improve our skills and understanding. A trade-off of this strategy
was not controlling the timing of drilling programs. Our goal is to operate even
more of our own deep-water properties and exploration wells so that we can
manage the pace of activity. In 2004, we invested $400 million on exploration
and development activities to further our strategy. We plan to invest
approximately $315 million in 2005.

In 2004, we produced approximately 54,700 boe/d before royalties (47,500 after
royalties), representing about 22% of Nexen's total production. Proved reserves
of 88 mmboe (103 before royalties) at year-end 2004 were about 20% of Nexen's
total proved oil and gas reserves after royalties. Our production and reserves
in the Gulf are primarily concentrated in five shallow-water fields and two
deep-water fields. We operate most of this production, and hold varying
interests on 182 undeveloped federal lease blocks.

[GRAPHIC OMITTED]
[Margin graphic: US Production before royalties 2002-2004 chart,
 separated by deep and shallow water]

<TABLE>
<CAPTION>
US PRODUCTION
                                     2004                     2003                     2002
---------------------------------------------------------------------------------------------------
                              Before       After       Before       After       Before       After
(mboe/d)                   Royalties   Royalties    Royalties   Royalties    Royalties   Royalties
                          ----------------------   -----------------------  -----------------------
<S>                        <C>         <C>          <C>         <C>          <C>         <C>
Shallow-water                   22.6        18.8         28.5        23.7         28.1        23.2
Deep-water                      32.1        28.7         24.0        21.7          0.5         0.5
                          ----------------------   -----------------------  -----------------------
Total                           54.7        47.5         52.5        45.4         28.6        23.7
                          =======================  =======================  =======================
</TABLE>

Royalty rates on our US production average 17% for shallow-water volumes and 10%
for deep-water volumes. We qualify for royalty relief at our deep-water Aspen
and Gunnison fields on the first 87.5 mmboe of production, making this
production very attractive. We are subject to royalties at Gunnison if the
annual commodity prices are higher than threshold prices set by the US
Department of the Interior's Minerals Management Service. Royalties on other
Gulf and state-water properties range from 12.5% to 25%. US taxable income is
subject to federal income tax of 35% and state taxes ranging from 0% to 8%.

Weather is a risk in the Gulf of Mexico, specifically tropical storms and
hurricanes. They can damage facilities, interrupt production, and delay
exploration and development programs, beyond the few days of the storm itself.
In September 2004, we shut-in 45,000 boe/d of production before royalties for
three days, as Hurricane Ivan passed through. No significant damage was
sustained at our facilities and full production was restored shortly thereafter.
In October 2002, we suffered extensive facilities damage at Eugene Island 295
from Hurricane Lili. Production was restored there in early 2003.


                                       5
<PAGE>

SHALLOW-WATER PRODUCTION

Our shelf producing assets are offshore Louisiana primarily in five 100% owned
fields: Eugene Island 18, Eugene Island 255/257/258/259, Eugene Island 295,
Vermilion 302/320 and Vermilion 76 (consisting of blocks 65, 66 and 67). We
continue to exploit these assets, and look for other opportunities on the shelf.
Most of our 2004 shelf development operations focused on increasing production
at Vermilion 76 and 302/320, through development drilling activities.


DEEP-WATER PRODUCTION

Our deep-water production comes from our 100% operated Aspen field and our 30%
non-operated Gunnison field. Our Gunnison SPAR production facility has excess
capacity, leaving room for growth from exploration and processing of third-party
volumes.

[GRAPHIC OMITTED]
[Margin text: Aspen achieved payout in just over 2 years.]


ASPEN

Aspen is located on Green Canyon Block 243 in 3,150 feet of water. The project
was developed using sub-sea wells tied back to the Shell-operated Bullwinkle
platform 16 miles away. Production began in December 2002. By tying-in a third
Aspen development well in July 2004, we increased 2004 production by 11,000
boe/d before royalties to 27,200 boe/d before royalties at year-end (24,600
after royalties), of which 14% was natural gas. There are no significant capital
plans for Aspen in 2005. We achieved payout on the full Aspen project in
early-2005, just over 2 years from first production.


GUNNISON

Gunnison is located in 3,100 feet of water, and includes Garden Banks Blocks
667, 668 and 669. The first discovery was in May 2000 on Garden Banks Block 668,
and the second in June 2001 on Garden Banks Block 667.

Gunnison began production in December 2003 through a truss SPAR platform that
can handle 40,000 barrels of oil per day and 200 million cubic feet of gas per
day. Our share of 2004 production before royalties was approximately 9,300 boe/d
(8,200 after royalties). During 2005, we plan to drill and tie-in two additional
development wells.

[GRAPHIC OMITTED]
[Graphic: Gunnison SPAR schematic with caption: Our Gunnison SPAR has capacity
 for future discoveries and third-party volumes.]


EXPLORATION

In 2004, half of our exploration budget was invested in the Gulf. The results in
2004 were mixed with four small discoveries and five abandoned wells:

<TABLE>
<CAPTION>
WELL                  LOCATION                           INTEREST (%)    RESULTS
---------------------------------------------------------------------------------------------------------------------------
<S>                   <C>                                <C>             <C>
Dawson Deep           Garden Banks 625                   15              discovery expected to begin producing late-2005
                                                                         through sub-sea tie-back to Gunnison
Tobago                Alaminos Canyon                    13.34           discovery temporarily abandoned; possibly part of
                      858/859                                            future regional development
Wrigley               Mississippi Canyon                 50              gas discovery expected to begin producing in
                      506                                                mid-2006
Anduin                Mississippi Canyon                 50              encountered oil shows; side-tracking to delineate
                      754/755
Shark                 South Timbalier 174                40              well abandoned
Crested Butte         Green Canyon 242                   100             well abandoned as oil shows were close to salt;
                                                                         further work required to see if side-track
                                                                         warranted
Main Pass 240         Main Pass 240                      45              well abandoned; found non-commercial quantities
Fawkes                Garden Banks 303                   33 1/3          well abandoned; found non-commercial quantities
Wind River            West Cameron 335                   50              well abandoned
</TABLE>

In 2004, we also increased our deep-water undeveloped land position to 148
blocks, by acquiring 19 blocks. We expect this acreage, plus new opportunities,
to sustain our current level of exploration drilling.


                                       6
<PAGE>

We are in the midst of our most active Gulf exploration program ever, with two
wells drilling and two more to begin drilling in the first half of 2005. Wells
currently drilling with results expected in the first half of 2005 include:

<TABLE>
<CAPTION>
                                                                                     OPERATOR
WELL               LOCATION                                    INTEREST (%)          STATUS             STRATEGY
-----------------------------------------------------------------------------------------------------------------------
<S>                <C>                                         <C>                   <C>                <C>
Big Bend           Mustang Island A-110                        50                    non-operated       deep-shelf gas
Vrede              Atwater Valley 223/224/267/268              25                    non-operated       deep-water
</TABLE>

We expect to drill other deep-shelf gas and deep-water prospects in 2005, the
most significant deep-water prospects are at Pathfinder (25% interest) and
Knotty Head (25% interest).

[GRAPHIC OMITTED]
[Margin text: We are in the midst of our strongest Gulf Exploration program
 ever.]


NORTH SEA - UNITED KINGDOM (UK)

On December 1, 2004, we acquired assets in the UK North Sea for US$2.1 billion
in cash subject to certain adjustments. This acquisition was completed by
purchasing all outstanding shares of EnCana (UK) Limited. We acquired a 43.2%
operated interest in the Buzzard development, operated interests in the Scott
and Telford producing fields, the Scott production platform, interests in
several satellite discoveries and over 700,000 net undeveloped exploration
acres. We also acquired the management and technical teams that found and
continue to develop Buzzard. From this acquisition we booked 130 mmboe of proved
reserves (130 before royalties) comprising 29% of Nexen's total oil and gas
reserves after royalties.

[GRAPHIC OMITTED]
[Graphic: North Sea map with Nexen's producing and exploration blocks.]

<TABLE>
<CAPTION>
                                              INTEREST        OPERATOR
FIELD              LOCATION                      (%)           STATUS        COMMENTS
-----------------------------------------------------------------------------------------------------------------------
<S>                <C>                           <C>           <C>           <C>
Buzzard            Blocks 19/10, 20/6,           43.2          operated      expected on stream late-2006 ramping up to
                   19/5a, 20/1s                                              80,000 boe/d our share in 2007
Scott              Blocks 15/21a, 15/22          41            operated      producing field with exploitation
                                                                             opportunities
Telford            Blocks 15/21a, 15/22          54.3          operated      producing field with exploitation
                                                                             opportunities
Ettrick            Blocks 20/2a, 20/3a           80            operated      discovery near Buzzard
Farragon           Block 16/28                   20            non-          expected on stream late-2005 at 3,000
                                                               operated      boe/d our share
Perth              Block 15/21a                  42            operated      discovery near Scott
Black Horse        Block 15/22                   56            operated      discovery near Scott
Bugle              Block 15/23d                  80            operated      discovery near Scott
</TABLE>

This acquisition establishes us as a significant regional player, with
concentrated assets, infrastructure and exploration and development potential
for future growth. It will add high-margin reserves and production, diversify
our world-wide portfolio by adding strong assets in a stable jurisdiction, and
complement the longer cycle-time projects we have in the Athabasca oil sands,
offshore West Africa, and the deep-water Gulf of Mexico.

[GRAPHIC OMITTED]
[Margin text: Our North Sea acquisition establishes us as a significant regional
 player.]

Our UK strategy is focused on exploration and exploitation near existing
infrastructure. We have a number of exploitation opportunities in our existing
fields and smaller satellite discoveries close to infrastructure. Most of our
unexplored acreage is near Scott/Telford or Buzzard, and could be tied-in
quickly upon success.

The Scott field is subject to Petroleum Revenue Tax (PRT), although no PRT is
payable until available oil allowances have been fully utilized. No PRT is
expected to be payable before 2009. Once payable, PRT is levied at 50% of cash
flow after capital expenditures, operating costs and an oil allowance. PRT is
applicable to fields receiving development consent prior to March 1993, thereby
excluding both the Buzzard and Telford fields. PRT is deductible for corporate
income tax purposes. The UK corporate income tax rate is 30% of taxable income.
Income from oil and gas activities is also subject to a supplemental charge of
10%. Assuming WTI of US$30/bbl, we do not expect to pay current taxes until
2009. The amount and timing of income taxes payable depends on many factors
including price, production and capital investment levels.


                                       7
<PAGE>

BUZZARD

Buzzard is one of the largest discoveries in the UK North Sea in recent years.
Discovered in 2001, it is in the Outer Moray Firth, central North Sea,
approximately 100 km northeast of Aberdeen, in 100 metres of water.

Our Buzzard development involves contractors across Europe building a three
bridge-linked platform complex comprising wellhead, production and utilities
decks and topsides. The facilities will have capacities of 200,000 bbls/d of oil
and 60 mmcf/d of gas. Currently, we anticipate the field will produce through 27
production wells, eight pre-drilled and producing by late-2006. Reservoir
pressure will be maintained through an active water-flood program. We estimate
peak gross production rates in 2007 at 180,000 bbls/d of oil and approximately
30 mmcf/d of gas, with our share at 80,000 boe/d before royalties.

[GRAPHICS OMITTED]
[Graphic: Buzzard production facilities drawing]

[Margin text: Our share of royalty-free Buzzard production is expected to climb
 to 80,000 boe/d in 2007.]

Work is well underway to construct jackets and topsides that will form the
Buzzard platform installation. At year-end 2004, the development project was
over 50% complete, on schedule and on budget. In 2005, we plan to invest $530
million to transport the three jackets to Buzzard, install them, install the
wellhead topsides, initiate drilling of the production wells, and install the
gas and oil export pipelines. In summer 2006, we plan to install the utilities
and production topsides and initiate hook-up and project commissioning.

Oil from Buzzard will be exported via the Forties Pipeline System to the
Grangemouth, Scotland refinery. Gas will be exported via the Frigg system to the
St. Fergus Gas Terminal in northeast Scotland.


SCOTT / TELFORD

Scott and Telford are both producing fields with additional exploitation
opportunities. Scott was discovered in 1987 and began producing in September
1993. Telford was discovered in 1991 and came on stream in 1996. Oil accounts
for over 85% of production at Scott and around 50% at Telford.

Oil and gas is produced through numerous subsea wells and from wells drilled
from the Scott platform. Oil is delivered to the Grangemouth, Scotland refinery
via the Forties pipeline. Gas is exported via the SAGE pipeline to a terminal at
St. Fergus in northeast Scotland.

In 2005, we plan to invest approximately $50 million to drill, complete, and
tie-in five development wells, work-over several existing wells, and
de-bottleneck and upgrade facilities on the Scott platform.


OTHER

We have a number of smaller discoveries on operated blocks near Scott, Buzzard
or third-party facilities. Ettrick could be developed using a floating
production facility, or tied-in to Buzzard (20 km away) once excess capacity is
available. Exploitation projects near Scott such as Perth, Black Horse and Bugle
are in various stages of evaluation. Farragon should begin producing in
late-2005, with our 20%, non-operated share of production expected to reach
between 3,000 and 4,000 boe/d before royalties in early 2006.

In 2005, we plan to drill at least four exploration wells and most are close to
Scott/Telford or Buzzard.

[GRAPHIC OMITTED]
[Margin text: We have a number of smaller discoveries near Scott, Buzzard or
 third-party facilities.]


                                       8
<PAGE>

MIDDLE EAST - YEMEN

Yemen has been Nexen's most significant international region since first
production on the Masila Block in 1993. We operate the country's largest oil
project and have developed excellent relationships with the government and
communities near our operations. Our success and reputation in Yemen opens doors
elsewhere in the Middle East and around the world.

Our strategy here is to maximize value from our existing blocks while continuing
to search for new fields in deeper horizons. We have two producing blocks:
Masila (Block 14) and East Al Hajr (Block 51). In 2004, we produced 107,300
bbls/d before royalties (53,500 after royalties) of oil, representing
approximately 30% of 2004 cash flow. Proved reserves of 80 mmboe (133 before
royalties) comprise approximately 18% of Nexen's total proved oil and gas
reserves after royalties.


[GRAPHIC OMITTED]
[Graphic: Yemen map showing East Al Hajr block, Masila block,
 and Ash Shihr terminal]


MASILA BLOCK (BLOCK 14)

We have a 52% working interest in and operate the Masila Project. Our share of
2004 production was 106,200 bbls/d before royalties (52,500 after royalties).
After more than 10 years of growth, our Masila fields have started maturing, but
significant value still remains. Due to terms in the production sharing
agreement, we still expect to generate approximately 40% of the total project
cash flow from the remaining 20% of reserves.

[GRAPHIC OMITTED]
[Margin text: We expect to generate approximately 40% of the total project cash
 flow from the remaining 20% of the reserves.]

The first successful Masila exploratory well was drilled at Sunah in 1991, with
additional discoveries quickly following at Heijah and Camaal. Initial
production began in July 1993 with the first lifting of oil in August 1993.
Masila Blend oil averages 31(degree) API at very low gas-oil ratios. Most of the
oil is produced from the Upper Qishn formation, but we also produce from deeper
formations including the Lower Qishn, Upper Saar, Saar, Madbi, Basal Sand, and
basement formations.

We are managing our drilling pace to ensure we recover the remaining reserves in
the most efficient, cost-effective manner. We still see 150 drillable locations
and plan to drill 20 to 40 wells annually. In 2005, we plan to invest
approximately $70 million to drill at least 20 wells and test deeper horizons
where we have had recent success.

[GRAPHIC OMITTED]
[Graphic: Map of Masila block]

Masila is the largest oil project in Yemen. Each day, approximately 1.9 million
barrels of fluid are produced and collected at our Central Processing Facility
(CPF) through over 1,000 km of gathering lines. Water is separated at the field
or CPF and re-injected via water disposal wells in an environmentally sensitive
manner.

[GRAPHIC OMITTED]
[Margin text: Masila is the largest oil project in Yemen.]

Treated oil is pumped from the CPF via 138 km of pipeline to the export terminal
at Ash-Shihr. This pipeline ships Masila, East Al Hajr and third-party crude.
Oil is stored in one of six tanks (one 1,000,000 barrel tank and five 500,000
barrel tanks). From the tanks, oil travels through a sub-sea pipeline to a
pipeline end manifold (PLEM) 4 km offshore in 50 metres of water. The oil moves
through the PLEM up to a single point mooring buoy at the water surface and then
through two floating pipelines into tankers.

The oil is shipped to primary customers in Asia. Masila Blend crude oil enjoys a
strong market due to its quality, reliability of supply and a consolidated
marketing approach. During 2004, we sold our Masila crude oil at an average
discount of US$4.84/bbl to WTI.


                                       9
<PAGE>

Masila production is governed by a Production Sharing Agreement (PSA) signed in
1987 between the Government of Yemen and the Masila joint venture partners
(Partners), including Nexen. Under the PSA, we have the right to produce oil
from Masila into 2011 and to negotiate a five-year extension. Production is
divided into cost recovery oil and profit oil. Cost recovery oil provides for
the recovery of all exploration, development, and operating costs which are
funded by the Partners. Costs are recovered from a maximum of 40% of production
each year, as follows:

COSTS                                     RECOVERY
--------------------------------------------------------------------------------
Operating                                 100% in year incurred
Exploration                               25% per year for 4 years
Development                               16.7% per year for 6 years

The remaining production is profit oil shared between the Partners and the
Government and is calculated on a sliding scale based on production. The
Partners' share of profit oil ranges from 20 to 33%. The structure of the
agreement moderates impact on the Partners' cash flows during periods of low
prices. We recover our costs first, and then share any remaining profit oil with
the Government. At current production levels, the Government is entitled to
approximately 74% of the profit oil, which includes a component for Yemen income
taxes payable by the Partners at 35%. In 2004, the Partners' share of Masila
production, including recovery of past costs, was approximately 38%.

[GRAPHIC OMITTED]
[Graphic: schematic of Masila Block PSA]


EAST AL HAJR BLOCK (BLOCK 51)

We have an 87.5% working interest in and operate East Al Hajr. The first
successful exploratory well was drilled at BAK-A in 2003, with the BAK-B
discovery quickly following. Early production began in November 2004 and the
field was producing 16,700 bbls/d before royalties at year-end. Full production
is expected to grow to 25,000 bbls/d before royalties in mid-2005.

[GRAPHICS OMITTED]
[Graphic: Map of East Al Hajr block]

[Margin text: Full production from Block 51 is expected to grow to 25,000 bbls/d
 before royalties in mid-2005.]

Development of the BAK-A discovery began in 2004, and will initially include 16
wells, a central processing facility, a gathering system and a 22-km tieback to
our Masila export pipeline. Additional development wells are planned throughout
2005. The BAK-B field will initially be developed with seven wells and will come
on stream in late-2005.

In 2004, we drilled four exploration wells on the block. The first two wells
were abandoned. The third well, BAK-I, encountered oil shows and will be
production tested in early 2005 after we source the necessary testing equipment.
The fourth exploration well, BAK-J, was suspended after encountering oil and gas
shows associated with high formation pressures, and will be re-entered and
deepened when suitable equipment is located and high-pressure drilling equipment
is sourced.

In 2005, we plan to invest approximately $200 million to complete development of
the BAK-A and BAK-B fields and continue exploring the block with four
exploration wells.


                                       10
<PAGE>

This block is governed by a PSA between the Government of Yemen, and the
Partners: The Yemen Company (an entity owned by the Government of Yemen) (12.5%
interest) and Nexen (87.5% interest). The PSA expires in 2023 and we have the
right to negotiate a five-year extension. Under the terms of the PSA, the
Partners pay a royalty ranging from 3 to 10% to the Government depending on
production. The remaining production is divided into cost recovery oil and
profit oil. Cost recovery oil provides for the recovery of all of the project's
exploration, development and operating costs, funded solely by Nexen. Costs are
recovered from a maximum of 50% of production each year, as follows:


COSTS                                    RECOVERY
--------------------------------------------------------------------------------
Operating                                100% in year incurred
Exploration                              75% per year, declining balance
Development                              75% per year, declining balance

The remaining production is profit oil that is shared between the Partners and
the Government on a sliding scale based on production rates. The Partners' share
of profit oil ranges from 20% to 30%. The Government's share of profit oil
includes a component for Yemen income taxes payable by the Partners at a rate of
35%.

[GRAPHIC OMITTED]
[Graphic: schematic of Block 51 PSA]


OTHER EXPLORATION BLOCKS

In 2004, we relinquished our interest in exploration Blocks 11, 12, 36, 50, 54,
and 59.


OFFSHORE WEST AFRICA

Offshore West Africa is a growing core area where we already have discoveries.
It offers prolific reservoirs and multiple opportunities to invest in this
oil-rich region. Our strategy here is to explore and develop our portfolio for
medium- to long-term growth. We have three exploration projects underway--
OPL-222 and OML-115, offshore Nigeria and Block K, offshore Equatorial Guinea.
We are also producing our final barrels from our Ejulebe field, offshore
Nigeria.

In 2004, we invested $69 million of capital offshore West Africa, and expect to
invest $84 million in 2005.

[GRAPHICS OMITTED]
[Graphic: Map of offshore West Africa showing Nexen production and
 exploration blocks]

[Margin text: Offshore West Africa is a growing core area where we already have
 discoveries.]


NIGERIA


BLOCK OML-109 - EJULEBE

Ejulebe is located in 45 feet of water on Block OML-109 in the Niger Delta,
approximately 15 km offshore Nigeria. Crude oil production is transported
through a pipeline to a third-party owned FPSO (floating production storage and
off-loading vessel) where it is made available for sale and export. We operate
the block under a risk service contract, requiring us to provide exploration,
development and operatorship services and fund all costs in return for a service
fee payable out of production from the block.

Ejulebe was still producing at year-end 2004. We expect to sell or abandon it in
2005. Abandonment would begin once government approvals have been obtained. No
capital expenditures are proposed for 2005 other than abandonment expenditures.


                                       11
<PAGE>

BLOCK OPL-222

In 1998, we acquired a 20% non-operated interest in Block OPL-222, which
includes 448,000 acres and is approximately 50 miles offshore in water depths
ranging from 600 to 3,500 feet. The ongoing appraisal of the block indicates
significant hydrocarbon accumulations based on the drilling results outlined
below:

<TABLE>
<CAPTION>
YEAR        WELL        LOCATION                        RESULTS
-----------------------------------------------------------------------------------------------------------------
<C>         <C>         <C>                             <C>
1998        Ukot-1      Ukot field discovery well       encountered  three  oil-bearing  intervals  and flowed at
                                                        restricted rate of 13,900 bbls/d from two intervals
2002        Usan-1      Usan field discovery well       encountered several oil-bearing intervals and flowed at
                                                        restricted rate of 5,000 bbls/d from one interval
2003        Usan-2      3 km west of discovery          appraised up-dip portion of the fault block
2003        Usan-3      2 km northwest of discovery     appraised  separate  fault block and flowed at restricted
                                                        rate of 5,600 bbls/d from one interval
2003        Ukot-2      3.5 km south of discovery       encountered three oil-bearing intervals
2003        Usan-4      5 km south of discovery         flowed at  restricted  rate of 4,400  bbls/d  from  first
                                                        interval and 6,300 bbls/d from second interval
2004        Usan-5      6 km west of discovery          sampled oil in several intervals
2004        Usan-6      4 km south of Usan-5            flowed  at  restricted  rate of  5,800  bbls/d  from  one
                                                        interval
</TABLE>

[GRAPHICS OMITTED]
[Margin Graphic: Map of OPL-222 showing Nexen discoveries and prospects.]

[Margin Text: We have confirmed the presence of commercial quantities of
 oil on OPL-222.]

Usan-4 confirmed the presence of commercial quantities of crude oil and Usan-5
and Usan-6 have built on this to the west. The operator has applied to convert
the block's licence to one or more Oil Mining Leases, which give 20 years to
appraise, develop and produce the reserves. A field development plan for Usan is
being prepared for submission to the government.

We plan additional exploration drilling on OPL-222 in 2005, and are now
determining which prospects will be drilled.


BLOCK OML-115

The Nigerian Government formally approved the Deed of Assignment for OML-115 in
December 2003, which assigned us a 40% interest in the block. Under the terms of
our Joint Operating Agreement with Oriental Energy Resources Limited, we have a
100% paying interest and are entitled to between 90% and 95% of the revenues for
an initial ten-year period. In 2004, we drilled a well on the Ameena prospect
and did not find hydrocarbons. We expect to drill our next exploration well on
the block in the first half of 2005.


EQUATORIAL GUINEA - BLOCK K

In 2003, we acquired a 25% operated interest in Block K, a deep-water block
located 100 km offshore Equatorial Guinea. This interest was later increased to
50%. In 2004, we drilled a well on the Zorro prospect and found non-commercial
quantities of hydrocarbons. We expect to drill our next exploration well on the
block in the first half of 2005. We plan to meet all of the work commitments
under the production sharing contract before the initial exploration period ends
on June 1, 2005.


OTHER INTERNATIONAL

COLOMBIA

BOQUERON BLOCK - GUANDO

In 2000, we made our first discovery at Guando on our 20% non-operated Boqueron
Block. Boqueron is located in the Upper Magdalena Basin of central Colombia,
approximately 45 km southwest of Bogota. Our share of 2004 production averaged
4,800 bbls/d before royalties (4,400 after royalties), about 2% of Nexen's total
production.

Production from Guando is subject to a 5% to 25% royalty depending on daily
production levels. The corporate income tax rate is 38.5%.

[GRAPHIC OMITTED]
[Graphic: Map of Colombia showing Nexen producing and exploration blocks]


                                       12
<PAGE>

EXPLORATION BLOCKS

Exploration activities in Colombia are focused on assessing potential drilling
opportunities on captured blocks. In addition to Boqueron, we have interests in
three exploration blocks in the Upper Magdalena Basin. Villarrica was acquired
in 2000, El Queso in 2003 and Boqueron Deep in 2003.

<TABLE>
<CAPTION>
BLOCK                 INTEREST (%)     OPERATOR STATUS      2004 ACTIVITY
--------------------------------------------------------------------------------------------------------
<S>                   <C>              <C>                  <C>
Boqueron Deep         40               non-operated         shot 80 km of seismic
Villarrica            50               operated             received environmental license for possible
                                                            2005 exploration well
El Queso              50               operated             shot 70 km of seismic
</TABLE>

The fiscal policy structure in Colombia was revised in 2004 to make the terms
more competitive in the world market. In December 2004, El Queso was recognized
under the new terms. The exploration commitments have been completed for the
current phase of Villarrica. The seismic acquisition with Phase One at Boqueron
Deep is complete, with processing and interpretation activities carrying forward
in 2005. The Phase Two commitments at El Queso will be fulfilled in 2005 with
the budgeted seismic program.

In 2005, we plan to drill one exploration well and acquire additional seismic
information to help identify future drilling opportunities.


AUSTRALIA - BUFFALO

Since first production in 1999, the Buffalo field, offshore northwest Australia,
has produced 53(degree) API crude oil using a fixed wellhead platform linked to
a leased floating production storage and off-loading vessel.

We produced our final barrel of crude oil in late-2004, and averaged 2,700
bbls/d before royalties of oil for 2004. Field abandonment began in November
2004 and is expected to be completed in 2005. There were no capital expenditures
in 2004, and other than abandonment expenditures, no further expenditures are
expected in 2005 .


WESTERN CANADA

Our strategy in Canada is to maximize value from our core operations while we
actively pursue emerging sources of supply. We continue to manage our mature
conventional assets through selective development, cost control and asset
dispositions. In 2004, we produced 59,900 boe/d before royalties (47,000 after
royalties) from these assets, which was approximately 24% of Nexen's total
production. At year-end 2004, proved reserves of 141 mmboe (164 before
royalties) were approximately 31% of Nexen's total proved oil and gas reserves
after royalties.

Our Canadian operations are concentrated in geographical regions based on
commodity:

o        light oil--in southeast Saskatchewan and northeast British Columbia;
o        heavy oil--in west central Saskatchewan;
o        natural gas--near Calgary, in northern Alberta foothills, southeast
         Alberta and Saskatchewan.

We operate most of our producing properties and hold 1.7 million net acres of
undeveloped land across western Canada.

[GRAPHICS OMITTED]
[Margin text: Our Western Canadian strategy is to maximize value from core
 operations while pursuing emerging sources of supply.]

[Graphic: Map of Western Canada showing Nexen areas of operations.]

The core assets provide predictable production and earnings while we advance
initiatives for future growth:

o    coal bed methane (CBM) - focusing on Upper Mannville and Horseshoe Canyon
     coals and applying our experience in shallow gas drilling and water
     handling techniques
o    enhanced oil recovery (EOR) - actively testing enhanced oil recovery
     technologies to increase recovery in our heavy oil fields.


                                       13
<PAGE>

In 2004, we invested $175 million in Canada, with $148 million in our maturing
core assets. In 2005, we plan to invest approximately $200 million, with $140
million allocated to our maturing core assets. From 2003 to 2005, we will have
doubled our capital investment in CBM and EOR.

In Canada, the federal and provincial governments impose royalties on production
at varying rates, ranging between 15% and 40%, from lands where they own the
mineral rights. Some provinces also impose taxes on production from lands where
they do not own the mineral rights. The Saskatchewan government assesses a
resource surcharge on gross Saskatchewan resource sales of 3.6% that is reduced
to 2.0% if the well was completed after October 1, 2002.

Profits earned in Canada from resource properties are subject to federal and
provincial income taxes. In 2003, legislation was introduced to reduce the
federal corporate income tax rate on income from Canadian oil and gas activities
from 28% to 21% by 2007. Canadian entities are also subject to capital taxes.

[GRAPHIC OMITTED]
[Margin text: Our Western Canadian production is split: 20% light oil,
 40% heavy oil and 40% natural gas.]

LIGHT OIL

Approximately 20% of our Canadian production is light oil.

We continue to develop and exploit our Hay property in northeast British
Columbia. We discovered Hay in 1997 and started producing in April 2000. Hay is
entering the final stage of development, with our focus on maximizing its value
and evaluating remaining reserve potential.

Our operations in southeast Saskatchewan are characterized by mature fields
producing medium-depth light oil. In 2004, we drilled 24 gross wells (19 net) as
part of our capital program. Our 2005 plans include ongoing exploitation of
these fields.

HEAVY OIL

Approximately 40% of our Canadian production is heavy oil.

Heavy oil is characterized by high specific gravity or weight and high viscosity
or resistance to flow. Because of these features, heavy oil is more difficult
and expensive to extract, transport and refine than other types of oil. Heavy
oil also yields a lower price relative to light oil, as a smaller percentage of
high value petroleum products can be refined from heavy oil.

Our heavy oil operations are in west central Saskatchewan. To maximize heavy oil
returns, it is important to manage finding, development and operating costs. Our
large production base and existing infrastructure helps. In 2004, we drilled 63
gross wells (52 net) as part of our capital program. In 2005, we plan to
continue exploiting our existing fields through drilling and optimizing
operations.

NATURAL GAS

Approximately 40% of our Canadian production is natural gas, produced primarily
from shallow sweet reservoirs in southeast Alberta, southwest and northwest
Saskatchewan and from deep sour gas near Calgary and in the northern Alberta
foothills.

Shallow gas is natural gas produced from thin, shallow sand formations yielding
sweet, low-pressure gas. In general, shallower gas targets are cheaper to drill
and develop, but have relatively smaller reserves and lower productivity per
well. We have been producing sour natural gas from our Balzac field northeast of
Calgary since 1961. This sour gas is processed through our operated Balzac
plant. We also have natural gas production from our Findley properties in the
Alberta foothills and gas production associated with oil wells. In 2005, we
expect to drill 126 gross wells (117 net).

Limited gas exploration activity is focused in the foothills of Alberta and
in Montana and central Saskatchewan.


COAL BED METHANE (CBM)

CBM is commonly referred to as an unconventional form of natural gas because it
is primarily stored through adsorption by coal in coal deposits rather than in
the pore space of the rock like most conventional gas. The gas is released in
response to a drop in reservoir pressure. If the coal deposit is water
saturated, water generally needs to be extracted to reduce the pressure and
allow gas production to occur. If the coal does not produce water and is "dry",
gas will be produced from initial development. CBM fields are likely to require
between two and eight gas wells per section to efficiently extract the natural
gas. Regulatory approval is required to drill more than one well per section. As
a result, the timing of drilling programs and land development can be uncertain.
Water producing CBM wells in the United States generally show increasing gas
production rates for a period of approximately one to three years before gas
rates begin to decline.

At the end of 2004, our net undeveloped CBM land position was 285,000 acres.
Most of this land is in the Fort Assiniboine region of Alberta, where our
Corbett pilot project is located. We have also established positions in other
prospective CBM areas in Alberta.


                                       14
<PAGE>

[GRAPHIC OMITTED]
[Graphic:  Alberta map showing Nexen lands and Corbett pilot location.]

Our CBM pilot at Corbett, operated by Trident Exploration, has established
techniques to produce natural gas from the wet Upper Mannville coals. Commercial
feasibility depends on achieving threshold production levels, which we hope to
achieve in 2005. These coals are generally deeper than the Horseshoe Canyon "dry
coal" play which is now being commercially developed in Alberta. During 2004, we
expanded our Corbett pilot from 15 to 49 producing wells.

In 2005, besides the potential of initiating commercial development at Corbett,
we will continue to evaluate other Mannville and Horseshoe Canyon CBM prospects
and pursue new opportunities in CBM. Our capital expenditures in 2004 were
approximately $30 million, and we plan to invest $45 million on CBM in 2005.

[GRAPHIC OMITTED]
[Margin text: A strong land position is critical to a successful CBM strategy.]


ENHANCED OIL RECOVERY (EOR)

Heavy oil reservoirs typically have lower recovery factors than conventional oil
reservoirs, leaving substantial amounts of oil in the ground. This creates an
opportunity to increase recovery factors by applying new technology. We are
researching various technologies to enhance our heavy oil recovery with ongoing
pilot projects in west central Saskatchewan.

ATHABASCA OIL SANDS

Our oil sands strategy is to economically develop our bitumen resource to
provide low-risk, stable, future growth. Our strategy involves integrating
bitumen production with field upgrading technology to produce a premium
synthetic crude oil. Our oil sands strategy also includes our 7.23% investment
in the Syncrude oil sands mining operation.

In 2001, we formed a 50/50 joint venture with OPTI Canada Inc. (OPTI Canada) to
develop the Long Lake property (Lease 27) using steam-assisted-gravity-drainage
(SAGD) for bitumen production and field upgrading with the OrCrude(TM) process,
a technology to which OPTI Canada has the exclusive Canadian license. OPTI
Canada has since reorganized its interest into OPTI Long Lake L.P. (OPTI). We
also acquired from OPTI the exclusive right to use the technology within
approximately 100 miles of Long Lake in collaboration with OPTI, and the right
to use the technology independently elsewhere in the world.

[GRAPHIC OMITTED]
[Graphic: Alberta map of Nexen bitumen acreage for Long Lake]

We have 199,000 net acres of bitumen-prone lands located in the Athabasca oil
sands of northeast Alberta, and plan to continue acquiring more. We plan to
develop our bitumen lands in a phased manner using our integrated upgrading
strategy. To begin exploiting this resource, we sanctioned and began development
of our Long Lake Project in 2004.

In 1995, Alberta announced generic royalty terms for new oil sands projects that
provide for a royalty rate of 25% on net revenues after all costs have been
recovered, subject to a minimum 1% gross royalty. We expect to be subject to
this royalty on our bitumen production and not our upgraded synthetic crude oil
production.

[GRAPHIC OMITTED]
[Margin text: We continue to expand our bitumen holdings and plan to develop
 them in a phased manner using our integrated upgrading strategy.]


                                       15
<PAGE>

LONG LAKE PROJECT

Our $3.5 billion Long Lake Project, the fourth and next major integrated oil
sands project in Canada, received regulatory approval in 2003. The project
consists of approximately 72,000 bbls/d of SAGD bitumen production integrated
with a field upgrading facility using the OrCrude(TM) process and commercially
available hydrocracking and gasification. The project is expected to produce
approximately 60,000 bbls/d of premium synthetic crude oil with low sulphur
content once the upgrader is on stream in the second half of 2007. The project
is designed to generate its own fuel and electricity, resulting in significant
operating cost savings compared to other bitumen production and upgrading
projects and significantly lower price risk on input costs. By upgrading the
bitumen to synthetic crude oil, we should also avoid price risk on the
production. We are the operator of the Long Lake lease and are responsible for
construction, development and operation of the SAGD project, while OPTI is
responsible for the design, construction and operation of the upgrader. We will
share the production and operating costs of the project equally with OPTI.

[GRAPHIC OMITTED]
[Margin text: We expect our share of phase one production from Long Lake to be
 30,000 bbls/d of premium synthetic crude oil.]

The SAGD and upgrader integration, along with the proprietary processes, allows
us to overcome three main economic hurdles of SAGD bitumen production: 1) cost
of natural gas, 2) cost of diluent, and 3) the realized price of bitumen. The
Project generates synthetic gas from internally produced asphaltenes for use as
fuel. This essentially eliminates the need for purchasing natural gas. With the
upgrading facilities located on site, expensive diluent is not required to
transport the produced bitumen to market. Upgrading the bitumen into a highly
desirable refinery feedstock or diluent supply enables the end product to
command significantly higher prices than raw bitumen.

We plan to produce bitumen using SAGD, a proven technology now being
commercialized at several locations in the region. SAGD involves drilling two
parallel horizontal wells, generally between 2,300 and 3,300 feet in length with
about 16 feet of vertical separation. Steam is injected into the shallower well,
where it heats the bitumen that then flows by gravity to the deeper producing
well. To optimize the project's well design, a three-well pair SAGD pilot was
completed and is still operating. We also have interests in other SAGD projects
at various stages of assessment outside of Long Lake.

[GRAPHICS OMITTED]
[Margin text: Our SAGD and upgrader integration allows us to limit our exposure
 to critical variables affecting the economics of SAGD bitumen production:
 1) cost of natural gas, 2) cost of diluent, and 3) price of bitumen.]

[Graphic: schematic of SAGD production and well pair]

[Graphic: schematic of SAGD and Upgrader with OrCrude(TM) upgrading process]


                                       16
<PAGE>

The OrCrude(TM) technology, using distillation, solvent deasphalting and thermal
cracking, converts bitumen into partially upgraded sour crude oil and liquid
asphaltenes. By coupling the OrCrude(TM) process with commercially available
hydrocracking and gasification technologies, sour crude is upgraded to light
(39(degree) API) premium synthetic crude oil and the asphaltenes are converted
to a low-energy, synthetic fuel gas containing free hydrogen for use in the
upgrading process. The synthetic fuel will be burned in a co-generation plant to
produce steam for the SAGD operations and for on-site power. A 500-bbl/d
demonstration plant successfully separated asphaltenes and upgraded over 250,000
bbls of various types of bitumen from the Cold Lake and Athabasca regions,
including Long Lake bitumen. Combined SAGD, cogeneration, and upgrading
operating costs are expected to average between $7 and $9/bbl.

[GRAPHIC OMITTED]
[Margin text: Combined SAGD cogeneration and upgrading costs are expected to
 average between $7 and $9/bbl.]

On February 12, 2004, our Board of Directors approved proceeding with commercial
development of the Long Lake Project. Field construction work on the SAGD and
upgrader facilities began in 2004, with above ground construction scheduled to
begin in the first half of 2005. Commercial SAGD drilling of 78 well pairs began
in September 2004, with expected completion by early 2006. At year-end,
procurement of major equipment was substantially complete, with pricing as
budgeted. First steam injection is scheduled to commence in 2006 and the
upgrader is scheduled to start-up in the second half of 2007. We expect peak
gross production to reach around 60,000 bbls/d before royalties of synthetic
crude oil. We expect to maintain this rate over the project's life, estimated at
40 years, by periodically drilling additional SAGD well pairs.

We expect the gross capital cost for the Long Lake Project, including upgrader
commissioning and start-up to total $3.5 billion ($1.75 billion, net to us).
This is $98 million higher ($49 million, net to us) than the estimate at the
time of sanctioning as we have accelerated the drilling of 13 well pairs to
ensure we have sufficient bitumen supply to fill the upgrader. In 2004, we
invested approximately $362 million and expect to invest $765 million in 2005.
The spending in 2005 increases substantially because we are entering the
construction phase of the commercial facilities. Ongoing sustaining capital is
expected to average $2.50/bbl. We estimate the capital costs of producing and
upgrading bitumen using this technology will be comparable to those for surface
mining and coking upgrading on a barrel of daily production basis.

[GRAPHIC OMITTED]
 Margin text: Our share of Long Lake capital costs to upgrader start-up is
 estimated at $1.75 billion.]

RESERVES, PRODUCTION AND RELATED INFORMATION
In addition to the tables below, we refer you to the Supplementary Data in Item
8 of this Form 10-K for information on our oil and gas producing activities.
Nexen has not filed with nor included in reports to any other United States
federal authority or agency, any estimates of total proved crude oil or natural
gas reserves since the beginning of the last fiscal year.

NET SALES BY PRODUCT FROM CONTINUING OPERATIONS (INCLUDING SYNCRUDE)

(Cdn$ millions)                                       2004      2003      2002
--------------------------------------------------------------------------------
Conventional Crude Oil and Natural Gas Liquids       1,856     1,590     1,374
Synthetic Crude Oil                                    321       240       245
Natural Gas                                            607       618       345
                                                   -----------------------------
                                                     2,784     2,448     1,964
                                                   =============================
Crude oil (including synthetic crude oil) and natural gas liquids represent
approximately 78% of our net sales, while natural gas represents the remaining
22%.

<TABLE>
<CAPTION>
SALES PRICES AND PRODUCTION COSTS (EXCLUDING SYNCRUDE)

                                    AVERAGE SALES PRICE (1)   AVERAGE PRODUCTION COSTS (1)
-----------------------------------------------------------   ----------------------------
                                    2004     2003     2002     2004       2003      2002
                                   ------------------------   ----------------------------
<S>                                <C>      <C>      <C>       <C>        <C>       <C>
Crude Oil and NGLs (Cdn$/bbl)
  Yemen                            47.59    39.45    38.80     5.64       4.37      4.13
  Canada (2)                       36.60    32.37    31.13    11.76      10.00      8.98
  United States                    46.60    37.68    38.88     6.09       5.08     10.95
  Australia (2)                    51.22    43.14    40.30    35.73      20.21     12.14
  United Kingdom                   46.81       --       --     8.26         --        --
  Other Countries                  43.07    38.22    38.96     4.09       9.01     10.69

Natural Gas (Cdn$/mcf)
  Canada (2)                        5.76     5.64     3.57     0.85       0.65      0.70
  United States                     7.89     8.16     5.29     1.02       0.89      1.83
  United Kingdom                    8.28       --       --       --         --        --
                                   ------------------------ -------------------------------
</TABLE>

Notes:
(1)  Prices and unit production costs are calculated using our working interest
     production after royalties.
(2)  Includes results of discontinued operations. (See Note 11 to our
     Consolidated Financial Statements).


                                       17
<PAGE>

<TABLE>
<CAPTION>
PRODUCING OIL AND GAS WELLS
(number of wells)                                        2004
------------------------------------------------------------------------------------------------
                                OIL                       GAS                     TOTAL
                     ------------------------   ----------------------    ----------------------
                      Gross (1)       Net (2)   Gross (1)      Net (2)    Gross (1)      Net (2)
<S>                   <C>          <C>          <C>          <C>          <C>          <C>
United States           196           89          208          129          404          218
Yemen                   371          195           --           --          371          195
United Kingdom           27           12           --           --           27           12
Canada                2,831        2,041        2,536        2,201        5,367        4,242
Nigeria                   1            1           --           --            1            1
Colombia                 74           16           --           --           74           16
                     ------------------------   ----------------------    ----------------------
Total                 3,500        2,354        2,744        2,330        6,244        4,684
                      =======================   ======================    ======================
</TABLE>
Notes:
(1)  Gross wells are the total number of wells in which we own an interest.
(2)  Net wells are the sum of fractional interests owned in gross wells.

<TABLE>
<CAPTION>
OIL AND GAS ACREAGE
(thousands of acres)                                       2004
-----------------------------------------------------------------------------------------------
                              DEVELOPED               UNDEVELOPED (1)              TOTAL
                         ------------------        ------------------        ------------------
                         Gross          Net        Gross          Net        Gross          Net
<S>                      <C>            <C>        <C>          <C>          <C>          <C>
United States              182          102        1,020          494        1,202          596
Yemen (2)                   45           24          761          633          806          657
Nigeria (2), (3), (4)        1            1          524          128          525          129
Equatorial Guinea           --           --        1,106          553        1,106          553
Canada                     909          695        2,754        1,680        3,663        2,375
Colombia (5)                 1           --          787          552          788          552
United Kingdom              44           19        1,598          708        1,642          727
Australia                    1            1           --           --            1            1
                         ------------------        ------------------        ------------------
Total                    1,183          842        8,550        4,748        9,733        5,590
                         ==================        ==================        ==================
</TABLE>
Notes:
(1)  Undeveloped acreage is considered to be those acres on which wells have not
     been drilled or completed to a point that would permit production of
     commercial quantities of crude oil and natural gas regardless of whether or
     not such acreage contains proved reserves.
(2)  The acreage is covered by production sharing contracts.
(3)  The acreage is covered by a risk service contract.
(4)  The acreage is covered by a joint venture agreement.
(5)  The acreage is covered by an association contract.

<TABLE>
<CAPTION>
DRILLING ACTIVITY

(number of net wells)                                 2004
--------------------------------------------------------------------------------------------------------
                                 NET EXPLORATORY                   NET DEVELOPMENT
                     ---------------------------------   ----------------------------------
                                       Dry                                 Dry
                     Productive      Holes       Total   Productive      Holes        Total        Total
<S>                  <C>             <C>         <C>     <C>             <C>          <C>          <C>
United States               0.3        1.8         2.1         11.0        1.0         12.0         14.1
United Kingdom               --         --          --           --         --           --           --
Yemen                        --        2.0         2.0         37.3        0.5         37.8         39.8
Nigeria                     0.4        1.0         1.4           --         --           --          1.4
Canada                     13.4        1.0        14.4        202.9         --        202.9        217.3
Colombia                     --         --          --          7.0         --          7.0          7.0
Equatorial Guinea            --        0.5         0.5           --         --           --          0.5
                     ---------------------------------   -----------------------------------------------
Total                      14.1        6.3        20.4        258.2        1.5        259.7        280.1
                     ==================================  ===============================================
</TABLE>

<TABLE>
<CAPTION>
                                                      2003
--------------------------------------------------------------------------------------------------------
                                 NET EXPLORATORY                   NET DEVELOPMENT
                     ---------------------------------   ----------------------------------
                                       Dry                                 Dry
                     Productive      Holes       Total   Productive      Holes        Total        Total
<S>                  <C>             <C>         <C>     <C>             <C>          <C>          <C>
United States                --        0.5         0.5          8.3        0.1          8.4          8.9
Yemen                       8.0        1.0         9.0         49.0         --         49.0         58.0
Nigeria                     0.6         --         0.6           --         --           --          0.6
Canada                     15.4        1.7        17.1        157.7        2.5        160.2        177.3
Colombia                     --        1.0         1.0          6.2         --          6.2          7.2
Brazil                       --        0.2         0.2           --         --           --          0.2
                     ---------------------------------   -----------------------------------------------
Total                      24.0        4.4        28.4        221.2        2.6        223.8        252.2
                     ==================================  ===============================================
</TABLE>

                                       18
<PAGE>

<TABLE>
<CAPTION>
                                                      2002
--------------------------------------------------------------------------------------------------------
                                 NET EXPLORATORY                   NET DEVELOPMENT
                     ---------------------------------   ----------------------------------
                                       Dry                                 Dry
                     Productive      Holes       Total   Productive      Holes        Total        Total
<S>                  <C>             <C>         <C>     <C>             <C>          <C>          <C>
United States              --          1.4         1.4         14.9        0.6         15.5         16.9
Yemen                      --          0.6         0.6         38.0        1.0         39.0         39.6
Canada                     16.0        4.0        20.0        225.0        8.0        233.0        253.0
Australia                  --         --          --            2.0       --            2.0          2.0
Other Countries (1)         0.2        0.7         0.9          2.0        0.2          2.2          3.1
                     ---------------------------------   -----------------------------------------------
Total                      16.2        6.7        22.9        281.9        9.8        291.7        314.6
                     ==================================  ===============================================
</TABLE>
Note:
(1)  Other countries include drilling primarily in Nigeria, Colombia and Brazil.

WELLS IN PROGRESS

At December 31, 2004, we were in the process of drilling ten wells (5.7 net) in
the United States, 29 wells (15.5 net) in Canada, four wells in Yemen (3.0 net),
and one well in Colombia (0.2 net).


SYNCRUDE MINING OPERATIONS

We hold a 7.23% participating interest in Syncrude Canada Ltd. (Syncrude). This
joint venture was established in 1975 to mine shallow oil sands deposits using
open-pit mining methods, extract the bitumen from the oil sands, and upgrade the
bitumen to produce a high-quality, light (32(degree) API), sweet, synthetic
crude oil.

The Syncrude operation exploits a portion of the Athabasca oil sands deposit
which contains bitumen in the unconsolidated sands of the McMurray formation.
Ore bodies are buried beneath 50 to 150 feet of over-burden, have bitumen grades
ranging from 4 to 14 weight percent, and ore bearing sand thickness of 100 to
160 feet.

Syncrude's operations are located on eight leases (10, 12, 17, 22, 29, 30, 31,
and 34) covering 258,000 acres, 40 km north of Fort McMurray in northeast
Alberta.

Syncrude mines oil sands at three mines: Base, North, and Aurora North. These
locations are readily accessible by public road. At the Base Mine (lease 17), a
dragline, bucket wheel reclaimers, and belt conveyors are used for mining and
transporting oil sands. In the North Mine (leases 17 and 22) and in the Aurora
North Mine (leases 10, 12, and 34), a truck-and-shovel and hydro-transport
system is used.

The extraction facilities, which separate bitumen from oil sands, are capable of
processing more than 240 million tons of oil sands per year and about 110 mmbbls
of bitumen per year. To extract bitumen, the oil sands are mixed with water to
form a slurry. Air and chemicals are added to separate bitumen from the sand
grains. The process at the Base Mine uses hot water, steam, and caustic soda to
create a slurry, while at the North Mine and the Aurora North Mine the oil sands
are mixed with warm water to produce a slurry.

The extracted bitumen is fed into a vacuum distillation tower and two cokers for
primary upgrading. The resulting products are then separated into naphtha, light
gas oil, and heavy gas oil streams. These streams are hydrotreated to remove
sulphur and nitrogen impurities to form light, sweet synthetic crude oil.
Sulphur and coke, which are by-products of the process, are stockpiled for
possible future sale. In 2004, the upgrading process yielded 0.86 barrels of
synthetic crude oil per barrel of bitumen.

[GRAPHICS OMITTED]
[Graphic: Alberta map of Syncrude oil sands leases.]

[Margin text: The quality of Syncrude's synthetic crude oil typically allows it
 to be sold at a premium to WTI.]

The quality of Syncrude's synthetic crude oil typically allows it to be sold at
a premium to WTI. In 2004, about 45% of the synthetic crude oil was sold to
Edmonton area refineries and the remaining 55% was sold to refineries in eastern
Canada and the mid-western United States.

Electricity is provided to Syncrude from two generating plants: a 270 MW plant
and an 80 MW plant. Both plants are located at Syncrude and are owned by the
Syncrude participants.

Since operations started in 1978, Syncrude has shipped more than 1.5 billion
barrels of synthetic crude oil to Edmonton, Alberta by Alberta Oil Sands
Pipeline Ltd. The pipeline was expanded in 2004 to accommodate increased
Syncrude production.


                                       19
<PAGE>


To the end of 2004, our total investment in the property, plant and equipment,
including surface mining facilities, transportation equipment, and upgrading
facilities is approximately $1 billion. Based on development plans, our share of
future expansion and equipment replacement costs over the next 35 years is
expected to be about $1.3 billion.

In 1999, the Alberta Energy and Utilities Board (AEUB) extended Syncrude's
operating license for the eight oil sands leases through to 2035. The licence
permits Syncrude to mine oil sands and produce synthetic crude oil from approved
development areas on the oil sands leases. The leases are automatically
renewable as long as oil sands operations are ongoing or the leases are part of
an approved development plan. All eight leases are included in a development
plan approved by the AEUB. There were no known commercial operations on these
leases prior to the start-up of operations in 1978.

Syncrude pays a royalty to the Province of Alberta. Subsequent to 1987, this
royalty was equal to 50% of Syncrude's deemed net profits after deduction of
capital expenditures. In 1995, the Province announced generic royalty terms for
new oil sands projects that provide for a royalty rate of 25% on net revenues
after all costs have been recovered, subject to a minimum 1% gross royalty. In
1997, the Province of Alberta and the Syncrude owners agreed to move to the
generic royalty terms when the total of all allowed capital costs incurred after
December 31, 1995 equalled $2.8 billion (gross). That total was surpassed at the
end of 2001.

In 1999, the AEUB approved an increase in Syncrude's production capacity to
465,700 bbls/d. At the end of 2001, Syncrude had increased its synthetic crude
oil capacity to 246,500 bbls/d with the development of the Aurora North Mine
which involved extending mining operations to a new location about 25 miles
north of the main Syncrude site. In 2001, the Syncrude owners approved the third
stage of the Syncrude expansion, which will increase capacity to 360,000 bbls/d
in 2006. 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 to $7.8 billion. Nexen's share of the project costs was revised
in May 2004 to $565 million, of which $440 million was incurred by year-end
2004. Activities in 2005 are focused on completing the upgrader expansion, as
well as spending $415 million (Nexen's share is $30 million) to replace bitumen
production capacity that will be lost with the closure of the depleted southwest
quadrant of the Base Mine in early 2006.

[GRAPHIC OMITTED]
[Margin text: Syncrude's capacity expansion to 360,000 bbls/d should be complete
 in 2006.]

In 2004, Syncrude's production of marketable synthetic crude oil was 238,000
bbls/d. Nexen's share was 17,200 bbls/d before royalties.

The following table sets out certain operating statistics for the Syncrude
operations:

                                                     2004       2003       2002
-------------------------------------------------------------------------------
Total mined volume (1)
  Millions of tons                                    389        380        375
  Mined volume to oil sands ratio (1)                 2.1        2.3        2.2

Oil sands processed
  Millions of tons                                    188        168        173
  Average bitumen grade (weight %)                   11.1       11.0       11.2

Bitumen in mined oil sands
  Millions of tons                                     21         18         19
  Average extraction recovery (%)                      87         89         90

Bitumen production (2)
  Millions of barrels                                 103         92         98
  Average upgrading yield (%)                          86         86         86

Gross synthetic crude oil shipped (3)
  Millions of barrels                                  87         77         84

Nexen's share of marketable crude oil
  Millions of barrels before royalties                6.3        5.6        6.1
  Millions of barrels after royalties                 6.1        5.5        6.0
                                                   ----------------------------

Notes:
(1)  Includes pre-stripping of mine areas and reclamation volumes.
(2)  Bitumen production in barrels is equal to bitumen in mined oil sands
     multiplied by the average extraction recovery and the appropriate
     conversion factor.
(3)  Approximately 1.2% of the produced synthetic crude oil is used internally
     at Syncrude. The remaining synthetic oil is sold externally.

[GRAPHIC OMITTED]
[Margin text: In 2004, approximately 1.8 tons of oil sand produced 1 barrel of
 bitumen that was upgraded to 0.86 barrels of synthetic crude oil.]


                                       20
<PAGE>

OIL AND GAS MARKETING

Our marketing group sells proprietary and third-party natural gas, crude oil and
power in certain regional markets where we have built a solid physical asset
base. This includes access to transportation, storage and facilities, as well as
crude oil and natural gas we produce or acquire. We optimize the margin on our
base business by trading around our access to these physical assets when market
opportunities present themselves. We use financial and derivative contracts,
including futures, forwards, swaps and options for hedging and for trading
purposes.

Our marketing strategy is to:

o      obtain competitive pricing on the sale of our own oil and gas production,

o      provide market intelligence in support of our oil and gas operations,

o      provide superior customer service to producers and consumers, and

o      capitalize on market opportunities through low-risk trading based on our
       transportation and storage capacity.

This strategy aligns with our corporate focus to extract full value from our
assets, and provides us with the market intelligence needed to deliver our
current and future oil and gas production to market at competitive pricing.


GAS MARKETING
The marketing and trading of natural gas is our marketing division's largest
revenue stream. We focus on key regional markets where we have a strategic
presence - solid customer relationships, in-depth understanding of the market or
established physical trading-based assets. We capture regional opportunities by
managing supply, transportation and storage assets for producers and end users.
In addition to the fee-for-service income we realize from managing these assets,
we generate further net revenue by:

o      capitalizing on location spreads (differences in prices between market
       locations) using our transportation assets, and

o      capitalizing on time spreads (differences in price between summer and
       winter) using our storage assets.

