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, 2005

                         COMMISSION FILE NUMBER 1-6702

                                   NEXEN INC.
                     Incorporated under the Laws of Canada

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

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

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

       Common shares, no par value            The New York Stock Exchange
                                              The Toronto Stock Exchange

       Subordinated Securities, due 2043      The New York Stock Exchange
                                              The Toronto Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act.

                Yes  [x]   No [ ]

Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Exchange Act.

                Yes  [ ]   No [x]

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 large accelerated filer, an
accelerated filer, or a non-accelerated filer.

Large accelerated filer [x]   Accelerated filer [ ]  Non-accelerated filer [ ]

Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act).

                Yes  [ ]   No [x]

On June 30, 2005, the aggregate market value of the voting shares held by
non-affiliates of the registrant was approximately Cdn $9.7 billion based on
the Toronto Stock Exchange closing price on that date. On January 31, 2006,
there were 261,614,723 common shares issued and outstanding.

<PAGE>

TABLE OF CONTENTS

PART I                                                                    PAGE
  Items 1 and 2.  Business and Properties....................................2
  Item 1A.        Risk Factors..............................................26
  Item 1B.        Unresolved Staff Comments.................................26
  Item 3.         Legal Proceedings.........................................26
  Item 4.         Submission of Matters to a Vote of Security Holders.......27
PART II
  Item 5.         Market for the Registrant's Common Shares and Related
                      Stockholder Matters...................................27
  Item 6.         Selected Financial Data...................................28
  Item 7.         Management's Discussion and Analysis of Financial
                      Condition and Results of Operations...................30
  Item 7A.        Quantitative and Qualitative Disclosures About Market
                      Risk..................................................75
  Item 8.         Financial Statements and Supplementary Data...............82
  Item 9.         Changes in and Disagreements with Accountants on
                      Accounting and Financial Disclosure..................131
  Item 9A.        Controls and Procedures..................................131
PART III
  Item 10.        Directors and Executive Officers of the Registrant.......135
  Item 11.        Executive Compensation...................................139
  Item 12.        Security Ownership of Certain Beneficial Owners and
                      Management...........................................149
  Item 13.        Certain Relationships and Related Transactions...........150
  Item 14.        Principal Accountant Fees and Services...................151
PART IV
  Item 15.        Exhibits and Financial Statement Schedules...............152

SPECIAL NOTE TO CANADIAN INVESTORS -- see page 80

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.

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

/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     bcf    =    billion cubic feet
            thermal units       WTI    =    West Texas Intermediate
km     =    kilometre           NGL    =    natural gas liquid
MW     =    megawatt

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  (6mcf/1bbl).  This  conversion  may be  misleading,
particularly  if used in  isolation,  as the  6mcf/1bbl  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
----------------------------------------------------------------------------
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
2005                 0.8577          0.8253          0.8690          0.7872

On January 31, 2006, the noon-day exchange rate was US $0.8742 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,  on 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 contains our
reports, proxy and information statements and other published information that
have been filed or furnished with the SEC and the OSC.

<PAGE>

As conventional basins in North America
mature, the transition of our operations
is on track toward major projects in
established basins, exploration in
newer basins and exploitation of
unconventional resources.

see the value

operations

                                      1
<PAGE>

                                     PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

                                                                          Page
About Us.....................................................................3

Strategy.....................................................................4

Understanding the Oil and Gas Business.......................................5

Oil and Gas Operations.......................................................5
    North Sea--United Kingdom ...............................................6
    Gulf of Mexico--United States............................................8
    Canada .................................................................10
    Athabasca Oil Sands.....................................................10
    Middle East--Yemen......................................................14
    Offshore West Africa....................................................16
    Other International.....................................................17

Reserves, Production and Related Information................................17

Syncrude Mining Operations .................................................20

Oil and Gas Marketing.......................................................22

Chemicals...................................................................24

Additional Factors Affecting Business.......................................25
    Government Regulations..................................................25
    Environmental Regulations...............................................25

Employees...................................................................26

                                      2
<PAGE>

[GRAPHIC OMITTED]
[Margin Image: Western Canada]

ABOUT US

Nexen Inc. (Nexen, we or our) is an independent, Canadian-based, global energy
company.  We were formed in Canada in 1971 by the  combination of the Canadian
crude oil, natural gas, sulphur and chemical operations of two subsidiaries of
Occidental  Petroleum  Corporation  (Occidental).  We've grown from  producing
10,700 boe/d before royalties with revenues of $26 million in 1971, to 241,700
boe/d before royalties  (including  Syncrude  production) and revenues of $4.1
billion in 2005.  We achieved  this  growth  through  exploration  success and
strategic  acquisitions.  In more  than 30 years of  operations,  we have been
profitable every year,  except one, and have been paying  quarterly  dividends
consecutively since 1975.

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  continued  to  expand  in  Western  Canada  by  acquiring
Canada-Cities  Service,  Ltd. in 1983. This  acquisition  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 more than 890 million  barrels
since  start-up.  Our 1997 purchase of Wascana Energy Inc.  almost tripled our
Canadian  production.  In 1998, we entered  Australia  with an interest in the
offshore Buffalo field and Nigeria as the operator of the Ejulebe field.  Also
in 1998, we discovered Ukot on Block 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.

[Margin Text: Nexen is an independent, Canadian-based, global energy company.]

So far in the  21st  century,  we  have  made a  number  of  discoveries,  two
strategic  acquisitions and completed a non-core divestiture program. In 2000,
we  discovered  Gunnison  in the  deep-water  Gulf of  Mexico  and  Guando  in
Colombia.  That same year, we joined with Ontario Teachers' Pension Plan Board
(Teachers)  to acquire  Occidental's  remaining  29% interest in us.  Teachers
purchased 20.2 million common shares.  We repurchased the remaining 20 million
common shares for $605 million, which would have had a value of more than $2.2
billion at year-end  2005.  We also  exchanged  our oil and gas  operations in
Ecuador for  Occidental's  15%  interest  in our  chemical  operations  and we
changed our name to Nexen Inc.  from  Canadian  Occidental  Petroleum  Ltd. In
2001, we discovered  Aspen in the deep-water Gulf of Mexico and signed a joint
venture  agreement  with OPTI  Canada  Inc.  to  develop,  produce and upgrade
bitumen at Long Lake in the Athabasca oil sands. In 2002, we discovered  Usan,
the second discovery on OPL-222, offshore Nigeria. In late 2003, we discovered
two fields on Block 51 in Yemen. And in 2004, we acquired properties in the UK
North Sea, providing us with strategic  operatorship of the Buzzard discovery,
the  producing  Scott and  Telford  fields and  700,000  acres of  exploratory
acreage.

In the  third  quarter  of 2005,  we sold  Canadian  conventional  oil and gas
properties  producing  approximately  18,300 boe/d before  royalties.  We also
monetized 39% of our chemical  business through the initial public offering of
the Canexus  Income Fund.  During the year, we made a potentially  significant
discovery  in the Gulf of  Mexico  at  Knotty  Head and  commenced  commercial
development  of  our  first  coal  bed  methane  (CBM)  project  in  the  Fort
Assiniboine  area in Western Canada.  Now in 2006, we are on track to complete
major development  projects at Buzzard in the North Sea and the Syncrude Stage
3 expansion,  followed by Long Lake in the Athabasca oil sands in 2007.  These
projects  and an active  exploration  program  provide  future  growth for our
company.

[GRAPHIC OMITTED]
[Margin Graph: Revenues for 1971, 1979, 1989, 1999 and 2005 in Cdn$ millions]

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

o    oil and gas;
o    Syncrude;
o    oil and gas marketing; and
o    chemicals.

                                      3
<PAGE>

[GRAPHIC OMITTED]
[Margin Image: Gulf of Mexico drill ship]


Our oil and gas  operations are broken down  geographically  into the UK North
Sea, US Gulf of Mexico,  Canada,  Yemen and Other International  (Colombia and
offshore  West  Africa).  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, natural gas liquids 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 appear in Note 20 to the Consolidated  Financial Statements
and in Management's Discussion and Analysis of Financial Condition and Results
of Operations (MD&A) in this report.

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.  We
believe in developing targeted capabilities,  which generate opportunities and
operations  required for long-term success in our ever-evolving  industry.  As
conventional  basins  in North  America  mature,  we have  developed  specific
capabilities  in oil  sands,  coal  bed  methane,  deep-water  technology  and
international  locations.  These  enable  us to  focus  on  specific  types of
projects,  as we  transition  toward  major  projects in  established  basins,
exploration in newer basins and exploitation of unconventional resources.

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

Today, we are building new sustainable businesses in Western Canada, the North
Sea, Gulf of Mexico, Middle East and offshore West Africa, capitalizing on the
following corporate strengths:

o    We are successful  deep-water  explorers with significant  discoveries at
     Knotty Head in the Gulf of Mexico and at Usan, offshore Nigeria;
o    We are  skilled  project  managers  with major  development  projects  at
     Buzzard in the North Sea, and Long Lake in Canada's  Athabasca oil sands.
     These projects are nearing completion on time and on budget;
o    We are innovative in our application of technology. Long Lake is expected
     to be the first oil  sands  project  to use  gasification  technology  to
     significantly reduce the cost of producing bitumen;
o    We are an international operator with a proven track record of successful
     business ventures in Yemen, Colombia and Australia; and
o    We make value-oriented acquisitions.  In 2001, we purchased approximately
     15% of our own shares, and in 2004, we made a strategic entry into the UK
     North Sea.

The location and scale of our operations often result in an extended period of
time from the capture of  opportunities  to first  production  and  non-linear
year-over-year growth in reserves and production. Significant up-front capital
investment  is often  required  prior to  realizing  production  and free cash
flows.  We fund this  investment  by  maximizing  cash flow from our producing
assets,  issuing  long-term debt and selling  non-core  assets into attractive
markets.

Our  long-term   strategy   focuses  on  ensuring   sufficient   inventory  of
opportunities for future growth.  Our major development  project at Buzzard is
expected to add significant  production in late 2006, followed by Long Lake in
2007.  With these projects on stream,  we expect our net production in 2007 to
grow by more than  50%,  net of  declines.  Beyond  2007,  we have a number of
growth opportunities,  including undeveloped discoveries at Knotty Head in the
Gulf of Mexico and Usan and Ukot offshore Nigeria, together with future phases
of our oil sands projects that we plan to develop sequentially.

[Margin Text: We expect our 2007  production  after  royalties to grow by more
 than 50% over current volumes.]

In  creating  sustainable  businesses,  we are  committed  to  good  corporate
governance  and social  responsibility.  We  believe  that over the long term,
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.

                                      4
<PAGE>

[GRAPHIC OMITTED]
[Margin Image: Yemeni employee at Masila]

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 reduce these impacts by investing in projects
we believe  will  generate  positive  returns  at low  commodity  prices.  For
example,  most of our major  projects  generate  attractive  returns  with oil
prices in the mid-US$20-per-barrel range.

[Margin Text: Most of our major projects generate attractive returns with WTI
 oil prices in the mid-US$20s per barrel.]

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 some of our  products can have a seasonal
component  that can impact  price.  In  particular,  heavy oil is generally in
higher demand in the summer for its use in road construction,  and natural gas
is generally in higher demand in the winter for heating.  Our realized  prices
for our oil and gas products are mainly  determined by volatile  international
crude oil markets and by North  American gas markets and, as a result,  we are
price takers.

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

We have oil and gas operations in the UK North Sea, US Gulf of Mexico, Western
Canada,  Yemen,  offshore West Africa and Colombia. 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.

[GRAPHICS OMITTED]
[Graphic: World map showing location of oil and gas operations]
[Margin Graph: Pie chart of 2005 Production Before Royalties by region]

                                      5
<PAGE>

[GRAPHIC OMITTED]
[Margin Image: Jack-up drill rig and Buzzard
 wellhead deck]

NORTH SEA--UNITED KINGDOM (UK)

The UK is one of our key growth areas.  In 2004, 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 more than 700,000 net undeveloped  exploration acres
for US$2.1 billion. This acquisition  established us as a significant regional
player  with   concentrated   assets,   infrastructure   and  exploration  and
development  potential for future growth.  It added  high-margin  reserves and
production,  diversified our worldwide  portfolio by adding strong assets in a
stable jurisdiction, and complemented our other longer cycle-time projects.

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

At year end,  the UK had proved  reserves of 145 mmboe before  royalties  (145
mmboe after royalties)  representing about 18% of Nexen's total proved oil and
gas and Syncrude reserves.

BUZZARD DEVELOPMENT

[GRAPHICS OMITTED]
[Graphic: Buzzard production facilities drawing]
[Margin Text: Buzzard is on time and on budget with first production expected
 by late 2006.]

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,  about
60 miles northeast of Aberdeen, in 317 feet of water.

Development  of  Buzzard is on budget and on  schedule  with first  production
expected by late 2006. In 2005, we installed  three  platform  jackets and the
wellhead  deck and  tied-in  the water  injection,  gas  export and oil export
pipelines. In October 2005, we began drilling production wells. Development of
the  facilities  is  approximately  88%  complete.  In summer 2006, we plan to
install the utilities and production topsides and initiate hook-up and project
commissioning.  The  facilities  will have a capacity of 200,000 bbls/d of oil
and 60 mmcf/d of gas.  We  anticipate  the field will be  produced  through 27
production  wells,  of which eight will be pre-drilled  and available to begin
producing  by late 2006.  Reservoir  pressure  will be  maintained  through an
active  water-flood  program.  We  estimate  peak  gross  production  rates at
approximately  200,000 bbls/d of oil and  approximately 30 mmcf/d of gas, with
our share  about  85,000  boe/d  after  royalties.  Oil from  Buzzard  will be
exported via the Forties pipeline to the Grangemouth refinery in Scotland. Gas
will be  exported  via the Frigg  system to the St.  Fergus  Gas  Terminal  in
northeast Scotland.  In 2006, we plan to invest  approximately $450 million to
complete the  facilities and drill eight  production  and six water  injection
wells.

UK PRODUCTION

[Margin Text: With Buzzard production estimated to peak at 85,000 boe/d, we
 expect significant growth from the UK.]

Scott  and  Telford  are  producing   fields  with   additional   exploitation
opportunities.  Scott, in which we have a 41% working interest, was discovered
in 1987  and  began  producing  in  September  1993.  We have a 54.3%  working
interest in Telford,  which was discovered in 1991 and came on stream in 1996.
In 2005, our share of Scott and Telford royalty-free  production  approximated
16,000 boe/d, of which 80% was oil.

Oil and gas is produced  through  numerous subsea wells and from wells drilled
from the Scott  platform.  Oil is  delivered  to the  Grangemouth  refinery in
Scotland via the Forties pipeline, while gas is exported via the SAGE pipeline
to the St. Fergus terminal in northeast Scotland.  In 2005, the Scott platform
underwent a  significant  maintenance  turnaround  and  facilities  upgrade to

                                      6
<PAGE>

improve reliability and extend facility life.  Upgrades included  improvements
to electric,  produced water injection,  and drilling and metering systems. In
2006,  we plan to invest  approximately  $35 million to drill,  complete,  and
tie-in three development wells and perform workovers.

[GRAPHICS OMITTED]
[Margin Image: Locator map - North Sea]
[Graphic: North Sea map with Nexen's producing and exploration blocks.]

Our 2004 UK acquisition included a non-operated  interest in Farragon, a small
satellite  discovery,  which was brought on stream in November  2005.  At year
end, our 20% share of  royalty-free  production  from Farragon was 3,900 boe/d
and is expected to average between 3,000 and 4,000 boe/d in 2006.

EXPLORATION AND UNDEVELOPED ASSETS

In 2005, we drilled and found hydrocarbons at Polecat, Yeoman and Black Horse.
Although  the   hydrocarbons   discovered  at  Polecat  and  Black  Horse  are
insufficient to warrant stand alone development,  these wells may form part of
a future  larger  development  plan for the area.  We have a number of smaller
discoveries on operated blocks near Scott, Buzzard and third-party  facilities
as follows:

<TABLE>
<CAPTION>
Field             Interest (%)  Operator Status   Comments
-----------------------------------------------------------------------------------------------------------
<S>               <C>           <C>               <C>
Ettrick           80            operated          sanctioned in February 2006 for development
Bugle             82            operated          discovery near Scott; evaluating development alternatives
Duart             50            non-operated      discovery near Scott; evaluating development alternatives
Dolphin           42            operated          discovery near Scott; evaluating development alternatives
Perth             42            operated          discovery near Scott; evaluating development alternatives
Selkirk           38            operated          evaluating development alternatives
Yeoman            50            operated          discovery near Scott; evaluating development alternatives
</TABLE>


[Margin Text: Ettrick will be developed using a floating production facility
 and is expected to begin production in early 2008.]

We recently  announced our plans to develop the Ettrick field,  which includes
drilling three  production wells tied back to a floating  production,  storage
and  offloading  vessel.  The field is expected to begin  production  in early
2008,  with our  share  reaching  approximately  16,000  boe/d.  Our  share of
full-cycle  development costs are estimated at $460 million with approximately
$90 million  invested in 2006. The other  discoveries are in various stages of
evaluation.

During 2005, we drilled the Saracen and  Bennachie  exploration  wells,  which
encountered  noncommercial  hydrocarbons and were abandoned. We also increased
our land  acreage  by  approximately  388,000  acres  to  support  our  future
exploration  activity.  We expect to drill four exploration wells in 2006. The
offshore  drilling rig market is  currently  tight,  however,  we have secured
drilling  rigs for most of our 2006  North  Sea  exploration  and  development
program.

FISCAL TERMS

[Margin Text: With royalty-free production, the UK offers favourable fiscal
 terms.]

UK fiscal terms are favorable.  New discoveries pay no royalties and result in
cash  netbacks that are higher than our company  average.  Scott is subject to
Petroleum  Revenue Tax (PRT),  although no PRT is payable until  available oil
allowances  have been fully  utilized,  which isn't expected 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. Buzzard,  Telford and Farragon fields
are not subject to PRT. 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%, although in a
recent pre-budget announcement,  the UK government said it intends to increase
this to 20%,  effective  January  1,  2006.  This  increase  is subject to the
introduction  of  legislation.  The amount and timing of income taxes  payable
depends on many factors  including  price,  production and capital  investment
levels.

                                      7
<PAGE>

GULF OF MEXICO--UNITED STATES (US)

[GRAPHICS OMITTED]
[Margin Image: Gunnison SPAR]
[Margin Image: Locator map - Gulf of Mexico]


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

The  Gulf  of  Mexico  is an  integral  part  of our  growth  strategy.  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  sands and high  production  rates,  factors  which  reduce  risk and
improve  economics.  Technology to find,  drill,  and develop  discoveries  is
rapidly  progressing and becoming more cost effective.  The deep-water Gulf is
relatively  near   infrastructure   and   continental  US  markets,   enabling
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
upside potential and exploit our existing asset base. We focus our exploration
program on three strategic play types:

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  plays  are   relatively   under-explored,   hold  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.  Although competition in the
Gulf is strong, a lot of expiring acreage becoming available over the next few
years may provide us access to additional exploration opportunities.

In 2005, we invested $362 million on exploration and development activities in
the Gulf. This resulted in a number of discoveries,  including  Knotty Head, a
large,  four-way  dip  closure  in the  Miocene  sub-salt  play.  Knotty  Head
showcases  the  potential in the Gulf,  as it has the  potential to be a major
discovery.  In 2006, we plan to invest  approximately $500 million in the Gulf
to further our strategy.

US PRODUCTION

[Margin Text: We have more than 240 blocks in the deep-water Gulf of Mexico,
 one of the world's most prospective sources for oil and gas.]

<TABLE>
<CAPTION>
                                 2005                         2004                         2003
                     --------------------------- ---------------------------- ----------------------------
                           Before         After         Before         After         Before         After
(mboe/d)                Royalties     Royalties      Royalties     Royalties      Royalties     Royalties
------------------------------------------------ ---------------------------- ----------------------------
<S>                  <C>           <C>            <C>           <C>            <C>           <C>
Deep-water                   24.0          21.5           32.1          28.7           24.0          21.7
Shallow-water                17.6          14.6           22.6          18.8           28.5          23.7
------------------------------------------------ ---------------------------- ----------------------------
Total                        41.6          36.1           54.7          47.5           52.5          45.4
================================================ ============================ ============================
</TABLE>

In 2005, we produced approximately 41,600 boe/d before royalties (36,100 after
royalties), even after weather-related disruptions.  This represents about 17%
of  Nexen's  total  production.  Weather  is a risk  in the  Gulf  of  Mexico:
specifically  tropical storms and hurricanes can damage  facilities,  drilling
rigs  and  surrounding   infrastructure,   interrupt  production,   and  delay
exploration  and  development   programs.  In  2005,  hurricanes  reduced  our
production by approximately 6,000 boe/d before royalties. Although we received
minor damage at two of our facilities, by year end we were producing at 92% of
our full  potential.  We expect to be back to full  production by mid 2006. We
carry property and business  interruption  insurance to mitigate losses caused
by adverse weather.

At year end, we had proved  reserves of 90 mmboe  before  royalties  (77 mmboe
after  royalties)  representing  about 11% of Nexen's total proved oil and gas
and Syncrude  reserves.  Our production and reserves in the Gulf are primarily
concentrated in two deep-water and five shallow-water  fields. We operate most
of this production.

                                      8
<PAGE>

[GRAPHIC OMITTED]
[Margin Image: Discoverer Spirit drill ship at Knotty Head]

DEEP-WATER PRODUCTION

Our deep-water  production  comes from our  100%-operated  Aspen field and 30%
non-operated  Gunnison field. Aspen is 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, and we achieved  payout on our full investment in Aspen in January 2005.
Our share of 2005 production before royalties was  approximately  14,300 boe/d
(13,000  after  royalties).  Production  declined  during the year  because of
increased  water cuts. In 2006, we plan to drill another  development  well to
access potential stranded reserves.

Gunnison is in 3,100 feet of water,  and includes Garden Banks Blocks 667, 668
and 669.  Gunnison  began  production  in December 2003 through our truss SPAR
platform  that can  handle  40,000  bbls/d of oil and 200  mmcf/d  of gas.  We
achieved  payout on  Gunnison  in  December  2005,  just two years after first
production.  In  2005,  we tied in one  development  well,  and our  share  of
production  before  royalties  was  approximately  9,700  boe/d  (8,500  after
royalties). Our Gunnison SPAR production facility has excess capacity, leaving
room for growth from  exploration  and processing of third-party  volumes.  In
2006,  we plan to complete  and tie-in our 15%  non-operated  2004 Dawson Deep
discovery to the Gunnison SPAR.

[GRAPHIC OMITTED]
[Margin Text: Gunnison and Aspen both achieved payout in just over two years
 after first production.]

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  302/321,  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  2005  shelf  activities  focused  on  development
drilling at Vermilion 76 and 321.

EXPLORATION AND UNDEVELOPED ASSETS

In 2005, our  exploration  program  produced strong results with a potentially
significant  discovery at Knotty Head and several other  smaller  discoveries.
Our undeveloped discoveries include:

<TABLE>
<CAPTION>
Well              Interest (%)   Operator Status   Comments
----------------------------------------------------------------------------------------------
<S>               <C>            <C>               <C>
Anduin            50             operated          appraisal drilling planned in 2006
Big Bend          50             non-operated      expected to complete the well in 2007
Dawson Deep       15             non-operated      expected to begin producing in 2006
Knotty Head       25             operated          appraisal drilling ongoing in 2006
Wrigley           50             non-operated      expected to begin producing in 2006
Tobago            10             non-operated      expected to begin producing in 2009 or 2010
</TABLE>


[Margin Text: We have a potentially significant discovery at Knotty Head.]

During the year, we drilled dry holes at Castleton and Vrede and increased our
deep-water  undeveloped  land  position  by 95 blocks to over 240  blocks.  We
expect this acreage and future  exploration  opportunities to position us well
for continued growth. In 2006, we plan to tie-in our 2004 Wrigley discovery to
a third-party facility and drill appraisal wells at Knotty Head and Anduin. We
also plan to drill eight  exploration  wells (five in the deep water and three
in the deep shelf).  Wells  currently  drilling  with results  expected in the
first half of 2006 include  Pathfinder and the Knotty Head sidetrack.  We have
drilling  rigs secured for the majority of our 2006  drilling  program and are
actively  working with  partners to find rigs for the  remainder.  We recently
committed to a deep-water drilling contract,  which provides us with access to
a new-build fifth generation dynamically positioned  semi-submersible drilling
rig for two years over a three-and-a-half  year period. We expect this new rig
to be available in mid 2009.

FISCAL TERMS

Royalty rates on our US production  average 17% for shallow-water  volumes and
10% for deep-water volumes. The fiscal terms are attractive, as we qualify for
royalty relief at our deep-water  Aspen and Gunnison  fields on the first 87.5
mmboe of  production.  However,  we are  subject to  royalties  at Gunnison if
annual  commodity  prices  are  higher  than  threshold  prices  set by the US
Department of the Interior's Minerals  Management Service. In 2005,  commodity
prices  exceeded these  thresholds,  and we were subject to a 12.5% royalty at
Gunnison.  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%.

                                      9
<PAGE>

[GRAPHIC OMITTED]
[Margin Image: Locator Map - Canada]

CANADA

[GRAPHICS OMITTED]
[Graphic: Map of Western Canada showing Nexen areas of operations.]
[Margin Text: In Canada, we are transitioning toward unconventional resources,
 including oil sands, CBM and EOR.]

Our strategy in Canada is to bring our new growth developments into production
while we maximize value from our established operations.  In the third quarter
of 2005, we disposed of approximately  18,300 boe/d of production,  comprising
approximately  60% oil and 40% gas,  and  realized  proceeds  of $900  million
(after closing adjustments).  The assets we retained have upside potential for
continued conventional  development and enhanced recovery with advancements in
extraction  technology.  During the year,  we  produced  49,900  boe/d  before
royalties  (39,400 after  royalties),  which was  approximately 21% of Nexen's
total  production.  At year end 2005,  proved  reserves  of 117  mmboe  before
royalties  (101 mmboe after  royalties)  were  approximately  15% of our total
proved oil and gas and Syncrude reserves.

Our remaining Canadian  conventional assets comprise heavy oil in east-central
Alberta and  west-central  Saskatchewan,  and natural gas near  Calgary and in
southern Alberta and Saskatchewan. We operate most of our producing properties
and hold 1.1 million net acres of  undeveloped  land  across  Western  Canada.
These assets  provide  predictable  production  volumes and earnings  while we
advance the following initiatives for future growth:

o    Athabasca oil sands--to produce and upgrade bitumen into synthetic
     crude;
o    enhanced oil recovery (EOR)--to increase recovery in our heavy oil
     fields; and
o    coal bed methane (CBM)--to extract natural gas primarily from Upper
     Mannville coals.

In 2005, we invested  $1,054  million in Canada,  $776 million in these growth
initiatives.  In 2006, we plan to invest  approximately  $1,170 million,  $800
million in these initiatives.

ATHABASCA OIL SANDS

[GRAPHIC OMITTED]
[Graphic: Alberta map of Nexen bitumen acreage]
[Margin Text: Our oil sands strategy is to economically develop our bitumen
 resource in phases to provide low-risk, stable, future growth.]

The Athabasca  oil sands in northeast  Alberta is a key growth area for Nexen.
Our  strategy is to  economically  develop  our bitumen  resource in phases to
provide  low-risk,  stable,  future  growth.  Our Long Lake  project  involves
integrating  bitumen  production with field upgrading  technology to produce a
premium  synthetic crude oil that  significantly  reduces our need to purchase
natural gas. It also  includes our 7.23%  investment in the Syncrude oil sands
mining operation.

LONG LAKE PROJECT

In 2001,  we formed a 50/50 joint  venture  with OPTI  Canada  Inc.  (OPTI) to
develop the Long Lake property  using  steam-assisted-gravity-drainage  (SAGD)
for bitumen production and field upgrading using the proprietary  OrCrude(TM);
process. OrCrude(TM) is a technology to which OPTI has the exclusive Canadian

                                      10
<PAGE>

license.  We acquired the exclusive right to use this  technology,  with OPTI,
within  approximately  100  miles  of  Long  Lake,  and the  right  to use the
technology independently elsewhere in the world.

We  operate  the  Long  Lake  lease  and  are  responsible  for  constructing,
developing  and operating the SAGD  project.  OPTI will design,  construct and
operate the upgrader. We share equally in all project production and operating
and capital costs.

[GRAPHIC OMITTED]
[Margin Image: Long Lake pilot project]

SAGD AND UPGRADER INTEGRATION

SAGD involves drilling two parallel horizontal wells,  generally between 2,300
and 3,300  feet  long,  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.

The OrCrude(TM)  technology,  using  distillation,  solvent  de-asphalting and
thermal cracking,  separates the produced 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* API)  premium  synthetic  sweet crude oil,  and the
asphaltenes  are  converted to a low-energy,  synthetic  fuel gas. This gas is
available as a low-cost fuel source,  and as a source for hydrogen required in
the  hydrocracker.  The gas will also be burned  in a  co-generation  plant to
produce steam for the SAGD  operations and for  electricity to be used on-site
and sold to the electric grid. The energy  conversion  efficiency for our Long
Lake  upgrader is about 90% compared to 75% for a typical  bitumen-fed  coker,
which provides us with a 50% margin advantage.

[Margin Text: Long Lake is on time and on budget with synthetic crude oil
 production expected on stream in 2007.]
[Graphic: schematic of SAGD and Upgrader with OrCrude(TM) upgrading process]

OUR STRATEGIC ADVANTAGE

[Margin Text: Our integrated upgrading strategy enables us to upgrade bitumen
 into high-value premium synthetic crude.]

Our SAGD and upgrading  integration enables us to overcome three main economic
hurdles of SAGD  bitumen  production:  1) the high cost of natural gas; 2) the
cost of diluent; and 3) the realized price of bitumen. With synthetic gas from
the asphaltenes as a fuel source,  we have little need to purchase  additional
natural gas. With the upgrading  facilities on site,  expensive diluent is not
required to transport  the bitumen to market.  And, by  upgrading  the bitumen
into a highly desirable  refinery feedstock or diluent supply, the end product
commands light-sweet crude oil premium pricing.

PROJECT MILESTONES AND COSTS

The  Long  Lake  project  is on time and on  budget.  It  received  regulatory
approval in 2003 and Nexen Board approval in 2004.  Field  construction on the
SAGD and upgrader  facilities  began in 2004. In 2005, we continued module and
site  construction  and  completed  drilling  78  SAGD  well-pairs.   Detailed
engineering and purchasing of major equipment is substantially  complete, with
pricing largely as expected.  Module construction of the SAGD is 87% complete,
and  site  construction  is 43% complete.  Module construction of the upgrader
is  64%  complete  and  site  construction  is  32%  complete.   Approximately

                                      11
<PAGE>

[GRAPHIC OMITTED]
[Margin Image: Long Lake SAGD slant drilling rig]

69% of the  project's  total costs are  committed.  The major  remaining  cost
uncertainty  relates to labour access and productivity.  First steam injection
is scheduled to begin in late 2006,  with upgrader  start-up  scheduled in the
second half of 2007. We expect peak gross  synthetic  crude oil  production to
reach  about  60,000  bbls/d  before  royalties  and be  maintained  over  the
project's life,  estimated at 40 years, by  periodically  drilling  additional
SAGD well-pairs.

Combined  SAGD,  cogeneration  and upgrading  operating  costs are expected to
average  between  $11/bbl  and  $13/bbl,   substantially   lower  than  coking
upgrading. In 2005, we invested $743 million at Long Lake and expect to invest
approximately  $650 million in 2006. Total project costs are estimated at $3.8
billion  ($1.9 billion our share),  which  includes $250 million ($125 million
our share) to increase  the  capability  of the steam  generating  facility to
ensure  adequate  bitumen  supply  as we fully  develop  the  reservoir.  This
expansion  will  enable us to  operate  at a steam oil ratio of up to 3.3.  In
optimizing  the value from the project,  we will also  construct a facility to
concentrate  soot produced by the gasifier and thereby reduce  disposal costs.
This facility is expected to cost  approximately $110 million ($55 million our
share).  We expect ongoing capital to average  between $2/bbl and $4/bbl.  The
capital  costs of producing and upgrading  bitumen using this  technology  are
comparable   to  those  for  surface   mining  and  coking   upgrading   on  a
barrel-of-daily production basis.

RESERVES RECOGNITION

[Margin Text: We have not yet recognized any proved bitumen reserves for
 Long Lake.]

Under SEC rules and regulations, we are required to recognize bitumen reserves
rather than the upgraded premium  synthetic crude oil that we will produce and
sell. The economic  recoverability of bitumen reserves is sensitive to natural
gas  prices,  diluent  costs and  light/heavy  differentials,  risks  that our
project has been designed to eliminate.  At December 31, 2005 and 2004,  these
factors  made  bitumen  production  uneconomic  and,  therefore,  we  did  not
recognize any proved bitumen reserves.  Under Canadian standards,  we would be
permitted to recognize  200 mmbbls of  high-value  proved  synthetic  reserves
before royalties (198 mmbbls after royalties) for our Long Lake project.

FUTURE PHASES

[Margin Text: By duplicating Long Lake in phases, we plan to increase our
 synthetic crude oil production to 120,000 bbls/d by 2016.]

We have 214,000 net acres of  bitumen-prone  lands in the Athabasca region and
plan to continue  acquiring  more. We plan to continue  developing our bitumen
lands in a phased manner using our integrated upgrading strategy.  In 2005, we
announced our plan to duplicate  Long Lake by developing  Phase 2. In 2006, we
will invest  approximately  $100 million in additional  drilling,  seismic and
engineering  to develop our leases and  advance  regulatory  applications  for
future  phases.  Phase 2 SAGD  production  is expected to be on stream by late
2010 with upgrader start-up by the second half of 2011, followed by additional
phases  every  two  years or so.  Each  subsequent  phase  will  leverage  the
knowledge and experience gained from successfully  developing Long Lake and be
similar in size and design to Long Lake. By keeping the core team in place and
repeating  and  improving on existing  designs and  implementation  plans,  we
expect to gain  efficiencies in engineering,  modular  fabrication and on-site
construction.  We also anticipate  enhanced  operating  efficiencies as we can
train and move people easily between the various plants.

HEAVY OIL

Approximately  54% 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  east-central  Alberta  and  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  are  advantageous  to us in managing these costs. In
2006, we plan to continue  exploiting our existing fields through drilling and
optimizing operations.

ENHANCED OIL RECOVERY

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

                                      12
<PAGE>

[GRAPHIC OMITTED]
[Margin Image: CBM pumpjack at Corbett]

new technology.  We are continuing to research various technologies to enhance
our  heavy  oil  recovery   with  ongoing  pilot   projects  in   west-central
Saskatchewan.

NATURAL GAS

Approximately 46% of our Canadian production is natural gas produced primarily
from shallow sweet  reservoirs in southern  Alberta and  Saskatchewan and from
deep sour gas reservoirs near Calgary.

Shallow gas is natural gas  produced  from shallow  sand  formations  yielding
low-pressure sweet gas. In general, shallower gas targets are cheaper to drill
and develop,  but have relatively  smaller reserves and lower productivity per
well.  Sour gas is natural gas that contains  hydrogen  sulfide.  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.

COAL BED METHANE

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.  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.

Our CBM pilot at Corbett in the Fort  Assiniboine  area of central Alberta has
established  techniques  to produce  natural  gas from water  saturated  Upper
Mannville  coals.  These coals are generally  deeper than the Horseshoe Canyon
"dry coal" play which is also being  commercially  developed  in  Alberta.  We
established  commerciality  of CBM production from the Mannville coals in 2005
by  applying  horizontal  well  technology.  Commercial  production  rates and
reduced de-watering time has enabled us to confidently develop these coals.

[Margin Text: We are developing the first commercial CBM project in the
 Mannville coals.]

In 2005, we approved commercial CBM developments at Corbett, Doris and Thunder
in the Fort  Assiniboine  area.  At the end of 2005, we held more than 600 net
sections of land in Alberta with CBM potential, some of which overlay existing
conventional  producing  lands.  We have also  established  positions in other
prospective  CBM areas of Alberta.  In 2006, we plan to invest $150 million to
develop 115 gross (53 net)  sections  using  single and  multi-leg  horizontal
wells.

In  addition  to our  development  at Fort  Assiniboine,  we will  continue to
evaluate other Mannville and Horseshoe Canyon CBM prospects and pursue new CBM
opportunities in 2006. In 2005, we invested  approximately  $83 million in CBM
to commence commercial development at Corbett, Thunder and Doris and build and
evaluate our CBM acreage position.

FISCAL TERMS

In Canada,  we pay royalties  ranging from 15% to 40% on production from lands
owned by the federal and  provincial  governments.  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 that are subject to crown  royalties of 3.6% that is reduced to
2.0% for wells 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.

For our oil sands projects, we will pay royalties based on bitumen production,
which  includes  a 1%  royalty  on gross  revenue  until all  costs  have been
recovered at which time the royalty  reverts to 25% on net  revenue.  With the
combination  of low  royalties,  our  operating  cost  advantage and a premium
product, our oil sands financial returns are expected to be attractive.

                                      13
<PAGE>

[GRAPHIC OMITTED]
[Margin Image: Locator Map - Yemen]

MIDDLE EAST--YEMEN

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

Yemen has been our most significant  international region since we first began
production at Masila in 1993. We operate the country's largest oil project and
have  developed   excellent   relationships  with  the  government  and  local
communities.  Our success and reputation in Yemen open doors  elsewhere in the
Middle East and around the world.

Our  strategy  is to maximize  the value from our  existing  blocks,  while we
continue to search for new fields in deeper  horizons.  We have two  producing
blocks:  Masila  (Block 14) and East Al Hajr (Block 51). In 2005,  we produced
112,700 bbls/d of oil before royalties (60,600 after royalties),  representing
approximately 39% of 2005 cash flow.

Proved  reserves of 105 mmboe  before  royalties  (59 mmboe  after  royalties)
comprise  approximately  13% of Nexen's  total proved oil and gas and Syncrude
reserves.

MASILA BLOCK (BLOCK 14)

[Margin Text: Although our Masila fields have matured, we expect to generate
 approximately 33% of the total project cash flow from the remaining proved
 reserves.]

We have a 52% working interest in and operate the Masila project. Our share of
2005 production was 87,100 bbls/d before royalties  (43,200 after  royalties).
After  more than 10 years of growth,  our  Masila  fields  have  matured,  but
significant  value  still  remains.  As a  result  of the  Production  Sharing
Agreement  (PSA)  terms that  govern  Masila  production,  we still  expect to
generate  approximately  33% of the total project cash flow from the remaining
proved reserves.

The first  successful  Masila  exploratory  well was drilled at Sunah in 1990,
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* 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.

Production is collected at our Central  Processing  Facility (CPF) where water
is  separated  for  reinjection  and oil is  pumped  to the Ash  Shihr  export
terminal and shipped to customers primarily in Asia.

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

We are  managing  the pace of our  drilling  program to ensure we recover  the
remaining reserves in the most efficient,  cost-effective  manner. In 2006, we
plan to invest  approximately $95 million to drill  approximately 30 wells and
test deeper horizons where we have had recent success.

The PSA governing Masila  production was 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,

                                      14
<PAGE>

[GRAPHIC OMITTED]
[Margin Image: Ash Shihr Terminal]

and operating costs that 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 that is 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 the impact on Partners'  cash flows during periods of low
prices,  as we recover our costs first and then share any remaining profit oil
with the  Government.  At current  production,  the  Government is entitled to
approximately  72% of the profit oil,  which  includes a  component  for Yemen
income taxes payable by the Partners at a rate of 35%. In 2005,  the Partners'
share  of  Masila   production,   including   recovery  of  past  costs,   was
approximately 37%.

EAST AL HAJR BLOCK (BLOCK 51)

[Margin Text: In its first full year of operation, Block 51 averaged 25,600
 bbls/d in 2005.]

We have an 87.5% working interest and operate Block 51. This block is governed
by a PSA between the  Government of Yemen and the Partners:  The Yemen Company
(TYCO) (12.5% carried  working  interest) and Nexen (87.5% working  interest).
Under  the  PSA,   TYCO  has  no  obligation  to  fund  capital  or  operating
expenditures.  For purposes of accounting  and recording of reserves,  we have
determined TYCO's 12.5% participating interest is a royalty interest, and that
our effective  interest is 100%. We recognize both the Government's  share and
TYCO's  share of profit oil under the PSA as  royalties  and taxes  consistent
with our treatment of our Masila  operations.  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 volumes.  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 after
royalties, 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%. In 2005, the Partners'  share of Block 51  production,  including
recovery of past costs, was approximately 61%.

[GRAPHIC OMITTED]
[Graphic: schematic of East Al Hajr PSA]

The first successful exploratory well was drilled at BAK-A in 2003, with BAK-B
discovered  shortly after.  Block 51 development  began in 2004 and includes a
CPF, gathering system and a 22-km tieback to our Masila export pipeline. Early
production began in November 2004 with 2005 production of 25,600 bbls/d before
royalties (17,400 bbls/d after royalties).

In 2005, we drilled four  exploration  wells on the block that were abandoned.
In 2006, we plan to invest  approximately $100 million to drill 17 development
wells and continue exploring with three exploration wells.

                                      15
<PAGE>

[GRAPHIC OMITTED]
[Margin Image: Locator Map - Offshore West Africa]

OFFSHORE WEST AFRICA

[GRAPHICS OMITTED]
[Graphic: Map of offshore West Africa showing Nexen discoveries, prospects,
 wells drilled and exploration blocks]

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.

In 2005, we invested $47 million of capital offshore West Africa and expect to
invest approximately $55 million in 2006.

NIGERIA

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
-----------------------------------------------------------------------------------------------------------
<S>        <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
2005      Usan-7    9 km southwest of discovery   confirmed an eastern extension of the field
2005      Usan-8    3 km southwest of discovery   confirmed an eastern extension of the field
</TABLE>


[Margin Text: Appraisal of Usan is complete, and a preliminary field
 development plan is awaiting approval from the Nigerian government.]

The Usan-7 and Usan-8  appraisal  wells were  successfully  drilled during the
year.  Appraisal  of this  field  is now  complete,  and a  preliminary  field
development  plan has been  submitted  to Nigerian  governmental  agencies for
approval.  The plan features a multi-well  development  of Usan connected to a
two-million- barrel floating production,  storage and offloading vessel (FPSO)
by subsea  flowlines  and  risers.  The peak  design  capacity  of the FPSO is
160,000 bbls/d.

In 2005, we drilled the deep-water  Efere well. This well was unsuccessful and
the capital costs were expensed.

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.  In 2004, we
drilled a well on the Ameena prospect and did not find hydrocarbons.  In 2006,
we plan to conduct geological and geophysical  studies to further evaluate the
block.

BLOCK OML-109--EJULEBE

Ejulebe  production  averaged  200 bbls/d for the year.  In June,  we sold our
assets and terminated our contractual interest in this block.


                                      16
<PAGE>

[GRAPHIC OMITTED]
[Margin Image: Drilling rig on OPL-222, offshore Nigeria]

EQUATORIAL GUINEA--BLOCK K

In 2003,  we acquired a 25% operated  interest in Block K, a deep-water  block
located 100 km off- shore Equatorial Guinea. This interest was later increased
to 50%.  In 2004  and  2005,  we  drilled  two  exploration  wells  and  found
non-commercial  quantities  of  hydrocarbons.  In  2006,  we  plan  to  make a
recommendation to the partners on future participation in this block.

OTHER INTERNATIONAL

COLOMBIA

BOQUERON BLOCK--GUANDO

In  2000,  we made our  first  discovery  at  Guando  on our 20%  non-operated
Boqueron Block.  Boqueron is in the Upper Magdalena Basin of central Colombia,
approximately 45 km southwest of Bogota. Our share of 2005 production averaged
5,400 bbls/d before  royalties  (5,000 after  royalties),  about 2% of Nexen's
total production.

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

EXPLORATION BLOCKS

We are assessing  potential  drilling  opportunities on our interests in three
other exploration blocks in the Upper Magdalena Basin. Villarrica was acquired
in 2000, El Queso in 2003 and Boqueron Deep in 2003. In 2005, we  relinquished
the Villarrica  Block and acquired the  Villarrica  Norte Block under improved
fiscal terms. In 2006, we plan to drill three exploration wells.

AUSTRALIA--BUFFALO

Field abandonment began in November 2004 and was completed in 2005.

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  OIL AND GAS  OPERATIONS
(INCLUDING SYNCRUDE)

<TABLE>
<CAPTION>
(Cdn$ millions)                                               2005        2004        2003
-------------------------------------------------------------------------------------------
<S>                                                     <C>         <C>         <C>
Conventional Crude Oil and Natural Gas Liquids (NGLs)        2,438       1,697       1,449
Synthetic Crude Oil                                            397         321         240
Natural Gas                                                    671         534         547
-------------------------------------------------------------------------------------------
Total                                                        3,506       2,552       2,236
===========================================================================================
</TABLE>


[Margin Text: Crude oil and NGLs represent about 81% of our oil and gas net
 sales.]

Crude oil (including  synthetic  crude oil) and natural gas liquids  represent
approximately  81% of our oil and gas net sales,  while natural gas represents
the remaining 19%.

                                      17
<PAGE>

[GRAPHIC OMITTED]
[Margin Image: Masita Block, Yemen]

SALES PRICES AND PRODUCTION COSTS (EXCLUDING SYNCRUDE)

<TABLE>
<CAPTION>
                                      Average Sales Price (1)                 Average Production Cost (1)
                           --------------------------------------- ---------------------------------------
                                   2005         2004         2003          2005         2004         2003
------------------------------------------------------------------ ---------------------------------------
<S>                         <C>          <C>          <C>           <C>          <C>          <C>
Crude Oil and NGLs
(Cdn$/bbl)
  Yemen                           62.07        47.59        39.45          6.75         5.64         4.37
  Canada (2)                      40.51        36.60        32.37         14.01        11.76        10.00
  United States                   57.63        46.60        37.68          7.33         6.09         5.08
  United Kingdom                  60.55        46.81            -         14.90         8.26            -
  Australia (2)                       -        51.22        43.14             -        35.73        20.21
  Other Countries                 59.96        43.07        38.22          6.08         4.09         9.01


Natural Gas (Cdn$/mcf)
  Canada (2)                       7.51         5.76         5.64          0.95         0.85         0.65
  United States                   10.56         7.89         8.16          1.22         1.02         0.89
  United Kingdom                   7.86         8.28            -          2.48            -            -
------------------------------------------------------------------ ---------------------------------------
</TABLE>

Notes:
1    Sales prices and unit production  costs are calculated  using our working
     interest production after royalties.
2    Includes  results  of  discontinued  operations.  (See  Note  14  to  our
     Consolidated Financial Statements.)

PRODUCING OIL AND GAS WELLS

<TABLE>
<CAPTION>
                                                                        2005
                            -----------------------------------------------------------------------------------------------
                                         Oil                             Gas                            Total
---------------------------------------------------------------------------------------------------------------------------
(number of net wells)             Gross (1)         Net (2)       Gross (1)        Net (2)       Gross (1)         Net (2)
---------------------------------------------------------------------------------------------------------------------------
<S>                         <C>             <C>             <C>            <C>             <C>             <C>
United States                       198              89             195            135             393             224
Yemen                               400             220               -              -             400             220
United Kingdom                       33              14               -              -              33              14
Canada                            2,321           1,625           2,457          2,161           4,778           3,786
Colombia                             79              17               -              -              79              17
---------------------------------------------------------------------------------------------------------------------------
Total                             3,031           1,965           2,652          2,296           5,683           4,261
===========================================================================================================================
</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.

OIL AND GAS ACREAGE

<TABLE>
<CAPTION>
                                                                2005
                           -------------------------- -------------------------- --------------------------
                                    Developed                Undeveloped (1)               Total
----------------------------------------------------- -------------------------- --------------------------
(thousands of acres)              Gross          Net         Gross          Net         Gross          Net
----------------------------------------------------- -------------------------- --------------------------
<S>                         <C>          <C>           <C>          <C>           <C>          <C>
United States                       183          103         1,445          606         1,628          709
Yemen (2)                            50           29           756          628           806          657
Nigeria (2, 3)                        -            -           510          114           510          114
Equatorial Guinea                     -            -         1,106          553         1,106          553
Canada                              702          531         2,120        1,109         2,822        1,640
Colombia (4)                          1            -           604          463           605          463
United Kingdom                       83           27         1,851          963         1,934          990
----------------------------------------------------- -------------------------- --------------------------
Total                             1,019          690         8,392        4,436         9,411        5,126
===================================================== ========================== ==========================
</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 joint venture agreement.
4    The acreage is covered by an association contract.


                                      18
<PAGE>

DRILLING ACTIVITY

<TABLE>
<CAPTION>
                                                                2005
                         ----------------------------------- ----------------------------------- -----------
                                    Net Exploratory                     Net Development             Total
------------------------------------------------------------ ----------------------------------- -----------
(number of net wells)      Productive  Dry Holes      Total    Productive  Dry Holes      Total
------------------------------------------------------------ ----------------------------------- -----------
<S>                       <C>          <C>        <C>         <C>          <C>        <C>         <C>
United States                       -        0.6        0.6           7.2        1.0        8.2         8.8
United Kingdom                    0.5        2.1        2.6           1.5          -        1.5         4.1
Yemen                             0.5        4.6        5.1          33.0        1.6       34.6        39.7
Nigeria                           0.4        0.2        0.6             -          -          -         0.6
Canada                           32.2        8.0       40.2         198.9        0.5      199.4       239.6
Colombia                            -          -          -           1.8          -        1.8         1.8
Equatorial Guinea                   -        0.5        0.5             -          -          -         0.5
------------------------------------------------------------ ----------------------------------- -----------
Total                            33.6       16.0       49.6         242.4        3.1      245.5       295.1
============================================================ =================================== ===========
</TABLE>

<TABLE>
<CAPTION>
                                                                2004
                         ----------------------------------- ----------------------------------- -----------
                                    Net Exploratory                     Net Development             Total
------------------------------------------------------------ ----------------------------------- -----------
(number of net wells)      Productive  Dry Holes      Total    Productive  Dry Holes      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             Total
------------------------------------------------------------ ----------------------------------- -----------
(number of net wells)      Productive  Dry Holes      Total    Productive  Dry Holes      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>

WELLS IN PROGRESS

At December 31, 2005, we were drilling 7 wells in the United States (4.0 net),
15 wells in Canada (8.6 net),  4 wells in Yemen (3.0 net),  1 well in Colombia
(0.2 net), and 2 wells in the UK (0.8 net).


                                      19
<PAGE>

[GRAPHIC OMITTED]
[Margin Image: Locator Map - Syncrude Mining Operations]

SYNCRUDE MINING OPERATIONS

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

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*  API),  sweet,
synthetic crude oil.

The Syncrude  operation  exploits a portion of the Athabasca oil sands deposit
that 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 percent by weight and ore bearing sand  thickness
of 100 to 160 feet.

Syncrude's operations are on eight leases (10, 12, 17, 22, 29, 30, 31, and 34)
covering 258,000 hectares, 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 260 million tons of oil sands per year and about 146
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 2005, the upgrading  process yielded 0.85 barrels
of synthetic crude oil per barrel of bitumen.

[Margin Text: The high quality of Syncrude's synthetic crude oil typically
 means it is sold at a premuim to WTI.]

The high quality of Syncrude's  synthetic crude oil typically means it is sold
at a premium to WTI. In 2005, about 49% of the synthetic crude oil was sold to
Edmonton  area  refineries,  and the  remaining  51% 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 at  Syncrude  and owned by the  Syncrude
participants.

Since operations  started in 1978,  Syncrude has shipped more than 1.6 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.

At year-end 2005, our total  investment in the property,  plant and equipment,
including surface mining facilities,  transportation  equipment, and upgrading
facilities,  was approximately  $1.2 billion.  Based on development plans, our
share of future  expansion  and equipment  replacement  costs over the next 35
years is expected to be about $1.5 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 license
permits Syncrude to mine oil sands and produce

                                      20
<PAGE>

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 of 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.  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 2005,  Syncrude was subject to
the minimum 1% gross royalty.  In 2006, we expect to complete full recovery of
allowed  capital costs and, as a result,  we expect  Syncrude  royalties to be
assessed at 25% of net revenues.

[Margin Text: Syncrude's Stage 3 expansion was substantially complete at year
 end and will add 8,000 bbls/d of production capacity to us in 2006.]

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. With higher engineering, manufacturing and construction costs,
the  estimated  costs of the Stage 3 expansion  have  increased  from  initial
estimates of $4.1 billion to $8.4 billion.  Nexen's share of the project costs
is $600  million,  of which $568  million had been  incurred by year end 2005.
Activities  in 2006 are  focused on  completion  and  start-up  of the Stage 3
expansion and base plant maintenance. Our share of capital spending in 2006 is
expected to be $80 million.

In 2005,  Syncrude's  production of marketable synthetic crude oil was 214,000
bbls/d.  Nexen's share was 15,500 bbls/d before royalties (15,300 bbls/d after
royalties).

The following table provides some operating statistics for Syncrude operations:

                                                     2005       2004       2003
--------------------------------------------------------------------------------
Total Mined Volume (1)
  Millions of Tons                                    353        389        380
  Mined Volume to Oil Sands Ratio (1)                 2.1        2.1        2.3
Oil Sands Processed
  Millions of Tons                                    169        188        168
  Average Bitumen Grade (weight %)                   11.1       11.1       11.0
Bitumen in Mined Oil Sands
  Millions of Tons                                     19         21         18
  Average Extraction Recovery (%)                      89         87         89
Bitumen Production (2)
  Millions of Barrels                                  94        103         92
  Average Upgrading Yield (%)                          85         86         86
Gross Synthetic Crude Oil Shipped (3)
  Millions of Barrels                                  78         87         77
Nexen's Share of Marketable Crude Oil
  Millions of Barrels Before Royalties                5.7        6.3        5.6
  Millions of Barrels After Royalties                 5.6        6.1        5.5

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 crude oil is sold
     externally.


                                      21
<PAGE>

[GRAPHIC OMITTED]
[Margin Image: Employee in our marketing operations]

OIL AND GAS MARKETING

Our marketing group sells proprietary and third-party  natural gas, crude oil,
natural gas liquids and power in certain  regional markets where we have built
a solid strategic  presence.  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 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 related to
     our transportation and storage assets.

This strategy  aligns with our corporate  focus on extracting  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

[Margin Text: The marketing and trading of natural gas is our marketing group's
 largest revenue stream.]

The  marketing  and trading of natural gas is our  marketing  group'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 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 prices between summer and
     winter) using our storage assets.

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 offices in Detroit
and Calgary work together to provide  services to our customers.  Our presence
in Houston has  established  us in the Gulf Coast region where we have our own
production.


[Margin Text: We use access to transportation and storage facilities to
 optimize returns, capitalizing on location and time spreads.]

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

In 2003 and 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 has given us access to new third party gas supply until
2008,  pipeline capacity to 2016 and new relationships that have enabled us to
negotiate new gas purchase and sales contracts.

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.  At the end of 2005, we held 4 bcf/d of pipeline capacity,
primarily  between Western Canada and Eastern US. We also use storage capacity
to store  typically  cheaper summer gas in the ground until the winter heating
season arrives.  We had access to 30 bcf of natural gas storage  facilities at
the end of the year.


                                      22
<PAGE>

In addition to transportation and storage assets, we hold financial  contracts
that enable 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

[Margin Text: Our crude oil business markets physical volumes to end-use
 refiners and takes advantage of quality differentials and time spreads.]

Our crude oil  business  focuses on  marketing  physical  crude oil to end-use
refiners. The crude oil group markets our own production and more than 500,000
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 our
trading team seeks to optimize  the mix for sale to  refiners.  Traditionally,
the  Chicago and Denver  areas have been key markets for our Western  Canadian
crude, however, recently we have expanded our presence into the US gulf coast.
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.  During the year, we added an
office in London, in the United Kingdom,  to begin maximizing the value of our
North Sea production. As Buzzard crude comes on stream in late 2006, we expect
to increase our presence in various European markets, ensuring we maximize the
value of this production.

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

POWER MARKETING

[Margin Text: We are now the largest supplier of power to the commercial and
 industrial sectors in Alberta.]

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 in
Alberta.  With our recent acquisition of a  commercial/industrial  business in
Alberta,  we have become the largest  supplier of power to the  commercial and
industrial  sectors in the province.  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.


                                      23
<PAGE>

[GRAPHIC OMITTED]
[Margin Image: Locator Map for chemicals operations - Canada & Brazil]

CHEMICALS

[GRAPHIC OMITTED]
[Graphic: Canada map of chemicals plant locations]

In 2005, we monetized part of our chemicals business through an initial public
offering  of the  Canexus  Income  Fund.  We have  retained  a 61.4%  indirect
interest in our  chemicals  business,  and we  continue  to fully  consolidate
chemicals in our consolidated financial statements.

Our chemicals business  manufactures 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  some  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.

[Margin Text: In 2005, we monetized a portion of our chemicals business through
 an initial public offering, retaining a 61.4% indirect interest.]

Electricity  is the  most  significant  operating  cost  in  producing  sodium
chlorate  and  chlor-alkali  products,  making  up over  half our cash  costs.
Therefore,  our current facilities are strategically located to take advantage
of economic power  sources.  Our second  highest cost is  transportation.  Our
sales are concentrated  mainly in North America and Brazil with a small amount
of sodium chlorate sold in Asia. The proximity of our manufacturing  plants to
major  customers and competitive  freight rates  minimizes our  transportation
costs. Labour is also a significant  manufacturing cost.  Approximately 50% of
our workforce is unionized with  collective  agreements in place at all of our
unionized plants.

To grow value in our chemicals business, we focus on improving our costs while
maintaining market share,  building a sustainable North American customer base
and capturing new offshore opportunities.

AVERAGE ANNUAL PRODUCTION CAPACITY

(short tons)                                     2005         2004         2003
--------------------------------------------------------------------------------
Sodium Chlorate
  North America                               446,208      446,617      432,812
  Brazil                                       68,563       68,563       68,563
--------------------------------------------------------------------------------
  Total                                       514,771      515,180      501,375
================================================================================
Chlor-alkali
  North America                               356,002      356,002      356,002
  Brazil                                      109,430      109,430      109,430
--------------------------------------------------------------------------------
Total                                         465,432      465,432      465,432
================================================================================

NORTH AMERICA

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

The North American pulp and paper industry  consumes  approximately 95% of the
continent's  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 31% of this production is
sold in Canada, 62% in the US, and the rest is marketed offshore.

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

In October 2004,  we completed an expansion of our plant in Brandon,  Manitoba
increasing  capacity  to 260,000  tonnes  per year.  This  expansion  replaced
higher-cost capacity idled in 2002 at Taft, Louisiana.  Brandon is 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. During the year, we closed our plant at Amherstburg, Ontario.


                                      24
<PAGE>

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.  (Aracruz),   the  leading
manufacturer  of pulp in Brazil.  The  majority of the  production  is sold to
Aracruz under a long-term sales agreement that expires in 2024. This agreement
had an initial six-year take-or-pay  component that ended 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 an expansion at both facilities to meet Aracruz's growing needs. The
majority of our electricity  needs are supplied by a long-term supply contract
in Brazil.

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  where 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,  that
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. We participate in
many  industry  and  professional  associations  and monitor  the  progress of
proposed legislation and regulatory amendments.

ENVIRONMENTAL REGULATIONS

[Margin Text: We have an active safety, environment and social responsibility
 group that ensures our worldwide operations are conducted in a safe, ethical
 and socially responsible manner.]

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  countries  where we operate.  We believe our  operations
comply in all material respects with applicable  environmental laws. To reduce
our exposure, we apply industry standards, codes and best practices to meet or
exceed these laws and regulations.  Occasionally, 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
ensures 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.

ENVIRONMENTAL PROVISIONS AND EXPENDITURES

The ultimate  financial  impact of  environmental  laws and regulations is not
clearly known and cannot 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, 2005,  $611  million  ($1,471  million,  undiscounted)  has been
provided  in  our  Consolidated  Financial  Statements  for  asset  retirement
obligations for our oil and gas, Syncrude and chemicals  facilities.  In 2005,
we increased our  retirement  obligations  for future  dismantlement  and site
restoration by $210 million primarily from increased  drilling and development
activities  in the Gulf of  Mexico,  North  Sea,  Canada  and  Yemen,  general
industry cost pressures and more stringent environmental laws and regulations.

In 2005, our capital expenditures for environmental-related matters, including
environment control facilities,  were approximately $34 million. Our operating
expenditures for environmental-related matters were approximately $35 million.
In 2006, we estimate these expenditures to be approximately $21 million.


                                      25
<PAGE>

[GRAPHIC OMITTED]
[Margin Image: Gulf of Mexico employee on drill ship]

EMPLOYEES

We had 3,282  employees on December 31, 2005, of which 301 were employed under
collective  bargaining  schemes.  Information  on our  executive  officers  is
presented in Item 10 of this report.

ITEM 1A. RISK FACTORS

Refer to pages 62 to 69 for a discussion of our risk factors.

ITEM 1B. UNRESOLVED STAFF COMMENTS

There are no unresolved staff comments with the SEC.

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 on 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 US Environmental  Protection Agency (EPA),  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 lawsuits 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  an  arbitration  at  the   International   Court  of
Arbitration of the  International  Chamber of Commerce (ICC) regarding an Area
of Mutual Interest Agreement  (Agreement) in Yemen. Pursuant to the Agreement,
if Nexen proposed to conduct petroleum development operations within two small
areas of Block 51 in 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.  Subsequent  to  the  Agreement's  expiry,  we  began  exploration
activities on Block 51,  including the  Heijah/Tawila  Extension Lands and, in
December  2003,  filed  a  notice  of  commercial  discovery  with  the  Yemen
government.  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.  Given that the agreement  expired without Nexen having proposed to
conduct petroleum  development  operations,  we believe  Occidental's claim is
without merit and have  vigorously  defended our contractual  rights.  The ICC
arbitration  hearing with respect to liability  took place in San Francisco in
July 2005,  and we are awaiting the decision of the tribunal.  If the tribunal
finds that  Occidental has a claim under the Agreement,  the amount of damages
will be determined in the second phase of the arbitration.

In  April  2005,  a  former  employee  in  our  US  offshore  operations  made
allegations that he tampered with water samples, dumped material overboard and
did not  report  oil  sheens.  All of these  allegations,  if  true,  would be
potential  violations of the permit and  regulations  issued under the Federal
Clean Water Act and possibly  violations of the Federal Oil Pollution  Act. In
May 2005,  Nexen made written  disclosure of these  allegations  to the Dallas
Region of the EPA, and on July 15, 2005, we sent a detailed written submission
to the EPA. During  compliance  training that Nexen conducted to address these
allegations,  Nexen uncovered  evidence that it may have  discharged  material
from certain cleaning vessels during routine cleaning. This discharge may have
been  prescribed  under the permit,  so this was also  disclosed to the EPA on
July 27, 2005.  The  potential  penalties  range up to  US$32,000  per day per
violation  for  civil  judicial  penalties  and up to  US$50,000  per  day for
criminal  violations.  At this time, it is difficult to determine the type and
level of  penalties  that  might  be  sought  by EPA,  as the  agency  has the
discretion to seek penalties within


                                      26
<PAGE>

a broad range of amounts.  These matters have been assigned to an EPA attorney
and an enforcement investigator in Dallas. Nexen's meeting with the EPA, which
was planned for late September 2005, was postponed because of the governments'
increased workload caused by Hurricanes Katrina and Rita.

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 2005.

                                   PART II

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

[Margin Text: On April 27, 2005,
 our shareholders approved a 2-for-1 split of our common shares.]

Nexen's  common shares are traded on the Toronto Stock  Exchange (TSX) and the
New York Stock  Exchange  (NYSE) under the symbol NXY. On April 27, 2005,  our
shareholders approved a split of our issued and outstanding common shares on a
two-for-one  basis.  All share and  per-share  amounts  have been  restated to
reflect this split.

On December 31, 2005, there were 1,294 registered holders of common shares and
261,140,571  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.

TRADING RANGE OF NEXEN'S COMMON SHARES

[Margin Text: In 2005, Nexen's common shares traded on the TSX from a low of
 $23.55 in Q1 to a high of $60.67 in Q3.]

                                          TSX (Cdn $)            NYSE (US $)
                                   ----------------------- ---------------------
($/share)                                High        Low        High        Low
---------------------------------------------------------- ---------------------
2005
  First Quarter                         35.50      23.55       29.18      19.44
  Second Quarter                        39.85      29.53       32.32      23.28
  Third Quarter                         60.67      40.25       51.73      31.95
  Fourth Quarter                        59.54      43.77       51.69      36.80
2004
  First Quarter                         26.68      22.50       20.31      17.05
  Second Quarter                        28.25      23.40       21.15      17.25
  Third Quarter                         26.85      22.17       21.07      16.94
  Fourth Quarter                        29.33      24.09       23.28      19.60

QUARTERLY DIVIDENDS DECLARED ON COMMON SHARES

                                   First       Second        Third       Fourth
($/share)                        Quarter      Quarter      Quarter      Quarter
--------------------------------------------------------------------------------
2005                                0.05         0.05         0.05         0.05
2004                                0.05         0.05         0.05         0.05

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. According to 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.  According  to the Plan,  a right is  attached  to each
present and future outstanding  common share,  entitling 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.


                                      27
<PAGE>

Rights  created  under the Plan,  which  can only be  exercised  when a person
acquires  20% or more of our common  shares (a Flip-In  Event),  entitle  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 2008 to
remain effective past that date.

ITEM 6. SELECTED FINANCIAL DATA

FIVE-YEAR SUMMARY OF SELECTED FINANCIAL DATA IN ACCORDANCE WITH US GAAP

[Margin Text: See page 119 for differences between Canadian & US GAAP.]