[GRAPHIC OMITTED]
[Margin text: The marketing and trading of natural gas is our marketing
 division's largest revenue stream.]

We have offices in key regions including Calgary, Detroit and Houston. Our
Calgary office provides a variety of services including supply, storage, and
transportation management as well as netback pool arrangements and other
customer services. Our customers include producers and consumers in Western
Canada as well as consumers (including utilities) in Eastern Canada, the
Northeastern United States and the US mid-continent. Our Detroit office works
closely with Calgary to provide services to our customers. Our presence in
Houston has established us in the Gulf Coast region where we have our own
production.

We use our access to transportation and storage facilities to optimize returns
for ourselves as well as our customers.

[GRAPHIC OMITTED]
[Margin text: We use our access to transportation and storage facilities to
 optimize returns.]

In 2004, we grew our asset base by acquiring physical gas purchase and sales
contracts, as well as natural gas transportation capacity on favourable terms.
This gave us access to new producer gas until 2008, as well as pipeline capacity
and gas purchase and sales contracts to the end of 2004. The majority of these
gas purchase and sales contracts have been renewed to the end of 2005. We also
added storage capacity in key regional locations.

Our position as a physical marketer at multiple delivery points in key markets
gives us the flexibility to capitalize on time and location spreads. With
pipeline capacity, we can move gas from producing regions to take advantage of
price differences. We can also use storage capacity to store less expensive
summer gas in the ground until the winter heating season arrives.

In addition to transportation and storage assets, we hold financial contracts
that allow us to capture profits around time and location spreads. The basis
risk we assume on these contracts is based on solid fundamental analysis and
in-depth knowledge of regional markets. The risk is managed proactively by our
product group teams and monitored closely by our risk group, with regular
reporting to management and the Board.


CRUDE OIL MARKETING

Our crude oil business focuses on marketing physical crude oil volumes to end
use refiners. The crude oil group markets our own production and over 100,000
bbls/d of third-party field production to refiners from producing regions where
we operate. In addition to physical marketing, we take advantage of quality
differentials and time spreads.

Our North American operations focus on key regions supported by our offices in
Calgary and Houston. In Western Canada, our producer services group concentrates
on the procurement of a diversified supply base, while the trading team seeks to
optimize the mix for sale to refiners. Traditionally, the


                                       21
<PAGE>

Chicago area has been the key market for Western Canadian crude. The recent
growth in our deep-water Gulf of Mexico crude oil production has given us the
opportunity to expand our presence in that market through our Houston office.

Internationally, we focus on the physical marketing of our Yemen crude oil. In
order to meet customer needs, we may occasionally market other regional crude
types. In addition to our own crude, we market production for our partners and
third parties in the Yemen region. By locating our international crude oil
marketing office in Singapore, we are well positioned to serve both the
producing region and the Asian refining market.

[GRAPHIC OMITTED]
[Margin text: Our international marketing group focuses on the physical
 marketing of our Yemen crude oil.]

Our crude oil marketing group also holds financial contracts that allow us to
capture trading profits around time, quality and location spreads. The basis
risk assumed is, like gas marketing, based on solid fundamental analysis and
proprietary knowledge of regional markets, and it is managed and monitored
closely by our risk group.


POWER MARKETING

Our power marketing group is responsible for optimizing the use of our 100 MW
gas-fired combined-cycle power generation facility at Balzac, Alberta and for
marketing power to larger commercial, industrial and municipal clients within
Alberta. Our Balzac facility began operations in 2001. We expect to increase our
power generation capacity with a 170 MW co-generation facility at Long Lake in
2007, and through our 70 MW Soderglen wind power project in southern Alberta in
2006. We have a 50% interest in each project.


CHEMICALS

We manufacture sodium chlorate and chlor-alkali products (chlorine, caustic soda
and muriatic acid) in Canada and Brazil. This production is sold in North and
South America, with a small amount of sodium chlorate distributed in Asia. Our
manufacturing facilities are modern, reliable, and strategically located to
capitalize on competitive power costs or transportation infrastructure to
minimize production and delivery costs. This enables us to have reliable
supplies and low costs, key factors for marketing bleaching chemicals.

The bleaching chemicals we produce are subject to commodity pricing structures.
Our strategy for adding value in this business focuses on:

o        improving our cost position,

o        maintaining our market share,

o        building a strong, sustainable North American customer base, and

o        capturing new offshore opportunities.

Since 1999, we have made significant investments to grow our capacity, expand
internationally and lower our overall cost structure, allowing us to improve our
position in the bleaching chemicals industry.

The primary raw materials required to produce sodium chlorate and chlor-alkali
products are electricity, salt, and fresh water. Electricity is the single
largest operational cost, making up more than half of our cash costs. Labour is
also a significant component of our manufacturing costs. Approximately 50% of
our workforce is unionized, with collective agreements in place at all of our
unionized plants.

[GRAPHIC OMITTED]
[Margin text: Our chemical facilities are modern, reliable, and strategically
 located to capitalize on competitive power costs or transporatation
 infrastructure.]

AVERAGE ANNUAL PRODUCTION CAPACITY

                                                   2004        2003        2002
--------------------------------------------------------------------------------
Sodium Chlorate (short-tons)
   North America                                446,617     432,812     500,650
   Brazil                                        70,213      70,213      57,320
                                              ----------------------------------
Total                                           516,830     503,025     557,970
                                              ==================================

Chlor-alkali (short-tons)
   North America                                356,002     356,002     351,844
   Brazil                                       109,430     109,430      97,462
                                              ----------------------------------
Total                                           465,432     465,432     449,306
                                              ==================================


                                       22
<PAGE>

NORTH AMERICA
[GRAPHIC OMITTED]
[Graphic: Canada map of chemical plant locations]

The North American pulp and paper industry consumes approximately 95% of local
sodium chlorate production. We market our sodium chlorate production to numerous
pulp and paper mills under multi-year contracts that contain price and volume
provisions. Approximately 30% of this production is sold in Canada, 60% in the
US, and the rest marketed offshore.

We are the third largest manufacturer of sodium chlorate in North America with
five Canadian facilities: Nanaimo, British Columbia; Bruderheim, Alberta;
Brandon, Manitoba; Amherstburg, Ontario; and Beauharnois, Quebec.

In October 2004, we completed an expansion of our Brandon, Manitoba plant by
increasing capacity 33% to 260,000 tonnes per year. This expansion replaced
higher-cost capacity idled in 2002 at Taft, Louisiana. Brandon is currently the
world's largest sodium chlorate facility, and has one of the lowest cost
structures in the industry, significantly enhancing our competitive position in
North America.

[GRAPHIC OMITTED]
[Margin comment: Our Brandon plant is the world's largest sodium chlorate plant
 and one of the lowest cost producers in North America.]

Our chlor-alkali facility at North Vancouver, British Columbia manufactures
caustic soda, chlorine and muriatic acid. Almost all of our caustic soda is
consumed by local pulp and paper mills, while our chlorine is sold to various
customers in the polyvinyl chloride, water purification and petrochemicals
industries, primarily in the United States.


BRAZIL

We entered Brazil in 1999 by acquiring a sodium chlorate plant and a
chlor-alkali plant from Aracruz Cellulose S.A., the leading Brazil manufacturer
of pulp. The majority of the production is sold to Aracruz under a long-term
sales agreement that expires in 2024. This agreement has an initial six year
take-or-pay component that ends in 2005. Most of the chlorine and about 20% of
the sodium chlorate production is sold in the merchant market under shorter-term
contractual arrangements. In 2002, we completed expanding both facilities to
meet Aracruz's growing needs. Chlorate production capacity is now 70,213
short-tons per year and chlor-alkali capacity is 109,430 short-tons per year.

ADDITIONAL FACTORS AFFECTING BUSINESS See Item 7 of this Form 10-K.


GOVERNMENT REGULATIONS

Our operations are subject to various levels of government controls and
regulations in the countries in which we operate. These laws and regulations
include matters relating to land tenure, drilling, production practices,
environmental protection, marketing and pricing policies, royalties, various
taxes and levies including income tax, and foreign trade and investment, all of
which are subject to change from time to time. Current legislation is generally
a matter of public record, and we are unable to predict what additional
legislation or amendments may be proposed that will affect our operations or
when any such proposals, if enacted, might become effective. However, we
participate in many industry and professional associations and otherwise monitor
the progress of proposed legislation and regulatory amendments.


ENVIRONMENTAL REGULATIONS

Our oil and gas and chemical operations are subject to government laws and
regulations designed to protect and regulate the discharge of materials into the
environment in the countries where we operate. We believe that our operations
comply in all material respects with applicable environmental laws. To mitigate
our exposure we apply industry standards, codes and best practices to meet or
exceed these laws and regulations. From time to time, we may conduct activities
in countries where environmental regulatory frameworks are in various stages of
evolution. Where regulations are lacking, we observe Canadian standards where
applicable, as well as internationally accepted industry environmental
management practices.

We have an active Safety, Environment and Social Responsibility group that are
responsible for ensuring that our worldwide operations are conducted in a safe,
ethical and socially responsible manner. We have developed policies for
continuing compliance with environmental laws and regulations in the countries
in which we operate.


                                       23
<PAGE>

ENVIRONMENTAL PROVISIONS AND EXPENDITURES

The ultimate financial impact of environmental laws and regulations is not
clearly known nor can they be reasonably estimated as new standards continue to
evolve in the countries in which we operate. We estimate our future
environmental costs based on past experience and current regulations. At
December 31, 2004, $468 million ($770 million, undiscounted) has been provided
in our consolidated financial statements for asset retirement obligations
relating to our oil and gas, Syncrude and chemicals facilities. During 2004, we
increased our retirement obligations for future dismantlement and site
restoration by $146 million primarily due to the acquisition of oil and gas
properties in the North Sea.

During 2004, our capital expenditures for environmental-related matters,
including environment control facilities, were approximately $31 million. Our
operating expenditures for environmental-related matters were approximately $8
million. Environmental related and site restoration capital expenditures in 2005
are expected to be approximately $47 million, primarily from the remediation of
our Australia and Nigeria oil producing areas.

EMPLOYEES

We had 3,247 employees on December 31, 2004.

Information on our executive officers is presented in Item 10 of this report.

[GRAPHIC OMITTED]
[Margin text: See page 125 for details on our executive officers.]


ITEM 3.    LEGAL PROCEEDINGS

There are a number of lawsuits and claims pending against Nexen, the ultimate
results of which cannot be ascertained at this time. Management is of the
opinion that any amounts assessed against us would not have a material adverse
effect upon our consolidated financial position or results of operations. We
believe we have made adequate provisions for such lawsuits and claims.

Certain of our US oil and gas operations have received, over the years, notices
and demands from the United States Environmental Protection Agency, state
environmental agencies, and certain third parties with respect to certain sites
seeking to require investigation and remediation under federal or state
environmental statutes. In addition, notices, demands, and suits have been
received for certain sites related to historical operations and activities in
the US for which, although no assurances can be made, we believe that certain
assumption and indemnification agreements protect our US operations from any
present or future material liabilities that may arise from these particular
sites.

On June 25, 2003, a subsidiary of Occidental Petroleum Corporation (Occidental)
initiated a request for arbitration at the International Court of Arbitration of
the International Chamber of Commerce regarding an Area of Mutual Interest
Agreement (Agreement) in the Republic of Yemen. Pursuant to the Agreement, if
Nexen proposed to conduct petroleum development operations within two small
areas of Block 51 in the Republic of Yemen (Heijah/Tawila Extension Lands), then
we were to offer Occidental the right to acquire 50% of our interest in those
areas. The Agreement expired on March 12, 2003, with Nexen not having proposed
any such operations. Occidental seeks a claim for declaratory relief under the
Agreement, claims compensation for breach of contract (50% of the net profits
earned or to be earned from the Heijah/Tawila Extension Lands), plus interest
and costs. Subsequent to the expiry of the Agreement, we commenced exploration
activities within Block 51, including the Heijah/Tawila Extension Lands and, in
December 2003, filed a notice of commercial discovery with the Yemen government.
Given that the agreement expired without Nexen having proposed to conduct
petroleum development operations, we believe Occidental's claim is without merit
and we are vigorously defending our contractual rights.


ITEM 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of Nexen's security holders during the
fourth quarter of 2004.


                                       24
<PAGE>

PART II


ITEM 5.    MARKET FOR THE REGISTRANT'S COMMON SHARES AND RELATED STOCKHOLDER
           MATTERS

Nexen's common shares are traded on the Toronto Stock Exchange (TSX) and the New
York Stock Exchange (NYSE) under the symbol NXY.

On December 31, 2004, there were 1,329 registered holders of common shares and
129,199,583 common shares outstanding. The number of registered holders of
common shares is calculated excluding individual participants in securities
positions listings. During the year, we made no purchases of our own equity
securities.

[GRAPHIC OMITTED]
[Margin text: Symbol: NXY, Traded on the TSX and NYSE with 129.2 million common
 shares outstanding.]

TRADING RANGE OF NEXEN'S COMMON SHARES

($/share)                                        TSX (CDN$)          NYSE (US$)
--------------------------------------------------------------------------------
                                              HIGH      LOW        HIGH      LOW
2004
   First Quarter                             53.35    45.00       40.61    34.10
   Second Quarter                            56.50    46.80       42.29    34.49
   Third Quarter                             53.70    44.34       42.13    33.88
   Fourth Quarter                            58.66    48.17       46.56    39.20

2003
   First Quarter                             34.85    29.30       22.55    19.89
   Second Quarter                            35.59    28.26       26.31    19.75
   Third Quarter                             39.68    33.02       29.00    24.03
   Fourth Quarter                            47.08    36.65       36.47    27.32
                                           -------------------------------------

[GRAPHIC OMITTED]
[Margin text: On the TSX in 2004, we traded from a
 low of $44.34 in Q3 to a high of
 $58.66 in Q4.]

QUARTERLY DIVIDENDS ON COMMON SHARES         FIRST     SECOND     THIRD   FOURTH
($/share)                                  QUARTER    QUARTER   QUARTER  QUARTER
--------------------------------------------------------------------------------
2004                                          0.10       0.10      0.10     0.10
2003                                         0.075      0.075     0.075     0.10
                                         ---------------------------------------

[GRAPHIC OMITTED]
[Margin text: We increased our quarterly dividend to $0.10/share in Q4 2003.]

Payment date for dividends was the first day of the next quarter.

The Income Tax Act of Canada requires us to deduct a withholding tax from all
dividends remitted to non-residents. In accordance with the Canada-US Tax
Treaty, we have deducted a withholding tax of 15% on dividends paid to residents
of the United States, except in the case of a company that owns at least 10% of
the voting stock where the withholding tax is 5%.

The Investment Canada Act requires that a "non-Canadian" (as defined) file
notice with Investment Canada and obtain government approval prior to acquiring
control of a "Canadian business" (as defined). Otherwise, there are no
limitations, either under the laws of Canada or in Nexen's charter on the right
of a non-Canadian to hold or vote Nexen's securities.

On February 3, 2000, at a Special Meeting of Shareholders, a Shareholder Rights
Plan was approved. On May 2, 2002, at the Annual General and Special Meeting of
Shareholders, an Amended and Restated Shareholder Rights Plan (Plan) was
approved. The Plan creates a right, which attaches to each present and future
outstanding common share. Each right entitles the holder to acquire additional
common shares during the term of the right. Prior to the separation date, the
rights are not separable from the common shares and no separate certificates are
issued. The separation date would typically occur at the time of an unsolicited
takeover bid, but our Board can defer the separation date.

The Plan creates a right, which can only be exercised when a person acquires 20%
or more of our common shares (a Flip-In Event), for each shareholder, other than
the 20% buyer, to acquire additional common shares at one-half of the market
price at the time of exercise. The Plan must be reapproved by shareholders on or
before our annual general meeting in 2005 to remain effective past that date.


                                       25
<PAGE>

ITEM 6.    SELECTED FINANCIAL DATA

<TABLE>
<CAPTION>
FIVE-YEAR SUMMARY OF SELECTED FINANCIAL DATA IN ACCORDANCE WITH US GAAP

(Cdn$ millions)                                       2004          2003         2002        2001        2000
--------------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS
<S>                                                <C>           <C>          <C>         <C>         <C>
   Net Sales (1)                                     3,176         2,844        2,341       2,356       1,366

   Net Income from Continuing Operations               775           462          299         340         474
   Basic Earnings per Common Share
     from Continuing Operations ($/share)             6.03          3.73         2.45        2.82        3.79
   Diluted Earnings per Common Share
     from Continuing Operations ($/share)             5.95          3.70         2.41        2.78        3.74

   Net Income                                          788           420          352         365         522
   Basic Earnings per Common Share ($/share)          6.13          3.39         2.88        3.03        4.17
   Diluted Earnings per Common Share ($/share)        6.05          3.36         2.84        2.99        4.12

   Production before Royalties (mboe/d) (2)            250           269          269         268         256
   Production after Royalties (mboe/d) (2)             174           185          176         184         171

FINANCIAL POSITION
   Total Assets (2)                                 12,339         7,703        6,764       5,609       5,874
   Long-Term Debt (3)                                4,214         2,470        2,575       2,242       2,238
   Shareholders' Equity                              2,892         2,131        1,812       1,414       1,050

   Capital Investment, including Acquisitions        4,264         1,432        1,545       1,325         841

   Dividends per Common Share ($/share) (4)           0.40         0.325         0.30        0.30        0.30

   Common Shares Outstanding (thousands)           129,200       125,606      122,966     121,202     119,855
                                                 ------------------------------------------------- -----------
</TABLE>

Notes:
(1)  During 2003, we sold non-core conventional light oil assets in southeast
     Saskatchewan in Canada producing 9,000 bbls/d. In late 2004, we concluded
     production from our Buffalo field, offshore Australia as anticipated. The
     results of these operations have been shown as discontinued operations.

(2)  In 2003, production increased from our deep-water Aspen development in the
     Gulf of Mexico in the United States. In 2004, production declined from our
     maturing assets in Yemen at Masila, in Canada, and in the United States on
     the Gulf of Mexico Shelf. In late 2004, we acquired North Sea assets and
     commenced production from Block 51 in Yemen.

(3)  In December 2004, we drew US$1,500 million on unsecured acquisition credit
     facilities to finance the purchase of North Sea assets. The remainder of
     the purchase price was funded from cash on hand.

(4)  Quarterly dividends were increased to 10(cent) per share in the fourth
     quarter of 2003.

[GRAPHIC OMITTED]
[Margin text: See page 108 for differences between Canadian & US GAAP.]


                                       26
<PAGE>

MD&A


[GRAPHIC OMITTED]
[Graphic Image: Masila Block, Yemen]





                                       27
<PAGE>

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


                                TABLE OF CONTENTS


                                                                            PAGE
Executive Summary of 2004 Results.............................................29
Capital Investment............................................................31
       2004 Investment Program................................................31
       2005 Estimated Capital.................................................32
Financial Results
       Year to Year Change in Net Income......................................35
       Oil & Gas and Syncrude
               Production  ...................................................36
               Commodity Prices...............................................39
               Operating Costs................................................42
               Depreciation, Depletion, Amortization and Impairment...........43
               Exploration Expense............................................44
       Oil & Gas and Syncrude Netbacks........................................45
       Oil and Gas Marketing..................................................46
       Chemicals .............................................................48
       Corporate Expenses.....................................................49
       Impact of Foreign Exchange on Operations...............................51
Outlook for 2005..............................................................51
Liquidity and Capital Resources...............................................53
Business Risk Management .....................................................58
Critical Accounting Estimates.................................................64
New Accounting Pronouncements.................................................67


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 SIGNIFICANT DIFFERENCES BETWEEN CANADIAN AND UNITED
STATES (US) ACCOUNTING PRINCIPLES ON THE FINANCIAL STATEMENTS IS DISCLOSED IN
NOTE 19 TO THE CONSOLIDATED FINANCIAL STATEMENTS. THE DATE OF THIS DISCUSSION IS
FEBRUARY 7, 2005.

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 72 WHICH HIGHLIGHTS DIFFERENCES BETWEEN OUR RESERVE ESTIMATES AND RELATED
DISCLOSURES THAT ARE OTHERWISE REQUIRED BY CANADIAN REGULATORY AUTHORITIES.


                                       28
<PAGE>

EXECUTIVE SUMMARY OF 2004 RESULTS

(Cdn$ millions)                                           2004     2003     2002
--------------------------------------------------------------------------------
Net Income                                                 793      578      409
Earnings per Common Share ($/share)                       6.17     4.67     3.34
Cash Flow from Operating Activities                      1,607    1,405    1,250

Production before Royalties (mboe/d) (1)                   250      269      269
Production after Royalties (mboe/d)                        174      185      176

Capital Investment, including Acquisitions               4,264    1,494    1,625

Net Debt (2)                                             4,219    1,690    2,527
Average Foreign Exchange Rate (Canadian to US dollar)     0.77     0.71     0.64
                                                         -----------------------

Notes:
(1)  Production before royalties reflects our working interest before royalties
     and includes production of synthetic crude oil from Syncrude. We have
     presented our working interest before royalties as we measure our
     performance on this basis consistent with other Canadian oil and gas
     companies.

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

[GRAPHIC OMITTED]
[Margin graph: Graph: Net Income (Cdn$ millions)]

In 2004, we had our best year ever financially. Strong oil and gas prices,
outstanding results from marketing, and late-year production additions in Yemen
and the North Sea fuelled our financial results. A stronger Canadian dollar,
declining base production and increasing costs moderated these results.
Nevertheless, net income has almost doubled since 2002. Over the same period,
our average realized oil and gas price only increased 28%. This is, in part, the
result of a strategic transition towards higher margin production, particularly
in the deep-water Gulf of Mexico where we have added over 30,000 boe/d of
low-royalty, low-cost production since 2002.

Margin text: Record financial results were fuelled by strong prices, outstanding
marketing results and new production from Yemen and the North Sea.

WTI averaged US$41.40/bbl in 2004, with crude oil prices spiking to new levels
throughout the year. The gains made from high prices were partially offset by a
strengthening Canadian dollar, relative to the US dollar. Our foreign revenues
and realized commodity prices were impacted when translated into Canadian
dollars, reducing cash flow from operating activities by $200 million and our
net income by $105 million.

To a lesser extent, the strengthening dollar positively affected our results.
Our foreign operating costs and capital expenditures were reduced when
translated into Canadian dollars. Additionally, most of our debt is US dollar
denominated, so the Canadian dollar debt equivalent was also decreased.

In total, we invested $4.3 billion in 2004 and made significant progress on the
many longer-cycle time development projects in our portfolio. In the Athabasca
oil sands, the Syncrude Stage 3 expansion is on schedule for production start-up
in mid-2006 and our Long Lake Project is on budget and on schedule to commence
bitumen production in 2006 and upgrading operations in 2007. In Yemen,
production from the BAK-A field on Block 51 came on stream in November, just 11
months after sanctioning and we had encouraging results from our exploration
program on the block. Offshore West Africa, drilling on OPL-222, offshore
Nigeria, resulted in a significant extension of the Usan discovery. We also
began exploration of OML-115, offshore Nigeria, and Block K, offshore Equatorial
Guinea.

In the fourth quarter, we acquired EnCana Corporation's UK North Sea assets for
US$2.1 billion in cash, subject to certain adjustments. The assets include the
Buzzard development, Scott and Telford producing fields, several undeveloped
discoveries, over 700,000 net exploratory acres and the team that built these
assets.

[GRAPHIC OMITTED]
[Margin text: Our US$2.1 billion North Sea acquisition establishes a new core
 area for us.]

This acquisition creates a new core area for us. The Buzzard development is
currently on schedule to deliver oil volumes in late-2006. Scott and Telford are
currently producing approximately 19,000 boe/d before royalties and there are
opportunities in these fields and surrounding acreage to increase production
over the next few years.


                                       29
<PAGE>

In 2004, we saw production increases from our deep-water Gulf of Mexico
properties, Syncrude, and late-year contributions from Block 51, Scott and
Telford--all higher margin assets. However, these increases were not able to
overcome the declines from our maturing asset base at Masila in Yemen, in
Canada, and in the shallow-water Gulf of Mexico. We reached final production
from our Buffalo field in Australia in the fourth quarter. In addition, our 2003
production volumes included 6,200 boe/d before royalties of production relating
to Canadian assets sold in August 2003.

We added 123 mmboe of proved oil and gas reserves after royalties, including 13
million barrels relating to our Syncrude operations. Most of these additions
related to the North Sea acquisition and Syncrude expansion, offset by some
negative revisions in Yemen and Canada. At our Long Lake oil sands project, SEC
regulations require us to represent bitumen reserves for this project rather
than upgraded synthetic crude oil reserves we plan to sell from the lease. As a
result, we recognized 241 million barrels of proved bitumen reserves on
sanctioning. At year-end, low bitumen prices and high diluent and natural gas
prices resulted in the write-off of our proved bitumen reserves. However, our
Long Lake Project is designed to produce and upgrade bitumen into high-quality
synthetic crude oil in a fully integrated process which requires no diluent or
purchased natural gas. As a result, the economic returns from this process are
not dependent on bitumen, diluent and natural gas prices. This write-off has no
impact on our decision to proceed with this project.

[GRAPHIC OMITTED]
[Margin text: We added 123 mmboe of proved reserves after royalties, mostly in
 the North Sea and at Syncrude. No proved reserves were booked at Long Lake.]

We financed our North Sea acquisition with cash on hand and bridge financing
facilities, increasing our net debt by about $2.6 billion. Historically, we have
used leverage to finance major expansions of our business, such as the Yemen
Masila project in 1993, the Wascana acquisition in 1997, and the Aspen
acquisition in 2002. In all cases, we have successfully used cash flow from
these assets to subsequently reduce our net debt. In 2005, we plan to reduce net
debt with approximately $1.5 billion in asset dispositions.

Our planned 2005 capital program of $2.6 billion is focussed on progressing our
major development projects and drilling over 20 high-potential exploration wells
in the Gulf of Mexico, offshore West Africa, North Sea and in Yemen. Less than
20% will be re-invested in our core assets to sustain production and cash flow.

Going forward, we are well positioned for growth. At the end of 2004, we had
over $3 billion of capital invested in multi-year development projects not yet
producing oil or cash flow. This amount is expected to peak in late-2006 at
approximately $5 billion, as we bring Buzzard and Long Lake on-stream. We expect
net debt to decrease significantly once these projects start contributing cash
flow in late-2006 and in 2007, respectively.

[GRAPHIC OMITTED]
[Margin text: By late-2006, we'll have almost $5 billion invested in multi-year
 projects not yet producing oil or cash flow.]

Our share of incremental production and cash flow from this investment is
expected to be significant. Block 51 in Yemen is expected to reach close to
25,000 bbls/d before royalties, in mid-2005. Syncrude's Stage 3 expansion is
expected to come on stream in early-2006 adding an incremental 8,000 bbls/d
before royalties. Buzzard is on schedule for production start-up planned for
late-2006 with production ramping up to 80,000 boe/d before royalties in 2007.
At Long-Lake, bitumen production is planned to begin in late-2006. In the second
half of 2007, this bitumen will be upgraded to 30,000 bbls/d of premium
synthetic crude oil when the upgrader comes on stream. Later in the decade, we
expect to see significant new production volumes from OPL-222, offshore Nigeria.

Overall, we expect our oil and gas production before royalties to grow to
between 300,000 and 350,000 boe/d in 2007, after projected asset sales and base
declines. We have assumed exploration success contributes little volume to these
estimates.

Most of our new production is subject to little or no royalty payments and
generates significantly higher cash margins than our current production. As a
result, we expect our production after royalties to grow to between 260,000 and
300,000 boe/d in 2007.

[GRAPHIC OMITTED]
[Margin text: In 2007, we expect to produce between 300,000 and 350,000 boe/d
 before royalties.]

                                       30
<PAGE>

<TABLE>
<CAPTION>
CAPITAL INVESTMENT

                                                          ESTIMATED
(Cdn$ millions)                                                2005          2004        2003
---------------------------------------------------------------------------------------------
<S>                                                       <C>               <C>         <C>
New Growth Development                                        1,675           682         358
New Growth Exploration                                          435           266         329
Core Asset Development                                          435           634         589
                                                          -----------------------------------
                                                              2,545         1,582       1,276
Acquisitions                                                     --         2,587         164
                                                          -----------------------------------
Total Oil & Gas and Syncrude                                  2,545         4,169       1,440
Chemicals, Marketing and Other                                   50            95          54
                                                          -----------------------------------
Total Capital                                                 2,595         4,264       1,494
                                                          ===================================
</TABLE>

Our strategy and capital programs are focused on growing long-term value for
shareholders. To maximize value, we invest in:

o    core assets for short-term production and free cash flow to fund ongoing
     capital programs and repay debt;

o    development projects that convert our discoveries into new production and
     cash flow; and

o    exploration projects for longer-term growth.

As conventional basins in North America mature, we are transitioning our
operations towards less mature basins and unconventional resources in more
mature basins. These include the North Sea, Athabasca oil sands, Gulf of Mexico,
offshore West Africa and the Middle East - basins which we believe have
attractive fiscal terms and significant remaining opportunity.

[GRAPHIC OMITTED]
[Margin text: Our capital program supports short, mid and long-term growth.]

[Margin text: We are shifting our capital: investing less in maturing core
 assets and more in attractive multi-year projects.]


2004 INVESTMENT PROGRAM

In 2004, we invested almost $4.3 billion, comprising $1.7 billion in capital
expenditures and $2.6 billion related to our North Sea acquisition. Excluding
this acquisition, most of our capital was invested in multi-year development
projects and long cycle-time exploration. Here is the breakdown of our capital
investment:

<TABLE>
<CAPTION>
                                       NEW GROWTH       NEW GROWTH      CORE ASSET
(Cdn$ millions)                       DEVELOPMENT      EXPLORATION     DEVELOPMENT     TOTAL
---------------------------------------------------------------------------------------------
<S>                                   <C>              <C>             <C>             <C>
Oil and Gas
   Synthetic (mainly Long Lake)               343               19              --       362
   North Sea                                   46                4               7        57
   Yemen                                      112               19             155       286
   United States                               --              133             267       400
   Canada                                      17               27             131       175
   Other Countries                             --               64              24        88
Syncrude                                      164               --              50       214
                                            -------------------------------------------------
                                              682              266             634     1,582

Chemicals                                      --               --              58        58
Marketing, Corporate and Other                 --               --              37        37
                                            -------------------------------------------------
Total Capital                                 682              266             729     1,677
                                            =================================================
As a % of Total Capital                        41%              16%             43%      100%
                                            -------------------------------------------------
</TABLE>

[GRAPHIC OMITTED]
[Chart:  2004 Capital and 2005 Estimated Capital.]

                                       31
<PAGE>

2005 ESTIMATED CAPITAL

In 2005, we are managing our largest development and exploration program ever.
We plan to invest over $2.5 billion on our oil and gas and Syncrude assets
before considering the impact of dispositions. Around 65% of this is focused on
multi-year development projects, with the remainder split equally between new
growth exploration and our core assets.

<TABLE>
<CAPTION>
                                       NEW GROWTH       NEW GROWTH      CORE ASSET
(Cdn$ millions)                       DEVELOPMENT      EXPLORATION     DEVELOPMENT     TOTAL
---------------------------------------------------------------------------------------------
<S>                                   <C>              <C>             <C>             <C>
Oil and Gas
   Synthetic (mainly Long Lake)               765               --              --       765
   North Sea                                  590               50              45       685
   Yemen                                      200               --              70       270
   United States                               --              215             100       315
   Canada                                      --               60             140       200
   Other Countries                             --              110              25       135
Syncrude                                      120               --              55       175
                                      -------------------------------------------------------
                                            1,675              435             435     2,545

Chemicals                                      --               --              17        17
Marketing, Corporate and Other                 --               --              33        33
                                      -------------------------------------------------------
Total Capital                               1,675              435             485     2,595
                                      =======================================================
As a % of Total Capital                       65%              17%             18%      100%
                                      -------------------------------------------------------
</TABLE>

[GRAPHIC OMITTED]
[Margin text: We'll invest over 80% of 2005 capital on major projects and
 exploration.]

NEW GROWTH DEVELOPMENT

LONG LAKE PROJECT

Almost half our new growth development capital is being invested at Long Lake.
The project remains on schedule and on budget. Drilling of the commercial SAGD
wells began in late-2004 and will continue throughout 2005. Construction of the
SAGD and upgrader facilities is expected to begin in 2005, with the SAGD
facilities to be completed in late-2006 and the upgrader in 2007. The upgrader
is expected to come on stream in the second half of 2007 with our share of
bitumen production ramping up to 36,000 bbls/d (approximately 30,000 bbls/d of
synthetic crude oil production).

We are continuing to operate the three well-pair SAGD pilot to optimize
performance and gain a better understanding of our operating requirements. To
date, we have experienced higher than expected steam-to-oil ratios primarily as
a result of the existence of lean zones which absorb the steam without
increasing the oil flow. Late in 2004, we shut in one well-pair and reduced the
operating pressure of the remaining two well-pairs to see if we could reduce
fluid losses into the lean zones. As a result, we have seen fluid losses
decline, and our steam to oil ratio is continuing to drop. Production is now
averaging 500 to 600 bbls/d per well-pair, in line with industry experience and
our expectations given the reduced operating pressures.

As a result of our core hole and horizontal drilling for the commercial
SAGD wells, we are confident that the lean zone density in the commercial area
is lower than the pilot area. We expect to operate most of our commercial wells
at higher pressures than the current operating pressures of the SAGD pilot.
Higher operating pressures increase well productivity.

To ensure certainty and reliability of bitumen production when we begin
upgrading, we are accelerating one well pad consisting of 13 well pairs. This
pad will be drilled and tied-in after the current 65 well pairs, for a gross
cost of $98 million. While there is no change to total project costs,
accelerating this drilling capital increases the total gross capital to upgrader
start-up from $3.4 billion to $3.5 billion. We expect to have sufficient bitumen
supply to fill our upgrader to capacity as a result of the accelerated drilling
of the well pairs and the lower lean zone density.

To the end of December, approximately 35% of the project's total costs are
committed and 20% of these costs have been incurred. Costs to date are
consistent with our original estimates and the project is on time and on budget.

NORTH SEA DEVELOPMENT

Following our acquisition in the North Sea, we invested $46 million in Buzzard.
In 2005, we plan to invest approximately $530 million for development drilling,
pipeline installation and facility construction. This development is on budget
and on schedule to begin production in late-2006, with our share of production
expected to ramp up to 80,000 boe/d before royalties during 2007.

We also plan to evaluate and start developing a number of smaller discoveries on
our North Sea acreage. These discoveries contribute to the expected doubling of
non-Buzzard production in the North Sea by 2008. The first of these projects,
Farragon, is scheduled to come on stream in late-2005, with our share of
production reaching between 3,000 and 4,000 boe/d before royalties by
early-2006.

[GRAPHICS OMITTED]
[Margin text: Our Long Lake and Buzzard developments are on schedule and on
 budget.]

[Margin text: North Sea should be producing about 120,000 boe/d after royalties
 in 2008.]


                                       32
<PAGE>

YEMEN BLOCK 51

At Block 51, we began first oil production ahead of schedule in mid-November.
Production from the BAK-A field was producing 16,700 bbls/d before royalties at
year-end. Early production from several development wells is handled through
temporary production facilities and a new 22-km oil pipeline that connects to
the existing Masila export pipeline. We expect to reach full production of
25,000 bbls/d before royalties late in the second quarter of 2005. Another 15
development wells are planned throughout 2005.

We are developing our second Block 51 discovery, BAK-B. The field will initially
be developed with five wells and is expected to come on stream in late-2005. We
expect the BAK-A and BAK-B fields to maintain production at approximately 25,000
bbls/d before royalties, through 2007. We also expect to have sufficient
capacity with our production facilities to handle any additional growth that may
come from exploration success on the block.


SYNCRUDE STAGE 3 EXPANSION

We expect the Syncrude expansion to be completed in early-2006, adding 8,000
bbls/d before royalties of synthetic crude net to our 7.23% interest in the
joint venture. In 2005, we will focus on completing and commissioning the
upgrader expansion and increasing bitumen production supply.


NEW GROWTH EXPLORATION

We remain committed to exploration for longer-term growth. Like other aspects of
our business, our exploration portfolio has undergone a transition. Once
characterized by non-operated, high-risk prospects, our program is focussing
more on prospects that are operated, so we control timing, and have lower risk.
We have a balance of short and longer cycle-time prospects. Many are also
located near existing infrastructure, allowing for relatively quick tie-in upon
success.

[GRAPHIC OMITTED]
[Margin text: We remain committed to exploration for longer-term growth and have
 both short and longer cycle-time prospects.]

We had a very active exploration program in 2004. We had success on OPL-222 in
Nigeria, and in the Gulf of Mexico at Tobago, Dawson Deep and most recently
Wrigley and Anduin. We will book proved reserves for these discoveries once
commercial projects are sanctioned.

<TABLE>
<CAPTION>
Below are the results of our 2004 exploration program:

WELL                     LOCATION                  INTEREST              WELL RESULTS
-------------------------------------------------------------------------------------------------------------------
<S>                      <C>                       <C>                   <C>
NIGERIA
Usan 5                   OPL-222                   20% non-operated      sampled oil in several intervals
Usan 6                   OPL-222                   20% non-operated      flowed at restricted rate of 5,800 bbls/d
                                                                         from one interval
Ameena                   OML-115                   40% operated          well abandoned

EQUATORIAL GUINEA
Zorro                    Block K                   50% operated          well abandoned

YEMEN
BAK-C                    Block 51                  87.5% operated        well abandoned
BAK-E                    Block 51                  87.5% operated        well abandoned
BAK-I                    Block 51                  87.5% operated        encountered oil shows; testing in
                                                                         progress

US GULF OF MEXICO
Shark                    South Timbalier 174       40% non-operated      well abandoned
Dawson Deep              Garden Banks 625          15% non-operated      discovery expected to begin producing in
                                                                         late-2005 through sub-sea tie-back to the
                                                                         Gunnison SPAR
Tobago                   Alaminos Canyon 858/859   13.34% non-operated   discovery temporarily abandoned; possibly
                                                                         part of future regional development
Crested Butte            Green Canyon 242          100% operated         well abandoned as oil shows were close
                                                                         to salt; further work required to see if
                                                                         side-track warranted
Main Pass 240            Main Pass 240             45% non-operated      well abandoned
Fawkes                   Garden Banks 303          33 1/3% non-operated  well abandoned
Wind River               West Cameron 335          50% non-operated      well abandoned
Wrigley                  Mississippi Canyon 506    50% non-operated      gas discovery expected on stream
                                                                         mid-2006
Anduin                   Mississippi Canyon        50% operated          encountered oil shows; side-tracking to
                         754/755                                         delineate
-------------------------------------------------------------------------------------------------------------------
</TABLE>

[GRAPHIC OMITTED]
[Margin text: 16 wells drilled: 6 successful, 1 requires testing, 9 abandoned.
 See page 44 for dry-hole costs expensed.]

                                       33
<PAGE>

Our US program was delayed in 2004 due to rig delays and storms, but we plan to
drill up to 10 exploration wells in the Gulf in the next year. This includes
major deep-water, sub-salt prospects at Vrede, Knotty Head and Pathfinder. Most
of the drilling rigs are lined up, partner approvals are in place and we are
looking forward to the results of this program.

Overall, we expect to drill more than 20 high-potential wells in 2005, with most
of these to be drilled in the first half of the year. Internationally, we are
planning to drill exploration wells offshore West Africa, at least four wells in
the North Sea and four wells on Block 51 in Yemen.

[GRAPHIC OMITTED]
[Margin text: In 2005, we plan to drill more than 20 high-potential wells.]

We already have three wells underway with results expected in the first half of
2005:

<TABLE>
<CAPTION>
REGION                   WELL                      LOCATION              INTEREST
-----------------------------------------------------------------------------------------
<S>                      <C>                       <C>                   <C>
US Gulf of Mexico        Big Bend                  Mustang Island A-110  50% non-operated
US Gulf of Mexico        Vrede                     Atwater Valley        25% non-operated
                                                   223/224/267/268
Yemen                    BAK-J                     Block 51              87.5% operated
</TABLE>

In Canada, we continue to focus on large unconventional resource opportunities.
We expect to establish commerciality of our Upper Mannville CBM pilot at Corbett
in 2005, setting the stage for full field development, and to continue
evaluating other Upper Mannville and Horseshoe Canyon CBM prospects. We also
plan to continue a number of enhanced oil recovery pilot projects on our heavy
oil properties in west central Saskatchewan. These projects are evaluating
technologies to increase recovery of our extensive heavy oil properties.


CORE ASSETS

We are limiting our capital investment in core assets: the Gulf of Mexico shelf,
Masila in Yemen, and Western Canada. Generally, only 20% of the cash flow they
generate is being reinvested back into these assets. Our goal is to maximize
value from these assets in the form of returns, not necessarily increasing
reserves or production. By maximizing value, we also generate significant free
cash flow from these assets to help fund our major development projects and new
growth exploration.

[GRAPHIC OMITTED]
[Margin text: Core asset investment is focussed on maximizing returns, not just
 increasing production or reserves.]

In the Gulf of Mexico, we tied-in the third development well at Aspen and the
remaining development wells at Gunnison. In 2005, our development program will
focus on a number of shallow-water gas opportunities in the Eugene Island and
Vermilion areas. In the deep-water, we intend to drill and tie back two sub-sea
wells and the Dawson Deep discovery to the Gunnison SPAR.

In the North Sea, we plan to drill, complete and tie-in five development wells
in the Scott/Telford area, work-over several existing wells and de-bottleneck
and upgrade production facilities on the Scott platform in 2005.

In Yemen, the Masila Block continues to generate value. At the end of 2004, we
have produced approximately 80% of Masila's expected reserves and have generated
more than US$1.5 billion of free cash flow, net to us. As we continue to deplete
the remaining reserves, we expect to recover more than US$1 billion of
additional free cash flow before the primary term of our production sharing
agreement expires in 2011.

The Masila fields are maturing and we are managing the pace of our drilling
program to between 20 and 40 wells per year to ensure we recover the remaining
reserves in the most economic and prudent manner. In 2005, we plan to drill at
least 20 wells to further develop existing fields and test deeper horizons where
we have had recent success. We expect our share of Masila production to be
between 74,000 and 84,000 bbls/d before royalties and to generate approximately
$300 million of free cash flow.

In Canada, we continue focusing on maximizing value from our existing assets
through infill drilling, optimizing production from existing wells and reducing
operating costs.


                                       34
<PAGE>

CHEMICALS

In the fourth quarter, our Brandon chemicals operations completed their sixth
expansion using relocated equipment from our idled Louisiana facility. The
expansion increased sodium chlorate production by 65,000 tonnes per year,
raising the annual plant capacity to over 260,000 tonnes. The Brandon plant is
now the largest sodium chlorate plant in the world, and we are one of the
largest and lowest cost producers of sodium chlorate in North America. Low input
and operating costs here are expected to help lower our overall manufacturing
cost of sodium chlorate. Activities in 2005 will focus on maintaining existing
infrastructure and limiting plant downtimes.

[GRAPHIC OMITTED]
[Margin comment: The expansion at Brandon makes it the world's largest sodium
 chlorate plant.]


MARKETING, CORPORATE AND OTHER

In 2004, we continued implementing and realizing full benefits from our SAP and
other information technology platforms.


FINANCIAL RESULTS

<TABLE>
<CAPTION>
YEAR TO YEAR CHANGE IN NET INCOME
                                                                                         MDA PAGE
(Cdn$ millions)                                           2004 VS 2003   2003 VS 2002   REFERENCE
-------------------------------------------------------------------------------------------------
<S>                                                       <C>            <C>            <C>
NET INCOME FOR 2003 AND 2002 (1)                                578             409
                                                          ===========================
   Favourable (unfavourable) variances:

   CASH ITEMS:
     Production volumes, after royalties:
       Crude oil                                               (116)             51
       Natural gas                                               (8)             41
       Change in crude oil inventory                             40             (25)
                                                          ---------------------------
         Total volume variance                                  (84)             67      page 36
                                                          ---------------------------
     Realized commodity prices:
       Crude oil                                                365              48
       Natural gas                                               --             234
                                                          ---------------------------
         Total price variance                                   365             282      page 39
                                                          ---------------------------
     Oil and gas operating expense:
       Conventional                                             (55)             46
       Synthetic                                                 (2)            (14)
                                                          ---------------------------
         Total operating expense variance                       (57)             32      page 42
                                                          ---------------------------
     Marketing contribution                                     (14)             96      page 46
     Chemicals contribution                                      10              (5)     page 48
     General and administrative                                 (39)            (34)     page 49
     Interest expense                                            26              12      page 50
     Current income taxes                                       (38)             13      page 50
     Other                                                      (22)             21      page 51
                                                          ---------------------------
   TOTAL CASH VARIANCE                                          147             484
                                                          ---------------------------

   NON-CASH ITEMS:
     Depreciation, depletion, amortization and impairment:
       Oil & Gas and Syncrude                                   271            (312)     page 43
       Other                                                     13              (5)
     Exploration expense                                        (45)            (12)     page 44
     General and administrative                                 (70)             (4)     page 49
     Future income taxes                                       (176)             34      page 50
     Other                                                       75             (16)     page 51
                                                          ---------------------------
   TOTAL NON-CASH VARIANCE                                       68            (315)
                                                          ---------------------------

                                                          ---------------------------
NET INCOME FOR 2004 AND 2003                                    793             578
                                                          ===========================
</TABLE>

Note:
(1)  Includes results of discontinued operations (see Note 11 to our
     Consolidated Financial Statements).

Significant variances in net income are explained in the sections that follow.
The impact of foreign exchange on our operations is summarized on page 51.

                                       35
<PAGE>

OIL & GAS AND SYNCRUDE

PRODUCTION

<TABLE>
<CAPTION>
All volumes discussed below are our working interest volumes.

                                           2004                          2003                            2002
-----------------------------------------------------------------------------------------------------------------------------
                                    Before            After         Before             After         Before            After
                                 Royalties (1)    Royalties      Royalties (1)     Royalties      Royalties (1)    Royalties
                               ----------------------------------------------------------------------------------------------
<S>                              <C>              <C>            <C>               <C>            <C>              <C>
Oil and Liquids (mbbls/d)
   Yemen                             107.3             53.5          116.8              57.5          118.0             55.8
   Canada (2)                         36.2             28.2           46.3              35.4           56.3             43.4
   United States                      30.0             26.5           28.3              25.0            9.9              8.2
   Australia (3)                       2.7              2.5            6.1               5.6           12.8             10.3
   United Kingdom                      1.5              1.5             --                --             --               --
   Other Countries                     5.3              4.7            5.4               4.6            8.9              5.2
Syncrude (mmbls/d) (4)                17.2             16.6           15.3              15.2           16.6             16.5
                               ----------------------------------------------------------------------------------------------
                                     200.2            133.5          218.2             143.3          222.5            139.4
                               ----------------------------------------------------------------------------------------------
Natural Gas (mmcf/d)
   Canada (2)                          146              115            158               125            167              128
   United States                       148              126            145               122            112               93
   United Kingdom                        3                3             --                --             --               --
                               ----------------------------------------------------------------------------------------------
                                       297              244            303               247            279              221
                               ----------------------------------------------------------------------------------------------

Total (mboe/d)                         250              174            269               185            269              176
                               ==============================================================================================
</TABLE>

Notes:
(1)  We have presented production volumes before royalties as we measure our
     performance on this basis consistent with other Canadian oil and gas
     companies.

(2)  Includes the following production from discontinued operations. See Note 11
     to our Consolidated Financial Statements.

     (mboe/d)                           2004       2003       2002
     -------------------------------------------------------------
     Production
       Before Royalties                   --        6.2       10.5
       After Royalties                    --        4.6        7.8
                                        --------------------------

(3)  Comprises production from discontinued operations. See Note 11 to our
     Consolidated Financial Statements.

(4)  Considered a mining operation for US reporting purposes.

2004 VS 2003 - LOWER PRODUCTION DECREASED NET INCOME BY $84 MILLION

Production after royalties decreased 6% from 2003. Our 2003 production included
volumes from our non-core Canadian light oil properties in southeast
Saskatchewan that were sold in August 2003. Excluding these volumes, our
production after royalties decreased 3%. This table summarizes the change:

<TABLE>
<CAPTION>
                                                                                                      Before          After
(mboe/d)                                                                                           Royalties      Royalties
-----------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                <C>            <C>
2003 Production                                                                                          269            185
    Sale of non-core Canadian properties                                                                  (6)            (5)
                                                                                              -------------------------------
                                                                                                         263            180
    Production changes:
      Masila Block in Yemen                                                                              (11)            (5)
      Block 51 in Yemen                                                                                    1              1
      Canada                                                                                              (6)            (4)
      Gulf of Mexico - deep-water                                                                          8              7
      Gulf of Mexico - shallow-water                                                                      (6)            (5)
      Australia                                                                                           (3)            (3)
      North Sea                                                                                            2              2
      Syncrude                                                                                             2              1
                                                                                              --------------- ---------------
2004 Production                                                                                          250            174
                                                                                              =============== ===============
</TABLE>

[GRAPHICs OMITTED]
[Margin text: Production dropped 6% after royalties and 7% before royalties as
 new volumes did not offset declines in maturing fields.]

[Margin graphic: Bar graph: Oil and Gas Production before royalties (mmboe/d)]

                                       36
<PAGE>

Production before royalties decreased 7% as new volumes from the deep-water Gulf
of Mexico, the North Sea and Block 51 did not offset declines in our maturing
conventional assets and late-life assets offshore Nigeria and Australia and the
sale of Canadian properties in 2003. Our known future production increases are
expected to come from Block 51 in Yemen in 2005, Syncrude in early-2006, first
production from Buzzard in the North Sea in late-2006, and from bitumen
production in 2006 and synthetic crude in 2007 from the Long Lake Project.


YEMEN
Production decreased 8% compared to 2003. The shortfall resulted from declining
base production, lower drilling success rates and delays in approvals for our
development drilling program. As a result, we drilled 73 development wells
rather than the 90 planned, and this drilling was unable to keep up with base
declines. In 2005, we plan to drill at least 20 wells.

First production from Block 51 commenced in November 2004 with initial rates
around 4,000 bbls/d. By mid-2005, we expect production to ramp up to
approximately 25,000 bbls/d before royalties as permanent production facilities,
including water handling facilities, are commissioned.

[GRAPHIC OMITTED]
[Margin text: First oil from Block 51 was achieved ahead of schedule.]

We expect production from Masila and Block 51 to average between 90,000 and
100,000 bbls/d before royalties in 2005.


CANADA

Production was down 9% from 2003, after adjusting for the August 2003 sale of
non-core, light-oil properties in southeast Saskatchewan. To maximize value, we
continue to manage our maturing conventional assets in Western Canada through
selective development, cost control and asset dispositions. In 2005, we expect
them to produce between 52,000 and 56,000 boe/d before royalties, net to us.
Looking ahead, we expect increases as the Long Lake Project starts up with
bitumen production in 2006 and synthetic crude in 2007. We are considering the
sale of certain Canadian oil and gas properties in 2005. Any sale of assets
would reduce our 2005 production volumes.


GULF OF MEXICO

Production averaged an all-time high of 54,700 boe/d before royalties, 4% higher
than last year, due to new deep-water volumes at Aspen and Gunnison.

Our deep-water production grew 8,000 boe/d before royalties over 2003 levels.
These high-margin volumes contribute cash netbacks almost twice our corporate
average. The third Aspen development well, brought on stream in July, is
currently producing 16,200 boe/d before royalties. However, we experienced
higher water cuts on our Aspen-1 well and completed an intervention, attempting
to reduce these cuts. The well was shut-in for most of August to complete this
work. To date, the response has not met our expectations as there has been no
increase in oil production or decrease in water production. We are currently
producing 24,500 boe/d before royalties from all three wells.

[GRAPHIC OMITTED]
[Margin text: We added 8,000 boe/d before royalties of high-margin barrels in
 the deep water. These fuelled our corporate netbacks. See page 45.]

We completed the tie-in of the remaining wells at Gunnison which added 9,000
boe/d before royalties in 2004. These volumes were less than expected as one
well sanded up in early May and another encountered tar on completion. We
successfully re-completed the well that sanded up and brought it back on stream
in mid-August. A sidetrack on the tar well was completed and this well started
producing from one of three intervals in mid-December. We expect to produce from
all three intervals by the end of February 2005.

Our shallow-water production declined 6,000 boe/d before royalties compared to
2003, caused by base declines and delays in our development program. We had
planned an expanded development program in the second half of the year, but it
was delayed due to rig delivery, storms and drilling problems. Development
drilling at Vermilion 302/320, West Cameron 170 and Vermilion 76 helped mitigate
declines.

We expect production from the Gulf of Mexico to average between 50,000 and
60,000 boe/d in 2005.


                                       37
<PAGE>

NORTH SEA

The acquired Scott and Telford fields contributed production for December 2004,
adding 2,000 boe/d before royalties to our annual average. In 2005, we expect
these fields to produce between 14,000 and 18,000 boe/d before royalties, net to
us.


OTHER COUNTRIES

Australia produced its final barrel in November and abandonment activities are
proceeding. We expect abandonment activities to be completed in 2005. Production
from Colombia grew 50% from 2003 to 4,800 bbls/d before royalties as we continue
to implement our development program at Guando. We continue to produce small
volumes from the Ejulebe field offshore Nigeria, but we expect final production
in the first half of 2005.

[GRAPHIC OMITTED]
[Margin text: Australia is fully depleted and Nigeria is to be depleted in
 2005.]


SYNCRUDE

Syncrude achieved a new annual production record despite operating problems
towards the end of the year. In November, we experienced an unscheduled coker
shut-down. After the coker had returned to full capacity in early December, a
major electrical interruption led to the shut-down of the LC finer for the rest
of the year. The LC finer has returned to full capacity. Turnarounds on the
coker and hydrotreater units in early-2005 are expected to cause first quarter
production to be lower than planned by 25%. We expect 2005 Syncrude volumes of
between 16,000 and 18,000 bbls/d before royalties, net to us.

[GRAPHIC OMITTED]
[Margin text: Syncrude produced a record 17.2 mboe/d before royalties,
 net to us.]


2003 VS 2002 - 5% PRODUCTION GROWTH AFTER ROYALTIES ADDED $67 MILLION TO NET
INCOME

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

Production before royalties was flat compared to 2002 as growth in our US
deep-water production was partially offset by dispositions in Canada, production
declines offshore Nigeria and Australia, and maturing conventional assets.
Production from the Masila block in Yemen decreased slightly in 2003 consistent
with the overall decline in the field's base production. In Canada, we
aggressively managed our assets by developing them where we could add value or
by selling them at attractive prices where this maximized value. 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.

Our production at Buffalo, offshore Australia and at Ejulebe, offshore Nigeria
declined as expected throughout 2003 as both fields approached the end of their
economic life. Syncrude production decreased 8% in 2003 as an unplanned
additional coker turnaround was completed during the year.


                                       38
<PAGE>

COMMODITY PRICES

                                                        2004      2003      2002
--------------------------------------------------------------------------------
CRUDE OIL
   West Texas Intermediate (US$/bbl)                   41.40     31.04     26.09
                                                      --------------------------

   Differentials (1) (US$/bbl)
     Masila                                             4.84      3.03      1.41
     Heavy Oil                                         13.53      8.63      6.49
     MARS                                               6.15      3.53      2.51

   Producing Assets (Cdn$/bbl)
     Yemen                                             47.59     39.45     38.80
     Canada                                            36.60     32.37     31.13
     United States                                     46.60     37.68     38.88
     Syncrude                                          52.80     43.36     40.89
     Australia                                         51.22     43.14     40.30
     North Sea                                         46.81        --        --
     Other Countries                                   43.07     38.22     38.96

   Corporate Average (Cdn$/bbl)                        45.90     38.04     37.13
                                                      --------------------------

NATURAL GAS
   New York Mercantile Exchange (US$/mmbtu)             6.19      5.60      3.37
   AECO (Cdn$/mcf)                                      6.44      6.35      3.84
                                                      --------------------------

   Producing Assets (Cdn$/mcf)
     Canada                                             5.76      5.64      3.57
     United States                                      7.89      8.16      5.29
     North Sea                                          8.28        --        --

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

NEXEN'S AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe)  44.94     38.63     35.14
                                                      --------------------------

AVERAGE FOREIGN EXCHANGE RATE
   Canadian to US Dollar                              0.7683    0.7135    0.6369
                                                      --------------------------

Note:
(1)  These differentials are a discount to WTI.

[GRAPHIC OMITTED]
[Margin graphic: Chart of Nexen's average realized oil and gas price 2002-2004]

2004 VS 2003 - HIGHER REALIZED PRICES ADDED $365 MILLION TO NET INCOME

Crude oil prices reached record levels in 2004, supported by supply concerns,
high demand and speculative traders increasing volatility to all-time highs. The
positive impact of strong crude oil reference prices was offset in part by the
weakening US dollar and widening crude oil quality differentials.