<TABLE>
<CAPTION>
                                                    2005        2004        2003        2002        2001
---------------------------------------------------------------------------------------------------------
<S>                                                <C>         <C>         <C>         <C>         <C>
Results of Operations
  Net Sales
    Oil and Gas and Syncrude (1)                   3,506       2,552       2,236       1,775       1,705
    Other                                            426         392         396         367         373
---------------------------------------------------------------------------------------------------------
  Total Net Sales                                  3,932       2,944       2,632       2,142       2,078


  Net Income from Continuing Operations              666         705         419         270         293
  Basic Earnings per Common Share from
    Continuing Operations ($/share)                 2.52        2.74        1.69        1.10        1.21
  Diluted Earnings per Common Share
    from Continuing Operations ($/share)            2.47        2.71        1.68        1.09        1.20
  Net Income                                       1,110         788         420         352         365
  Basic Earnings per Common Share ($/share)         4.26        3.06        1.70        1.44        1.51
  Diluted Earnings per Common Share ($/share)       4.17        3.03        1.68        1.42        1.50
  Production Before Royalties (mboe/d) (2)           242         250         269         269         268
  Production After Royalties (mboe/d) (2)            173         174         185         176         184
---------------------------------------------------------------------------------------------------------

Financial Position
  Total Assets (2)                                14,493      12,339       7,703       6,764       5,609
  Long-Term Debt (3)                               3,630       4,214       2,470       2,575       2,242
  Shareholders' Equity                             3,961       2,892       2,131       1,812       1,414
  Capital Investment, including Acquisitions       2,638       4,264       1,432       1,545       1,325
  Dividends per Common Share ($/share) (4)          0.20        0.20       0.163        0.15        0.15
  Common Shares Outstanding (thousands)          261,141     258,399     251,212     245,932     242,404
---------------------------------------------------------------------------------------------------------
</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. In the third quarter of 2005, we sold
     certain Canadian conventional oil and gas properties in Saskatchewan,
     British Columbia and Alberta producing 18,300 bbls/d. 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
     began production from Block 51 in Yemen. In 2005, we sold producing
     properties in Canada and suffered hurricane-related downtime in the Gulf
     of Mexico. A full year's production from the North Sea and Block 51 in
     Yemen offset declines caused by these events.
3    In December 2004, we drew US$1.5 billion 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. The
     acquisition credit facility was repaid in 2005 with proceeds from the
     issuance of US $1.04 billion in senior notes in the first quarter and from
     our asset disposition program in the third quarter.
4    Quarterly dividends were increased to 5 cents per share in the fourth
     quarter of 2003.


                                      28
<PAGE>

We've done what we set out to do:
delivered record results, met our
production targets, reduced net debt,
achieved exploration success and
kept our major projects on time
and on budget.

see the value

md&a


                                      29
<PAGE>

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

                                                                          Page
Executive Summary of 2005 Results...........................................31

Capital Investment..........................................................32

Financial Results
    Year-to-Year Change in Net Income.......................................36
    Oil & Gas and Syncrude
        Production..........................................................37
        Commodity Prices....................................................40
        Operating Costs.....................................................43
        Depreciation, Depletion, Amortization and Impairment................45
        Exploration Expense.................................................46
    Oil & Gas and Syncrude Netbacks.........................................48
    Oil and Gas Marketing...................................................49
    Chemicals...............................................................52
    Corporate Expenses......................................................53

Outlook for 2006............................................................55

Liquidity and Capital Resources.............................................57

Risk Factors................................................................62

Critical Accounting Estimates...............................................70

Quantitative and Qualitative Disclosures about Market Risk..................75


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 21 to the  Consolidated  Financial  Statements.  The date of
this discussion is February 7, 2006.

Unless otherwise noted,  tabular amounts are in millions of Canadian  dollars.
Our discussion and analysis of our oil and gas activities include our Syncrude
activities  since the product  produced from Syncrude  competes in the oil and
gas market. Oil and gas volumes, reserves and related performance measures are
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 80 which highlights differences between our reserve estimates and related
disclosures that are otherwise required by Canadian regulatory authorities.


                                      30
<PAGE>


EXECUTIVE SUMMARY OF 2005 RESULTS

[GRAPHIC OMITTED]
[Margin Graph: Net Income]

<TABLE>
<CAPTION>
(Cdn$ millions)                                            2005         2004         2003
------------------------------------------------------------------------------------------
<S>                                                       <C>          <C>          <C>
Net Income                                                1,152          793          578
Earnings per Common Share ($/share)                        4.43         3.08         2.33
Cash Flow from Operating Activities                       2,143        1,606        1,405
Production before Royalties (mboe/d) (1)                    242          250          269
Production after Royalties (mboe/d)                         173          174          185
Capital Investment, including Acquisitions                2,638        4,264        1,494
Net Debt (2)                                              3,641        4,219        1,690
Average Foreign Exchange Rate (Canadian to US dollar)      0.83         0.77         0.71
</TABLE>

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 working capital.

[Margin Text: We achieved record financial results due to all-time high
commodity prices, gains on dispositions and a
record contribution
from marketing.]

We achieved  record  financial  results in 2005 with net income  exceeding  $1
billion  for the first time in company  history.  We exceeded  our  production
targets,  notwithstanding the sale of oil and gas properties in Canada and the
impact of  hurricanes  in the US. We also  successfully  reduced  our net debt
while managing our largest capital program ever. We made significant  progress
on our strategic  initiatives by moving closer to first  production at Buzzard
and Long Lake,  beginning  commercial CBM  development  at Corbett,  Doris and
Thunder and making a potentially  significant  discovery at Knotty Head in the
US Gulf.  In  addition,  we received  record net revenues  from our  marketing
group.

Record high commodity prices  throughout the year underpinned our results.  We
also realized a gain of $225 million on disposition  of Canadian  conventional
oil and gas  properties,  and a gain of $193  million  on the  initial  public
offering of a portion of our  chemicals  business  through the Canexus  Income
Fund.  We raised more than $1.4 billion from these  transactions  and used the
proceeds to reduce net debt and fund our capital programs.

Our  major  capital  projects  remain  on  time  and  on  budget.  Buzzard  is
approximately  88% complete and we are on track for first  production  in late
2006.  Peak production is expected to be  approximately  200,000 boe/d (85,000
boe/d net to us),  royalty free. At our Long Lake project,  we are on track to
complete and tie-in our commercial  SAGD wells and begin steam  injection late
in 2006.  Production is expected to ramp up before the upgrader is complete in
the second half of 2007. We expect our share of synthetic  crude oil from Long
Lake to be 30,000 bbls/d.  We are already planning to duplicate Long Lake in a
phased  manner,  and expect to increase our synthetic  crude oil production to
120,000 bbls/d over the next ten years. At Syncrude,  the Stage 3 expansion is
almost  complete  and we expect  our  share of  production  capacity  there to
increase by 8,000 bbls/d in 2006.

[Margin Text: Our major capital projects remain on time and on budget and our
 capital program is delivering results that will add to our future growth.]

Our capital  program is also  delivering  results  that will add to our future
growth.  In the Gulf of Mexico,  we made a discovery at Knotty Head, our first
sub-salt  discovery  and the  deepest  well ever  drilled in the Gulf.  We are
presently  drilling a sidetrack well to determine the extent of our discovery.
Offshore Nigeria, we had further drilling success at Usan on Block OPL-222 and
expect to book proved reserves once the project is sanctioned.  In Canada,  we
are  moving  forward  with  commercial  development  of our coal  bed  methane
resources  and are  looking  to  increase  recovery  rates  from our heavy oil
properties through the innovative use of technology.

New  production  from Block 51 in Yemen and Scott and  Telford in the UK North
Sea offset natural declines on our base producing  assets in Canada,  the Gulf
of Mexico and at Masila in Yemen.  We sold more than 18,000  boe/d of Canadian
conventional  production and lost approximately  6,000 boe/d of Gulf of Mexico
production as a result of  hurricanes.  While damage to most of our facilities
was  fairly  minor,   post-hurricane  start-up  delays  caused  by  damage  to
surrounding  infrastructure  required some of our production to be shut-in for
an extended  period.  Most of our fields in the Gulf are now up and running at
full production.


                                      31
<PAGE>

[Margin Text: In 2005, our stock price increased 128%, increasing shareholder
 value by over $8 billion.]

In 2005, our stock price increased from $24.35 to $55.42 per share, increasing
shareholder  value by more than $8 billion.  It also increased our expense for
employee  stock-based  compensation  programs,  and we expensed  $490  million
during  the year.  In 2005,  Nexen  was the 7th best  performing  stock  among
companies on the S&P TSX Composite Index.

Following  our 2004 North Sea  acquisition,  we  purchased  WTI put options to
provide an annual  average  floor price of US$43/bbl  and  US$38/bbl on 60,000
bbls/d of production in 2005 and 2006, respectively. At the end of 2004, these
put  options  had a market  value of $200  million.  As a result of  continued
strong crude oil prices, the value of these options was only $4 million at the
end of 2005. We expensed the $196 million decrease in value in 2005.

Throughout 2005, the Canadian dollar  strengthened  relative to the US dollar.
Our sales revenue is denominated in or referenced to US dollars.  As a result,
our  revenues  decline  as the US  dollar  weakens.  On the  other  hand,  our
US-dollar capital spending, operating costs and US-dollar denominated debt are
lower when  translated  to  Canadian  dollars.  Overall,  the weaker US dollar
reduced our 2005 cash flow from  operating  activities  and net income by $251
million and $116 million, respectively, and debt decreased by $109 million.

[Margin Text: We added 82 mmboe of proved oil and gas and Syncrude reserves
 before royalties, almost fully replacing our 2005 production of 90 mmboe.]

We  added  82  mmboe  of  proved  oil  and gas and  Syncrude  reserves  before
royalties,  replacing  the majority of our 2005  production  of 90 mmboe.  Our
major development activities, principally at Buzzard and Syncrude, contributed
45 mmboe of the additions.  Reserves were also added from ongoing exploitation
in Yemen,  Canada,  the Gulf of Mexico  and the North  Sea.  Once  again,  SEC
regulations  that  require us to recognize  bitumen  reserves  using  year-end
prices,  did not allow us to book any proved  bitumen  reserves  for Long Lake
because of high natural gas costs and wide  light/heavy  differentials.  Under
Canadian  regulations,  we would  recognize  200 mmbbls of  high-value  proved
synthetic reserves.  We also sold 49 mmboe of proved reserves in Canada during
the year.

In 2006, we are planning our largest capital program ever. We expect to invest
$2.9  billion to develop  core  assets and  develop and explore for new growth
opportunities.  Almost  half of this  capital  will be directed  toward  major
development  projects  at  Buzzard,  Long  Lake and  Syncrude,  as well as the
development  of coal bed methane  from the Upper  Mannville  coals in the Fort
Assiniboine  area of Alberta.  On the  exploration  front, we will continue to
appraise our Knotty Head  discovery and expect to drill 20  high-impact  wells
primarily in the Gulf of Mexico, North Sea, offshore West Africa and Yemen.

We expect our 2006  production  to average  between  220,000 boe/d and 240,000
boe/d,  before  royalties,  and between  165,000 boe/d and 180,000 boe/d after
royalties.  In 2007,  we expect  our  before-royalties  production  to grow to
between 300,000 boe/d and 350,000 boe/d. Most of our new production is subject
to little or no royalties and generates  significantly higher margins than our
current production.

Capital Investment

<TABLE>
<CAPTION>
(Cdn$ millions)                               Estimated 2006              2005              2004
-------------------------------------------------------------------------------------------------
<S>                                           <C>                        <C>               <C>
Major Development                                      1,300             1,550               663
Early Stage Development                                  300                54                19
New Growth Exploration                                   600               456               266
Core Asset Development                                   600               504               634
-------------------------------------------------------------------------------------------------
                                                       2,800             2,564             1,582
Acquisitions                                               -                20             2,587
-------------------------------------------------------------------------------------------------
Total Oil & Gas and Syncrude                           2,800             2,584             4,169
Marketing, Corporate, Chemicals and Other                100                54                95
-------------------------------------------------------------------------------------------------
Total Capital                                          2,900             2,638             4,264
=================================================================================================
</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 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.


                                      32
<PAGE>

As conventional basins in North America mature, we have been transitioning our
operations  toward less mature basins and  unconventional  resources.  Our key
focus areas  include the North Sea,  Athabasca  oil sands,  Canadian  coal bed
methane,  Gulf of Mexico,  offshore West Africa and the Middle  East--areas we
believe have attractive  fiscal terms and significant  remaining  opportunity,
and where we have some competitive advantage.

[Margin Text: In 2005, most of our capital was invested in multi-year
 development projects and long cycle-time exploration.]

In 2005, we invested more than $2.6 billion in capital expenditures, mostly in
multi-year development projects and long cycle-time  exploration.  In 2006, we
are managing our largest  development and exploration program ever. We plan to
invest more than $2.9  billion in our oil and gas and Syncrude  assets.  About
45% of this is focused on multi-year  development projects, 24% on core assets
to sustain  production and provide cash flow, and 21% on drilling  high-impact
exploration wells and building our acreage position. The rest will be spent on
early stage development activities.

2005 INVESTMENT PROGRAM

<TABLE>
<CAPTION>
                                   Major     Early Stage       New Growth       Core Asset
(Cdn$ millions)              Development     Development      Exploration      Development          Total
----------------------------------------------------------------------------------------------------------
<S>                      <C>              <C>              <C>              <C>              <C>
Oil and Gas
  Synthetic (mainly
    Long Lake)                       743               31               16                -           790
  North Sea                          469               10               59               87           625
  Yemen                              161                -               41               75           277
  United States                        4                -              211              144           359
  Canada                              33               10               74              130           247
  Other Countries                      -                3               55               11            69
Syncrude                             140                -                -               57           197
----------------------------------------------------------------------------------------------------------
                                   1,550               54              456              504         2,564
Chemicals                              -                -                -               14            14
Marketing, Corporate
  and Other                            -                -                -               40            40
----------------------------------------------------------------------------------------------------------
Total Capital                      1,550               54              456              558         2,618
==========================================================================================================

As a % of Total Capital              59%               2%              17%              22%          100%
----------------------------------------------------------------------------------------------------------
</TABLE>

2006 ESTIMATED CAPITAL

<TABLE>
<CAPTION>
                                   Major     Early Stage       New Growth       Core Asset
(Cdn$ millions)              Development     Development      Exploration      Development          Total
----------------------------------------------------------------------------------------------------------
<S>                      <C>              <C>              <C>              <C>              <C>
Oil and Gas
  Synthetic (mainly
    Long Lake)                       650              100                -               10           760
  North Sea                          450              100               75               85           710
  Yemen                                -                -               35              160           195
  United States                        -               20              255              235           510
  Canada                             150               60              120               80           410
  Other Countries                      -               20              115                -           135
Syncrude                              50                -                -               30            80
----------------------------------------------------------------------------------------------------------
                                   1,300              300              600              600         2,800
Marketing, Corporate
  and Other                            -                -                -              100           100
----------------------------------------------------------------------------------------------------------
Total Capital                      1,300              300              600              700         2,900
----------------------------------------------------------------------------------------------------------

As a % of Total Capital              45%              10%              21%              24%          100%
----------------------------------------------------------------------------------------------------------
</TABLE>

[GRAPHIC OMITTED]
[Margin Graph: 2006 Estimated Capital]

MAJOR AND EARLY STAGE DEVELOPMENT PROJECTS

More than 60% of our 2005 capital  investment was directed  toward early stage
and major development projects including Buzzard, Long Lake, Syncrude Stage 3,
Yemen  Block  51 and CBM.  These  projects  are  characterized  by  multi-year
investments that result in timing  differences  between reserve  additions and
capital  expenditures,  but each project has attractive full-cycle finding and
development  costs.  Our new growth  development  resulted  in proved  reserve
additions of 45 mmboe.


                                      33
<PAGE>

SYNTHETIC

[Margin Text: Our Long Lake and Buzzard developments are on time and
on budget.]

We invested  $774  million to develop  our insitu oil sands  resource in 2005,
$743  million  of this at Long  Lake.  The base Long Lake  project  remains on
schedule  and  on  budget.   Detailed  project  engineering  is  substantially
complete,  and  approximately  69% of the  project's  total  costs  have  been
committed.  Steam  injection is expected to begin in late 2006,  followed by a
ramp-up in bitumen  production.  The upgrader is scheduled to start operations
in the second half of 2007.

To  enhance  reliability,  ensuring  bitumen  feedstock  supply  and  building
capacity for future growth,  we are expanding our steam generating  facilities
so we can operate at a steam-oil ratio of up to 3.3 compared with the existing
design of 2.5.  This  expansion is expected to cost up to $250  million  ($125
million,  net to us). In optimizing  the value from the project,  we will also
construct a facility to concentrate  soot produced by the gasifier and thereby
reduce disposal costs.  This facility is expected to cost  approximately  $110
million ($55 million,  net to us).  These two projects will increase our total
capital investment to construct Long Lake by 10% to $1.9 billion.

At peak rates of premium  synthetic crude, Long Lake Phase 1 should provide us
with cash flow of between $400 million and $500 million per year, assuming oil
prices of US$50/bbl  (WTI).  We are planning to increase  synthetic  crude oil
production to 240,000  bbls/d over the next 10 years (120,000  bbls/d,  net to
us) in phases  of  60,000  bbls/d  (30,000  bbls/d,  net to us) using the same
technology  as Long Lake.  Phase 2 bitumen  production is expected to begin in
late 2010,  with  upgrader  commissioning  in 2011.  In 2005,  we invested $31
million to further  evaluate  our  existing  resource  and acquire  additional
resource.  We have made commitments for some of the long-lead time modules for
phase 2. In 2006, we expect to invest $650 million on the ongoing  development
of Long Lake and $100  million in  additional  drilling and seismic to develop
our oil sands leases and advance our regulatory applications.

NORTH SEA--BUZZARD

At Buzzard,  we  invested  $439  million in 2005.  Buzzard is  progressing  on
schedule and on budget.  Development  of the facilities is  approximately  88%
complete. We are currently drilling the production wells and expect to install
the utilities and production  decks during the second  quarter of 2006.  First
oil is  expected  in late  2006.  At its  peak,  Buzzard  is  expected  to add
approximately 85,000 boe/d of net production and between $1.6 billion and $1.7
billion of annual pre-tax cash flow,  assuming  US$50/bbl  (WTI).  In 2006, we
expect to spend $450 million on Buzzard and $100 million to complete appraisal
and development  evaluation work on a number of small discoveries in the North
Sea.

YEMEN

In  Yemen  on  Block  51,  we began  production  in late  2004  using an early
production  system.  In 2005, we invested $161 million to construct  permanent
production facilities and further develop the fields. The permanent facilities
are expected to be fully commissioned in early 2006.

CANADA--COAL BED METHANE

[Margin Text: We are developing the first commercial CBM project in Mannville
 coals.]

In Canada,  we are  developing  the first  commercial CBM project in Mannville
coals.  In 2005, we invested $33 million in CBM  development,  and in 2006, we
plan to spend  $150  million  to  develop  115 gross (53 net)  sections  using
single-leg and multiple-leg  wells, and construct gas gathering and processing
facilities.  We expect our CBM production to be modest in 2006, with growth in
2007 and beyond as we dewater the reservoirs and expand our  developments.  We
are  targeting to add 150 mmcf/d of  production by 2011 from our CBM projects.
We have more than 600 net sections of CBM lands.

SYNCRUDE--STAGE 3 EXPANSION

We invested  $140  million in 2005 for the Syncrude  Stage 3  expansion.  This
project was  approximately 98% complete at year end, with 65% of the new units
completed  and  operating  reliably  throughout  2005.  Commissioning  of  all
remaining Stage 3 units is underway. The expansion is expected to be completed
and  fully on  stream  by mid  year,  adding  approximately  8,000  bbls/d  of
production  capacity,  net to us. We expect  to spend $50  million  in 2006 to
complete and commission the Stage 3 upgrader expansion.


                                      34
<PAGE>

NEW GROWTH EXPLORATION

[Margin Text: We had exploration success in 2005, including a potentially
 significant discovery at Knotty Head.]

We invested $456 million in exploration in 2005. Approximately $140 million of
this  was  invested  in  land,  seismic  and  other  early  stage  exploration
activities.  The balance  was  invested  to drill 20  high-impact  exploration
wells.  This  resulted in a number of  exploration  successes,  including  the
potentially  significant  Knotty Head discovery in the Gulf of Mexico where we
have a 25% interest.  We also had smaller discoveries in the Gulf at Big Bend,
Anduin and Wrigley.  In total, we participated in  approximately  one-third of
deep-water discoveries in the Gulf of Mexico in 2005. Offshore West Africa, we
drilled two successful  appraisal wells at Usan on Nigeria's OPL-222.  Despite
our exploration success, we only recognized 4 mmboe of proved reserves because
of  additional  appraisal  work  required  to make a  decision  on  commercial
development.

Knotty Head is a potentially  significant discovery on Green Canyon Block 512.
A  sidetrack  appraisal  well  commenced  drilling in late 2005 and is nearing
completion.  Additional  appraisal drilling is planned within the next year to
determine the extent of the discovery.

We are proceeding  with  development  of the Wrigley  discovery on Mississippi
Canyon 506. We plan to sub-sea tieback the well to nearby infrastructure, with
first production  expected in the second half of 2006. We plan to complete our
Big Bend  discovery  and tie back to existing  infrastructure  in 2007. At our
Anduin discovery,  we plan to drill an appraisal well in 2006 to determine the
resource size and development options.

Internationally,  we  drilled  three  small  discoveries  in the  North Sea at
Polecat, Yeoman and Black Horse. Their ultimate development is being evaluated
and may depend on  additional  exploration  success in the area. We have a 40%
interest in  Polecat,  a 50%  interest  in Yeoman and a 60%  interest in Black
Horse, and we operate all three wells.

On Nigeria  OPL-222,  offshore  West Africa,  the Usan-7 and Usan-8  appraisal
wells were  successfully  drilled during 2005.  Appraisal of the Usan field is
now complete and a preliminary  field  development  plan has been submitted to
Nigerian governmental agencies for approval. Preparation for basic engineering
and tendering of contracts is proceeding on a multi-well development plan. The
current design consists of a purpose-built  floating  production,  storage and
offshore  loading facility (FPSO) capable of handling peak production rates of
160,000  bbls/d  with  storage  capacity  of  2  million  barrels.   Following
government  approvals of the final field development plan, the partners expect
to formally sanction the project in late 2006. In 2005, we completed  drilling
the deep-water  Efere well. This well was  unsuccessful  and its capital costs
have been expensed. During 2006, the exploration and appraisal program outside
the Usan field will continue on the block.

[Margin Text: In 2006, we plan to drill 20 high-impact exploration wells.]

In 2006, we expect to invest $600 million in  exploration  capital to drill 20
high-impact  wells  primarily in the Gulf of Mexico,  the North Sea,  offshore
West  Africa and Yemen.  We  currently  have  drilling  rigs  secured  for the
majority of our 2006 program.  We have an extensive  inventory of  exploration
prospects in the Gulf of Mexico.  To ensure the  continuity of our  deep-water
drilling   program,   we  have   contracted   a   new-build   fifth-generation
dynamically-positioned semi-submersible drilling rig, which is scheduled to be
completed in 2009.  The  contract  provides us access to the rig for two years
over a three-and-a-half-year period.

CORE ASSET DEVELOPMENT

In 2005, we invested $504 million in core asset development and minor property
acquisitions  that  added 33 mmboe of  proved  reserves.  Our  strategy  is to
maximize  the value we extract  from our core  assets,  in  addition to adding
reserves and  production.  In 2006, we plan to invest $600 million in our core
assets  including gas  opportunities in the Eugene Island and Vermillion areas
in the shallow-water Gulf of Mexico shelf, development activities at Scott and
Telford  in the North  Sea and  development  of our BAK-A and BAK-B  fields in
Block 51, Yemen.


                                      35
<PAGE>

FINANCIAL RESULTS

YEAR-TO-YEAR CHANGE IN NET INCOME

<TABLE>
<CAPTION>
                                                                                                                 MD&A PAGE
(Cdn$ millions)                                                         2005 vs 2004       2004 vs 2003          REFERENCE
---------------------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>                <C>                  <C>
Net Income for 2004 and 2003 (1)                                                 793                578
===========================================================================================================================

Favourable (unfavourable) variances:

Cash Items
  Production Volumes, After Royalties                                                                              page 37
  Crude Oil                                                                     39               (116)
    Natural Gas                                                                  (55)                (8)
    Change in Crude Oil Inventory                                                  4                 40
---------------------------------------------------------------------------------------------------------------------------
      Total Volume Variance                                                      (12)               (84)
  Realized Commodity Prices                                                                                        page 40
    Crude Oil                                                                    648                365
    Natural Gas                                                                  165                  -
---------------------------------------------------------------------------------------------------------------------------
      Total Price Variance                                                       813                365
  Oil and Gas Operating Expense                                                                                    page 43
    Conventional                                                                 (64)               (55)
    Synthetic                                                                    (27)                (2)
---------------------------------------------------------------------------------------------------------------------------
      Total Operating Expense Variance                                           (91)               (57)
  Marketing Contribution                                                          49                (14)           page 49
  Chemicals Contribution                                                          31                 10            page 52
  General and Administrative                                                     (96)               (30)           page 53
  General and Administrative--Stock-Based Compensation Paid                      (60)                (9)
  Interest Expense                                                                46                 26            page 53
  Current Income Taxes                                                           (91)               (38)           page 54
  Other                                                                          (69)               (22)           page 55
---------------------------------------------------------------------------------------------------------------------------
Total Cash Variance                                                              520                147

Non-Cash Items
  Depreciation, Depletion, Amortization and Impairment                                                             page 45
    Oil & Gas and Syncrude                                                      (308)               271
    Other                                                                        (19)                13
  Exploration Expense                                                             (5)               (45)           page 46
  General and Administrative--Stock-Based Compensation Accrual                  (337)               (70)           page 53
  Future Income Taxes                                                            348               (176)           page 54
  Increase (Decrease) in Fair Value of Crude Oil Put Options                    (252)                56            page 55
  Gains from Divestiture Programs                                                418                  -            page 55
  Other                                                                           (6)                19            page 55
---------------------------------------------------------------------------------------------------------------------------
Total Non-Cash Variance                                                         (161)                68

Net Income for 2005 and 2004 (1)                                               1,152                793
===========================================================================================================================
</TABLE>

Note:
1    Includes  results  of  discontinued   operations  (see  Note  14  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 55.


                                      36
<PAGE>

OIL & GAS AND SYNCRUDE

PRODUCTION

<TABLE>
<CAPTION>
                                           2005                        2004                            2003
                            ---------------------------- -------------------------------- -------------------------------
                                 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                           112.7            60.6            107.3            53.5            116.8            57.5
  Canada (2)                       29.2            22.6             36.2            28.2             46.3            35.4
  United States                    22.2            19.6             30.0            26.5             28.3            25.0
  United Kingdom                   12.6            12.6              1.5             1.5                -               -
  Australia (3)                       -               -              2.7             2.5              6.1             5.6
  Other Countries                   5.6             5.1              5.3             4.7              5.4             4.6
Syncrude (mbbls/d) (4)             15.5            15.3             17.2            16.6             15.3            15.2
-------------------------------------------------------- -------------------------------- --------------------------------
                                  197.8           135.8            200.2           133.5            218.2           143.3

Natural Gas (mmcf/d)
  Canada (2)                        124             101              146             115              158             125
  United States                     116              99              148             126              145             122
  United Kingdom                     23              23                3               3                -               -
-------------------------------------------------------- -------------------------------- --------------------------------
                                    263             223              297             244              303             247

Total (mboe/d)                      242             173              250             174              269             185
======================================================== ================================ ================================
</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
     14 to our Consolidated Financial Statements.

                                                   2005       2004       2003
     -------------------------------------------------------------------------
     Before Royalties
       Oil and Liquids (mbbls/d)                    6.7       11.7       19.6
       Natural Gas (mmcf/d)                          24         47         50
     -------------------------------------------------------------------------
     After Royalties
       Oil and Liquids (mbbls/d)                    5.3        9.0       14.5
       Natural Gas (mmcf/d)                          17         33         34
     -------------------------------------------------------------------------

3    Comprises  production from  discontinued  operations.  See Note 14 to our
     Consolidated Financial Statements.
4    Considered a mining operation for US reporting purposes.

2005 VS 2004--LOWER PRODUCTION DECREASED NET INCOME BY $12 MILLION

[Margin Text: Even after Canadian dispositions and hurricanes in the Gulf of
Mexico, 2005 production before royalties declined only 3%.]

Production  before  royalties  declined 3% during the year,  while  production
after  royalties  remained  consistent  with  2004  levels.  New  royalty-free
production from the UK North Sea partially  offset the sale of  higher-royalty
production from Canada. We sold Canadian  production during the year to reduce
debt used to fund our  acquisition of offshore oil and gas assets in the North
Sea.  Production  was lower as a result of  hurricane  activity in the Gulf of
Mexico in the second  half of the year.  Removing  the impact of the  Canadian
asset sales and the lost volumes  attributable to Hurricanes Katrina and Rita,
our 2005 production before royalties would have increased 3% from 2004.


                                      37
<PAGE>

The following table summarizes our production changes year over year:

<TABLE>
<CAPTION>
(mboe/d)                                      Before Royalties    After Royalties
----------------------------------------------------------------------------------
<S>                                           <C>                <C>
2004 Production                                            250                174
Canada--Disposition of Properties                           (9)                (6)
Gulf of Mexico--Hurricane Related Downtime                  (6)                (5)
----------------------------------------------------------------------------------
                                                           235                163
Production changes
  Block 51 in Yemen                                         25                 16
  North Sea                                                 14                 14
  Masila Block in Yemen                                    (18)                (8)
  Gulf of Mexico                                            (7)                (6)
  Canada                                                    (2)                (2)
  Australia                                                 (3)                (3)
  Syncrude                                                  (2)                (1)
----------------------------------------------------------------------------------
2005 Production                                            242                173
==================================================================================
</TABLE>

[Margin Text: See page 56 for production expected in 2006.]

Future production increases are expected to come from Syncrude in 2006 and our
North Sea  Buzzard  project  in late  2006,  along  with  Long Lake  synthetic
production in 2007. Production volumes discussed in this section represent our
working interest before royalties.

YEMEN

Yemen production  increased 5% from 2004  as we replaced  maturing  production
from Masila with new production from Block 51. Masila production declined 18%.
As the field nears the end of its contract term, we are strategically managing
development  capital to optimize recovery of remaining  reserves.  In 2005, we
drilled 36 development  wells compared with 73 wells in 2004.  While new wells
coming on stream are yielding  strong  production  rates,  we expect Masila to
continue declining in the future.

On Block 51,  production  from the East Al Hajr field  averaged  25,600 bbls/d
during the year. We have been operating  from temporary  facilities and expect
to complete the permanent central processing  facility in the first quarter of
2006. During the year, we drilled 20 development wells. We expect our share of
total  production  from Yemen to average  between  90,000  bbls/d and  100,000
bbls/d in 2006.

CANADA

[Margin Text: In 2005, we sold Canadian conventional oil and gas properties
producing 18,300 boe/d.]

In the third quarter,  we sold conventional oil and gas properties in Alberta,
British Columbia and Saskatchewan that were producing 18,300 boe/d. Production
from our remaining natural gas and heavy oil properties  declined  marginally.
In 2006,  we are  focusing our capital on drilling  infill  shallow gas wells,
developing our coal bed methane  projects and developing new  technologies  to
increase heavy oil recovery. In 2006, we plan to drill more than 300 net wells
on our properties and expect our Canadian production to average between 35,000
boe/d and 40,000 boe/d.

GULF OF MEXICO

[Margin Text: In the Gulf of Mexico, hurricanes reduced our annual volumes by
about 6,000 boe/d.]

Gulf of Mexico  production  declined 24%, or about 13,000 boe/d from 2004. The
effects of Hurricanes Katrina and Rita reduced volumes by approximately  6,000
boe/d as a  result  of  shut-in  production  and  subsequent  start-up  delays
following  damage to our facilities and third-party  infrastructure.  We carry
insurance which, subject to certain deductibles, we expect will cover property
damage  and  business   interruption  up  to  defined   limits.   We  expensed
insurance-related costs of US$34 million as a result of the hurricanes.

In the deep water, natural declines and increasing water-cuts at Aspen reduced
volumes by 8,000 boe/d from 2004. We plan to drill another development well at
Aspen in 2006 to tap potential  unrecovered  reserves.  Strong production from
development  drilling  on the  shelf  and an  additional  deep-water  well  at
Gunnison  partly  offset  the Aspen  decline.  A second  development  well was
drilled at Gunnison  and came on stream in January  2006.  We plan to continue
development  drilling on our maturing  shelf  properties  to maintain  current
production  rates and tie-in our deep-water  discoveries at Wrigley and Dawson
Deep. We expect our Gulf production to average between 40,000 boe/d and 45,000
boe/d in 2006.


                                      38
<PAGE>

NORTH SEA

[Margin Text: We expect our North Sea production to average between 25,000 and
 30,000 boe/d in 2006.]

The Scott and Telford fields acquired in December 2004 contributed a full year
of production averaging 16,400 boe/d. Our North Sea production was impacted by
two generator failures on the Scott platform in early May. We completed repair
work and performed a major maintenance turnaround on the platform in the third
quarter.  The  platform  upgrades and infill  drilling  enabled us to increase
production rates in the second half of the year.

Our  non-operated  Farragon field came on stream in November and was producing
3,900  boe/d net to Nexen  from two  producing  wells at year  end.  We expect
Farragon to contribute  between 3,000 boe/d and 4,000 boe/d to our  production
in 2006.

Our  Buzzard  development  project is on time and on budget,  and we expect to
begin  producing  from  this  field in late  2006.  We expect  our total  year
production  from our North Sea  assets,  which  were  producing  approximately
19,000 boe/d when we purchased  them in late 2004, to average  between  25,000
boe/d and 30,000 boe/d in 2006.

OTHER COUNTRIES

In 2005,  we  completed  abandonment  activities  in  Australia,  which ceased
production  in late 2004.  Production  from the Guando  field in Colombia  was
consistent with 2004, as we maintained rates with nine additional  development
wells. We expect to maintain production rates in Colombia in 2006.

SYNCRUDE

[Margin Text: The Syncrude Stage 3 expansion is expected to increase our
 volumes to between 20,000 and 22,000 bbls/d in 2006.]

Syncrude  production  decreased 10% from 2004 as a result of  maintenance  and
turnaround work on various units during 2005. In January, the delayed start-up
of the LC finer and  unscheduled  repairs  to a  hydrogen  plant  limited  the
hydrotreating  capacity for the first  quarter.  Production  was reduced again
later in the year for a scheduled 52-day turnaround of the vacuum distillation
unit. We exited 2005 at 20,000 bbls/d (net to us) following  completion of the
turnarounds.  Start-up  of the Stage 3 expansion  is expected to increase  our
production capacity by approximately  8,000 bbls/d in mid-2006,  and we expect
our share of total-year  production  from Syncrude to average  between  20,000
bbls/d and 22,000 bbls/d.

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

Production  after  royalties  decreased  6%  from  2003,  half  of  which  was
attributable  to the sale of our non-core  Canadian  light oil  properties  in
southeast Saskatchewan in August 2003.

Production before royalties  decreased 7%, caused by the sale of properties in
August 2003 and  declining  base  production  from our  maturing  conventional
assets in the shallow-water Gulf of Mexico,  Masila in Yemen and our remaining
Canadian properties.  Delays in development drilling programs also contributed
to reduced volumes in Yemen and in the shallow-water Gulf of Mexico.  However,
our deep-water  Gulf of Mexico assets  performed  strongly,  achieving  record
production at Aspen and Gunnison.  This partially offset the declining volumes
from our maturing conventional properties.

In the fourth quarter of 2004, new volumes from our North Sea  acquisition and
initial  production  from  Block  51 in  Yemen  offset  reduced  volumes  from
Australia, where we produced our final barrel in November 2004.

Syncrude  production  increased  12% from 2003,  achieving a new annual record
despite maintenance shut-down of the LC finer at year end.


                                      39
<PAGE>

COMMODITY PRICES

[GRAPHIC OMITTED]
[Margin Graph: Average Realized Oil and Gas Price]

<TABLE>
<CAPTION>
                                                            2005         2004         2003
-------------------------------------------------------------------------------------------
<S>                                                  <C>          <C>          <C>
Crude Oil
  West Texas Intermediate (US$/bbl)                        56.58        41.40        31.04

  Differentials (1) (US$/bbl)
    Heavy Oil - LLK                                        20.82        13.53         8.63
    MARS                                                    6.59         6.15         3.53
    Masila                                                  5.71         4.84         3.03
    Dated Brent                                             2.20            -            -

  Producing Assets (Cdn$/bbl)
    Yemen                                                  62.07        47.59        39.45
    Canada                                                 40.51        36.60        32.37
    United States                                          57.63        46.60        37.68
    United Kingdom                                         60.55        46.81            -
    Australia                                                  -        51.22        43.14
    Other Countries                                        59.96        43.07        38.22
    Syncrude                                               71.00        52.80        43.36

  Corporate Average (Cdn$/bbl)                             58.98        45.90        38.04
-------------------------------------------------------------------------------------------

Natural Gas
  New York Mercantile Exchange (US$/mmbtu)                  8.99         6.19         5.60
  AECO (Cdn$/mcf)                                           8.04         6.44         6.35

Producing Assets (Cdn$/mcf)
    Canada                                                  7.51         5.76         5.64
    United States                                          10.56         7.89         8.16
    United Kingdom                                          7.86         8.28            -

  Corporate Average (Cdn$/mcf)                              8.89         6.85         6.85
-------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------
Nexen's Average Realized Oil and Gas Price (Cdn$/boe)      57.97        44.94        38.63
-------------------------------------------------------------------------------------------

Average Foreign Exchange Rate
Canadian to US Dollar                                     0.8253       0.7683       0.7135
</TABLE>

Note:
1    These differentials are a discount to WTI.


2005 VS 2004--HIGHER REALIZED PRICES ADDED $813 MILLION TO NET INCOME

[Margin Text: A stronger Canadian dollar reduced our realized oil and gas
 prices and reduced net sales by approximately $270 million.]

WTI reached  record highs in 2005 averaging  US$56.58/bbl,  an increase of 37%
compared with  US$41.40/bbl  in 2004. We realized record annual prices for our
crude  oil,  averaging  $58.98/bbl  in 2005,  an  increase  of 28% over  2004.
Although  crude oil reference  prices  increased  37% over 2004,  our realized
prices only increased by 28%, because of wider crude oil  differentials  and a
weaker US dollar.

Our realized  gas price  increased  30% from a year ago to average  $8.89/mcf.
NYMEX increased 45% in the same period, averaging US$8.99/mmbtu.

The full benefit of higher  benchmark  prices wasn't reflected in our realized
prices  because of the weaker US dollar in 2005. All of our oil sales and most
of our gas sales  are  denominated  in, or  referenced  to, US  dollars.  As a
result, the weaker US dollar decreased net sales for the year by approximately
$270  million,  and reduced our  realized  crude oil and natural gas prices by
approximately $4.40/bbl and $0.65/mcf, respectively, compared with 2004.


                                      40
<PAGE>

CRUDE OIL REFERENCE PRICES

[Margin Text: WTI reached new  highs and new levels of volatility in 2005,
reflecting concerns over long-term supply and refining capacity.]

Crude oil prices  remained strong in 2005 reaching new highs and new levels of
volatility.  WTI  prices  peaked  on  August  31 when  trading  broke  through
US$70/bbl.  The  trading  range  for  WTI in 2005  was  between  US$41.25  and
US$70.85.  While global  demand was moderate and supply levels  adequate,  the
stability  and security of  long-term  supply  remained a concern,  along with
tightening  refining  capacity  worldwide.  Throughout  the year,  events that
threatened supply or strained refining capacity caused prices to spike.

[GRAPHIC OMITTED]
[Graph: 2005 WTI Monthly Average Oil Prices]

Several factors  contributed to increased prices and greater market volatility
throughout the year:

o    hurricane  activity in the US Gulf of Mexico  removed  approximately  110
     million barrels of supply and temporarily shut down refining capacity;
o    growing participation by hedge funds and banks in the commodity markets;
o    ongoing  labour  and  political  unrest in crude oil  producing  regions,
     particularly the Middle East, West Africa and Venezuela;
o    political  disputes or  disagreements  between  producing  and  consuming
     regions; and
o    the weaker US dollar.

With sufficient  levels of supply and moderate demand,  crude oil inventories,
particularly in North America,  are at the top of their  historical  range and
almost 30  million  barrels  higher  than last  year.  Given the  shortage  in
refining capacity,  product  inventories,  unlike crude oil inventories,  have
remained tight throughout most of the year.

Most worldwide refining capacity requires  light-sweet crude oil as feedstock,
but only a small  portion  of new supply is light or sweet.  With  light-sweet
crudes in greatest  demand but limited  supply,  prices for both WTI and Brent
have risen.  Events that threatened this supply or refining  capacity  created
volatility.

CRUDE OIL DIFFERENTIALS

[Margin Text: Widening differentials did not allow us to realize
 the full benefit of the increase in WTI.]

Crude oil  differentials  widened in 2005  because of a strong WTI and greater
demand  worldwide for light-sweet  crude oil than for heavy sour crude.  World
supply of heavy oil has been increasing faster than the supply of light crude,
and refining  constraints and environmental  standards  continue to tighten in
favour of lighter crudes. Therefore, we expect differentials between light and
heavy oil to remain wide.

In Canada,  heavy crude oil had some  short-lived  strength during the summer,
but generally  differentials widened in 2005, with benchmark LLK differentials
averaging US$20.82.  Differentials narrowed in the summer, as demand for heavy
blends increased relative to light blends, reflecting normal summer demand for
asphalt.  Hurricane activity kept differentials narrow for longer than normal,
as much of the heavy oil production from the Gulf to the US mid-continent  was
shut-in,  increasing the demand for Canadian heavy oil. The heavy differential
has since  widened  again,  and we expect it to remain  wide into  2007,  when
additional conversion capacity will enable more heavy oil.


                                      41
<PAGE>

Our US Gulf Coast MARS  differential  widened  slightly  in  relation to 2004,
averaging US$6.59/bbl in 2005. While the differential  strengthened during the
year because of growing demand from US-based refiners, it did not outpace WTI,
resulting  in a  slightly  wider  differential.  With  refineries  damaged  by
hurricanes,  there was a  temporary  decline  in demand  that  caused the MARS
differential to widen to US$15. Late in the year, the differential narrowed to
normal levels with the recovery of demand from refiners.

The  Masila  differential  widened  relative  to WTI  during  2005,  averaging
US$5.71/bbl  compared with US$4.84/bbl in 2004.  Despite an increase in demand
from Asia and North America for sweeter blends, the differential still widened
as a result of strong WTI pricing throughout 2005.

The Brent/WTI  differential  strengthened during 2005, averaging  US$2.20/bbl,
resulting  in a solid  crude oil price  for our North Sea  production.  Strong
demand from European refiners, an increase in Asian demand and lost production
in the North Sea combined to push Brent up relative to the North  American WTI
benchmark.

NATURAL GAS REFERENCE PRICES

[Margin Text: NYMEX reached record highs and experienced increased volatility.]

Natural  gas  prices  averaged   US$8.99/mmbtu,   reaching  record  highs  and
experienced increased volatility.  Prices early in the year were propped up by
strong oil prices.  The  disruptions  caused by the  hurricanes  pushed  North
American  gas  prices  to new  highs.  The  volatility  did not end  with  the
hurricane  activity,  but continued into the winter, as markets  speculated on
the impact of a cold or mild winter on tight supply. Prices peaked on December
13, with NYMEX gas  settling at  US$15.38/mmbtu.  Prices have since  softened,
mainly from a weak winter heating season and low inventory withdrawals.

[GRAPHIC OMITTED]
[Graph: 2005 NYMEX Monthly Average Natural Gas Prices]

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 because of the weakening US dollar.  The Canadian to US
dollar exchange rate closed the year at 83(cents).


                                      42
<PAGE>

OPERATING COSTS

<TABLE>
<CAPTION>
                                      2005                             2004                             2003
                        -------------------------------- -------------------------------- --------------------------------
                                 Before           After           Before           After           Before           After
(Cdn$/boe)                    Royalties (1)   Royalties        Royalties (1)   Royalties        Royalties (1)   Royalties
-------------------------------------------------------- -------------------------------- --------------------------------
<S>                         <C>             <C>              <C>             <C>              <C>             <C>
Conventional Oil and Gas
  Yemen                            3.63            6.75             2.80            5.64             2.16            4.37
  Canada                           8.21           10.34             7.12            8.98             6.00            7.76
  United States                    6.35            7.33             5.30            6.12             4.49            5.19
  United Kingdom                  14.90           14.90             8.26            8.26                -               -
  Australia                           -               -            32.94           35.73            18.60           20.21
  Other Countries                  5.55            6.08             3.76            4.09             7.47            9.01
  Average Conventional             6.03            8.70             5.13            7.59             4.17            6.24
-------------------------------------------------------- -------------------------------- --------------------------------

Synthetic Crude Oil
  Syncrude                        26.95           27.22            19.89           20.61            21.96           22.18
Average Oil and Gas                7.36           10.34             6.15            8.83             5.19            7.56
-------------------------------------------------------- -------------------------------- --------------------------------
</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.

2005 VS 2004--HIGHER OIL AND GAS OPERATING COSTS DECREASED NET INCOME BY $91
MILLION

[Margin Text: Higher operating costs per boe reflect a change in our production
 profile, storm-related costs, maintenance activities, higher energy prices and
 industry cost pressures.]

Higher  operating  costs  reflect  the  change in our  profile  as more of our
production  is coming  from  higher-cost  areas such as the North Sea and from
Canadian heavy oil following the Canadian  property sales completed during the
year.  Operating costs were  negatively  impacted by  storm-related  costs and
maintenance  activities.  In  addition,  high levels of industry  activity and
higher energy costs,  driven by record  commodity  prices,  have increased our
operating costs.

Our  operations  at Masila in Yemen are  maturing  and have  higher  operating
costs,  mainly  from  increased  service rig  activity to minimize  production
declines.  These higher costs added  9(cents)/boe  to our  corporate  average.
Costs on a per-unit basis will continue to rise with  increasing  workover and
water handling efforts and from declining production. Block 51 operating costs
were  higher  than  Masila,   reflecting  the  use  of  temporary   production
facilities.  Higher  operating  costs from Block 51  increased  our  corporate
average by 53(cents)/boe. We expect operating costs at Block 51 to decrease in
2006 when we complete the permanent central  processing  facility early in the
year.

Industry cost pressures and the sale of conventional  production increased our
Canadian unit operating costs in 2005.  Although we sold high-cost  production
relative to our corporate  average,  we expect our overall Canadian  operating
costs to increase as we will have  proportionately  higher production from our
heavy oil properties.  These  properties have higher operating costs and lower
recovery rates  compared to the lighter oil  production  that was sold. We are
focused  on  increasing  recovery  rates  from our  heavy  oil  properties  by
developing new technologies.

In the Gulf of Mexico,  lower volumes of higher-cost  barrels at Aspen,  along
with $12 million of Aspen-1 intervention costs expensed in 2004, decreased our
corporate average by 10(cents)/boe. Workovers on our shelf properties, coupled
with lower  production  and property  damage  costs not covered by  insurance,
increased our corporate average by 5(cents)/boe from 2004.

The addition of  higher-cost  North Sea  production  increased  our  corporate
average unit costs by  $1.14/boe.  Our North Sea  operating  costs were higher
than  anticipated  as a result  of  maintenance  and  repair  work  caused  by
generator failures in the second quarter and major maintenance  turnaround and
facilities upgrading at the Scott platform in the third quarter. We expect our
North Sea operating costs to decrease on a per-unit basis in 2006.

Our  Australian  operations  ceased  in late 2004 and the  exclusion  of these
high-cost, late-life barrels reduced our corporate average by 57(cents)/boe.


                                      43
<PAGE>

US-dollar  denominated  operating costs were lower when translated to Canadian
dollars as a result of the weak US dollar.  Our corporate  average was reduced
by 30(cents)/boe as a result.

Syncrude operating costs per boe were 35% higher than in 2004.  Turnaround and
maintenance  costs  accounted for half of the increase,  as we completed major
turnarounds  on various  upgrading  units during the year.  When combined with
higher energy costs required in the upgrading  process,  our corporate average
increased by 34(cents)/boe.

[Margin Text: We expect our 2006 operating costs per unit to increase due to
 a change in our production mix and industry cost pressures.]

In 2006,  we expect  operating  costs per unit to increase.  This reflects the
higher  proportion  of Canadian  heavy oil  production in our  production  mix
following  the 2005  Canadian  property  sales,  coupled  with  industry  cost
pressures in all of our operating areas.

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

Our operating costs 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.

At Masila in Yemen, flow line replacements,  higher  water-handling  costs and
more   maintenance   increased  our   corporate   unit   operating   costs  by
30(cents)/boe.  However,  these  increased  costs in Yemen  only  reduced  our
corporate  netbacks by 5(cents)/boe as a result of the cost recovery mechanism
in our production sharing agreement.

Operating  costs in Canada were  slightly  lower than in 2003,  but because of
declining   volumes,   our   corporate   average   unit  costs   increased  by
25(cents)/boe.

Aspen-1  intervention  costs of $12 million were  expensed in 2004.  They were
higher than  expected,  as storm  activity in the Gulf of Mexico  extended the
work.  These costs,  together with higher  workover  activities in the shallow
water, contributed a 28(cents)/boe increase to our corporate unit costs.

The incremental North Sea barrels added  7(cents)/boe to our corporate average
in 2004.

Australia  produced  its  final  barrel  in  November  2004.  These  expensive
late-life  barrels  increased our corporate unit costs by  30(cents)/boe,  but
high crude prices allowed us to produce them economically.

The  strength  of  the  Canadian  dollar  reduced  our  US-dollar  denominated
operating costs,  contributing a 25(cents)/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  were no major
turnarounds.  As more expensive  Syncrude barrels were a larger portion of our
total  corporate  production  in 2004,  our  corporate  unit  operating  costs
increased by 17(cents)/boe.


                                      44
<PAGE>

DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT (DD&A)

<TABLE>
<CAPTION>
                                      2005                             2004                             2003
                        -------------------------------- -------------------------------- --------------------------------
                                 Before           After           Before           After           Before           After
(Cdn$/boe)                    Royalties (2)   Royalties        Royalties (2)   Royalties        Royalties (2)   Royalties
-------------------------------------------------------- -------------------------------- --------------------------------
<S>                         <C>             <C>              <C>             <C>              <C>             <C>
Conventional Oil and Gas
  Yemen                            8.56           15.93             4.35            8.77             3.96            8.03
  Canada (1)                       9.26           11.67             9.02           11.37             9.10           11.76
  United States                   15.39           17.77            12.93           14.93            10.80           12.47
  United Kingdom                  33.25           33.25            22.44           22.44                -               -
  Australia                           -               -             5.82            6.31            13.31           14.46
  Other Countries                  6.20            6.79             9.90           10.77            17.09           22.47
  Average Conventional            11.78           17.00             7.87           11.64             7.37           11.04
-------------------------------------------------------- -------------------------------- --------------------------------

Synthetic Crude Oil
  Syncrude                         3.08            3.12             2.75            2.85             2.50            2.53
Average Oil and Gas               11.23           15.77             7.52           10.80             7.09           10.33
-------------------------------------------------------- -------------------------------- --------------------------------
</TABLE>

Notes:
1    2003 DD&A per boe excludes the impairment  charge  described in Note 6 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.

2005 VS 2004--HIGHER OIL AND GAS DD&A DECREASED NET INCOME BY $308 MILLION

[Margin Text: Our 2005 DD&A rate increased, reflecting additional capital cost
 recovery from Block 51 and new production from the North Sea.]

Strong  production  volumes,  new  production  from our North Sea  assets  and
additional  capital cost recovery from Block 51 in Yemen increased our oil and
gas DD&A  compared with 2004 levels.  We also expensed $58 million  related to
unproved  North  Sea  properties  as  a  result  of  unsuccessful  exploration
activities.

Block 51  production  in Yemen  increased  our  corporate  unit  depletion  by
$2.21/boe  from  2004 as a  result  of  carried  interest  accounting  for the
recovery of Block 51 capital costs.  Strong production and higher realized oil
prices have resulted in faster  recovery of capital costs we paid on behalf of
the government.

Our Canadian  depletion  rate per unit has  increased  slightly  compared with
2004.  Reserve  revisions  at the end of 2004  increased  our 2005  heavy  oil
depletion rate.  This increase was somewhat  offset when we stopped  depleting
our  Canadian  assets held for sale in the second  quarter,  but  continued to
recognize  related  production.  The  disposition of these assets in the third
quarter  changed  our asset  mix and  reduced  our  average  annual  corporate
depletion rate by 23(cents)/boe.

Depletion rates in the Gulf of Mexico increased following reserve revisions in
late 2004. Reduced volumes offset the increase in rates with minimal impact on
our overall unit rate.

North Sea depletion  increased our corporate average by $2.37/boe in 2005. The
depletable carrying costs of our Scott, Telford and Farragon fields include an
allocation of the purchase  price we paid for these assets.  In addition,  our
North Sea depletion  includes $58 million  relating to a partial  write-off of
our purchase price allocation to unproved  properties  subject to unsuccessful
exploration activities.

The  strengthening  Canadian dollar offset these increases as the depletion of
our international and US assets is denominated in US dollars. This lowered our
corporate average by 70(cents)/boe compared with 2004.


                                      45
<PAGE>

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  because of  negative  reserve  revisions  on our  Canadian  heavy oil
properties.  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(cents)/boe.  However, these properties 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(cents)/boe  mainly because additional
volumes from Block 51 slightly offset lower Masila volumes.  The new North Sea
volumes increased our corporate rate by  20(cents)/boe.  Our UK depletion rate
of $22.44/boe reflects the depletion of part 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.

The strong Canadian dollar lowered our depletion rate by 45(cents)/boe, as the
depletion of our US and international  assets is denominated in US dollars. As
well, the depletable  costs on our Canadian heavy oil properties  were reduced
at year-end 2003,  and both Australia and Nigeria were almost fully  depleted.
The writedown of our Canadian heavy oil properties  reduced our depletion rate
by  31(cents)/boe,   and  lower  volumes  in  Canada,  Australia  and  Nigeria
contributed to a combined reduction of 65(cents)/boe.

EXPLORATION EXPENSE (1)

[Margin Text: Exploration success in the Gulf of Mexico and UK decreased our
 exploration expense to 49% of total exploration expenditures.]

<TABLE>
<CAPTION>
(Cdn$ millions)                                              2005        2004        2003
------------------------------------------------------------------------------------------
<S>                                                          <C>         <C>         <C>
Seismic                                                        53          73          62
Unsuccessful Drilling                                         143         125          70
Other                                                          55          48          69
------------------------------------------------------------------------------------------
Total Exploration Expense                                     251         246         201
==========================================================================================

New Growth Exploration                                        456         266         267
Geological and Geophysical Costs                               53          73          62
------------------------------------------------------------------------------------------
Total Exploration Expenditures                                509         339         329
==========================================================================================

Exploration Expense as a % of Exploration Expenditures        49%         73%         61%
</TABLE>

Note:
1    Includes exploration expense from discontinued operations. See Note 14 to
     our Consolidated Financial Statements.

2005 VS 2004--HIGHER EXPLORATION EXPENSE REDUCED NET INCOME BY $5 MILLION

Our 2005  exploration  program was our most active in company  history,  as we
spent more than $500 million on 20 high-potential exploration wells in our key
basins. In the Gulf of Mexico, Knotty Head, drilled to a depth of 34,189 feet,
encountered hydrocarbons in multiple zones. We are continuing to appraise this
discovery  in  2006,  initially  by  drilling  a  side-track  well to  further
delineate  the  reservoir.  Additional  delineation  in 2006 is  contingent on
finding a rig to continue our program here.  Smaller  successes in the Gulf of
Mexico and the North Sea will be further evaluated in 2006. Drilling equipment
has been contracted for the majority of this work.


                                      46
<PAGE>

Our exploration  expense includes costs associated with unsuccessful  wells in
the Gulf of Mexico,  North Sea, offshore West Africa and Yemen. In the Gulf of
Mexico, we expensed $44 million for the Vrede well. Vrede, a sub-salt prospect
drilled to a total depth of 32,600 feet, encountered non-commercial quantities
of  hydrocarbons  and was  temporarily  abandoned.  We also  wrote  off  costs
relating to our Castleton dry hole together with trailing costs related to the
2004 Crested Butte, Wind River and Fawkes wells.

[Margin Text: In the UK, we wrote off Black Horse and Polecat since stand-alone
 developments were not feasible. However, these wells could be developed in
 combination with other projects.]

In the North Sea,  exploration expense includes costs relating to Black Horse,
Polecat,  Bennachie and Saracen. The Black Horse and Polecat wells encountered
hydrocarbons,  but insufficient to warrant  stand-alone  development.  We will
continue to evaluate  these  reservoirs in  combination  with other  potential
development  projects  that may be  sanctioned  in the future.  Bennachie  was
abandoned after  encountering  no reservoir sands in the target zone.  Saracen
was written off earlier in the year as an unsuccessful exploratory well.

Internationally, we expensed costs related to four unsuccessful wells on Block
51 in Yemen and we abandoned our deep-water Efere well in Nigeria,  as well as
our K-2 well on Block K in Equatorial Guinea.

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

Higher  exploration  expense  reflected  the increase in our 2004  exploration
capital  expenditures.  We had  further  success  at  Usan on  Block  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, Equatorial Guinea,
and in Yemen.

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 costs for
this  well in the  fourth  quarter.  We  drilled  Main  Pass 240 and found the
objective  sand wet, so we abandoned the well 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.  Fawkes and Wind River completed drilling and were abandoned in
early 2005, resulting in a write-off of $13 million in 2004. Overall, dry hole
and  seismic  costs in the Gulf of Mexico  accounted  for more than 50% of our
exploration expense.

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.


                                      47
<PAGE>

OIL & GAS AND SYNCRUDE NETBACKS

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

[GRAPHIC OMITTED]
[Margin Graph: Cash Netback Before Royalties]

BEFORE ROYALTIES

<TABLE>
<CAPTION>
                                                                    2005
                                ---------------------------------------------------------------------------
($/boe)                         Yemen     Canada          US         UK      Other     Syncrude      Total
-----------------------------------------------------------------------------------------------------------
<S>                         <C>        <C>        <C>         <C>        <C>        <C>          <C>
Sales                           62.07      42.42       60.26      57.83      59.96        71.00      57.97
Royalties and Other            (28.71)     (8.75)      (8.06)         -      (5.23)       (0.71)    (16.70)
Operating Expenses              (3.63)     (8.21)      (6.35)    (14.90)     (5.55)      (26.95)     (7.36)
In-country Taxes                (7.17)         -           -          -          -            -      (3.34)
-----------------------------------------------------------------------------------------------------------

Cash Netback                    22.56      25.46       45.85      42.93      49.18        43.34      30.57
===========================================================================================================
</TABLE>

<TABLE>
<CAPTION>
                                                                    2004
                 ------------------------------------------------------------------------------------------
($/boe)              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
===========================================================================================================
</TABLE>

<TABLE>
<CAPTION>
                                                                    2003
                            -------------------------------------------------------------------------------
($/boe)                         Yemen     Canada         US   Australia      Other     Syncrude      Total
-----------------------------------------------------------------------------------------------------------
<S>                         <C>        <C>        <C>        <C>         <C>        <C>          <C>
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
===========================================================================================================
</TABLE>

AFTER ROYALTIES

<TABLE>
<CAPTION>
                                                                    2005
                           --------------------------------------------------------------------------------
($/boe)                         Yemen     Canada          US         UK      Other     Syncrude      Total
-----------------------------------------------------------------------------------------------------------
<S>                         <C>        <C>        <C>         <C>        <C>        <C>          <C>
Sales                           62.07      42.42       60.26      57.83      59.96        71.00      57.97
Operating Expenses              (6.75)    (10.34)      (7.33)    (14.90)     (6.08)      (27.22)    (10.34)
In-country Taxes               (13.35)         -           -          -          -            -      (4.69)
-----------------------------------------------------------------------------------------------------------

Cash Netback                    41.97      32.08       52.93      42.93      53.88        43.78      42.94
===========================================================================================================
</TABLE>

<TABLE>
<CAPTION>
                                                                    2004
                 ------------------------------------------------------------------------------------------
($/boe)              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
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
===========================================================================================================
</TABLE>

<TABLE>
<CAPTION>
                                                                    2003
                           --------------------------------------------------------------------------------
($/boe)                         Yemen     Canada         US   Australia      Other     Syncrude      Total
-----------------------------------------------------------------------------------------------------------
<S>                         <C>        <C>        <C>        <C>         <C>        <C>          <C>
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
===========================================================================================================
</TABLE>


                                      48
<PAGE>

OIL AND GAS MARKETING

[GRAPHIC OMITTED]
[Margin Graph: Transportation Capacity]

<TABLE>
<CAPTION>
(Cdn$ millions)                                    2005        2004        2003
--------------------------------------------------------------------------------
<S>                                          <C>         <C>         <C>
Revenue                                             847         608         568
Transportation                                     (641)       (451)       (398)
Other                                                (2)         (2)         (1)
--------------------------------------------------------------------------------
Net Marketing Revenue                               204         155         169

Marketing Contribution to Income from
  Continuing Operations before Income Taxes         104          87         111
================================================================================

Natural Gas
  Physical Sales Volumes (1) (bcf/d)                4.9         4.9         3.3
  Transportation Capacity (bcf/d)                   4.0         3.5         2.0
  Storage Capacity (bcf)                             30          27          18

Crude Oil
  Physical Sales Volumes (1) (mbbls/d)              510         465         479
  Storage Capacity (mbbls)                          580         408           -

Value-at-Risk
  Year-end                                           24          21          21
  High                                               28          42          31
  Low                                                11          17          14
  Average                                            21          29          20
</TABLE>

Note:
1    Excludes intra-segment transactions.

2005 VS 2004--NET MARKETING REVENUE INCREASED NET INCOME BY $49 MILLION

[Margin Text: Gas marketing contributed 57% of marketing net revenue
 in 2005.]

Marketing  delivered strong results in 2005, with net revenue of $204 million.
Our gas marketing  group grew their net revenue to $117  million.  We achieved
these results through our continued focus on an asset-based  trading strategy,
using our  transportation  and storage  capacity to take advantage of seasonal
and locational pricing differences and market inefficiencies.

While 2005 was a profitable year, it was also volatile with hurricane activity
in  the  Gulf  of  Mexico  disrupting  gas  supply  and  infrastructure.  This
volatility  caused us to  recognize  losses in the third  quarter on financial
contracts  hedging our  physical  assets.  However,  we were able to recognize
gains  on  our  physical   assets  in  the  fourth  quarter  as  we  used  our
transportation  capacity and sold gas from storage.  This allowed us to recoup
our third  quarter  losses and  recognize  $175  million of net revenue in the
fourth  quarter.  We also  generated  profits from  financial  contracts  that
captured time and location spreads.

Our crude oil marketing group  contributed $65 million of net revenue in 2005,
an  increase  of 33% over  2004.  Similar  to prior  years,  we  continued  to
capitalize on forward prices,  as well as differences in crude  qualities.  In
particular,  in 2005,  we took  advantage of contango  (rising  forward  month
prices) by  successfully  pricing our purchases  lower than our sales,  and by
financially  trading calendar spreads. We also captured profits around quality
spreads by diverting  crude oil, or by blending to enhance the crude  quality,
and attract higher prices.

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

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.


                                      49
<PAGE>

During  2004,  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  and move gas to where it was
needed  most.  We also held  financial  contracts  that  enabled 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 forward month prices) in the forward price
curve  throughout  the year enabled 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 in
2003. Throughout 2004, we successfully capitalized on the pricing of purchases
relative to sales, as we took advantage of  backwardation in the forward price
curve.

COMPOSITION OF NET MARKETING REVENUE

(Cdn$ millions)                                              2005          2004
--------------------------------------------------------------------------------
Trading Activities                                            168           133
Non-Trading Activities                                         36            22
--------------------------------------------------------------------------------
Total Net Marketing Revenue                                   204           155
================================================================================

TRADING ACTIVITIES

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

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 included with 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.

FAIR VALUE OF DERIVATIVE CONTRACTS

At  December  31,  2005,  the  fair  value  of our  derivative  contracts  not
designated as hedges  totalled $169 million  (2004--$93  million).  Below is a
breakdown of this fair value by valuation method and contract maturity.

[Margin Text: More than 35% of our unrealized fair value relates to contracts
 that will settle in 2006.]

<TABLE>
<CAPTION>
                                                           Maturity
--------------------------------------------------------------------------------------------
                                 (less than)                         (more than)
(Cdn$ millions)                      1 year   1-3 years   4-5 years     5 years       Total
--------------------------------------------------------------------------------------------
<S>                              <C>         <C>         <C>         <C>              <C>
Prices
  Actively Quoted Markets               (29)         14         (18)         (3)        (36)
  From Other External Sources            90         100          12           3         205
  Based on Models and Other
    Valuation Methods                     -           -           -           -           -
--------------------------------------------------------------------------------------------
Total                                    61         114          (6)          -         169
============================================================================================
</TABLE>

These  unrealized  fair  values  will be  realized  over  time as the  related
contracts  settle.  Until  then,  the  value of the  contracts  will vary with
forward  commodity  prices.  While  forward  prices  vary,  the  value  of our
contracts  only  varies  to  the  extent  they  are  economically  exposed  or
unprotected.  As most of our unrealized value is not economically  exposed, we
expect to realize most of this fair value.

More than 35% of the  unrealized  fair value  relates to  contracts  that will
settle in 2006.  Contract maturities vary from a single day up to eight years.
Those maturing beyond one year primarily relate to North


                                      50
<PAGE>

American  natural  gas  positions.   The  relatively  short  maturity  of  our
contracts,  the  high  quality  of our  valuations  and the  limited  economic
exposure combine to lower our portfolio risk.

Included in the  derivative  contracts  that we  mark-to-market  are financial
contracts  that act as  economic  hedges of our  physical  transportation  and
storage  capacity.  For  economic  purposes,  we monitor the fair value of our
transportation  and  storage  capacity as well as any  commodities  we have in
storage, but we do not record this value in income until realized.  At the end
of 2005,  the  unrecognized  fair value of these  transportation  and  storage
positions was $29 million.

We have designated certain derivative contracts as accounting cash flow hedges
of the future sale of our gas in storage.  Mark-to-market  gains and losses on
these  designated  contracts  are excluded  from income  until the  underlying
inventory is sold.  At December 31, 2005,  we had $35 million of  unrecognized
losses on these  derivative  contracts.  These contracts have been valued from
actively quoted markets and will settle within 12 months.

CHANGES IN FAIR VALUE OF DERIVATIVE CONTRACTS

<TABLE>
<CAPTION>
                                                             Contracts
                                                           Outstanding        Contracts
                                                          at Beginning     Entered into
(Cdn$ millions)                                                of Year      During Year            Total
---------------------------------------------------------------------------------------------------------
<S>                                                    <C>              <C>              <C>
Fair Value at December 31, 2004                                     93                -               93
  Change in Fair Value of Contracts                                 92               90              182
  Net Losses (Gains) on Contracts Closed                           (47)             (59)            (106)
  Changes in Valuation Techniques and Assumptions (1)                -                -                -
---------------------------------------------------------------------------------------------------------
Fair Value at December 31, 2005                                    138               31              169
=========================================================================================================

Unrecognized Losses on Hedges of Future Sale of
  Gas Inventory at December 31, 2005                                                                (35)
---------------------------------------------------------------------------------------------------------
Total Outstanding at December 31, 2005                                                               134
=========================================================================================================
</TABLE>

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


TOTAL CARRYING VALUE OF DERIVATIVE CONTRACTS

(Cdn$ millions)                                                2005        2004
--------------------------------------------------------------------------------
Current Assets                                                  382         177
Non-Current Assets                                              232          91
--------------------------------------------------------------------------------
Total Derivative Contract Assets                                614         268
================================================================================

Current Liabilities                                             321         129
Non-Current Liabilities                                         124          46
--------------------------------------------------------------------------------
Total Derivative Contract Liabilities                           445         175
================================================================================

Total Derivative Contract Net Assets (1)                        169          93
================================================================================

Note:
1    Excludes  derivative  contracts  that have been  designated as accounting
     hedges.