All of our oil sales and most of our gas sales are denominated in or referenced
to US dollars. As a result, a stronger Canadian dollar relative to the US dollar
reduced our realized crude oil price by $3.50/bbl and our realized natural gas
price by $0.50/mcf. In total, our net sales decreased $220 million from 2003 due
to the weakening US dollar. The Canadian to US dollar exchange rate closed the
year at 83(cent).


[GRAPHIC OMITTED]
[Margin text: A stronger Canadian dollar reduced our realized oil and gas prices
 and dropped net sales by $220 million.]

                                       39
<PAGE>

CRUDE OIL REFERENCE PRICES

Crude oil prices reached record highs in 2004 and West Texas Intermediate (WTI)
averaged US$41.40/bbl in 2004, 33% higher than its 2003 average of US$31.04/bbl.
At its peak, WTI broke through US$55/bbl. Strong demand and concerns around
supply disruptions and inventories, coupled with significant volatility,
contributed to the increase.

                                [GRAPHIC OMITTED]
               [LINE CHART - 2004 Oil Prices (WTI Monthly Average]

Strong global demand, led by China and India, prevailed throughout much of 2004.
Even as WTI reached successive record highs late in the year, demand for crude
oil, particularly sweet blends, remained strong globally. While global demand
drove crude oil prices up, actual and potential supply concerns supported major
price moves:

o    terrorist activities in Iraq continued throughout the year, disrupting
     supply on several occasions;

o    attacks in Saudi Arabia called into question not only the security of
     current supply, but also the security of the only significant spare
     capacity globally;

o    on-going civil unrest in Nigeria and Venezuela impacted their ability to
     export crude;

o    labour disputes and safety concerns in the North Sea disrupted supply on
     several occasions, increasing concerns around already tight European
     supply;

o    Hurricane Ivan disrupted supply from the Gulf of Mexico in the third
     quarter and increased concern over low inventory levels in the US; and

o    the Yukos bankruptcy crisis reduced expected production increases from
     Russia.

OPEC responded by increasing output on several occasions, but these increases
were not enough to change the perception that there was insufficient stable
supply to meet demand.

These events caused significant oil price volatility. As a result, traders and
longer-term commodity investors flocked to the market, pushing daily trading
bands higher than previously observed. Traders' positions and related
profit-taking created more volatility. With supply concerns, growing speculation
and continued volatility, we expect to see high crude oil prices continue into
2005.

[GRAPHICS OMITTED]
[Margin text: WTI oil price was 33% higher than in 2003, reflecting supply
 concerns.]
[Margin text: We expect strong crude oil prices in 2005.]

CRUDE OIL DIFFERENTIALS

Crude oil differentials were wide in 2004 due mostly to strong benchmark prices.
Growing global demand for diesel and gasoline has created a premium for light,
sweet crudes. Incremental heavy, sour barrels brought on by OPEC throughout the
year widened out the light/heavy differentials even further. The Canadian heavy
oil differential widened to average US$13.53/bbl, as light, sweet blends
increased in value relative to heavy, sour blends. Although differentials were
wide, the normal seasonal patterns held true which narrows the heavy oil
differential through the summer when there is increased demand due to road
construction. Heavy oil differentials reached a record-wide US$22.67/bbl in
December from these factors.

[GRAPHIC OMITTED]
[Margin text: Widening differentials reduced the price we received for our
 heavy oil, Masila and Aspen volumes.]


                                       40
<PAGE>

The WTI/Brent differential (relevant for our Masila crude and North Sea
production) widened to average US$3.19/bbl in 2004 compared to US$2.20 in 2003.
Higher freight rates due to increased production out of the Middle East made
Brent more expensive to purchase, thereby decreasing its value relative to WTI.

The Masila differential tracked the Brent/WTI spread very closely through the
first eight months of the year, but widened relative to both WTI and Brent late
in the year. As with Canadian heavy oil differentials, our Masila barrels were
impacted by the increased supply of heavy, sour oil from the Middle East later
in the year and strong demand by Asian refiners for lighter blends. The
differential reached US$7.84/bbl in the fourth quarter, compared to its annual
average of US$4.84.

Similar to Canadian heavy oil and Masila, the MARS differential (relevant for
Aspen) widened on the strength of WTI and the increased supply of world heavies.

NATURAL GAS REFERENCE PRICES

Natural gas prices remained strong in 2004, buoyed by high crude oil prices and
tight long-term supply and demand fundamentals. In 2004, NYMEX averaged
US$6.19/mcf, 11% higher than 2003. Weather was reasonably mild in North America,
causing a strong build in inventory levels into winter.

                                [GRAPHIC OMITTED]
         [LINE CHART - 2004 Natural Gas Prices (NYMEX Monthly Average)]

At year-end, inventory levels were 3% higher than 2003 and 11% higher than the
five-year average. Despite this, long-term concerns remain around the ability of
supply to keep up with demand from North American utilities. As a result, we
expect prices to remain above US$5/mmbtu into the future. Even with short-term
bearish fundamentals, prices tracked their normal seasonal pattern and remained
relatively strong into winter, consistent with higher heating oil prices.

[GRAPHICS OMITTED]
[Margin text: NYMEX gas price was 11% higher than in 2003, reflecting concerns
 that supply could not keep pace with demand.]

[Margin text: We expect prices to remain above US$5/mcf into the future]


2003 VS 2002 - HIGHER REALIZED PRICES ADDED $282 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 stronger Canadian dollar and wider crude oil differentials.

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


                                       41
<PAGE>

<TABLE>
<CAPTION>
OPERATING COSTS

(Cdn$/boe)                                   2004                        2003                            2002
-----------------------------------------------------------------------------------------------------------------------------
                                       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                                 2.80          5.64            2.16             4.37            1.95            4.13
   Canada                                7.12          8.98            6.00             7.76            5.70            7.45
   United States                         5.30          6.12            4.49             5.19            9.09           10.87
   Australia                            32.94         35.73           18.60            20.21            9.76           12.14
   United Kingdom                        8.26          8.26              --               --              --              --
   Other Countries                       3.76          4.09            7.47             9.01            6.21           10.69
   Average Conventional                  5.13          7.59            4.17             6.24            4.60            7.24
                                 --------------------------------------------------------------------------------------------

Synthetic Crude Oil
   Syncrude                             19.89         20.61           21.96            22.18           18.10           18.21
Average Oil and Gas                      6.15          8.83            5.19             7.56            5.42            8.26
                                 --------------------------------------------------------------------------------------------
</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.

2004 VS 2003 - HIGHER OIL AND GAS OPERATING COSTS DECREASED NET INCOME BY $57
MILLION

Our operating costs have increased as a result of high-cost, late-life barrels
in Australia, higher maintenance costs in Yemen and Canada, more workover and
remediation activity in the Gulf of Mexico and the spread of fixed costs over
fewer barrels.

[GRAPHIC OMITTED]
[Margin text: Higher operating costs per boe reflect lower volumes and
 increased maintenance and workovers.]

Flow line replacements, higher water handling costs and increased maintenance at
Masila in Yemen increased our corporate unit operating costs by 30(cent)/boe.
However, these increased Yemen costs only reduce our corporate netbacks by
5(cent)/boe as a result of the cost recovery mechanism contained in our
production sharing agreement.

Operating costs in Canada were slightly lower than 2003, but because of
declining volumes, our corporate average unit costs increased by 25(cent)/boe.
We expect our unit costs to continue to increase with increased water handling,
higher labour costs and declining volumes.

Aspen-1 intervention costs of $12 million were expensed during the year. They
were higher than expected as storm activity in the Gulf extended the work. These
costs, together with higher workover activities on the Shelf, contributed a
28(cent)/boe increase to our corporate unit costs.

Australia produced its final barrel in November. These expensive late-life
barrels increased our corporate unit costs by 30(cent)/boe but high crude prices
allowed us to produce them economically.

The incremental North Sea barrels added 7(cent)/boe to our corporate average for
the year.

The strength of the Canadian dollar reduced our US-dollar denominated operating
costs, contributing a 25(cent)/boe reduction to our corporate unit costs.

Syncrude's operating costs were flat compared to 2003, but because of increased
volumes, unit costs decreased 9%. Higher natural gas input costs were offset by
lower maintenance costs in 2004 since there was not a major coker turnaround. As
more expensive Syncrude barrels were a larger portion of our total corporate
production in the year, our corporate unit operating costs increased by
17(cent)/boe.

[GRAPHIC OMITTED]
[Margin graphic: Nexen's operating Costs before Royalties ($/boe) 2002 - 2004]

2003 VS 2002 - LOWER OIL AND GAS OPERATING COSTS INCREASED NET INCOME BY $32
MILLION

Conventional unit operating costs decreased as we added low-cost Aspen
production in the Gulf of Mexico and the Canadian dollar strengthened 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 40(cent)/boe. Aspen
production costs are lower than our corporate average for conventional
production as most of the costs in the deep-water are capital related.


                                       42
<PAGE>

The strengthening Canadian dollar decreased US-dollar denominated operating
costs, lowering our corporate average unit operating costs by approximately
25(cent)/boe. Higher repairs, increased maintenance and workover activity
resulted in a 55(cent)/bbl increase in Yemen operating costs. However, these
increased Yemen costs only reduced our corporate netbacks by 14(cent)/boe as a
result of the cost recovery mechanism contained in our production sharing
agreement. 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.

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

(Cdn$/boe)                                     2004                           2003                            2002
-----------------------------------------------------------------------------------------------------------------------------
                                       Before         After          Before            After          Before           After
                                    Royalties (2) Royalties       Royalties (2)    Royalties       Royalties (2)   Royalties
                                 --------------------------------------------------------------------------------------------
<S>                                 <C>           <C>             <C>              <C>             <C>             <C>
Conventional Oil and Gas
   Yemen                                 4.35          8.77            3.96             8.03            3.47            7.34
   Canada (1)                            9.02         11.37            9.10            11.76            8.22           10.72
   United States                        12.93         14.93           10.80            12.47           12.74           15.38
   Australia                             5.82          6.31           13.31            14.46           10.45           12.99
   United Kingdom                       22.44         22.44              --               --              --              --
   Other Countries                       9.90         10.77           17.09            22.47           13.22           22.90
   Average Conventional                  7.87         11.64            7.37            11.04            6.84           10.81
                                 --------------------------------------------------------------------------------------------

Synthetic Crude Oil
   Syncrude                              2.75          2.85            2.50             2.53            2.13            2.17
Average Oil and Gas                      7.52         10.80            7.09            10.33            6.55           10.01
                                 --------------------------------------------------------------------------------------------
</TABLE>

Notes:
(1)  2003 DD&A per boe excludes the impairment charge described in Note 5 to 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.

2004 VS 2003 - LOWER OIL AND GAS DD&A INCREASED NET INCOME BY $271 MILLION

Our DD&A expense in 2003 included an impairment charge of $269 million largely
attributable to Canadian heavy oil property negative reserve revisions.
Excluding this charge from our 2003 per unit DD&A costs, our per unit corporate
depletion rate has increased. Higher depletion from our more capital-intensive
deep- water properties in the Gulf of Mexico has increased corporate rates by
70(cent)/boe. These properties, however, benefit from low royalties and lower
unit operating costs as most of the costs are capital in nature.

Yemen increased our corporate rate by 30(cent)/boe mainly due to the additional
volumes from Block 51, offset slightly by lower volumes at Masila. The North Sea
volumes increased our corporate rate by 20(cent)/boe. Our UK depletion rate of
$22.44/boe reflects the depletion of the portion of the acquisition cost
allocated to our interests in the Scott/Telford fields on a before-tax basis.

Syncrude depletion rates increased reflecting the depletable costs of the Aurora
2 bitumen train which came into service in late-2003.

By way of offset, we benefited from the strong Canadian dollar as the depletion
of our US and International assets is denominated in US dollars. This lowered
our depletion rate by 45(cent)/boe. As well, the depletable costs on our
Canadian heavy oil properties were reduced at year-end 2003 and both Australia
and Nigeria are nearly fully depleted. The write down of our Canadian heavy oil
properties reduced our depletion rate by 31(cent)/boe and lower volumes in
Canada, Australia and Nigeria contributed a combined reduction of 65(cent)/boe.

[GRAPHIC OMITTED]
[Margin text: Our DD&A rate is increasing because of more capital-intensive
 areas includiong the Gulf of Mexico and the North Sea.]


2003 VS 2002 - HIGHER OIL AND GAS DD&A REDUCED NET INCOME BY $312 MILLION

Conventional depletion rates increased with higher 2002 finding and development
costs and our changing production mix, as more capital-intensive properties like
Aspen contributed production 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
prepared to abandon these fields.


                                       43
<PAGE>

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 48(cent)/boe.

Our 2003 DD&A expense includes an impairment charge of $269 million largely
attributable to reserve revisions to Canadian heavy oil properties. These
revisions reflected our more conservative view of production profiles for
certain properties, proven undeveloped reserves we were no longer certain we
could recover and changes in end-of-life economic assumptions.


EXPLORATION EXPENSE (1)


(Cdn$ millions)                                             2004    2003    2002
--------------------------------------------------------------------------------
Seismic                                                       73      62      80
Unsuccessful Drilling                                        125      70      61
Other                                                         48      69      48
                                                            --------------------
Total Exploration Expense                                    246     201     189
                                                            ====================

New Growth Exploration                                       266     267     179
Geological and Geophysical Costs                              73      62      80
                                                            --------------------
Total Exploration Expenditures                               339     329     259
                                                            ====================

Exploration Expense as a % of Exploration Expenditures       73%     61%     73%
                                                            --------------------

Note:
(1)  Includes exploration expense from discontinued operations. See Note 11 to
     our Consolidated Financial Statements.

2004 VS 2003 - HIGHER EXPLORATION EXPENSE REDUCED NET INCOME BY $45 MILLION

Increased exploration expense reflected the increase in our 2004 exploration
capital expenditures. We had further success at Usan on OPL-222, offshore
Nigeria, Block 51 in Yemen and at Dawson Deep, Tobago, Wrigley and Anduin in the
deep-water Gulf of Mexico. However, unsuccessful drilling included dry holes in
the Gulf of Mexico, offshore Nigeria and Equatorial Guinea, and in Yemen.

[GRAPHIC OMITTED]
[Margin text: Increased 2004 exploration expense reflects higher exploration
 capital. See 2004 drilling results on page 33.]

In the Gulf of Mexico, we had five dry holes: Crested Butte, Main Pass 240,
Shark, Fawkes and Wind River. At our 100%-owned Crested Butte well on Green
Canyon Block 242, we found oil-bearing sands in many horizons, but the volumes
were not commercial so we abandoned the well. Further work is required to
determine if a sidetrack is warranted. We expensed $39 million of well costs in
the fourth quarter. In 2004, we drilled Main Pass 240 and found the objective
sand wet. This well was abandoned in December 2004. Shark was an
ultra-deep-shelf gas test on South Timbalier 174 that finished drilling during
the first quarter of 2004. Following our evaluation, we expensed $25 million of
well costs. While the well has been abandoned, we can re-enter it if required.
Fawkes and Wind River, located in deep water, completed drilling and were
abandoned in January 2005, resulting in a write-off of $13 million in 2004.
Overall, dry hole and seismic costs in the Gulf of Mexico accounted for over 50%
of our exploration expense.

[GRAPHIC OMITTED]
[Margin text: Gulf of Mexico accounts for half our 2004 dry-hole and seismic
 costs.]

Dry hole costs also included the Ameena prospect on OML-115, offshore Nigeria,
the Zorro-1 prospect, offshore Equatorial Guinea and two unsuccessful
exploration wells on Block 51 in Yemen.


2003 VS 2002 - HIGHER EXPLORATION EXPENSE REDUCED NET INCOME $12 MILLION

Exploration expense was higher in light of our increased 2003 exploration
capital expenditures. We had success in 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 where we found hydrocarbons but not commercial quantities, so the well
costs were written off. We were unsuccessful at Santa Rosa.

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.


                                       44
<PAGE>

OIL & GAS AND SYNCRUDE NETBACKS

Netbacks are the cash margins we receive for every equivalent barrel sold. Below
are the sales prices, per unit costs and netbacks for our producing assets,
calculated using our working interest production before and after royalties.

<TABLE>
<CAPTION>
BEFORE ROYALTIES

($/boe) 2004
---------------------------------------------------------------------------------------------------------------------
                         Yemen    Canada          US   Australia         UK         Other     Syncrude         Total
                       ----------------------------------------------------------------------------------------------
<S>                      <C>       <C>         <C>         <C>        <C>           <C>          <C>           <C>
Sales                    47.59     35.76       46.94       51.22      47.45         43.07        52.80         44.94
Royalties and other     (23.98)    (7.40)      (6.29)      (4.00)        --         (3.49)       (1.84)       (13.65)
Operating expenses       (2.80)    (7.12)      (5.30)     (32.94)     (8.26)        (3.76)      (19.89)        (6.15)
In-country taxes         (5.82)       --          --          --         --            --           --         (2.48)
                       ----------------------------------------------------------------------------------------------

Cash netback             14.99     21.24       35.35       14.28      39.19         35.82        31.07         22.66
                       ==============================================================================================

($/boe) 2003
---------------------------------------------------------------------------------------------------------------------
                         Yemen    Canada          US   Australia         UK         Other     Syncrude         Total
                       ----------------------------------------------------------------------------------------------
Sales                    39.45     32.99       42.88       43.14         --         38.22        43.36         38.63
Royalties and other     (19.98)    (7.53)      (5.91)      (3.44)        --         (5.69)       (0.48)       (12.14)
Operating expenses       (2.16)    (6.00)      (4.49)     (18.60)        --         (7.47)      (21.96)        (5.19)
In-country taxes         (4.73)       --          --          --         --            --           --         (2.06)
                       ----------------------------------------------------------------------------------------------

Cash netback             12.58     19.46       32.48       21.10         --         25.06        20.92         19.24
                       ==============================================================================================

($/boe) 2002
---------------------------------------------------------------------------------------------------------------------
                         Yemen    Canada          US   Australia         UK         Other     Syncrude         Total
                       ----------------------------------------------------------------------------------------------
Sales                    38.80     27.90       34.21       40.30         --         38.96        40.89         35.14
Royalties and other     (20.45)    (6.53)      (5.82)      (7.88)        --        (16.48)       (0.36)       (12.56)
Operating expenses       (1.95)    (5.70)      (9.09)      (9.76)        --         (6.21)      (18.10)        (5.42)
In-country taxes         (4.81)       --          --          --         --            --           --         (2.10)
                       ----------------------------------------------------------------------------------------------

Cash netback             11.59     15.67       19.30       22.66         --         16.27        22.43         15.06
                       ==============================================================================================

AFTER ROYALTIES

($/boe) 2004
---------------------------------------------------------------------------------------------------------------------
                         Yemen    Canada          US   Australia         UK         Other     Syncrude         Total
                       ----------------------------------------------------------------------------------------------
Sales                    47.59     35.76       46.94       51.22      47.45         43.07        52.80         44.94
Operating expenses       (5.64)    (8.98)      (6.12)     (35.73)     (8.26)        (4.09)      (20.61)        (8.83)
In-country taxes        (11.72)       --          --          --         --            --           --         (3.57)
                       ----------------------------------------------------------------------------------------------

Cash netback             30.23     26.78       40.82       15.49      39.19         38.98        32.19         32.54
                       ==============================================================================================

($/boe) 2003
---------------------------------------------------------------------------------------------------------------------
                         Yemen    Canada          US   Australia         UK         Other     Syncrude         Total
                       ----------------------------------------------------------------------------------------------
Sales                    39.45     32.99       42.88       43.14         --         38.22        43.36         38.63
Operating expenses       (4.37)    (7.76)      (5.19)     (20.21)        --         (9.01)      (22.18)        (7.56)
In-country taxes         (9.58)       --          --          --         --            --           --         (3.00)
                       ----------------------------------------------------------------------------------------------

Cash netback             25.50     25.23       37.69       22.93         --         29.21        21.18         28.07
                       ==============================================================================================

($/boe) 2002
---------------------------------------------------------------------------------------------------------------------
                         Yemen    Canada          US   Australia          UK         Other     Syncrude         Total
                       ----------------------------------------------------------------------------------------------
Sales                    38.80     27.90       34.21       40.30         --         38.96        40.89         35.14
Operating expenses       (4.13)    (7.45)     (10.87)     (12.14)        --        (10.69)      (18.21)        (8.26)
In-country taxes        (10.17)       --          --          --         --            --           --         (3.20)
                       ----------------------------------------------------------------------------------------------

Cash netback             24.50     20.45       23.34       28.16         --         28.27        22.68         23.68
                       ==============================================================================================
</TABLE>

[GRAPHIC OMITTED]
[Margin text: With little or no royalties, new production from the deep-water
 Gulf of Mexico and North Sea is driving our corporate netbacks.]

                                       45
<PAGE>

<TABLE>
<CAPTION>
OIL AND GAS MARKETING

(Cdn$ millions)                                                  2004       2003    2002
-----------------------------------------------------------------------------------------
<S>                                                               <C>        <C>     <C>
   Revenue                                                        623        568     496
   Transportation                                                (466)      (398)   (423)
   Other                                                           (2)        (1)     --
                                                                -------------------------
Net Revenue                                                       155        169      73
                                                                =========================

Marketing Contribution to Income from Continuing Operations
    before Income Taxes                                            87        111      35
                                                                -------------------------

Natural Gas
   Physical Sales Volumes (bcf/d) (1)                             4.9        3.3     2.9
   Transportation Capacity (bcf/d)                                3.5        2.0     1.2
   Storage Capacity (bcf)                                          27         18       9

Crude Oil
   Physical Sales Volumes (mbbls/d) (1)                           465        479     412
   Storage Capacity (mbbls)                                       408         --      --

Value-at-Risk
   Year-end                                                        21         21      19
   High                                                            42         31      28
   Low                                                             17         14      12
   Average                                                         29         20      17
                                                                -------------------------
</TABLE>

Note:
(1)  Excludes intra-segment transactions.

[GRAPHIC OMITTED]
[Margin graphic:  Oil and Gas Volumes Marketed (boe/d)]

2004 VS 2003 - NET MARKETING REVENUE DECREASED NET INCOME BY $14 MILLION

Although more profitable in 2003, marketing had another exceptional year in
2004, with net revenue of $155 million. Gas marketing contributed $95 million to
net revenue from asset-based trading, our energy services business, and from
transportation and commodity contracts acquired on favourable terms.

[GRAPHIC OMITTED]
[Margin text: Gas marketing contributed 61% of marketing revenue.]

During the year, we took advantage of market inefficiencies and seasonal
variations. In particular, our transportation and storage capacity gave us the
flexibility to capitalize on weather events by allowing us to move gas to where
it was needed most. We also held financial contracts that allowed us to capture
trading profits around time and location spreads.

North American crude oil contributed $25 million to net revenue as varying
degrees of backwardation (declining prices) in the forward price curve
throughout the year allowed us to capitalize on calendar spreads. In addition,
we took advantage of quality spreads and arbitrage opportunities to capture
favourable price differences.

International crude oil contributed $24 million, three times higher than last
year. Throughout the year, we successfully capitalized on the pricing of
purchases relative to sales as we took advantage of backwardation in the forward
price curve.


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.

                                       46
<PAGE>

COMPOSITION OF NET MARKETING REVENUE

(Cdn$ millions)                                                 2004        2003
--------------------------------------------------------------------------------
Trading Activities                                               133         148
Non-Trading Activities                                            22          21
                                                               -----------------
Total Net Marketing Revenue                                      155         169
                                                               =================

TRADING ACTIVITIES

In marketing, we enter into contracts to purchase and sell crude oil and natural
gas. We also use financial and derivative contracts, including futures,
forwards, swaps and options for hedging and trading purposes.

We account for all derivative contracts, not designated as hedges for accounting
purposes, 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 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.

[GRAPHIC OMITTED]
[Margin text: We mark-to-market all derivative contracts not designated as
 hedges. The gain or loss is recorded in marketing and other income.]


FAIR VALUE OF DERIVATIVE CONTRACTS

At December 31, 2004, the fair value of our derivative contracts not designated
as hedges totalled $93 million (2003 - $106 million). Below is a breakdown of
this fair value by valuation method and contract maturity:

<TABLE>
<CAPTION>
(Cdn$ millions)                                                          MATURITY
----------------------------------------------------------------------------------------------------------
                                     (less than)1 year   1-3 years   4-5 years (more than)5 years   Total
                                     ---------------------------------------------------------------------
<S>                                  <C>                 <C>         <C>        <C>                 <C>
Prices
   Actively Quoted Markets                           5          (3)         --                 --       2
   From Other External Sources                      43          40           9                 (1)     91
   Based on Models and
    Other Valuation Methods                         --          --          --                 --      --
                                     ---------------------------------------------------------------------
Total                                               48          37           9                 (1)     93
                                     =====================================================================
</TABLE>

More than 50% of the unrealized fair value relates to contracts that will settle
in 2005. 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.

[GRAPHIC OMITTED]
[Margin text: More than 50% of our unrealized fair value is for contracts
 settling in 2005. This helps reduce our risk.]

At December 31, 2004, we had $6 million of unrecognized gains on our derivative
contracts designated as accounting hedges of the future sale of our gas
inventory. These gains will be recognized in income when the inventory is sold.
These contracts were valued from actively quoted markets and settle within 12
months.

We do not use option valuation methods to record income on transportation and
storage contracts.


                                      47
<PAGE>

<TABLE>
<CAPTION>
CHANGES IN FAIR VALUE OF DERIVATIVE 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, 2003                                      106               --                 --             106
Change in Fair Value of Contracts                                    (26)              77                 82             133
Net Losses (Gains) on Contracts Closed                               (69)             (77)                --            (146)
Changes in Valuation Techniques
    and Assumptions (1)                                               --               --                 --              --
                                                          -------------------------------------------------------------------
Fair Value at December 31, 2004                                       11               --                 82              93
                                                          ====================================================
Unrecognized Gains on Hedges of
   Future Sale of Inventory
    at December 31, 2004                                                                                                   6
                                                                                                              ---------------
Total Outstanding at December 31, 2004                                                                                    99
                                                                                                              ===============
</TABLE>

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

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

(Cdn$ millions)                                                                                        2004            2003
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                     <C>             <C>
Current Assets                                                                                          177             102
Non-Current Assets                                                                                       91              63
                                                                                               -----------------------------
   Total Derivative Contract Assets                                                                     268             165
                                                                                               =============================

Current Liabilities                                                                                     129              34
Non-Current Liabilities                                                                                  46              25
                                                                                               -----------------------------
   Total Derivative Contract Liabilities                                                                175              59
                                                                                               =============================

Total Derivative Contract Net Assets (1)                                                                 93             106
                                                                                               =============================
</TABLE>

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

NON-TRADING ACTIVITIES

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 $22 million from our non-trading activities in 2004 (2003 - $21
million).

In 2003 and 2004, we increased our transportation capacity and were paid to
assume future obligations associated with the capacity. We included $53 million
of deferred revenue on our balance sheet to recognize the liability associated
with these obligations. This deferred revenue will be amortized to earnings as
the capacity is used.

[GRAPHIC OMITTED]
[Margin text: We enter into fee-for-service contracts related to transportation
 and storage, and increased our transportation capacity in 2003 and 2004.]

<TABLE>
<CAPTION>
CHEMICALS

(Cdn$ millions)                                                                            2004        2003        2002
------------------------------------------------------------------------------------------------------------------------
<S>                                                                                         <C>         <C>         <C>
Net Sales                                                                                   378         375         367
Sales Volumes (thousand short tons)
   Sodium chlorate                                                                          506         478         454
   Chlor-alkali                                                                             403         396         375

Operating Profit (1)                                                                        105          95         100
Operating Margin (2)                                                                         28%         25%         27%

Chemicals Contribution to Income from Continuing Operations
    Before Income Taxes                                                                      40          28          27

Capacity Utilization                                                                         95%         95%         85%
                                                                                     ------------------------------------
</TABLE>

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

(2)  Operating profit divided by net sales.

[GRAPHIC OMITTED]
[Margin text: Chemicals contribution to income before taxes 2002 - 2004]

                                       48
<PAGE>

2004 VS 2003 - HIGHER CHEMICALS OPERATING PROFIT INCREASED NET INCOME BY $10
MILLION

Our chemicals business benefited from strong demand for bleaching chemicals in
North and South America. Solid North American demand for chlor-alkali and sodium
chlorate throughout 2004 resulted in strong pricing for our products. A stronger
Canadian dollar lowered our sales by $15 million in 2004, as most of our sales
are denominated in US dollars while our costs are primarily in Canadian dollars.

[GRAPHIC OMITTED]
[Margin text: Solid demand for bleaching chemicals resulted in strong prices for
 our products in 2004.]

We successfully completed the expansion of our Brandon, Manitoba plant in
October, making it the largest sodium chlorate production facility in the world.
This expansion minimizes our exposure to the rising electricity costs faced in
other provinces, as Manitoba enjoys stable, regulated electricity markets. We
expect further margin and cash flow improvement in 2005 as we produce more of
our product from this low-cost plant.

At our Brazil plant, production improvements allowed us to take advantage of
strong market demand. We are changing our electricity source for our facilities
and expect to contract longer-term electricity supply for most of our
requirements. We expect lower annual electricity costs in 2005 when these
contracts are in place.

We are considering the sale of our chemicals business in 2005. Any such sale
would reduce contributions from this business to our 2005 net income.


2003 VS 2002 - LOWER CHEMICALS OPERATING PROFIT REDUCED NET INCOME BY $5 MILLION
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. A stronger Canadian
dollar lowered our operating profit by $13 million, as most of our sales are
denominated in US dollars.

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.


CORPORATE EXPENSES

<TABLE>
<CAPTION>
GENERAL AND ADMINISTRATIVE (G&A) (1)

(Cdn$ millions)                                                                            2004        2003           2002
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                                         <C>         <C>            <C>
General and Administrative Expense before Stock Based Compensation                          206         176            150
Stock Based Compensation (2)                                                                 93          14              2
                                                                                     -------------------------------------
    Total General and Administrative Expense                                                299         190            152
                                                                                     =====================================
</TABLE>

Notes:
(1)  Includes G&A from discontinued operations. See Note 11 to our Consolidated
     Financial Statements.

(2)  Includes tandem option plan, stock options for our US-based employees and
     stock appreciation rights.

2004 VS 2003 - HIGHER COSTS REDUCED NET INCOME BY $109 MILLION

During the second quarter, our shareholders approved modifying our stock option
plan to a tandem option plan, creating a one-time G&A expense of $82 million.
Our tandem option obligations are accrued on a graded vesting basis and
represent the difference between the market value of our common shares and the
exercise price of the options. These obligations are revalued each reporting
period based on the change in the market value of our common shares and the
number of graded vested options outstanding.

[GRAPHIC OMITTED]
[Margin text: Modifying our stock option plan to a tandem option plan added a
 one-time $82 million charge to G&A in 2004.]

Other G&A costs include increased variable incentive compensation in light of
our record results, increased headcount due to increased capital investment, and
higher regulatory compliance costs, including costs associated with our
Sarbanes-Oxley internal control documentation project.


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.

                                       49
<PAGE>

INTEREST

(Cdn$ millions)                                    2004        2003        2002
--------------------------------------------------------------------------------
Interest (1)                                        194         212         212
   Less: Capitalized                                (51)        (43)        (31)
                                                  ------------------------------
Net Interest Expense                                143         169         181
                                                  ==============================

Effective Rate                                     6.6%        7.2%        7.1%
                                                  ------------------------------

Note:
(1)  Includes dividends on preferred securities. See Note 1(r) to our
     Consolidated Financial Statements.

2004 VS 2003 - LOWER INTEREST EXPENSE INCREASED NET INCOME BY $26 MILLION

In late-2003 and early-2004, we refinanced our preferred securities with lower-
cost debt. We also repaid US$225 million of bonds in February 2004. The
refinancing of our preferred securities and the repayment of the bonds reduced
interest expense in 2004.

[GRAPHIC OMITTED]
[Margin text: Our effective rate dropped to 6.6% as we refinanced our preferred
 securities with lower-cost debt and repaid bonds. See page 53 for details on
 our capital structure.]

In December 2004, we drew US$1.5 billion on our acquisition credit facilities to
assist the financing of our North Sea acquisition in the UK. This increased our
interest expense by $5 million.

The strong Canadian dollar lowered our US-dollar denominated interest expense by
$6 million.

We capitalized interest on our Syncrude Stage 3 expansion, the Long Lake Project
in Canada, our Block 51 development in Yemen and our Buzzard development in the
North Sea.


2003 VS 2002 - LOWER INTEREST EXPENSE ADDED $4 MILLION TO NET INCOME

The full year impact of our 30-year notes issued in March 2002, together with
the refinancing of our preferred securities with lower-cost debt in November
2003 and the impact of a strong Canadian dollar on our US-dollar denominated
interest expense kept our interest costs flat.

We capitalized interest on our Syncrude Stage 3 expansion and our Gunnison
development project in the Gulf of Mexico.

INCOME TAXES

(Cdn$ millions)                                      2004       2003       2002
--------------------------------------------------------------------------------
Current                                               248        214        207
Future                                                122        (73)       (44)
                                                     ---------------------------
    Total Provision for Income Taxes                  370        141        163
                                                     ===========================

Effective Rate                                        32%        20%        31%
                                                     ---------------------------

2004 VS 2003 - EFFECTIVE TAX RATE INCREASES FROM 20% TO 32%

In 2004, a 1% reduction in Alberta's corporate income tax rate resulted in a $15
million recovery of future income taxes. The low effective tax rate for 2003
resulted from reduced federal tax rates for Canadian resource activities which
generated a recovery of future income taxes of $76 million. The effective tax
rate for 2005 is expected to be 33%.

Most of our current income taxes are cash taxes paid in Yemen. In 2004, these
totalled $227 million (2003 - $201 million; 2002 - $207 million). In 2004 and
2003, federal and provincial capital taxes were payable in Canada. In both
years, current income taxes also include alternative minimum tax in the United
States.

[GRAPHIC OMITTED]
[Margin text: See page 102 for breakdown of income taxes. We estimate our 2005
 tax rate to be consistent with 2004.]


2003 VS 2002 - EFFECTIVE TAX RATE DECLINES FROM 31% TO 20%

The low 2003 effective tax rate was due to reduced federal tax rates for
Canadian resource activities. This resulted in a recovery of future income taxes
of $76 million during the second quarter of 2003.


                                       50
<PAGE>

OTHER INCOME

(Cdn$ millions)                                         2004      2003     2002
--------------------------------------------------------------------------------
Unrealized Mark-to-Market Gains on WTI Put Options         56       --       --
Gains (Losses) on Disposition of Assets                    24       --       (8)
Foreign Exchange Gains (Losses)                           (13)       6       (3)
Business Interruption Insurance Proceeds                   10       12        -
Interest Income                                            12        9        7
Other                                                      17       15        4
                                                      --------------------------
    Total Other Income                                    106       42       --
                                                      ==========================

We purchased WTI put options in the fourth quarter of 2004 to manage the
commodity price risk exposure on part of our oil production in 2005 and 2006.
These options are carried at fair value and an unrealized gain of $56 million
was recognized in the fourth quarter as WTI forward prices declined late in the
year.

[GRAPHIC OMITTED]
[Margin text: Unrealized mark-to-market gains on our put options make up
 approximately 50% of other income. These options will be revalued quarterly.]

Gains on the disposition of assets in 2004 resulted from selling minor oil and
gas assets in Canada. There was no gain or loss on the 2003 sale of our
southeast Saskatchewan properties as described in Note 11 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. The business interruption insurance proceeds received in 2004 and 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.

Foreign exchange losses in 2004 mainly relate to the impact of a stronger
Canadian dollar on our US-dollar cash balances. Foreign exchange gains on our
US-dollar debt portfolio are not recognized in our net income as our US-dollar
debt has been designated as a hedge of our net investment in foreign operations.
These gains are recorded on our balance sheet as cumulative foreign currency
translation adjustments.


IMPACT OF FOREIGN EXCHANGE ON OPERATIONS

The strengthening Canadian dollar relative to the US dollar reduced cash flow
from operating activities by $200 million and our net income by $105 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 the Canadian dollar equivalent of this debt is
reduced with a strengthening Canadian dollar. We have designated our US-dollar
denominated debt as a hedge of our net investment in foreign operations. As a
result, unrealized foreign exchange gains on the translation of this debt are
not included in our net income. These unrealized gains are included as
cumulative foreign currency translation adjustments on our balance sheet. The
tax effect of unrealized foreign exchange gains on our US-dollar debt results in
a decrease to our future income tax assets. This decrease in our future income
tax assets is offset by a decrease to our cumulative translation adjustment
account.

[GRAPHIC OMITTED]
[Margin text: A stronger Canadian dollar negatively impacts our realized
 commodity prices, and positively impacts our US-dollar denominated fixed-rate
 debt, operating costs and capital expenditures.]


OUTLOOK FOR 2005

In 2005, we plan to invest approximately $2.6 billion in capital projects, an
increase of over $900 million compared to 2004, excluding acquisitions.
Approximately 20% of this capital will be directed toward sustaining production
and cash flow from our producing oil, gas and other assets in the short term.
The majority, however, will be invested in longer cycle-time growth
opportunities that we expect to begin contributing production and cash flow in
2006 and beyond. In 2005, our oil and gas capital program is expected to be
invested as follows:

o    65% in new growth development projects;

o    18% in core assets to maintain existing production levels; and

o    17% in new growth exploration projects.

Details of our 2005 capital investment program are included in the Capital
Investment section of the MD&A.

[GRAPHIC OMITTED]
[Margin text: See page 32 for details of our 2005 capital program.]

We plan to raise $1.5 billion in 2005 by selling assets which may include, among
other things, our chemicals business and certain conventional Canadian oil and
gas assets. The capital, cash flow and production guidance which follows does
not take into account any dispositions.


                                       51
<PAGE>

DAILY PRODUCTION

Approximately 20% of our cash flow from core assets will be reinvested in those
assets in 2005. This will deliver production before royalties of between 230,000
and 250,000 boe/d (170,000-185,000 after royalties) in 2005 before planned asset
sales.

                                                   2005 ESTIMATED PRODUCTION
                                         ---------------------------------------
(mboe/d)                                 BEFORE ROYALTIES        AFTER ROYALTIES
--------------------------------------------------------------------------------
Gulf of Mexico (1)                              50  -  60               43 -  53
UK North Sea                                    14  -  18               14 -  18
Yemen                                           90  - 100               52 -  58
Canada (2)                                      52  -  56               40 -  44
Syncrude                                        16  -  18               16 -  17
Colombia                                         4  -   6                4 -   5
                                         ---------------------------------------
Total                                          230  - 250              170 - 185
                                         =======================================

Notes:
(1)  US natural gas production is estimated to comprise 46% of total US
     equivalent production in 2005.

(2)  Canadian natural gas production is estimated to comprise 44% of total
     Canadian equivalent production in 2005.

[GRAPHIC OMITTED]
[Margin text: In 2005, we expect to modestly grow production after royalties and
 generate over $2 billion in cash flow from operating activities.]

We expect our production after royalties to grow modestly in 2005, while we
continue to invest in major development projects which are expected to come on
stream in 2006 and beyond. Many of these have low or no royalties, lower costs
and ultimately higher margins and returns than our current producing assets.
This changing production mix is expected to improve profitability, even if oil
prices trend somewhat lower.

CASH FLOW AND SENSITIVITIES

We expect to generate over $2 billion in cash flow from operating activities in
2005 (before asset sales, site restoration and geological and geophysical
expenditures), assuming the following:


---------------------------------------------------------------------------
WTI (US$/bbl)                                                        40.00
NYMEX natural gas (US$/mmbtu)                                         6.50
US to Canadian dollar exchange rate                                   0.80

We have purchased put options on 60,000 bbls/d of our oil production in both
2005 and 2006. These options establish an average WTI floor price for this
production of US$43.17/bbl in 2005 and US$38.17 in 2006. Changes in actual
commodity prices and exchange rates impact our annual cash flow from operating
activities as follows:

(Cdn$ millions)
--------------------------------------------------------------------------
WTI - US$1 change above US$43.17                                       50
WTI - US$1 change below US$43.17                                       25
NYMEX natural gas - US$0.10 change                                     10
Exchange rate - $0.01 change                                           25

In addition to strong cash flow from our oil and gas operations, we expect
continued strong performance from our chemicals and marketing businesses in
2005. Our chemicals operations expect another year of solid stable cash flow and
net income as we continue to see strong demand and pricing for our products. Our
Brandon plant will provide lower cost operations. Our marketing group also
anticipates another profitable year as they continue to maximize the value of
their asset base.


[GRAPHIC OMITTED]
[Margin text: A US$1 change in WTI above $43/bbl will change cash flow from
 operating activities by $50 million.]


                                       52
<PAGE>

LIQUIDITY AND CAPITAL RESOURCES

CAPITAL STRUCTURE

(Cdn$ millions)                                                2004        2003
--------------------------------------------------------------------------------
NET DEBT (1)
   Bank Debt                                                  1,993          --
   Public Senior Notes                                        1,813       2,214
                                                              ------------------
     Senior Debt                                              3,806       2,214
   Subordinated Debt                                            553         594
   Preferred Securities                                          --         281
                                                              ------------------
     Total Debt                                               4,359       3,089
   Less: Cash and Cash Equivalents                              (74)     (1,087)
   Less: Non-Cash Working Capital (2)                           (66)       (312)
                                                              ------------------
TOTAL NET DEBT                                                4,219       1,690
                                                              ==================

SHAREHOLDERS' EQUITY (3)                                      2,867       2,075
                                                              ==================

Notes:
(1)  Includes all of our debt and is calculated as long-term debt less net
     working capital.

(2)  Excludes current portion of long-term debt and short-term borrowings.

(3)  At January 31, 2005, there were 129,415,565 common shares and US$460
     million of unsecured subordinated securities outstanding. These
     subordinated securities may be redeemed by issuing common shares at our
     option after November 8, 2008. The number of shares issuable depends on the
     common share price on the redemption date.

[GRAPHIC OMITTED]
[Margin text: Net debt is long-term debt less working capital. We use it to
 monitor the strength of our balance sheet]

NET DEBT

We use net debt as a key indicator of our leverage levels and to monitor the
strength of our balance sheet. Our net debt levels are directly related to our
operating cash flows, our capital investment activities and disposition
programs. We ended the year with net debt at $4.2 billion, an increase of $2.5
billion over 2003 year-end levels. This reflects our North Sea acquisition on
December 1, 2004, which was financed with US$1.5 billion of debt and US$600
million of cash on hand. Changes in net debt related to:

<TABLE>
<CAPTION>
(Cdn$ millions)                                                          2004      2003
----------------------------------------------------------------------------------------
<S>                                                                     <C>       <C>
Capital Investment (including North Sea acquisition)                    4,264     1,494
Cash Flow from Operating Activities                                    (1,607)   (1,405)
                                                                       -----------------
Excess of Capital Investment over Cash Flow                             2,657        89

Dividends on Common Shares                                                 52        40
Proceeds on Disposition of Assets                                         (34)     (293)
Issue of Common Shares (primarily exercise of employee stock options)    (124)      (73)
Foreign Exchange Translation of US-Dollar Debt and Cash                   (78)     (281)
Other                                                                      56      (240)
                                                                       -----------------
Increase (Decrease) in Net Debt                                         2,529      (758)
                                                                       =================
</TABLE>

[GRAPHIC OMITTED]
[Margin text: We financed the North Sea acquisition with US$600 million in cash
 and US$1.5 billion of debt.]

The increase in net debt has impacted our leverage metrics:

<TABLE>
<CAPTION>
(times)                                                       2004      2003       2002
----------------------------------------------------------------------------------------
<S>                                                            <C>       <C>        <C>
Net Debt to Cash Flow from Operating Activities                2.6       1.2        2.0
Interest Coverage (1)                                         11.9      10.1        7.9
                                                              --------------------------
</TABLE>

Note:
(1)  Earnings before interest, taxes, DD&A and exploration expense divided by
     interest expense (before capitalized interest).

Our business strategy is focused on value-based growth through full-cycle
exploration and development, supplemented by strategic acquisitions when
appropriate. To grow our company, we used leverage to develop the Masila project
in Yemen in 1993, acquire Wascana in 1997 and acquire the remaining interest in
Aspen in 2002. Each time, we exceeded our internal net debt to cash flow target
band, however, we successfully brought our leverage back down once these
projects began generating cash flow. In 2004, we again elevated our leverage
levels as a result of our North Sea acquisition. We plan to sell $1.5 billion of
assets in 2005 to reduce our leverage. Leverage is expected to be reduced
further when our Buzzard and Long Lake projects come on stream and contribute
cash flow in 2006 and 2007.


                                       53
<PAGE>

<TABLE>
<CAPTION>
CHANGE IN WORKING CAPITAL

                                                                                      INCREASE/
(Cdn$ millions)                                               2004          2003     (DECREASE)
-----------------------------------------------------------------------------------------------
<S>                                                           <C>          <C>       <C>
Cash and Cash Equivalents                                        74        1,087        (1,013)
Accounts Receivable                                           2,136        1,423           713
Inventories and Supplies                                        351          270            81
Accounts Payable and Accrued Liabilities                     (2,416)      (1,404)       (1,012)
Other                                                            (5)          23           (28)
                                                             -----------------------------------
                                                                140        1,399        (1,259)
                                                             ===================================
</TABLE>

Cash and cash equivalents decreased by over $1 billion during the year as we:

o    repaid US$225 million of senior debt in February;

o    redeemed US$217 million of preferred securities in February; and

o    paid US$600 million relating to our North Sea acquisition.

Accounts receivable and accounts payable increased, reflecting higher commodity
prices and increased activity for our gas marketing business. We also acquired
accounts receivable and accounts payable as part of our North Sea acquisition.
Capital accruals were higher at year-end from our Buzzard and Long Lake
development projects, and as a result of increased exploration activity in the
Gulf of Mexico. Inventory levels in the marketing group were up at year-end
given higher activity during the last part of 2004.

[GRAPHIC OMITTED]
[Margin text: Increased payables and receivables reflect higher commodity prices
 and increased activity for our gas marketing business.]


LIQUIDITY

We generally 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. Given the long cycle-time of some
of our development projects and the volatility of commodity prices, it is not
unusual, in any given year, for capital expenditures to exceed our cash flow.
When this happens, we draw on available credit facilities, as we maintain
significant undrawn committed credit facilities. From time to time, we access
the capital markets to meet our financing needs. We also use various financial
instruments to minimize our exposure to fluctuations in foreign exchange and
commodity prices. For example, we purchased WTI put options for 2005 and 2006 to
mitigate liquidity risk and reduce cash flow volatility. Overall, we manage our
capital structure to maintain flexibility so we can fund our capital programs
throughout the highs and lows of the price cycles inherent in the oil and gas
business.

[GRAPHIC OMITTED]
[Margin text: We manage our capital structure to maintain flexibility so we can
 fund our capital program through the commodity price cycles.]

The following table shows how we use our cash flow from operating activities to
fund our investing activities. When our operating cash flows exceed our
investment requirements, we generally pay down debt. We generally borrow to fund
investment requirements in excess of our operating cash flows.

<TABLE>
<CAPTION>
(Cdn$ millions)                                       2004         2003         2002      2001      2000
---------------------------------------------------------------------------------------------------------
<S>                                                  <C>          <C>         <C>        <C>       <C>
Cash Flow from Operating Activities                  1,607        1,405       1,250      1,496     1,261
Cash Flow from Investing Activities                 (4,013)      (1,219)     (1,569)    (1,469)     (897)
                                                    -----------------------------------------------------
                                                    (2,406)         186        (319)        27       364

Cash Flow from Financing Activities                  1,426        1,006         329       (100)     (359)
                                                    -----------------------------------------------------
                                                    -----------------------------------------------------
                                                      (980)       1,192          10        (73)        5
                                                    =====================================================
</TABLE>

In 2000, strong commodity prices allowed us to generate sufficient cash flow to
buy back 20 million common shares. In 2001 and 2002, we began to invest
significantly in two deep-water Gulf of Mexico projects (Aspen and Gunnison),
our Syncrude expansion and our Long Lake project. In 2001, we used our cash flow
and in 2002, we accessed the public debt markets to fund this investment
activity. In 2003, Aspen contributed significantly to our cash flow and in
late-2003, we pre-funded debt repayments by raising over $1 billion in senior
and subordinated debt. We used these funds in 2004 to repay higher cost debt,
and coupled with our acquisition credit facilities, acquired the North Sea
assets.


                                       54
<PAGE>

FUTURE LIQUIDITY

Our future liquidity is primarily dependent on cash flows generated from our
operations, our capital programs and the flexibility of our capital structure.
Assuming WTI of US$40/bbl in 2005, we expect our 2005 capital investment program
and dividend requirements to exceed our cash flow by almost $600 million. We are
planning to raise $1.5 billion from asset dispositions in 2005 and we expect to
use the proceeds to fund the shortfall and to retire debt.

Our cash flow is sensitive to changes in commodity prices and exchange rates.
For 2005, we expect to generate cash flow of over $2.0 billion (before asset
sales, remediation and geological and geophysical expenditures) assuming the
following:


--------------------------------------------------------------------------
WTI (US$/bbl)                                                       40.00
NYMEX natural gas (US$/mmbtu)                                        6.50
US to Canadian dollar exchange rate                                  0.80

Changes in commodity prices and exchange rates will impact our cash flow and our
borrowing requirements. The impact of a variance in any one of the above
assumptions on our cash flow is described in the Outlook for 2005 section of the
MD&A.

[GRAPHIC OMITTED]
[Margin text: See page 52 for our commodity price and foreign exchange
 sensitivities.]

We are in the midst of developing a number of major projects. Much of our
planned capital spending over the next three years will be allocated to Long
Lake, the Buzzard project in the North Sea and Syncrude Stage 3.

Our anticipated spending on these projects in 2005, 2006 and 2007 is as follows:

(Cdn$ millions)
---------------------------------------------------------------------------
2005                                                                 1,388
2006                                                                 1,125
2007                                                                   415
                                                                    -------
Total Capital Investment                                             2,928
                                                                    =======

Given our reliance on cash flows to fund these projects, we executed a cash flow
protection strategy using WTI crude oil put options in late-2004. These put
options provide us with an annual average WTI floor price of US$43.17/bbl in
2005 and US$38.17 in 2006 on 60,000 bbls of oil per day each year. This strategy
reduces the downside risk to our future cash flows in 2005 and 2006 when our
capital requirements are high, yet still allows us to realize price upside.

[GRAPHIC OMITTED]
[Margin text: Our put options reduce downside price risk in 2005 and 2006 yet
 enable us to realize price upside.]

Our Buzzard project creates foreign currency exposure as a portion of the
capital costs are denominated in British pounds and Euros. In order to reduce
our exposure to fluctuations in these currencies, we purchased foreign currency
call options in early 2005 which effectively set a ceiling on most of our
British pound and Euro spending exposure from March 2005 through to the end of
2006.

While these development projects lack exploration risk, they are subject to
execution risk, the risk of higher than anticipated spending or delayed
start-up. We minimize the financial impact of these risks by maintaining undrawn
committed credit facilities. These facilities extend beyond the expected
start-up dates of our Syncrude expansion, our Long Lake project and the Buzzard
development. Undrawn amounts on these facilities at December 31, 2004 were
almost $1.6 billion. We also have a committed credit facility available until
late-2007 which may be used to finance the development and operation of our
North Sea assets including Buzzard. At December 31, 2004, US$500 million was
available on this facility.

In addition to our operating cash flows and our sizeable undrawn committed
credit facilities, we have a US$1 billion shelf registration available in the US
and Canada to allow us to access the debt capital markets.

[GRAPHIC OMITTED]
[Margin text: If required, we have more than $2 billion in undrawn credit
 facilities and a US$1 billion shelf registration in the US and Canada to access
 debt markets.]


                                       55
<PAGE>

At December 31, 2004, the average term to maturity of our long-term debt was
11.9 years. We have the following debt maturities in the next five years:

(Cdn$ millions)                           2005     2006    2007     2008    2009
--------------------------------------------------------------------------------
Acquisition Credit Facilities              903       --     903       --      --
Term Credit Facilities (1)                  --       --      22       65      --
Debentures                                  --       93      --       --      --
Medium Term Notes                           --       --     150      125      --
                                          --------------------------------------
Total                                      903       93   1,075      190      --
                                          ======================================

Note:
(1)  Undrawn amounts of $0.4 billion available until 2008 and $1.2 billion
     available until 2009.

We may retire our debt maturities with a portion of the proceeds from planned
asset sales or we may refinance the maturities with longer term debt. In
addition, we have sufficient capacity on our term credit facilities to refinance
a portion of these maturities, if need be.

In light of our cash flow streams, our commodity price and foreign exchange
hedging strategies and our current levels of liquidity, we expect to have no
difficulties funding our planned capital programs, dividend requirements and
debt repayments or in meeting the obligations that arise from our day-to-day
operations.

In 2004, we declared common share dividends of $0.40 per common share (2003 -
$0.325, 2002 - $0.30). We expect to declare common share dividends of $0.40 per
common share in 2005.

[GRAPHIC OMITTED]
[We expect to declare common share dividends of $0.40 per common share in 2005.]

CONTRACTUAL OBLIGATIONS, COMMITMENTS AND GUARANTEES

We assume various contractual obligations and commitments in the normal course
of our operations and financing activities. These obligations and commitments
are considered in assessing our cash requirements, as noted in the above
discussion of future liquidity. They include:

<TABLE>
<CAPTION>
(Cdn$ millions)                                                              PAYMENTS
-----------------------------------------------------------------------------------------------------------------
                                                              (less than)                             (more than)
                                                   Total          1 year   1-3 years     4-5 years       5 years
                                                   --------------------------------------------------------------
<S>                                                <C>         <C>         <C>           <C>          <C>
Short and Long-Term Debt                              4,359        1,003       1,168           190         1,998
Interest on Short and Long-Term Debt                  3,789          221         401           278         2,889
Operating Leases (1)                                    248           31          53            45           119
Energy Commodity Contracts                              175          129          42             4            --
Transportation and Storage Commitments (1)              780          366         200            84           130
Work Commitments and Purchase Obligations (2)         1,794          958         832             4            --
Asset Retirement Obligations                            770           47          32            42           649
Other                                                     5            1           1             1             2
                                                   --------------------------------------------------------------
Total                                                11,920        2,756       2,729           648         5,787
                                                   ==============================================================
</TABLE>

Notes:
(1)  Payments for operating leases and transportation commitments are deducted
     from our cash flow from operating activities.

(2)  The vast majority of these payments relate to work commitments cancellable
     at our option without penalties or additional fees.

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

o    Short and long-term debt amounts are included on our December 31, 2004
     Consolidated Balance Sheet.

o    Operating leases include the minimum lease payment obligations associated
     with leases for office space, rail cars, vehicles 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 2005, Shell has elected to take payment in kind so the 2005
     obligation has been excluded from this table. Instead, it is shown as a
     royalty and excluded from reserves and production.

o    Energy commodity contracts include the purchase and sale of physical
     quantities of oil and natural gas, and financial derivatives used to manage
     our exposure to commodity prices. For contracts where the price is based on
     an index, the amount is based on forward market prices at December 31,
     2004. For certain contracts, we may net settle rather than pay cash.

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.

[GRAPHIC OMITTED]
[Margin text: Our long-term debt accounts for almost 70% of our contractual
 obligations and commitments.]


                                       56
<PAGE>

o    Work commitments include non-discretionary capital spending related to
     drilling, seismic, construction of facilities and other development
     commitments in our international operations, at Long Lake ($274 million),
     the Buzzard project in the North Sea ($1 billion) and at Block 51 ($189
     million). The timing of certain payments is difficult to determine with
     certainty. The table has been prepared using our best estimates; the
     remainder of our 2005 capital investment is discretionary.

o    We have $770 million of undiscounted asset retirement obligations. As of
     December 31, 2004, the estimated fair value ($468 million) of these
     obligations has been provided for in our consolidated financial statements
     (including $47 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 $46 million and our share of Syncrude's
     unfunded obligation is $41 million. Our $46 million obligation includes $34
     million that is unfunded as a result of statutory limitations. These
     obligations are backed by irrevocable letters of credit. During 2004, we
     contributed $6 million to our defined benefit pension plan. We currently
     are not anticipating any funding requirements in 2005 for our defined
     benefit pension plan.

o    We have excluded our unvested obligations on our stock option and stock
     appreciation rights programs as the amount and timing of the cash payments
     are indeterminable.

o    We have excluded our normal purchase arrangements as they are discretionary
     and are reflected in our expected cash flow from operating activities and
     our capital expenditures for 2005.

o    We have excluded our future income tax liabilities as the amount and timing
     of any cash payments for income taxes are based primarily on taxable income
     for each discrete fiscal year in the various jurisdictions in which we
     operate.

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, therefore, 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 (S&P), Baa2 by
Moody's Investor Service, Inc. and BBB by Dominion Bond Rating Service (DBRS).
In addition, S&P currently rates our outlook as stable while Moody's and DBRS
have a negative outlook. Our strong financial results, ample liquidity and
financial flexibility continue to support our credit rating.

[GRAPHIC OMITTED]
[Margin text: Credit Rating: S&P: BBB-, Moody's: Baa2, DBRS: BBB]

FINANCIAL ASSURANCE PROVISIONS IN COMMERCIAL CONTRACTS

The commercial agreements our marketing group enters into often include
financial assurance provisions that allow Nexen and our counterparties to
effectively manage credit risk. The agreements normally require posting
collateral 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, 2004, we would be required to post collateral
of approximately $780 million if we were downgraded to non-investment grade.
These obligations are reflected on our balance sheet. The posting of collateral
merely accelerates the payment of such amounts. Our committed undrawn credit
facilities available for general corporate purposes of $1.6 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 contracts that allow us to demand certain
counterparties post collateral with us if they are downgraded to non-investment
grade.


OFF-BALANCE SHEET ARRANGEMENTS

None.


CONTINGENCIES

We have no contingencies that would have a material adverse effect on our
liquidity, consolidated financial position or results of operations. See Note 12
to the Consolidated Financial Statements in Item 8, which is incorporated herein
by reference for a discussion of our contingencies.


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BUSINESS RISK MANAGEMENT

Our operations are exposed to various risks, some of which are common to others
in our industry and some of which are unique to our operations. We attempt to
mitigate the risks to an acceptable level but many of these risks are beyond our
control so we cannot provide any assurances that they will not result in
negative financial consequences.

COMPETITION

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 petroleum industry also competes
with other industries in supplying energy, fuel and related products to
customers.

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

o    price;

o    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.

Competitive forces may result in shortages of prospects to drill, services to
carry out exploration, development or operating activities, and infrastructure
to produce and transport production. It may also result in an oversupply of
crude oil and natural gas. Each of these factors could have a negative impact on
costs and prices and, therefore, our financial results.

OPERATIONAL RISKS

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; and

o    environmental risks.

We operate two facilities that are located in close proximity to populated
areas, and each processes materials of potential harm to the local populations.
At Balzac, just north of Calgary, we operate a gas plant that processes sour
gas. In North Vancouver, we operate a chlor-alkali plant that produces chlorine.
We have undertaken several initiatives to mitigate the potential risks
associated with these operations. First, we have instituted operating procedures
that have allowed each to be verified as Responsible Care(R) facilities by the
Canadian Chemical Producers Association, with our Balzac plant being the first
oil and gas facility in the world to be so certified. Also, at North Vancouver,
we conducted extensive quantified risk analysis complying with guidelines of the
Major Industrial Accidents Council of Canada (MIACC). As a result, substantial
changes to operating and inventory practices were implemented. The risk is now
consistent with Responsible Care(R) and MIACC guidelines. Also, at both
facilities, we work with surrounding communities to keep them informed of our
operations and have invited them to tour our facilities. Finally, we continually
work with local municipalities to maintain appropriate emergency response and
evacuation plans in the event of an accidental release of chemicals from the
facilities.

Although we maintain insurance according to customary industry practice, we may
not be fully insured against all of these risks. Losses resulting from the
occurrence of these risks may have a material adverse impact on our financial
results.

OFFSHORE OPERATIONS

Offshore operations are subject to a variety of operating risks peculiar to the
marine environment, such as damage or loss from hurricanes or other adverse
weather conditions. These conditions can cause substantial damage to facilities
and interrupt production. When possible, we take precautionary measures of
temporarily shutting-in production, de-manning facilities and ceasing drilling
operations. We carry insurance to compensate us for physical damage and business
interruption, subject to normal deductions, resulting from such weather
conditions.

Our operations in the Gulf of Mexico have been suspended, from time to time, due
to hurricanes or tropical storms. While operations are generally restored
quickly and production losses are not material, we have had one instance in the
last five years where production was suspended for an extended period of time
and substantial damage to facilities was incurred. In 2002, our facilities at
Eugene Island 295 were damaged during Hurricane Lili. Production from this field
was suspended for about four months while temporary production facilities were
put in place. During this period, production volumes were reduced by
approximately 2,500 boe/d. Production was restored at a reduced rate through
temporary facilities for approximately six months while installation of new
permanent facilities was completed. It is estimated that volumes were reduced by
approximately 1,800 boe/d during this period. There was no significant financial
impact after business interruption and property insurance claims.


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UNCERTAINTY OF RESERVES ESTIMATES

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 through exploration, acquisition
or development activities, our reserves and production will decline over time as
reserves are produced. The business of exploring for, developing or acquiring
reserves is capital intensive. To the extent cash flows from operations are
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 will be impaired.

Over the past three years, we experienced net negative revisions of 337 million
boe to our proved reserves (including Syncrude and before royalties). This
includes 239 million boe related to changes in year-end prices, of which 246
million boe relates to the write-off of the reserves at our Long Lake oil sands
project as a result of low bitumen prices at the end of 2004. Positive price
revisions of 7 million boe related primarily to our Canadian heavy oil
properties. The remaining negative revisions of 98 million boe, representing
about 12% of worldwide proved reserves, occurred primarily on our producing
properties in Canada and Yemen. In Canada, the majority of the negative
revisions of 64 million boe occurred in 2003 as result of an ongoing assessment
of the future production profiles of our properties and a reduction of proved
undeveloped reserves based on drilling results and updated geological mapping.
In Yemen, the negative revisions of 37 million boe occurred largely in 2003 and
2004 and resulted primarily from lower-than-expected production performance,
drilling results and updated geological mapping.

About two-thirds of the 98 million boe of net negative revisions were recognized
as proved reserves based on projected future production performance of producing
properties. These projections considered historical performance and expected
future changes in production using all available engineering and geological
data. However, subsequent production performance did not meet our projections
due to such factors as sand production, steeper than expected declines due to
higher water cuts and the drilling of some infill locations which proved to have
already been swept. The remainder of the reserves were recognized as proved
undeveloped reserves based on production performance, well control and geologic
mapping using seismic and other data. Lower than expected production, greater
sweep efficiencies, and unsuccessful drilling caused us to revise our proved
reserves estimates downward.

Under SEC rules, we recognize our oil sands as bituman reserves. As a result, we
expect price-related revisions, both positive and negative, to occur in the
future as the economic producibility of our bitumen and heavy oil reserves are
sensitive to year-end prices. In particular, since we recognize our oil sands as
bitumen reserves and they are related to one project, all or none of the
reserves will likely be considered economic depending on the year-end prices of
bitumen, diluent and natural gas. The impact of year-end prices on our heavy oil
reserves is expected to be immaterial.

INCREASED LEVERAGE

Our overall indebtedness has increased as a result of acquiring the North Sea
assets. Additional borrowings may be necessary to fund the field development
plan for the Buzzard field as well as for the development of the Long Lake
project. While we believe that our overall indebtedness can be reduced through
proceeds from the disposition of non-core assets, no assurance can be given that
we will be able to implement such transactions.

HEAVY OIL OPERATIONS

Heavy oil is characterized by high specific gravity or weight and high viscosity
or resistance to flow. Because of these features, heavy oil is more difficult
and expensive to extract, transport and refine than other types of oil. Heavy
oil also yields a lower price relative to light oil and gas, as a smaller
percentage of high-value petroleum products can be refined from heavy oil. As a
result, our heavy oil operations are exposed to the following risks:

o    additional costs may be incurred to purchase diluent to transport heavy
     oil;

o    there could be a shortfall in the supply of diluent which may cause its
     price to increase; and

o    the market for heavy oil is more limited than for light oil making it more
     susceptible to supply and demand fundamentals which may cause the price to
     decline.

Any one or combination of these factors could cause some of our heavy oil
properties to become uneconomic to produce and/or result in negative reserve
revisions.

Additional risk factors relating to our Long Lake oil sands project are provided
under "Risk Factors Relating to Long Lake".

RISK FACTORS RELATING TO LONG LAKE

Our Long Lake Project is planned as a fully integrated production, upgrading and
co-generation facility. We intend to use Steam Assisted Gravity Drainage (SAGD)
technology to recover bitumen from oil sands. As designed, the bitumen will be
partially upgraded using the proprietary OrCrude(TM) process, followed by
conventional hydrocracking to produce a sweet, premium synthetic crude oil. The
OrCrude(TM) process also yields liquid asphaltines that will be gasified into a
syngas. This syngas will be used as a fuel source for the SAGD process, a source
of hydrogen for use in the upgrading process, and to generate electricity
through a co-generation facility.

We have a 50% working interest in this project, and our share of the
construction cost is estimated to be $1.75 billion ($3.5 billion gross). Given
the higher initial investment and operating costs to produce and upgrade
bitumen, the payout period for the project is longer and the economic return is
lower than a conventional light oil project with an equal volume of reserves.


                                       59
<PAGE>

Risks associated with our Long Lake oil sands project include the following:

STATUS OF THE LONG LAKE PROJECT

The Long Lake Project is currently in the construction stage. There is a risk
that actual costs may be higher than expected or that the project may not be
completed on time or at all due to many factors, including:

o    construction performance falling below expected levels of output or
     efficiency;

o    labour disputes, disruptions or declines in productivity;

o    increases in materials or labour costs;

o    inability to attract sufficient numbers of qualified workers;

o    design errors;

o    contractor or operator errors;

o    non-performance by third-party contractors;

o    changes in project scope;

o    delays in obtaining, or conditions imposed by, regulatory approvals;

o    breakdown or failure of equipment or processes;

o    violation of permit requirements;

o    catastrophic events such as fires, earthquakes, storms or explosions; and

o    disruption in the supply of energy.

Actual costs to construct and develop the project will vary from our estimates,
and such variances may be significant. Our estimate of the cost associated with
developing the Long Lake Project has been developed with an expected range of
accuracy of approximately +/- 15%. In the formative stage of the project, our
capital cost estimate was approximately $2.3 billion (gross). After completing
further project definition, engineering and reviewing pilot results, we changed
the scope of the project to include co-generation facilities, planned for
certain redundancies within the upgrader, and applied more conservative
estimates to labour productivity. As a result, the capital cost estimate at the
time of our Board's sanctioning the project in February 2004 was $3.4 billion
(gross). Our current capital cost estimate for completing the project is $3.5
billion (gross) reflecting the acceleration of drilling of an additional well
pad consisting of 13 well pairs to ensure certainty and reliability of bitumen
production at the commencement of upgrader operations.

SAGD BITUMEN RECOVERY PROCESS

SAGD has been used in Western Canada to increase recoveries from conventional
heavy oil reservoirs for over a decade. However, application of SAGD to the
in-situ recovery of bitumen from oil sands is relatively new. Most of the SAGD
oil sands applications to date have been pilot projects and the process is in
the early stages of application in commercial oil sands projects.

Our estimates for performance and recoverable volumes for the Long Lake Project
are based primarily on our three well-pair SAGD pilot and industry performance
from SAGD operations in the McMurray formation in the Athabasca oilsands. Using
this data, our assumptions included average well-pair productivity of 900 bbls/d
of bitumen and a steam-to-oil ratio of 2.5. We commenced steaming the reservoir
for our SAGD pilot in May 2003 and commenced production in September 2003. The
pilot is currently producing at a rate of about 600 barrels of bitumen per day
per well-pair and a steam-to-oil ratio of about 3.5. Since September 2003, the
pilot has recovered less than 2% of the original bitumen in place. While we
expect actual performance to improve as the steam chamber grows in the
reservoir, there can be no assurance that our SAGD operation will produce
bitumen at the expected levels or steam-to-oil ratio. If the assumed production
rates or steam-to-oil ratio are not achieved, we might have to drill additional
wells to maintain optimal production levels, construct additional steam
generating capacity and/or purchase natural gas for additional steam generation.
These could have a significant adverse impact on the future activities and
economic return of the Long Lake Project.

BITUMEN UPGRADING PROCESS

The proprietary OrCrude(TM) process we are using to upgrade raw bitumen to
synthetic crude will be the first commercial application of the process although
we have operated it in a 500 bbls/d demonstration plant. All the individual
components of the technology used in this process, are currently used in
commercial applications around the world, however, there can be no assurance
that the commercial upgrader being constructed at Long Lake will achieve the
same or similar results as the demonstration plant or the results which are
forecast. If we are unable to upgrade the bitumen for any reason we may decide
to sell it as bitumen without upgrading it, which would expose us to the
following risks:

o    the market for bitumen is limited;

o    additional costs would be incurred to purchase diluent for blending and
     transporting bitumen;

o    there could be a shortfall in the supply of diluent which may cause its
     price to increase;

o    the market price for bitumen is relatively low reflecting its quality
     differential; and

o    additional costs would be incurred to purchase natural gas for use in
     generating steam for the SAGD process since we would not be producing
     syngas from the upgrading process.

These factors could have a significant adverse impact on the future activities
and returns of the Long Lake Project.

If any of these factors arise, our operating costs would increase and our
revenues would decrease from those we have assumed. This would cause a material
decrease in expected earnings from the project and the project may not be
profitable under these conditions.


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At December 31, 2004, a shortage of diluent caused the price of diluent products
to rise substantially above prices seen in the past. These conditions could be
repeated in the future as the demand for diluents increases with the expected
increase in production of bitumen from the Canadian oil sands.

DEPENDENCE ON OPTI CANADA

We are undertaking the Long Lake Project jointly with OPTI Canada (OPTI)
pursuant to a joint venture agreement governing the construction, ownership and
joint operation of the project. The agreement provides for the creation of a
management committee that is responsible for the supervision and direction of
the management and operation of the project, the supervision and control of the
operators and all other matters relating to the development of the project. If
our interest in any element of the project falls below 25%, OPTI may be able to
make decisions respecting that element without our input, which may adversely
affect our operations.

DEPENDENCE UPON PROPRIETARY TECHNOLOGY

The success of the project and our investment in the project depends to a
significant extent on the proprietary technology of OPTI and proprietary
technology of third parties that has been, or is required to be, licensed by
OPTI. OPTI currently relies on intellectual property rights and other
contractual or proprietary rights, including (without limitation) copyright,
trademark laws, trade secrets, confidentiality procedures, contractual
provisions, licenses and patents, to secure the rights to utilize its
proprietary technology and the proprietary technology of third parties. OPTI may
have to engage in litigation in order to protect the validity of its patents or
other intellectual property rights, or to determine the validity or scope of the
patents or proprietary rights of third parties. This kind of litigation can be
time-consuming and expensive, regardless of whether or not OPTI is successful.
The process of seeking patent protection can itself be long and expensive, and
there can be no assurance that any currently pending or future patent
applications of OPTI or such third parties will actually result in issued
patents, or that, even if patents are issued, they will be of sufficient scope
or strength to provide meaningful protection or any commercial advantage to
OPTI. Furthermore, others may develop technologies that are similar or superior
to the technology of OPTI or such third parties or design around the patents
owned by OPTI and/or such third parties. There is also a risk that OPTI may not
be able to enter into licensing arrangements with third parties for the
additional technologies required for the possible further expansion of the Long
Lake upgrader.

OPERATIONAL HAZARDS

The operation of the project will be subject to the customary hazards of
recovering, transporting and processing hydrocarbons, such as fires, explosions,
gaseous leaks, migration of harmful substances, blowouts and oil spills. A
casualty occurrence might result in the loss of equipment or life, as well as
injury or property damage. We may not carry insurance with respect to all
potential casualty occurrences and disruptions. It cannot be assured that our
insurance will be sufficient to cover any such casualty occurrences or
disruptions. The project could be interrupted by natural disasters or other
events beyond our control. Losses and liabilities arising from uninsured or
under-insured events could have a material adverse effect on the project and on
our business, financial condition and results of operations.

Recovering bitumen from oil sands and upgrading the recovered bitumen into
synthetic crude oil and other products involve particular risks and
uncertainties. The project is susceptible to loss of production, slowdowns, or
restrictions on its ability to produce higher value products due to the
interdependence of its component systems. Severe climatic conditions can cause
reduced production and in some situations result in higher costs. SAGD bitumen
recovery facilities and development and expansion of production can entail
significant capital outlays. The costs associated with synthetic crude oil
production are largely fixed and, as a result, operating costs per unit are
largely dependent on levels of production.

The Long Lake SAGD operation and upgrader will process large volumes of
hydrocarbons at high-pressure and at high temperatures and will handle large
volumes of high pressure steam. Equipment failures could result in damage to the
project's facilities and liability to third parties against which we may not be
able to fully insure or may elect not to insure because of high premium costs or
for other reasons.

Certain components of the Long Lake Project will produce sour gas, which is gas
containing hydrogen sulphide (H2S). Sour gas is a colourless, corrosive gas that
is toxic at relatively low levels to plants and animals, including humans. The
project will include integrated facilities for handling and treating the sour
gas, including the use of gas sweetening units, sulphur recovery systems and
emergency flaring systems. Failures or leaks from these systems or other
exposure to sour gas produced as part of the project could result in damage to
other equipment, liability to third parties, adverse effect to humans, animals
and the environment, or the shut down of operations.

The Long Lake Project will produce carbon dioxide emissions. Carbon dioxide is a
greenhouse gas that will be regulated by the Kyoto Protocol, which is expected
to come into effect in Canada in 2008. We will be required to purchase carbon
dioxide credits in connection with these emissions, which we have budgeted at
approximately $0.20/bbl of oil produced. If the cost of carbon dioxide credits
reaches the Canadian cap, our actual cost would increase to approximately
$0.40/bbl of oil produced.

ABORIGINAL CLAIMS

Aboriginal peoples have claimed aboriginal title and rights to a substantial
portion of Western Canada. Certain aboriginal peoples have filed a claim against
the Government of Canada, the Province of Alberta, certain governmental entities
and the regional municipality of Wood Buffalo (which includes the city of Fort
McMurray, Alberta) claiming, among other things, aboriginal title to large areas
of lands surrounding Fort McMurray, including the lands on which the project and
most of the other oil sands operations in Alberta are located. Such claims, if
successful, could have a significant adverse effect on the project and on us.


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COMPETITION

The Canadian and international petroleum industry is highly competitive in all
aspects, including the exploration for, and the development of, new sources of
supply, the acquisition of oil interests and the distribution and marketing of
petroleum products. The Long Lake Project competes with other producers of
synthetic crude oil blends and other producers of conventional crude oil. Some
of the conventional producers have lower operating costs than the project is
anticipated to have. The petroleum industry also competes with other industries
in supplying energy, fuel and related products to consumers.

A number of companies other than OPTI and us have announced plans to enter the
oil sands business and begin production of synthetic crude oil, or expand
existing operations. Expansion of existing operations and development of new
projects could materially increase the supply of synthetic crude oil and other
competing crude oil products in the marketplace. Depending on the levels of
future demand, increased supplies could have a negative impact on prices.

CONCENTRATION OF PRODUCING ASSETS

A portion of our production is generated from highly productive individual wells
or central production facilities. Examples include:

o    central processing facility, oil pipeline, and export terminal at our Yemen
     operations;

o    Gunnison SPAR production platform in the Gulf of Mexico;

o    highly productive Aspen wells tied-in to a third-party processing facility
     in the Gulf of Mexico; and

o    Scott production platform in the North Sea.

As significant production is generated from each of these assets, any single
event causing an interruption to these operations could result in the loss of
production. We carry insurance to compensate us for physical damage and business
interruption arising from most circumstances but it does not provide for losses
arising from equipment failures.

COAL BED METHANE

Coal bed methane (CBM) is commonly referred to as an unconventional form of
natural gas because it is primarily stored through adsorption by the coal itself
rather than in the pore space of the rock like most conventional gas. The gas is
released in response to a drop in pressure in the coal. If the coal is water
saturated, water generally needs to be extracted to reduce the pressure and
allow gas production to occur. CBM wells typically have lower producing rates
and reserves per well than conventional gas wells, although this varies by area.
CBM fields are likely to require between two and eight gas wells per section to
efficiently extract the natural gas. Regulatory approval is required to drill
more than one well per section. As a result, the timing of drilling programs and
land development can be uncertain.

We are testing the feasibility of gas production from the Mannville coals in the
Fort Assiniboine region of Alberta. These coals are deeper than other producing
CBM projects and are water saturated. These projects require significant
up-front capital investment in the form of land acquisition and drilling and
completion costs. A significant period of time may be required to sufficiently
de-water the coals to determine if commercial production is feasible. As a
result, we may have to invest significant capital in CBM assets before they
achieve commercial rates of production. The wells may never achieve commercial
rates of production as there are no commercially proven Mannville CBM projects
in operation.

CBM projects in some areas of the United States have had negative public
reaction due to certain water disposal practices. In Canada, as in the United
States, water disposal practices are regulated to ensure public safety and water
conservation. Nevertheless, negative public perception around CBM production
could impede our access to the resource.

COMMITMENTS TO PROJECTS UNDER DEVELOPMENT

We have significant commitments in connection with various development
activities currently underway. The Syncrude Stage 3 expansion is currently 74%
complete and is expected to commence production in mid-2006. Development and
construction activities on the Buzzard field are approximately 60% complete and
is expected to commence production in late-2006. Detailed project engineering on
our Long Lake SAGD and upgrading project near Fort McMurray, Alberta is
currently approximately 60% complete. Bitumen production from the Long Lake
Project is expected to be achieved in the second half of 2006 and the first
commercial production of upgraded synthetic crude oil is expected to be achieved
in mid-2007. Our combined capital commitments for these projects are anticipated
to be $1,388 million in 2005 and $1,125 million in 2006. In these projects, we
are exposed to the possibility of cost overruns, which may be significant,
and/or delays in commencement of commercial production.

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 against these risks and the related financial
consequences.

In particular, our operations in Yemen expose us to potential material adverse
financial consequences. In 2004, Yemen accounted for $415 million or 52% of our
net income and this is expected to decline somewhat in 2005 as production
declines on Masila are partially offset by production from completion of
development activities on Block 51.


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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 citizens 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 15 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.

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, 2004, $468 million ($770 million, undiscounted) has been
     provided in the Consolidated Financial Statements for future asset
     retirement costs, relating to our oil and gas, Syncrude and chemicals
     facilities.

o    During 2004, we increased our asset retirement obligations by $146 million
     (2003 - $6 million) to reflect new obligations incurred or acquired.

o    Actual site remediation expenditures for the year were $31 million (2003 -
     $20 million). We anticipate actual site remediation expenditures in 2005 to
     approximate $47 million primarily in Australia and Nigeria.

o    We perform periodic internal and external assessments of our operations and
     adjust our estimates and retirement obligations accordingly.

o    During 2002, we conducted an external audit of our management systems for
     safety, environment and social responsibility issues. Overall, the review
     was positive and the few minor recommendations for improvement were
     implemented.

o    During 2003 and 2004, we conducted an external operational audit and
     confirmed that our management systems for safety, environment and social
     responsibility issues were being followed.

CLIMATE CHANGE

The Kyoto Protocol comes into force on February 16, 2005 following Russia's
delivery of its ratification instrument on November 18, 2004. Canada had
previously ratified the Kyoto Protocol in December 2002. Canada committed in
Kyoto in 1997 to an emission reduction of 6% below 1990 levels during the First
Commitment period (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 associated with
ratification and implementation of the Kyoto Protocol by providing the oil and
gas sector with limits on cost (a cap of $15/tonne) and volume (a cap of 55
megatonnes for large industrial emitters) as well as its position on long-term,
high capital-cost projects. In addition, emission reductions for oil and gas
producers are expected to be capped at levels that are 15% lower than business
as usual levels. 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 remains 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 Green House Gas
(GHG)-related legislation should not adversely affect the development of new
energy projects such as the oil sands.

For years, we have been assessing the impact of climate change developments on
our various business interests. 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. As well, we continue
to work closely with the Canadian and Alberta governments to assess the impact
of domestic regulatory options and provide information on our business to assist
governments in their policy deliberations. We maintain a wide range of business
contacts to ensure that a full slate of options is available to us in order to
meet the obligations that may be imposed by future legislation.


                                       63
<PAGE>

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. We have voluntarily reduced direct GHG emissions by
almost two 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.

We have entered into discussions with the management of several GHG investment
pools and we continue to evaluate the opportunities associated with biological
and geological sequestration of (CO2) and the capture of methane from landfills.
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 policy and requirements with respect to GHG when conducting these
reviews.

We are committed to the principles of full disclosure and we 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. Any indirect risks and
liabilities attributable to GHG are too remote and unquantifiable at this time.


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.

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 prepare our estimates. However, 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.

Management is responsible for estimating the quantities of proved oil and
natural gas reserves and for 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. An Executive Reserves Committee,
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 this 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 are resolved when the
differences are greater than 10%.


                                       64
<PAGE>

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-estimated 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.

Reserves 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 2004, $125 million of our
     total $175 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 $33 million after tax.

o    Calculating our unit-of-production depletion 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.
     Proved reserves are used where a property is acquired and proved developed
     reserves are used where a property is drilled and developed. In 2004, oil
     and gas depletion of $541 million was recorded in depletion, depreciation,
     amortization and impairment expense. If our reserves estimates changed by
     10%, our depletion, depreciation, amortization and impairment expense would
     have changed by approximately $38 million, after tax, assuming no other
     changes to our reserves profiles.

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.

Since we do not have any loan covenants directly linked to reserves, 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 the
Liquidity section of the MD&A.

OIL AND GAS ACCOUNTING - EVALUATION OF EXPLORATION DRILLING

We use the successful efforts method to account for our oil and gas exploration
and production activities. Under this method, exploration costs are capitalized
pending an evaluation as to whether sufficient quantities of reserves have been
found to justify commercial production. Accounting rules require that this
evaluation be made within at least one year of well completion. If our
evaluation determines that the well did not encounter sufficient quantities of
reserves to justify commercial production, the well costs are expensed as a dry
hole and are reported in exploration expense. Exploratory wells that are judged
to have discovered potentially sufficient quantities of oil and gas in areas
where major capital expenditures are required before the commencement of
production and where commercial viability requires the drilling of additional
exploratory wells, remain capitalized as long as the drilling of additional
exploratory wells is under way or firmly planned for the near future. For
offshore deep-water exploratory discoveries, it is not unusual to have
exploratory wells capitalized on our balance sheet for a number of years while
we perform additional appraisal drilling and seismic work on the potential oil
and gas field. We continually monitor the results of the additional appraisal
work and expense capitalized well costs as dry holes if we determine that the
potential field does not warrant further exploratory efforts in the near term.

We currently have an interest in an exploration block, offshore Nigeria where
capitalized exploratory costs have been on our balance sheet for longer than one
year. Major capital expenditures are required before production can begin and
additional drilling efforts are underway to fully appraise the block. We are
preparing a field development plan for the block with our partners for
submission to the Nigerian government for approval. Once we obtain this approval
and the project has been sanctioned, we will book proved reserves. Capitalized
costs relating to this exploration block as at December 31, 2004 were $77
million (2003 - $68 million). In the event that we are unable to book proved
reserves for this project, amounts capitalized will be written off.

For more information with respect to amounts and geographic locations of costs
incurred on exploration activity and amounts on our balance sheet relating to
unproved properties, please refer to our Capitalized Costs and Costs Incurred
tables set out in our supplemental Oil and Gas Producing Activities disclosures.


(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 producibility 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.


                                       65
<PAGE>

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 at the end of 2004 and
found no impairments were required based on our assumptions.

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$17/bbl to US$56/bbl and US$2/mmbtu to US$19/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 and development 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 forecast WTI crude oil prices were to fall to mid-US$20 levels 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.

Any impairment charges would lower our net income.

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.

BUSINESS COMBINATION - PURCHASE PRICE ALLOCATION

During the fourth quarter of 2004, we acquired EnCana (UK) Limited, a company
operating and exploring oil and gas properties located in the North Sea. We
accounted for this acquisition using the purchase method of accounting. Under
this method, we are required to record on our consolidated balance sheet the
estimated fair values of the acquired company's assets and liabilities at the
acquisition date. Any excess of the purchase price over the fair values of the
tangible and intangible net assets acquired is recorded as goodwill.

We have made various assumptions in determining the fair values of the acquired
company's assets and liabilities. The most significant assumptions and judgments
made relate to the estimation of the fair value of the oil and gas properties.
To determine the fair value of these properties, we estimated (a) oil and gas
reserves in accordance with our reserve standards, and (b) future prices of oil
and gas.

Our reserve estimates were based on the work performed by our engineers and
outside consultants. The judgments associated with these estimated reserves are
described earlier in our critical accounting estimates discussion entitled "Oil
and Gas Accounting - Reserves Determination". Our estimates of future prices
were based on prices derived from a consensus of future price forecasts amongst
industry analysts and our own assessments. The judgments associated with these
estimates are described earlier in our critical accounting estimates discussion
entitled "Oil and Gas Accounting - Impairment".

We applied our estimated future prices to the estimated reserves quantities
acquired, and we estimated future operating and development costs, to arrive at
estimated future net revenues for the properties acquired. For proved
properties, we discounted the future net revenues using after-tax discount
rates. The same principles were applied in arriving at the fair value of
unproved properties acquired. These unproved properties generally represent the
value of the probable and possible reserves. Because of their very nature,
probable and possible reserve estimates are more imprecise than those of proved
reserves. To compensate for the inherent risk of estimating and valuing unproved
reserves, an appropriate risk-weighting factor was applied to the discounted
future net revenues of the probable and possible reserves in each particular
instance.

If the fair value allocated to oil and gas properties acquired had been
decreased by $50 million, future income tax liabilities would have decreased by
$20 million and goodwill would have increased by $30 million.


ASSET RETIREMENT OBLIGATIONS

We are required to remove or remedy the effect of our activities on the
environment at our present and former operating sites by dismantling and
removing production facilities and remediating any damage caused. Estimating our
future asset retirement obligations requires us to make estimates and judgments
with respect to activities that will occur many years into the future. In
addition, the ultimate financial impact of environmental laws and regulations is
not always clearly known and cannot be reasonably estimated as standards evolve
in the countries in which we operate.


                                       66
<PAGE>

We record asset retirement obligations in our consolidated financial statements
by discounting the present value of the estimated retirement obligations
associated with our oil and gas wells and facilities and chemical plants. In
arriving at amounts recorded, numerous assumptions and judgments are made with
respect to ultimate settlement amounts, inflation factors, credit adjusted
discount rates, timing of settlement and expected changes in legal, regulatory,
environmental and political environments. The asset retirement obligations we
have recorded result in an increase to the carrying cost of our property, plant
and equipment. The obligations are accreted with the passage of time. A change
in any one of our assumptions could impact our asset retirement obligations, our
property, plant and equipment and our net income.

It is difficult to determine the impact of a change in any one of our
assumptions. As a result, we are unable to provide a reasonable sensitivity
analysis of the impact a change in our assumptions would have on our financial
results. We are confident, however, that our assumptions are reasonable.


NEW ACCOUNTING PRONOUNCEMENTS

CANADIAN PRONOUNCEMENTS
In an effort to harmonize Canadian GAAP with US GAAP, the Canadian Accounting
Standards Board has issued sections:

o    1530, COMPREHENSIVE INCOME;

o    3855, FINANCIAL INSTRUMENTS -- RECOGNITION AND MEASUREMENT; and

o    3865, HEDGES.

Under these new standards, all financial assets should be measured at fair value
with the exception of loans, receivables and investments that are intended to be
held to maturity and certain equity investments, which should be measured at
cost. Similarly, all financial liabilities should be measured at fair value when
they are held for trading or they are derivatives.

Gains and losses on financial instruments measured at fair value will be
recognized in the income statement in the periods they arise with the exception
of gains and losses arising from:

o    financial assets held for sale, for which unrealized gains and losses are
     deferred in other comprehensive income until sold or impaired; and

o    certain financial instruments that qualify for hedge accounting.

Sections 3855 and 3865 make use of "other comprehensive income". Other
comprehensive income comprises revenues, expenses, gains and losses that are
recognized in comprehensive income, but are excluded from net income. Unrealized
gains and losses on qualifying hedging instruments, translation of
self-sustaining foreign operations, and unrealized gains or losses on financial
instruments held for sale will be included in other comprehensive income and
reclassified to net income when realized. Comprehensive income and its
components will be a required disclosure under the new standard.

These new standards are effective for fiscal years beginning on or after October
1, 2006 and early adoption is permitted. Adoption of these standards as at
December 31, 2004 would have the following impact on our Consolidated Financial
Statements:

(Cdn$ millions)                                                  Increase
--------------------------------------------------------------------------
Accounts Receivable                                                     6
Future Income Tax Liabilities                                           2
Shareholders' Equity                                                    4
                                                                ----------

US PRONOUNCEMENTS

In November 2004, the Financial Accounting Standards Board (FASB) issued
Statement 151, INVENTORY COSTS. This statement amends ARB 43 to clarify that:

o    abnormal amounts of idle facility expense, freight, handling costs and
     wasted material (spoilage) should be recognized as current-period charges;
     and

o    requires the allocation of fixed production overhead to inventory based on
     the normal capacity of the production facilities.

The provisions of this statement are effective for inventory costs incurred
during fiscal years beginning after June 15, 2005. We do not expect the adoption
of this statement will have any material impact on our results of operations or
financial position.

In December 2004, the FASB issued Statement 123(R), SHARE-BASED PAYMENTS. This
statement revises Statement 123, ACCOUNTING FOR STOCK-BASED COMPENSATION, and
supersedes APB Opinion 25, ACCOUNTING FOR STOCK ISSUED TO EMPLOYEES.

Statement 123(R) requires all stock-based awards issued to employees to be
measured at fair value and to be expensed in the income statement. This
statement is effective for reporting periods beginning after June 15, 2005.

We are currently expensing stock-based awards issued to employees using the fair
value method for equity based awards and the intrinsic method for liability
based awards. Adoption of this standard will change our expense under US GAAP
for tandem options and stock appreciation rights as these awards will be
measured using the fair value method rather than the intrinsic method. We are
currently evaluating the provisions of Statement 123(R) and have not yet
determined the full impact this statement will have on our results of operations
or financial position under US GAAP.


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<PAGE>

In December 2004, the FASB issued Statement 152, ACCOUNTING FOR REAL ESTATE.
This statement amends Statement 66, ACCOUNTING FOR SALES OF REAL ESTATE, to
reference the financial accounting and reporting guidance for real estate
time-sharing transactions that is provided in AICPA Statement of Position 04-2,
ACCOUNTING FOR REAL ESTATE TIME-SHARING TRANSACTIONS. This statement also amends
FASB Statement 67, ACCOUNTING FOR COSTS AND INITIAL RENTAL OPERATIONS OF REAL
ESTATE PROJECTS, to state that the guidance for incidental operations and costs
incurred to sell real estate projects does not apply to real estate time-sharing
transactions. This statement is effective for financial statements with fiscal
years beginning after June 15, 2005 and will not impact our results of
operations or financial position.

In December 2004, the FASB issued Statement 153, EXCHANGES OF NONMONETARY
ASSETS, an amendment of APB Opinion 29, ACCOUNTING FOR NONMONETARY TRANSACTIONS.
This amendment eliminates the exception for nonmonetary exchanges of similar
productive assets and replaces it with a general exception for exchanges of
nonmonetary assets that do not have commercial substance. Under Statement 153,
if a nonmonetary exchange of similar productive assets meets a
commercial-substance test and fair value is determinable, the transaction must
be accounted for at fair value resulting in the recognition of any gain or loss.
This statement is effective for nonmonetary transactions in fiscal periods that
begin after June 15, 2005. We do not expect the adoption of this statement will
have any material impact on our results of operations or financial position.


ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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 recognize these risks and manage our operations to
minimize our exposures to the extent practical.

NON-TRADING

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.

In 2004, WTI averaged US$41.40/bbl reaching a high of US$56.42/bbl and a low of
US$32.41/bbl. NYMEX natural gas prices averaged US$6.19/mcf in 2004, reaching a
high of US$8.12/mcf and a low of US$4.34/mcf.

Our sensitivities to commodity prices and the expected impact on our 2005 cash
flow from operating activities and net income are as follows:

(Cdn$ millions)                                         Cash Flow   Net Income
-------------------------------------------------------------------------------
WTI - US$1 change above US$43.17                               50           35
WTI - US$1 change below US$43.17                               25           17
NYMEX natural gas - US$0.10 change                             10            7
                                                        -----------------------

These sensitivities to changes in benchmark prices for crude oil and natural gas
are based on our estimated 2005 production levels for crude oil and natural gas
and assume a Canadian/US dollar exchange rate of 80(cent). Our estimated crude
oil and natural gas production range for 2005 is between 230,000 and 250,000
boe/d, of which natural gas represents approximately 20%.

The majority of our oil and gas 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 2004, we purchased WTI put options to manage the commodity price risk
exposure on a portion of our oil production in 2005 and 2006. These options
establish an annual average WTI floor price of US$43/bbl in 2005 and US$38/bbl
in 2006, as follows:

                                       Notional                    Average Price
                                        Volumes         Term               (WTI)
--------------------------------------------------------------------------------
                                                                       (US$/bbl)
Crude Oil WTI Put Options          60,000 bbls/d        2005                  43
                                   60,000 bbls/d        2006                  38
                                   ---------------------------------------------

In 2003, we entered into WTI and NYMEX gas forward contracts for a 12 month
period. These forward contracts fixed our oil and gas prices at contract prices
for the hedged volumes, less applicable price differentials, as follows:

                                 Hedged                                  Average
                                Volumes                      Term          Price
--------------------------------------------------------------------------------
                                                                           (US$)
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
                         -------------------------------------------------------


                                       68
<PAGE>

Since actual prices during the contract period were higher than the fixed prices
we received, our return was lower than what it would have been without these
contracts in place. These contracts expired in March 2004.

FOREIGN CURRENCY RISK

A substantial portion of our operations are denominated in or referenced to US
dollars including:

o    sales of crude oil, natural gas and certain chemicals products;

o    capital spending and expenses for our oil and gas and chemicals operations;
     and

o    short-term and long-term borrowings.

The Canadian/US dollar exchange rate averaged 77(cent) in 2004 with a high of
85(cent) and a low of 72(cent).

Our sensitivities to the US dollar and the expected impact of a one cent change
on our 2005 cash flow from operating activities, net income, capital
expenditures and long-term debt are as follows:

<TABLE>
<CAPTION>
                                                   Cash      Net       Capital   Long-Term
(Cdn$ millions)                                    Flow   Income  Expenditures        Debt
-------------------------------------------------------------------------------------------
<S>                                                  <C>      <C>           <C>         <C>
   $0.01 change in US to Canadian dollar             25       13            18          50
                                                   ----------------------------------------
</TABLE>

Our sensitivities to changes in the Canadian/US dollar exchange rate are
calculated based on projected revenues, expenses, capital expenditures and
US-dollar denominated long-term debt for 2005. These estimates are based on a
WTI price for crude oil of US$40.00/bbl, a NYMEX natural gas price of
US$6.50/mcf and a Canadian/US dollar exchange rate of 80 (cent).

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 Canadian and
US-dollar borrowing facilities that can be used or repaid depending on expected
net cash flows. We designate our US-dollar borrowings as a hedge against our
US-dollar net investment in foreign operations.

Our Buzzard project in the North Sea creates foreign currency exposure as a
portion of the capital costs are denominated in British pounds (GBP) and Euros.
In order to reduce our exposure to fluctuations in these currencies relative to
the US dollar, we purchased foreign currency call options in early-2005. These
options set a ceiling on most of our British pound and Euro spending exposure
from February 2005 through to the end of 2006.

These call options effectively set a maximum GBP-US$ exchange rate of 1.95 on a
total of GBP 84 million for the period March 2005 through June 2005, and a
maximum rate of 2.00 on a total of GBP 185 million for the period July 2005
through December 2006. With respect to our Euro exposure, the call options
effectively set a maximum Euro-US$ exchange rate of 1.40 on a total of Euros 59
million for the period February through September 2005. Managing our exchange
rate exposure through the use of call options caps our exposure if the US dollar
weakens relative to the British pound and the Euro but allows us to benefit
fully from any strengthening of the US dollar relative to these currencies.

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. At December 31, 2004, we held a
foreign currency derivative instrument that obligates us and the counterparty to
exchange principal and interest amounts. In November 2006, we will pay US$37
million and receive Cdn $50 million.

INTEREST RISK

We are exposed to fluctuations in short-term interest rates from our
floating-rate debt and, to a lesser extent, our derivative instruments and
long-term debt, as their market value is sensitive to interest rate
fluctuations. To minimize our exposure to interest rate fluctuations, we
occasionally use derivative instruments.

Short-term interest rates for US dollar borrowings averaged 3.1% in 2004,
reaching a high of 3.2% and low of 3.0%.

Our sensitivity to interest rates and the expected impact of a 1% change in
interest rates on our 2005 cash flow from operating activities and net income is
as follows:

(Cdn$ millions)                                         Cash Flow    Net Income
--------------------------------------------------------------------------------
Interest Rates - 1% change in rates                             12            8
                                                        ------------------------

Our sensitivity to changes in interest rates is based on 2005 estimated average
floating rate debt of $1.2 billion and a Canadian/US dollar exchange rate of
80 (cent).

Our floating rate debt exposes us to changes in interest payments as interest
rates fluctuate. To manage this exposure, we maintain a combination of fixed and
floating rate borrowings and facilities. At December 31, 2004 fixed-rate
borrowings comprised 56% (2003 - 100%) of our long-term debt at an effective
average rate of 6.6% (2003 - 8.2%). During the year we periodically drew on our
unsecured syndicated term credit facilities and at December 31, 2004, floating
rate debt comprised 44% (2003 - nil) of our long-term debt at an effective
average rate of 3.2% (2003 - 2.0%).

We had no interest rate swaps outstanding in 2004 or 2003.


                                       69
<PAGE>

TRADING

COMMODITY PRICE RISK
Our marketing operation is involved in the marketing and trading of crude oil,
natural gas and power, 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. These net open positions allow us to generate income, but also expose
us to risk of loss due to fluctuating market prices (market risk). 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 exceeded and the potential loss could be greater than our
estimate. There were no changes in the methodology we used to estimate VaR in
2004.

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 year-end, annual high, annual low and annual average VaR amounts are as
follows:

(Cdn$ millions)                                   2004        2003          2002
--------------------------------------------------------------------------------
Value at Risk
   Year-End                                         21          21           19
   High                                             42          31           28
   Low                                              17          14           12
   Average                                          29          20           17
                                                  ------------------------------

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 our energy trading activities regularly.

CREDIT RISK

Credit risk affects both our trading and non-trading activities and is the risk
of loss if counterparties do not fulfill their contractual obligations. Most of
our receivables are with counterparties in the oil and gas and energy trading
industry and are subject to normal industry credit risk. We take the following
measures to reduce this risk:

o    we assess the financial strength of our counterparties 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 rating agency credit ratings and internal
     assessments based on company and industry analysis;

o    we review counterparty credit limits regularly; and

o    we use standard agreements that allow for the netting of 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, 2004:

o    over 90% of our receivables were investment grade;

o    only two counterparties individually made up more than 5% of our credit
     exposure. All were investment grade.


                                       70
<PAGE>

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements in this report, including those appearing in ITEMS 1 AND 2 -
BUSINESS AND PROPERTIES and ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS, are forward-looking
statements(1). Forward-looking statements are generally identifiable by terms
such as ANTICIPATE, BELIEVE, INTEND, PLAN, EXPECT, ESTIMATE, BUDGET, OUTLOOK or
other similar words, and include statements relating to future production
associated with our Long Lake, North Sea and West Africa projects.

These statements are subject to known and unknown risks and uncertainties and
other factors which may cause actual results, levels of activity and
achievements to differ materially from those expressed or implied by such
statements. These risks, uncertainties and other factors include:

o    market prices for oil, natural gas and chemicals products;

o    our ability to produce and transport crude oil and natural gas to markets;

o    the results of exploration and development drilling and related activities;

o    foreign-currency exchange rates;

o    economic conditions in the countries and regions in which we carry on
     business;

o    governmental actions that increase taxes, change environmental and other
     laws and regulations;

o    renegotiations of contracts; and

o    political uncertainty, including actions by terrorists, insurgent or other
     groups or armed other conflict, including conflict between states.

The above items and their possible impact are discussed more fully in the
section, titled BUSINESS RISK MANAGEMENT in Item 7 and QUANTITATIVE AND
QUALITATIVE DISCLOSURES ABOUT MARKET RISK in Item 7A.

The impact of any one risk, uncertainty or factor on a particular
forward-looking statement is not determinable with certainty as these are
interdependent and management's future course of action depends upon our
assessment of all information available at that time. Any statements regarding
the following are forward-looking statements:

o    future crude oil, natural gas or chemicals prices;

o    future production levels;

o    future cost recovery oil revenues from our operations in Yemen;

o    future capital expenditures and their allocation to exploration and
     development activities;

o    future asset dispositions;

o    future sources of funding for our capital program;

o    future debt levels;

o    future cash flows and their uses;

o    future drilling of new wells;

o    ultimate recoverability of reserves;

o    expected finding and development costs;

o    expected operating costs;

o    future demand for chemicals products;

o    future expenditures and future allowances relating to environmental
     matters; and

o    dates by which certain areas will be developed or will come on stream.

We believe that any forward-looking statements made are reasonable based on
information available to us on the date such statements were made. However, no
assurance can be given as to future results, levels of activity and
achievements. We undertake no obligation to update publicly or revise any
forward-looking statements contained in this report. All subsequent
forward-looking statements, whether written or oral, attributable to us or
persons acting on our behalf are expressly qualified in their entirety by these
cautionary statements.



(1) Within the meaning of the United States PRIVATE SECURITIES LITIGATION REFORM
ACT OF 1995, Section 21E of the United States SECURITIES EXCHANGE ACT OF 1934,
as amended, and Section 27A of the United States SECURITIES ACT OF 1933, as
amended.


                                       71
<PAGE>

SPECIAL NOTE TO CANADIAN INVESTORS

Nexen is a US Securities and Exchange Commission (SEC) registrant and a Form
10-K and related forms filer. Therefore, our reserves estimates and securities
regulatory disclosures generally follow SEC requirements.

In 2003, Canadian regulatory authorities adopted NATIONAL INSTRUMENT 51-101 -
STANDARDS OF DISCLOSURE FOR OIL AND GAS ACTIVITIES (NI 51-101) which prescribe
that Canadian companies follow certain standards for the preparation and
disclosure of reserves and related information. We have been granted the
following exemptions permitting us to:

o    substitute our SEC disclosures for much of the annual disclosure required
     by NI 51-101;

o    prepare our reserves estimates and related disclosures 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 (COGE Handbook) modified to
     reflect SEC requirements;

o    dispense with the requirement to have our reserves estimates and the
     Standardized Measure of Discounted Future Net Cash Flows and Changes
     Therein, included in the Supplementary Financial Information, evaluated or
     audited by independent qualified reserves evaluators; and

o    not disclose certain prescribed information pertaining to prospects if such
     disclosures would result in the contravention of a legal obligation, would
     likely be detrimental to our competitive interests or the information does
     not exist.

As a result of these exemptions, Canadian investors should note the following
fundamental differences in reserves estimates and related disclosures contained
in the Form 10-K:

o    SEC registrants apply SEC reserves definitions and prepare their reserves
     estimates in accordance with SEC requirements and generally accepted
     industry practices in the US whereas NI 51-101 requires adherence to the
     definitions and standards promulgated by the COGE Handbook;

o    the SEC mandates disclosure of proved reserves and the Standardized Measure
     of Discounted Future Net Cash Flows and Changes Therein calculated using
     year-end constant prices and costs only whereas NI 51-101 also requires
     disclosure of reserves and related future net revenues using forecast
     prices;

o    the SEC mandates disclosure of proved and proved producing reserves by
     country only whereas NI 51-101 requires disclosure of more reserve
     categories and product types;

o    the SEC does not require separate disclosure of proved undeveloped reserves
     or related future development costs whereas NI 51-101 requires disclosure
     of more information regarding proved undeveloped reserves, related
     development plans and future development costs;

o    the SEC does not require disclosure of finding and development (F&D) costs
     per boe of proved reserves additions whereas NI 51-101 requires that
     various F&D costs per boe be disclosed. NI 51-101 requires that F&D costs
     be calculated by dividing the aggregate of exploration and development
     costs incurred in the current year and the change in estimated future
     development costs relating to proved reserves by the additions to proved
     reserves in the current year. However, this will generally not reflect full
     cycle finding and development costs related to reserve additions for the
     year;

o    the SEC leaves the engagement of independent qualified reserves evaluators
     to the discretion of a company's board of directors whereas NI 51-101
     requires issuers to engage such evaluators and to file their reports;

o    the SEC does not consider the upgrading component of our integrated oil
     sands project at Long Lake as an oil and gas activity, and therefore
     permits recognition of bitumen reserves only. NI 51-101 specifically
     includes such activity as an oil and gas activity and recognizes synthetic
     oil as a product type, and therefore permits recognition of synthetic
     reserves. Given low year-end bitumen prices, we have not recognized any
     proved bitumen reserves under SEC requirements whereas under NI 51-101 we
     would have recognized 205 million barrels of proved synthetic reserves
     (before royalties); and

o    the SEC considers our Syncrude operation as a mining activity rather than
     an oil and gas activity, and therefore does not permit related reserves to
     be included with oil and gas reserves. NI 51-101 specifically includes such
     activity as an oil and gas activity and recognizes synthetic oil as a
     product type, and therefore permits them to be included with oil and gas
     reserves. We have provided a separate table showing our share of the
     Syncrude proved reserves as well as the additional disclosures relating to
     mining activities required by SEC requirements.

The foregoing is a general description of the principal differences only.

NI 51-101 requires that we make the following disclosures:

o    we use oil equivalents (boes) to express quantities of natural gas and
     crude oil in a common unit. A conversion ratio of 6 mcf of natural gas to 1
     barrel of oil is used. Boes may be misleading, particularly if used in
     isolation. The conversion ratio is based on an energy equivalency
     conversion method primarily applicable at the burner tip and does not
     represent a value equivalency at the wellhead.

                                       72
<PAGE>

FINANCIAL STATEMENTS


[GRAPHIC OMITTED]
[GRAPHIC IMAGE: GULF OF MEXICO, US]






                                       73
<PAGE>

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL INFORMATION



                                TABLE OF CONTENTS



REPORT OF MANAGEMENT..........................................................75

REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS........................76

CONSOLIDATED FINANCIAL STATEMENTS

     Consolidated Statement of Income.........................................77
     Consolidated Balance Sheet ..............................................78
     Consolidated Statement of Cash Flows ....................................79
     Consolidated Statement of Shareholders' Equity ..........................80
     Notes to Consolidated Financial Statements ..............................81


SUPPLEMENTARY FINANCIAL INFORMATION (UNAUDITED)

     Quarterly Financial Data in Accordance with Canadian and US GAAP........113
     Oil and Gas Producing Activities and Syncrude Operations ...............114




                                       74
<PAGE>

REPORT OF MANAGEMENT

February 7, 2005

To the Shareholders of Nexen Inc.:

We are responsible for the preparation and fair presentation of the consolidated
financial statements, as well as the financial reporting process that gives rise
to such consolidated financial statements. This responsibility requires us to
make significant accounting judgments and estimates. For example, we are
required to choose accounting principles and methods that are appropriate to the
company's circumstances and we are required to make estimates and assumptions
that affect amounts reported. Fulfilling this responsibility requires the
preparation and presentation of our consolidated financial statements in
accordance with generally accepted accounting principles in Canada with a
reconciliation to generally accepted accounting principles in the US.

We also have responsibility for the preparation and fair presentation of other
financial information in this report and to ensure the consistency of this
information with the financial statements.

We are responsible for the development and implementation of internal controls
over the financial reporting process. These controls are designed to provide
reasonable assurance that relevant and reliable financial information is
produced. To gather and control financial data, we have established accounting
and reporting systems supported by internal controls over financial reporting
and an internal audit program. We believe that our internal controls over
financial reporting provide reasonable assurance that our assets are safeguarded
against loss from unauthorized use or disposition, that receipts and
expenditures of the company are made only in accordance with authorization of
management and directors of the company, and that our records are reliable for
preparing our consolidated financial statements and other financial information
in accordance with applicable generally accepted accounting principles and in
accordance with applicable securities rules and regulations. All internal
control systems, no matter how well designed, have inherent limitations.
Therefore, even those systems determined to be effective can provide only
reasonable assurance with respect to financial statement preparation and
presentation.

We have established disclosure controls and procedures, internal controls over
financial reporting and corporate-wide policies to ensure that Nexen's
consolidated financial position, results of operations and cash flows are
presented fairly. Our disclosure controls and procedures are designed to ensure
timely disclosure and communication of all material information required by
regulators. We oversee, with assistance from our Disclosure Review Committee,
these controls and procedures and all required regulatory disclosures.

To ensure the integrity of our financial statements, we carefully select and
train qualified personnel. We also ensure our organizational structure provides
appropriate delegation of authority and division of responsibilities. Our
policies and procedures are communicated throughout the organization and include
a written ethics and integrity policy that applies to all employees including
the chief executive officer, chief financial officer and chief accounting
officer or controller.

Our Board of Directors is responsible for reviewing and approving the
consolidated financial statements and for overseeing management's performance of
its financial reporting responsibilities. Their financial statement related
responsibilities are fulfilled mainly through the Audit and Conduct Review
Committee (the Audit Committee) with assistance from the Reserves Review
Committee regarding the annual review of our crude oil and natural gas reserves
and the Finance Committee regarding the assessment and mitigation of risk. The
Audit Committee is composed entirely of independent directors, and includes four
directors with financial expertise. The Audit Committee meets regularly with
management, the internal auditors, and the independent auditors, to review
accounting policies, financial reporting and internal control issues and to
ensure each party is properly discharging its responsibilities. The Audit
Committee is responsible for the appointment and compensation of the independent
auditors and also considers their independence, reviews their fees and (subject
to applicable securities laws), pre-approves their retention for any permitted
non-audit services and their fee for such services. The internal auditors and
independent registered Chartered Accountants have full and unlimited access to
the Audit Committee, with or without the presence of management.



(signed) "Charles W. Fischer"                (signed) "Marvin F. Romanow"
President and Chief Executive Officer        Executive Vice President
                                             and Chief Financial Officer


                                       75
<PAGE>

REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

To the Board of Directors and Shareholders of Nexen Inc.:

We have audited the consolidated balance sheet of Nexen Inc. as at December 31,
2004 and 2003 and the consolidated statements of income, cash flows and
shareholders' equity for each of the years in the three year period ended
December 31, 2004. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing
standards and the standards of the Public Company Accounting Oversight Board
(United States). These standards require that we plan and perform an audit to
obtain reasonable assurance whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.

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

We have also audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the effectiveness of the Company's
internal control over financial reporting as at December 31, 2004, based on the
criteria established in INTERNAL CONTROL - INTEGRATED FRAMEWORK issued by the
Committee of Sponsoring Organizations of the Treadway Commission and our report
dated February 7, 2005 expressed an unqualified opinion on management's
assessment of the effectiveness of the Company's internal control over financial
reporting and an unqualified opinion on the effectiveness of the Company's
internal control over financial reporting.




Calgary, Canada                                 (signed) "Deloitte & Touche LLP"
February 7, 2005                                Independent Registered
                                                Chartered Accountants



COMMENTS BY AUDITORS ON CANADA-UNITED STATES OF AMERICA REPORTING DIFFERENCE

The standards of the Public Company Accounting Oversight Board (United States)
require the addition of an explanatory paragraph (following the opinion
paragraph) when there are changes in accounting principles that have a material
effect on the comparability of the Company's financial statements, such as the
changes described in Note 1(r) to the consolidated financial statements. Our
report to the board of directors and shareholders on the consolidated financial
statements of Nexen Inc., dated February 7, 2005, is expressed in accordance
with Canadian reporting standards which do not require a reference to such
changes in accounting principles in the auditors' report when the change is
properly accounted for and adequately disclosed in the financial statements.







Calgary, Canada                                 (signed) "Deloitte & Touche LLP"
February 7, 2005                                Independent Registered
                                                Chartered Accountants


                                       76
<PAGE>

<TABLE>
<CAPTION>
NEXEN INC.
CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE YEARS ENDED DECEMBER 31, 2004
Cdn$ millions, except per share amounts

                                                                     2004             2003             2002
------------------------------------------------------------------------------------------------------------
                                                                              Restated for     Restated for
                                                                                Changes in       Changes in
                                                                                Accounting       Accounting
                                                                                Principles       Principles
                                                                                  Note 1(r)        Note 1(r)
<S>                                                                 <C>              <C>              <C>
REVENUES
    Net Sales                                                       3,176            2,844            2,341
    Marketing and Other (Note 14)                                     729              610              496
                                                                    ----------------------------------------
                                                                    3,905            3,454            2,837
                                                                    ----------------------------------------
EXPENSES
    Operating                                                         762              721              701
    Depreciation, Depletion, Amortization and Impairment (Note 5)     744              995              632
    Transportation and Other                                          564              489              475
    General and Administrative                                        299              190              151
    Exploration                                                       246              199              178
    Interest (Note 7)                                                 143              169              181
                                                                    ----------------------------------------
                                                                    2,758            2,763            2,318
                                                                    ----------------------------------------

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES               1,147              691              519
                                                                    ----------------------------------------

PROVISION FOR INCOME TAXES (Note 15)
    Current                                                           248              214              207
    Future                                                            119              (73)             (44)
                                                                    ----------------------------------------
                                                                      367              141              163
                                                                    ----------------------------------------

NET INCOME FROM CONTINUING OPERATIONS                                 780              550              356
    Net Income from Discontinued Operations (Note 11)                  13               28               53
                                                                    ----------------------------------------

NET INCOME                                                            793              578              409
                                                                    ========================================

EARNINGS PER COMMON SHARE FROM CONTINUING OPERATIONS ($/share)
    Basic (Note 10)                                                  6.07             4.45              2.91
                                                                    ========================================

    Diluted (Note 10)                                                5.99             4.41              2.87
                                                                    ========================================

EARNINGS PER COMMON SHARE ($/share)
    Basic (Note 10)                                                  6.17             4.67              3.34
                                                                    ========================================

    Diluted (Note 10)                                                6.09             4.63              3.30
                                                                    ========================================
</TABLE>

SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.