NON-TRADING ACTIVITIES

[Margin Text: We enter into
 fee-for-service contacts related to transportation and storage, and increased
 our transportation capacity
 in 2004 and 2005.]

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  $36  million  from our  non-trading  activities  in 2005
(2004--$22 million).

In 2004 and 2005,  we increased our  transportation  capacity and were paid to
assume future obligations associated with the capacity. We have $28 million of
deferred  revenue on our balance sheet to recognize  the liability  associated
with these obligations. We are amortizing this deferred revenue to earnings as
the capacity is used.


                                      51
<PAGE>

CHEMICALS

(Cdn$ millions)                                      2005      2004      2003
------------------------------------------------------------------------------
Net Sales                                             398       378       375
Sales Volumes (thousand short tons)
  Sodium Chlorate                                     493       506       478
  Chlor-alkali                                        400       403       396
Operating Profit (1)                                  136       105        95
Operating Margin (2)                                  34%       28%       25%
Chemicals Contribution to Income from Continuing
  Operations Before Income Taxes                       37        40        28
Capacity Utilization                                  96%       95%       95%

Notes:
1    Total revenues less operating costs, transportation and other.
2    Operating profit divided by net sales.

2005 VS 2004--HIGHER CHEMICALS OPERATING PROFIT INCREASED NET INCOME
BY $31 MILLION

[Margin Text: We monetized a portion of our chemicals business in 2005,
 retaining a 61.4% indirect interest.]

In the third quarter of 2005, we monetized a portion of our chemicals business
by creating the Canexus Income Fund through an initial public  offering (IPO),
which raised net proceeds of $301  million.  Canexus  Income Fund invested the
offering proceeds into Canexus Limited  Partnership,  which also raised US$167
million ($200  million) of bank debt.  Canexus  Limited  Partnership  used the
proceeds from Canexus  Income Fund's IPO and the bank debt,  together with the
issuance of 50.5 million exchangeable units of the Canexus Limited Partnership
to Nexen, to purchase our chemicals operations. The exchangeable units we hold
had a market value of $442 million at December  31, 2005.  We have  retained a
61.4% indirect interest in the chemicals  operations through our investment in
Canexus  Limited  Partnership,  and we recorded a gain of $193  million on the
dilution of our interest.

[Margin Text: Despite lower sales volumes, strong
 chlor-alkali prices and higher margins generated strong 2005 results
 for chemicals.]

Despite lower sales  volumes,  strong  chlor-alkali  prices and higher margins
generated strong results for the chemicals  business.  Sodium chlorate volumes
decreased  compared  with 2004 as a result of our  decision  in early  2005 to
forego low-margin  business  consistent with our restructuring  effort and the
closure of our  Amherstburg,  Ontario  plant.  Sales and  operations  from the
Brazil  plant  remained  strong as a result of  continued  strong  demand from
Aracruz Cellulose, our primary customer in Brazil, and an expanded presence in
the merchant market.

The weaker US dollar put pressure on our US-dollar denominated sales, reducing
net sales by $13 million. During 2005, we purchased US-dollar foreign currency
call options to mitigate our exposure to the weakening dollar. We generated $4
million of income as a result of these call options.

Our chemicals contribution was reduced by $12 million for an impairment charge
relating to our chemicals plant in Amherstburg,  which was closed in the third
quarter of 2005.

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.
However,  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.

We successfully  completed the expansion of our plant in Brandon,  Manitoba in
October 2004, 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 a stable,  regulated electricity
market.

At our Brazil plant,  production  improvements enabled us to take advantage of
strong market demand.


                                      52
<PAGE>

CORPORATE EXPENSES

GENERAL AND ADMINISTRATIVE (G&A) (1)

(Cdn$ millions)                                    2005        2004        2003
--------------------------------------------------------------------------------
General and Administrative Expense before
  Stock Based Compensation                          302         206         176
Stock Based Compensation (2)                        490          93          14
--------------------------------------------------------------------------------
Total General and Administrative Expense            792         299         190
================================================================================

Notes:
1    Includes  G&A  from   discontinued   operations.   See  Note  14  to  our
     Consolidated Financial Statements.
2    Includes tandem option plan, stock options for our US-based employees and
     stock appreciation rights.

2005 VS 2004--HIGHER COSTS REDUCED NET INCOME BY $493 MILLION

[Margin Text: Our stock-based compensation expense increased $397 million in
 2005, as our share price increased 128%.]

Our stock-based compensation expense in 2005 reflects the significant increase
in the price of our common shares.  Our share price increased 128% from $24.35
to $55.42,  adding  more than $8 billion of  shareholder  value.  The  expense
represents   approximately   6%  of  the   increase  in   shareholder   value.
Notwithstanding  this increase in our share price,  cash payments to employees
under our stock-based compensation programs only amounted to $79 million.

Our  growing  international  presence  and  the  expansion  of our  businesses
increased  our G&A  costs  during  the year.  Costs  reflect  more  employees,
additional travel,  and higher compliance and governance costs,  combined with
increased variable incentive compensation stemming from our record results. We
also incurred  additional costs related to our disposition  activities and the
integration of our North Sea operations acquired in late 2004.

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

During the second quarter,  our shareholders  approved the modification of our
stock option plan to a tandem option plan,  creating a one-time G&A expense of
$82 million.

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

INTEREST

(Cdn$ millions)                                    2005        2004        2003
--------------------------------------------------------------------------------
Interest (1)                                        275         194         212
  Less: Capitalized                                (178)        (51)        (43)
--------------------------------------------------------------------------------
Net Interest Expense                                 97         143         169
================================================================================

Effective Rate                                     6.4%        6.6%        7.2%

Note:
1    Includes  dividends on preferred  securities  in 2004 and 2003.  See Note
     1(u) to our Consolidated Financial Statements.

2005 VS 2004--LOWER NET INTEREST EXPENSE INCREASED NET INCOME BY $46 MILLION

[Margin Text: Our effective interest rate has dropped the last two years as we
 replaced higher-cost preferred securities with lower-cost long-term debt.]

We acquired  our North Sea assets in late 2004.  We  partially  financed  this
acquisition  with US$1 billion of new  long-term  debt,  which  increased  our
interest  costs by $87 million in 2005.  Interest  expense  also  increased $3
million relating to the Canexus debt consolidated  with our results.  However,
the stronger Canadian dollar lowered our US-dollar denominated interest by $12
million.  During the last two  years,  we have taken  advantage  of  declining
interest  rates by replacing our  higher-cost  preferred  securities  with new
long-term debt at lower rates.


                                      53
<PAGE>

We  capitalize  interest on our major  development  projects in the North Sea,
Syncrude, Long Lake and Block 51 in Yemen based on our average borrowing rate.
Capitalized interest grew primarily from the increased investment in the North
Sea  Buzzard  project  and  additional   spending  at  Long  Lake.  We  expect
capitalized interest to continue increasing as we invest additional capital on
these projects prior to their completion in 2006 and 2007.

2004 VS 2003--LOWER NET 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.
These two events reduced  interest  expense in 2004. In December 2004, we drew
US$1.5 billion on our acquisition  credit  facilities to provide financing for
our UK North Sea  acquisition,  increasing our interest expense by $5 million.
The strong Canadian dollar lowered our US-dollar  denominated interest expense
by $6 million.

Capitalized  interest  increased over 2003 from additional capital spending at
our major development  projects  including Syncrude Stage 3 expansion and Long
Lake in Canada, Block 51 in Yemen and Buzzard in the North Sea.

INCOME TAXES

[Margin Text: Our 2005 effective tax rate decreased to 9%, as we revalued our
 future income tax liabilities after dispositions and recognized a recovery
 of $229 million.]

(Cdn$ millions)                                            2005    2004    2003
--------------------------------------------------------------------------------
Current                                                     339     248     210
Future                                                     (229)    119     (57)
--------------------------------------------------------------------------------
Total Provision for Income Taxes                            110     367     153
================================================================================

Disclosed as:
Provision for Income Taxes--Continuing Operations           239     317      97
Provision for Income Taxes--Discontinued Operations (1)    (129)     50      56
--------------------------------------------------------------------------------
Total Provision for Income Taxes                            110     367     153
================================================================================

Effective Rate                                               9%     32%     21%

Note:

1    See Note 14 to our Consolidated Financial Statements.

2005 VS 2004--EFFECTIVE TAX RATE DECREASES FROM 32% TO 9%

The recovery of future taxes  payable of $229 million is  attributable  to the
disposition of our oil and gas producing  properties in Canada and the sale of
our chemicals business to the Canexus Limited Partnership.  As a result of the
dispositions,  we revalued our future income tax liabilities for the change in
the underlying book and tax values. This revaluation resulted in the reduction
of our future income tax liabilities.  In addition, the disposition gains were
taxed at lower  capital  gains  tax  rates.  Removing  the tax  impact  of the
dispositions, the effective tax rate for our continuing operations was 32%.

In a recent  pre-budget  announcement,  the UK  government  said it intends to
increase the 10% supplemental  charge on income from oil and gas activities to
20% effective January 1, 2006. This increase is subject to the introduction of
legislation.  If this  announcement  becomes law, we expect our  effective tax
rate to increase above 32%.

Current  income taxes include cash taxes in Yemen of $296 million  (2004--$227
million;  2003--$201 million).  Our current income tax provision also includes
cash taxes in Colombia, federal and state taxes in the US and capital taxes in
Canada.

2004 VS 2003--EFFECTIVE TAX RATE INCREASES FROM 21% 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.


                                      54
<PAGE>

OTHER

(Cdn$ millions)                                        2005      2004     2003
-------------------------------------------------------------------------------
Gain on Dilution of Interest in Chemicals Business      193         -        -
Gain on Disposition of Oil and Gas Assets
  included as Discontinued Operations                   225         -        -
Increase (Decrease) in Fair Value of Crude
  Oil Put Options                                      (196)       56        -

As a result  of the sale of our  chemicals  business  to the  Canexus  Limited
Partnership,  we recorded a gain on the dilution of our interest  from 100% to
61.4% of $193 million. Our gain on the sale of Canadian oil and gas properties
in Alberta,  British Columbia and Saskatchewan was $225 million.  This gain is
net of losses attributable to pipeline contracts and fixed-price gas contracts
associated with these  properties  that we retained,  but no longer use in our
oil and gas business.

Following our North Sea  acquisition in late 2004, we purchased put options on
60,000 bbls/d of oil  production for 2005 and 2006 to ensure base cash flow in
those years while we invest in our major development  projects.  These options
created an average floor price for this production of US$43.17/bbl in 2005 and
US$38.17/bbl in 2006.  Accounting rules require that these options be recorded
at fair value throughout their term. As a result, changes in forward crude oil
prices  cause gains or losses to be  recorded on these  options at each period
end.  A gain of $56  million  was  recorded  in the  fourth  quarter  of 2004,
bringing  the fair value of these  options to $200  million.  During  2005,  a
significant  increase in forward crude prices resulted in a value loss of $196
million.  The  carrying  value of these  options at  December  31, 2005 was $4
million.

IMPACT OF FOREIGN EXCHANGE ON OPERATIONS

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

The strengthening  Canadian dollar relative to the US dollar reduced cash flow
from operating  activities by $251 million and our net income by $116 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 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,  but  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 an  increase  to our future  income tax  liabilities,  which is offset by a
decrease to our cumulative translation adjustment account.

OUTLOOK FOR 2006

[Margin Text: In 2006, we plan to invest $2.9 billion in value-generating
 capital projects. See page 32 for more details.]

In 2006, we plan to invest $2.9 billion in value-generating  capital projects.
Approximately  45% of this  capital  will be  invested  in  major  development
projects.  These  include  Buzzard,  Long Lake,  coal bed methane and Syncrude
Stage 3, all planned to come on stream in 2006 and 2007. We are also directing
10% of our 2006  capital  to early  stage  development  projects  expected  to
contribute  production and cash flow beyond 2006. These include development of
additional CBM lands, enhanced oil recovery projects, additional phases of oil
sands and existing North Sea discoveries. We have allocated 21% of our capital
to high-quality  exploration  opportunities in our growth areas. The remaining
24% of the 2006 capital will be invested to exploit  potential in our existing
producing assets and in other corporate assets.

Details of our 2006  capital  investment  program are  included in the Capital
Investment section of the MD&A.


                                      55
<PAGE>

DAILY PRODUCTION

[Margin Text: In 2007, we expect  production  after  royalties to grow by more
 than 50% over current volumes.]

Even  after  selling  Canadian  production  in  mid-2005,  we expect  our 2006
production  before royalties to be similar to 2005. Our annual  production for
2006 is expected to average  between  220,000  boe/d and 240,000  boe/d before
royalties, 165,000 boe/d and 180,000 boe/d after royalties, as follows:

2006 ESTIMATED PRODUCTION

(mboe/d)                                  Before Royalties    After Royalties
------------------------------------------------------------------------------
Gulf of Mexico                                  40  -   45         33  -   38
North Sea                                       25  -   30         25  -   30
Yemen                                           90  -  100         50  -   55
Canada                                          35  -   40         27  -   31
Syncrude                                        20  -   22         18  -   20
Other International                              6  -    7          5  -    6
------------------------------------------------------------------------------
Total                                          220  -  240        165  -  180
==============================================================================

We expect our production  will grow  significantly  in 2007, as we gain a full
year of  high-margin  production  from Buzzard and Syncrude  Stage 3, and Long
Lake synthetic volumes come on stream.  Production after royalties is expected
to  increase  by more  than  50% in  2007,  generating  strong  growth  in our
operating margins and cash flow, assuming commodity prices remain strong.

CASH FLOW AND SENSITIVITIES

[Margin Text: We expect to generate more than $2.6 billion in cash flow from
 operating activities in 2006. A US$1/bbl change in WTI will impact cash flow
 by $40 million.]

We expect to  generate  more than  $2.6  billion  in cash flow from  operating
activities in 2006 (before site  restoration  and geological  and  geophysical
expenditures), assuming the following:

------------------------------------------------------------------------------
WTI (US$/bbl)                                                           55.00
NYMEX Natural Gas (US$/mmbtu)                                            9.25
US to Canadian Dollar Exchange Rate                                      0.85
------------------------------------------------------------------------------

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

(Cdn$ millions)
------------------------------------------------------------------------------
WTI--US$1 Change                                                           40
NYMEX Natural Gas--US $0.10 Change                                          7
Exchange Rate--$0.01 Change                                                25
------------------------------------------------------------------------------

We expect our chemicals and marketing  businesses to continue generating solid
contributions  to cash flow and net income in 2006.  We continue to see strong
demand and high prices for our chemical products.  Solid North American energy
markets are expected in 2006,  which will enable our marketing group to profit
from our  asset-based  trading  strategy.  Our marketing group plans to expand
into  European  markets with the addition of crude oil volumes from Buzzard in
the North Sea.


                                      56
<PAGE>

LIQUIDITY AND CAPITAL RESOURCES

CAPITAL STRUCTURE

(Cdn$ millions)                                              2005        2004
------------------------------------------------------------------------------
Net Debt (1)
  Bank Debt                                                   171       1,993
  Public Senior Notes                                       2,980       1,813
  Senior Debt                                               3,151       3,806
  Subordinated Debt                                           536         553
------------------------------------------------------------------------------
    Total Debt                                              3,687       4,359
  Less: Cash and Cash Equivalents                             (48)        (73)
  Less: Restricted Cash                                       (70)          -
------------------------------------------------------------------------------
                                                            3,569       4,286
  Less: Non-Cash Working Capital (2)                           72         (67)
------------------------------------------------------------------------------
Total Net Debt                                              3,641       4,219
==============================================================================

Shareholders' Equity (3)                                    4,008       2,867
==============================================================================

Notes:
1    Includes all of our debt and is calculated as long-term debt less working
     capital.
2    Excludes short-term borrowings.
3    At January 31,  2006,  there were  261,614,723  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.

NET DEBT

We use net debt as a key indicator of our leverage and to monitor the strength
of our balance  sheet.  Net debt is  directly  related to our  operating  cash
flows, capital investment  activities and disposition  programs.  We ended the
year with net debt of $3.6 billion, a decrease of $0.6 billion from 2004.

[Margin Text: In 2005, we issued more than US$1 billion of long-term debt and
 generated proceeds from asset dispositions. These funds reduced debt incurred
 on the North Sea acquisition and partially funded our capital programs.]

During  the year,  we sold  certain  Canadian  oil and gas  producing  assets,
monetized  a portion  of our  chemicals  business  and  issued  more than US$1
billion of  long-term  debt.  These  funds were used to repay the  acquisition
credit facilities that we used to finance purchase of North Sea assets in late
2004, and to partially fund our 2005  investment  program.  Our cash flow from
operating activities funded the balance of our investment program.

The year-over-year change in our net debt results from:

<TABLE>
<CAPTION>
(Cdn$ millions)                                                             2005        2004
---------------------------------------------------------------------------------------------
<S>                                                                       <C>         <C>
Capital Investments (including 2004 North Sea Acquisition)                 2,638       4,264
Cash Flow from Operating Activities                                       (2,143)     (1,606)
---------------------------------------------------------------------------------------------
  Excess of Capital Investment over Cash Flow                                495       2,658
Net Proceeds on Disposition of Oil and Gas Properties                       (911)        (34)
Net Proceeds from Canexus Initial Public Offering                           (301)          -
Dividends on Common Shares                                                    52          52
Issue of Common Shares (Primarily Exercise of Employee Stock Options)        (58)       (124)
Foreign Exchange Translation of US-dollar Debt and Cash                     (113)        (78)
Increase in Current Obligation Related to Stock Based Compensation           321          91
Other                                                                        (63)        (36)
---------------------------------------------------------------------------------------------
Increase (Decrease) in Net Debt                                             (578)      2,529
=============================================================================================
</TABLE>

The decrease in our net debt has improved our net-debt-to-cash-flow  leverage,
while our lower interest coverage reflects the additional interest incurred to
finance our North Sea acquisition, as follows:


<TABLE>
<CAPTION>
(times)                                                      2005        2004        2003
------------------------------------------------------------------------------------------
<S>                                                    <C>         <C>         <C>
Net Debt to Cash Flow from Operating Activities               1.7         2.6         1.2
Interest Coverage (1)                                         9.8        11.9        10.1
</TABLE>

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


                                      57
<PAGE>

Our business  strategy is focused on  value-based  growth  through  full-cycle
exploration  and  development,  supplemented  by strategic  acquisitions  when
appropriate. We have leveraged our balance sheet in the past to accomplish our
growth  strategy,  as most of our projects have  long-cycle  times,  requiring
significant  amounts of capital to be invested prior to generating cash flows.
Historically,  we have been  successful with this strategy as we used leverage
to:

o    develop the Masila project in Yemen in 1993;
o    acquire Wascana in 1997;
o    repurchased 20 million common shares in 2000;
o    acquire the remaining interest in Aspen in 2003; and
o    acquire the Buzzard project and other key assets in the North Sea in
     2004.

Each  time,  we  exceeded  our  internal  net debt to cash flow  target  band;
however,  we successfully  brought our leverage down once these projects began
generating  cash flow. In 2005,  we reduced our net debt by selling  producing
assets in Canada and  monetizing  a portion  of our  chemicals  business.  Our
future  liquidity is expected to strengthen and our net debt is expected to be
reduced  further  when our Buzzard and Long Lake  projects  come on stream and
contribute significant free cash flow in 2007 and beyond.

CHANGE IN WORKING CAPITAL

[Margin Text: Receivables and payables increased primarily in our marketing
 operations, reflecting higher commodity prices.]

<TABLE>
<CAPTION>
                                                                             Increase/
(Cdn$ millions)                                          2005        2004   (Decrease)
---------------------------------------------------------------------------------------
<S>                                                    <C>         <C>          <C>
Cash and Cash Equivalents                                  48          73          (25)
Restricted Cash                                            70           -           70
Accounts Receivable                                     3,151       2,100        1,051
Inventories and Supplies                                  504         351          153
Accounts Payable and Accrued Liabilities               (3,710)     (2,377)      (1,333)
Other                                                     (17)         (7)         (10)
---------------------------------------------------------------------------------------
                                                           46         140          (94)
=======================================================================================
</TABLE>

Higher  commodity  prices impacted our non-cash  working capital by increasing
the receivables and payables  attributable to our marketing  group.  Inventory
held by our marketing  operation was higher at year end from higher gas prices
that  increased the cost of our  inventoried  gas. Our payables have increased
since  2004  because  of the  higher  accrued  liability  of  our  stock-based
compensation programs.

LIQUIDITY

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

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 committed credit facilities. At December 31, 2005, we had
committed  term credit  facilities  of $2.4 billion that are  available  until
2010. At year end, $250 million of these  facilities  were utilized to support
letters of credit.  We also had $732 million of uncommitted,  unsecured credit
facilities, of which $468 million was utilized to support letters of credit.

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.

The table on the following  page 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 borrow or
issue equity to fund  investment  requirements  that exceed our operating cash
flow.


                                      58
<PAGE>

<TABLE>
<CAPTION>
(Cdn$ millions)                                2005         2004         2003         2002         2001
--------------------------------------------------------------------------------------------------------
<S>                                          <C>          <C>          <C>          <C>          <C>
Cash Flow from Operating Activities           2,143        1,606        1,405        1,250        1,496
Cash Flow from Investing Activities          (1,864)      (4,013)      (1,219)      (1,569)      (1,469)
--------------------------------------------------------------------------------------------------------
                                                279       (2,407)         186         (319)          27

Cash Flow from Financing Activities            (274)       1,426        1,006          329         (100)
--------------------------------------------------------------------------------------------------------
                                                  5         (981)       1,192           10          (73)
========================================================================================================
</TABLE>

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.  We used our cash flow in 2001 and  accessed  public debt  markets in
2002 to fund these  investments.  In 2003, Aspen contributed  significantly to
our cash flow and in late 2003, we pre-funded  debt repayments by raising more
than $1 billion in senior and  subordinated  debt. We used these funds in 2004
to repay higher cost debt,  and coupled with  acquisition  credit  facilities,
acquired the North Sea assets. In 2005, we used our cash flow and the proceeds
from asset dispositions to fund our capital program and repay debt.

Our  marketing  business also  requires  liquidity to support its  asset-based
trading  strategy.  Liquidity  requirements  include cash for working capital,
cash or credit  lines to fund  collateral  requirements  and risk  capital  to
absorb  unexpected  market or credit  losses.  The  commercial  agreements our
marketing  business enters into often include financial  assurance  provisions
that allow Nexen and our  counterparties  to  effectively  manage credit risk.
These  agreements   typically  require  posting  of  collateral  when  adverse
credit-related  events  occur,  such as a  reduction  in  credit  ratings.  In
evaluating our liquidity requirements, we consider the current requirements of
our marketing business as well as additional collateral or other payments that
could be required in the event of reductions in our credit ratings.

FUTURE LIQUIDITY

[Margin Text: In 2006, we expect our capital program and dividend requirements
 to exceed  our cash  flow.  We plan to fund this  shortfall  using  committed
 credit facilities.]

Our future  liquidity is primarily  dependent on cash flows generated from our
operations,  existing  committed  credit  facilities and our ability to access
debt and equity markets. Assuming WTI of US$55/bbl, we expect our 2006 capital
investment  program and dividend  requirements to exceed our cash flow by more
than $350  million.  We plan to fund this  shortfall  by drawing on our unused
committed credit  facilities.  In late 2006, we will also repay $93 million of
medium term notes that become due, which we expect to fund using our committed
credit facilities.

Our cash flow is sensitive to changes in commodity  prices and exchange rates.
For 2006,  we expect cash flow of more than $2.6 billion  (before  remediation
and geological and geophysical expenditures) assuming:

--------------------------------------------------------------------------------
WTI (US$/bbl)                                                             55.00
NYMEX Natural Gas (US$/mmbtu)                                              9.25
US to Canadian Dollar Exchange Rate                                        0.85
--------------------------------------------------------------------------------

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 2006 section on
page 55.

[Margin  Text:  Much of our planned  capital  spending over the next two years
 relates to our Buzzard, Long Lake and coal bed methane projects.]

We are in the midst of  developing  major  projects  including  Buzzard in the
North Sea, Long Lake and our coal bed methane project in the Fort  Assiniboine
area of Alberta.  Our anticipated  spending on these projects in 2006 and 2007
is as follows:

(Cdn$ millions)
--------------------------------------------------------------------------------
2006                                                                      1,080
2007                                                                        330
--------------------------------------------------------------------------------
Total Capital Investment                                                  1,410
================================================================================

Given our reliance on cash flows to fund these projects, we implemented a cash
flow protection strategy using WTI crude oil put options in late 2004 for 2005
and 2006. For 2006, these put options provide us

                                      59
<PAGE>

with an annual  average  WTI floor price of US$38.17 on 60,000 bbls of oil per
day. This strategy  reduces the downside risk to our future cash flows in 2006
if commodity  prices were to fall when our capital  requirements are high, yet
still allows us to realize all price upside.

Our Buzzard  project  creates  foreign  currency  exposure as a portion of the
capital costs are  denominated in British pounds and Euros,  while our revenue
stream is primarily  US dollars.  To reduce our  exposure to  fluctuations  in
these currencies relative to the US dollar, we purchased foreign currency call
options in early 2005 that  effectively  set a ceiling on most of our  British
pound and Euro spending exposure from March 2005 to the end of 2006.

[Margin  Text: If required,  we have more than $2 billion in committed  credit
 facilities and a US$1.5 billion shelf prospectus available.]

While these  development  projects lack exploration  risk, they are subject to
other  risks  including  higher  than  anticipated  capital  costs or  delayed
start-up. We maintain undrawn committed credit facilities to manage this risk.
In  addition to our  operating  cash flows and our  undrawn  committed  credit
facilities,  we have a US$1.5 billion shelf prospectus available in the US and
Canada.

At December 31, 2005,  the average term to maturity of our long-term  debt was
20.5 years. We have the following debt maturities during the next five years:

(Cdn$ millions)                       2006     2007     2008    2009    2010
-----------------------------------------------------------------------------
Term Credit Facilities (1)               -        -        -       -       -
Canexus LP Term Credit Facilities        -        -        -     171       -
Debentures                              93        -        -       -       -
Medium Term Notes                        -      150      125       -       -
-----------------------------------------------------------------------------
Total                                   93      150      125     171       -
=============================================================================

Note:
1    $2.4 billion available until 2010.

With our expected  cash flow  streams,  commodity  price and foreign  exchange
hedging strategies, current levels of liquidity, and access to debt and equity
markets,  we  expect  to have no  difficulties  funding  our  planned  capital
programs,   dividend  requirements  and  debt  repayments,  or  meeting  other
obligations  that may  arise  from our oil and gas,  chemicals  and  marketing
operations.

[Margin Text: We expect to declare common share
 dividends of $0.20 per share in 2006.]

In 2005, we declared common share  dividends of $0.20 per share  (2004--$0.20,
2003--$0.163).  We expect to declare common share dividends of $0.20 per share
in 2006.

CONTRACTUAL OBLIGATIONS, COMMITMENTS AND GUARANTEES

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

<TABLE>
<CAPTION>
                                                                     Payments
--------------------------------------------------------------------------------------------------------
                                                      (less than)                           (more than)
(Cdn$ millions)                               Total       1 year    1-3 years    4-5 years      5 years
--------------------------------------------------------------------------------------------------------
<S>                                           <C>          <C>          <C>          <C>          <C>
Long-Term Debt                                3,687           93          275          171        3,148
Interest on Long-Term Debt                    5,086          225          420          402        4,039
Operating Leases (1)                            272           33           63           55          121
Capital Leases                                  113            2           10           10           91
Energy Commodity Contract Liabilities           445          321          102           20            2
Transportation and Storage
  Commitments (1)                               888          440          230          102          116
Work Commitments and Purchase
  Obligations (2)                             2,143        1,229          568          261           85
Asset Retirement Obligations                  1,471           21           35           32        1,383
Other                                             6            1            2            2            1
--------------------------------------------------------------------------------------------------------
Total                                        14,111        2,365        1,705        1,055        8,986
========================================================================================================
</TABLE>

Notes:
1    Payments for operating leases and transportation and storage  commitments
     are deducted from our cash flow from operating activities.
2    Some of these  payments  relate to work  commitments  cancellable  at our
     option without penalties or additional fees.


                                      60
<PAGE>

[Margin Text: Our long-term debt and interest accounts for more than 60% of our
 contractual obligations and commitments.]

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    Long-term debt amounts are included on our December 31, 2005 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 2006,  Shell has elected to take payment in kind, so
     the 2006  obligation  has been excluded from this table.  Instead,  it is
     shown as a royalty and excluded from reserves and production.
o    Capital leases include pipeline  commitments  primarily related to future
     production at Long Lake.
o    Energy commodity contract liabilities 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, 2005. For certain contracts, we may net settle.
o    Work commitments  include  non-discretionary  capital spending related to
     drilling,  seismic,  construction  of  facilities  and other  development
     commitments in our international operations, and includes Long Lake ($422
     million),  the  Buzzard  project in the North Sea ($592  million)  and at
     Block 51 in Yemen  ($88  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 2006 capital  investment  is
     discretionary.
o    We also have included work  commitments  relating to drilling rigs, which
     have been  contracted to work for us in the North Sea and Gulf of Mexico,
     totalling $602 million over the next five years.
o    We have $1,471 million of undiscounted asset retirement  obligations.  As
     of December  31,  2005,  the  discounted  value  ($611  million) of these
     estimated obligations has been provided for in our consolidated financial
     statements (including $21 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 $86 million (of which $9 million  relates to
     Canexus), and our share of Syncrude's unfunded obligation is $51 million.
     Our $86 million  obligation  includes  $43 million  that is unfunded as a
     result  of  statutory  limitations.   These  obligations  are  backed  by
     irrevocable letters of credit.
o    We have excluded  obligations on our stock option and stock  appreciation
     rights   programs  as  the  amount  and  timing  of  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 expected capital expenditures for 2006.
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 fiscal year in the various jurisdictions in which
     we operate.

We have entered into a long-term supply agreement under which we are committed
to  deliver  35,000  bbls/d  of heavy  crude oil at  market  prices  beginning
mid-2008 for ten years.

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 of operations.


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CREDIT RATINGS

Currently,  our senior debt is rated BBB- by Standard & Poor's (S&P),  Baa2 by
Moody's  Investor  Service,  Inc.  (Moody's)  and BBB by Dominion  Bond Rating
Service (DBRS). In addition, S&P and DBRS currently rate our outlook as stable
while Moody's has a negative  outlook.  Our strong  financial  results,  ample
liquidity and financial flexibility continue to support our credit ratings.

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 of
collateral  when  adverse  credit-related  events occur such as a reduction in
credit  ratings.  Based on the  contracts  in place  and  commodity  prices at
December  31,  2005,  we could be  required to post  collateral  of up to $1.1
billion if we were downgraded to non-investment  grade.  These obligations are
already  reflected  on our balance  sheet.  The posting of  collateral  merely
accelerates  the payment of such  amounts.  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

We have no off-balance  sheet  arrangements that would have a material adverse
effect  on our  liquidity,  consolidated  financial  position  or  results  of
operations.  We use  operating  leases in the  normal  course of  business  as
disclosed in Contractual  Obligations,  Commitments  and Guarantees on page 60
and in Note 15 to the  Consolidated  Financial  Statements in Item 8, which is
incorporated herein by reference.

CONTINGENCIES

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

RISK FACTORS

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 price,  product quality,  and logistics and reliability of
supply.

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.


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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 a few instances in the
last five years where  production was suspended for an extended period of time
and damage to facilities was incurred.  In late August 2005, we shut-in all of
our production in the Gulf of Mexico, consisting of approximately 50,000 boe/d
before royalties,  and ceased drilling operations in anticipation of Hurricane
Katrina. Production was restored in early September for most of our fields. On
September 20, 2005, we again shut-in all of our production and ceased drilling
operations in anticipation of Hurricane Rita. While we incurred minimal damage
to most of our  facilities,  extensive  damage was incurred to the third party
infrastructure  necessary to  accommodate  our  production.  As a result,  our
annualized production was reduced approximately 6,000 boe/d. These storms also
resulted in damage to rigs under  contract with us, which  increased our costs
and delayed our drilling  schedule.  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.  In each of these  instances,
there was no  significant  financial  impact after business  interruption  and
property insurance claims.

Our exploration and development  capital  programs in our offshore  operations
are exposed to risk of delay or additional costs by limited access to drilling
rigs.  Recent industry  pressure in the Gulf of Mexico  following storm damage
sustained  in the 2005  hurricane  season  has  reduced  the  availability  of
drilling  rigs. We have been able to secure  contracts for the majority of our
2006 exploration and development  drilling in the Gulf of Mexico and the North
Sea. In early 2006,  we entered  into a long-term  contract  that will give us
access to a  deep-water  drilling  rig  beginning in 2009 for two years over a
three and a half year period, capable of drilling our sub-salt prospects.  Our
profitability  and success at finding  replacement  reserves may be reduced by
extended delays or higher costs of obtaining drilling rigs.

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.


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<PAGE>

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  258 million boe of  economic  revisions  related to changes in
year-end  prices and costs,  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. The remaining negative revisions of 79 million boe, representing about
10% of worldwide proved reserves,  relate to technical  revisions primarily on
our producing properties. In Canada, the majority of the negative revisions of
56 million boe  occurred in 2003 as a 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 geologic  mapping.
In Yemen,  the negative  revisions of 30 million boe occurred  largely in 2003
and  2004  and  resulted   primarily   from   lower-than-expected   production
performance,  drilling results and updated geological  mapping.  In the United
States, negative revisions of 21 million boe occurred largely in 2004 and 2005
and resulted primarily from lower-than-expected  production performance at our
deep water  Aspen  property  and at  various  properties  on the Shelf.  These
negative  revisions were somewhat offset by a positive  revision of 17 million
boe in our Buzzard field due to updated geologic mapping.

About  two-thirds  of  the 79  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
geologic 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   unexpected   loss  of  well
productivity.  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 must recognize our oil sands as bitumen  reserves  rather
than the upgraded  premium  synthetic crude oil that we expect to produce from
Long Lake. 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 for bitumen,  diluent and natural gas,  even
though the Long Lake project has virtually no exposure to these  factors.  The
impact  of  year-end  prices  on our  heavy oil  reserves  is  expected  to be
immaterial.

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 capital
costs is estimated to be $1.9 billion ($3.8 billion gross).  Given the 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.


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<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 to construct and develop 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).  In December 2004, we accelerated the 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
at a cost of $98 million  (gross).  Recently,  we further modified the project
design by adding steam  generation  capacity and soot handling  equipment at a
cost of $360 million  (gross).  We expect the other project costs to be within
our initial  estimates.  Our total  estimated  capital cost is currently  $3.8
billion (gross).

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
insitu  recovery of bitumen from oil sands is relatively new. Some of the SAGD
oil sands  applications  to date have been pilot  projects,  however there are
several commercial SAGD projects in steady stage operation.

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 like reservoirs in the McMurray  formation
in the Athabasca oil sands. 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. In order to test operating  parameters,  we built a three  well-pair SAGD
pilot,  commenced steaming the reservoir in May 2003 and commenced  production
in September  2003.  The pilot is  currently  producing at a rate of about 400
barrels of bitumen per day per producing well-pair and an average steam-to-oil
ratio of about 4.2. Since September 2003, the pilot has recovered less than 3%
of the  original  bitumen  in place.  While we expect  actual  performance  to
improve as we commence commercial operations where SAGD drilling has confirmed
higher quality reservoir  conditions,  there can be no assurance that our SAGD
operation will produce bitumen at the expected  levels or steam-to-oil  ratio.
We have  addressed  this risk by drilling  additional  wells and adding  steam
generating  capacity to allow for a steam-to-oil ratio of 3.3, however, 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.


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<PAGE>

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 economic 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.

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  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.


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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  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. 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.

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 facilities,  oil pipelines, and export terminal at our
     two 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.


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<PAGE>

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.  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.

The Mannville coals in the Fort Assiniboine  region of Alberta are deeper than
other producing CBM projects and are water saturated.  A significant period of
time may be  required  to  sufficiently  dewater  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.  We
tested the feasibility of gas production from a portion of our Mannville coals
and determined  that we could achieve  commercial  production  rates with five
months  of  commencing  dewatering.  Based  on  these  results,  we  commenced
commercial  development  on our  Corbett,  Doris and  Thunder  leases.  In the
future,  we plan to undertake pilots to test the feasibility of gas production
before commencing full-scale commercial developments.

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 98%
complete and is expected to commence  production in mid 2006.  Development and
construction  activities  on the Buzzard  field are over 88%  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
substantially  complete,  SAGD drilling is complete and site  construction  is
well  underway.  First steam  injection is scheduled to begin in late-2006 and
the first commercial production of upgraded synthetic crude oil is expected to
be achieved in the second half of 2007. We are  continuing  development of our
Upper Mannville CBM assets in the Fort  Assiniboine area in 2006. Our combined
capital spending for these projects is anticipated to be $1.3 billion 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 2005,  Yemen accounted for $536 million or 46% of
our net income and this is expected to decline  somewhat in 2006 as production
declines on Masila are  partially  offset by  production  from  completion  of
development activities on Block 51.

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 over 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.


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<PAGE>

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, 2005, $611 million  ($1,471  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.  Our provision for future  retirement  costs does not include
     costs  related  to  the  Syncrude  upgrader  or  sulphur  pile  as we are
     currently  unable  to  reasonably  determine  the  fair  value  of  these
     obligations.
o    During  2005,  we  increased  our asset  retirement  obligations  by $210
     million  (2004--$170  million)  to reflect  new  obligations  incurred or
     acquired,   general   industry   cost   pressures   and  more   stringent
     environmental laws and regulations.
o    Actual  site  remediation  expenditures  for the year  were  $34  million
     (2004--$31 million).  We anticipate actual site remediation  expenditures
     in 2006 to approximate $21 million.
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 came into force on February 16, 2005.  Canada  ratified the
Kyoto  Protocol in December  2002.  In 1997,  Canada  committed to an emission
reduction of 6% below 1990 levels during the First Commitment  period (2008 to
2012). On March 24, 2005, the Canadian government introduced to Parliament for
first reading Bill C-43 "An Act to Implement Certain  Provisions of the Budget
Tabled by  Parliament  on February  23,  2005" (Bill  C-43),  which  contained
certain  proposals  relating to the Kyoto Protocol.  While the content of Bill
C-43 and whether it will eventually pass into law is uncertain, it constitutes
the first attempt by the Canadian  government to implement  obligations  under
the Kyoto Protocol.  As well, on April 13, 2005,  Environment  Canada released
its Kyoto Plan, which sets out a number of initiatives, including the lowering
of the target for  reductions  in  greenhouse  gas  emissions  by large  final
emitters  from  the  initial  target  of 55  megatons  to a new  target  of 45
megatons.  Any required  reductions in the  greenhouse  gases emitted from our
operations could result in increases in our capital expenditures and operating
expenses,  especially those related to the Long Lake project, which could have
an adverse effect on our results of operations and financial condition. Recent
changes  in  the  Canadian  government  may  have  an  impact  on  our  future
obligations under the Kyoto Plan.


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<PAGE>

CRITICAL ACCOUNTING ESTIMATES

We make  estimates  and  assumptions  that affect the reported  amounts of our
assets and liabilities and the disclosure of contingent assets and liabilities
at the date of the  Consolidated  Financial  Statements  and our  revenues and
expenses during the reporting period.  Our management reviews these estimates,
including  those  related to  accruals,  litigation,  environmental  and asset
retirement obligations,  income taxes and the 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.  Our critical
accounting 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 internally  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  reserves  assessed  annually by  independent
qualified reserves  consultants.  Given that the respective 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%.

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
reserves estimates and related disclosures. It has


                                      70
<PAGE>

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 2005,  $143 million of
     our total $456 million spent on  exploration  drilling was  expensed.  If
     none of our  drilling  had been  successful,  our net  income  would have
     decreased by $206 million after tax.
o    Calculating  our  unit-of-production  depletion  rates.  Both  proved and
     proved developed  reserves(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
     2005, oil and gas and Syncrude  depletion of $628 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
     $42  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 reserves estimates, are discussed below.

Since we do not have any loan covenants directly linked to reserves,  it would
take a  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--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 reserves estimates, changes in operating
costs, or significant or adverse political changes. If one of these occurs, we
assess  estimated  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 2005 and
found no impairments were required based on our assumptions.

Cash flow estimates for 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$71/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/bbl  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  reserves
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 reserves
estimate decrease would have on our assessment of impairment.

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.


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<PAGE>

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.

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.

BUSINESS COMBINATION--PURCHASE PRICE ALLOCATION

During  the fourth  quarter  of 2004,  we  acquired  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 were  required to record on our  consolidated  balance  sheet the estimated
fair  values  of  the  acquired   company's  assets  and  liabilities  at  the
acquisition date. The excess of the purchase price over the fair values of the
tangible and intangible net assets acquired was 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.

FUTURE INCOME TAXES

We follow the liability  method of accounting  for income taxes whereby future
income  tax  assets  and  liabilities   are  recognized   based  on  temporary
differences in reported amounts for financial  statement and tax purposes.  We
carry on  business  in several  countries  and as a result,  we are subject to
income taxes in numerous  jurisdictions.  The  determination of our income tax
provision is inherently  complex and we are required to interpret  continually
changing regulations and make certain judgments.  While income tax filings are
subject  to  audits  and  reassessments,  we  believe  we have  made  adequate
provision  for all  income  tax  obligations.  However,  changes  in facts and
circumstances as a result of income tax audits,  reassessments,  jurisprudence
and any new legislation may result in an increase or decrease in our provision
for income taxes.


                                      72
<PAGE>

NEW ACCOUNTING PRONOUNCEMENTS

CANADIAN PRONOUNCEMENTS

In an effort to harmonize Canadian GAAP with US GAAP, the Canadian  Accounting
Standards Board (AcSB) 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, 2005 would have the  following  impact on our  Consolidated
Financial Statements:

                                                                    Increase/
(Cdn$ millions)                                                    (Decrease)
------------------------------------------------------------------------------
Accounts Payable                                                           35
Future Income Tax Liabilities                                             (11)
Shareholder's Equity                                                      (24)

In June 2005, the AcSB issued Section 3831, Non-Monetary  Transactions,  which
replaces  Section  3830  and  requires  all  non-monetary  transactions  to be
measured at fair value unless:

o    the transaction lacks commercial substance;
o    the  transaction is an exchange of a product or property held for sale in
     the  ordinary  course of business for a product or property to be sold in
     the same line of business to facilitate sales to customers other than the
     parties to the exchange;
o    neither  the fair value of the assets or services  received  nor the fair
     value of the assets or services given up is reliably measurable; or
o    the transaction is a non-monetary, non-reciprocal transfer to owners that
     represents a spin-off or other form of restructuring or liquidation.

The new requirements apply to non-monetary  transactions  initiated in periods
beginning on or after January 1, 2006. Earlier adoption is permitted as of the
beginning of a period beginning on or after July 1, 2005. We do not expect the
adoption  of this  section  will have any  material  impact on our  results of
operations or financial position.

In December 2005, the CICA's  Emerging Issues  Committee  issued Abstract 159,
Conditional Asset Retirement Obligations (EIC-159). EIC-159 clarifies that the
term conditional asset retirement obligation, as used in CICA Handbook Section
3110, Asset Retirement  Obligations refers to a legal obligation to perform an
asset  retirement  activity where the timing and (or) method of settlement are
conditional on a future event that may or may not be within the control of the
entity.  EIC-159 also clarifies when there would be sufficient  information to
reasonably estimate the fair value of an asset retirement obligation.  EIC-159
is effective for interim and annual  reporting  periods ending after March 31,
2006.  We do not expect the  adoption of this  section  will have any material
impact on our results of operations or financial position.


                                      73
<PAGE>

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 fiscal years 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.
Upon  implementing  the new rules,  we expect to record an expense for US GAAP
purposes of $3 million ($2  million net of income  taxes) in 2006,  reflecting
the cumulative effect of the change in accounting policy.

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.

In March 2005, the FASB issued  Financial  Interpretation  47,  Accounting for
Conditional  Asset Retirement  Obligations (FIN 47). FIN 47 clarifies that the
term  conditional  asset  retirement  obligation as used in FASB Statement No.
143, Accounting for Asset Retirement Obligations, refers to a legal obligation
to perform an asset retirement activity in which the timing and (or) method of
settlement are conditional on a future event that may or may not be within the
control of the entity. The obligation to perform the asset retirement activity
is  unconditional  even though  uncertainty  exists  about the timing and (or)
method of  settlement.  Thus,  the timing and (or) method of settlement may be
conditional on a future event. Accordingly, an entity is required to recognize
a liability for the fair value of a conditional asset retirement obligation if
the fair  value of the  liability  can be  reasonably  estimated.  FIN 47 also
clarifies  when an entity  would have  sufficient  information  to  reasonably
estimate the fair value of an asset retirement obligation. FIN 47 is effective
no later than the end of fiscal  years ending  after  December  15, 2005.  The
adoption  of this  statement  has not had a material  impact on our results of
operations or financial position.


                                      74
<PAGE>

In March 2005,  the Emerging  Issues Task Force (EITF)  reached a consensus on
Issue No. 04-6,  Accounting for Stripping Costs Incurred during  Production in
the Mining  Industry.  In the mining  industry,  companies  may be required to
remove  overburden and other mine waste materials to access mineral  deposits.
The EITF concluded that the costs of removing  overburden and waste materials,
often referred to as "stripping  costs",  incurred during the production phase
of a mine are variable  production  costs that should be included in the costs
of the  inventory  produced  during the period  that the  stripping  costs are
incurred. Issue No. 04-6 is effective for the first reporting period in fiscal
years beginning after December 15, 2005, with early adoption permitted.  We do
not expect the adoption of this statement  will have a material  impact on our
results of operations or financial position.

In June 2005,  the FASB issued  Statement  154,  Accounting  Changes and Error
Corrections, which replaces APB Opinion 20 and FASB Statement 3. Statement 154
changes the  requirements  for the  accounting  and  reporting  of a change in
accounting  principle.  Opinion 20  previously  required  that most  voluntary
changes in accounting  principles  be  recognized by including the  cumulative
effect of the new  accounting  principle  in net  income of the  period of the
change. In the absence of explicit  transition  provisions provided for in new
or   existing   accounting   pronouncements,   Statement   154  now   requires
retrospective  application of changes in accounting  principle to prior period
financial  statements,  unless it is  impracticable to do so. The Statement is
effective for fiscal years beginning after December 15, 2005. We do not expect
the adoption of this statement  will have a material  impact on our results of
operations or financial position.

In September 2005, the EITF reached a consensus on Issue No. 04-13, Accounting
for Purchases and Sales of Inventory  with the Same  Counterparty.  This issue
addresses the question of when it is appropriate to measure purchase and sales
of  inventory  at fair value and record them in cost of sales and revenues and
when they should be recorded  as  exchanges  measured at the book value of the
item sold.  The EITF  concluded that purchases and sales of inventory with the
same counterparty that are entered into in contemplation of one another should
be combined and  recorded as exchanges  measured at the book value of the item
sold.  The consensus  should be applied to new  arrangements  entered into and
modifications  or renewals of existing  agreements,  beginning with the second
quarter of 2006. We do not expect the adoption of this  statement  will have a
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 and  natural gas are
commodities which are sensitive to numerous worldwide  factors,  many of which
are beyond our control,  and are generally  sold at contract or posted prices.
Changes in world crude oil and natural gas prices may significantly affect our
results  of  operations  and  cash   generated   from  operating   activities.
Consequently,  such  prices  also  may  affect  the  value  of our oil and gas
properties  and  our  level  of  spending  for oil  and  gas  exploration  and
development.

Our crude oil prices are based on various reference prices,  primarily the WTI
crude oil reference  price and other prices which generally track the movement
in WTI.  Adjustments  are made to the  reference  prices  to  reflect  quality
differentials and transportation. WTI and other international reference prices
are  affected by numerous  and complex  worldwide  factors  such as supply and
demand  fundamentals,   economic  outlooks,   production  quotas  set  by  the
Organization of Petroleum  Exporting  Countries and political events.  Quality
differentials are affected by local supply and demand factors.

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 2005, WTI averaged  US$56.58/bbl  reaching a high of US$70.85/bbl and a low
of  US$41.25/bbl.  NYMEX natural gas prices  averaged  US$8.99/mmbtu  in 2005,
reaching a high of US$15.78/mmbtu and a low of US$5.71/mmbtu.


                                      75
<PAGE>

Our sensitivities to commodity prices and the expected impact on our 2006 cash
flow from operating activities and net income are as follows:

(Cdn$ millions)                                      Cash Flow      Net Income
-------------------------------------------------------------------------------
WTI--US$1 Change                                            40              32
NYMEX Natural Gas--US$0.10 Change                            7               6

These  sensitivities  to changes in benchmark prices for crude oil and natural
gas are  based on our  estimated  2006  production  levels  for  crude oil and
natural gas and assume a Canadian/US  dollar  exchange rate of 85(cents).  Our
estimated  crude oil and  natural  gas  production  range for 2006 is  between
220,000 and 240,000 boe/d before  royalties,  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. In 2006,  these
options  establish  an annual  average WTI floor price of  US$38/bbl on 60,000
bbls/d of production.

FOREIGN CURRENCY RISK

A substantial  portion of our activities are transacted 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  0.8253(cents)  in 2005 with a
high of 0.8690(cents) and a low of 0.7872(cents).

Our  sensitivities  to the US  dollar  and the  expected  impact of a one cent
change on our 2006 cash flow from operating  activities,  net income,  capital
expenditures and long-term debt are as follows:

<TABLE>
<CAPTION>
                                                                          Capital
(Cdn$ millions)                            Cash Flow    Net Income   Expenditures  Long-Term Debt
----------------------------------------------------------------------------------------------------
<S>                                          <C>           <C>           <C>              <C>
$0.01 Change in US to Canadian Dollar             25            12             18              38
</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 2006. These estimates are based on a
WTI  price  for  crude  oil of  US$55.00/bbl,  a NYMEX  natural  gas  price of
US$9.25/mcf and a Canadian/US dollar exchange rate of 85(cents).

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.


                                      76
<PAGE>

Our chemicals operations are exposed to changes in the US-dollar exchange rate
as a portion of their sales are denominated in US-dollars.  In connection with
the Canexus initial public  offering,  we purchased  US-dollar call options to
reduce this exposure.  These call options give Canexus the right to sell US$11
million monthly and purchase  Canadian dollars at an exchange rate of US$0.813
until August 2006.

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, 2005,  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 4.1% in 2005,
reaching a high of 4.8% and low of 3.5%.

Our  sensitivity to interest  rates and the expected  impact of a 1% change in
interest rates on our 2006 cash flow from operating  activities and net income
is as follows:

(Cdn$ millions)                                      Cash Flow      Net Income
------------------------------------------------------------------------------
Interest Rates--1% change in rates                          4               3

Our  sensitivity  to  changes  in  interest  rates is based on 2006  estimated
average  floating rate debt of $380 million and a Canadian/US  dollar exchange
rate of 85(cents).

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, 2005 fixed-rate
borrowings  comprised 95%  (2004--56%)  of our long-term  debt at an effective
average rate of 6.3% (2004--6.6%). During the year we periodically drew on our
unsecured syndicated term credit facilities and at December 31, 2005, floating
rate debt  comprised  5%  (2004--44%)  of our  long-term  debt at an effective
average rate of 4.4% (2004--3.2%).

We had no interest rate swaps outstanding in 2005 or 2004.

TRADING

COMMODITY PRICE RISK

Our marketing operation is involved in the marketing and trading of crude oil,
natural  gas,  natural  gas  liquids  and power  through  the use of  physical
purchase and sales contracts as well as financial commodity  contracts.  These
activities expose us to commodity price risk. The marketing operation actively
manages this risk by utilizing  energy-related  futures,  forwards,  swaps and
options,  and  generally  attempts  to  balance  its  physical  and  financial
contracts in terms of contract  volumes and timing of performance and delivery
obligations.  However,  net open  positions may exist or may be established to
take advantage of existing market conditions.

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).  Open
positions  and  derivative  instruments  expose us to other  risks,  including
credit risk and the risk of margin calls from third parties.  The inability to
close out options,  futures and forward positions could have an adverse impact
on the use of derivative instruments to effectively hedge our portfolio and/or
generate income from marketing activities. 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.


                                      77
<PAGE>

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
2005. However,  based on our assessment of risk measurements,  we have removed
VaR relating to credit from our total VaR and we review this  separately.  For
2005, VaR relating to credit ranged between $3 million and $5 million.

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)                              2005          2004          2003
------------------------------------------------------------------------------
Value at Risk
  Year-End                                     24            21            21
  High                                         28            42            31
  Low                                          11            17            14
  Average                                      21            29            20

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 credit  exposures 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, 2005:

o    over 97% of our credit exposures were investment grade; and
o    only two  counterparties  individually made up more than 5% of our credit
     exposure. Both were investment grade.


                                      78
<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 Coal Bed Methane, Long Lake, Syncrude,  North Sea and West
Africa projects and future capital investment plans.

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,  among
others:

o    market prices for oil, natural gas and chemicals products;
o    our ability to explore,  develop,  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  insurgent  or other armed
     groups or 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    possible commerciality, development plans or capacity expansions;
o    future ability to execute dispositions of assets or businesses;
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. Except to the extent required by law, 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.


                                      79
<PAGE>

SPECIAL NOTE TO CANADIAN INVESTORS

Nexen is an SEC registrant and a Form 10-K and related forms filer. Therefore,
our  reserves  estimates  and  securities  regulatory  disclosures  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 prescribes 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  developed  reserves by
     geographic  region 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
     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 high natural gas prices and wide  light/heavy
     differentials  at year end,  we have not  recognized  any proved  bitumen
     reserves  under SEC  requirements  whereas  under NI 51-101 we would have
     recognized  200  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  (boe) 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. Boe 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.


                                      80
<PAGE>

In 2005, we built on our solid financial
position, increasing net income to
exceed $1 billion for the first time,
strengthening earnings per share to
$4.43 and reducing long-term debt
by almost $600 million

see the value

financial statements


                                      81
<PAGE>

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                                                                          Page
REPORT OF MANAGEMENT........................................................83

REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS......................84

CONSOLIDATED FINANCIAL STATEMENTS

    Consolidated Statement of Income........................................85
    Consolidated Balance Sheet..............................................86
    Consolidated Statement of Cash Flows....................................87
    Consolidated Statement of Shareholders' Equity..........................88
    Notes To Consolidated Financial Statements..............................89

SUPPLEMENTARY DATA (UNAUDITED)

    Quarterly Financial Data In Accordance with Canadian and US GAAP.......125
    Oil And Gas Producing Activities and Syncrude Operations...............126


                                      82
<PAGE>

REPORT OF MANAGEMENT

February 7, 2006

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
registered Chartered Accountants  (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  auditors 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


                                      83
<PAGE>

REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

To the Board of Directors and Shareholders of Nexen Inc.:

We have audited the  consolidated  balance sheets of Nexen Inc. as at December
31, 2005 and 2004 and the  consolidated  statements of income,  cash flows and
shareholders'  equity  for each of the years in the three  year  period  ended
December 31, 2005. 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 Nexen Inc. as at December 31,
2005 and 2004 and the results of its operations and its cash flows for each of
the years in the three year period ended December 31, 2005 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, 2005,  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, 2006 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, 2006                    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(u) 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, 2006, 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, 2006                    Independent Registered Chartered Accountants


                                      84
<PAGE>

NEXEN INC.
CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE YEARS ENDED DECEMBER 31, 2005

<TABLE>
<CAPTION>
 Cdn$ million, except per share amounts                                      2005        2004        2003
----------------------------------------------------------------------------------------------------------
<S>                                                                         <C>         <C>         <C>
Revenues and Other Income
  Net Sales                                                                 3,932       2,944       2,632
  Marketing and Other (Note 17)                                               702         713         610
  Gain on Dilution of Interest in Chemicals Business (Note 2)                 193           -           -
----------------------------------------------------------------------------------------------------------
                                                                            4,827       3,657       3,242
Expenses
  Operating                                                                   893         722         688
  Depreciation, Depletion, Amortization and Impairment (Note 6)             1,052         674         914
  Transportation and Other                                                    796         549         489
  General and Administrative                                                  792         299         185
  Exploration                                                                 250         243         193
  Interest (Note 8)                                                            97         143         169
----------------------------------------------------------------------------------------------------------
                                                                            3,880       2,630       2,638

----------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Income Taxes                         947       1,027         604

Provision for Income Taxes (Note 18)
  Current                                                                     339         248         214
  Future                                                                     (100)         69        (117)
----------------------------------------------------------------------------------------------------------
                                                                              239         317          97

----------------------------------------------------------------------------------------------------------
Net Income from Continuing Operations before Non-Controlling Interests        708         710         507
  Net Income Attributable to Non-Controlling Interests                          8           -           -

----------------------------------------------------------------------------------------------------------
Net Income from Continuing Operations                                         700         710         507
  Net Income from Discontinued Operations (Note 14)                           452          83          71
----------------------------------------------------------------------------------------------------------

Net Income                                                                  1,152         793         578
==========================================================================================================


Earnings Per Common Share from Continuing Operations ($/share)
  Basic (Note 13)                                                            2.69        2.76        2.05
  Diluted (Note 13)                                                          2.63        2.72        2.03


Earnings Per Common Share ($/share)
  Basic (Note 13)                                                            4.43        3.08        2.33
  Diluted (Note 13)                                                          4.33        3.04        2.31
</TABLE>

See accompanying notes to Consolidated Financial Statements.


                                      85
<PAGE>

NEXEN INC.
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 2005 AND 2004

<TABLE>
<CAPTION>
Cdn$ million, except share amounts                                           2005        2004
----------------------------------------------------------------------------------------------
<S>                                                                        <C>         <C>
ASSETS
  Current Assets
    Cash and Cash Equivalents                                                  48          73
    Restricted Cash                                                            70           -
    Accounts Receivable (Note 4)                                            3,151       2,100
    Inventories and Supplies (Note 5)                                         504         351
    Assets of Discontinued Operations (Note 14)                                 -          38
    Other                                                                      51          41
----------------------------------------------------------------------------------------------
      Total Current Assets                                                  3,824       2,603

Property, Plant and Equipment (Note 6)                                      9,594       8,203
  Goodwill                                                                    364         375
  Future Income Tax Assets (Note 18)                                          410         333
  Deferred Charges and Other Assets (Note 10)                                 398         429
  Assets of Discontinued Operations (Note 14)                                   -         440
----------------------------------------------------------------------------------------------

TOTAL ASSETS                                                               14,590      12,383
==============================================================================================

LIABILITIES AND SHAREHOLDERS' EQUITY
  Current Liabilities
    Short-Term Borrowings (Note 8)                                              -         100
    Accounts Payable and Accrued Liabilities                                3,710       2,377
    Accrued Interest Payable                                                   55          34
    Dividends Payable                                                          13          13
    Liabilities of Discontinued Operations (Note 14)                            -          39
----------------------------------------------------------------------------------------------
      Total Current Liabilities                                             3,778       2,563

  Long-Term Debt (Note 8)                                                   3,687       4,259
  Future Income Tax Liabilities (Note 18)                                   1,960       2,023
  Asset Retirement Obligations (Note 9)                                       590         399
  Deferred Credits and Other Liabilities (Note 11)                            479         142
  Liabilities of Discontinued Operations (Note 14)                              -         130
  Non-Controlling Interests (Note 2)                                           88           -
  Shareholders' Equity (Note 12)
    Common Shares, no par value
      Authorized:    Unlimited
      Outstanding:  2005--261,140,571 shares
                  2004--258,399,166 shares                                    732         637
    Contributed Surplus                                                         2           -
    Retained Earnings                                                       3,435       2,335
    Cumulative Foreign Currency Translation Adjustment                       (161)       (105)
----------------------------------------------------------------------------------------------
      Total Shareholders' Equity                                            4,008       2,867
  Commitments, Contingencies and Guarantees (Notes 15 and 18)
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                                 14,590      12,383
==============================================================================================
</TABLE>

See accompanying notes to Consolidated Financial Statements.

Approved on behalf of the Board:

(signed) "Charles W. Fischer"                      (signed) "Thomas C. O'Neill"
Director                                           Director


                                      86
<PAGE>

NEXEN INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE YEARS ENDED DECEMBER 31, 2005

<TABLE>
<CAPTION>
Cdn$ millions                                                                2005        2004        2003
----------------------------------------------------------------------------------------------------------
<S>                                                                        <C>         <C>         <C>
Operating Activities
  Net Income from Continuing Operations                                       700         710         507
  Net Income from Discontinued Operations                                     452          83          71
  Charges and Credits to Income not Involving Cash (Note 19)                1,069         906       1,024
  Exploration Expense                                                         250         243         193
  Changes in Non-Cash Working Capital (Note 19)                              (195)       (122)       (320)
  Other                                                                      (133)       (214)        (70)
----------------------------------------------------------------------------------------------------------
                                                                            2,143       1,606       1,405

Financing Activities
  Proceeds from Long-Term Notes and Debentures (Note 8)                     1,253       1,779         651
  Repayment of Long-Term Notes and Debentures (Note 8)                     (1,818)       (300)          -
  Proceeds from (Repayment of) Term Credit Facilities, Net                    (66)         83          93
  Proceeds from (Repayment of) Short-Term Borrowings, Net                     (99)        101         (18)
  Proceeds from Subordinated Debentures (Note 8)                                -           -         613
  Redemption of Preferred Securities                                            -        (289)       (340)
  Dividends on Common Shares                                                  (52)        (52)        (40)
  Issue of Common Shares                                                       58         124          73
  Net Proceeds from Canexus Initial Public Offering (Note 2)                  301           -           -
  Proceeds from Term Credit Facilities of Canexus, Net (Notes 2 and 8)        176           -           -
  Other                                                                       (27)        (20)        (26)
----------------------------------------------------------------------------------------------------------
                                                                             (274)      1,426       1,006

Investing Activities
  Business Acquisition, Net of Cash Acquired (Note 3)                           -      (2,583)          -
  Capital Expenditures
    Exploration and Development                                            (2,564)     (1,582)     (1,276)
    Proved Property Acquisitions                                              (20)         (4)       (164)
    Chemicals, Corporate and Other                                            (54)        (95)        (54)
  Proceeds on Disposition of Assets                                           911          34         293
  Changes in Non-Cash Working Capital (Note 19)                               (54)        244         (18)
  Changes in Restricted Cash                                                  (70)          -           -
  Other                                                                       (13)        (27)          -
----------------------------------------------------------------------------------------------------------
                                                                           (1,864)     (4,013)     (1,219)

Effect of Exchange Rate Changes on Cash and Cash Equivalents                  (30)        (33)       (164)

Increase (Decrease) in Cash and Cash Equivalents                              (25)     (1,014)      1,028
----------------------------------------------------------------------------------------------------------

Cash and Cash Equivalents--Beginning of Year                                   73       1,087          59
----------------------------------------------------------------------------------------------------------

Cash and Cash Equivalents--End of Year                                         48          73       1,087
==========================================================================================================
</TABLE>

See accompanying notes to Consolidated Financial Statements.


                                      87
<PAGE>


NEXEN INC.
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
FOR THE THREE YEARS ENDED DECEMBER 31, 2005

<TABLE>
<CAPTION>
Cdn$ millions                                                                 2005        2004        2003
-----------------------------------------------------------------------------------------------------------



<S>                                                                     <C>         <C>         <C>
Common Shares (Note 12)
  Balance at Beginning of Year                                                 637         513         440
    Exercise of Stock Options                                                   29          93          50
    Issue of Common Shares                                                      29          31          23
    Previously Recognized Liability Relating
      to Stock Options Exercised                                                37           -           -
-----------------------------------------------------------------------------------------------------------
  Balance at End of Year                                                       732         637         513
===========================================================================================================


Contributed Surplus
  Balance at Beginning of Year                                                   -           1           -
    Stock Based Compensation Expense (Note 12)                                   2           2           1
    Modification of Stock Option Plan to Tandem
      Option Plan (Note 12)                                                      -          (3)          -
-----------------------------------------------------------------------------------------------------------
  Balance at End of Year                                                         2           -           1
===========================================================================================================


Retained Earnings
  Balance at Beginning of Year                                               2,335       1,594       1,056
    Net Income                                                               1,152         793         578
    Dividends on Common Shares                                                 (52)        (52)        (40)
-----------------------------------------------------------------------------------------------------------
  Balance at End of Year                                                     3,435       2,335       1,594
===========================================================================================================


Cumulative Foreign Currency Translation Adjustment
  Balance at Beginning of Year                                                (105)        (33)         94
    Translation Adjustment, Net of Income Taxes                                (56)        (72)       (127)
-----------------------------------------------------------------------------------------------------------
  Balance at End of Year                                                      (161)       (105)        (33)
===========================================================================================================
</TABLE>

See accompanying notes to Consolidated Financial Statements.


                                      88
<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 United States (US) GAAP on the Consolidated
Financial Statements is disclosed in Note 21.

(a) USE OF ESTIMATES

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 accruals,  litigation,  environmental  and asset  retirement
obligations,  income  taxes and the  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.

(b) PRINCIPLES OF CONSOLIDATION

The Consolidated  Financial  Statements include the accounts of Nexen Inc. and
our subsidiary  companies (Nexen, we or our). All subsidiary  companies,  with
the  exception  of  Canexus LP (see Note 2) and its  subsidiaries,  are wholly
owned  and all  material  intercompany  accounts  and  transactions  have been
eliminated.  On August 18, 2005, we sold our  chemicals  operations to Canexus
LP, but  retained  effective  control of these  operations  through  our 61.4%
interest  in  Canexus  LP (see Note 2).  All of the  assets,  liabilities  and
results of operations of Canexus LP and its subsidiaries have been included in
our consolidated  financial  statements.  The non-Nexen ownership interests in
Canexus LP and its subsidiaries  are shown as  non-controlling  interests.  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.

(c) ACCOUNTS RECEIVABLE

Accounts  receivable are recorded based on our revenue recognition policy (see
Note 1(j)). Our allowance for doubtful accounts provides for specific doubtful
receivables.

(d) 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.