                                       77
<PAGE>

<TABLE>
<CAPTION>
NEXEN INC.
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 2004 AND 2003
Cdn$ millions, except share amounts

                                                                        2004              2003
-----------------------------------------------------------------------------------------------
                                                                                  Restated for
                                                                                    Changes in
                                                                                    Accounting
                                                                                    Principles
                                                                                     Note 1(r)
<S>                                                                    <C>               <C>
ASSETS
    CURRENT ASSETS
      Cash and Cash Equivalents                                           74             1,087
      Accounts Receivable (Note 3)                                     2,136             1,423
      Inventories and Supplies (Note 4)                                  351               270
      Other                                                               42                79
                                                                     --------------------------
          Total Current Assets                                         2,603             2,859
                                                                     --------------------------

    PROPERTY, PLANT AND EQUIPMENT (Note 5)                             8,643             4,550
    GOODWILL                                                             375                36
    FUTURE INCOME TAX ASSETS (Note 15)                                   333               108
    DEFERRED CHARGES AND OTHER ASSETS (Note 17)                          429               164
                                                                     --------------------------

                                                                      12,383             7,717
                                                                     ==========================
LIABILITIES AND SHAREHOLDERS' EQUITY
    CURRENT LIABILITIES
      Short-Term Borrowings (Note 7)                                     100                --
      Current Portion of Long-Term Debt (Note 7)                          --               572
      Accounts Payable and Accrued Liabilities                         2,416             1,404
      Accrued Interest Payable                                            34                44
      Dividends Payable                                                   13                12
                                                                     --------------------------
          Total Current Liabilities                                    2,563             2,032
                                                                     --------------------------

    LONG-TERM DEBT (Note 7)                                            4,259             2,517
    FUTURE INCOME TAX LIABILITIES (Note 15)                            2,131               720
    ASSET RETIREMENT OBLIGATIONS (Note 8)                                421               305
    DEFERRED CREDITS AND OTHER LIABILITIES                               142                68
    SHAREHOLDERS' EQUITY (Note 9)
      Common Shares, no par value
        Authorized:        Unlimited
        Outstanding:       2004 - 129,199,583 shares
                           2003 - 125,606,107 shares                     637               513
      Contributed Surplus                                                 --                 1
      Retained Earnings                                                2,335             1,594
      Cumulative Foreign Currency Translation Adjustment                (105)              (33)
                                                                     --------------------------
          Total Shareholders' Equity                                   2,867             2,075
                                                                     --------------------------

    COMMITMENTS, CONTINGENCIES AND GUARANTEES (Notes 12 and 15)
                                                                      12,383             7,717
                                                                     ==========================
</TABLE>

SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

Approved on behalf of the Board:


(Signed) "Charles W. Fischer"                   (Signed) "David A. Hentschel"
Director                                        Director


                                       78
<PAGE>

<TABLE>
<CAPTION>
NEXEN INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE YEARS ENDED DECEMBER 31, 2004
Cdn$ millions

                                                                                   2004               2003                2002
-------------------------------------------------------------------------------------------------------------------------------
                                                                                              Restated for        Restated for
                                                                                                Changes in          Changes in
                                                                                                Accounting          Accounting
                                                                                                Principles          Principles
                                                                                                 Note 1(r)           Note 1(r)
<S>                                                                               <C>                <C>                 <C>
OPERATING ACTIVITIES
    Net Income from Continuing Operations                                           780                550                 356
    Net Income from Discontinued Operations                                          13                 28                  53
    Charges and Credits to Income not Involving Cash (Note 16)                      903              1,018                 724
    Exploration Expense                                                             246                199                 178
    Changes in Non-Cash Working Capital (Note 16)                                  (122)              (320)                (46)
    Other (Note 16)                                                                (213)               (70)                (15)
                                                                               ------------------------------------------------
                                                                                  1,607              1,405               1,250

FINANCING ACTIVITIES
    Proceeds from Long-Term Notes and Debentures (Note 7)                         1,779                651                 790
    Repayment of Long-Term Notes and Debentures (Note 7)                           (300)                --                   -
    Proceeds from (Repayment of) Term Credit Facilities, Net                         83                 93                (419)
    Proceeds from (Repayment of) Short-Term Borrowings, Net                         101                (18)                (33)
    Proceeds from Subordinated Debentures (Note 7)                                   --                613                  --
    Redemption of Preferred Securities (Note 7)                                    (289)              (340)                 --
    Dividends on Common Shares                                                      (52)               (40)                (37)
    Issue of Common Shares                                                          124                 73                  51
    Other                                                                           (20)               (26)                (23)
                                                                               ------------------------------------------------
                                                                                  1,426              1,006                 329

INVESTING ACTIVITIES
    Business Acquisition, Net of Cash Acquired (Note 2)                          (2,583)                --                  --
    Capital Expenditures
      Exploration and Development                                                (1,582)            (1,276)             (1,477)
      Proved Property Acquisitions                                                   (4)              (164)                 (4)
      Chemicals, Corporate and Other                                                (95)               (54)               (144)
    Proceeds on Disposition of Assets                                                34                293                  49
    Changes in Non-Cash Working Capital (Note 16)                                   244                (18)                  7
    Other                                                                           (27)                --                  --
                                                                               ------------------------------------------------
                                                                                 (4,013)            (1,219)             (1,569)


EFFECT OF EXCHANGE RATE CHANGES ON CASH AND
    CASH EQUIVALENTS                                                                (33)              (164)                (12)
                                                                               ------------------------------------------------

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                                 (1,013)             1,028                  (2)

CASH AND CASH EQUIVALENTS - BEGINNING OF YEAR                                     1,087                 59                  61
                                                                               ------------------------------------------------

CASH AND CASH EQUIVALENTS - END OF YEAR                                              74              1,087                  59
                                                                               ================================================
</TABLE>

SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

                                       79
<PAGE>

<TABLE>
<CAPTION>
NEXEN INC.
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
FOR THE THREE YEARS ENDED DECEMBER 31, 2004
Cdn$ millions

                                                                                   2004               2003                2002
-------------------------------------------------------------------------------------------------------------------------------
                                                                                              Restated for        Restated for
                                                                                                Changes in          Changes in
                                                                                                Accounting          Accounting
                                                                                                Principles          Principles
                                                                                                 Note 1(r)           Note 1(r)
<S>                                                                               <C>                <C>                 <C>
COMMON SHARES (Note 9)
    Balance at Beginning of Year                                                    513                440                 389
    Exercise of Stock Options                                                        93                 50                  27
    Issue of Common Shares                                                           31                 23                  24
                                                                               ------------------------------------------------
    Balance at End of Year                                                          637                513                 440
                                                                               ------------------------------------------------

CONTRIBUTED SURPLUS
    Balance at Beginning of Year                                                      1                 --                  --
    Stock Based Compensation Expense (Note 9)                                         2                  1                  --
    Modification of Stock Option Plan to Tandem Option Plan (Note 9)                 (3)                --                  --
                                                                               ------------------------------------------------
    Balance at End of Year                                                           --                  1                  --
                                                                               ------------------------------------------------

RETAINED EARNINGS
    Balance at Beginning of Year                                                  1,594              1,056                 697
    Retroactive Adjustment for Changes in Accounting Principles (Note 1)             --                 --                 (13)
    Net Income                                                                      793                578                 409
    Dividends on Common Shares                                                      (52)               (40)                (37)
                                                                               ------------------------------------------------
    Balance at End of Year                                                        2,335              1,594               1,056
                                                                               ------------------------------------------------

CUMULATIVE FOREIGN CURRENCY TRANSLATION ADJUSTMENT
    Balance at Beginning of Year                                                    (33)                94                  94
    Retroactive Adjustment for Changes in Accounting Principles (Note 1)             --                 --                 (34)
    Translation Adjustment, Net of Income Taxes                                     (72)              (127)                 34
                                                                               ------------------------------------------------
    Balance at End of Year                                                         (105)               (33)                 94
                                                                               ------------------------------------------------
</TABLE>

SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

                                       80
<PAGE>

NEXEN INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cdn$ millions except as noted

1.       ACCOUNTING POLICIES

Our Consolidated Financial Statements are prepared in accordance with Canadian
Generally Accepted Accounting Principles (GAAP). The impact of significant
differences between Canadian and US GAAP on the Consolidated Financial
Statements is disclosed in Note 19. We make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the Consolidated Financial
Statements, and revenues and expenses during the reporting period. Our
management reviews these estimates, including those related to litigation,
environmental and dismantlement liabilities, income taxes and determination of
proved reserves on an ongoing basis. Changes in facts and circumstances may
result in revised estimates and actual results may differ from these estimates.

(a)      PRINCIPLES OF CONSOLIDATION

The Consolidated Financial Statements include the accounts of Nexen Inc. and our
subsidiary companies (Nexen, we or our). All subsidiary companies are wholly
owned and all material intercompany accounts and transactions have been
eliminated. We proportionately consolidate our undivided interests in our oil
and gas exploration, development and production activities conducted under joint
venture arrangements. We also proportionately consolidate our 7.23% undivided
interest in the Syncrude joint venture, which is considered a mining activity
under US regulations. While the joint ventures under which these activities are
carried out do not comprise distinct legal entities, they are operating
entities, the significant operating policies of which are, by contractual
arrangement, jointly controlled by all working interest parties.

(b)      ACCOUNTS RECEIVABLE

Accounts receivable are recorded based on our revenue recognition policy (see
Note 1(i)). Our allowance for doubtful accounts provides for specific doubtful
receivables.

(c)      INVENTORIES AND SUPPLIES

Inventories and supplies for our oil and gas, marketing and chemicals operations
are stated at the lower of cost and net realizable value. Cost is determined on
the first-in, first-out method or average basis.

Inventory costs include expenditures and other costs, including depreciation,
depletion and amortization, directly or indirectly incurred in bringing the
inventory to its existing condition.

(d)      PROPERTY, PLANT AND EQUIPMENT (PP&E)

Property, plant and equipment is recorded at cost and includes only recoverable
costs that directly result in an identifiable future benefit. Unrecoverable
costs, maintenance and turnaround costs are expensed as incurred. Improvements
that increase capacity or extend the useful lives of the related assets are
capitalized to PP&E.

We follow successful efforts accounting for our oil and gas business. All
property acquisition costs are initially capitalized to PP&E as unproved
property costs. Once proved reserves are discovered, the acquisition costs are
reclassified to proved property acquisition costs. Exploration drilling costs
are capitalized pending evaluation as to whether sufficient quantities of
reserves have been found to justify commercial production. If commercial
quantities of reserves are not found, exploration drilling costs are expensed.
All exploratory wells are evaluated for commercial viability within twelve
months of drilling completion. Exploration wells that discover potentially
commercial quantities of reserves in areas requiring major capital expenditures
before the commencement of production and where commercial viability requires
the drilling of additional exploratory wells, remain capitalized as long as the
drilling of additional exploratory wells is under way or firmly planned. All
other exploration costs, including geological and geophysical and annual lease
rentals are expensed to earnings as incurred. All development costs are
capitalized as proved property costs. General and administrative costs that
directly relate to acquisition, exploration and development activities are
capitalized to PP&E.

Property, plant and equipment for our Syncrude operation is recorded at cost and
includes only recoverable costs that directly result in an identifiable future
benefit. Unrecoverable costs, maintenance and turnaround costs are expensed as
incurred. Improvements that increase capacity or extend the useful lives of the
related assets are capitalized to PP&E.

We engage in research and development activities to develop or improve processes
and techniques to extract oil and gas. Research involves investigating new
knowledge. Development involves translating that knowledge into a new technology
or process. Research costs are expensed as incurred. Development costs are
deferred once technical feasibility is established and we intend to proceed with
development. We defer these costs in PP&E until the commencement of commercial
operations or production. Otherwise, development costs are expensed as incurred.
Development costs include pre-operating revenues and costs.


                                       81
<PAGE>

(e)      DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT (DD&A)

Under successful efforts accounting, we deplete oil and gas capitalized costs
using the unit-of-production method. Development and exploration drilling and
equipping costs are depleted over remaining proved developed reserves and proved
property acquisition costs over remaining proved reserves. Depletion is
considered a cost of inventory when the oil and gas is produced. When this
inventory is sold, the depletion is charged to DD&A expense.

Our Syncrude PP&E is depleted using the unit-of-production method. Capitalized
costs are depleted over proved and probable reserves within developed areas of
interest.

We depreciate other plant and equipment costs, including our chemicals
facilities, using the straight-line method based on the estimated useful lives
of the assets, which range from 3 years to 30 years. Unproved property costs and
major projects that are under construction or development are not depreciated,
depleted or amortized.

We evaluate the carrying value of our PP&E whenever events or conditions occur
that indicate that the carrying value of properties on our balance sheet may not
be recoverable from future cash flows. These events or conditions occur
periodically. If carrying value exceeds the sum of undiscounted future cash
flows, the property's value is impaired. The property is then assigned a fair
value equal to its estimated total future cash flows, discounted for the time
value of money, and we expense the excess carrying value to depreciation,
depletion, amortization and impairment. Our cash flow estimates require
assumptions about future commodity prices, operating costs and other factors.
Actual results can differ from those estimates.

In assessing the carrying values of our unproved properties, we take into
account our future plans for those properties, the remaining terms of the leases
and any other factors that may be indicators of potential impairment.

(f)      CARRIED INTEREST

We conduct certain international operations jointly with foreign governments in
accordance with production sharing agreements pursuant to which proved reserves
are recognized using the economic interest method. Under these agreements, we
pay both our share and the government's share of operating and capital costs. We
recover the government's share of these costs from future revenues or production
over several years. The government's share of operating costs are recorded in
operating expense when incurred and capital costs are recorded in PP&E and are
expensed to DD&A in the year recovered. All recoveries are recorded as revenue
in the year of recovery.

(g)      ASSET RETIREMENT OBLIGATIONS

We provide for future asset retirement obligations on our resource properties,
facilities, production platforms, pipelines and chemicals facilities based on
estimates established by current legislation and industry practices. The asset
retirement obligation is initially measured at fair value and capitalized to
property, plant and equipment as an asset retirement cost. The asset retirement
obligation accretes until the time the retirement obligation is expected to
settle while the asset retirement cost is amortized over the useful life of the
underlying property, plant and equipment. The amortization of the asset
retirement cost and the accretion of the asset retirement obligation are
included in depreciation, depletion, amortization and impairment. Actual
retirement costs are recorded against the obligation when incurred. Any
difference between the recorded asset retirement obligation and the actual
retirement costs incurred is recorded as a gain or loss in the period of
settlement.

(h)      GOODWILL

Goodwill is recorded at cost and is not amortized. We test goodwill for
impairment annually based on estimated future cash flows of the reporting unit
to which the goodwill is attributable. In addition, we test goodwill for
impairment whenever an event or circumstance occurs that may reduce the fair
value of a reporting unit below its carrying amount. Our goodwill is
attributable to our Marketing and United Kingdom reporting units.

(i)      REVENUE RECOGNITION

CRUDE OIL AND NATURAL GAS

Revenue from the production of crude oil and natural gas is recognized when
title passes to the customer. In Canada, the United States and the United
Kingdom, our customers typically take title when the crude oil and natural gas
reaches the end of the pipeline. For our other international operations, our
customers take title when the crude oil is loaded onto the tanker. When we
produce or sell more or less oil or natural gas than our share, production
overlifts and underlifts occur. We record overlifts as liabilities, and
underlifts as assets. We settle these over time as liftings are equalized or in
cash when production ends.

Revenue represents Nexen's share and is recorded net of royalty payments to
governments and other mineral interest owners. For our international operations,
all government interests, except for income taxes, are considered royalty
payments. Our revenue also includes the recovery of costs paid on behalf of
foreign governments in international locations. See Note 1(f).


                                       82
<PAGE>

CHEMICALS

Revenue from our chemicals operations is only recognized when our products are
delivered to our customers. Delivery only takes place when we have a sales
contract in place specifying delivery volumes and sales prices. We assess
customer credit worthiness before entering into sales contracts to minimize
collection risk.

MARKETING

Substantially all of the physical purchase and sales contracts entered into by
our marketing operation are considered to be derivative instruments.
Accordingly, financial and physical commodity contracts (collectively derivative
instruments) held by our marketing operation are stated at fair value on the
balance sheet date unless the requirements for hedge accounting are met (see
Note 1(m)). We record any change in fair value as a gain or loss in marketing
and other.

Any margin realized by our marketing department on the sale of our proprietary
oil and gas production is included in marketing and other. We assess customer
credit worthiness before entering into contracts and provide for netting terms
to minimize collection risk. Amounts are recorded on a net basis where we have
the legal right of offset. Our marketing operation has received cash payments in
exchange for assuming certain transportation obligations from third parties.
These cash payments have been recorded as deferred liabilities and are
recognized in net income as the transportation is used.

(j)      INCOME TAXES

We follow the liability method of accounting for income taxes (see Note 15).
This method recognizes income tax assets and liabilities at current rates, based
on temporary differences in reported amounts for financial statement and tax
purposes. The effect of a change in income tax rates on future income tax assets
and future income tax liabilities is recognized in income when substantively
enacted.

We do not provide for foreign withholding taxes on the undistributed earnings of
our foreign subsidiaries, since we intend to invest such earnings indefinitely
in foreign operations.

(k)      FOREIGN CURRENCY TRANSLATION

Our foreign operations, which are considered financially and operationally
independent, are translated from their functional currency into Canadian dollars
as follows:

o    assets and liabilities using exchange rates at the balance sheet dates; and

o    revenues and expenses using the average exchange rates throughout the year.

Gains and losses resulting from this translation are included in the cumulative
foreign currency translation adjustment in shareholders' equity.

Monetary balances denominated in a currency other than a functional currency are
translated into the functional currency using exchange rates at the balance
sheet dates. Gains and losses arising from translation, except on our designated
US-dollar debt, are included in income. We have designated US-dollar debt as a
hedge against our net investment in US-dollar based self-sustaining foreign
operations. Gains and losses resulting from the translation of the designated
US-dollar debt are included in the cumulative foreign currency translation
adjustment in shareholders' equity. If our US-dollar debt, net of income taxes,
exceeds our US-dollar investment in foreign operations, then the gains or losses
attributable to such excess are included in marketing and other in the
Consolidated Statement of Income.

(l)      CAPITALIZED INTEREST

We capitalize interest on major development projects until such time as the
project is substantially complete using the weighted-average interest rate on
all of our borrowings. Capitalized interest cannot exceed the actual interest
expense.

(m)      DERIVATIVE INSTRUMENTS

NON-TRADING ACTIVITIES

We use derivative instruments such as physical purchase and sales, forwards,
futures, swaps and options for non-trading purposes to manage fluctuations in
commodity prices, foreign currency exchange rates and interest rates (see Note
6). We record these instruments at fair value at the balance sheet date and
record any change in fair value as a net gain or loss in marketing and other
during the period of change unless the requirements for hedge accounting are
met. Hedge accounting is used when there is a high degree of correlation between
price movements in the derivative instruments and the items designated as being
hedged. Nexen formally documents all hedges and the risk management objectives
at the inception of the hedge. We recognize gains and losses on the derivative
instruments designated as hedges in the same period as the gains or losses on
the hedged items are recognized. If effective correlation ceases, hedge
accounting is terminated and future changes in the market value of the
derivative instrument are included as gains or losses in marketing and other in
the period of change.


                                       83
<PAGE>

TRADING ACTIVITIES

Our marketing operation uses derivative instruments for marketing and trading
crude oil and natural gas including:

o    commodity contracts settled with physical delivery;

o    exchange-traded futures and options; and

o    non-exchange traded forwards, swaps and options.

We record these instruments at fair value at the balance sheet date and record
changes in fair value as net gains or losses in marketing and other during the
period of change. The fair value of these instruments is recorded as accounts
receivable or payable if we anticipate settling the instruments within a year of
the balance sheet date. If we anticipate settling the instruments beyond 12
months we record them as deferred charges and other assets or deferred credits
and other liabilities.

(n)      EMPLOYEE BENEFITS

The cost of pension benefits earned by employees in our defined benefit pension
plans is actuarially determined using the projected-benefit method prorated on
service and our best estimate of the plans' investment performance, salary
escalations and retirement ages of employees. To calculate the plans' expected
returns, assets are measured at fair value. Past service costs arising from plan
amendments, and net actuarial gains and losses which exceed 10% of the greater
of the accrued benefit obligation and the fair value of plan assets, are
expensed in equal amounts over the expected average remaining service life of
the employee group. We measure the plan assets and the accrued benefit
obligation on October 31 each year.

(o)      STOCK-BASED COMPENSATION

In 2003, we adopted the fair-value method of accounting for stock options
granted to employees and directors. We recorded stock-based compensation expense
in the Consolidated Statement of Income as general and administrative expenses
for all options granted on or after January 1, 2003, with a corresponding
increase to contributed surplus. Compensation expense for options granted was
based on estimated fair values at the time of grant and we recognized the
expense over the vesting period of the option.

In May 2004, we modified our stock option plan to a tandem option plan by
including a cash feature. The tandem options give the holders a right to either
purchase common shares at the exercise price or to receive cash payments equal
to the excess of the market value of the common shares over the exercise price.
As a result of the modification, we record obligations for the tandem options
using the intrinsic-value method of accounting and recognize compensation
expense. Obligations are accrued on a graded vesting basis and represent the
difference between the market value of our common shares and the exercise price
of the options. The obligations are revalued each reporting period based on the
change in the market value of our common shares and the number of graded vested
options outstanding. We reduce the liability when the options are surrendered
for cash. When the options are exercised for stock, the recorded liability
amount is transferred to share capital.

Stock options awarded to our US employees on or after December 1, 2004 do not
include a cash feature and are not accounted for as tandem options. Instead, we
account for these options using the fair-value method. Compensation expense is
based on estimated fair values at the time of grant and is recognized over the
vesting period of the options. The expense is included as general and
administrative expense with a corresponding increase to contributed surplus.

We provide stock appreciation rights to employees as described in Note 9.
Obligations are accrued as compensation expense over the graded vesting period
of the stock appreciation rights.

(p)      CASH AND CASH EQUIVALENTS

Cash and cash equivalents include short-term, highly liquid investments that
mature within three months of their purchase. They are recorded at cost, which
approximates market value.

(q)      TRANSPORTATION

We pay to transport the crude oil, natural gas and chemicals products that we
market, and then bill our customers for the transportation. This transportation
is presented in our Consolidated Financial Statements as a cost to us and is
recorded as transportation and other.

(r)      CHANGES IN ACCOUNTING PRINCIPLES

ASSET RETIREMENT OBLIGATIONS (ARO)

On January 1, 2004, we retroactively adopted the Canadian Institute of Chartered
Accountants (CICA) standard S.3110, ASSET RETIREMENT OBLIGATIONS. This new
standard requires recognition of a liability for the future retirement
obligations associated with our property, plant and equipment, which includes
oil and gas wells and facilities, and chemicals plants. We previously provided
for dismantlement and site restoration costs on our oil and gas wells and
facilities, and chemicals plants based on estimates established by current
legislation and industry practices. We recorded a provision for these costs in
DD&A based on proved reserves or estimated remaining asset lives. The change was
adopted retroactively and all prior periods presented have been restated.


                                       84
<PAGE>

FINANCIAL INSTRUMENTS

In the fourth quarter of 2004, we retroactively adopted the changes to CICA
standard S.3860, FINANCIAL INSTRUMENTS. These changes require that fixed-amount
contractual obligations that can be settled by issuing a variable number of
equity instruments be classified as a liability. Our US-dollar denominated
preferred and subordinated securities have these characteristics and accordingly
have been reclassified as long-term debt. Dividends and interest on these
securities have been included in interest expense and issue costs previously
charged to retained earnings have been amortized over the life of the
securities. Unamortized issue costs have been expensed on the redemption of the
preferred securities in 2003 and 2004. Foreign exchange gains or losses from
translation of the US-dollar amounts have been included as cumulative foreign
currency translation adjustments. The change was adopted retroactively and all
prior periods presented have been restated.


GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

In 2004, we adopted CICA standard S.1100, GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES which eliminated general practice in Canada as a component of GAAP.
Our accounting policy for 2004 is to include geological and geophysical costs as
operating cash outflows in our Consolidated Statement of Cash Flows. For
previous years, we included geological and geophysical costs as investing cash
outflows consistent with industry practice in Canada. In our Consolidated
Statement of Cash Flows for 2004, we included $73 million of geological and
geophysical costs as other operating cash outflows. For 2003 and 2002,
geological and geophysical costs of $62 million and $80 million, respectively,
are included in investing activities as exploration and development capital
expenditures. This change in accounting policy was adopted prospectively.


IMPACT OF CHANGES IN ACCOUNTING PRINCIPLES

The impact of the changes on our 2004 Consolidated Statement of Income resulted
in additional interest expense of $3 million for dividends on preferred
securities, additional transportation and other expense of $11 million for the
unamortized issue costs on the redemption of preferred securities, and a
corresponding reduction in the provision for income taxes of $6 million. The
impact of these changes in accounting principles on our Consolidated Statement
of Income and Earnings per Common Share for the years ended December 31, 2003
and 2002 and on our Consolidated Balance Sheet at December 31, 2003, are shown
below.

CONSOLIDATED STATEMENT OF INCOME FOR THE YEARS ENDED DECEMBER 31, 2003 AND 2002

<TABLE>
<CAPTION>
                                                                                  2003      2002
-------------------------------------------------------------------------------------------------
<S>                                                                               <C>      <C>
Depletion, Depreciation, Amortization and Impairment Expense as Reported (1)       995      632
    Less:  Dismantlement and Site Restoration                                      (33)     (35)
    Plus:  Asset Retirement Cost Amortization                                       14       15
    Plus:  Asset Retirement Obligation Accretion                                    19       20
                                                                                -----------------
Depletion, Depreciation, Amortization and Impairment Expense as Restated           995      632
                                                                                -----------------

Transportation and Other Expense as Reported                                       461      475
    Plus:  Unamortized Issue Costs on Redemption of Preferred Securities            28       --
                                                                                -----------------
Transportation and Other Expense as Restated                                       489      475
                                                                                -----------------

Interest Expense as Reported                                                       105      109
    Plus:  Dividends on Preferred Securities                                        64       72
                                                                                -----------------
Interest Expense as Restated                                                       169      181
                                                                                -----------------

Provision for Future Income Taxes as Reported (1)                                  (42)     (15)
    Plus:  Tax Effect of Changes in Accounting Principles                          (31)     (29)
                                                                                -----------------
Provision for Future Income Taxes as Restated                                      (73)     (44)
                                                                                -----------------
</TABLE>

Note:
(1)  Adjusted for discontinued operations.


                                       85
<PAGE>

<TABLE>
<CAPTION>
NET INCOME AND EARNINGS PER COMMON SHARE FOR THE YEARS ENDED DECEMBER 31, 2003 AND 2002

                                                                                              2003          2002
----------------------------------------------------------------------------------------------------------------
<S>                                                                                            <C>           <C>
Net Income Attributable to Common Shareholders
    As Reported                                                                                599           409
    Less: Unamortized Issue Costs on Preferred Securities Redemption, Net of Income Taxes      (21)           --
                                                                                            --------------------
    As Restated                                                                                578           409
                                                                                            =====================

Earnings per Common Share ($/share)
    Basic as Reported                                                                         4.84          3.34
                                                                                            =====================
    Restated                                                                                  4.67          3.34
                                                                                            =====================

    Diluted as Reported                                                                       4.79          3.30
                                                                                            =====================
    Restated                                                                                  4.63          3.30
                                                                                            =====================
</TABLE>

<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEET AS AT DECEMBER 31, 2003

                                                                                        FINANCIAL
                                                                                ARO   INSTRUMENTS
                                                         AS REPORTED         CHANGE        CHANGE    AS RESTATED
----------------------------------------------------------------------------------------------------------------
<S>                                                      <C>                 <C>      <C>            <C>
Property, Plant and Equipment                                  4,469             81            --          4,550
Deferred Charges and Other Assets                                153             --            11            164
Current Portion of Long-Term Debt                                291             --           281            572
Long-Term Debt                                                 2,485             --            32          2,517
Future Income Tax Liabilities                                    724            (17)           13            720
Asset Retirement Obligations                                      --            305            --            305
Dismantlement and Site Restoration                               179           (179)           --             --
Preferred and Subordinated Securities                            364             --          (364)            --
Retained Earnings                                              1,659            (28)          (37)         1,594
Cumulative Foreign Currency Translation Adjustment              (119)            --            86            (33)
                                                         -------------------------------------------------------
</TABLE>

(s)      RECLASSIFICATION

Certain information provided for prior years has been reclassified to conform to
the presentation adopted in 2004.

2.       BUSINESS ACQUISITION

On December 1, 2004, we acquired 100% of the issued and outstanding share
capital of EnCana (UK) Limited (EnCana UK) from EnCana Corporation (EnCana) for
cash consideration of US$2.1 billion, subject to certain adjustments. EnCana UK
held all of EnCana's offshore oil and gas assets in the North Sea.

We acquired EnCana UK to establish a strategic presence in the North Sea by
acquiring operatorship of the Buzzard field development and operatorship of the
producing Scott and Telford fields. The acquisition also gives us access to
interests in several satellite discoveries and over 700,000 net undeveloped
exploration acres. In addition, we acquired the management and technical teams
that found and are developing the Buzzard discovery. Goodwill paid is
attributable to the established North Sea presence acquired and the knowledge
and business relationships acquired through the management team and employees of
EnCana UK.


                                       86
<PAGE>

The acquisition has been accounted for using the purchase method and the results
of EnCana UK have been consolidated with the results of Nexen from December 1,
2004. The following table shows the allocation of the purchase price based on
the estimated fair value of the assets and liabilities acquired:

--------------------------------------------------------------------------
Purchase Price, Net of Cash Acquired:
    Cash Paid                                                       2,561
    Transaction Costs                                                  22
                                                                   -------
                                                                    2,583
                                                                   =======
Purchase Price Allocated as follows:
    Accounts Receivable                                               310
    Inventories and Supplies                                           11
    Other Current Assets                                                2
    Property, Plant and Equipment                                   3,395
    Future Income Tax Assets                                          239
    Goodwill (1)                                                      334
    Deferred Charges and Other Assets                                  12
    Accounts Payable and Accrued Liabilities                         (289)
    Asset Retirement Obligations                                     (134)
    Future Income Tax Liabilities                                  (1,284)
    Deferred Credits and Other Liabilities                            (13)
                                                                   -------
      Total Purchase Price Allocated                                2,583
                                                                   =======

Note:
(1)  The amount of goodwill deductible for tax purposes is nil.


The unaudited pro forma results for the years ended December 31, 2004 and 2003
are shown below as if the acquisition had occurred on January 1, 2003. Pro forma
results are not necessarily indicative of actual results or future performance.

                                                                2004       2003
--------------------------------------------------------------------------------
Revenues                                                       4,258      3,642
Net Income                                                       841        595
Earnings Per Common Share - Basic ($/share)                     6.54       4.81
Earnings Per Common Share - Diluted ($/share)                   6.46       4.75
                                                              ------------------
3.       ACCOUNTS RECEIVABLE

                                                                2004       2003
--------------------------------------------------------------------------------
Trade
    Marketing                                                  1,452      1,078
    Oil and Gas                                                  593        263
    Chemicals and Other                                           57         47
                                                              ------------------
                                                               2,102      1,388
Non-Trade                                                         49         50
                                                              ------------------
                                                               2,151      1,438
Allowance for Doubtful Receivables                               (15)       (15)
                                                              ------------------
Total Accounts Receivable                                      2,136      1,423
                                                              ==================

4.       INVENTORIES AND SUPPLIES

                                                                2004       2003
--------------------------------------------------------------------------------
Finished Products
    Marketing                                                    199        138
    Oil and Gas                                                    6         16
    Chemicals and Other                                           13         12
                                                              -----------------
                                                                 218        166
Work in Process                                                    4          6
Field Supplies                                                   129         98
                                                              -----------------
Total Inventories and Supplies                                   351        270
                                                              =================


                                       87
<PAGE>

<TABLE>
<CAPTION>
5.       PROPERTY, PLANT AND EQUIPMENT

                                                   2004                                       2003
------------------------------------------------------------------------------------------------------------------
                                            Accumulated    Net Book                    Accumulated       Net Book
                                   Cost            DD&A       Value            Cost           DD&A          Value
                               -------------------------------------  --------------------------------------------
<S>                               <C>            <C>          <C>            <C>             <C>           <C>
Oil and Gas
    Yemen                           678            506          172            656             489            167
    Yemen - Carried Interest      1,360          1,044          316          1,242           1,008            234
    Canada                        3,463          1,615        1,848          2,951           1,460          1,491
    United States                 2,249          1,037        1,212          2,153             887          1,266
    United Kingdom                3,499             16        3,483             --              --             --
    Other Countries                 535            408          127            534             410            124
    Marketing                       157             64           93            158              57            101
                               -------------------------------------  --------------------------------------------
                                 11,941          4,690        7,251          7,694           4,311          3,383
Syncrude                          1,030            155          875            821             144            677
Chemicals                           815            409          406            774             381            393
Corporate and Other                 201             90          111            168              71             97
                               -------------------------------------  --------------------------------------------

Total PP&E                       13,987          5,344        8,643          9,457           4,907          4,550
                               =====================================  ============================================
</TABLE>

The above table includes capitalized costs of $3,945 million (2003 - $630
million) relating to unproved properties and projects under construction or
development. These costs are not being depreciated, depleted or amortized. We
currently have an interest in an exploration block, offshore Nigeria, where
capitalized exploratory costs have been on our balance sheet for longer than one
year. Major capital expenditures are required before production can begin and
additional drilling efforts are underway to fully appraise the block.
Exploratory drilling costs were first capitalized in 1998 and we have
subsequently drilled a further seven successful wells on the block. We are
preparing a field development plan for the block with our partners for
submission to the Nigerian government for approval. Once we obtain this approval
and the project has been sanctioned, we will book proved reserves. Capitalized
costs relating to this exploration block as at December 31, 2004 were $77
million (2003 - $68 million).

Our 2003 depreciation, depletion, amortization and impairment expense in the
Consolidated Statement of Income includes an impairment charge of $269 million
relating to certain Canadian oil and gas properties. The impairment results from
negative reserve revisions and is largely attributable to Canadian heavy oil
properties. The revisions resulted from changes in late field-life economic
assumptions, changes in proved undeveloped reserves based on drilling results
and geological mapping, and reassessments of estimated future production
profiles.

We incurred $35 million (2003 - $20 million) related to research and development
activities. Costs of $26 million (2003 - $14 million) were recorded in other
expense on the Consolidated Statement of Income. The remaining costs have been
deferred and are included in PP&E.

                                                                2004        2003
--------------------------------------------------------------------------------
Development Costs Deferred, Beginning of Year                     6         --
    Deferred in the Year                                          9          6
    Amortized in the Year                                        --         --
                                                               -----------------
Development Costs Deferred, End of Year                          15          6
                                                               =================


                                       88
<PAGE>

6.       DERIVATIVE INSTRUMENTS AND FINANCIAL RISK MANAGEMENT

(a)      CARRYING VALUE AND ESTIMATED FAIR VALUE OF DERIVATIVE AND FINANCIAL
         INSTRUMENTS

The carrying value, fair value, and unrecognized gains or losses on our
outstanding derivatives and long-term financial assets and liabilities at
December 31 are:

<TABLE>
<CAPTION>
(Cdn$ millions)                                             2004                                       2003
---------------------------------------------------------------------------------------------------------------------
                                           Carrying      Fair    Unrecognized    Carrying      Fair     Unrecognized
                                              Value     Value     Gain/(Loss)       Value     Value      Gain/(Loss)
                                          ------------------------------------  -------------------------------------
<S>                                          <C>       <C>               <C>       <C>       <C>               <C>
Commodity Price Risk
    Non-Trading Activities
      Future Sale of Oil and Gas
        Production                               --        --              --          --        (3)             (3)
      Crude Oil Put Options                     200       200              --          --        --              --

    Trading Activities
      Crude Oil and Natural Gas                  83        83              --         101       101              --
      Future Sale of Gas Inventory               --         6               6          --       (11)            (11)

Foreign Currency Risk
    Non-Trading Activities                        7         7              --          --        (1)             (1)
    Trading Activities                           10        10              --           5         5              --
                                          ------------------------------------  -------------------------------------
      Total Derivatives                         300       306               6         106        91             (15)
                                          ====================================  =====================================

Financial Assets and Liabilities
      Long-Term Debt                         (4,259)   (4,503)           (244)     (3,089)   (3,316)           (227)
                                          ====================================  =====================================
</TABLE>

The estimated fair value of all derivative instruments is based on quoted market
prices and, if not available, on estimates from third-party brokers or dealers.
The carrying value of cash and cash equivalents, amounts receivable and
short-term obligations approximates their fair value because the instruments are
near maturity.

(b)      COMMODITY PRICE RISK MANAGEMENT

NON-TRADING ACTIVITIES

We generally sell our crude oil and natural gas under short-term market based
contracts.


FUTURE SALE OF OIL AND GAS PRODUCTION

In 2003, we entered into WTI and NYMEX gas forward contracts for a 12-month
period. These forward contracts fixed our oil and gas prices at the contract
prices for the hedged volumes, less applicable price differentials. Since actual
prices during the contract period were higher than the fixed prices we received,
our return was lower than it would have been without these contracts in place.
These contracts expired in March 2004.

CRUDE OIL PUT OPTIONS

We purchased WTI crude oil put options to manage the commodity price risk
exposure of a portion of our oil production in 2005 and 2006. These options
establish an annual average WTI floor price of US$43/bbl in 2005 and US$38 in
2006 at a cost of $144 million. The WTI crude oil put options are stated at fair
value and included in deferred charges and other assets as they settle beyond 12
months of the balance sheet date. Any change in fair value is included in
marketing and other on the Consolidated Statement of Income.

<TABLE>
<CAPTION>
                                     NOTIONAL                     AVERAGE             MARKET
                                      VOLUMES        TERM     PRICE (WTI)              VALUE
---------------------------------------------------------------------------------------------
                                     (bbls/d)                   (US$/bbl)     (Cdn$ millions)
<S>                                    <C>           <C>      <C>                     <C>
WTI Crude Oil Put Options              30,000        2005              44                 57
                                       20,000        2005              43                 33
                                       10,000        2005              41                 12
                                       30,000        2006              39                 53
                                       20,000        2006              38                 32
                                       10,000        2006              36                 13
                                                                                      -------
                                                                                         200
                                                                                      =======
</TABLE>

                                       89
<PAGE>

TRADING ACTIVITIES

CRUDE OIL AND NATURAL GAS

We enter into physical purchase and sales contracts as well as financial
commodity contracts to enhance our price realizations and lock-in our margins.
The physical and financial commodity contracts (derivative contracts) are stated
at market value. The $83 million fair value of the contracts has been recognized
in net income.

FUTURE SALE OF GAS INVENTORY

We have certain NYMEX futures contracts and swaps in place, which effectively
lock-in our margins on the future sale of our natural gas inventory in storage.
We have designated, in writing, some of these derivative contracts as cash flow
hedges of the future sale of our storage inventory. As a result, gains and
losses on these designated futures contracts and swaps are recognized in net
income when the inventory in storage is sold. The principal terms of these
outstanding contracts and the unrecognized gains and losses at December 31, 2004
are:

<TABLE>
<CAPTION>
                                        HEDGED                      AVERAGE    UNRECOGNIZED
                                       VOLUMES            MONTH       PRICE            GAIN
--------------------------------------------------------------------------------------------
                                        (mmcf)                     (US$/mcf) (Cdn$ millions)
<S>                                      <C>      <C>               <C>        <C>
NYMEX Natural Gas Futures                3,740     January 2005       6.825               2
                                         5,660    February 2005        6.53               2

NYMEX Natural Gas Fixed Price Swaps      1,000     January 2005       7.147               1
                                           500    February 2005       6.987               1
                                                                                     -------
                                                                                          6
                                                                                     =======
</TABLE>

(c)      FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT

NON-TRADING ACTIVITIES

We designate our US-dollar debt as a hedge against our net investment in
self-sustaining foreign operations. The US-dollar debt issued in November 2003
to re-finance existing designated US-dollar debt was designated as part of the
hedge in February 2004. In December 2004, we drew US$1.5 billion against term
credit facilities established for our North Sea acquisition. This amount has
been designated as a hedge of our investment in our self-sustaining foreign
operations.

The foreign exchange gains or losses related to the designated debt are included
in the cumulative foreign currency translation adjustment in shareholders'
equity. Undesignated foreign exchange gains or losses on the November 2003 debt
issues were included in marketing and other prior to the designation of this
debt as a hedging instrument in February 2004. Our net investment in
self-sustaining foreign operations and our designated US-dollar debt at December
31 are as follows:

(US$ millions)                                                2004         2003
--------------------------------------------------------------------------------
    Net Investment in Self-Sustaining Foreign Operations      3,973       1,574
    US-Dollar Debt                                            3,315       1,143
                                                             -------------------

We also have exposure to currencies other than the US dollar. A portion of our
capital spending on our Long Lake project is denominated in Euros and Japanese
Yen. A portion of our United Kingdom operating expenses and capital spending is
denominated in British Pounds and Euros. 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. At December 31, 2004, we held a
foreign currency derivative instrument that obligates us and the counterparty to
exchange principal and interest amounts. In November 2006, we will pay US$37
million and receive Cdn $50 million (see Note 7). We have recognized a gain of
$7 million for the fair value of this derivative instrument.

TRADING ACTIVITIES

Our sales and purchases of crude oil and natural gas are generally transacted in
or referenced to the US dollar, as are most of the financial commodity contracts
used by our marketing group. We enter into forward contracts to sell US dollars.
When combined with certain commodity sales contracts, either physical or
financial, these forward contracts allow us to lock-in our margins on the future
sale of crude oil and natural gas. The fair value of our US dollar forward
contracts at December 31, 2004 was $10 million (2003 - $5 million). This fair
value has been recognized in net income and settles within one year.


                                       90
<PAGE>

(d) TOTAL CARRYING VALUE OF DERIVATIVE CONTRACTS RELATED TO TRADING ACTIVITIES

Amounts related to derivative instruments held by our marketing operation are
equal to fair value as we use mark-to-market accounting, and are as follows at
December 31:

(Cdn $millions)                                               2004         2003
--------------------------------------------------------------------------------
Accounts Receivable                                            177          102
Deferred Charges and Other Assets (1)                           91           63
                                                             -------------------
    Total Derivative Contract Assets                           268          165
                                                             ===================

Accounts Payable and Accrued Liabilities                       129           34
Deferred Credits and Other Liabilities (1)                      46           25
                                                             -------------------
    Total Derivative Contract Liabilities                      175           59
                                                             ===================

    Total Derivative Contract Net Assets                        93          106
                                                             ===================

Note:
(1)  These derivative instruments settle beyond 12 months and are considered
     non-current.

(e)      INTEREST RATE RISK MANAGEMENT

We use fixed and floating rate debt to finance our operations. The floating rate
debt exposes us to changes in interest payments as interest rates fluctuate. To
manage this exposure, we maintain a combination of fixed and floating rate
borrowings and facilities. At December 31, 2004, fixed-rate borrowings comprised
56% (2003 - 100%) of our long-term debt at an effective average rate of 6.6%
(2003 - 8.2%). During the year we periodically drew on our floating rate
unsecured syndicated term credit facilities. We had no interest rate swaps
outstanding in 2004 or 2003.

(f)      CREDIT RISK MANAGEMENT

A substantial portion of our accounts receivable are with counterparties in the
energy industry and are subject to normal industry credit risk. This
concentration of risk within the energy industry is reduced because of our broad
base of domestic and international counterparties. We assess the financial
strength of our counterparties, including those involved in marketing and other
commodity arrangements, and we limit the total exposure to individual
counterparties. As well, a number of our contracts contain provisions that allow
us to demand the posting of collateral in the event downgrades to non-investment
grade credit ratings occur. Credit risk, including credit concentrations, is
routinely reported to our Risk Management Committee. We also use standard
agreements that allow for the netting of exposures associated with a single
counterparty. We believe this minimizes our overall credit risk.

7.       LONG-TERM DEBT AND SHORT-TERM BORROWINGS
                                                                  2004     2003
--------------------------------------------------------------------------------
Acquisition Credit Facilities (US$1.5 billion drawn) (a)         1,806       --
Term Credit Facilities (US$72 million drawn) (b)                    87       --
Notes, due 2004 (c)                                                 --      291
Debentures, due 2006 (d)                                            93       98
Medium Term Notes, due 2007 (e)                                    150      150
Medium Term Notes, due 2008 (f)                                    125      125
Notes, due 2013 (US$500 million) (g)                               602      646
Notes, due 2028 (US$200 million) (h)                               241      258
Notes, due 2032 (US$500 million) (i)                               602      646
Subordinated Debentures, due 2043 (US$460 million) (j)             553      594
Preferred Securities, due 2048 (US$217 million) (k)                 --      281
                                                                ----------------
                                                                 4,259    3,089
Less: Current Portion of Long-Term Debt (c) (k)                     --     (572)
                                                                ----------------
                                                                 4,259    2,517
                                                                ================

(a)      ACQUISITION CREDIT FACILITIES

Nexen has committed, unsecured, non-revolving credit facilities totalling US$2
billion. The credit facilities include a bridge facility in the amount of US$1.5
billion, which was advanced on December 1, 2004 and used to fund a portion of
the purchase price for the acquisition of EnCana (UK) Limited and a development
facility in the amount of US$500 million, which may be drawn upon to finance a
portion of our share of the costs for the development and operation of the
acquired assets.


                                       91
<PAGE>

The credit facilities provide that the bridge facility shall not exceed US$750
million by November 2005 with the balance to be repaid by May 2007. The credit
facilities also provide that the development facility be repaid by November
2007, unless this date is extended to May 2008. Optional repayments may be made
by Nexen at any time with notice. Borrowings are available as US-dollar base
rate loans, LIBOR-based loans, Canadian bankers' acceptances and Canadian prime
rate loans. Interest is payable monthly at a floating rate. During 2004, the
weighted average interest rate on the acquisition credit facilities was 3.2%.

Amounts due November 2005 with respect to the bridge facility have not been
included in current liabilities as we are able to refinance this amount with our
term credit facilities, if need be.

(b)      TERM CREDIT FACILITIES

Nexen has committed, unsecured, revolving term credit facilities totalling
$1,656 million, $410 million of which is available until 2008 and $1,246 million
until 2009. At December 31, 2004, US$72 million was drawn on these facilities.
The lenders have the option to extend the terms annually. Borrowings are
available as Canadian bankers' acceptances, LIBOR-based loans, Canadian prime
loans or US-dollar base rate loans. Interest is payable monthly at a floating
rate. During 2004, the weighted average interest rate was 3.2% (2003 - 2.0%).

(c)      NOTES, DUE 2004

During February 2004, we repaid US$225 million of notes.

(d)      DEBENTURES, DUE 2006

During November 1996, we issued $100 million of unsecured 10-year redeemable
debentures. Interest is payable semi-annually at a rate of 6.85% and the
principal is to be repaid in November 2006. In December 1996, $50 million of
this obligation was effectively converted through a currency exchange contract
with a Canadian chartered bank to a US$37 million liability bearing interest at
6.75% for the term of the debentures. We may redeem part or all of the
debentures at any time. The redemption price will be the greater of par and an
amount that provides the same yield as a Government of Canada Bond having a term
to maturity equal to the remaining term of the debentures plus 0.1%.

(e)      MEDIUM TERM NOTES, DUE 2007

During July 1997, we issued $150 million of notes. Interest is payable
semi-annually at a rate of 6.45% and the principal is to be repaid in July 2007.
We may redeem part or all of the notes at any time. The redemption price will be
the greater of par and an amount that provides the same yield as a Government of
Canada Bond having a term to maturity equal to the remaining term of the notes
plus 0.125%.

(f)      MEDIUM TERM NOTES, DUE 2008

During October 1997, we issued $125 million of notes. Interest is payable
semi-annually at a rate of 6.3% and the principal is to be repaid in June 2008.
We may redeem part or all of the notes at any time. The redemption price will be
the greater of par and an amount that provides the same yield as a Government of
Canada Bond having a term to maturity equal to the remaining term of the notes
plus 0.125%.

(g)      NOTES, DUE 2013

During November 2003, we issued US$500 million of notes. Interest is payable
semi-annually at a rate of 5.05% and the principal is to be repaid in November
2013. We may redeem part or all of the notes at any time. The redemption price
will be the greater of par and an amount that provides the same yield as a US
Treasury security having a term to maturity equal to the remaining term of the
notes plus 0.2%.

(h)      NOTES, DUE 2028

During April 1998, we issued US$200 million of notes. Interest is payable
semi-annually at a rate of 7.4% and the principal is to be repaid in May 2028.
We may redeem part or all of the notes any time. The redemption price will be
the greater of par and an amount that provides the same yield as a US Treasury
security having a term to maturity equal to the remaining term of the notes plus
0.25%.

(i)      NOTES, DUE 2032

During March 2002, we issued US$500 million of notes. Interest is payable
semi-annually at a rate of 7.875% and the principal is to be repaid in March
2032. We may redeem part or all of the notes at any time. The redemption price
will be the greater of par and an amount that provides the same yield as a US
Treasury security having a term to maturity equal to the remaining term of the
notes plus 0.375%.


                                       92
<PAGE>

(j)      SUBORDINATED DEBENTURES, DUE 2043

During November 2003, we issued US$460 million of unsecured subordinated
debentures. Interest is payable quarterly in cash at a rate of 7.35% and the
principal is to be repaid in November 2043. We may redeem part or all of the
debentures at any time on or after November 8, 2008. The redemption price is
equal to the par value of the principal amount plus any accrued and unpaid
interest to the redemption date. We may choose to redeem the principal amount
with either cash or common shares.

(k)      PREFERRED SECURITIES, DUE 2048

During March 1998, we issued US$217 million of preferred securities. The
securities were redeemed at par on February 9, 2004. Interest was payable
quarterly at a rate of 9.375%.

(l)      DEBT REPAYMENTS

------------------------------------------------------------------------
2005                                                                903
2006                                                                 93
2007                                                              1,075
2008                                                                190
2009                                                                 --
Thereafter                                                        1,998
                                                                 -------
Total Debt Repayments                                             4,259
                                                                 =======

(m)      DEBT COVENANTS

Some of our debt instruments contain covenants with respect to certain financial
ratios and our ability to grant security. At December 31, 2004, we were in
compliance with all covenants.

(n)      SHORT-TERM BORROWINGS

Nexen has unsecured operating loan facilities of approximately $349 million, of
which $100 million was drawn (US$83 million) at December 31, 2004. Interest is
payable at floating rates. During 2004, the weighted average interest rate on
our short-term borrowings was 2.9% (2003 - 2.4%).

(o)      INTEREST EXPENSE

                                                    2004       2003        2002
--------------------------------------------------------------------------------
Long-Term Debt                                       182        204        206
Other                                                 12          8          6
                                                   -----------------------------
Total                                                194        212        212
    Less: Capitalized                                (51)       (43)       (31)
                                                   -----------------------------
Total Interest Expense                               143        169        181
                                                   =============================

Capitalized interest relates to and is included as part of the cost of oil and
gas and Syncrude properties. The capitalization rates are based on our
weighted-average cost of borrowings.

8.       ASSET RETIREMENT OBLIGATIONS

Changes in carrying amounts of the asset retirement obligations associated with
our property, plant and equipment are as follows:

                                                              2004         2003
--------------------------------------------------------------------------------
Balance at Beginning of Year                                   323          390
    Obligations Assumed with Development Activities             12            6
    Obligations Assumed with Business Acquisition              134           --
    Obligations Discharged with Disposed Properties             (4)         (27)
    Expenditures Made on Asset Retirements                     (31)         (20)
    Accretion                                                   17           22
    Revisions to Estimates                                      24          (19)
    Effect of Foreign Exchange                                  (7)         (29)
                                                             -------------------
Balance at End of Year (1)                                     468          323
                                                             ===================

Note:
(1)  Obligations due within 12 months of $47 million (2003 - $18 million) have
     been included in accounts payable and accrued liabilities.


                                       93
<PAGE>

Our total estimated undiscounted asset retirement obligations amount to $770
million ($514 million - December 31, 2003). We have discounted the total
estimated asset retirement obligations using a weighted-average, credit-adjusted
risk-free rate of 5.7%. Approximately $121 million included in our asset
retirement obligations will be settled over the next five years. The remaining
obligations settle beyond five years and will be funded by future cash flows
from our operations.

We own interests in assets for which the fair value of the asset retirement
obligations cannot be reasonably determined because the assets currently have an
indeterminate life and we cannot determine when remediation activities would
take place. These assets include our interest in Syncrude's upgrader and sulphur
pile.

The estimated future recoverable reserves at Syncrude are significant and given
the long life of this asset, we are unable to determine when asset retirement
activities would take place. Furthermore, the Syncrude plant can continue to run
indefinitely with ongoing maintenance activities.

The retirement obligations for these assets will be recorded in the first year
in which the lives of the assets are determinable.

9.       SHAREHOLDERS' EQUITY

(a)      AUTHORIZED CAPITAL

Authorized share capital consists of an unlimited number of common shares of no
par value, and an unlimited number of Class A preferred shares of no par value,
issuable in series.

(b)      ISSUED COMMON SHARES AND DIVIDENDS

(thousands of shares)                                2004       2003       2002
--------------------------------------------------------------------------------
Beginning of Year                                 125,606    122,966    121,202
Issue of Common Shares for Cash:
    Exercise of Stock Options                       2,951      1,964      1,090
    Dividend Reinvestment Plan                        448        476        500
    Employee Flow-through Shares                      195        200        174
                                                 -------------------------------
End of Year                                       129,200    125,606    122,966
                                                 ===============================

Dividends per Common Share ($/share)                 0.40      0.325       0.30
                                                 ===============================

Cash Consideration (Cdn$ millions)
    Exercise of Stock Options                          93         50        27
    Dividend Reinvestment Plan                         21         15        17
    Employee Flow-through Shares                       10          8         7
                                                 -------------------------------
                                                      124         73        51
                                                 ===============================

At December 31, 2004, there were 689,937 common shares (2003 - 1,307,305; 2002 -
1,783,968) reserved for issuance under the Dividend Reinvestment Plan.

(c)      STOCK OPTIONS

In May 2004, our shareholders approved the modification of our stock option plan
to a tandem option plan by including a cash feature. The tandem options give the
holders a right to either purchase common shares at the exercise price or to
receive cash payments equal to the excess of the market value of the common
shares over the exercise price.

Similar to our stock appreciation rights, we use the intrinsic-value method to
recognize compensation expense associated with our tandem options. Obligations
are accrued on a graded vesting basis and represent the difference between the
market value of our common shares and the exercise price of the options. The
obligations are revalued each reporting period based on the change in the market
value of our common shares and the number of graded vested options outstanding.

Upon modification of the stock option plan, we were required to recognize an
obligation for our tandem options. This obligation represented the difference
between the market value of our common shares and the weighted-average exercise
price of the options. As a result, we recognized an obligation of $85 million
for the graded vested portion of the 6.3 million outstanding options on June 30,
2004. In the second quarter, a one-time, non-cash charge of $82 million was
included in general and administrative expense, net of $3 million previously
expensed in respect of our original stock options.


                                       94
<PAGE>

Following the introduction of the AMERICAN JOB CREATION ACT OF 2004 in the US,
stock options awarded to our US employees on or after December 1, 2004 do not
include a tandem option cash feature. We use the fair-value method to recognize
compensation expense associated with these options. The expense is recognized
over the vesting period of the options with a corresponding increase to
contributed surplus. This resulted in compensation expense in 2004 of $0.1
million which was included in general and administrative expense.