(e) 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 on a regular
basis  following  completion of drilling.  Exploration  drilling  costs remain
capitalized when a well has found a sufficient quantity of reserves to justify
its completion as a producing  well and  sufficient  progress is being made to
assess the reserves and the economic and operating  viability of the well. 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.


                                      89
<PAGE>

PP&E  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.

(f) 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 these estimates.

In assessing  the carrying  values of our  unproved  properties,  we take into
account our future  plans for these  properties,  the  remaining  terms of the
leases and any other factors that may be indicators of potential impairment.

(g) 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 expensed to DD&A in the year  recovered.  All  recoveries
are recorded as revenue in the year of recovery.

(h) 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
PP&E 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
PP&E. We periodically  review our estimates for changes in expected amounts or
timing of cash flows.

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.


                                      90
<PAGE>

(i) 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.  If our  goodwill  is
impaired,  we write it down to its implied fair value, based on the fair value
of the assets and  liabilities of the underlying  reporting unit. Our goodwill
is attributable to our marketing and UK reporting units.

(j) 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 US and the UK, our  customers
primarily 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(g).

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 unless the  requirements  for hedge  accounting are
met (see Note  1(n)).  We record any change in fair value as a gain or loss in
marketing and other.

Any margin realized by our marketing  operation 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.

(k) INCOME TAXES

We follow the liability  method of accounting  for income taxes (see Note 18).
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, as we intend to invest such earnings indefinitely
in foreign operations.

(l) 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 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.


                                      91
<PAGE>

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 this translation, except on
our designated  US-dollar debt, are included in income. We have designated our
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.

(m) CAPITALIZED INTEREST

We  capitalize  interest on major  development  projects  until the project is
substantially complete using the weighted- average interest rate on all of our
borrowings. Capitalized interest cannot exceed the actual interest expense.

(n)  DERIVATIVE INSTRUMENTS

NON-TRADING ACTIVITIES

We use derivative  instruments such as physical  purchase and sales contracts,
forwards,  futures,  swaps and  options  for  non-trading  purposes  to manage
fluctuations in commodity prices, foreign currency exchange rates and interest
rates (see Note 7). 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.

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.

(o) EMPLOYEE FUTURE 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 that
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.

(p) 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


                                      92
<PAGE>

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  between  December  1,  2004 and
December 1, 2005 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.  Stock  options  awarded to our US  employees  after
December 1, 2005 are accounted for as tandem options.

We provide stock appreciation rights to employees as described in Note 12, and
we account for these on the same basis as our tandem options.  Obligations are
accrued as  compensation  expense over the graded  vesting period of the stock
appreciation rights.

(q) 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.

(r) RESTRICTED CASH

Restricted  cash  includes  margin  deposits  relating to our  exchange-traded
derivative   contracts   and  other  cash   balances   subject  to  regulatory
restrictions.

(s) LEASES

We classify leases entered into as either capital or operating leases.  Leases
that transfer  substantially  all of the benefits and risks of ownership to us
are accounted for as capital  leases and included with PP&E.  These assets are
depreciated on the same basis as other PP&E.  Rental  payments under operating
leases are expensed as incurred.

(t) 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.

(u) CHANGES IN ACCOUNTING PRINCIPLES

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  denominated  preferred and
subordinated  securities  have been  included as cumulative  foreign  currency
translation adjustments.

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  2005  and  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 2005 and 2004,  we included $53 and
$73  million,  respectively,  of  geological  and  geophysical  costs as other
operating cash outflows.  For 2003,  geological and  geophysical  costs of $62
million are included in investing  activities as exploration  and  development
capital   expenditures.   This  change  in   accounting   policy  was  adopted
prospectively.


                                      93
<PAGE>

(v) RECLASSIFICATION

Certain information  provided for prior years has been reclassified to conform
to the presentation adopted in 2005.

2. CANEXUS INCOME FUND

In June 2005, our board of directors approved a plan to monetize our chemicals
operations  through the  creation of an income trust and the issuance of trust
units in an initial public  offering.  This initial public  offering closed on
August 18, 2005,  with Canexus Income Fund (Canexus)  issuing 30 million units
at a price of $10 per unit for gross  proceeds of $300 million ($284  million,
net of underwriters' commissions).

Concurrent with the closing of the offering, Canexus acquired a 36.5% interest
in Canexus  Limited  Partnership  (Canexus LP) using the net proceeds from the
initial public offering.  Canexus LP acquired Nexen's  chemicals  business for
approximately $1 billion,  comprised of the net proceeds from Canexus' initial
public  offering  and $200  million  (US$167  million) of bank debt,  plus the
issuance of 52.3 million  exchangeable limited partnership units (Exchangeable
LP Units) of Canexus LP. At that time, the Exchangeable LP Units held by Nexen
represented a 63.5% interest in Canexus LP.

The  Exchangeable  LP Units held by Nexen are  exchangeable  on a  one-for-one
basis for trust units of Canexus. As a result, the Exchangeable LP Units owned
by Nexen were  exchangeable  into 52.3 million  trust units which  represented
63.5% of the  outstanding  trust  units of Canexus  assuming  exchange  of the
Exchangeable LP Units.

On  September  16,  2005,  the  underwriters  of the initial  public  offering
exercised a portion of their  over-allotment  option to purchase  1.75 million
trust units at $10 per unit for gross  proceeds of $18 million  ($17  million,
net of underwriters'  commissions).  As a result, Nexen exchanged 1.75 million
of its  Exchangeable  LP Units for $17  million  in net  proceeds.  After this
exchange, Nexen has a 61.4% interest in Canexus LP represented by 50.5 million
Exchangeable LP Units. The initial public offering, together with the exercise
of the  over-allotment,  resulted  in  total  net  proceeds  to  Nexen of $301
million.

These  transactions  diluted our interest in our  chemicals  operations.  As a
result of this  dilution,  we recorded a gain of $193 million during the third
quarter of 2005.

We have the  right to  nominate  a  majority  of the  members  of the board of
Canexus  Limited,  the  corporation  with  responsibility  for  the  strategic
management  and  operational  decisions  of Canexus and Canexus LP.  Nexen has
nominated two representatives to the 10-member board of Canexus Limited. Since
we have retained  effective  control of our chemicals  business,  the results,
assets and  liabilities of this business have been included in these financial
statements.  The non-Nexen  ownership  interests in our chemicals business are
shown as non-controlling interests.


                                      94
<PAGE>

3. 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 gave us access to
interests  in  several  satellite   discoveries  and  more  than  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 was attributable to the established  North Sea presence  acquired and the
knowledge and business  relationships acquired through the management team and
employees of EnCana UK.

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  values  of the  assets  and  liabilities
acquired:

Purchase Price, Net of Cash Acquired:
  Cash Paid                                                              2,561
  Transaction Costs                                                         22
-------------------------------------------------------------------------------
Total Purchase Price                                                     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 ($/share)                   3.27        2.40
Earnings Per Common Share--Diluted ($/share)                 3.23        2.38

4. ACCOUNTS RECEIVABLE

                                                             2005        2004
------------------------------------------------------------------------------
Trade
  Marketing                                                 2,400       1,452
  Oil and Gas                                                 614         557
------------------------------------------------------------------------------
  Chemicals and Other                                          48          57
------------------------------------------------------------------------------
                                                            3,062       2,066
Non-Trade                                                      96          49
------------------------------------------------------------------------------
                                                            3,158       2,115
Allowance for Doubtful Receivables                             (7)        (15)
------------------------------------------------------------------------------

Total Accounts Receivable                                   3,151       2,100
==============================================================================


                                      95
<PAGE>

5. INVENTORIES AND SUPPLIES

                                                              2005       2004
------------------------------------------------------------------------------
Finished Products
  Marketing                                                    320        199
  Oil and Gas                                                   11          6
  Chemicals and Other                                           15         13
------------------------------------------------------------------------------
                                                               346        218
Work in Process                                                  6          4
Field Supplies                                                 152        129
------------------------------------------------------------------------------

Total Inventories and Supplies                                 504        351
==============================================================================

6. PROPERTY, PLANT AND EQUIPMENT

<TABLE>
<CAPTION>
                                              2005                                 2004
----------------------------------------------------------------- ----------------------------------
                                        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                           833           546         287        678           506        172
  Yemen--Carried Interest       1,410         1,295         115      1,360         1,044        316
  Canada                        3,631         1,311       2,320      2,603         1,195      1,408
  United States                 2,437         1,159       1,278      2,249         1,037      1,212
  United Kingdom                4,013           216       3,797      3,499            16      3,483
  Other Countries                 249           119         130        535           408        127
  Marketing                       177            72         105        157            64         93
----------------------------------------------------------------- ----------------------------------
                               12,750         4,718       8,032     11,081         4,270      6,811
Syncrude                        1,240           171       1,069      1,030           155        875
Chemicals                         827           456         371        815           409        406
Corporate and Other               245           123         122        201            90        111
----------------------------------------------------------------- ----------------------------------

Total PP&E                     15,062         5,468       9,594     13,127         4,924      8,203
================================================================= ==================================
</TABLE>

The above table includes  capitalized  costs of $5,211  million  (2004--$3,945
million)  relating to unproved  properties and projects under  construction or
development. These costs are not being depreciated, depleted or amortized.

DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT

Included in our 2005  depreciation,  depletion,  amortization  and  impairment
expense was $58 million relating to the writedown of a portion of our purchase
price allocation to unproved properties purchased in the North Sea as a result
of unsuccessful exploration activities.

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  resulted
from negative reserve revisions and was 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.

RESEARCH AND DEVELOPMENT

We  incurred  $54  million   (2004--$35   million)  related  to  research  and
development activities. Costs of $44 million (2004--$26 million) were recorded
in other expense on the Consolidated  Statement of Income. The remaining costs
have been deferred and are included in PP&E.

                                                              2005       2004
------------------------------------------------------------------------------
Development Costs Deferred, Beginning of Year                   15          6
  Deferred in the Year                                          10          9
  Amortized in the Year                                          -          -
------------------------------------------------------------------------------
Development Costs Deferred, End of Year                         25         15
==============================================================================


                                      96
<PAGE>

SUSPENDED WELL COSTS

In the third quarter of 2005, we adopted staff position 19-1 (FSP 19-1) issued
by the Financial Accounting Standards Board (FASB) on accounting for suspended
well costs.  FSP 19-1 amends FASB Statement No. 19,  Financial  Accounting and
Reporting  by Oil  and  Gas  Producing  Companies,  for  companies  using  the
successful  efforts  method of  accounting,  which  required that  capitalized
exploratory well costs be expensed if related reserves could not be classified
as proved  within one year.  FSP 19-1  provides  that  exploratory  well costs
should continue to be capitalized when a well has found a sufficient  quantity
of reserves  to justify its  completion  as a  producing  well and  sufficient
progress is being made to assess the reserves  and the economic and  operating
viability of the well. FSP 19-1 also requires certain disclosures with respect
to capitalized exploratory well costs.

The following  table shows the changes in capitalized  exploratory  well costs
during  the years  ended  December  31,  2005 and 2004,  and does not  include
amounts that were initially  capitalized and subsequently expensed in the same
period.

<TABLE>
<CAPTION>
                                                                                                        2005       2004
------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                <C>        <C>
Balance at Beginning of Year                                                                             116         89
  Additions to Capitalized Exploratory Well Costs Pending the Determination of Proved Reserves           174         51
  Capitalized Exploratory Well Costs Charged to Expense                                                  (27)       (19)
  Transfers to Wells, Facilities and Equipment Based on Determination of Proved Reserves                  (3)         -
  Effects of Foreign Exchange                                                                             (8)        (5)
------------------------------------------------------------------------------------------------------------------------
Balance at End of Year                                                                                   252        116
========================================================================================================================
</TABLE>

The following  table provides an aging of capitalized  exploratory  well costs
based on the date  drilling was completed and shows the number of projects for
which  exploratory  well costs have been capitalized for a period greater than
one year after the completion of drilling.

<TABLE>
<CAPTION>
                                                                                                        2005       2004
------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                <C>        <C>
  Capitalized for a Period of One Year or Less                                                           165         53
  Capitalized for a Period of Greater than One Year                                                       87         63
------------------------------------------------------------------------------------------------------------------------
Balance at End of Year                                                                                   252        116
========================================================================================================================

Number of Projects that have Exploratory Well Costs Capitalized for a Period Greater than One Year         3          2
</TABLE>

As at December 31, 2005, we have exploratory  costs that have been capitalized
for more than one year  relating  to our  interest  in an  exploratory  block,
offshore Nigeria ($74 million), our interest in exploratory blocks in the Gulf
of Mexico ($4 million) and coal bed methane  exploratory  activities in Canada
($9 million).  Exploratory  costs offshore  Nigeria were first  capitalized in
1998, and we have subsequently drilled a further seven successful wells on the
block.  The joint  venture  partners  have  finalized  pre-development  design
studies and have submitted a field  development plan for government  approval.
Drilling  activity has resumed and an appraisal and exploration  program is in
progress.  When final regulatory  approvals have been received and the project
has been sanctioned,  we will book proved reserves.  We have capitalized costs
related to  successful  wells  drilled in 2004 and 2005 in the Gulf of Mexico,
and in Canada, we have capitalized  exploratory costs relating to our coal bed
methane projects. We are assessing all of these wells and projects, and we are
working with our partners to prepare development plans.


                                      97
<PAGE>

7. DERIVATIVE INSTRUMENTS AND FINANCIAL RISK MANAGEMENT

(a) CARRYING VALUE AND ESTIMATED FAIR VALUE OF DERIVATIVE AND FINANCIAL
    INSTRUMENTS

The  carrying  values,  fair  values and  unrecognized  gains or losses on our
outstanding  derivatives  and long-term  financial  assets and  liabilities at
December 31 are:

<TABLE>
<CAPTION>
                                                         2005                                           2004
--------------------------------------------------------------------------------- -----------------------------------------------
                                      Carrying                      Unrecognized      Carrying                       Unrecognized
Cdn$ millions                            Value       Fair Value      Gain (Loss)         Value       Fair Value       Gain (Loss)
--------------------------------------------------------------------------------- -----------------------------------------------
<S>                                   <C>            <C>            <C>               <C>            <C>             <C>
Commodity Price Risk
  Non-Trading Activities
    Crude Oil Put Options                    4                4                -           200              200                -
    Fixed Price Natural Gas
      Contracts                           (175)            (175)               -             -              (98)             (98)
    Natural Gas Swaps                       29               29                -             -                -                -

  Trading Activities
    Crude Oil and Natural Gas              161              161                -            83               83                -
    Future Sale of Gas Inventory             -              (35)             (35)            -                6                6

Foreign Currency Risk
  Non-Trading Activities                    14               14                -             7                7                -
  Trading Activities                         8                8                -            10               10                -
--------------------------------------------------------------------------------- -----------------------------------------------
Total Derivatives                           41                6              (35)          300              208              (92)
================================================================================= ===============================================

Financial Assets and Liabilities
  Long-Term Debt                        (3,687)          (3,863)            (176)       (4,259)          (4,503)            (244)
</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,  restricted  cash,
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.

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
established  an  annual  average  WTI  floor  price of  US$43/bbl  in 2005 and
US$38/bbl  in 2006 at a cost of $144  million.  The WTI crude oil put  options
with respect to 2005 production were not used and have expired.  The WTI crude
oil put options with respect to 2006  production  are stated at fair value and
are  included in deferred  charges and other  assets as they settle  beyond 12
months of December 31, 2005. Any change in fair value is included in marketing
and other on the Consolidated Statement of Income.

<TABLE>
<CAPTION>
                                     Notional                           Average             Fair
                                      Volumes                       Price (WTI)            Value
WTI CRUDE OIL PUT OPTIONS            (bbls/d)             Term        (US$/bbl)  (Cdn$ millions)
-------------------------------------------------------------------------------------------------


<S>                           <C>              <C>              <C>              <C>
                                       30,000             2006               39                2
                                       20,000             2006               38                1
                                       10,000             2006               36                1
-------------------------------------------------------------------------------------------------
                                                                                               4
                                                                                =================
</TABLE>


                                      98
<PAGE>

FIXED PRICE NATURAL GAS CONTRACTS AND NATURAL GAS SWAPS

In July and August 2005, we sold certain Canadian oil and gas properties,  and
we retained  fixed-price  natural  gas sales  contracts  that were  previously
associated with those properties (see Note 14).

Since these  contracts  are no longer used in the normal course of our oil and
gas  operations,  they  have been  marked-to-market  and are  included  in the
Consolidated  Balance Sheet. Any change in fair value is included in marketing
and other in the Consolidated Statement of Income.

<TABLE>
<CAPTION>
                                     Notional                                               Fair
                                      Volumes                             Price            Value
                                       (Gj/d)             Term           ($/Gj)  (Cdn$ millions)
-------------------------------------------------------------------------------------------------


<S>                           <C>              <C>              <C>              <C>
Fixed-Price Natural Gas                22,034        2005-2006        2.28-3.72              (47)
                                       15,514        2007-2010        2.47-2.77             (128)
-------------------------------------------------------------------------------------------------
                                                                                            (175)
                                                                                =================
</TABLE>

Following  the sale of the  Canadian oil and gas  properties,  we entered into
natural  gas swaps to  economically  hedge  our  exposure  to the  fixed-price
natural gas  contracts.  Any change in fair value is included in marketing and
other in the Consolidated Statement of Income.

<TABLE>
<CAPTION>
                                     Notional                                               Fair
                                      Volumes                             Price            Value
                                       (Gj/d)             Term           ($/Gj)  (Cdn$ millions)
-------------------------------------------------------------------------------------------------


<S>                           <C>              <C>              <C>              <C>
Natural Gas Swaps                      22,034        2005-2006       9.02-11.81                1
                                       15,514        2007-2010             7.45               28
-------------------------------------------------------------------------------------------------
                                                                                              29
                                                                                =================
</TABLE>

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 $161 million fair value of the commodity contracts
at December  31, 2005 is included in the  Consolidated  Balance  Sheet and any
change in fair value is included in  marketing  and other in the  Consolidated
Statement of 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, 2005 are:

<TABLE>
<CAPTION>
                                                    Hedged Volumes                     Average Price  Unrecognized Loss
                                                            (mmcf)            Month        (US$/mcf)    (Cdn$ millions)
-----------------------------------------------------------------------------------------------------------------------
<S>                                                <C>              <C>              <C>               <C>
NYMEX Natural Gas Futures                                    9,100     January 2006             8.89               (27)
                                                               400    February 2006            10.96                 -

NYMEX Natural Gas Fixed-Price and Basis Swaps                4,529     January 2006             9.15                (8)
-----------------------------------------------------------------------------------------------------------------------
                                                                                                                   (35)
                                                                                                      =================
</TABLE>


                                      99
<PAGE>

(c) FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT

NON-TRADING ACTIVITIES

<TABLE>
<CAPTION>
                                                                                                        Rate        Fair Value
                                                                    Amount             Term    (for US$1.00)   (Cdn$ millions)
------------------------------------------------------------------------------------------------------------------------------
<S>                                                <C>                      <C>              <C>              <C>
Foreign Currency Call Options--Buzzard (i)                  GBP207 million             2006             2.00                -
US Dollar Call Options--Canexus (ii)                 US$11 million monthly             2006             0.813               6
Foreign Currency Swap (iii)                                  US$37 million             2006             0.736               8
------------------------------------------------------------------------------------------------------------------------------
                                                                                                                           14
                                                                                                             =================
</TABLE>

(i) FOREIGN CURRENCY CALL OPTIONS--BUZZARD

Our  Buzzard  development  project in the North Sea creates  foreign  currency
exposure as a portion of the capital costs are  denominated  in British pounds
and Euros. To reduce our exposure to fluctuations in these currencies relative
to the US dollar,  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.  Any change in fair value
is included in marketing and other in the Consolidated Statement of Income.

(ii) US DOLLAR CALL OPTIONS--CANEXUS

The  operations  of Canexus are exposed to changes in the  US-dollar  exchange
rate as a portion of its sales are  denominated  in US dollars.  In connection
with the initial  public  offering of Canexus,  we  purchased  US-dollar  call
options to reduce this  exposure to  fluctuations  in the  Canadian-US  dollar
exchange  rate.  Canexus  has the  right to sell  US$11  million  monthly  and
purchase  Canadian  dollars at an exchange rate of US$0.813 until August 2006.
Any  change  in  fair  value  is  included  in  marketing  and  other  in  the
Consolidated Statement of Income.

(iii) FOREIGN CURRENCY SWAP

We occasionally use derivative  instruments to effectively  convert cash flows
from  Canadian to US dollars and vice versa.  At December 31, 2005,  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 8). Any change in fair
value is included in  marketing  and other in the  Consolidated  Statement  of
Income.

OTHER

The  foreign  exchange  gains or losses  related  to our  designated  debt are
included  in  the  cumulative  foreign  currency  translation   adjustment  in
shareholders' equity. Our net investment in self-sustaining foreign operations
and our designated US-dollar debt at December 31 are as follows:

US$ millions                                                   2005       2004
------------------------------------------------------------------------------
Net Investment in Self-Sustaining Foreign Operations          4,357      3,973
US-Dollar Debt                                                2,700      3,315

We also have small exposures 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.

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  enable us to lock-in  our
margins on the future sale of crude oil and natural  gas.  The $8 million fair
value of our  US-dollar  forward  contracts  and swaps at December 31, 2005 is
included in the  Consolidated  Balance Sheet,  and any change in fair value is
included in marketing and other in the Consolidated Statement of Income.


                                      100
<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                                                 2005       2004
------------------------------------------------------------------------------
Accounts Receivable                                            382        177
Deferred Charges and Other Assets (1) (Note 10)                232         91
Total Derivative Contract Assets                               614        268
------------------------------------------------------------------------------

Accounts Payable and Accrued Liabilities                       321        129
Deferred Credits and Other Liabilities (1) (Note 11)           124         46
------------------------------------------------------------------------------
Total Derivative Contract Liabilities                          445        175
==============================================================================

Total Derivative Contract Net Assets (2)                       169         93
==============================================================================

Note:
1    These derivative  instruments  settle beyond 12 months and are considered
     non-current.
2    Comprised  of $161  million  (2004--$83  million)  related  to  commodity
     contracts and $8 million (2004--$10 million) related to US-dollar forward
     contracts and swaps.

Our  exchange-traded  derivative  contracts  are  subject  to  margin  deposit
requirements.  We are required to advance cash to  counterparties  in order to
satisfy these requirements. We did not have any margin deposit requirements at
December 31, 2005 and 2004.

(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, 2005,  fixed-rate
borrowings  comprised 95%  (2004--56%)  of our long-term  debt at an effective
average rate of 6.3% (2004--6.6%). During the year we periodically drew on our
floating rate unsecured syndicated term credit facilities.  We had no interest
rate swaps outstanding in 2005 or 2004.

(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.

8. LONG-TERM DEBT AND SHORT-TERM BORROWINGS

                                                                 2005     2004
-------------------------------------------------------------------------------
Acquisition Credit Facilities (a)                                   -    1,806
Canexus LP Term Credit Facilities (US$147 million drawn) (b)      171        -
Term Credit Facilities (c)                                          -       87
Debentures, due 2006 (1) (d)                                       93       93
Medium-Term Notes, due 2007 (e)                                   150      150
Medium-Term Notes, due 2008 (f)                                   125      125
Notes, due 2013 (US$500 million) (g)                              583      602
Notes, due 2015 (US$250 million) (h)                              292        -
Notes, due 2028 (US$200 million) (i)                              233      241
Notes, due 2032 (US$500 million) (j)                              583      602
Notes, due 2035 (US$790 million) (k)                              921        -
Subordinated Debentures, due 2043 (US$460 million) (l)            536      553
-------------------------------------------------------------------------------
Total                                                           3,687    4,259
===============================================================================

Note:
1    Includes $50 million of principal that was effectively  converted through
     a currency exchange contract to US$37 million.


                                      101
<PAGE>

(a) ACQUISITION CREDIT FACILITIES

During  the year,  we repaid all  amounts  outstanding  under our  acquisition
credit facilities, which were used to fund a portion of the purchase price for
the  acquisition  of  EnCana  UK in  2004.  We  replaced  the  US$500  million
development  facility  associated with the acquisition  credit facilities with
the renewal of our term credit  facilities.  During 2005, the weighted average
interest rate on the acquisition credit facilities was 3.9% (2004--3.2%).

(b) CANEXUS LP TERM CREDIT FACILITIES

Canexus LP has $350  million of  committed,  secured,  revolving  term  credit
facilities,  which are  available  until 2009.  At December 31,  2005,  US$147
million ($171 million) was drawn on these facilities. Borrowings are available
as Canadian bankers' acceptances, LIBOR-based loans, Canadian prime rate loans
or US-dollar base rate loans.  Interest is payable monthly at a floating rate.
The term credit facilities are secured by a floating charge debenture over all
of Canexus  LP's  assets and by certain  guarantees,  security  interests  and
subordination  agreements  provided by certain affiliates of Canexus LP (which
do not include Nexen). During 2005, the weighted- average interest rate on the
Canexus LP term credit facilities was 4.8%.

(c) TERM CREDIT FACILITIES

We have committed,  unsecured,  term credit facilities of $2.4 billion,  which
are  available  until  2010.  The  lenders  have the option to extend the term
annually.   Borrowings  are  available  as  Canadian   bankers'   acceptances,
LIBOR-based loans, Canadian prime loans,  US-dollar base rate loans or British
pound call-rate loans.  Interest is payable monthly at a floating rate. During
2005, the weighted- average interest rate was 4.4%  (2004--3.2%).  At December
31, 2005, $250 million of these facilities were utilized to support letters of
credit.

(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%.
Amounts due November 2006 have not been included in current  liabilities as we
expect to refinance this amount with our term credit facilities.

(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%.


                                      102
<PAGE>

(h) NOTES, DUE 2015

During  March 2005,  we issued  US$250  million of notes.  Interest is payable
semi-annually  at a rate of 5.20%,  and the principal is to be repaid in March
2015. 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 0.15%.

(i) 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%.

(j) 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%.

(k) NOTES, DUE 2035

During  March 2005,  we issued  US$790  million of notes.  Interest is payable
semi-annually at a rate of 5.875%,  and the principal is to be repaid in March
2035. 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%.

(l) 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.

(m) DEBT REPAYMENTS

2006                                                                       93
2007                                                                      150
2008                                                                      125
2009                                                                      171
2010                                                                        -
Thereafter                                                              3,148
------------------------------------------------------------------------------
Total Debt Repayments                                                   3,687
==============================================================================

(n) DEBT COVENANTS

Some of our  debt  instruments  contain  covenants  with  respect  to  certain
financial  ratios and our ability to grant security.  At December 31, 2005, we
were in compliance with all covenants.

(o) SHORT-TERM BORROWINGS

Nexen has  uncommitted,  unsecured  credit  facilities of  approximately  $732
million.  No amounts  were drawn under these  facilities  at December 31, 2005
(2004--$100  million).  We have utilized  $468 million of these  facilities to
support  letters  of credit at  December  31,  2005.  Interest  is  payable at
floating  rates.  During  2005,  the  weighted-average  interest  rate  on our
short-term borrowings was 3.6% (2004--2.9%).


                                      103
<PAGE>

(p) INTEREST EXPENSE

                                                   2005       2004       2003
------------------------------------------------------------------------------
Long-Term Debt                                      260        182        204
Other                                                15         12          8
------------------------------------------------------------------------------
Total                                               275        194        212
  Less: Capitalized                                (178)       (51)       (43)
------------------------------------------------------------------------------
Total Interest Expense                               97        143        169
==============================================================================

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.

9. ASSET RETIREMENT OBLIGATIONS

Changes in carrying  amounts of the asset  retirement  obligations  associated
with our PP&E are as follows:

                                                              2005       2004
------------------------------------------------------------------------------
Balance at Beginning of Year                                   468        323
  Obligations Assumed with Development Activities               72         12
  Obligations Assumed with Business Acquisition                  -        134
  Obligations Discharged with Disposed Properties              (37)        (4)
  Expenditures Made on Asset Retirements                       (34)       (31)
  Accretion                                                     26         17
  Revisions to Estimates                                       138         24
  Effects of Foreign Exchange                                  (22)        (7)
------------------------------------------------------------------------------
Balance at End of Year 1, 2                                    611        468
==============================================================================

Notes:
1    Obligations due within 12 months of $21 million (2004--$47  million) have
     been included in accounts  payable and accrued  liabilities.  Obligations
     related to discontinued operations of $22 million have been included with
     liabilities of discontinued operations at December 31, 2004.
2    Obligations relating to our oil and gas activities amount to $564 million
     (2004--$422  million) and obligations  relating to our chemicals business
     amount to $47 million (2004--$46 million).

Our total estimated undiscounted asset retirement obligations amount to $1,471
million.  We have discounted the total estimated asset retirement  obligations
using  a   weighted-average,   credit-adjusted   risk-free   rate   of   5.7%.
Approximately $88 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.

In connection  with the sale of our chemicals  business to Canexus LP, we have
contributed $14 million to a remediation  fund to be used for asset retirement
obligations  associated  with the assets sold. This is included on our balance
sheet as part of deferred charges and other assets.

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.

10. DEFERRED CHARGES AND OTHER ASSETS

                                                              2005       2004
------------------------------------------------------------------------------
Long-Term Marketing Derivative Contracts (Note 7d)             232         91
Deferred Financing Costs                                        63         67
Asset Retirement Remediation Fund (Note 9)                      14          -
Crude Oil Put Options (Note 7)                                   4        200
Defined Benefit Pension Plan Asset (Note 16)                     -         13
Other                                                           85         58
------------------------------------------------------------------------------
Total                                                          398        429
==============================================================================


                                      104
<PAGE>

11. DEFERRED CREDITS AND OTHER LIABILITIES

                                                              2005       2004
------------------------------------------------------------------------------
Fixed-Price Natural Gas Contracts (Note 7b)                    128          -
Long-Term Marketing Derivative Contracts (Note 7d)             124         46
Deferred Transportation                                         87         33
Stock-Based Compensation Liability                              53          -
Defined Benefit Pension Obligation (Note 16)                    39         32
Other                                                           48         31
------------------------------------------------------------------------------
Total                                                          479        142
==============================================================================

12. 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.

Our shareholders  approved a split of our issued and outstanding common shares
on a  two-for-one  basis at our annual and special  meeting on April 27, 2005.
All  common  shares,  per  common  share  amounts,  stock  options  and  stock
appreciation  rights  together  with their related  weighted-average  exercise
prices, have been restated to retroactively reflect the share split.

(b) ISSUED COMMON SHARES AND DIVIDENDS

(thousands of shares)                                2005      2004      2003
------------------------------------------------------------------------------
Beginning of Year                                 258,399   251,212   245,932
Issue of Common Shares for Cash
  Exercise of Stock Options                         1,823     5,902     3,928
  Dividend Reinvestment Plan                          605       895       952
  Employee Flow-through Shares                        314       390       400
------------------------------------------------------------------------------
End of Year                                       261,141   258,399   251,212
==============================================================================

Dividends Declared per Common Share ($/share)        0.20      0.20    0.1625
==============================================================================

Cash Consideration (Cdn$ millions)
  Exercise of Stock Options                            29        93        50
  Dividend Reinvestment Plan                           20        21        15
  Employee Flow-through Shares                          9        10         8
------------------------------------------------------------------------------
                                                       58       124        73
==============================================================================

At December  31,  2005,  there were 774,915  common  shares  (2004--1,379,874;
2003--2,274,610) 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 options  outstanding on June 30,
2004.  In the  second  quarter of 2004,  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.


                                      105
<PAGE>

Following the introduction of the American Job Creation Act of 2004 in the US,
stock  options  awarded  to our US  employees  between  December  1,  2004 and
December 1, 2005 did 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 2005 of $2  million  (2004--$0.1  million)  which was  included  in
general and administrative expense. In 2005, US tax regulations were modified.
As a result,  tandem  options  have  been  issued  to our US  employees  after
December  1, 2005.  These  options  are  expensed  using the  intrinsic-method
described above.