We have granted options to purchase common shares to directors, officers and
employees. Each option permits the holder to purchase one Nexen common share at
the stated exercise price. Options granted prior to February 2001 vest over 4
years and are exercisable on a cumulative basis over 10 years. Options granted
after February 2001 vest over 3 years and are exercisable on a cumulative basis
over 5 years. At the time of grant, the exercise price equals the market price.
The following options have been granted:

<TABLE>
<CAPTION>
                                                             2004                        2003                     2002
                                                  ----------------------------------------------------------------------------
                                                                  Weighted                 Weighted                  Weighted
                                                                   Average                  Average                   Average
                                                                  Exercise                 Exercise                  Exercise
                                                      Options        Price      Options       Price      Options        Price
------------------------------------------------------------------------------------------------------------------------------
                                                  (thousands)    ($/option)  (thousands)  ($/option)  (thousands)   ($/option)
<S>                                                   <C>          <C>          <C>        <C>           <C>         <C>
BALANCE AT BEGINNING OF YEAR                            9,203           34        9,476          30        8,831           30
Granted                                                 2,112           51        1,877          44        1,788           31
Exercised for stock                                    (2,951)          30       (1,964)         28       (1,090)          25
Surrendered for cash                                     (144)          34           --          --           --           --
Forfeited                                                 (82)          33         (186)         32          (53)          30
                                                  ----------------------------------------------------------------------------
BALANCE AT END OF YEAR                                  8,138           39        9,203          34        9,476           30
                                                  ============================================================================

OPTIONS EXERCISABLE AT END OF YEAR                      4,227           34        5,067          30        5,113           29
                                                  ----------------------------------------------------------------------------

COMMON SHARES RESERVED FOR ISSUANCE
   UNDER THE STOCK OPTION PLAN                          9,586                     9,788                    9,760
                                                  ----------------------------------------------------------------------------
</TABLE>

The range of exercise prices of options outstanding and exercisable at December
31, 2004 is as follows:

<TABLE>
<CAPTION>
                                                                   OUTSTANDING OPTIONS                   EXERCISABLE OPTIONS
------------------------------------------------------------------------------------------------------------------------------
                                                                           Weighted    Weighted                      Weighted
                                                                            Average     Average                       Average
                                                             Number of     Exercise    Years to       Number of      Exercise
                                                               Options        Price      Expiry         Options         Price
                                                          --------------------------------------    ------------ -------------
                                                           (thousands)    ($/option)     (years)     (thousands)    ($/option)
<S>                                                          <C>           <C>         <C>            <C>            <C>
$15.00 to $19.99                                                  132            18           4             132           18
$20.00 to $24.99                                                  182            24           2             182           24
$25.00 to $29.99                                                  768            27           4             641           27
$30.00 to $34.99                                                1,772            33           3           1,326           33
$35.00 to $39.99                                                1,330            36           6           1,324           36
$40.00 to $44.99                                                1,850            43           4             622           43
$45.00 to $49.99                                                   25            48           4              --           --
$50.00 to $54.99                                                2,079            51           5              --           --
                                                          --------------------------------------    --------------------------
   Total options                                                8,138                                     4,227
                                                          =============                             ============
</TABLE>

In previous periods, we estimated the fair value of stock options issued using
the Generalized Black-Scholes option pricing model under the following
assumptions:

<TABLE>
<CAPTION>
                                                                                                           2003          2002
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                       <C>            <C>
Weighted-Average Fair Value ($/option)                                                                    10.10          9.08
Risk-Free Interest Rate (%)                                                                                 3.6           3.6
Estimated Hold Period Prior to Exercise (years)                                                               3             3
Volatility in the Price of Nexen's Common Shares (%)                                                         30            35
Dividends per Common Share ($/share)                                                                       0.40          0.30
                                                                                                    --------------------------
</TABLE>

                                       95
<PAGE>

The following shows pro forma net income and earnings per common share had we
applied the fair-value method to account for all stock options outstanding that
were granted up to December 31, 2002. Stock options granted after that date have
been expensed as general and administrative costs.

<TABLE>
<CAPTION>
                                                                                                            2003         2002
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                         <C>          <C>
Fair Value of Stock Options Granted                                                                           25           22
Less: Fair Value of Stock Options Expensed                                                                    (1)          --
                                                                                                     -------------------------
                                                                                                              24           22
Net Income Attributable to Common Shareholders
    As Reported                                                                                              578          409
                                                                                                     -------------------------
    Pro Forma                                                                                                554          387
                                                                                                     =========================

Earnings Per Common Share ($/share)
    Basic as Reported                                                                                       4.67         3.34
                                                                                                     =========================
    Pro Forma                                                                                               4.48         3.16
                                                                                                     =========================

    Diluted as Reported                                                                                     4.63         3.30
                                                                                                     =========================
    Pro Forma                                                                                               4.44         3.13
                                                                                                     =========================
</TABLE>

(d)      STOCK APPRECIATION RIGHTS

Under our stock appreciation rights (StARs) plan established in 2001, employees
are entitled to cash payments equal to the excess of the market price of the
common shares over the exercise price of the right. The vesting period and other
terms of the plan are similar to the stock option plan. The total rights granted
and outstanding at any time cannot exceed 10% of Nexen's total outstanding
common shares. At the time of grant, the exercise price equals the market price.
The following stock appreciation rights have been granted:

<TABLE>
<CAPTION>
                                                              2004                       2003                     2002
                                                  ------------------------- ------------------------ -------------------------
                                                                  Weighted                 Weighted                  Weighted
                                                                   Average                  Average                   Average
                                                                  Exercise                 Exercise                  Exercise
                                                        StARs        Price        StARs       Price          StARs      Price
------------------------------------------------------------------------------------------------------------------------------
                                                   (thousands)   ($/right)   (thousands)   ($/right)    (thousands)  ($/right)
<S>                                                     <C>       <C>             <C>       <C>              <C>      <C>
BALANCE AT BEGINNING OF YEAR                            2,404           37        1,812          33            915         31
Granted                                                 1,304           51        1,017          43            908         34
Exercised for cash                                       (433)          33         (363)         32             (3)        31
Forfeited                                                 (57)          37          (62)         32             (8)        31
                                                  ---------------------------------------------------------------------------
BALANCE AT END OF YEAR                                  3,218           43        2,404          37          1,812         33
                                                  ===========================================================================

RIGHTS EXERCISABLE AT END OF YEAR                       1,011           36          495          33            306         31
                                                  ---------------------------------------------------------------------------
</TABLE>

The range of exercise prices of stock appreciation rights outstanding and
exercisable at December 31, 2004 is as follows:

<TABLE>
<CAPTION>
                                                                    Outstanding StARs                     Exercisable StARs
------------------------------------------------------------------------------------------------------------------------------
                                                                           Weighted    Weighted                      Weighted
                                                                            Average     Average                       Average
                                                             Number of     Exercise    Years to       Number of      Exercise
                                                                 StARs        Price      Expiry           StARs         Price
                                                          --------------------------------------    --------------------------
                                                            (thousands)    ($/right)     (years)     (thousands)     ($/right)
<S>                                                          <C>            <C>         <C>           <C>            <C>
$30.00 to $34.99                                                  999            33           3             714           33
$35.00 to $39.99                                                    5            38           3               2           38
$40.00 to $44.99                                                  909            44           4             295           44
$45.00 to $49.99                                                   14            48           4              --           --
$50.00 to $54.99                                                1,290            51           5              --           --
$55.00 to $59.99                                                    1            55           4              --           --
                                                          --------------------------------------    --------------------------
   Total StARs                                                  3,218                                     1,011
                                                          =============                             ============
</TABLE>

                                       96
<PAGE>

10.      EARNINGS PER COMMON SHARE

We calculate basic earnings per common share from continuing operations using
net income from continuing operations divided by the weighted-average number of
common shares outstanding. We calculate basic earnings per common share using
net income and the weighted-average number of common shares outstanding. We
calculate diluted earnings per common share from continuing operations and
diluted earnings per common share in the same manner as basic, except we use the
weighted-average number of diluted common shares outstanding in the denominator.

<TABLE>
<CAPTION>
(millions of shares)                                                                           2004      2003         2002
---------------------------------------------------------------------------------------------------------------------------
<S>                                                                                           <C>       <C>          <C>
Weighted-average number of common shares outstanding                                          128.6     123.8        122.4
Shares issuable pursuant to stock options                                                       6.5       6.2          8.1
Shares to be purchased from proceeds of stock options                                          (4.8)     (5.1)        (6.7)
                                                                                         ----------------------------------
Weighted-average number of diluted common shares outstanding                                  130.3     124.9        123.8
                                                                                         ==================================
</TABLE>

In calculating the weighted-average number of diluted common shares outstanding
for the year ended December 31, 2004, we excluded 174,100 options (2003 -
2,817,023; 2002 - 46,167), because their exercise price was greater than the
annual average common share market price in those periods. During the last three
years, outstanding stock options were the only potential dilutive instruments.

11.      DISCONTINUED OPERATIONS

During the fourth quarter of 2004, we concluded production from our Buffalo
field, offshore Australia as anticipated. The results of our operations in
Australia have been treated as discontinued operations, as we have no plans to
continue operations in the country. Scheduled remediation and abandonment of the
field has commenced and is expected to be complete by the end of 2005. We expect
no gain or loss on abandonment as the expected asset retirement obligations have
been fully accrued.

During the third quarter of 2003, we sold certain non-core conventional light
oil properties in southeast Saskatchewan in Canada. Net proceeds were $268
million and there was no gain or loss on the sale.

The results of operations from these properties in Australia and Canada are
detailed below and shown as discontinued operations in our Consolidated
Statement of Income.

<TABLE>
<CAPTION>
                                             2004                     2003                                    2002
                                         AUSTRALIA     AUSTRALIA      CANADA      TOTAL        AUSTRALIA      CANADA     TOTAL
------------------------------------------------------------------------------------------------------------------------------
<S>                                      <C>           <C>            <C>         <C>          <C>            <C>        <C>
Revenues
   Net Sales                                    75           64          66        130              165         100       265
Expenses
   Operating                                    53           30          16         46               50          25        75
   General and Administration                   --           --          --         --                1          --         1
   Depreciation, Depletion,
    Amortization and Impairment                  9           22          20         42               53          35        88
   Exploration                                  --            1           1          2                3           8        11
                                        ----------    ---------------------------------       --------------------------------
Income before Income Taxes                      13           11          29         40               58          32        90
   Current Income Taxes                         --           (4)         --         (4)              16          --        16
   Future Income Taxes                          --            2          14         16                3          18        21
                                        ----------    ---------------------------------       --------------------------------
Net Income                                      13           13          15         28               39          14        53
                                        ==========    =================================       ================================

Earnings per Common Share ($/share)
   Basic (Note 10)                            0.10         0.10        0.12       0.22             0.32        0.11      0.43
                                        ==========    =================================       ================================
   Diluted (Note 10)                          0.10         0.10        0.12       0.22             0.32        0.11      0.43
                                        ==========    =================================       ================================
</TABLE>


                                       97
<PAGE>

Assets and liabilities on the Consolidated Balance Sheet include the following
amounts for our discontinued operations in Australia. There are no assets and
liabilities associated with our Saskatchewan properties on our Consolidated
Balance Sheet at December 31, 2004 and 2003.

<TABLE>
<CAPTION>
                                                                                                 DECEMBER 31     DECEMBER 31
                                                                                                        2004            2003
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                              <C>             <C>
Cash and Cash Equivalents                                                                                  1               2
Accounts Receivable                                                                                        8               8
Inventories and Supplies                                                                                  --              13
Other Current Assets                                                                                       1               1
Property, Plant and Equipment                                                                             --               4
Accounts Payable and Accrued Liabilities                                                                  25               1
Asset Retirement Obligations                                                                              --              34
                                                                                              --------------------------------
</TABLE>

<TABLE>
<CAPTION>
12.      COMMITMENTS, CONTINGENCIES AND GUARANTEES

                                               2005      2006          2007            2008             2009      THEREAFTER
------------------------------------------------------------------------------------------------------------------------------
<S>                                            <C>       <C>           <C>             <C>              <C>       <C>
Operating leases                                 31        27            26              23               22             119
Transportation commitments                      366       126            74              51               33             130
                                       ---------------------------------------------------------------------------------------
                                                397       153           100              74               55             249
                                       =======================================================================================
</TABLE>

We have a number of lawsuits and claims pending including income tax
reassessments (see Note 15), for which we currently cannot determine the
ultimate result. We record costs as they are incurred or become determinable. We
believe the resolution of these matters would not have a material adverse effect
on our liquidity, consolidated financial position or results of operations.

During 2004, total rental expense was $45 million (2003 - $49 million; 2002 -
$47 million).

From time to time we enter into certain types of contracts that require us to
indemnify parties against possible third party claims particularly when these
contracts relate to divestiture transactions. On occasion we may provide routine
indemnifications. The terms of such obligations vary and generally, a maximum is
not explicitly stated. Because the obligations in these agreements are often not
explicitly stated, the overall maximum amount of the obligations cannot be
reasonably estimated. Historically, we have not been obligated to make
significant payments for these obligations. 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 that payments, if
any, related to such matters would not have a material adverse effect on our
liquidity, financial condition or results of operations.

13.      PENSION AND OTHER POST RETIREMENT BENEFITS

Nexen has contributory and non-contributory defined benefit and defined
contribution pension plans, which together cover substantially all employees.
Syncrude has a defined benefit plan for its employees, and we disclose only our
share of this plan. Under these defined benefit plans, we provide benefits to
retirees based on their length of service and final average earnings. Benefits
paid out of Nexen's defined benefit plan are indexed to 75% of the annual rate
of inflation.


                                       98
<PAGE>

(a)      DEFINED BENEFIT PENSION PLANS

The cost of pension benefits earned by employees is determined using the
projected-benefit method prorated on employment services and is expensed as
services are rendered. We fund these plans according to federal and provincial
government regulations by contributing to trust funds administered by an
independent trustee. These funds are invested primarily in equities and bonds.

<TABLE>
<CAPTION>
                                                               2004                      2003
--------------------------------------------------------------------------------------------------------
Change in Projected Benefit Obligation (PBO)          Nexen          Syncrude     Nexen        Syncrude
                                                      -----------------------     ----------------------
<S>                                                   <C>            <C>          <C>          <C>
  Beginning of Year                                     192                79       164              68
  Service Cost                                            8                 3         7               3
  Interest Cost                                          12                 5        11               4
  Plan Participants' Contributions                        2                --         2              --
  Actuarial Loss                                         10                 7        14               6
  Benefits Paid                                          (7)               (3)       (6)             (2)
                                                      ------------------------    ----------------------
  End of Year (1)                                       217                91       192              79
                                                      ========================    ======================

Change in Fair Value of Plan Assets
  Beginning of Year                                     154                44       127              37
  Actual Return on Plan Assets                           16                 5        15               7
  Employer's Contribution                                 6                 4        16               2
  Plan Participants' Contributions                        2                --         2              --
  Benefits Paid                                          (7)               (3)       (6)             (2)
                                                      ------------------------    ----------------------
  End of Year                                           171                50       154              44
                                                      ========================    ======================

Reconciliation of Funded Status
  Funded Status (2)                                     (46)              (41)      (38)            (35)
  Unamortized Transitional Obligation                     1                --         1               -
  Unamortized Prior Service Costs                         4                --         5               -
  Unamortized Net Actuarial Loss                         30                30        26              25
                                                      ------------------------    ----------------------
Pension Liability                                       (11)              (11)       (6)            (10)
                                                      ========================    ======================

Pension Liability Recognized:
  Deferred Charges and Other Assets                      13                --        15              --
  Accounts Payable and Accrued Liabilities               (1)               (2)       (1)             (2)
  Other Deferred Credits and Liabilities                (23)               (9)      (20)             (8)
                                                      ------------------------    ----------------------
Pension Liability                                       (11)              (11)       (6)            (10)
                                                      ========================    ======================

Assumptions (%)
  ACCRUED BENEFIT OBLIGATION AT DECEMBER 31
  Discount Rate                                         6.00             5.75      6.25            6.00
  Long-Term Rate of Employee Compensation
    Increase                                            4.00             4.00      4.00            4.00
                                                      ------------------------    ----------------------
  BENEFIT COST FOR YEAR ENDED DECEMBER 31 (3)
  Discount Rate                                         6.25             6.00      6.75            6.50
  Long-Term Rate of Employee Compensation
    Increase                                            4.00             4.00      4.00            4.00
  Long-Term Annual Rate of Return on Plan Assets (4)    7.00             8.50      7.00            9.00
                                                      ------------------------    ----------------------
</TABLE>

Notes:
(1)  Nexen's employee pension plan's accumulated benefit obligation (the
     projected benefit obligation excluding future salary increases) was $159
     million at December 31, 2004. Nexen's supplemental pension plan's
     accumulated benefit obligation was $23 million at December 31, 2004.
     Nexen's share of Syncrude's employee pension plan's accumulated benefit
     obligation was $67 million at December 31, 2004.

(2)  Includes unfunded obligations for supplemental benefits to the extent that
     the benefit is limited by statutory guidelines. At December 31, 2004, the
     PBO for supplemental benefits was $34 million (2003 - $29 million).

(3)  The assumptions have been used to calculate the recognized expense for
     Nexen. There were no changes to the assumptions between the measurement
     date and December 31, 2004. Syncrude's measurement date was December 31,
     2004.

(4)  The long-term annual rate of return on plan assets assumption is based on a
     mix of historical market returns for debt and equity securities.

                                       99
<PAGE>

<TABLE>
<CAPTION>
NET PENSION EXPENSE RECOGNIZED UNDER OUR DEFINED BENEFIT PENSION PLANS

                                                                                         2004          2003           2002
---------------------------------------------------------------------------------------------------------------------------
<S>                                                                                      <C>           <C>            <C>
Nexen
    Cost of Benefits Earned by Employees                                                    8             7             7
    Interest Cost on Benefits Earned                                                       12            11            10
    Actual Return on Plan Assets                                                          (16)          (15)            7
    Actuarial (Gains) Losses                                                               10            14           (11)
                                                                                   ----------------------------------------
    Pension Expense Before Adjustments for the Long-Term Nature of
      Employee Future Benefit Costs                                                        14            17            13
    Difference Between Actual and Expected Return                                           5             7           (16)
    Difference Between Actual and Recognized Actuarial Gains (Losses)                     (10)          (15)           10
    Difference Between Actual and Recognized Past Service Costs                             1             1             1
                                                                                   ----------------------------------------
      Net Pension Expense                                                                  10            10             8
                                                                                   ----------------------------------------

Syncrude
    Cost of Benefits Earned by Employees                                                    3             3             3
    Interest Cost on Benefits Earned                                                        5             4             4
    Actual Return on Plan Assets                                                           (5)           (7)            3
    Actuarial (Gains) Losses                                                                7             6            --
                                                                                   ----------------------------------------
    Pension Expense Before Adjustments for the Long-Term Nature of
      Employee Future Benefit Costs                                                        10             6            10
    Difference Between Actual and Expected Return                                           1             4            (7)
    Difference Between Actual and Recognized Actuarial Gains (Losses)                      (6)           (5)            1
    Difference Between Actual and Recognized Past Service Costs                            --            --            --
                                                                                   ----------------------------------------
      Net Pension Expense                                                                   5             5             4
                                                                                   ----------------------------------------
Total                                                                                      15            15            12
                                                                                   ========================================
</TABLE>

(b)      PLAN ASSET ALLOCATION AT DECEMBER 31

Our investment goal for the assets in our defined benefit pension plan is to
preserve capital and earn a long-term rate of return on assets, net of all
management expenses, in excess of the inflation rate. Investment funds are
managed by external fund managers based on policies mandated by our Board of
Directors and Pension Committee. Nexen's investment strategy is to diversify
plan assets between debt and equity securities of Canadian and non-Canadian
corporations, that are traded on recognized stock exchanges. A fund's market
value may not exceed a maximum in any one issuer at the time of purchase, as set
out by our investment policy provided to fund managers. Allowable and prohibited
investment types are also prescribed in Nexen's investment policy.

Syncrude's pension plan is governed and administered separately from ours.
Syncrude's investment assets are subject to a similar investment goal, policy
and strategy.

<TABLE>
<CAPTION>
                                                                                     EXPECTED
(%)                                                                                      2005           2004             2003
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                       <C>            <C>              <C>
Nexen
    Equity Securities                                                                      60             60               52
    Debt Securities                                                                        40             40               40
    Real Estate                                                                            --             --               --
    Other                                                                                  --             --                8
                                                                                   -------------------------------------------
Total                                                                                     100            100              100
                                                                                   ===========================================

Syncrude
    Equity Securities                                                                      70             70               72
    Debt Securities                                                                        30             30               28
    Real Estate                                                                            --             --               --
    Other                                                                                  --             --               --
                                                                                   -------------------------------------------
Total                                                                                     100            100              100
                                                                                   ===========================================
</TABLE>


                                      100
<PAGE>

(c)      DEFINED CONTRIBUTION PENSION PLANS

Under these plans, pension benefits are based on plan contributions. During
2004, Canadian pension expense for these plans was $4 million (2003 - $4
million; 2002 - $3 million). During 2004, US pension expense for these plans was
$3 million (2003 - $3 million; 2002 - $3 million).

(d)      POST-RETIREMENT BENEFITS

Nexen provides certain post-retirement benefits, including group life and
supplemental health insurance, to eligible employees and their dependents. These
costs are fully accrued as compensation in the period employees work; however,
these future obligations are not funded. The present value of Nexen employees'
future post retirement benefits in 2004 was $5 million (2003 - $5 million).
Nexen's share of post-retirement and post-employment benefits related to
Syncrude in 2004 was $7 million (2003 - $6 million).

(e)      EMPLOYER FUNDING CONTRIBUTIONS AND BENEFIT PAYMENTS

Canadian regulators have prescribed funding requirements for our defined benefit
plans. Our funding contributions over the last three years have met these
requirements and also included additional discretionary contributions permitted
by law. For our defined contribution plans, we always match the employee
contribution and no further obligation exists. Our funding contributions for the
defined benefit plans are:

<TABLE>
<CAPTION>
                                                                                     EXPECTED
                                                                                         2005           2004             2003
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                      <C>            <C>              <C>
Defined Benefit Contributions
    Nexen                                                                                   1              6              16
    Syncrude                                                                                5              4               2
                                                                                  --------------------------------------------
Total Funding Contributions                                                                 6             10              18
                                                                                  ============================================
</TABLE>

Our most recent funding valuation was prepared as of June 30, 2004. Our next
funding valuation is required by June 30, 2007. Syncrude's most recent funding
valuation was prepared as of January 1, 2004. Syncrude's next funding valuation
is January 1, 2007.

Our total benefit payments in 2004 were $7 million (2003 - $6 million). Our
share of Syncrude's total benefit payments in 2004 was $3 million (2003 - $2
million). Our estimated future payments are as follows:

<TABLE>
<CAPTION>
                                                                           DEFINED BENEFIT                   OTHER
------------------------------------------------------------------------------------------------------------------------------
                                                                           Nexen     Syncrude          Nexen         Syncrude
                                                                     ---------------------------------------------------------
<S>                                                                        <C>       <C>               <C>           <C>
2005                                                                           8            3              1               --
2006                                                                           8            3              1               --
2007                                                                           9            3              1               --
2008                                                                          10            4              1               --
2009                                                                          10            4              2               --
2010 - 2014                                                                   66           26             12                2
                                                                     ---------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
14.      MARKETING AND OTHER

                                                                                         2004           2003             2002
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                       <C>            <C>             <C>
Marketing Revenue, Net                                                                    623            568             496
Unrealized Gains on Crude Oil Put Options                                                  56             --              --
Interest                                                                                   12              9               7
Foreign Exchange Gains (Losses)                                                           (13)             6              (3)
Gains (Losses) on Disposition of Assets (1)                                                24             --              (8)
Other (2)                                                                                  27             27               4
                                                                                     ----------------------- -----------------
     Total Marketing and Other                                                            729            610             496
                                                                                     =========================================
</TABLE>

Notes:
(1)  In 2004, gains on disposition of assets resulted from the sale of minor oil
     and gas assets by our Canadian oil and gas business. 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.

(2)  In 2004, other includes $10 million (2003 - $12 million) of business
     interruption proceeds received from our insurers. The proceeds result from
     damage sustained in the Gulf of Mexico during tropical storm Isidore and
     Hurricane Lili in the third and fourth quarters of 2002.


                                      101
<PAGE>

15.      INCOME TAXES

<TABLE>
<CAPTION>
(a)      TEMPORARY DIFFERENCES
                                                                       2004                                2003
------------------------------------------------------------------------------------------------------------------------------
                                                                 Future            Future              Future          Future
                                                             Income Tax        Income Tax          Income Tax      Income Tax
                                                                 Assets       Liabilities              Assets     Liabilities
                                                        ----------------------------------    --------------------------------
<S>                                                          <C>              <C>                  <C>            <C>
Property, Plant and Equipment, Net                                   31             1,960                  26             519
Tax Losses Carried Forward                                          277                --                  69              --
Deferred Income                                                      --               171                  --             200
Recoverable Taxes                                                    25                --                  13              --
Other                                                                --                --                  --               1
                                                        ----------------------------------    --------------------------------
                                                                    333             2,131                 108             720
                                                        ==================================    ================================
</TABLE>

<TABLE>
<CAPTION>
(b)      CANADIAN AND FOREIGN INCOME TAXES
                                                                                       2004             2003             2002
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                   <C>              <C>               <C>
 Income from Continuing Operations before Income Taxes:
      Canadian                                                                          144            (265)               36
      Foreign                                                                         1,003             956               483
                                                                                   -------------------------------------------
                                                                                      1,147             691               519
                                                                                   ===========================================
 Provision for Income Taxes:
    Current
      Canadian                                                                            6               5                 4
      Foreign                                                                           242             209               203
                                                                                   -------------------------------------------
                                                                                        248             214               207
                                                                                   -------------------------------------------
    Future
      Canadian                                                                           47            (136)               (8)
      Foreign                                                                            72              63               (36)
                                                                                   -------------------------------------------
                                                                                        119             (73)              (44)
                                                                                   -------------------------------------------
        Total Provision for Income Taxes                                                367             141               163
                                                                                   ===========================================
</TABLE>

The Canadian and foreign components of the provision for income taxes are based
on the jurisdiction in which income is taxed. Foreign taxes relate mainly to
Yemen and the United States and include Yemen cash taxes of $227 million (2003 -
$201 million; 2002 - $207 million).

<TABLE>
<CAPTION>
(c) RECONCILIATION OF EFFECTIVE TAX RATE TO THE CANADIAN FEDERAL TAX RATE

                                                                                       2004             2003              2002
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                    <C>              <C>               <C>
Income before Income Taxes
    From Continuing Operations                                                         1,147             691              519
                                                                                    ==========================================

Provision for Income Taxes Computed at the Canadian Statutory Rate                       396             256              205
Add (Deduct) the Tax Effect of:
    Royalties and Rentals to Provincial Governments                                       37              44               45
    Resource Allowance and Provincial Tax Rebates                                        (42)            (50)             (60)
    Lower Tax Rates on Foreign Operations                                                (22)            (48)             (32)
    Additional Canadian Tax on Canadian Resource Income                                   11              11                7
    Lower Tax Rates on Capital Gains                                                      --              --               (6)
    Federal and Provincial Capital Tax                                                     6               4                4
    Revaluation of Future Income Tax Liabilities for Reductions in Statutory Rates       (15)            (76)              (1)
    Other                                                                                 (4)             --                1
                                                                                    ------------------------------------------
Provision for Income Taxes                                                               367             141              163
                                                                                    ==========================================
</TABLE>

During the last three years, the federal and some provincial governments in
Canada reduced statutory income tax rates. In 2004, this reduced our liability
and provision for future income taxes by $15 million (2003 - $76 million; 2002 -
$1 million).


                                      102
<PAGE>

(d)      AVAILABLE UNUSED TAX LOSSES AND TAX CONTINGENCIES

At December 31, 2004, we had unused tax losses totalling $702 million mostly
from our UK operations. At December 31, 2003, we had unused tax losses totalling
$195 million mostly from our US operations.

Nexen's income tax filings are subject to audit by taxation authorities. There
are audits in progress and items under review, some that may increase our tax
liability. In addition, we have filed notices of objection with respect to
certain issues. While the results of these items cannot be ascertained at this
time, we believe we have an adequate provision for income taxes based on
available information.

At the time of acquisition, Wascana had outstanding taxation issues in dispute
from prior taxation years. Wascana disagreed with issues raised and has filed
notices of objection. The value of the tax pools acquired at the time of
acquisition reflected our evaluation of the potential impact of these issues.

16.      CASH FLOWS

<TABLE>
<CAPTION>
(a) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH
                                                                                       2004             2003             2002
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                    <C>              <C>              <C>
Depreciation, Depletion, Amortization and Impairment                                    744              995              632
Stock Based Compensation                                                                 74                4               --
Loss (Gain) on Disposition of Assets                                                    (24)              --                8
Future Income Taxes                                                                     119              (73)             (44)
Unrealized Gains on Crude Oil Put Options                                               (56)              --               --
Non-Cash Items included in Discontinued Operations                                        9               60              120
Unamortized Issue Costs on Preferred Securities Redemption                               11               28               --
Other                                                                                    26                4                8
                                                                                   -------------------------------------------
                                                                                        903            1,018              724
                                                                                   ===========================================
</TABLE>

<TABLE>
<CAPTION>
(b)      CHANGES IN NON-CASH WORKING CAPITAL
                                                                                       2004             2003             2002
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                    <C>              <C>              <C>
Accounts Receivable                                                                    (454)            (488)            (388)
Inventories and Supplies                                                               (106)             (45)             (73)
Other Current Assets                                                                     44              (59)              (6)
Accounts Payable and Accrued Liabilities                                                650              242              411
Other                                                                                   (12)              12               17
                                                                                   -------------------------------------------
Total Change in Non-Cash Working Capital                                                122             (338)             (39)
                                                                                   ===========================================
Relating to:
    Operating Activities                                                               (122)            (320)             (46)
    Investing Activities                                                                244              (18)               7
                                                                                   -------------------------------------------
Total Change in Non-Cash Working Capital                                                122             (338)             (39)
                                                                                   ===========================================
</TABLE>

<TABLE>
<CAPTION>
(c)      OTHER CASH FLOW INFORMATION
                                                                                        2004            2003             2002
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                     <C>              <C>              <C>
Interest Paid                                                                           190              197              189
Income Taxes Paid                                                                       249              211              238
                                                                                   -------------------------------------------
</TABLE>

In 2004, other operating activity cash outflows include $144 million for the
purchase of crude oil put options.

                                      103
<PAGE>

<TABLE>
<CAPTION>
17.      DEFERRED CHARGES AND OTHER ASSETS
                                                                                                        2004             2003
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                     <C>              <C>
Crude Oil Put Options (Note 6)                                                                           200               --
Long-Term Marketing Derivative Contracts (Note 6)                                                         91               63
Defined Benefit Pension Plan Asset (Note 13)                                                              13               15
Deferred Financing Costs                                                                                  67               62
Other                                                                                                     58               24
                                                                                             ---------------------------------
                                                                                                         429              164
                                                                                             =================================
</TABLE>

18.      OPERATING SEGMENTS AND RELATED INFORMATION

Nexen has the following operating segments in various industries and geographic
locations:

OIL AND GAS: We explore for, develop and produce crude oil, natural gas and
related products around the world. We manage our operations to reflect
differences in the regulatory environments and risk factors for each country.
Our core operations are onshore in Yemen and Canada, and offshore in the US Gulf
of Mexico and the UK North Sea. Our other operations are primarily offshore West
Africa and in Colombia. Oil and gas also includes our marketing operations.
Marketing sells our own crude oil and natural gas, markets third party crude oil
and natural gas and engages in energy trading.

SYNCRUDE: We own 7.23% of the Syncrude Joint Venture, which develops and
produces synthetic crude oil from mining bitumen in the oil sands in northern
Alberta, Canada.

CHEMICALS: We manufacture, market and distribute industrial chemicals,
principally sodium chlorate, chlorine, acid and caustic soda. We produce sodium
chlorate at five facilities in Canada and one in Brazil. We produce chlorine,
acid and caustic soda at chlor-alkali facilities in Canada and Brazil.

The accounting policies of our operating segments are the same as those
described in Note 1. Net income of our operating segments excludes interest
income, interest expense, unallocated corporate expenses and foreign exchange
gains and losses. Identifiable assets are those used in the operations of the
segments.


                                      104
<PAGE>

<TABLE>
<CAPTION>
2004 OPERATING AND GEOGRAPHIC SEGMENTS
                                                                                                           CORPORATE
                                                                                                                 AND
(Cdn$ millions)                                    OIL AND GAS                        SYNCRUDE(1) CHEMICALS    OTHER   TOTAL
------------------------------------------------------------------------------------------------------------------------------
                                                                  Other
                                                                Countries
                              Yemen   Canada      US     UK (2)     (3)    Marketing
                              ------------------------------------------------------
<S>                           <C>     <C>        <C>     <C>    <C>        <C>        <C>         <C>            <C>    <C>
Net Sales (4)                    921     622     811      36         73         14         321         378 (5)    --    3,176
Marketing and Other                5      28      11      --          2        623          --           5        55(6)   729
                              ------------------------------------------------------------------------------------------------
Total Revenues                   926     650     822      36         75        637         321         383        55    3,905
Less: Expenses
Operating                        109     156     106       6          7         16         125         237        --      762
Depreciation, Depletion,
 Amortization and Impairment     169     198     258      18         18         10          18          37        18      744
Transportation and Other           5      15      --      --         --        466          12          41        25      564
General and Administrative         4      42      30      --         47         58           1          28        89      299
Exploration                        2      21     138       3         82 (7)     --          --          --        --      246
Interest                          --      --      --      --         --         --          --          --       143      143
                              ------------------------------------------------------------------------------------------------
Income (Loss) from
 Continuing Operations
  before Income Taxes            637     218     290       9        (79)        87         165          40      (220)   1,147
Less: Provision for (Recovery
 of) Income Taxes (8)            222      78     104       4          1         28          47          13      (130)     367
                              ------------------------------------------------------------------------------------------------
Net Income (Loss) from
 Continuing Operations           415     140     186       5        (80)        59         118          27       (90)     780
Add: Net Income from
 Discontinued Operations          --      --      --       13 (9)    --         --          --          --        --       13
                              ------------------------------------------------------------------------------------------------
Net Income (Loss)                415     140     186       5        (67)        59         118          27       (90)     793
                              ================================================================================================

Identifiable Assets              564   1,979   1,359   4,446        218      2,030 (10)    912         497       378   12,383
                              ================================================================================================

Capital Expenditures
 Development and Other           267     491     267      53         24          4         214          58        33    1,411
 Exploration                      19      46     133       4         64         --          --          --        --      266
 Proved Property Acquisitions     --       4      --      --         --         --          --          --        --        4
                              ------------------------------------------------------------------------------------------------
Total Capital Expenditures       286     541     400      57         88          4         214          58        33    1,681
                              ================================================================================================

Property, Plant and Equipment
 Cost                          2,038   3,463   2,249   3,499        535        157       1,030         815       201   13,987
  Less: Accumulated DD&A       1,550   1,615   1,037      16        408         64         155         409        90    5,344
                              ------------------------------------------------------------------------------------------------
 Net Book Value (4)              488   1,848   1,212   3,483        127         93         875         406       111    8,643
                              ================================================================================================

Goodwill
 Cost                             --      --      --     339         --         60          --          --        --      399
  Less: Accumulated DD&A          --      --      --      --         --         24          --          --        --       24
                              ------------------------------------------------------------------------------------------------
 Net Book Value                   --      --      --     339         --         36          --          --        --      375
                              ================================================================================================
</TABLE>

Notes:
(1)  Syncrude is considered a mining operation for US reporting purposes.
     Property, plant and equipment at December 31, 2004 includes mineral rights
     of $6 million.

(2)  On December 1, 2004 we acquired EnCana (UK) Limited (see Note 2).

(3)  Includes results of operations from producing activities in Nigeria,
     Colombia, and Australia.

(4)  Net sales made from all segments originating in Canada:   $  1,242
     Property, plant and equipment located in Canada:          $  3,198

(5)  Net sales for our chemicals operations include:
           Canada                                              $    285
           United States                                             33
           Brazil                                                    60
                                                               --------
                                                               $    378
                                                               ========

(6)  Includes interest income of $12 million, foreign exchange losses of $13
     million and unrealized mark-to-market gains on crude oil put options of $56
     million.

(7)  Includes exploration activities primarily in Nigeria and Colombia.

(8)  The provision for (recovery of) income taxes for foreign locations is based
     on in-country taxes on foreign income. For oil and gas locations with no
     operating activities, the provision is based on the tax jurisdiction of the
     entity performing the activity.

(9)  In the fourth quarter of 2004, we concluded production activities in
     Australia. These results are shown as discontinued operations (Note 11).

(10) Approximately 81% of Marketing's identifiable assets are accounts
     receivable and inventories.

                                      105
<PAGE>

<TABLE>
<CAPTION>
2003 OPERATING AND GEOGRAPHIC SEGMENTS
                                                                                                            CORPORATE
                                                                                                                  AND
(Cdn$ millions)                                      OIL AND GAS                    SYNCRUDE (1) CHEMICALS      OTHER   TOTAL
------------------------------- -- ------------------------------------------------ ----------- ----------- ---------- -------
                                                                 Other
                                                              Countries  Marketing
                                    Yemen   Canada       US        (2)      (3)
                                   -------- -------- -------- ---------- ----------
<S>                                <C>      <C>         <C>   <C>        <C>        <C>          <C>            <C>     <C>
Net Sales (4)                         827      609      707         65          21        240         375(5)      --    2,844
Marketing and Other                     6        5       14         --         568         --           2         15(6)   610
                                   -------------------------------------------------------------------------------------------
Total Revenues                        833      614      721         65         589        240         377         15    3,454
Less: Expenses
Operating                              92      143       86         15          22        123         240         --      721
Depreciation, Depletion.
 Amortization and Impairment          168      490(7)   207         38          15         14          46         17      995
Transportation and Other                5        4       --         --         398         11          42         29      489
General and Administrative              5       27       13         20          43          1          21         60      190
Exploration                            17       34       89         59(8)       --         --          --         --      199
Interest                               --       --       --         --          --         --          --        169      169
                                   -------------------------------------------------------------------------------------------
Income (Loss) from
 Continuing Operations
  before Income Taxes                 546      (84)     326        (67)        111         91          28       (260)     691
Less: Provision for (Recovery
 of) Income Taxes (9)                 191      (96)     115         (1)         39         25          10       (142)     141
                                   -------------------------------------------------------------------------------------------
Net Income (Loss) from
 Continuing Operations                355       12      211        (66)         72         66          18       (118)     550
Add: Net Income from
 Discontinued Operations               --       15(10)   --         13(11)      --         --          --         --       28
                                   -------------------------------------------------------------------------------------------
Net Income (Loss)                     355       27      211        (53)         72         66          18       (118)     578
                                   ===========================================================================================

Identifiable Assets                   574    2,176    1,446        197       1,518(12)    719         475        612    7,717
                                   ===========================================================================================

Capital Expenditures
 Development and Other                219      259      249         25           1        195          24         29    1,001
 Exploration                           34       51      147         97          --         --          --         --      329
 Proved Property Acquisitions          --       --      164(13)     --          --         --          --         --      164
                                   -------------------------------------------------------------------------------------------
 Total Capital Expenditures           253      310      560        122           1        195          24         29    1,494
                                   ===========================================================================================

Property, Plant and Equipment
 Cost                               1,898    2,951    2,153        534         158        821         774        168    9,457
  Less: Accumulated DD&A            1,497    1,460      887        410          57        144         381         71    4,907
                                   -------------------------------------------------------------------------------------------
 Net Book Value (4)                   401    1,491    1,266        124         101        677         393         97    4,550
                                   ===========================================================================================

Goodwill
 Cost                                  --       --       --         --          60         --          --         --       60
  Less: Accumulated DD&A               --       --       --         --          24         --          --         --       24
                                   -------------------------------------------------------------------------------------------
 Net Book Value                        --       --       --         --          36         --          --         --       36
                                   ===========================================================================================
</TABLE>

Notes:
(1)  Syncrude is considered a mining operation for US reporting purposes.
     Property, plant and equipment at December 31, 2003 includes mineral rights
     of $6 million.

(2)  Includes results of operations from producing activities in Nigeria,
     Colombia and Australia.

(3)  Includes results of operations from a natural gas-fired generating facility
     in Alberta. In 2002, these results were included in Corporate and Other.

(4)  Net sales made from all segments originating in Canada:     $  1,218
     Property, plant and equipment located in Canada:            $  2,566

(5)  Net sales for our chemicals operations include:
         Canada                                                  $    282
         United States                                                 13
         Brazil                                                        80
                                                                 --------
                                                                 $    375
                                                                 ========

(6)  Includes interest income of $9 million and foreign exchange gains of $6
     million.

(7)  Includes impairment charge of $269 million as discussed in Note 5.

(8)  Includes exploration activities primarily in Nigeria, Colombia, Brazil and
     Equatorial Guinea.

(9)  The provision for (recovery of) income taxes for foreign locations is based
     on in-country taxes on foreign income. For oil and gas locations with no
     operating activities, the provision is based on the tax jurisdiction of the
     entity performing the activity.

(10) In August 2003, we sold non-core conventional light oil assets in southeast
     Saskatchewan for net proceeds of $268 million. No gain or loss was
     recognized on the sale. These results are shown as discontinued operations
     (see Note 11).

(11) In the fourth quarter of 2004, we concluded production activities in
     Australia. These results are shown as discontinued operations (see Note
     11).

(12) Approximately 80% of Marketing's identifiable assets are accounts
     receivable and inventories.

(13) On March 27, 2003, we acquired the residual 40% interest in Aspen in the
     Gulf of Mexico for US$109 million.

                                      106
<PAGE>

<TABLE>
<CAPTION>
2002 OPERATING AND GEOGRAPHIC SEGMENTS
                                                                                                            CORPORATE
                                                                                                                 AND
(Cdn$ millions)                                     OIL AND GAS                      SYNCRUDE (1)  CHEMICALS   OTHER(2) TOTAL
------------------------------------------------------------------------------------------------------------------------------
                                                                 Other
                                   Yemen   Canada       US   Countries(3)  Marketing
                                  --------------------------------------------------
<S>                                <C>     <C>         <C>   <C>           <C>       <C>           <C>        <C>       <C>
Net Sales (4)                        789      556      296          78          --         245         367(5)     10    2,341
Marketing and Other                   --      (19)(6)   --          --         496          --           2        17(7)   496
                                  -------------------------------------------------------------------------------------------
Total Revenues                       789      537      296          78         496         245         369        27    2,837
Less: Expenses
Operating                             86      151       94          22          --         109         229        10      701
Depreciation, Depletion,
  Amortization and Impairment        149      218      133          46           8          13          52        13      632
Transportation and Other              --       --        3          --         423           6          40         3      475
General and Administrative             4       22       11          19          30           1          21        43      151
Exploration                           21       30       82          45(8)       --          --          --        --      178
Interest                              --       --       --          --          --          --          --       181      181
                                  -------------------------------------------------------------------------------------------
Income (Loss) from
  Continuing Operations
     before Income Taxes             529      116      (27)        (54)         35         116          27      (223)     519
Less: Provision for (Recovery
  of) Income Taxes (9)               188       41      (10)        (18)         12          37           9       (96)     163
                                  -------------------------------------------------------------------------------------------
Net Income (Loss)
  from Continuing Operations         341       75      (17)        (36)         23          79          18      (127)     356
Add: Net Income from
  Discontinued Operations             --       14(10)   --          39(11)      --          --          --        --       53
                                  -------------------------------------------------------------------------------------------
Net Income (Loss)                    341       89      (17)          3          23          79          18      (127)     409
                                  ===========================================================================================


Identifiable Assets                  600    2,164    1,477         227         811(12)     543         542       301    6,665
                                  ===========================================================================================

Capital Expenditures
  Development and Other              209      258      541          69           2         141          45        97(13)1,362
  Exploration                         22       60      116          61          --          --          --        --      259
  Proved Property Acquisitions        --        4       --          --          --          --          --        --        4
                                  -------------------------------------------------------------------------------------------
 Total Capital Expenditures          231      322      657         130           2         141          45        97    1,625
                                  ===========================================================================================

Property, Plant and Equipment
  Cost                             2,054    3,170    2,244         563          87         638         803       213    9,772
     Less: Accumulated DD&A        1,646    1,169      992         426          41         142         355        57    4,828
                                  -------------------------------------------------------------------------------------------
  Net Book Value (4)                 408    2,001    1,252         137          46         496         448       156    4,944
                                  ===========================================================================================

Goodwill
  Cost                                --       --       --          --          60          --          --        --       60
     Less: Accumulated DD&A           --       --       --          --          24          --          --        --       24
                                  -------------------------------------------------------------------------------------------
  Net Book Value                      --       --       --          --          36          --          --        --       36
                                  ===========================================================================================
</TABLE>

Notes:
(1)  Syncrude is considered a mining operation for US reporting purposes.
     Property, plant and equipment at December 31, 2002 includes mineral rights
     of $6 million.

(2)  Includes results of operations from a natural gas-fired generating facility
     in Alberta.

(3)  Includes results of operations from producing activities in Nigeria,
     Colombia and Australia.

(4)  Net sales made from all segments originating in Canada:     $  1,162
     Property, plant and equipment located in Canada:            $  2,908

(5)  Net sales for our chemicals operations include:
               Canada                                            $    251
               United States                                          56
               Brazil                                                 60
                                                               ----------
                                                                 $    367
                                                               ==========

(6)  Includes a loss of $21 million on disposition of our non-operated oil and
     gas properties for proceeds of $14 million.

(7)  Includes interest income of $7 million, foreign exchange losses of $3
     million and a gain of $13 million disposition of our Moose Jaw Asphalt
     operation for proceeds of $27 million plus working capital.

(8)  Includes exploration activities primarily in Nigeria, Colombia and Brazil.

(9)  The provision for (recovery of) income taxes for foreign locations is based
     on in-country taxes on foreign income. For oil and gas locations with no
     operating activities, the provision is based on the tax jurisdiction of the
     entity performing the activity.

(10) In August 2003, we sold non-core conventional light oil assets in southeast
     Saskatchewan for net proceeds of $268 million. No gain or loss was
     recognized on the sale. These results are shown as discontinued operations
     (see Note 11).

(11) In the fourth quarter of 2004, we concluded production activities in
     Australia. These results are shown as discontinued operations (see Note
     11).

(12) Approximately 87% of Marketing's identifiable assets are accounts
     receivable and inventories.

(13) Includes $67 million related to the buy out of the lease agreement related
     to the construction of a natural gas-fired generating facility in Alberta.

                                      107
<PAGE>

19.      DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING
         PRINCIPLES

The Consolidated Financial Statements have been prepared in accordance with
Canadian GAAP. US GAAP Consolidated Financial Statements and summaries of
differences from Canadian GAAP are as follows:

<TABLE>
<CAPTION>
(a)      CONSOLIDATED STATEMENT OF INCOME - US GAAP
         FOR THE THREE YEARS ENDED DECEMBER 31, 2004

(Cdn$ millions except per share amounts)                                       2004             2003             2002
----------------------------------------------------------------------------------------------------------------------
<S>                                                                           <C>              <C>              <C>
REVENUES
    Net Sales                                                                 3,176            2,844            2,341
    Marketing and Other (ii); (ix); (x)                                         712              623              498
                                                                          --------------------------------------------
                                                                              3,888            3,467            2,839
                                                                          --------------------------------------------
EXPENSES
    Operating (iv)                                                              771              727              701
    Depreciation, Depletion, Amortization and Impairment (i)                    786            1,108              685
    Transportation and Other (ix)                                               539              489              483
    General and Administrative (viii)                                           263              190              151
    Exploration                                                                 246              199              178
    Interest                                                                    143              169              181
                                                                          --------------------------------------------
                                                                              2,748            2,882            2,379
                                                                          --------------------------------------------

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES                         1,140              585              460
                                                                          --------------------------------------------

PROVISION FOR INCOME TAXES
    Current                                                                     248              214              207
    Deferred (i) - (x)                                                          117              (91)             (46)
                                                                          --------------------------------------------
                                                                                365              123              161
                                                                          --------------------------------------------

NET INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE EFFECT
    OF CHANGES IN ACCOUNTING PRINCIPLES                                         775              462              299
    Net Income from Discontinued Operations (i)                                  13                6               53
    Cumulative Effect of Changes in Accounting Principles,
      Net of Income Taxes (vii); (x)                                             --              (48)              --
                                                                          --------------------------------------------

NET INCOME - US GAAP (1)                                                        788              420              352
                                                                          ============================================

EARNINGS PER COMMON SHARE ($/share)
    Basic (Note 10)
      Net Income from Continuing Operations                                    6.03             3.73             2.45
      Net Income from Discontinued Operations                                  0.10             0.04             0.43
      Cumulative Effect of Changes in Accounting Principles                      --            (0.38)              --
                                                                          --------------------------------------------
                                                                               6.13             3.39             2.88
                                                                          ============================================

    Diluted (Note 10)
      Net Income from Continuing Operations                                    5.95             3.70             2.41
      Net Income from Discontinued Operations                                  0.10             0.04             0.43
      Cumulative Effect of Changes in Accounting Principles                      --            (0.38)              --
                                                                          --------------------------------------------
                                                                               6.05             3.36             2.84
                                                                          ============================================
Note:
(1) RECONCILIATION OF CANADIAN AND US GAAP NET INCOME
    (Cdn$ millions)                                                            2004             2003             2002
    ------------------------------------------------------------------------------------------------------------------
    Net Income - Canadian GAAP                                                  793              578              409
    Impact of US Principles, Net of Income Taxes:
      Fair Value of Preferred Securities (x)                                      4                7               --
      Depreciation, Depletion, Amortization and Impairment (i); (vii)           (42)             (92)             (53)
      Stock Based Compensation included in Retained Earnings (viii)              36               --               --
      Loss on Disposition (i)                                                    --              (22)              --
      Other (ii); (iv)                                                           (3)              (3)              (4)
      Cumulative Effect of Changes in Accounting Principles (vii); (x)           --              (48)              --
                                                                          -------------------------------------------
    Net Income - US GAAP                                                        788              420              352
                                                                          ===========================================
</TABLE>

                                      108
<PAGE>

<TABLE>
<CAPTION>
(b)      CONSOLIDATED BALANCE SHEET - US GAAP

                                                                                    DECEMBER 31       DECEMBER 31
(Cdn$ millions, except share amounts)                                                      2004              2003
------------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>               <C>
ASSETS
    CURRENT ASSETS
      Cash and Cash Equivalents                                                             74             1,087
      Accounts Receivable (ii)                                                           2,142             1,423
      Inventories and Supplies                                                             351               270
      Other                                                                                 42                79
                                                                                ----------------------------------
        Total Current Assets                                                             2,609             2,859
                                                                                ----------------------------------

    PROPERTY, PLANT AND EQUIPMENT
      Net of Accumulated Depreciation, Depletion, Amortization and
         Impairment of $5,792 (December 31, 2003 - $5,330) (i); (iv); (vii)              8,638             4,583
    GOODWILL                                                                               375                36
    DEFERRED INCOME TAX ASSETS                                                             333               108
    DEFERRED CHARGES AND OTHER ASSETS (v)                                                  384               117
                                                                                ----------------------------------

                                                                                        12,339             7,703
                                                                                ==================================
LIABILITIES AND SHAREHOLDERS' EQUITY
    CURRENT LIABILITIES
      Short-Term Borrowings                                                                100                --
      Current Portion of Long-Term Debt (x)                                                 --               575
      Accounts Payable and Accrued Liabilities (ii)                                      2,416             1,418
      Accrued Interest Payable                                                              34                44
      Dividends Payable                                                                     13                12
                                                                                ----------------------------------
        Total Current Liabilities                                                        2,563             2,049
                                                                                ----------------------------------

    LONG-TERM DEBT (v)                                                                   4,214             2,470
    DEFERRED INCOME TAX LIABILITIES (i) - (x)                                            2,101               678
    ASSET RETIREMENT OBLIGATIONS (vii)                                                     421               305
    DEFERRED CREDITS AND OTHER LIABILITIES (vi)                                            148                70
    SHAREHOLDERS' EQUITY
      Common Shares, no par value
        Authorized:   Unlimited
        Outstanding:  2004   - 129,199,583 shares
                      2003   - 125,606,107 shares                                          637               513
      Contributed Surplus                                                                   --                 1
      Retained Earnings (i) - (x)                                                        2,360             1,660
      Accumulated Other Comprehensive Income (ii); (iii); (vi)                            (105)              (43)
                                                                                ----------------------------------
          Total Shareholders' Equity                                                     2,892             2,131
                                                                                ----------------------------------

    COMMITMENTS, CONTINGENCIES AND GUARANTEES
                                                                                        12,339             7,703
                                                                                ==================================
</TABLE>

<TABLE>
<CAPTION>
(c)  CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - US GAAP FOR THE THREE
     YEARS ENDED DECEMBER 31, 2004

(Cdn$ millions)                                                               2004           2003           2002
-----------------------------------------------------------------------------------------------------------------
<S>                                                                           <C>            <C>            <C>
Net Income - US GAAP                                                           788            420            352
Other Comprehensive Income, net of income taxes:
    Translation Adjustment (iii)                                               (72)          (127)            34
    Unrealized Mark-to-Market Gain (Loss) (ii)                                  11             (7)            --
    Minimum Unfunded Pension Liability (vi)                                     (1)            (1)            (2)
                                                                          ---------------------------------------
Comprehensive Income                                                           726            285            384
                                                                          =======================================
</TABLE>

                                      109
<PAGE>

(d)  CONSOLIDATED STATEMENT OF CASH FLOWS

Under US principles, geological and geophysical costs in 2003 of $62 million and
in 2002 of $80 million included in investing activities would be reported in
operating activities. See Note 1(r) to our Consolidated Financial Statements.

NOTES TO THE CONSOLIDATED US GAAP FINANCIAL STATEMENTS:

i.       Under US principles, the liability method of accounting for income
         taxes was adopted in 1993. In Canada, the liability method was adopted
         in 2000. In 1997, we acquired certain oil and gas assets and the amount
         paid for these assets differed from the tax basis acquired. Under US
         principles, this difference was recorded as a deferred tax liability
         with an increase to property, plant and equipment rather than a charge
         to retained earnings. As a result:

         o    additional depreciation, depletion, amortization and impairment of
              $42 million (2003 - $98 million; 2002 - $53 million) was included
              in net income; and

         o    property, plant and equipment is higher under US GAAP by $29
              million (December 31, 2003 - $71 million).

         During the third quarter of 2003, some of these assets were sold as
         described in Note 11. With the carrying value of these assets higher
         under US GAAP, the sale resulted in a loss on disposition of $22
         million, net of income taxes of $10 million. This loss was included in
         our 2003 net income from discontinued operations disclosed on the
         Consolidated Statement of Income - US GAAP.

         Included in depreciation, depletion, amortization and impairment
         expense for 2003 is an impairment charge of $315 million. The amount is
         higher under US GAAP as we have higher US GAAP carrying values for the
         assets impaired resulting from differences in adopting the liability
         method of accounting for income taxes as previous described.

ii.      Under US principles, all derivative instruments are recognized on the
         balance sheet as either an asset or a liability measured at fair value.
         Changes in the fair value of derivatives are recognized in earnings
         unless specific hedge criteria are met.

         CASH FLOW HEDGES

         Changes in the fair value of derivatives that are designated as cash
         flow hedges are recognized in earnings in the same period as the hedged
         item. Any fair value change in a derivative before that period is
         recognized on the balance sheet. The effective portion of that change
         is recognized in other comprehensive income with any ineffectiveness
         recognized in net income.

         FUTURE SALE OF OIL AND GAS PRODUCTION: Included in accounts payable at
         December 31, 2003, was a $3 million loss on the forward contracts we
         used to hedge the commodity price risk on the future sale of a portion
         of our production from the Aspen field as described in Note 6. These
         contracts expired in March 2004. The losses ($2 million, net of income
         taxes), that were deferred in accumulated other comprehensive income
         (AOCI) at December 31, 2003, were recognized in net sales in 2004.

         FUTURE SALE OF GAS INVENTORY: Included in accounts payable at December
         31, 2003, was $11 million of losses on the futures and basis swap
         contracts we used to hedge the commodity price risk on the future sale
         of our gas inventory as described in Note 6. These contracts
         effectively lock-in profits on our stored gas volumes. Losses of $8
         million ($5 million, net of income taxes) related to the effective
         portion and deferred in AOCI at December 31, 2003, were recognized in
         marketing and other in 2004. Additionally, losses of $3 million ($2
         million, net of income taxes), related to the ineffective portion, were
         recognized in marketing and other under US GAAP in 2003. Under Canadian
         GAAP, the ineffective portion was recognized in net income in 2004.

         At December 31, 2004, gains of $6 million ($4 million, net of income
         taxes) were included in accounts receivable and deferred in AOCI until
         the underlying gas inventory is sold. The gains will be reclassified to
         marketing and other in 2005 as they settle over the next 12 months.

         FAIR VALUE HEDGES

         Both the derivative instrument and the underlying commitment are
         recognized on the balance sheet at their fair value. The change in fair
         value of both are reflected in earnings. At December 31, 2004, we had
         no fair value hedges in place.

iii.     Under US principles, exchange gains and losses arising from the
         translation of our net investment in self-sustaining foreign operations
         are included in comprehensive income. Additionally, exchange gains and
         losses, net of income taxes, from the translation of our US-dollar
         long-term debt designated as a hedge of our foreign net investment are
         included in comprehensive income. Cumulative amounts are included in
         AOCI in the Consolidated Balance Sheet - US GAAP.

                                      110
<PAGE>

iv.      Under Canadian principles, we defer certain development costs and all
         pre-operating revenues and costs to property, plant and equipment.
         Under US principles, these costs have been included in operating
         expenses. As a result:

         o    operating expenses include pre-operating costs of $9 million ($6
              million, net of income taxes) (2003 - $4 million, net of income
              taxes of $2 million); and

         o    property, plant and equipment is lower under US GAAP by $15
              million (December 31, 2003 - $6 million).

v.       Under US principles, discounts on long-term debt are classified as a
         reduction of long-term debt rather than as deferred charges and other
         assets. Discounts of $45 million (December 31, 2003 - $47 million) have
         been included in long-term debt.

vi.      Under US principles, the amount by which our accrued pension cost is
         less than the unfunded accumulated benefit obligation is included in
         AOCI and accrued pension liabilities. This amount was $6 million ($4
         million, net of income taxes) at December 31, 2004 (December 31, 2003 -
         $4 million ($3 million, net of income taxes)).

vii.     On January 1, 2003 we adopted FASB Statement No. 143, ACCOUNTING FOR
         ASSET RETIREMENT OBLIGATIONS (FAS 143) for US GAAP reporting purposes.
         We adopted the equivalent Canadian standard for asset retirement
         obligations on January 1, 2004 as described in Note 1. These standards
         are consistent except for the adoption date which resulted in our
         property, plant and equipment under US GAAP being lower by $19 million.

         This change in accounting policy has been reported as a cumulative
         effect adjustment in the Consolidated Statement of Income - US GAAP as
         a loss of $37 million, net of income taxes of $25 million, on January
         1, 2003.

viii.    As described in Note 9(c), our existing stock option plan was modified
         to a tandem option plan. An obligation of $85 million was recognized
         for these tandem options. This resulted in a one-time, non-cash charge
         to net income of $54 million, net of tax in the second quarter of 2004.
         Under US principles, the modification of our stock option plan is
         accounted for by providing us with credit for the pro-forma expense
         previously disclosed for the stock options modified. The related
         pro-forma expense was $36 million, which is accounted for as an
         adjustment to retained earnings with a corresponding decrease to our
         one-time charge to net income.

ix.      Under US principles, gains and losses on the disposition of assets are
         shown as other expense. Gains (losses) of $24 million (2003 - $nil;
         2002 - $(8)) were reclassed from marketing and other to transportation
         and other.

x.       In May 2003, FASB issued Statement No. 150, ACCOUNTING FOR CERTAIN
         INSTRUMENTS WITH CHARACTERISTICS OF BOTH LIABILITIES AND EQUITY that
         requires certain financial instruments, including our preferred
         securities, to be valued at fair value with changes in fair value
         recognized through net income.

<TABLE>
<CAPTION>
                                                                            GAIN          NET GAIN
        (Cdn$ millions)                                                   (LOSS)     TAX     (LOSS)
        --------------------------------------------------------------------------------------------
        <S>                                                                <C>       <C>  <C>
        Fair value change up to June 30, 2003 (2)                            (16)      5       (11)
        Fair value change from July 1, 2003 to December 31, 2003 (1)          12      (5)        7
        Fair value change from January 1, 2004 to February 9, 2004 (1), (3)    4      --         4
                                                                          --------------------------
</TABLE>

         Notes:
        (1) Included in marketing and other.
        (2) Reported as cumulative effect of a change in accounting principle.
        (3) Redemption date of preferred securities.


                                      111
<PAGE>

NEW ACCOUNTING PRONOUNCEMENTS

In November 2004, the Financial Accounting Standards Board (FASB) issued
Statement 151, INVENTORY COSTS. This statement amends ARB 43 to clarify that:

o    abnormal amounts of idle facility expense, freight, handling costs and
     wasted material (spoilage) should be recognized as current-period charges;
     and

o    requires the allocation of fixed production overhead to inventory based on
     the normal capacity of the production facilities.

The provisions of this statement are effective for inventory costs incurred
during fiscal years beginning after June 15, 2005. We do not expect the adoption
of this statement will have any material impact on our results of operations or
financial position.

In December 2004, the FASB issued Statement 123(R), SHARE-BASED PAYMENTS. This
statement revises Statement 123, ACCOUNTING FOR STOCK-BASED COMPENSATION, and
supersedes APB Opinion 25, ACCOUNTING FOR STOCK ISSUED TO EMPLOYEES.

Statement 123(R) requires all stock-based awards issued to employees to be
measured at fair value and to be expensed in the income statement. This
statement is effective for reporting periods beginning after June 15, 2005.

We are currently expensing stock-based awards issued to employees using the fair
value method for equity based awards and the intrinsic method for liability
based awards. Adoption of this standard will change our expense under US GAAP
for tandem options and stock appreciation rights as these awards will be
measured using the fair value method rather than the intrinsic method. We are
currently evaluating the provisions of Statement 123(R) and have not yet
determined the full impact this statement will have on our results of operations
or financial position under US GAAP.

In December 2004, the FASB issued Statement 152, ACCOUNTING FOR REAL ESTATE.
This statement amends Statement 66, ACCOUNTING FOR SALES OF REAL ESTATE, to
reference the financial accounting and reporting guidance for real estate
time-sharing transactions that is provided in AICPA Statement of Position 04-2,
ACCOUNTING FOR REAL ESTATE TIME-SHARING TRANSACTIONS. This statement also amends
FASB Statement 67, ACCOUNTING FOR COSTS AND INITIAL RENTAL OPERATIONS OF REAL
ESTATE PROJECTS, to state that the guidance for incidental operations and costs
incurred to sell real estate projects does not apply to real estate time-sharing
transactions. This statement is effective for financial statements with fiscal
years beginning after June 15, 2005 and will not impact our results of
operations or financial position.

In December 2004, the FASB issued Statement 153, EXCHANGES OF NONMONETARY
ASSETS, an amendment of APB Opinion 29, ACCOUNTING FOR NONMONETARY TRANSACTIONS.
This amendment eliminates the exception for nonmonetary exchanges of similar
productive assets and replaces it with a general exception for exchanges of
nonmonetary assets that do not have commercial substance. Under Statement 153,
if a nonmonetary exchange of similar productive assets meets a
commercial-substance criterion and fair value is determinable, the transaction
must be accounted for at fair value resulting in recognition of any gain or
loss. This statement is effective for nonmonetary transactions in fiscal periods
that begin after June 15, 2005. The adoption of this statement will not have any
material impact on our results of operation or financial position.


                                      112
<PAGE>

SUPPLEMENTARY FINANCIAL INFORMATION (UNAUDITED)

<TABLE>
<CAPTION>
QUARTERLY FINANCIAL DATA IN ACCORDANCE WITH CANADIAN AND US GAAP

(Cdn$ millions)                                                             QUARTER ENDED
------------------------------------------------------------------------------------------------------------------------------
                                                  March 31             June 30            September 30          December 31
                                              2004       2003       2004       2003      2004       2003      2004       2003
                                         -------------------------------------------------------------------------------------
<S>                                           <C>        <C>        <C>        <C>       <C>        <C>       <C>        <C>
Net Sales as Previously Reported               743        806        779        726       837        716       866        660
Discontinued Operations - Australia            (28)       (28)       (21)       (17)       --        (19)       --         --
                                         -------------------------------------------------------------------------------------
Net Sales (1)                                  715        778        758        709       837        697       866        660
                                         =====================================================================================

Operating Profit as Previously Reported        319        410        283        288       391        304       383        (40)
Discontinued Operations - Australia             (4)        (9)        (5)        (1)       --         (4)       --          3
                                         -------------------------------------------------------------------------------------
Operating Profit (1), (2), (3), (4)            315        401        278        287       391        300       383        (37)
                                         =====================================================================================
Operating Profit is Comprised of:
  Oil and Gas                                  265        370        232        260       328        256       337        (54)
  Syncrude                                      40         28         40         18        52         32        33         13
  Chemicals                                     10          3          6          9        11         12        13          4
                                         -------------------------------------------------------------------------------------
                                               315        401        278        287       391        300       383        (37)
                                         =====================================================================================
Net Income (Loss) from Continuing
  Operations as Previously Reported -
    Canadian GAAP                              192        244        143        258       220        178       242        (56)
Discontinued Operations - Australia             (4)        (6)        (5)        (8)       --         (1)       --          2
Changes in Accounting Polices (5)               (8)       (11)        --        (10)       --        (10)       --        (30)
                                         -------------------------------------------------------------------------------------
Net Income (Loss) from Continuing
  Operations - Canadian GAAP  (6)              180        227        138        240        220       167       242        (84)
US GAAP Adjustments                            (20)       (14)        39        (89)       (12)       (1)      (12)        16
                                         -------------------------------------------------------------------------------------
Net Income (Loss) from Continuing
  Operations - US GAAP                         160        213        177        151       208        166       230        (68)
                                         =====================================================================================

Net Income (Loss) as Previously
  Reported - Canadian GAAP                     192        251        143        263       220        181       246        (56)
Changes in Accounting Policies                  (8)       (11)        --        (10)       --        (10)       --        (30)
                                         -------------------------------------------------------------------------------------
Net Income (Loss) - Canadian GAAP              184        240        143        253       220        171       246        (86)
US GAAP Adjustments                            (20)       (51)        39        (89)      (12)       (34)      (12)        16
                                         -------------------------------------------------------------------------------------
Net Income (Loss) - US GAAP                    164        189        182        164       208        137       234        (70)
                                         =====================================================================================

Earnings per Common Share from
  Continuing Operations ($/share)
    Canadian GAAP - Basic                     1.41       1.84       1.07       1.95      1.70       1.35      1.87      (0.67)
    Canadian GAAP - Diluted                   1.39       1.83       1.06       1.94      1.69       1.33      1.85      (0.66)
    US GAAP - Basic                           1.26       1.73       1.37       1.23      1.61       1.34      1.78      (0.54)
    US GAAP - Diluted                         1.24       1.72       1.35       1.22      1.60       1.32      1.76      (0.53)
                                         -------------------------------------------------------------------------------------

Earnings per Common Share ($/share)
    Canadian GAAP - Basic                     1.44       1.95       1.11       2.05      1.70       1.38      1.90      (0.69)
    Canadian GAAP - Diluted                   1.42       1.94       1.09       2.04      1.69       1.36      1.88      (0.68)
    US GAAP - Basic                           1.29       1.54       1.41       1.33      1.61       1.11      1.81      (0.56)
    US GAAP - Diluted                         1.27       1.53       1.39       1.32      1.60       1.09      1.79      (0.55)
                                         -------------------------------------------------------------------------------------

Dividends Declared (7)                        0.10      0.075       0.10      0.075      0.10      0.075      0.10       0.10
                                         -------------------------------------------------------------------------------------

Common Share Prices ($/share)
  Toronto Stock Exchange - High              53.35      34.85      56.50      35.59     53.70      39.68     58.66      47.08
  Toronto Stock Exchange - Low               45.00      29.30      46.80      28.26     44.34      33.02     48.17      36.65
                                         -------------------------------------------------------------------------------------
  New York Stock Exchange - High (US$)       40.61      22.55      42.29      26.31     42.13      29.00     46.56      36.47
  New York Stock Exchange - Low (US$)        34.10      19.89      34.49      19.75     33.88      24.03     39.20      27.32
                                         -------------------------------------------------------------------------------------
</TABLE>

Notes:
(1)  Excludes results of our Buffalo field, offshore Australia where we
     concluded production and the previously reported sale of non-core
     conventional light oil assets in southeast Saskatchewan. These results are
     shown as discontinued operations (see Note 11 to the Consolidated Financial
     Statements).

(2)  Includes impairment charge of $269 million (see Note 5 to the Consolidated
     Financial Statements).

(3)  Plant turnarounds and coker maintenance at Syncrude in the fourth quarters
     of 2003 and 2004 increased operating costs and temporarily reduced
     production volumes.

(4)  In 2004, a gain of $24 million was recorded on the sale of minor oil and
     gas assets by our Canadian oil and gas business.

(5)  Includes the impact of changes in accounting policies as described in Note
     1(r) to the Consolidated Financial Statements.

(6)  Canadian GAAP net income includes a reduction in tax rates for Canadian
     resource activities in the second quarter of 2003. This reduction was
     recognized in the fourth quarter of 2003 for US GAAP.

(7)  In February 2005, the Board of Directors declared a regular quarterly
     dividend of $0.10 per common share, payable April 1, 2005, to shareholders
     of record on March 10, 2005.

(8)  At December 31, 2004, there were 1,329 registered holders of common shares
     and 129,199,583 common shares outstanding.

                                      113
<PAGE>

OIL AND GAS PRODUCING ACTIVITIES AND SYNCRUDE OPERATIONS (UNAUDITED)

The following oil and gas information is provided in accordance with the US
Financial Accounting Standards Board Statement No. 69 DISCLOSURES ABOUT OIL AND
GAS PRODUCING ACTIVITIES. It also includes information relating to our interest
in Syncrude as it produces a crude oil product similar to our oil and gas
activities even though these operations are considered mining activities under
SEC regulations.

A.       RESERVE QUANTITY INFORMATION

Our net proved reserves and changes in those reserves for our conventional
operations (excluding Syncrude) are disclosed below. The net proved reserves
represent management's best estimate of proved oil and natural gas reserves
after royalties. Reserve estimates for each property are prepared internally
each year and at least 80% of the reserves (including Syncrude) have been
assessed by independent qualified reserves consultants.

Estimates of conventional crude oil and natural gas proved reserves are
determined through analysis of geological and engineering data, and demonstrate
reasonable certainty that they are recoverable from known reservoirs under
economic and operating conditions that existed at year-end. See CRITICAL
ACCOUNTING ESTIMATES in Item 7 for a description of our reserves estimation
process.

<TABLE>
<CAPTION>
CONVENTIONAL  OIL  AND  BITUMEN ARE
IN MMBBLS  AND  NATURAL  GAS IN BCF      TOTAL                                          UNITED          UNITED           OTHER
-----------------------------------  CONVENTIONAL  YEMEN(1)        CANADA               STATES          KINGDOM      COUNTRIES(3)
                                     OIL    GAS      OIL      OIL    GAS   BITUMEN(2) OIL      GAS    OIL     GAS         OIL
                                   ----------------------------------------------------------------------------------------------
<S>                                 <C>     <C>      <C>      <C>    <C>   <C>        <C>      <C>    <C>     <C>    <C>
Proved Developed and
  Undeveloped Reserves (4)
December 31, 2001                   309     791      111      157    546      --       28      245     --      --          13
                                   ----------------------------------------------------------------------------------------------

Extensions and Discoveries           72     103       23        9     31       1       32       72     --      --           7
Purchases of Reserves in Place       --       1       --       --      1      --       --       --     --      --          --
Sales of Reserves In Place           (6)     (1)      --       (2)    (1)     --       --       --     --      --          (4)
Revisions of Previous Estimates      (6)    (10)     (14)       7     (6)     --        1       (4)    --      --          --
Production                          (45)    (81)     (20)     (16)   (47)     --       (3)     (34)    --      --          (6)
                                   ----------------------------------------------------------------------------------------------
December 31, 2002                   324     803      100      155    524       1       58      279     --      --          10
                                   ----------------------------------------------------------------------------------------------

Extensions and Discoveries           48      33       36       10     20      --        1       13     --      --           1
Purchases of Reserves in Place       19      21       --       --     --      --       19       21     --      --          --
Sales of Reserves in Place          (24)     (7)      --      (24)    (6)     --       --       (1)    --      --          --
Revisions of Previous Estimates     (31)    (99)      (5)     (31)   (88)      3       (2)     (11)    --      --           4
Production                          (47)    (90)     (21)     (13)   (45)     --       (9)     (45)    --      --          (4)
                                   ----------------------------------------------------------------------------------------------
December 31, 2003                   289     661      110       97    405       4       67      256     --      --          11
                                   ----------------------------------------------------------------------------------------------

Extensions and Discoveries          244      33        1        3     18     239        1       15     --      --          --
Purchases of Reserves in Place      127      23       --        1     --      --       --       --    126      23          --
Sales of Reserves in Place           (1)     (3)      --       (1)    (2)     --       --       (1)    --      --          --
Revisions of Previous Estimates    (265)    (25)     (12)     (11)    (7)   (243)      (6)      (9)     3      (9)          4
Production                          (43)    (89)     (19)     (10)   (42)     --      (10)     (46)    (1)     (1)         (3)
                                   ----------------------------------------------------------------------------------------------
December 31, 2004                   351     600       80       79    372      --       52      215    128      13          12
                                   ==============================================================================================

Proved Developed Reserves (5)
December 31, 2002                   246     702       61      130    487       1       46      215     --      --           8
                                   ==============================================================================================
December 31, 2003                   216     576       63       87    367       4       54      209     --      --           8
                                   ==============================================================================================
December 31, 2004                   199     518       49       72    348      --       48      166     20       4          10
                                   ==============================================================================================
</TABLE>

Notes:
(1)  Under the terms of the Masila and the Block 51 production sharing
     contracts, production is divided into cost recovery oil and profit oil.
     Cost recovery oil provides for the recovery of all our costs and those of
     our partners. Remaining production is profit oil, which is shared between
     the partners and the Government of Yemen based on production rates, with
     the partners' share ranging from 20% to 33%. The Government's share of
     profit oil represents their royalty interest and an amount for income taxes
     payable in Yemen. Yemen's net proved reserves have been determined using
     the economic interest method and include our share of future cost recovery
     and profit oil after the Government's royalty interest but before reserves
     relating to income taxes payable. Under this method, reported reserves will
     increase as oil prices decrease (and vice versa) since the barrels
     necessary to achieve cost recovery change with prevailing oil prices.

(2)  Represents bitumen reserves from the insitu recovery of Canadian oil sands,
     rather than upgraded synthetic crude oil reserves.

(3)  Represents reserves in Australia, Nigeria and Colombia.

(4)  "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 recovered in
     future years from known reservoirs under existing economic and operating
     conditions. Reserves are considered "proved" if they can be produced
     economically, as demonstrated by either actual production or conclusive
     formation test.

(5)  "Proved developed" oil and gas reserves are expected to be recovered
     through existing wells with existing equipment and operating methods.

                                      114
<PAGE>

Our net proved reserves and changes in those reserves for our Syncrude
operations are disclosed below. Additional disclosures required by SEC Industry
Guide 7 can be found on pages 19 and 20. The net proved reserves represent
management's best estimate of proved synthetic reserves after royalties. Reserve
estimates are prepared internally each year and at least 80% of our reserves
(including oil and gas activities) have been assessed by independent qualified
reserves consultants.

Estimates of Syncrude's synthetic crude oil reserves are based on detailed
geological and engineering assessments of the bitumen volume in-place, the
mining plan, historical extraction recovery and upgrading yield factors,
installed plant operating capacity, and operating approval limits. The in-place
volume, depth and grade are established through extensive and closely spaced
core drilling. In accordance with the approved mining plan, there are an
estimated 2,175 million tons of economically extractable oil sands in the Base
and North Mines, with an average bitumen grade of 10.6 weight percent. The
Aurora North Mine contains an estimated 4,720 million tons of economically
extractable oil sands at an average bitumen grade of 11.2 weight percent. Aurora
South Lease 31 contains measured economically extractable oil sands of 3,440
million tons at an average bitumen grade of 10.8 weight percent.

<TABLE>
<CAPTION>
                                                                 SYNTHETIC CRUDE OIL
                                                   BASE MINE AND
(millions of barrels)                                 NORTH MINE(1)      AURORA(2)     TOTAL
----------------------------------------------------------------------------------------------
<S>                                                <C>                   <C>          <C>
December 31, 2001                                             65            166          231
                                                   -------------------------------------------

Revision of Previous Estimates                                (2)           (10)         (12)
Extensions and Discoveries                                    --             13           13
Production                                                    (5)            (1)          (6)
                                                   -------------------------------------------
December 31, 2002                                             58            168          226
                                                   -------------------------------------------

Revision of Previous Estimates                                 1              4            5
Extensions and Discoveries                                    --             22           22
Production                                                    (4)            (1)          (5)
                                                   -------------------------------------------
December 31, 2003                                             55            193          248
                                                   -------------------------------------------

Revision of Previous Estimates                                (1)            (5)          (6)
Extensions and Discoveries                                    --             19           19
Production                                                    (4)            (2)          (6)
                                                   -------------------------------------------
December 31, 2004                                             50            205          255
                                                   ===========================================
</TABLE>

Notes:
(1)  Leases 12 and 17

(2)  Leases 10, 12, 31 and 34.

                                      115
<PAGE>

<TABLE>
<CAPTION>
B.      CAPITALIZED COSTS (EXCLUDING SYNCRUDE OPERATIONS)

                                                                                         ACCUMULATED
                                                                                       DEPRECIATION,
                                                                                          DEPLETION,
                                                           PROVED        UNPROVED       AMORTIZATION    CAPITALIZED
(Cdn$ millions)                                        PROPERTIES      PROPERTIES     AND IMPAIRMENT          COSTS
---------------------------------------------------------------------------------------------------------------------
<S>                                                    <C>             <C>            <C>               <C>
December 31, 2004
    Yemen                                                   2,022              16              1,550            488
    Canada                                                  3,732             136              2,025          1,843
    United States                                           2,102             147              1,037          1,212
    United Kingdom                                          3,117             382                 16          3,483
    Other Countries                                           437              98                408            127
                                                       --------------------------------------------------------------
    Total Capitalized Costs                                11,410             779              5,036          7,153
                                                       ==============================================================

December 31, 2003
    Yemen                                                   1,881              17              1,497            401
    Canada                                                  3,271             129              1,863          1,537
    United States                                           2,034             123                892          1,265
    Other Countries                                           454              85                420            119
                                                       --------------------------------------------------------------
    Total Capitalized Costs                                 7,640             354              4,672          3,322
                                                       ==============================================================

December 31, 2002
    Yemen                                                   2,024              30              1,646            408
    Canada                                                  2,882             216              1,137          1,961
    United States                                           2,061             125                959          1,227
    Other Countries                                           460              54                382            132
                                                       --------------------------------------------------------------
    Total Capitalized Costs                                 7,427             425              4,124          3,728
                                                       ==============================================================
</TABLE>

<TABLE>
<CAPTION>
C.       COSTS INCURRED (EXCLUDING SYNCRUDE OPERATIONS)

(Cdn$ millions)                                 TOTAL                         CONVENTIONAL OIL AND GAS
--------------------------------------------------------------------------------------------------------------------
                                            Conventional                            United       United       Other
                                             Oil and Gas           Yemen  Canada    States      Kingdom   Countries
                                            -------------     ------------------------------------------------------
<S>                                         <C>                    <C>    <C>        <C>        <C>       <C>
Year Ended December 31, 2004
   Property Acquisition Costs
      Proved                                       1,774              --      4         --        1,770          --
      Unproved                                     1,491              --     --         --        1,491          --
   Exploration Costs                                 339              22     56        162            4          95
   Development Costs                               1,102             267    491        267           53          24
   Asset Retirement Costs                            168               3     27          4          134          --
                                            -------------     ------------------------------------------------------
                                                   4,874             292    578        433        3,452         119
                                            =============     ======================================================
Year Ended December 31, 2003
   Property Acquisition Costs
      Proved                                         164              --     --        164           --          --
      Unproved                                        38              --     --         38           --          --
   Exploration Costs                                 291              34     51        109           --          97
   Development Costs                                 752             219    259        249           --          25
   Asset Retirement Costs                            185              --     69         62           --          54
                                            -------------     ------------------------------------------------------
                                                   1,430             253    379        622           --         176
                                            =============     ======================================================
Year Ended December 31, 2002
   Property Acquisition Costs
      Proved                                           4              --      4         --           --          --
      Unproved                                        31              --     --         31           --          --
   Exploration Costs                                 228              22     60         85           --          61
   Development Costs                               1,077             209    258        541           --          69
                                            -------------     ------------------------------------------------------
                                                   1,340             231    322        657           --         130
                                            =============     ======================================================
</TABLE>

                                      116
<PAGE>

<TABLE>
<CAPTION>
D.      RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES (EXCLUDING SYNCRUDE OPERATIONS)

(Cdn$ millions)                                   TOTAL                         CONVENTIONAL OIL AND GAS
----------------------------------------------------------------------------------------------------------------------
                                              Conventional                            United       United       Other
                                               Oil and Gas           Yemen  Canada    States      Kingdom   Countries
                                            ---------------     ------------------------------------------------------
<S>                                           <C>                    <C>    <C>       <C>         <C>       <C>
Year Ended December 31, 2004
Net Sales                                            2,538             921    622        811           36         148
Production Costs                                       437             109    156        106            6          60
Exploration Expense                                    246               2     21        138            3          82
Depreciation, Depletion, Amortization
  and Impairment                                       712             169    240        258           18          27
Other Expenses (Income)                                106               4     38         19           --          45
                                            ---------------     ------------------------------------------------------
                                                     1,037             637    167        290            9         (66)
Income Tax Provision (Recovery)                        406             222     75        104            4           1
                                            ---------------     ------------------------------------------------------
Results of Operations                                  631             415     92        186            5         (67)
                                            ===============     ======================================================

Year Ended December 31, 2003
Net Sales                                            2,338             827    675        707           --         129
Production Costs                                       382              92    159         86           --          45
Exploration Expense                                    201              17     35         89           --          60
Depreciation, Depletion, Amortization
  and Impairment                                       945             168    510        207           --          60
Other Expenses (Income)                                 49               4     26         (1)          --          20
                                            ---------------     ------------------------------------------------------
                                                       761             546    (55)       326           --         (56)
Income Tax Provision (Recovery)                        221             191    (82)       115           --          (3)
                                            ---------------     ------------------------------------------------------
Results of Operations                                  540             355     27        211           --         (53)
                                            ===============     ======================================================

Year Ended December 31, 2002
Net Sales                                            1,984             789    656        296           --         243
Production Costs                                       428              86    176         94           --          72
Exploration Expense                                    189              21     38         82           --          48
Depreciation, Depletion, Amortization
  and Impairment                                       634             149    253        133           --          99
Other Expenses (Income)                                 79               4     41         14           --          20
                                            ---------------     ------------------------------------------------------
                                                       654             529    148        (27)          --           4
Income Tax Provision (Recovery)                        238             188     59        (10)          --           1
                                            ---------------     ------------------------------------------------------
Results of Operations                                  416             341     89        (17)          --           3
                                            ===============     ======================================================
</TABLE>

E. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN
   (EXCLUDING SYNCRUDE OPERATIONS)

The following disclosure is based on estimates of net proved reserves (excluding
Syncrude) and the period during which they are expected to be produced. Future
cash inflows are computed by applying year-end prices to our after royalty share
of estimated annual future production from proved conventional oil and gas
reserves. Future development and production costs to be incurred in producing
and further developing the proved reserves are based on year-end cost
indicators. Future income taxes are computed by applying year-end statutory-tax
rates. These rates reflect allowable deductions and tax credits, and are applied
to the estimated pre-tax future net cash flows.

Discounted future net cash flows are calculated using 10% mid-period discount
factors. The calculations assume the continuation of existing economic,
operating and contractual conditions. However, such arbitrary assumptions have
not proved to be the case in the past. Other assumptions could give rise to
substantially different results.

We believe this information does not in any way reflect the current economic
value of our oil and gas producing properties or the present value of their
estimated future cash flows as:

o    no economic value is attributed to probable and possible reserves;

o    use of a 10% discount rate is arbitrary; and

o    prices change constantly from year-end levels.


                                      117
<PAGE>

<TABLE>
<CAPTION>
                                                                                             UNITED       UNITED       OTHER
(Cdn$ millions)                                              TOTAL         YEMEN    CANADA   STATES      KINGDOM   COUNTRIES
-----------------------------------------------------------------------------------------------------------------------------
<S>                                                         <C>            <C>       <C>      <C>        <C>       <C>
December 31, 2004
Future Cash Inflows                                         18,950         3,779     4,747    4,085        5,852         487
Future Production Costs                                      4,781           722     2,135      613        1,271          40
Future Development Costs                                     1,477           275       100      185          903          14
Future Dismantlement and Site Restoration Costs, Net           626             4       149      129          336           8
Future Income Tax                                            2,798           388       382      845        1,058         125
                                                         ----------    ------------------------------------------------------
Future Net Cash Flows                                        9,268         2,390     1,981    2,313        2,284         300
10% Discount Factor                                          2,978           499       760      631        1,011          77
                                                         ----------    ------------------------------------------------------
Standardized Measure                                         6,290         1,891     1,221    1,682        1,273         223
                                                         ==========    ======================================================

December 31, 2003
Future Cash Inflows                                         14,660         4,416     5,319    4,470           --         455
Future Production Costs                                      3,651           868     1,980      666           --         137
Future Development Costs                                       788           412       102      249           --          25
Future Dismantlement and Site Restoration Costs, Net           309            --       112      137           --          60
Future Income Tax                                            2,152           574       656      854           --          68
                                                         ----------    ------------------------------------------------------
Future Net Cash Flows                                        7,760         2,562     2,469    2,564           --         165
10% Discount Factor                                          2,243           620       879      691           --          53
                                                         ----------    ------------------------------------------------------
Standardized Measure                                         5,517         1,942     1,590    1,873           --         112
                                                         ==========    ======================================================

December 31, 2002
Future Cash Inflows                                         18,687         4,662     9,067    4,516           --         442
Future Production Costs                                      3,943           881     2,375      535           --         152
Future Development Costs                                       722           296       169      228           --          29
Future Dismantlement and Site Restoration Costs, Net           227            --        24      150           --          53
Future Income Tax                                            3,650           790     1,976      863           --          21
                                                         ----------    ------------------------------------------------------
Future Net Cash Flows                                       10,145         2,695     4,523    2,740           --         187
10% Discount Factor                                          3,776           819     2,081      818           --          58
                                                         ----------    ------------------------------------------------------
Standardized Measure                                         6,369         1,876     2,442    1,922           --         129
                                                         ==========    ======================================================
</TABLE>


CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

The following are the principal sources of change in the standardized measure of
discounted future net cash flows:

<TABLE>
<CAPTION>
(Cdn$ millions)                                                                                    2004      2003       2002
-----------------------------------------------------------------------------------------------------------------------------
<S>                                                                                               <C>       <C>        <C>
Beginning of Year                                                                                 5,517     6,369      3,087
Sales and Transfers of Oil and Gas Produced, Net of Production Costs                             (1,674)   (2,298)    (1,158)
Net Changes in Prices and Production Costs Related to Future Production                             142    (1,249)     3,083
Extensions, Discoveries and Improved Recovery, Less Related Costs (1)                               (71)      740      1,929
Changes in Estimated Future Development and Dismantlement Costs                                    (122)     (279)      (103)
Previous Estimated Future Development and Dismantlement Costs
    Incurred during the Period                                                                      604       456        425
Revisions of Previous Quantity Estimates                                                           (223)     (291)       267
Accretion of Discount                                                                               692       884        409
Purchases of Reserves in Place                                                                    1,764       354          2
Sales of Reserves in Place                                                                          (20)     (252)      (109)
Net Change in Income Taxes                                                                         (319)    1,083     (1,463)
                                                                                          -----------------------------------
End of Year                                                                                       6,290     5,517      6,369
                                                                                          ===================================
</TABLE>

Note:
(1)  Includes approximately $230 million of negative deemed discounted future
     net cash flows relating to bitumen reserves based on 2004 year-end
     assumptions.


                                      118
<PAGE>

ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
           FINANCIAL DISCLOSURE

There were no disagreements with accountants on accounting and financial
disclosure.


ITEM 9A.   CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer have evaluated the
effectiveness of our disclosure controls and procedures (as defined in Exchange
Act Rules 13a-15(e) and 15-d-15(e)) as of the end of the period covered by this
report. They concluded that, as of the end of the period covered by this report,
our disclosure controls and procedures were adequate and effective in ensuring
that material information relating to the Company and its consolidated
subsidiaries would be made known to them by others within those entities,
particularly during the period in which this report was being prepared.
Management recognizes that any controls and procedures, no matter how well
designed and operated, can provide only reasonable assurance of achieving the
desired control objectives, and in reaching a reasonable level of assurance,
management necessarily is required to apply its judgement in evaluating the
cost-benefit relationship of possible controls and procedures.

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal
control over financial reporting (as defined in Exchange Act Rules 13a-15(f)).
Under the supervision and with the participation of our management, including
our principal executive officer (CEO) and principal financial officer (CFO), we
conducted an evaluation of the effectiveness of our internal control over
financial reporting based on the INTERNAL CONTROL-INTEGRATED FRAMEWORK issued by
the Committee of Sponsoring Organizations of the Treadway Commission. Based on
our evaluation, we concluded that our internal control over financial reporting
is effective as of December 31, 2004. We have documented this assessment and
made this assessment available to our independent registered Chartered
Accountants. We recognize that all internal control systems, no matter how well
designed, have inherent limitations. Therefore, even those systems determined to
be effective can provide only reasonable assurance with respect to financial
statement preparation and presentation.

There were two important exclusions from our assessment.

o    Our 7.23% working interest in the Syncrude joint venture was excluded from
     our assessment since we do not have the ability to dictate or modify this
     entity's internal control over financial reporting and we do not have the
     practical ability to assess those controls. Our 7.23% working interest in
     the Syncrude joint venture represents 7.4% of our consolidated total assets
     and 8.2% of our consolidated revenues as at and for the year ended December
     31, 2004. Despite this exclusion, we have assessed our internal control
     over financial reporting with respect to the inclusion of our share of this
     joint venture and its results for the year in our consolidated financial
     statements.

o    The internal control over financial reporting of Nexen Petroleum UK
     Limited, formerly EnCana (UK) Limited, has been excluded from our
     assessment. Our acquisition of EnCana (UK) Limited closed on December 1,
     2004 and we were unable to formally document and assess the internal
     controls over financial reporting within this acquired company by the end
     of 2004. Nexen Petroleum UK Limited represents 35.9% of our consolidated
     total assets and 0.9% of our consolidated revenues as at and for the year
     ended December 31, 2004. The significance of this acquisition to our
     consolidated financial statements is described in Note 2 to our
     consolidated financial statements. Despite this exclusion, we have assessed
     our internal controls with respect to the acquisition process and our
     internal controls relating to the consolidation and disclosure of the
     acquired company and its results since December 1, 2004 in our consolidated
     financial statements.

Further financial information with respect to the Syncrude joint venture and
Nexen Petroleum UK Limited may be found in the Syncrude and North Sea segments
of Note 18 to our consolidated financial statements.

Our management's assessment of the effectiveness of our internal control over
financial reporting as of December 31, 2004 has been audited by Deloitte &
Touche LLP, independent registered Chartered Accountants, as stated in their
report which is set out on page 120 of this Form 10-K.

CHANGES IN INTERNAL CONTROLS

We have continually had in place systems relating to internal control over
financial reporting. There has not been any change in our internal control over
financial reporting during the fourth quarter of 2004 that has materially
affected, or is reasonably likely to materially affect, our internal control
over financial reporting. During 2004, we continued to improve and enhance our
financial reporting systems by continuing to implement our existing Systems,
Applications, and Products in Data Processing (SAP) system into our North
American chemicals operations. We expect that the system conversion of our
Brazil chemicals operations will be completed in the first half of 2005. We also
implemented SAP in our Nigerian oil and gas operations during the year. The
conversion of data and the implementation and operation of SAP has been
continually monitored and reviewed.

                                      119
<PAGE>

REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS
To the Board of Directors and Shareholders of Nexen Inc.:

We have audited management's assessment, included in the foregoing Management's
Report on Internal Control over Financial Reporting that Nexen Inc. (the
"Company") maintained effective internal control over financial reporting as at
December 31, 2004, based on criteria established in INTERNAL CONTROL -
INTEGRATED FRAMEWORK issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). As described in Management's Report on Internal
Control over Financial Reporting, management excluded from their assessment,
firstly, the internal control over financial reporting at the Syncrude joint
venture whose financial statements reflect total assets and revenues
constituting 7.4% and 8.2%, respectively, of the related consolidated financial
statement amounts as at and for the year ended December 31, 2004 and, secondly,
the internal control over financial reporting at Nexen Petroleum UK Limited
(formerly EnCana (UK) Limited) which was acquired on December 1, 2004 and whose
financial statements reflect total assets and revenues constituting 35.9% and
0.9%, respectively, of the related consolidated financial statement amounts as
at and for the year ended December 31, 2004. Accordingly, our audit did not
include the internal control over financial reporting at either the Syncrude
joint venture or Nexen Petroleum UK Limited. The Company's management is
responsible for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting. Our responsibility is to express an opinion on management's
assessment and an opinion on the effectiveness of the Company's internal control
over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, evaluating management's assessment, testing and evaluating
the design and operating effectiveness of internal control, and performing such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by,
or under the supervision of, the company's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
company's board of directors, management, and other personnel to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial
reporting, including the possibility of collusion or improper management
override of controls, material misstatements due to error or fraud may not be
prevented or detected on a timely basis. Also, projections of any evaluation of
the effectiveness of the internal control over financial reporting to future
periods are subject to the risk that controls may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.

In our opinion, management's assessment that the Company maintained effective
internal control over financial reporting as at December 31, 2004, is fairly
stated, in all material respects, based on criteria established in INTERNAL
CONTROL - INTEGRATED FRAMEWORK issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Also, in our opinion, the Company
maintained, in all material respects, effective internal control over financial
reporting as at December 31, 2004, based on criteria established in INTERNAL
CONTROL - INTEGRATED FRAMEWORK issued by the Committee of Sponsoring
Organizations of the Treadway Commission.

We have also audited, in accordance with Canadian generally accepted auditing
standards and the standards of the Public Company Accounting Oversight Board
(United States), the consolidated financial statements of Nexen Inc. as at and
for the year ended December 31, 2004 and our report dated February 7, 2005
expressed an unqualified opinion on those financial statements and included a
separate report on Canada-United States of America reporting differences.


Calgary, Canada                                (signed) "Deloitte & Touche LLP"
February 7, 2005                               Independent Registered
                                               Chartered Accountants


                                      120
<PAGE>

CORPORATE GOVERNANCE


[GRAPHIC OMITTED]
[Graphic Image: Long Lake Project, Alberta]




                                      121
<PAGE>

ITEMS 10. TO 15.

                                                                            PAGE
Directors....................................................................123
Independence and Board Committees............................................124
Executive Officers...........................................................125
Summary Compensation.........................................................127
Compensation and Human Resources Committee...................................133
Share Performance............................................................135
Security Ownership...........................................................136
Certain Relationships and Related Transactions...............................137
Principal Accounting Fees and Services.......................................137
Exhibits.....................................................................138
Certifications...............................................................142



                                      122
<PAGE>

PART III


ITEM 10.   DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT


DIRECTORS

According to our Articles, Nexen must have between three and 15 directors. On
January 5, 2004, the Board determined that, until changed, there will be 11
directors.

Our By-Laws provide that directors will be elected at the annual general meeting
of shareholders (AGM) each year and will hold office until their successors are
elected. All of our current directors were elected at the last AGM.

This table shows each director's principal occupation or employment during the
past five years and any other directorships they held in public companies as at
February 10, 2005. The following directors are management nominees for election
to the Board.

<TABLE>
<CAPTION>
                                     PRINCIPAL OCCUPATION AND                                                       DIRECTOR
NAME (AGE)                           OTHER DIRECTORSHIPS                                                               SINCE
-----------------------------------------------------------------------------------------------------------------------------
<S>                                  <C>                                                                            <C>
Charles W. Fischer (54)              President and Chief Executive Officer (CEO) of Nexen. Formerly, Executive          2000
                                     Vice President and Chief Operating Officer (COO).
-----------------------------------------------------------------------------------------------------------------------------
Dennis G. Flanagan (1), (2) (65)     Retired oil executive. Director of NAL Oil & Gas Trust.                            2000
-----------------------------------------------------------------------------------------------------------------------------
David A. Hentschel (1) (71)          Oil and gas consultant. Retired oil executive. Formerly, Chairman and CEO of       1985
                                     Occidental Oil and Gas Corporation. A director of Cimarex Energy Co.
-----------------------------------------------------------------------------------------------------------------------------
S. Barry Jackson (1) (52)            Retired oil executive. Formerly, President and CEO of Crestar Energy Inc.          2001
                                     Chairman of Resolute Energy Inc. and Deer Creek Energy Limited. A director
                                     of TransCanada Corporation and TransCanada Pipelines Limited.
-----------------------------------------------------------------------------------------------------------------------------
Kevin J. Jenkins (1), (2) (48)       Managing Director of TriWest Capital Management Corp. Formerly, President and      1996
                                     CEO and a director of The Westaim Corporation.
-----------------------------------------------------------------------------------------------------------------------------
Eric P. Newell, O.C. (60)            Retired Chairman and CEO of Syncrude Canada Ltd. Director of Canfor                2004
                                     Corporation and Terasen Inc.
-----------------------------------------------------------------------------------------------------------------------------
Thomas C. O'Neill (1), (2) (59)      Retired Chairman of PwC Consulting. Formerly, CEO of PwC Consulting. Prior to      2002
                                     that, COO of PricewaterhouseCoopers LLP, Global. Prior to that, CEO of
                                     PricewaterhouseCoopers LLP, Canada. Director of BCE Inc., Loblaw Companies
                                     Limited, Dofasco Inc. and Adecco S.A.
-----------------------------------------------------------------------------------------------------------------------------
Francis M. Saville, Q.C. (66)        Counsel to Fraser Milner Casgrain LLP, Barristers and Solicitors. Formerly,        1994
                                     Senior Partner and Vice Chair of Fraser Milner Casgrain LLP, Barristers and
                                     Solicitors. Director of Mullen Transportation Inc.
-----------------------------------------------------------------------------------------------------------------------------
Richard M. Thomson, O.C. (1),(2)(71) Retired banking executive. Chair of the Board of Nexen and a director of The       1997
                                     Thomson Corporation and Trizec Properties Inc.
-----------------------------------------------------------------------------------------------------------------------------
John M. Willson (65)                 Retired President and CEO of Placer Dome Inc. Director of Aber Diamond             1996
                                     Corporation, Finning International Inc. and PanAmerican Silver Corporation.
-----------------------------------------------------------------------------------------------------------------------------
Victor J. Zaleschuk (61)             Retired President and CEO of Nexen. Chairman of Cameco Corporation and             1997
                                     a director of Agrium Inc.
-----------------------------------------------------------------------------------------------------------------------------
</TABLE>

Notes:
(1)  Members of Nexen's Audit and Conduct Review Committee. All members of the
     Committee are independent pursuant to Nexen's Categorical Standards for
     Director Independence which meet or exceed all applicable regulations.

(2)  Financial Experts on Nexen's Audit and Conduct Review Committee.

                                      123
<PAGE>

INDEPENDENCE AND BOARD COMMITTEES

Director's independence was affirmatively determined by the Board in reference
to our current Categorical Standards for Director Independence (Categorical
Standards) which were adopted on February 10, 2005. Our Categorical Standards
meet or exceed the requirements set out in US Securities and Exchange Commission
(SEC) rules and regulations, the SARBANES-OXLEY ACT OF 2002 (Sarbanes-Oxley),
the New York Stock Exchange (NYSE) rules, proposed NATIONAL INSTRUMENT 58-201
CORPORATE GOVERNANCE GUIDELINES and applicable provisions of NATIONAL INSTRUMENT
51-101 STANDARDS OF DISCLOSURE FOR OIL AND GAS ACTIVITIES.

<TABLE>
<CAPTION>
                                                          COMMITTEES (NUMBER OF MEMBERS)
----------------------------------------------------------------------------------------------------------------------
                                        AUDIT                         CORPORATE                                SAFETY,
                                          AND       COMPENSATION     GOVERNANCE                            ENVIRONMENT
                                      CONDUCT          AND HUMAN            AND              RESERVES       AND SOCIAL
                                    REVIEW(1),(2)   RESOURCES(1)   NOMINATING(1)   FINANCE   REVIEW(3)  RESPONSIBILITY
                                        (6)             (6)             (6)          (7)        (7)           (7)
----------------------------------------------------------------------------------------------------------------------
<S>                                 <C>             <C>            <C>             <C>       <C>        <C>
INDEPENDENT OUTSIDE DIRECTORS
----------------------------------------------------------------------------------------------------------------------
   Dennis G. Flanagan (4)                x                               x            x        Chair
----------------------------------------------------------------------------------------------------------------------
   David A. Hentschel (4)              Chair             x                                       x             x
----------------------------------------------------------------------------------------------------------------------
   S. Barry Jackson                      x               x                                       x           Chair
----------------------------------------------------------------------------------------------------------------------
   Kevin J. Jenkins (4)                  x                               x          Chair                      x
----------------------------------------------------------------------------------------------------------------------
   Thomas C. O'Neill (4)                 x                               x                       x             x
----------------------------------------------------------------------------------------------------------------------
   Francis M. Saville, Q.C. (5)                          x             Chair          x                        x
----------------------------------------------------------------------------------------------------------------------
   Richard M. Thomson, O.C. (4),(6)      x               x               x            x
----------------------------------------------------------------------------------------------------------------------
   John M. Willson                                     Chair                          x          x             x
----------------------------------------------------------------------------------------------------------------------
   Victor J. Zaleschuk                                   x               x            x          x
----------------------------------------------------------------------------------------------------------------------

OUTSIDE DIRECTOR
  - NOT INDEPENDENT
----------------------------------------------------------------------------------------------------------------------
   Eric P. Newell, O.C. (7)                                                           x           x             x
----------------------------------------------------------------------------------------------------------------------

MANAGEMENT DIRECTOR
   - NOT INDEPENDENT
----------------------------------------------------------------------------------------------------------------------
   Charles W. Fischer (8)
----------------------------------------------------------------------------------------------------------------------
</TABLE>

Notes:
(1)  All members of the Audit and Conduct Review Committee, Corporate Governance
     and Nominating Committee, and Compensation and Human Resources Committee
     are independent. All members of the Audit and Conduct Review Committee are
     independent under additional regulatory requirements for audit committee
     members.

(2)  The Board has considered the circumstances of Mr. O'Neill's service on four
     audit committees, plus Nexen's. Mr. O'Neill is retired and holds
     neither a full nor part-time employee position. His only commitments are to
     the boards and committees on which he serves. Accordingly, the Board has
     determined that service as an audit committee member on four other public
     companies does not impair Mr. O'Neill's ability to serve on Nexen's Audit
     and Conduct Review Committee.

(3)  A majority of the Reserves Review Committee members are independent.

(4)  A financial expert under US regulatory requirements.

(5)  Mr. Saville retired as a Partner and Vice Chair of Fraser Milner Casgrain
     (FMC) in January of 2004. Since February 1, 2004, he has been Counsel to
     the firm. Mr. Saville does not solicit or participate in any work done by
     FMC for Nexen and, as Counsel with FMC, does not receive any share of the
     fees paid to FMC by Nexen.

(6)  Mr. Thomson, Chair of the Board, presides at the regularly scheduled in
     camera sessions of the non-management directors.

(7)  Mr. Newell is not independent because a Nexen officer sits on the
     compensation committee of Syncrude. If circumstances remain the same, Mr.
     Newell will be independent after January 2, 2007 (three years after his
     retirement from Syncrude).

(8)  Mr. Fischer is not independent as he is the President and CEO of Nexen.


COMMUNICATING WITH THE BOARD

Shareholders may write to the Board or any member or members of the Board in
care of the following address:

                    By mail to:    Nexen Inc.
                                   801 - 7th Avenue S.W.,
                                   Calgary, Alberta  T2P 3P7
                     Attention:    John B. McWilliams
                                   Senior Vice President, General Counsel and
                                   Secretary
                   By email to:    board@nexeninc.com


                                      124
<PAGE>

Nexen receives an exceptional number of inquiries on a large range of subjects
every day. As a result, the Board is not able to respond to all shareholder
inquiries directly and has consulted with management to develop a process to
assist in managing inquiries directed to the Board or its members.

Letters and emails addressed to the Board, any of its members or the independent
directors, as a group, are reviewed to determine if a response from the Board is
appropriate. While the Board oversees management, it does not participate in the
day-to-day functions and operations of Nexen and is not normally in the best
position to respond to inquiries on those matters. Inquiries on operations or
day-to-day management of Nexen will be directed to the appropriate personnel
within Nexen for a response. The Board has instructed the Secretary to review
all correspondence and, in his discretion, not forward items if they:

o    are not relevant to Nexen's operations, policies and philosophies;

o    are commercial in nature; or

o    are not appropriate for consideration by the Board.

All inquiries will receive a written response from either the Board or
management, as appropriate. The Secretary maintains a log of all correspondence
addressed to members of the Board. Directors may review the log at any time and
request copies of any correspondence received.


EXECUTIVE OFFICERS

The Board determines the term of office for each executive officer. Below are
Nexen's officers. Prior offices and non-executive positions are set out for
officers who have not held their current executive positions with Nexen for more
than five years. Start dates are indicated for officer positions with Nexen.

<TABLE>
<CAPTION>
                                                                                             EFFECTIVE DATE OF      EXECUTIVE
OFFICER (AGE)                        CURRENT AND PAST POSITION(S) WITH NEXEN                  CURRENT POSITION  OFFICER SINCE
------------------------------------------------------------------------------------------------------------------------------
<S>                                  <C>                                                      <C>               <C>
Charles W. Fischer (54)              President and CEO and a director                             June 1, 2001           1994
                                     Formerly: Executive Vice President and COO since May
                                     14, 1997
------------------------------------------------------------------------------------------------------------------------------

Marvin F. Romanow (49)               Executive Vice President and CFO                             June 1, 2001           1997
                                     Formerly:  Senior Vice President, Finance and CFO
                                     since February 19, 1999
                                     Vice President, Finance and CFO since February 27, 1998
------------------------------------------------------------------------------------------------------------------------------

Laurence Murphy (1) (54)             Senior Vice President, International Oil and Gas          January 1, 1999           1998
------------------------------------------------------------------------------------------------------------------------------

John B. McWilliams, Q.C. (1) (57)    Senior Vice President, General Counsel and Secretary         May 11, 1993           1987
------------------------------------------------------------------------------------------------------------------------------

Douglas B. Otten (1) (61)            Senior Vice President, United States Oil and Gas             May 12, 1998           1990
------------------------------------------------------------------------------------------------------------------------------

Thomas A. Sugalski (1) (61)          Senior Vice President, Chemicals                             May 10, 1994           1988
------------------------------------------------------------------------------------------------------------------------------

Roger D. Thomas (1) (52)             Senior Vice President, Canadian Oil and Gas             February 19, 1999           1998
------------------------------------------------------------------------------------------------------------------------------

Nancy F. Foster (45)                 Vice President, Human Resources and Corporate Services      July 11, 2000           2000
                                     Formerly:  Division Vice President,  Finance - Canadian
                                     Oil and Gas since February 1, 1999
                                     General Manager, Human Resources since March 1, 1998
------------------------------------------------------------------------------------------------------------------------------

Gary H. Nieuwenburg (46)             Vice President, Synthetic Crude                             July 11, 2002           2001
                                     Formerly:   Vice  President,   Corporate  Planning  and
                                     Business Development since February 16, 2001
                                     Division Vice President, Exploration and Production
                                     - Canadian Oil and Gas since October 1, 1998
------------------------------------------------------------------------------------------------------------------------------

Kevin J. Reinhart (46)               Vice President, Corporate Planning and Business              July 11, 2002           1994
                                     Development
                                     Formerly: Treasurer since October 20, 1998
------------------------------------------------------------------------------------------------------------------------------

Una M. Power (2) (40)                Treasurer                                                   July 11, 2002           1998
                                     Formerly: Controller and Director, Corporate Insurance
                                     since May 2, 2002
                                     Controller and Director, Risk Management since
                                     December 1, 1998
------------------------------------------------------------------------------------------------------------------------------

Michael J. Harris (41)               Controller                                              December 10, 2002           2002
                                     Formerly: Manager, Corporate Finance - Treasury since
                                     December 1, 2000
                                     General  Manager - New Ventures Finance since March 1,
                                     2000
                                     Division Vice President,  Finance - International since
                                     March 1, 1999
</TABLE>

Notes:
(1)  Officer has held the same executive position with Nexen for more than 5
     years.

(2)  Ms. Power concurrently maintained her position as Controller until December
     10, 2002.

                                      125
<PAGE>

ETHICS POLICY

Under Nexen's Ethics Policy, all directors, officers and employees must
demonstrate a commitment to ethical business practices and behaviour in all
business relationships, both within and outside of Nexen. An employee is not
permitted to commit an unethical, dishonest or illegal act or to instruct other
employees to do so. Our Ethics Policy has been adopted as a code of ethics
applicable to our principal executive officer, principal financial officer and
principal accounting officer or controller.

Any waivers of or changes to the Ethics Policy must be approved by the Board of
Directors and appropriately disclosed. There were no waivers of the Ethics
Policy during 2004. Revisions were made to our Ethics Policy to provide for an
external Integrity Hotline which came into effect on February 1, 2005.

Our Ethics Policy is available on our internet website at www.nexeninc.com and
it is our intention to provide disclosure regarding waivers of or changes to our
Ethics Policy in this manner. In addition, our Ethics Policy is filed on SEDAR
and all future amendments to the Ethics Policy will be filed on SEDAR. A hard
copy of the Ethics Policy can be requested from the Assistant Corporate
Secretary by telephone at (403) 699-4000, by facsimile at (403) 716-0468 or by
email at assistant_secretary@nexeninc.com.

CORPORATE GOVERNANCE

Nexen's Board of Directors takes their duties and responsibilities for good
corporate governance seriously. Nexen supports and conducts business according
to the rules and guidelines of the Toronto Stock Exchange (TSX), NYSE and
proposed NATIONAL POLICY 58-201 CORPORATE GOVERNANCE GUIDELINES. Nexen's
corporate governance practices comply with the corporate governance practices
followed by domestic companies under NYSE listing standards.

On March 1, 2005, our CEO certified to the NYSE that he was unaware of any
violation by Nexen of the NYSE's corporate governance listing standards. Nexen
also provided the required Annual Written Affirmation to the NYSE on March 1,
2005. As well, our CEO and CFO have certified the quality of Nexen's public
disclosure to the SEC.

Our Committee Mandates, including the Mandates for each of the Audit and Conduct
Review Committee, the Compensation and Human Resources Committee and the
Corporate Governance and Nominating Committee and our Corporate Governance
Policy and Categorical Standards are available on our website at
www.nexeninc.com and it is our intention to provide disclosure in this manner.
Shareholders wishing to receive a copy of any of these documents may contact the
Assistant Corporate Secretary by telephone at (403) 699-4000, by facsimile at
(403) 716-0468 or by email at assistant_secretary@nexeninc.com.


                                      126
<PAGE>

ITEM 11.   EXECUTIVE COMPENSATION

<TABLE>
<CAPTION>
SUMMARY COMPENSATION

--------------------------------------------------------------------------------------------------------------------------
                                              ANNUAL COMPENSATION              LONG-TERM COMPENSATION
                                   -----------------------------------------  ------------------------
                                                                                       AWARDS
                                                                              ------------------------
                                                                              SECURITIES   RESTRICTED
                                                                              UNDERLYING    SHARES OR
                                                                OTHER ANNUAL     OPTIONS   RESTRICTED         ALL OTHER
NAME AND PRINCIPAL                    SALARY       BONUS (1)    COMPENSATION     GRANTED  SHARE UNITS      COMPENSATION
POSITION                     YEAR        ($)             ($)             ($)         (#)          ($)               ($)
--------------------------------------------------------------------------------------------------------------------------
<S>                          <C>     <C>           <C>          <C>           <C>         <C>              <C>
Charles W. Fischer           2004    847,917       1,310,000              --     150,000           --            50,875(2)
President and CEO            2003    725,000         600,000              --     100,000           --            43,500(2)
                             2002    637,500         300,000              --     100,000           --            38,250(2)
--------------------------------------------------------------------------------------------------------------------------

Marvin F. Romanow            2004    462,500         555,000              --      57,000           --            27,750(2)
Executive Vice President     2003    440,500         267,000              --      55,000           --            26,430(2)
and CFO                      2002    418,000         310,000              --      50,000           --            25,080(2)
--------------------------------------------------------------------------------------------------------------------------

Douglas B. Otten             2004    438,005         299,345              --      40,000           --  26,280(2)/63,536(3)
Senior Vice President,       2003    416,152         226,170              --      37,000           --  24,969(2)/60,221(3)
United States Oil and Gas    2002    485,873         125,886              --      35,000           --  29,156(2)/63,004(3)
--------------------------------------------------------------------------------------------------------------------------

Thomas A. Sugalski           2004    403,465         208,240              --      30,000           --  24,208(2)/56,165(4)
Senior Vice President,       2003    384,439         156,830              --      30,000           --  23,066(2)/53,395(4)
Chemicals                    2002    449,993         118,019              --      30,000           --  26,999(2)/60,889(4)
--------------------------------------------------------------------------------------------------------------------------

Laurence Murphy              2004    385,500         565,000              --      40,000           --            23,130(2)
Senior Vice President,       2003    366,500         196,000              --      37,000           --            21,990(2)
International Oil and Gas    2002    346,000          90,000              --      35,000           --            20,760(2)
--------------------------------------------------------------------------------------------------------------------------
</TABLE>

Notes:
For the CEO and four other highest compensated officers (all numbers stated in
Cdn$).

(1)  Bonuses for a year are determined based on performance during the year and
     are paid to the employee in the following year. Bonuses are paid pursuant
     to the Incentive Compensation Plan. The bonuses indicated were the payments
     made in the year shown and include special bonuses of $450,000, $225,000
     and $200,000 paid to Messrs. Fischer, Murphy and Romanow, respectively, for
     successful completion of the North Sea Acquisition in 2004.

(2)  Contributions to the Employee Savings Plan.

(3)  Nexen contributed to a Qualified Defined Contribution Plan and a
     Restoration Plan with Nexen Petroleum USA Inc. for Mr. Otten.

(4)  Nexen contributed to a Qualified Defined Contribution Plan and a
     Restoration Plan with Nexen Chemicals USA Inc. for Mr. Sugalski.

OPTIONS

Pursuant to Nexen's Tandem Option (TOP) Plan, the Board, on the recommendation
of the Compensation and Human Resources Committee, may grant options to Nexen
officers and employees. Nexen does not receive any consideration when options
are granted. The exercise price is the market price of Nexen's common shares on
the TSX for Canadian based employees or the NYSE for US based employees, when
the option is granted.

The Board determines the term of each option, to a maximum of ten years, and the
vesting schedule. For all options granted before February 2001, each option has
a term of ten years; 20% of the grant vests after six months and then 20% more
vests each year for four years on the anniversary of the grant. In February
2001, the Compensation and Human Resources Committee and the Board approved an
amendment to the TOP Plan which sets out that each option granted has a term of
five years and the options vest one-third each year over three years. Generally,
if a change of control event occurs (as defined in the TOP Plan), all issued but
unvested options will become vested.


                                      127
<PAGE>

<TABLE>
<CAPTION>
OPTION GRANTS DURING 2004

------------------------------------------------------------------------------------------------------------------------
                                       % OF TOTAL                                      POTENTIAL REALIZABLE VALUE AT
                                      OPTIONS/STOCK                                    ASSUMED ANNUAL RATES OF STOCK
                                      APPRECIATION                                   PRICE APPRECIATION FOR OPTION TERM
                                         RIGHTS                                      -----------------------------------
                        SECURITIES     GRANTED TO
                        UNDERLYING      EMPLOYEES
                         OPTIONS           IN        EXERCISE OR
                         GRANTED        FINANCIAL    BASE PRICE(1)
        NAME               (#)            YEAR     ($/SECURITY)(2)  EXPIRATION DATE        5% ($)           10% ($)
------------------------------------------------------------------------------------------------------------------------
<S>                      <C>            <C>         <C>            <C>                  <C>               <C>
Charles W. Fischer       150,000           4.5          50.87      December 6, 2009     2,108,166         4,658,497
------------------------------------------------------------------------------------------------------------------------
Marvin F. Romanow         57,000           1.7          50.87      December 6, 2009       801,103         1,770,229
------------------------------------------------------------------------------------------------------------------------
Douglas B. Otten          40,000           1.2       42.32 (US$)   December 6, 2009       604,442         1,335,658
------------------------------------------------------------------------------------------------------------------------
Thomas A. Sugalski        30,000           0.9       42.32 (US$)   December 6, 2009       453,331         1,001,744
------------------------------------------------------------------------------------------------------------------------
Laurence Murphy           40,000           1.2          50.87      December 6, 2009       562,178         1,242,266
------------------------------------------------------------------------------------------------------------------------
</TABLE>

Notes:
(1)  Equal to the market value of securities underlying options on the date of
     grant.

(2)  All values in Canadian dollars unless otherwise noted.

<TABLE>
<CAPTION>
OPTIONS EXERCISED DURING 2004 AND FINANCIAL YEAR-END OPTION VALUES

---------------------------------------------------------------------------------------------------------------------------
                                                                          NUMBER OF SECURITIES
                                                                        UNDERLYING UNEXERCISED         VALUE OF UNEXERCISED
                             SECURITIES ACQUIRED                                    OPTIONS AT      IN-THE-MONEY-OPTIONS AT
                                     ON EXERCISE     VALUE REALIZED(1)      FINANCIAL YEAR-END           FINANCIAL YEAR-END
NAME                                         (#)                ($)(2)                      (#)                      ($)(2)
                                                                       EXERCISABLE/UNEXERCISABLE  EXERCISABLE/UNEXERCISABLE
---------------------------------------------------------------------------------------------------------------------------
<S>                                     <C>                 <C>                <C>                    <C>
Charles W. Fischer                        26,400              731,328          514,000 / 249,000      9,562,740 / 830,610
---------------------------------------------------------------------------------------------------------------------------
Marvin F. Romanow                         62,000              968,300          202,200 / 109,800      3,068,535 / 432,465
---------------------------------------------------------------------------------------------------------------------------
Douglas B. Otten                          75,696            1,979,928           111,805 / 75,970      1,981,117 / 513,066
---------------------------------------------------------------------------------------------------------------------------
Thomas A. Sugalski                        95,500            2,111,164            35,800 / 59,700        827,468 / 429,066
---------------------------------------------------------------------------------------------------------------------------
Laurence Murphy                          108,000            2,797,130           104,030 / 75,970      1,406,613 / 297,578
---------------------------------------------------------------------------------------------------------------------------
</TABLE>

Notes:
(1)  Equals market price at the time of the exercise minus exercise price.

(2)  All values in Canadian dollars.

EMPLOYEE SAVINGS PLAN

The Summary Compensation Table includes Nexen's contribution to the savings plan
made on behalf of executive officers. All regular employees may participate in
our Employee Savings Plan. Through payroll deductions, employees may contribute
any percentage of their regular earnings to purchase Nexen common shares or
mutual fund units or a combination of Nexen common shares and mutual fund units.
Nexen matches employee contributions to a maximum of 6% of regular earnings. The
extent of matching is based on the investment option selected and the employee's
length of participation in the plan. The full amount of Nexen's contribution is
invested in common shares and is fully vested immediately. Employee and employer
contributions may be allocated to registered or non-registered accounts.
Employees may vote the Nexen common shares they hold in the Employee Savings
Plan.

For employees in the United States, the savings plan is intended to qualify
under Section 401(a) and 501(a) of the Internal Revenue Code. Nexen matches
employee contributions to a maximum of 6% of eligible compensation. The full
amount of Nexen's matching contribution is invested in common shares and is
fully vested immediately.


BENEFIT PLANS

All named executive officers, except Mr. Sugalski and Mr. Otten, are members of
Nexen's Defined Benefit Pension Plan and of the Executive Benefit Plan. Both Mr.
Sugalski and Mr. Otten are employed in the United States and are members of a
qualified 401(k) savings plan, a qualified defined contribution pension plan and
a non-qualified restoration plan.


                                      128
<PAGE>

DEFINED BENEFIT PENSION PLAN (CANADA)

Under this registered pension plan, participants must contribute 3% of their
regular gross earnings, up to an allowable maximum. Upon retirement,
participants are entitled to receive a benefit equal to 1.7% of their average
earnings for the 36 highest paid consecutive months during the ten years before
retirement, multiplied by the number of years of credited service. The plan is
integrated with the Canada Pension Plan (CPP) in order to provide a maximum
offset of one-half of the prevailing CPP benefit. Nexen contributed $5.1 million
to the Defined Benefit Pension Plan in 2004.

Pension benefits earned prior to January 1, 1993 may be indexed on an ad hoc
basis. Pension benefits earned after December 31, 1992 will be indexed at an
amount not greater than 5% and not less than 0% and equal to the greater of:

o   75% of the increase in the Canadian Consumer Price Index, less 1%; and

o   25% of the increase in the Canadian Consumer Price Index.

Effective January 1, 2005, the plan was amended to permit plan participants to
periodically switch between the Defined Benefit Pension Plan and the Defined
Contribution Pension Plan at different stages in their careers. In addition, the
benefit accrual formula under the plan was increased from 1.7% to 1.8% for
contributions after January 1, 2005. Plan participants have been provided with
an opportunity to further increase their benefit accrual formula on a go-forward
basis, from 1.8% to 2%, through additional tax effective employee contributions.
Employees who chose this option are required to contribute an additional 2% of
pensionable earnings to the allowable maximum.


EXECUTIVE BENEFIT PLAN (CANADA)

The Executive Benefit Plan (EBP) provides supplemental retirement benefits for
defined benefit plan participants who have earned a retirement benefit in excess
of the statutory limits. This supplemental benefit provides employees the
opportunity to accrue a pension that is more in line with their final earnings
level and also ensures competitiveness within our marketplace. Benefits are
accrued under the EBP similar to the underlying registered pension formula which
provides for 1.7% for credited service prior to 2005 and 1.8% or 2% for credited
service from 2005. For executive officers, annual incentive payments made during
the last three years of participation in the EBP are also included for benefit
accrual purposes. For the annual incentives, pension benefit is accrued on the
lesser of target bonus or actual bonus paid, averaged over the final three years
of participation, and the associated pension benefit is payable from the EBP.

The pension expense for the EBP is determined and recognized annually. Benefits
payable for the year are paid from the cash flows from Nexen's general operating
revenues and are a reduction to the related pension liability. As liabilities
under the EBP are not funded, a level of protection is provided to participants
through a letter of credit. The letter of credit basically makes participants
secured creditors up to the aggregate value of the letter of credit. This is
separate from the protection of benefits in the registered plan, which is
funded. The service cost of the letter of credit was $163,500 in 2004.

Ten executive officers, together with all employees who have exceeded the
statutory limit with their earned retirement benefits participate in the EBP.
The benefit calculation formula is the same as under the Defined Benefit Pension
Plan.

As indicated in the notes to our financial statements, Nexen's supplemental
pension plan's accumulated benefit obligation (the projected benefit obligation
excluding future salary increases) was $23 million at December 31, 2004 and the
projected benefit obligation for supplemental benefits was $34 million at that
same date.

Effective January 1, 2005, the EBP was amended to provide a supplemental pension
allocation for defined contribution plan participants who are affected by annual
statutory contribution limits. In 2005, the supplemental allocation for eligible
participants will be $18,000. No Canadian executive officer participates in the
defined contribution plan.


DEFINED CONTRIBUTION PENSION PLAN (US)

Under this qualified retirement plan, Nexen provides participants with a
contribution of 6% of eligible compensation up to the Social Security taxable
wage base and 11.5% of eligible compensation that exceeds the Social Security
taxable wage base. For 2004, the maximum amount of contributions permitted by
legislation to defined contribution plans was $41,000 per participant.


NON-QUALIFIED RESTORATION PLAN (US)

This plan is intended to be an unfunded and non-qualified deferred compensation
arrangement that provides deferred compensation benefits to a select group of
management or highly compensated employees. The plan is established and
maintained for the purpose of providing benefits in excess of applicable
legislative limits.


                                      129
<PAGE>

ESTIMATED PENSION BENEFIT

This table shows the estimated annual pension an executive officer who retired
on December 31, 2004 would receive, assuming that the amount in the Summary
Compensation Table is the officer's final average salary. It includes benefits
from both the Defined Benefit Pension Plan and the EPB and assumes a retirement
age of 65. The normal form of benefit paid from this plan is joint life with
66 2/3% to the surviving spouse.

<TABLE>
<CAPTION>
  ----------------------------------------------------------------------------------------------------------------
                                                               YEARS OF SERVICE
  ----------------------------------------------------------------------------------------------------------------
  REMUNERATION ($)                    5          10          15           20          25          30           35
  ----------------------------------------------------------------------------------------------------------------
  <S>                            <C>         <C>         <C>          <C>        <C>         <C>          <C>
     300,000                     24,802      49,604      74,406       99,209     124,011     148,813      173,615
  ----------------------------------------------------------------------------------------------------------------
     350,000                     29,052      58,104      87,156      116,209     145,261     174,313      203,365
  ----------------------------------------------------------------------------------------------------------------
     400,000                     33,302      66,604      99,906      133,209     166,511     199,813      233,115
  ----------------------------------------------------------------------------------------------------------------
     450,000                     37,552      75,104     112,656      150,209     187,761     225,313      262,865
  ----------------------------------------------------------------------------------------------------------------
     500,000                     41,802      83,604     125,406      167,209     209,011     250,813      292,615
  ----------------------------------------------------------------------------------------------------------------
     550,000                     46,052      92,104     138,156      184,209     230,261     276,313      322,365
  ----------------------------------------------------------------------------------------------------------------
     600,000                     50,302     100,604     150,906      201,209     251,511     301,813      352,115
  ----------------------------------------------------------------------------------------------------------------
     650,000                     54,552     109,104     163,656      218,209     272,761     327,313      381,865
  ----------------------------------------------------------------------------------------------------------------
     700,000                     58,802     117,604     176,406      235,209     294,011     352,813      411,615
  ----------------------------------------------------------------------------------------------------------------
     750,000                     63,052     126,104     189,156      252,209     315,261     378,313      441,365
  ----------------------------------------------------------------------------------------------------------------
     800,000                     67,302     134,604     201,906      269,209     336,511     403,813      471,115
  ----------------------------------------------------------------------------------------------------------------
     850,000                     71,552     143,104     214,656      286,209     357,761     429,313      500,865
  ----------------------------------------------------------------------------------------------------------------
     900,000                     75,802     151,604     227,406      303,209     379,011     454,813      530,615
  ----------------------------------------------------------------------------------------------------------------
     950,000                     80,052     160,104     240,156      320,209     400,261     480,313      560,365
  ----------------------------------------------------------------------------------------------------------------
   1,000,000                     84,302     168,604     252,906      337,209     421,511     505,813      590,115
  ----------------------------------------------------------------------------------------------------------------
   1,050,000                     88,552     177,104     265,656      354,209     442,761     531,313      619,865
  ----------------------------------------------------------------------------------------------------------------
   1,100,000                     92,802     185,604     278,406      371,209     464,011     556,813      649,615
  ----------------------------------------------------------------------------------------------------------------
   1,150,000                     97,052     194,104     291,156      388,209     485,261     582,313      679,365
  ----------------------------------------------------------------------------------------------------------------
   1,200,000                    101,302     202,604     303,906      405,209     506,511     607,813      709,115
  ----------------------------------------------------------------------------------------------------------------
   1,250,000                    105,552     211,104     316,656      422,209     527,761     633,313      738,865
  ----------------------------------------------------------------------------------------------------------------
   1,300,000                    109,802     219,604     329,406      439,209     549,011     658,813      768,615
  ----------------------------------------------------------------------------------------------------------------
   1,350,000                    114,052     228,104     342,156      456,209     570,261     684,313      798,365
  ----------------------------------------------------------------------------------------------------------------
   1,400,000                    118,302     236,604     354,906      473,209     591,511     709,813      828,115
  ----------------------------------------------------------------------------------------------------------------
   1,450,000                    122,552     245,104     367,656      490,209     612,761     735,313      857,865
  ----------------------------------------------------------------------------------------------------------------
   1,500,000                    126,802     253,604     380,406      507,209     634,011     760,813      887,615
  ----------------------------------------------------------------------------------------------------------------
   1,550,000                    131,052     262,104     393,156      524,209     655,261     786,313      917,365
  ----------------------------------------------------------------------------------------------------------------
   1,600,000                    135,302     270,604     405,906      541,209     676,511     811,813      947,115
  ----------------------------------------------------------------------------------------------------------------
   1,650,000                    139,552     279,104     418,656      558,209     697,761     837,313      976,865
  ----------------------------------------------------------------------------------------------------------------
   1,700,000                    143,802     287,604     431,406      575,209     719,011     862,813    1,006,615
  ----------------------------------------------------------------------------------------------------------------
   1,750,000                    148,052     296,104     444,156      592,209     740,261     888,313    1,036,365
  ----------------------------------------------------------------------------------------------------------------
   1,800,000                    152,302     304,604     456,906      609,209     761,511     913,813    1,066,115
  ----------------------------------------------------------------------------------------------------------------
   1,850,000                    156,552     313,104     469,656      626,209     782,761     939,313    1,095,865
  ----------------------------------------------------------------------------------------------------------------
   1,900,000                    160,802     321,604     482,406      643,209     804,011     964,813    1,125,615
  ----------------------------------------------------------------------------------------------------------------
   1,950,000                    165,052     330,104     495,156      660,209     825,261     990,313    1,155,365
  ----------------------------------------------------------------------------------------------------------------
   2,000,000                    169,302     338,604     507,906      677,209     846,511   1,015,813    1,185,115
  ----------------------------------------------------------------------------------------------------------------
</TABLE>

                                      130
<PAGE>

Additional past service credits or accelerated service benefits must be approved
by the Board. No accelerated service credits have been authorized. Additional
past service credits authorized by the Board for the three named executive
officers who participate in the EBP are noted in the table below. Information on
the Qualified and Non-Qualified Defined Contribution Plan contributions for the
other two named executive officers, Mr. Otten and Mr. Sugalski, is included in
the Summary Compensation Table on page 127.

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------
                                           YEARS OF                      FINAL     ACCRUED ANNUAL
                                           CREDIT SERVICE(1)  AVERAGE EARNINGS(1)  PENSION BENEFIT(1)
-----------------------------------------------------------------------------------------------------
NAME                                                   (#)                   ($)               ($)
-----------------------------------------------------------------------------------------------------
<S>                                                 <C>               <C>                 <C>
Charles W. Fischer                                  20.58(2)          1,140,139           396,100
-----------------------------------------------------------------------------------------------------
Marvin F. Romanow                                   17.50(2)            624,167           205,900
-----------------------------------------------------------------------------------------------------
Laurence Murphy                                     18.67               492,267           153,600
-----------------------------------------------------------------------------------------------------
</TABLE>

Notes:
(1)  All information as of December 31, 2004.

(2)  Ten years of additional past service credits were granted to both Mr.
     Fischer and Mr. Romanow by the Board in 2001.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

The members of the Compensation and Human Resources Committee are set out in the
table on page 124. Mr. Saville, a member of the Compensation and Human Resources
Committee, had a relationship requiring disclosure, the details of which are set
out under "Certain Relationships" on page 137. There were no compensation
committee interlocks during 2004.


CHANGE OF CONTROL AGREEMENTS

Nexen has entered into Change of Control Agreements with Messrs. Fischer,
Romanow, Otten, Sugalski, Murphy and other key executives. The agreements were
effective October 1999, amended December 2000 and amended and restated December
2001. The agreements recognize that these executives are critical to Nexen's
ongoing business. They recognize the need to retain the executives, protect them
from employment interruption due to a change in control and treat them in a fair
and equitable manner, consistent with industry standards.

For the purposes of these agreements, a change of control includes any
acquisition of common shares or other securities that carry the right to cast
more than 35% of the votes attaching to all common shares and, in general, any
event, transaction or arrangement which results in a person or group exercising
effective control of Nexen.

If the named executives are terminated following a change in control, they will
be entitled to receive salary and benefits for a specified severance period. For
Mr. Fischer and Mr. Romanow, the severance period is 36 months. They may also
terminate their employment on a voluntary basis following a change of control
with severance periods of 36 and 30 months, respectively. For Messrs. Otten,
Sugalski and Murphy, the severance period is 30 months.


DIRECTOR COMPENSATION

In December 2004, all director compensation was reviewed and confirmed at the
then current levels. All directors who are not employees are paid:

----------------------------------------------------------------------
Annual Board Chair Retainer                                  $150,000
----------------------------------------------------------------------
Annual Board Retainer                                         $28,100
----------------------------------------------------------------------
Annual Committee Retainer                                      $9,100
----------------------------------------------------------------------
Additional Annual Committee Chair Retainer                     $5,300
----------------------------------------------------------------------
Board Committee Meeting Fees (1)                               $1,800
----------------------------------------------------------------------

Note:
(1)  Per meeting for attendance either in person or by telephone conference
     call.


                                      131
<PAGE>

Committee retainers are paid quarterly, in advance, and are pro-rated for
partial service if appropriate.

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------
                                                        ANNUAL
                                                     COMMITTEE        ANNUAL
                                         ANNUAL      RETAINERS     COMMITTEE           BOARD      COMMITTEE
                                          BOARD     (NUMBER OF         CHAIR         MEETING        MEETING      TOTAL
DIRECTOR                               RETAINER    COMMITTEES)      RETAINER            FEES           FEES       FEES
------------------------------------ ----------- -------------- ------------- --------------- -------------- -------------
<S>                                    <C>         <C>             <C>               <C>            <C>        <C>
Charles W. Fischer(1)                      n/a            n/a           n/a             n/a            n/a         n/a
------------------------------------ ----------- -------------- ------------- --------------- -------------- -------------
Dennis G. Flanagan                      $28,100    $36,400 (4)        $5,300         $14,400        $41,400    $125,600
------------------------------------ ----------- -------------- ------------- --------------- -------------- -------------
David A. Hentschel                      $28,100    $36,400 (4)        $5,300         $14,400        $37,800    $122,000
------------------------------------ ----------- -------------- ------------- --------------- -------------- -------------
S. Barry Jackson                        $28,100    $36,400 (4)        $5,300         $14,400        $37,800    $122,000
------------------------------------ ----------- -------------- ------------- --------------- -------------- -------------
Kevin J. Jenkins                        $28,100    $36,400 (4)        $5,300         $14,400        $41,400    $125,600
------------------------------------ ----------- -------------- ------------- --------------- -------------- -------------
Eric P. Newell, O.C. (2)                $25,629    $24,900 (3)            --         $14,400        $27,000     $91,929
------------------------------------ ----------- -------------- ------------- --------------- -------------- -------------
Thomas C. O'Neill (3)                   $28,100    $36,400 (4)            --         $14,400        $39,600    $118,500
------------------------------------ ----------- -------------- ------------- --------------- -------------- -------------
Francis M. Saville, Q.C.                $28,100    $36,400 (4)        $5,300         $14,400        $39,600    $123,800
------------------------------------ ----------- -------------- ------------- --------------- -------------- -------------
Richard M. Thomson, O.C. (4)           $150,000    $36,400 (4)            --         $14,400        $41,400    $242,200
------------------------------------ ----------- -------------- ------------- --------------- -------------- -------------
John M. Willson                         $28,100    $36,400 (4)        $5,300         $12,600        $36,000    $118,400
------------------------------------ ----------- -------------- ------------- --------------- -------------- -------------
Victor J. Zaleschuk                     $28,100    $36,400 (4)            --         $14,400        $39,600    $118,500
------------------------------------ ----------- -------------- ------------- --------------- -------------- -------------
</TABLE>

Notes:
(1)  As an executive of Nexen, Mr. Fischer is not paid retainers or meeting
     fees.

(2)  Mr. Newell received all retainers and meeting fees in DSUs, except for
     meeting fees for two Board and three Committee meetings. His retainers were
     pro-rated to his appointment. As part of his orientation, he attended all
     Committee meetings held on February 11, 2004. He was appointed to three
     Committees the following day and it was determined to pay him meeting fees
     for the previous day for those three Committees as though he were a member
     at the time.

(3)  Mr. O'Neill received all meeting fees in DSUs for 2004.

(4)  Mr. Thomson received all retainers and meeting fees in DSUs from January 1,
     2004 to April 1, 2004.

In 2001, a Deferred Share Unit (DSU) plan was approved as an alternative form of
compensation for non-employee directors. Under the plan, eligible directors may
elect annually to receive all or part of their fees in the form of DSUs, rather
than cash. A DSU is a bookkeeping entry which tracks the value of one Nexen
common share. DSUs are not paid out until the director leaves the Board,
providing an ongoing equity stake in Nexen during the director's term of
service. Payments of DSUs may be made in cash or in Nexen common shares
purchased on the open market at the time of payment, at Nexen's option.

In 2003, the Board adopted a policy setting out that non-executive directors
would no longer be granted stock options and non-executive directors are not
eligible to receive options under the Tandem Option Plan. DSUs have since been
employed as an alternate type of performance-based compensation. In December
2004, all directors who were not employees of Nexen were granted 2,100 DSUs,
except for the Board Chair, who was granted 3,200 DSUs. The value of the grants
was $106,827 and $162,784, respectively, at the closing market price of Nexen
shares on the TSX on December 6, 2004 of $50.87.

--------------------------------------------------------------------------
                                                        DSUs  HELD AS OF
DIRECTOR                                               DECEMBER 31, 2004
--------------------------------------------------------------------------
Charles W. Fischer                                                  None
--------------------------------------------------------------------------
Dennis G. Flanagan                                                 4,217
--------------------------------------------------------------------------
David A. Hentschel                                                 4,217
--------------------------------------------------------------------------
S. Barry Jackson                                                   4,217
--------------------------------------------------------------------------
Kevin J. Jenkins                                                   7,443
--------------------------------------------------------------------------
Eric P. Newell, O.C.                                               5,823
--------------------------------------------------------------------------
Thomas C. O'Neill                                                  6,664
--------------------------------------------------------------------------
Francis M. Saville, Q.C.                                           4,217
--------------------------------------------------------------------------
Richard M. Thomson, O.C.                                           7,589
--------------------------------------------------------------------------
John M. Willson                                                    7,299
--------------------------------------------------------------------------
Victor J. Zaleschuk                                                4,217
--------------------------------------------------------------------------

DIRECTORS' AND OFFICERS' LIABILITY INSURANCE

Nexen maintains a directors' and officers' liability insurance policy for the
benefit of our directors and officers. The policy provides coverage for costs
incurred to defend and settle claims against directors and officers to an annual
limit of US$130 million with a US$1 million deductible per occurrence. The cost
of coverage for 2004 was approximately US$0.8 million.


SHARE OWNERSHIP GUIDELINES FOR DIRECTORS

The Board believes it is important that directors demonstrate their commitment
through share ownership. The Board has approved guidelines setting out that
directors are expected to own or control at least 3,000 shares (DSUs count
towards share ownership), to be accumulated over three years. Specific
arrangements may be made when a qualified candidate might be prevented from
serving by this guideline. The guideline is reviewed by the Board from time to
time. At the time of writing, all directors meet the ownership requirements.


                                      132
<PAGE>

COMPENSATION AND HUMAN RESOURCES COMMITTEE

The Compensation and Human Resources Committee's primary purpose is to assist
the Board in fulfilling its oversight responsibilities with respect to (i) key
compensation and human resources policies; (ii) CEO and executive management
compensation; and, (iii) executive management succession and development.

The Committee oversees Nexen's Incentive Compensation Plan, TOP Plan, Stock
Appreciation Rights (StARs) Plan and Pension Plan. It reviews and approves
executive management's recommendations for the annual salaries, bonuses and
grants of TOPS and StARs. The Committee reports to the Board and the Board gives
final approval to compensation matters.

The Committee evaluates the performance of the CEO and recommends his
compensation which is approved by the independent directors of the Board.

POLICIES OF THE COMMITTEE

Nexen's policies and practices are linked to strategic business objectives and
increased shareholder returns. Within that framework, the Committee's goal is to
compensate executives based on performance, at a level competitive with the
market and in a manner that would attract and retain a talented leadership team
who are focused on managing Nexen's operations, finances and assets.

To ensure competitiveness, Nexen uses compensation surveys to compare executive
compensation practices to peers, primarily major Canadian oil and gas companies
and, where relevant, chemical and marketing companies. The Committee receives a
report on CEO compensation from its own independent consultant, from time to
time. The report includes competitive compensation data from a predetermined
list of peer companies. The information is used as the basis for the Committee's
annual compensation recommendation for the CEO.

COMPENSATION OBJECTIVES

The compensation programs are designed to meet performance and competitiveness
objectives.

Programs are pay-for-performance plans, with the level of rewards directly
linked to planned performance for Nexen and its divisions. Individual
performance and contributions are considered in making awards. Measures are
aligned with goals and shareholder interests.

Competitiveness is assessed using compensation survey information from peers,
including energy companies with whom Nexen competes for talent. Total
compensation is assessed, while also considering the competitiveness of each
component.

The compensation program has three components: base salary, annual cash
incentives and long-term incentives. The Committee's goal is to provide total
compensation for experienced top performing employees between the 50th and 75th
percentile as compared to compensation levels of peer companies. Nexen's
position against the market is reviewed on an annual basis.

BASE SALARIES

To determine base salaries, Nexen maintains a framework of job levels based on
internal comparability and external market data. Base salary decisions are
determined by considering the individual's current and sustained performance
results, skills and potential.

ANNUAL INCENTIVES

The Board approves awards under the Annual Incentive Plan. The Committee
determines the total amount of cash available for annual incentive awards by
evaluating a combination of financial and non-financial criteria, including net
income, cash flow and specific goals outlined in a balanced scorecard. The
indicators, net income and cash flow, are commonly used metrics in our industry
and each contributes one-quarter of the overall assessment. The qualitative
assessment of the balanced scorecard performance indicators provides a
comprehensive evaluation and accounts for the remaining one-half of the overall
performance assessment. It includes qualitative and quantitative targets for
growth and operating performance, such as net asset value growth, cost
management, safety record, production volumes and reserves growth, among others.
Another important measure in the scorecard is the extent to which the operations
were conducted in an environmentally safe and socially responsible manner.

The purpose of annual incentives are to provide cash compensation that is
at-risk and depends on the achievement of business and operating objectives.
Individual target award levels increase in relation to job responsibilities so
that the ratio of at-risk compensation versus fixed compensation is greater for
higher levels of management. Individual awards are intended to reflect a
combination of overall Nexen, personal and business unit performance, along with
market competitiveness. Annual incentive payments vary within a range of 0% to
approximately 200% of targeted awards.

The incentive plan is reviewed annually to ensure it continues to attract,
motivate, reward and retain the high-performing and high-potential employees
needed to achieve Nexen's business objectives, while reflecting long-term fiscal
responsibility to our shareholders.


                                      133
<PAGE>

STOCK AND LONG-TERM INCENTIVES

The Board believes that employees should have a stake in Nexen's future and that
their interest should be aligned with the interest of our shareholders. To this
end, Nexen's contributions to employee savings plans are made in Nexen common
shares. In addition, the Committee selects those officers and employees whose
decisions and actions can most directly impact business results to participate
in the TOP and the StARs plans.

Under these plans, participating officers and employees receive grants of TOPs
or StARs as a long-term incentive to increase shareholder value. The StARs Plan
was introduced in 2001 and the TOP Plan (which is described on page 127) was
introduced in 2004. For employees at or below mid-level department managers,
StARs are typically granted instead of TOPs. The grants have a five-year term
and vest one-third for each of the first three years of their term on the
anniversary date of the grant. Awards of TOPs and StARs are supplementary to the
Annual Incentive Plan and are intended to increase the pay-at-risk component.
TOPS do not provide employees the right to vote the shares that are the subject
of the TOPs.

To determine the number of TOPs and StARs available for distribution, we
consider market information on options and other forms of long-term incentives
and the impact of the programs on the level of dilution to shareholders. The
focus in 2004 was on providing differentiated awards based on performance,
potential and retention risk. The total TOPs granted and shares reserved for
issue under all of our stock-based compensation programs will not exceed 10% of
our total outstanding shares.

Effective July 1, 2004, the shareholders approved the conversion of Nexen's
previous Stock Option Plan to the TOP Plan. The TOP Plan allows employees to
exchange their TOPs for a cash payment, instead of exercising them for shares,
if they choose to do so. No shares are issued when employees exchange their TOPs
for a cash payment, which reduces further shareholder dilution over time.

The AMERICAN JOBS CREATION ACT OF 2004 was signed into law on October 22, 2004
and contained some unexpected additions that affect deferred compensation for
employees, including Nexen's TOPs. The new law requires employees who receive
options with a cash payment feature to recognize the taxable income and, in some
cases, pay penalties as soon as the options vest, even if they are not exercised
at that time. Nexen believed that this change disadvantaged our US employees
and diminished the value of TOPs as a long-term incentive for them.

In order to ease this less favourable tax treatment for US employees, the
Board, as allowed under the terms of the TOP Plan, granted options without a
cash payment feature to US employees in the December 2004 grant program. Nexen
anticipates that it will continue to grant this type of modified TOP to US
employees so that they are not disadvantaged in comparison to our other
employees.


EXECUTIVE OFFICER SHARE OWNERSHIP GUIDELINES

Executive officers are required to demonstrate their commitment to Nexen through
share ownership and the Board has approved the officer shareholding guidelines
set out below. The period to accumulate the shares is five years and
shareholdings include the net value of exercisable options, flow-through shares,
shares purchased and held within the Nexen Savings Plan and any other personal
holdings. The guidelines are reviewed from time to time.

----------------------------------------------------------------------
Position                                       Required Shareholdings
----------------------------------------------------------------------
President and CEO                           Three times annual salary
----------------------------------------------------------------------
CFO                                           Two times annual salary
----------------------------------------------------------------------
Other Executive Officers                      One times annual salary
----------------------------------------------------------------------

PRESIDENT AND CHIEF EXECUTIVE OFFICER COMPENSATION

Competitive compensation information for our President and CEO is determined
based on assessments conducted by independent compensation consulting firms
which compare similar positions in the oil and gas industry. Target total cash
compensation (base salary plus incentive bonus) is competitive within the range
of the oil and gas comparator group.

Mr. Fischer's responsibility is to provide direction and leadership in setting
and achieving goals which will create value for Nexen's shareholders in the
short-term and the long-term. More specifically, the goals in 2004 for the CEO
were to:

o    Develop and execute the corporate strategy, balancing short-term growth
     while positioning Nexen for continued future growth;

o    Achieve the targets for cash flow, production, net asset value, earnings
     per share, cash flow per share and reserve replacement as set out in the
     annual operating plan;

o    Maintain financial flexibility and liquidity to support business strategies
     without undue financial risk for shareholders;

o    Achieve operating, finding and development and general and administrative
     cost performance targets set out in the annual operating plan;

o    Achieve top quartile performance in safety, environmental performance and
     social responsibility; and

o    Provide for corporate management succession and development.


                                      134
<PAGE>

Based on the Board assessment of Mr. Fischer's achievement of objectives in
2003, his base salary was increased to $850,000 in April 2004 and to $900,000 in
July 2004 after an extensive competitive market review. He was awarded a bonus
of $860,000 under the Annual Incentive Plan, which was 176% of his target bonus.

Mr. Fischer was also granted options to purchase 150,000 shares at an exercise
price of $50.87 under the Nexen TOP Plan. Awards under the TOP Plan are a direct
link to share performance and form a part of the competitive overall
compensation package.

Submitted on behalf of the Compensation and Human Resources Committee:

                                                             John Willson, Chair
                                                                  Dave Hentschel
                                                                   Barry Jackson
                                                                 Francis Saville
                                                                    Dick Thomson
                                                                   Vic Zaleschuk


SHARE PERFORMANCE GRAPH

The following graph shows changes in the past five year period, ending December
31, 2004 in the value of $100 invested in our common shares, compared to the
S&P/TSX Composite Index, the S&P/TSX Energy Sector Index and the S&P/TSX Oil &
Gas Exploration & Production Index as at December 31, 2004. Our common shares
are included in each of these indices.

                               [GRAPHIC OMITTED]
                    [LINE GRAPH - TOTAL RETURN INDEX VALUES]


<TABLE>
<CAPTION>
                                            1999/12    2000/12    2001/12     2002/12   2003/12    2004/12
-----------------------------------------------------------------------------------------------------------
<S>                                          <C>        <C>        <C>         <C>       <C>        <C>
Nexen Inc.                                   100.00     130.86     110.92      123.22    170.29     178.13
S&P/TSX Energy Sector Index                  100.00     147.69     157.90      179.60    224.43     292.41
S&P/TSX Oil & Gas Explor. & Prod. Index      100.00     147.04     151.79      176.33    211.85     298.03
S&P/TSX Composite Index                      100.00     107.41      93.91       82.23    104.20     119.20
                                            ---------------------------------------------------------------
</TABLE>

        Assuming an investment of $100 and the reinvestment of dividends


                                      135
<PAGE>

ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT


SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

Nexen's common shares are the only class of voting securities. Based on
information known to Nexen, the following table shows each person or group who
beneficially owns (pursuant to SEC Regulations) more than 5% of Nexen's voting
securities at December 31, 2004.

<TABLE>
<CAPTION>
                                                                          # OF SHARES
NAME AND ADDRESS OF BENEFICIAL OWNER                               BENEFICIALLY OWNED    % OF SHARES
-----------------------------------------------------------------------------------------------------
<S>                                                                <C>                    <C>
Jarislowsky Fraser Limited (1)                                             21,148,998             16.4
Suite 2005, 1010 Sherbrooke Street West
Montreal, Quebec, Canada, H3A 2R7
-----------------------------------------------------------------------------------------------------
Ontario Teachers' Pension Plan Board (2)                                   19,349,618             15.0
5650 Yonge Street
Toronto, Ontario, Canada, M2M 4H5
-----------------------------------------------------------------------------------------------------
Capital Research and Management Co. (3)                                     9,326,080              7.2
333 South Hope Street, 53 Floor
Los Angeles, California, USA, 90071-1406
-----------------------------------------------------------------------------------------------------
</TABLE>

Notes:
(1)  The beneficial owner has sole voting power over 17,878,438 shares, shared
     voting power over 3,270,560 shares; and sole power to dispose of all
     shares.

(2)  The beneficial owner has sole voting and power to dispose of all shares.

(3)  The beneficial owner has sole power to dispose of all shares and disclaims
     beneficial ownership pursuant to Rule 13d-4.

SECURITY OWNERSHIP OF MANAGEMENT

At February 22, 2005, the following directors, certain executive officers, and
all directors and executive officers as a group beneficially owned the following
Nexen common shares:

<TABLE>
<CAPTION>
                                                                     NUMBER OF      EXERCISABLE
NAME OF BENEFICIAL OWNER                                              SHARES(1)       OPTIONS(2)
------------------------------------------------------------------------------------------------
<S>                                                                     <C>             <C>
Charles W. Fischer                                                      33,651          514,000
------------------------------------------------------------------------------------------------
Dennis G. Flanagan                                                       6,001           13,960
------------------------------------------------------------------------------------------------
David A. Hentschel                                                       5,656           35,185
------------------------------------------------------------------------------------------------
S. Barry Jackson                                                         6,000           10,185
------------------------------------------------------------------------------------------------
Kevin J. Jenkins                                                         3,068           18,685
------------------------------------------------------------------------------------------------
Eric P. Newell, O.C.                                                     3,000              Nil
------------------------------------------------------------------------------------------------
Thomas C. O'Neill                                                        4,000            3,685
------------------------------------------------------------------------------------------------
Francis M. Saville, Q.C.                                                10,400           27,936
------------------------------------------------------------------------------------------------
Richard M. Thomson, O.C.                                                23,001           52,861
------------------------------------------------------------------------------------------------
John M. Willson                                                          7,001           25,185
------------------------------------------------------------------------------------------------
Victor J. Zaleschuk                                                     15,675           70,185
------------------------------------------------------------------------------------------------
Laurence Murphy                                                         13,574           52,580
------------------------------------------------------------------------------------------------
Douglas B. Otten                                                        28,072           85,958
------------------------------------------------------------------------------------------------
Marvin F. Romanow                                                       23,998          202,200
------------------------------------------------------------------------------------------------
Thomas A. Sugalski                                                          17           35,800
------------------------------------------------------------------------------------------------
All directors and executive officers as a group (22 persons)           227,375        1,395,642
------------------------------------------------------------------------------------------------
</TABLE>

Notes:
(1)  The number of shares held and options exercisable by each beneficial
     owner represents less than 1% of the shares outstanding.

(2)  Includes all options exercisable within 60 days of February 22, 2005. All
     options held by non-executive directors are vested.

Under the terms of our TOP Plan, the Board of Directors may grant options to
officers and employees and, when previously allowed for, to directors. Nexen
does not receive any consideration when options are granted.

<TABLE>
<CAPTION>
Equity Compensation Plan Information:
                                                                                              NUMBER OF SECURITIES
                                      NUMBER OF SECURITIES TO BE      WEIGHTED-AVERAGE      REMAINING AVAILABLE FOR
                                       ISSUED UPON EXERCISE OF       EXERCISE PRICE OF       FUTURE ISSUANCE UNDER
                                       OUTSTANDING OPTIONS (a)    OUTSTANDING OPTIONS (b) EQUITY COMPENSATION PLANS (c)
-----------------------------------------------------------------------------------------------------------------------
<S>                                    <C>                        <C>                     <C>
Equity compensation plans
    approved by shareholders                  8,138,183                     $39                    9,586,237
-----------------------------------------------------------------------------------------------------------------------
</TABLE>


                                      136
<PAGE>

ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Mr. Saville, a director, was a senior partner of Fraser Milner Casgrain LLP
(FMC), Barristers and Solicitors, Calgary, Alberta until the end of January
2004. Since February 1, 2004, he has been counsel with the firm. FMC has
rendered legal services to Nexen during each of the last five years. Mr. Saville
neither solicits nor participates in the services rendered to Nexen and does not
receive any portion or percentage of the fees paid to FMC. In addition, he is
independent pursuant to our Categorical Standards.


ITEM 14.   PRINCIPAL ACCOUNTING FEES AND SERVICES

In connection with their responsibilities, the Audit and Conduct Review
Committee:

o    met with management and the independent auditor to review and discuss the
     December 31, 2004 consolidated financial statements,

o    discussed with the independent auditor the matters required by Canadian
     regulators in accordance with Section 5751 of the General Assurance and
     Auditing Standards of the Canadian Institute of Chartered Accountants
     COMMUNICATIONS WITH THOSE HAVING OVERSIGHT RESPONSIBILITY FOR THE FINANCIAL
     REPORTING PROCESS and by US regulators in accordance with the Statement
     on Auditing Standards No. 61 COMMUNICATION WITH AUDIT COMMITTEES issued by
     the American Institute of Certified Public Accountants,

o    received written disclosures from the independent auditor required by the
     SEC in accordance with the Independence Standards Board Standard No. 1
     INDEPENDENCE DISCUSSIONS WITH AUDIT COMMITTEES,

o    discussed with the independent auditor that firm's independence, and

o    oversaw the progress of the Section 404 Sarbanes-Oxley project for
     management and the independent auditor to report on the effectiveness of
     internal control over financial reporting as at December 31, 2004.

AUDIT FEES

Fees billed by Deloitte & Touche LLP were:

o    $1,041,000 for the completion of the 2003 audit ($641,000) and commencement
     of the 2004 audit ($400,000) of the Consolidated Financial Statements
     included in our Annual Report on Form 10-K (2003 billings - $596,000).

o    $45,000 for the 2004 first, second and third quarter reviews ($42,000 for
     the 2003 first, second and third quarter reviews) of the Consolidated
     Financial Statements included on Form 10-Qs.

o    $630,000 (nil for 2003) for the commencement of the 2004 audit of internal
     control over financial reporting.

AUDIT-RELATED FEES

Fees billed by Deloitte & Touche LLP were:

o    $296,000 for 2004 ($322,000 for 2003) for the annual audits of our
     subsidiary financial statements and employee benefit plans.

o    $9,500 for 2004 ($87,000 for 2003) for comfort letters to securities
     commissions.

TAX FEES

Fees billed by Deloitte & Touche LLP were $60,000 for 2004 ($160,000 for 2003)
for tax return preparation assistance and tax-related consultation.

ALL OTHER FEES

No other fees were billed by Deloitte & Touche LLP during 2004 and 2003.

AUDIT COMMITTEE APPROVAL

Before Deloitte & Touche LLP is engaged by Nexen or our subsidiaries to render
audit or non-audit services, the engagement is approved by Nexen's Audit and
Conduct Review Committee. All audit-related and tax services provided by
Deloitte & Touche LLP since May 6, 2003 have been approved by the Audit and
Conduct Review Committee.

Submitted on behalf of the Audit and Conduct Review Committee:

                                                           Dave Hentschel, Chair
                                                                 Dennis Flanagan
                                                                   Barry Jackson
                                                                   Kevin Jenkins
                                                                     Tom O'Neill
                                                                    Dick Thomson


                                      137
<PAGE>

PART IV


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


FINANCIAL STATEMENTS AND SCHEDULES

We refer you to the Index to Financial Statements and Related Information under
Item 8 of this report where these documents are listed.

Schedules and separate financial statements of subsidiaries are omitted because
they are not required or applicable, or the required information is shown in the
Consolidated Financial Statements or notes.


EXHIBITS

Exhibits filed as part of this report are listed below. Certain exhibits have
been previously filed with the Commission and are incorporated in this Form 10-K
by reference. Instruments defining the rights of holders of debt securities that
do not exceed 10% of Nexen's consolidated assets have not been included. A copy
of such instruments will be furnished to the Commission upon request.

2.2     Agreement for the Sale and Purchase of EnCana (UK) Limited, between
        EnCana (UK) Holdings Limited and Nexen Energy Holdings International
        Limited dated October 28, 2004 (filed as Exhibit 2.1 to Form 8-K dated
        October 29, 2004, filed by the Registrant).

3.5     Restated Certificate of Incorporation of the Registrant dated June 5,
        1995, and Restated Articles of Incorporation (filed as Exhibit 3.5 to
        Form 10-K for the year ended December 31, 1995, filed by the
        Registrant).

3.6     Certificate of Amendment of the Articles of the Registrant dated May 9,
        1996 (filed as Exhibit 3.6 to Form 10-K for the year ended December 31,
        1996, filed by the Registrant).

3.7     Certificate of Amendment and Articles of Amendment of the Registrant
        dated November 2, 2000, with respect to the name change to Nexen Inc.
        (filed as Exhibit 3.7 to Form 10-K for the year ended December 31, 2000,
        filed by the Registrant).

3.8     By-Law No. 1 of the Registrant enacted February 15, 2002, being a by-law
        relating generally to the transaction of the business and affairs of the
        Registrant (filed as Exhibit 2 to Form 8-A/A dated August 20, 2002,
        filed by the Registrant).

3.9     By-Law No. 2 of the Registrant enacted December 9, 2003, being a by-law
        relating generally to the transaction of the business and affairs of the
        Registrant (filed as Exhibit 3.9 to Form 10-K for the year ended
        December 31, 2003, filed by the Registrant).

3.10    Certificate of Amalgamation dated January 1, 2005 relating to the
        amalgamation of Nexen Canada Ltd., a wholly-owned subsidiary of the
        Registrant, into the Registrant (filed as Exhibit 1 to Form 8-K dated
        February 4, 2005, filed by the Registrant).

3.11    Amended Articles of Amalgamation dated January 13, 2005 relating to the
        amalgamation of Nexen Canada Ltd., a wholly-owned subsidiary of the
        Registrant, into the Registrant (filed as Exhibit 2 to Form 8-K dated
        February 4, 2005, filed by the Registrant).

4.29    Acquisition Agreement between the Registrant, Occidental Petroleum
        Corporation and Ontario Teachers' Pension Plan Board, dated March 1,
        2000 (filed as Exhibit 4.29 to Form 10-K for the year ended December
        31, 1999, filed by the Registrant).

4.32    Amended and Restated Loan Agreement of December 29, 1988, between the
        Registrant, the Toronto Dominion Bank, as Agent, and the Lenders, dated
        November 17, 2000, amending the amount of the facility to $400 million
        and providing for various conforming covenant amendments to the Loan
        Agreement dated April 14, 1997 (as restated) (filed as Exhibit 4.32 to
        Form 10-K for the year ended December 31, 2000, filed by the
        Registrant).

4.33    Restated Loan Agreement of April 14, 1997, between the Registrant, the
        Toronto Dominion Bank, as Agent, and the Lenders dated October 16, 2000,
        reducing the amount of the facility to $975 million and splitting the
        loan into 364 day (40%) and six-year term (60%) portions, and other
        various amendments (filed as Exhibit 4.33 to Form 10-K for the year
        ended December 31, 2000, filed by the Registrant).


                                      138
<PAGE>

4.36    First Amending Agreement to the October 16, 2000 Restated Loan Agreement
        of April 14, 1997, between the Registrant, the Toronto Dominion Bank, as
        Agent, and the Lenders, dated July 31, 2001 (filed as Exhibit 4.36 to
        Form 10-K for the year ended December 31, 2001, filed by the
        Registrant).

4.37    First Amending Agreement to the November 17, 2000 Amended and Restated
        Loan Agreement of December 29, 1988, between the Registrant, the Toronto
        Dominion Bank, as Agent, and the Lenders, dated August 1, 2001 (filed as
        Exhibit 4.37 to Form 10-K for the year ended December 31, 2001, filed by
        the Registrant).

4.38    Second Amending Agreement to the October 16, 2000 Restated Loan
        Agreement of April 14, 1997, between the Registrant, the Toronto
        Dominion Bank, as Agent, and the Lenders, dated July 30, 2002 (filed as
        Exhibit 4.38 to Form 10-K for the year ended December 31, 2002, filed by
        the Registrant).

4.39    Second Amending Agreement to the November 17, 2000 Amended and Restated
        Loan Agreement of December 29, 1988, between the Registrant, the Toronto
        Dominion Bank, as Agent, and the Lenders, dated July 31, 2002 (filed as
        Exhibit 4.39 to Form 10-K for the year ended December 31, 2002, filed by
        the Registrant).

4.40    Amended and Restated Shareholder Rights Plan Agreement dated May 2, 2002
        between the Registrant and CIBC Mellon Trust Company, as Rights Agent,
        which includes the Form of Rights Certificate as Exhibit A (filed as
        Exhibit 3 to Form 8-A/A dated August 20, 2002, filed by the Registrant).

4.42    Trust Indenture dated April 28, 1998 between the Registrant and CIBC
        Mellon Trust Company providing for the issue of debt securities from
        time to time (filed as Exhibit 4.42 to Form 10-K for the year ended
        December 31, 2003, filed by the Registrant).

4.43    First Supplemental Indenture dated April 28, 1998 to the Trust Indenture
        dated April 28, 1998 between the Registrant and CIBC Mellon Trust
        Company pertaining to the issuance of US$200 million, 7.40% notes due
        2028 (filed as Exhibit 4.43 to Form 10-K for the year ended December 31,
        2003, filed by the Registrant).

4.44    Third Amending Agreement dated July 29, 2003 to the October 16, 2000
        Restated Loan Agreement of April 14, 1997 between the Registrant, the
        Toronto Dominion Bank, as Agent, and the Lenders (filed as Exhibit 4.44
        to Form 10-K for the year ended December 31, 2003, filed by the
        Registrant).

4.45    Third Amending Agreement dated July 29, 2003 to the November 17, 2000
        Amended and Restated Loan Agreement of December 29, 1988, between the
        Registrant, the Toronto Dominion Bank, as Agent, and the Lenders (filed
        as Exhibit 4.45 to Form 10-K for the year ended December 31, 2003, filed
        by the Registrant).

4.46    Third Supplemental Indenture dated March 11, 2002 to the Trust Indenture
        dated April 28, 1998 between the Registrant and CIBC Mellon Trust
        Company pertaining to the issuance of $500 million, 7.85% notes due 2032
        (filed as Exhibit 4.46 to Form 10-K for the year ended December 31,
        2003, filed by the Registrant).

4.47    Subordinated Debt Indenture dated November 4, 2003 between the
        Registrant and Deutsche Bank Trust Company Americas, pertaining to the
        issue of subordinated notes from time to time (filed as Exhibit 4.47 to
        Form 10-K for the year ended December 31, 2003, filed by the
        Registrant).

4.48    Officer's Certificate dated November 4, 2003 pursuant to the
        Subordinated Debt Indenture dated November 4, 2003 between the
        Registrant and Deutsche Bank Trust Company Americas, pertaining to the
        issuance of US$460 million, 7.35% subordinated notes due 2043 (filed as
        Exhibit 4.48 to Form 10-K for the year ended December 31, 2003, filed by
        the Registrant).

4.49    Fourth Amending Agreement dated November 4, 2003 to the October 16, 2003
        Restated Loan Agreement of April 14, 1997, between the Registrant, the
        Toronto Dominion Bank, as Agent, and the Lenders (filed as Exhibit 4.49
        to Form 10-K for the year ended December 31, 2003, filed by the
        Registrant).

4.50    Fourth Amending Agreement dated November 4, 2003 to the November 17,
        2000 Amended and Restated Loan Agreement of December 29, 1988, between
        the Registrant, the Toronto Dominion Bank, as Agent, and the Lenders
        (filed as Exhibit 4.50 to Form 10-K for the year ended December 31,
        2003, filed by the Registrant).

4.51    Fourth Supplemental Indenture dated November 20, 2003 to the Trust
        Indenture dated April 28, 1998, between the Registrant and CIBC Mellon
        Trust Company pertaining to the issuance of US$500 million, 5.05% notes
        due 2013 (filed as Exhibit 4.51 to Form 10-K for the year ended December
        31, 2003, filed by the Registrant).

4.52    Loan Agreement of November 26, 2004, between the Registrant, the Toronto
        Dominion Bank, as Agent, and the Lenders (filed as Exhibit 4.1 to Form
        8-K dated December 7, 2004, filed by the Registrant).

10.40   Amended and Restated Change of Control Agreements with Executive
        Officers dated during December, 2001 (filed as Exhibit 10.41 to Form
        10-K for the year ended December 31, 2001, filed by the Registrant).


                                      139
<PAGE>

10.41   Indemnification Agreements made between the Registrant and its directors
        and officers during 2002 (filed as Exhibit 10.41 to Form 10-K for the
        year ended December 31, 2002, filed by the Registrant).

10.42   Indemnification Agreement made between the Registrant and one of its
        directors, Eric P. Newell, as of January 5, 2004 (filed as Exhibit 10.42
        to Form 10-K for the year ended December 31, 2003, filed by the
        Registrant).

11.2    Statement regarding the Computation of Per Share Earnings for the three
        years ended December 31, 2004.

16.1    Letter re change in certifying accountant (filed as Exhibit 16.1 to Form
        8-K filed July 17, 2002 by the Registrant).

21.0    Subsidiaries of the Registrant.

23.0    Consent of Independent Registered Chartered Accountants.

31.2    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.

99.1    Opinion of Internal Qualified Reserves Evaluator on National Instrument
        51-101 Form F2 as required by certain Canadian securities regulatory
        authorities.


REPORTS ON FORM 8-K

During the quarter ended December 31, 2004, we filed or furnished the following
reports on Form 8-K:

o    Current report on Form 8-K dated October 14, 2004, to furnish our press
     release announcing our 2004 third quarter results.

o    Current report on Form 8-K dated November 3, 2004, to announce an agreement
     with a wholly-owned subsidiary of EnCana Corporation to acquire EnCana
     (UK) Limited.

o    Current report on Form 8-K dated December 7, 2004, to announce the
     completion of the acquisition of EnCana (UK) Limited.

Up until the filing of this Form 10-K, during 2005, we filed or furnished the
following reports on Form 8-K:

o    Current report on Form 8-K/A dated January 12, 2005, to file the pro forma
     financial information in connection with the acquisition of EnCana (UK)
     Limited.

o    Current report on Form 8-K dated February 4, 2005, to file our Certificate
     and Amended Articles of Amalgamation.

o    Current report on Form 8-K dated February 10, 2005, to furnish our press
     release announcing our 2004 annual reserves and annual results.

o    Current report on Form 8-K/A Amendment No. 2 dated February 25, 2005, to
     file the amended pro forma financial information in connection with the
     acquisition of EnCana (UK) Limited.


                                      140
<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)


Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities indicated on March 1, 2005.

/s/ Dennis G. Flanagan                    /s/ Charles W. Fischer
-----------------------                   -----------------------
Dennis G. Flanagan, Director              Charles W. Fischer
                                          President, Chief Executive Officer
/s/ David A. Hentschel                    and Director (Principal Executive
-----------------------                   Officer)
David A. Hentschel, Director

/s/ S. Barry Jackson                      /s/ Marvin F. Romanow
---------------------                     -----------------------
S. Barry Jackson, Director                Marvin F. Romanow
                                          Executive Vice President and Chief
/s/ Kevin J. Jenkins                      Financial Officer
---------------------                     (Principal Financial Officer)
Kevin J. Jenkins, Director

/s/ Eric P. Newell                        /s/ Michael J. Harris
-------------------                       ----------------------
Eric P. Newell, Director                  Michael J. Harris
                                          Controller
/s/ Thomas C. O'Neill                     (Principal Accounting Officer)
----------------------
Thomas C. O'Neill, Director
                                          /s/ John B. McWilliams
/s/ Francis M. Saville                    -----------------------
-----------------------                   John B. McWilliams
Francis M. Saville, Director              Senior Vice President, General Counsel
                                          and Secretary
/s/ Richard M. Thomson
-----------------------
Richard M. Thomson, Director              /s/ Kevin J. Reinhart
                                          -----------------------
/s/ John M. Willson                       Kevin J. Reinhart
--------------------                      Vice President, Corporate Planning
John M. Willson, Director                 and Business Development

/s/ Victor J. Zaleschuk
------------------------
Victor J. Zaleschuk, Director


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