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
four years and are  exercisable on a cumulative  basis over 10 years.  Options
granted  after  February 2001 vest over three years and are  exercisable  on a
cumulative  basis over five years.  At the time of grant,  the exercise  price
equals the market price. The following options have been granted:

<TABLE>
<CAPTION>
                                               2005                            2004                            2003
----------------------------------------------------------------- ------------------------------- -------------------------------
                                                        Weighted                        Weighted                        Weighted
                                                         Average                         Average                         Average
                                        Options   Exercise Price        Options   Exercise Price        Options   Exercise Price
                                    (thousands)      ($/options)    (thousands)      ($/options)     (thousands)      ($/options)
----------------------------------------------------------------- ------------------------------- -------------------------------
<S>                                  <C>              <C>            <C>              <C>            <C>              <C>
Balance at Beginning of Year             16,276               20         18,406               17         18,952               15
  Granted                                 3,392               55          4,224               25          3,753               22
  Exercised for Stock                    (1,823)              16         (5,902)              15         (3,927)              14
  Surrendered for Cash                   (2,089)              17           (289)              17              -                -
  Forfeited                                (441)              22           (163)              17           (372)              16
----------------------------------------------------------------- ------------------------------- -------------------------------
Balance at End of Year                   15,315               28         16,276               20         18,406               17
================================================================= =============================== ===============================

Options Exercisable at End of Year        8,131               19          8,455               17         10,133               15
----------------------------------------------------------------- ------------------------------- -------------------------------
Common Shares Reserved for
Issuance Under the
Stock Option Plan                        17,290                          19,172                          19,576
</TABLE>

The range of  exercise  prices  of  options  outstanding  and  exercisable  at
December 31, 2005 is as follows:

<TABLE>
<CAPTION>
                                                       Outstanding Options                              Exercisable Options
--------------------------------------------------------------------------------------------- ---------------------------------
                                                                 Weighted           Weighted                           Weighted
                                               Number of          Average      Average Years         Number of          Average
                                                 Options   Exercise Price          to Expiry           Options   Exercise Price
                                             (thousands)      ($/options)            (years)       (thousands)      ($/options)
--------------------------------------------------------------------------------------------- ---------------------------------
<S>                                          <C>              <C>              <C>               <C>              <C>
$5.00 to $9.99                                        196                9                3               196                9
$10.00 to $14.99                                    1,198               13                3             1,198               13
$15.00 to $19.99                                    4,266               18                3             3,992               17
$20.00 to $24.99                                    3,311               23                3             1,774               22
$25.00 to $29.99                                    2,974               25                4               971               25
$30.00 to $34.99                                       38               31                4                 -                -
$35.00 to $39.99                                        -                -                -                 -                -
$40.00 to $44.99                                        2               40                5                 -                -
$45.00 to $49.99                                       14               47                5                 -                -
$50.00 to $54.99                                    2,669               55                5                 -                -
$55.00 to $59.99                                      647               55                5                 -                -
--------------------------------------------------------------------------------------------- ---------------------------------
Total Options                                      15,315                                               8,131
============================================================================================= =================================
</TABLE>


                                      106
<PAGE>

In previous periods, we estimated the fair value of stock options issued using
the  Generalized  Black-Scholes  option  pricing  model  under  the  following
assumptions:

                                                                         2003
------------------------------------------------------------------------------
Weighted-Average Fair Value ($/option)                                  10.10
Risk-Free Interest Rate (%)                                               3.6
Estimated Hold Period Prior to Exercise (years)                             3
Volatility in the Price of Nexen's Common Shares (%)                       30
Dividends per Common Share ($/share)                                     0.40

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.

                                                                         2003
------------------------------------------------------------------------------
Fair Value of Stock Options Granted                                        25
Less: Fair Value of Stock Options Expensed                                 (1)
------------------------------------------------------------------------------
                                                                           24
                                                                   ===========
Net Income Attributable to Common Shareholders
  As Reported                                                             578
  Pro Forma                                                               554
------------------------------------------------------------------------------

Earnings Per Common Share ($/share)
  Basic as Reported                                                      2.33
  Pro Forma                                                              2.24

  Diluted as Reported                                                    2.31
  Pro Forma                                                              2.22
------------------------------------------------------------------------------

(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>
                                              2005                            2004                            2003
---------------------------------------------------------------- -------------------------------- ------------------------------
                                                       Weighted                         Weighted                       Weighted
                                                        Average                          Average                        Average
                                         StARs   Exercise Price           StARs   Exercise Price         StARs   Exercise Price
                                   (thousands)        ($/right)     (thousands)        ($/right)   (thousands)        ($/right)
---------------------------------------------------------------- -------------------------------- ------------------------------



<S>                                <C>              <C>            <C>              <C>            <C>              <C>
Balance at Beginning of Year             6,436               22          4,809               18          3,625               17
  Granted                                1,443               55          2,609               25          2,033               22
  Exercised for Cash                    (1,455)              19           (867)              16           (725)              16
  Forfeited                               (460)              23           (115)              18           (124)              16
---------------------------------------------------------------- -------------------------------- ------------------------------
Balance at End of Year                   5,964               30          6,436               22          4,809               18
================================================================ ================================ ==============================


Rights Exercisable at End of Year        2,426               21          2,021               17            990               17
</TABLE>


                                      107
<PAGE>

The range of exercise prices of StARs  outstanding and exercisable at December
31, 2005 is as follows:

<TABLE>
<CAPTION>
                                          Outstanding StARs                              Exercisable StARs
---------------------------------------------------------------------------- ----------------------------------
                                                 Weighted          Weighted                          Weighted
                                Number of          Average    Average Years         Number of          Average
                                    StARs   Exercise Price        to Expiry             StARs   Exercise Price
                              (thousands)        ($/right)          (years)       (thousands)        ($/right)
---------------------------------------------------------------------------- ----------------------------------
<S>                           <C>              <C>              <C>               <C>              <C>
$15.00 to $19.99                    1,028               16                2             1,024               16
$20.00 to $24.99                    1,308               22                3               737               22
$25.00 to $29.99                    2,193               25                4               665               25
$30.00 to $34.99                       18               33                4                 -                -
$35.00 to $39.99                       15               37                5                 -                -
$40.00 to $44.99                        9               41                5                 -                -
$45.00 to $49.99                       39               48                5                 -                -
$50.00 to $54.99                    1,353               55                5                 -                -
$55.00 to $59.99                        1               55                5                 -                -
---------------------------------------------------------------------------- ----------------------------------
Total StARs                         5,964                                               2,426
============================================================================ ==================================
</TABLE>

13. EARNINGS PER COMMON SHARE

Our shareholders  approved a split of our issued and outstanding common shares
on a  two-for-one  basis at our annual and special  meeting on April 27, 2005.
All  common  share  and  per  common  share  amounts  have  been  restated  to
retroactively reflect this share split.

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)                                                   2005        2004        2003
----------------------------------------------------------------------------------------------------
<S>                                                                   <C>         <C>         <C>
Weighted-Average Number of Common Shares Outstanding                  260.4       257.3       247.5
Shares Issuable Pursuant to Stock Options                              13.4        13.1        12.6
Shares to be Purchased from Proceeds of Stock Options                  (7.4)       (9.8)      (10.2)
----------------------------------------------------------------------------------------------------
Weighted-Average Number of Diluted Common Shares Outstanding          266.4       260.6       249.9
====================================================================================================
</TABLE>

In  calculating   the   weighted-average   number  of  diluted  common  shares
outstanding for the year ended December 31, 2005, we excluded  280,708 options
(2004--348,200;  2003--5,634,046),  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.

14. DISCONTINUED OPERATIONS

In the third quarter of 2005, we sold certain  Canadian  conventional  oil and
gas properties in southeast Saskatchewan,  northwest  Saskatchewan,  northeast
British Columbia and the Alberta foothills. The results of operations of these
properties have been presented as discontinued operations. The sales closed in
the third  quarter of 2005 with net  proceeds of $900  million  after  closing
adjustments,  and we realized  gains of $225  million.  These gains are net of
losses  attributable to pipeline contracts and fixed price gas sales contracts
associated with these  properties that we have retained,  but no longer use in
connection with our oil and gas business.

During the fourth  quarter of 2004, we concluded  production  from our Buffalo
field,  offshore  Australia.  The results of our  operations in Australia have
been  presented as  discontinued  operations,  as we have no plans to continue
operations in the country.  Remediation and  abandonment  activities have been
completed, and no gain or loss was recognized.

During the third quarter of 2003, we sold certain non-core  conventional light
oil properties in southeast Saskatchewan.  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.


                                      108
<PAGE>

<TABLE>
<CAPTION>
                                                2005                  2004                                 2003
----------------------------------------------------- ------------------------------------ ------------------------------------
                                              Canada     Canada    Australia        Total     Canada    Australia        Total
----------------------------------------------------- ------------------------------------ ------------------------------------
<S>                                           <C>        <C>          <C>          <C>        <C>          <C>          <C>
Revenues and Other Income
  Net Sales                                      154        232           75          307        278           64          342
  Marketing and Other                              -          1            -            1          -            -            -
  Gain on Disposition of Assets                  225          -            -            -          -            -            -
----------------------------------------------------- ------------------------------------ ------------------------------------
                                                 379        233           75          308        278           64          342
Expenses
  Operating                                       27         40           53           93         49           30           79
  Depreciation, Depletion, Amortization and
Impairment                                        28         70            9           79        101           22          123
  General and Administrative                       -          -            -            -          5            -            5
  Exploration Expense                              1          3            -            3          7            1            8
----------------------------------------------------- ------------------------------------ ------------------------------------
Income before Income Taxes                       323        120           13          133        116           11          127
  Current Income Taxes                             -          -            -            -          -           (4)          (4)
  Future Income Taxes                           (129)        50            -           50         58            2           60
----------------------------------------------------- ------------------------------------ ------------------------------------
Net Income                                       452         70           13           83         58           13           71
----------------------------------------------------- ------------------------------------ ------------------------------------

Earnings per Common Share ($/share)
  Basic (Note 13)                               1.74       0.27         0.05         0.32       0.23         0.05         0.28
  Diluted (Note 13)                             1.70       0.27         0.05         0.32       0.23         0.05         0.28
</TABLE>

Assets and  liabilities on the  Consolidated  Balance Sheet as at December 31,
2004, include the following amounts for discontinued operations:

<TABLE>
<CAPTION>
                                                 Canada    Australia        Total
----------------------------------------------------------------------------------
<S>                                         <C>          <C>          <C>
Cash and Cash Equivalents                             -            1            1
Accounts Receivable                                  28            8           36
Other Current Assets                                  -            1            1
Property, Plant and Equipment, Net                  440            -          440
Accounts Payable and Accrued Liabilities             14           25           39
Asset Retirement Obligations                         22            -           22
Future Income Tax Liabilities                       108            -          108
</TABLE>

There were no assets and liabilities related to discontinued  operations as at
December 31, 2005.

15. COMMITMENTS, CONTINGENCIES AND GUARANTEES

<TABLE>
<CAPTION>
                                                  2006         2007         2008         2009         2010   Thereafter
------------------------------------------------------------------------------------------------------------------------
<S>                                               <C>          <C>          <C>          <C>          <C>    <C>
Operating Leases                                    33           33           30           29           26          121
Transportation and Storage Commitments             440          133           97           57           45          116
------------------------------------------------------------------------------------------------------------------------
                                                   473          166          127           86           71          237
========================================================================================================================
</TABLE>

We  have a  number  of  lawsuits  and  claims  pending  including  income  tax
reassessments  (see Note 18),  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  2005,  total  rental  expense  was  $47  million  (2004--$45  million;
2003--$49 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.


                                      109
<PAGE>

16. 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 less 1%, to a maximum increase of 5%.

On the  establishment  of Canexus  during 2005,  the portion of the  projected
benefit obligation and fair value of plan assets relating to Canexus employees
was  transferred  to  Canexus  from  Nexen,  subject to  regulatory  approval.
Canexus' pension and other post retirement benefit amounts have been disclosed
separately for 2005.

(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>
                                                                        2005                         2004
------------------------------------------------------------------------------------------ --------------------------
                                                          Nexen      Canexus     Syncrude         Nexen     Syncrude
------------------------------------------------------------------------------------------ --------------------------
<S>                                                       <C>        <C>         <C>              <C>       <C>

Change in Projected Benefit Obligation (PBO)
  Beginning of Year                                         217            -           91           192           79
    Service Cost                                             15            1            4             8            3
    Interest Cost                                            12            1            5            12            5
    Plan Participants' Contributions                          3            -            1             2            -
    Actuarial Loss/(Gain)                                    33           (2)          11            10            7
    Benefits Paid                                            (8)           -           (3)           (7)          (3)
    Transfer to Canexus                                     (49)          49            -             -            -
------------------------------------------------------------------------------------------ --------------------------
  End of Year (1)                                           223           49          109           217           91
========================================================================================== ==========================

Change in Fair Value of Plan Assets
  Beginning of Year                                         171            -           50           154           44
    Actual Return on Plan Assets                             18            -            6            16            5
    Employer's Contribution                                   2            -            4             6            4
    Plan Participants' Contributions                          3            -            1             2            -
    Benefits Paid                                            (8)           -           (3)           (7)          (3)
    Transfer to Canexus                                     (40)          40            -             -            -
------------------------------------------------------------------------------------------ --------------------------
  End of Year                                               146           40           58           171           50
========================================================================================== ==========================

Reconciliation of Funded Status
  Funded Status (2)                                         (77)          (9)         (51)          (46)         (41)
  Unamortized Transitional Obligation                         1            -            -             1            -
  Unamortized Prior Service Costs                             3            -            -             4            -
  Unamortized Net Actuarial Loss                             44            9           38            30           30
------------------------------------------------------------------------------------------ --------------------------
Pension Liability                                           (29)           -          (13)          (11)         (11)
========================================================================================== ==========================

Pension Liability Recognized
  Deferred Charges and Other Assets (Note 10)                 -            -            -            13            -
  Accounts Payable and Accrued Liabilities                   (1)           -           (2)           (1)          (2)
  Other Deferred Credits and Liabilities (Note 11)          (28)           -          (11)          (23)          (9)
------------------------------------------------------------------------------------------ --------------------------
Pension Liability                                           (29)           -          (13)          (11)         (11)
========================================================================================== ==========================
</TABLE>


<TABLE>
<S>                                                        <C>          <C>          <C>            <C>          <C>
     Assumptions (%)
       Accrued Benefit Obligation at December 31
         Discount Rate                                      5.25        5.25         5.00          6.00         5.75
         Long-Term Rate of Employee Compensation Increase   4.00        4.00         4.00          4.00         4.00
       Benefit Cost for Year Ended December 31 (3)
         Discount Rate                                      5.00        5.00         5.00          6.25         6.00
         Long-Term Rate of Employee Compensation Increase   4.00        4.00         4.00          4.00         4.00
         Long-Term Annual Rate of Return on Plan Assets (4) 7.00        6.50         8.50          7.00         8.50
</TABLE>

Notes:
1    The accumulated  benefit  obligations (the projected  benefit  obligation
     excluding  future  salary  increases) of the Nexen and Canexus plans were
     $161 million and $36 million at December 31, 2005, respectively.  Nexen's
     supplemental  pension  plan's  accumulated  benefit  obligation  was  $29
     million at December 31, 2005,  and  Canexus'  was nil.  Nexen's  share of
     Syncrude's employee pension plan's accumulated benefit obligation was $82
     million at December 31, 2005.
2    Includes  unfunded  obligations for  supplemental  benefits to the extent
     that the benefit is limited by  statutory  guidelines.  At  December  31,
     2005,  the  PBO  for  Nexen's  supplemental   benefits  was  $43  million
     (2004--$34 million) and $1 million for Canexus (2004--nil).
3    The  assumptions  have been used to calculate the recognized  expense for
     Nexen and Canexus.  There were no changes to the assumptions  between the
     measurement date and December 31, 2005.  Syncrude's  measurement date was
     December 31, 2005.
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.


                                      110
<PAGE>

NET PENSION EXPENSE RECOGNIZED UNDER OUR DEFINED BENEFIT PENSION PLANS

<TABLE>
<CAPTION>
                                                                            2005        2004        2003
---------------------------------------------------------------------------------------------------------
<S>                                                                   <C>         <C>         <C>
Nexen
    Cost of Benefits Earned by Employees                                      15           8           7
    Interest Cost on Benefits Earned                                          12          12          11
    Actual Return on Plan Assets                                             (18)        (16)        (15)
    Actuarial Losses                                                          33          10          14
---------------------------------------------------------------------------------------------------------
  Pension Expense Before Adjustments for the Long-Term Nature of
    Employee Future Benefit Costs                                             42          14          17
    Difference Between Actual and Expected Return                              8           5           7
    Difference Between Actual and Recognized Actuarial Losses                (32)        (10)        (15)
    Difference Between Actual and Recognized Past Service Costs                -           1           1
---------------------------------------------------------------------------------------------------------
  Net Pension Expense                                                         18          10          10
---------------------------------------------------------------------------------------------------------

Canexus
    Cost of Benefits Earned by Employees                                       1           -           -
    Interest Cost on Benefits Earned                                           1           -           -
    Actual Return on Plan Assets                                               -           -           -
    Actuarial Gains                                                           (2)          -           -
---------------------------------------------------------------------------------------------------------
  Pension Expense Before Adjustments for the Long-Term Nature of
    Employee Future Benefit Costs                                              -           -           -
    Difference Between Actual and Expected Return                             (1)          -           -
    Difference Between Actual and Recognized Actuarial Gains                   2           -           -
    Difference Between Actual and Recognized Past Service Costs                -           -           -
---------------------------------------------------------------------------------------------------------
  Net Pension Expense                                                          1           -           -
---------------------------------------------------------------------------------------------------------

Syncrude
    Cost of Benefits Earned by Employees                                       4           3           3
    Interest Cost on Benefits Earned                                           5           5           4
    Actual Return on Plan Assets                                              (6)         (5)         (7)
    Actuarial Losses                                                          11           7           6
---------------------------------------------------------------------------------------------------------
  Pension Expense Before Adjustments for the Long-Term Nature of
    Employee Future Benefit Costs                                             14          10           6
    Difference Between Actual and Expected Return                              2           1           4
    Difference Between Actual and Recognized Actuarial Losses                 (8)         (6)         (5)
    Difference Between Actual and Recognized Past Service Costs                -           -           -
---------------------------------------------------------------------------------------------------------
  Net Pension Expense                                                          8           5           5
---------------------------------------------------------------------------------------------------------

Total Net Pension Expense                                                     27          15          15
=========================================================================================================
</TABLE>

(b) PLAN ASSET ALLOCATION AT DECEMBER 31

Our investment  goal for the assets in our defined benefit pension plans 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  approved by the Board of
Directors and Pension  Committees  of Nexen and Canexus.  Nexen's and Canexus'
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. Allowable and prohibited investment types are also
prescribed in Nexen's investment policies.


                                      111
<PAGE>

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.

(%)                           Expected 2006             2005             2004
------------------------------------------------------------------------------
Nexen
  Equity Securities                      60               60               60
  Debt Securities                        40               40               40
  Real Estate                             -                -                -
  Other                                   -                -                -
------------------------------------------------------------------------------
Total                                   100              100              100
==============================================================================

Canexus
  Equity Securities                      60               60                -
  Debt Securities                        40               40                -
  Real Estate                             -                -                -
  Other                                   -                -                -
------------------------------------------------------------------------------
Total                                   100              100                -
==============================================================================

Syncrude
  Equity Securities                      70               70               70
  Debt Securities                        30               30               30
  Real Estate                             -                -                -
  Other                                   -                -                -
------------------------------------------------------------------------------
Total                                   100              100              100
==============================================================================

(c) DEFINED CONTRIBUTION PENSION PLANS

Under these plans,  pension benefits are based on plan  contributions.  During
2005,  Canadian  pension  expense  for these  plans was $4  million  (2004--$4
million;  2003--$4  million).  During 2005, US pension expense for these plans
was $4 million (2004--$3 million; 2003--$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 2005 was $4 million  (2004--$5
million)   and  $2  million  for  Canexus   (2004--nil).   Nexen's   share  of
post-retirement and  post-employment  benefits related to Syncrude in 2005 was
$5 million (2004--$7 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:

                                      Expected 2006         2005         2004
------------------------------------------------------------------------------
Defined Benefit Contributions
  Nexen                                          18            2            6
  Canexus                                         2            -            -
  Syncrude                                        5            4            4
------------------------------------------------------------------------------
Total Funding Contributions                      25            6           10
==============================================================================

Our most recent funding valuation was prepared as of August 17, 2005. Our next
funding  valuation is required by June 30, 2008.  Canexus' most recent funding
valuation was prepared as of August 17, 2005, and their next funding valuation
is required by December 31, 2007. Syncrude's most recent funding valuation was
prepared as of December 31, 2003, and their next funding valuation is December
31, 2006.


                                      112
<PAGE>

Our total  benefit  payments  in 2005  were $8  million  for  Nexen  (2004--$7
million)  and nil for  Canexus  (2004--nil).  Our  share of  Syncrude's  total
benefit  payments in 2005 was $3 million  (2004--$3  million).  Our  estimated
future payments are as follows:

<TABLE>
<CAPTION>
                                                  Define Benefit                              Other
-------------------------------------------------------------------------- ---------------------------------------
                                          Nexen      Canexus     Syncrude         Nexen      Canexus     Syncrude
-------------------------------------------------------------------------- ---------------------------------------
<S>                                 <C>          <C>          <C>           <C>          <C>          <C>
2006                                          8            -            3             1            -            -
2007                                          9            1            3             1            -            -
2008                                          9            1            4             2            -            -
2009                                         10            1            4             2            -            -
2010                                         11            1            4             2            -            -
2011-2015                                    66           13           28            14            -            2
</TABLE>

17. MARKETING AND OTHER

<TABLE>
<CAPTION>
                                                           2005         2004         2003
------------------------------------------------------------------------------------------


<S>                                                 <C>          <C>          <C>
Marketing Revenue, Net                                      847          608          568
Change in Fair Value of Crude Oil Put Options              (196)          56            -
Interest                                                     29           12            9
Foreign Exchange Gains (Losses)                             (19)         (13)           6
Gains on Disposition of Assets (1)                            4           24            -
Other (2)                                                    37           26           27
------------------------------------------------------------------------------------------
Total Marketing and Other                                   702          713          610
==========================================================================================
</TABLE>

Notes:
1    In 2005,  gains on disposition of assets  resulted from the sale of minor
     oil and gas assets by our Nigeria  oil and gas  business  (2004--sale  of
     minor oil and gas assets by our Canadian oil and gas business).
2    In 2005,  other  includes  $2 million  (2004--$10  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.

18. INCOME TAXES

(a) TEMPORARY DIFFERENCES

<TABLE>
<CAPTION>
                                                                 2005                               2004
----------------------------------------------------------------------------- ----------------------------------
                                                     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            1,785                31            1,852
Tax Losses Carried Forward                              370                -               277                -
Deferred Income                                           -              175                 -              171
Recoverable Taxes                                         9                -                25                -
----------------------------------------------------------------------------- ----------------------------------
Total                                                   410            1,960               333            2,023
============================================================================= ==================================
</TABLE>

(b) CANADIAN AND FOREIGN INCOME TAXES

<TABLE>
<CAPTION>
                                                                     2005         2004         2003
----------------------------------------------------------------------------------------------------
<S>                                                           <C>          <C>          <C>

Income from Continuing Operations before Income Taxes
  Canadian                                                           (387)          24         (352)
  Foreign                                                           1,334        1,003          956
----------------------------------------------------------------------------------------------------
                                                                      947        1,027          604
====================================================================================================

Provision for Income Taxes
  Current
    Canadian                                                            1            6            5
    Foreign                                                           338          242          209
----------------------------------------------------------------------------------------------------
                                                                      339          248          214
  Future
    Canadian                                                         (203)          (3)        (180)
    Foreign                                                           103           72           63
----------------------------------------------------------------------------------------------------
                                                                     (100)          69         (117)
----------------------------------------------------------------------------------------------------

Total Provision for Income Taxes                                      239          317           97
====================================================================================================
</TABLE>


                                      113
<PAGE>

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,  Colombia and the United  States and include Yemen cash taxes
of $296 million (2004--$227 million; 2003--$201 million).

(c) RECONCILIATION OF EFFECTIVE TAX RATE TO THE CANADIAN FEDERAL TAX RATE

<TABLE>
<CAPTION>
                                                                                         2005         2004         2003
------------------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>          <C>          <C>
Income before Income Taxes From Continuing Operations                                     947        1,027          604
------------------------------------------------------------------------------------------------------------------------

Provision for Income Taxes Computed at the Canadian Statutory Rate                        324          354          224
Add (Deduct) the Tax Effect of:
  Royalties and Rentals to Provincial Governments                                          24           20           20
  Resource Allowance and Provincial Tax Rebates                                           (24)         (29)         (35)
  Lower Tax Rates on Foreign Operations                                                   (40)         (22)         (48)
  Additional Canadian Tax on Canadian Resource Income                                       6            7            8
  Lower Tax Rates on Capital Gains                                                        (54)           -            -
  Federal and Provincial Capital Tax                                                        5            6            4
  Revaluation of Future Income Tax Liabilities for Reductions in Statutory Rates            -          (15)         (76)
  Other                                                                                    (2)          (4)           -
------------------------------------------------------------------------------------------------------------------------
Provision for Income Taxes                                                                239          317           97
------------------------------------------------------------------------------------------------------------------------
</TABLE>

In 2004 and  2003,  the  federal  and some  provincial  governments  in Canada
reduced  statutory income tax rates.  This reduced our liability and provision
for  future  income  taxes by $15  million  and $76  million in 2004 and 2003,
respectively.

(d) AVAILABLE UNUSED TAX LOSSES AND TAX CONTINGENCIES

At December 31, 2005 and 2004, we had unused tax losses totalling $965 million
and $702 million, respectively, mostly from our UK operations.

Nexen's income tax filings are subject to audit by taxation authorities. There
are audits in progress and items under review,  some of which 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.

19. CASH FLOWS

(a) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH

<TABLE>
<CAPTION>
                                                                       2005         2004         2003
------------------------------------------------------------------------------------------------------
<S>                                                             <C>          <C>          <C>
Depreciation, Depletion, Amortization and Impairment                  1,052          674          914
Stock Based Compensation                                                411           74            4
Gains on Disposition of Assets                                           (4)         (24)           -
Future Income Taxes                                                    (100)          69         (117)
Change in Fair Value of Crude Oil Put Options                           196          (56)           -
Non-Cash Items included in Discontinued Operations                     (325)         132          191
Unamortized Issue Costs on Preferred Securities Redemption                -           11           28
Gain on Dilution of Interest in Chemicals Business                     (193)           -            -
Net Income Attributable to Non-Controlling Interests                      8            -            -
Other                                                                    24           26            4
------------------------------------------------------------------------------------------------------
Total                                                                 1,069          906        1,024
======================================================================================================
</TABLE>


                                      114
<PAGE>

(b) CHANGES IN NON-CASH WORKING CAPITAL

<TABLE>
<CAPTION>
                                                    2005         2004         2003
-----------------------------------------------------------------------------------


<S>                                          <C>          <C>          <C>
Accounts Receivable                               (1,078)        (454)        (488)
Inventories and Supplies                            (163)        (106)         (45)
Other Current Assets                                 (10)          44          (59)
Accounts Payable and Accrued Liabilities             982          650          242
Other                                                 20          (12)          12
-----------------------------------------------------------------------------------
Total                                               (249)         122         (338)
===================================================================================

Relating to:
  Operating Activities                              (195)        (122)        (320)
  Investing Activities                               (54)         244          (18)
-----------------------------------------------------------------------------------
Total                                               (249)         122         (338)
===================================================================================
</TABLE>

(c) OTHER CASH FLOW INFORMATION

<TABLE>
<CAPTION>
                                                 2005         2004         2003
--------------------------------------------------------------------------------
<S>                                       <C>          <C>          <C>
Interest Paid                                     237          190          197
Income Taxes Paid                                 325          249          211
</TABLE>

In 2004,  other operating  activity cash outflows include $144 million for the
purchase of crude oil put options.

20. 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 in
West Africa and 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.

CHEMICALS:  Through our  investment  in Canexus,  we  manufacture,  market and
distribute industrial chemicals,  principally sodium chlorate,  chlorine, acid
and caustic soda. We produce sodium  chlorate at four facilities in Canada and
one in  Brazil.  We  produce  chlorine,  caustic  soda  and  muriatic  acid 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 with the  exception  of  Chemicals.  Identifiable  assets are
those used in the operations of the segments.


                                      115
<PAGE>

2005 OPERATING AND GEOGRAPHIC SEGMENTS

<TABLE>
<CAPTION>
                                                                                                                   Corporate
                                                    Oil and Gas                           Syncrude (1) Chemicals   and Other Total
-------------------------------------------------------------------------------------- --------------------------------------------
                                                                    Other
(Cdn$ millions)                  Yemen  Canada(2)   US     UK   Countries(3) Marketing
-------------------------------------------------------------------------------------- --------------------------------------------
<S>                             <C>      <C>        <C>    <C>   <C>         <C>          <C>          <C>         <C>       <C>
Net Sales (4)                    1,377     455      792    366      119          28         397          398 (5)       -     3,932
Marketing and Other                  8       3        2     16        4         847           -           15        (193)(6)   702
Gain on Dilution of Interest
in Chemicals Business
                                     -       -        -      -        -           -           -          193           -       193
-------------------------------------------------------------------------------------- --------------------------------------------
                                 1,385     458      794    382      123         875         397          606        (193)    4,827
Less: Expenses
  Operating                        150     121       96     95       12          30         152          237           -       893
  Depreciation, Depletion,
   Amortization and
   Impairment                      354     140      234    210       13          11          17           51 (7)      22     1,052
  Transportation and Other           6      23        1      -        2         641          21           40          62       796
  General and Administrative (8)    42     105       84      8       97          89           1           45         321       792
  Exploration                       12      23      100     51       64(9)        -           -            -           -       250
  Interest                           -       -        -      -        -           -           -            3          94        97
-------------------------------------------------------------------------------------- --------------------------------------------
Income (Loss) from
  Continuing Operations
  before Income Taxes              821      46      279     18      (65)        104         206          230        (692)      947
Less: Provision for
  (Recovery of) Income Taxes (10)  285      14       99      7      (12)         41          60           15        (270)      239
-------------------------------------------------------------------------------------- --------------------------------------------
Net Income (Loss) from
  Continuing Operations            536      32      180     11      (53)         63         146          215        (422)      708
Less: Non-Controlling
  Interests                          -       -        -      -        -           -           -            8           -         8
Add: Net Income from
  Discontinued Operations            -     452        -      -        -           -           -            -           -       452
-------------------------------------------------------------------------------------- --------------------------------------------
Net Income (Loss)                  536     484      180     11      (53)         63         146          207        (422)    1,152
====================================================================================== ============================================

Identifiable Assets                635   2,449    1,433  4,775      183       3,165(11)   1,135          482         333    14,590
====================================================================================== ============================================

Capital Expenditures
  Development and Other            236     947      148    566       14          16         197           14          24     2,162
  Exploration                       41      90      211     59       55           -           -            -           -       456
  Proved Property Acquisitions       -      17        3      -        -           -           -            -           -        20
--------------------------------------------------------------------------------------- -------------------------------------------
Total Capital Expenditures         277   1,054      362    625       69          16         197           14          24     2,638
======================================================================================= ===========================================

Property, Plant and
  Equipment Cost                 2,243   3,631    2,437  4,013      249         177       1,240          827         245    15,062
  Less: Accumulated DD&A         1,841   1,311    1,159    216      119          72         171          456         123     5,468
--------------------------------------------------------------------------------------- -------------------------------------------
Net Book Value (4)                 402   2,320    1,278  3,797      130         105       1,069          371         122     9,594
======================================================================================= ===========================================

Goodwill
  Cost                               -       -        -    325        -          63           -            -           -       388
  Less: Accumulated DD&A             -       -        -      -        -          24           -            -           -        24
--------------------------------------------------------------------------------------- -------------------------------------------
Net Book Value                       -       -        -    325        -          39           -            -           -       364
======================================================================================= ===========================================
<CAPTION>
<S>  <C>
Notes:
1    Syncrude is considered a mining operation for US reporting purposes. PP&E at December 31, 2005 includes mineral rights of $6
     million.
2    During the third quarter of 2005, we concluded the sale of certain Canadian conventional oil and gas properties. The results
     of these properties are shown as discontinued operations (see Note 14).
3    Includes results of operations from producing activities in Nigeria and Colombia.
4    Net sales made from all segments originating in Canada:        1,014
     PP&E located in Canada:                                        3,899
5    Net sales for our chemicals operations include:
       Canada           132
       United States    198
       Brazil            68
       Total            398
6    Includes interest income of $29 million, foreign exchange losses of $19 million, decrease in the fair value of crude oil put
     options of $196 million and decrease in the fair value of foreign currency call options of $7 million.
7    Includes impairment charge of $12 million related to the closure of our sodium chlorate plant in Amherstburg, Ontario.
8    Includes stock-based compensation expense of $490 million.
9    Includes exploration activities primarily in Nigeria, Colombia and Equatorial Guinea.
10   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.
11   Approximately 86% of Marketing's identifiable assets are accounts receivable and inventories.
</TABLE>

                                      116
<PAGE>

2004 OPERATING AND GEOGRAPHIC SEGMENTS

<TABLE>
<CAPTION>
                                                                                                                  Corporate
                                                        Oil and Gas                        Syncrude(1) Chemicals  and Other  Total
------------------------------------------------------------------------------------------ ----------------------------------------
                                                                        Other
(Cdn$ millions)                  Yemen   Canada        US     UK(2) Countries(3) Marketing
------------------------------------------------------------------------------------------ ----------------------------------------
<S>                             <C>      <C>          <C>      <C>    <C>        <C>        <C>         <C>        <C>       <C>
Net Sales (4)                      921      390       811      36        73            14       321       378(5)       -     2,944
Marketing and Other                  5       27        11       -         2           608         -         5         55(6)    713
------------------------------------------------------------------------------------------ ----------------------------------------
                                   926      417       822      36        75           622       321       383         55     3,657
Less: Expenses
  Operating                        109      116       106       6         7            16       125       237          -       722
  Depreciation, Depletion,
   Amortization and Impairment     169      128       258      18        18            10        18        37         18       674
  Transportation and Other           5       15         -       -         -           451        12        41         25       549
  General and Administrative         4       42        30       -        47            58         1        28         89       299
  Exploration                        2       18       138       3        82(7)          -         -         -          -       243
  Interest                           -        -         -       -         -             -         -         -        143       143
------------------------------------------------------------------------------------------ ----------------------------------------
Income (Loss) from
  Continuing Operations
  before Income Taxes              637       98       290       9       (79)           87       165        40       (220)    1,027
Less: Provision for (Recovery of)
  Income Taxes (8)                 222       28       104       4         1            28        47        13       (130)      317
------------------------------------------------------------------------------------------ ----------------------------------------
Net Income (Loss) from
  Continuing Operations            415       70       186       5       (80)           59       118        27        (90)      710
Add: Net Income from
  Discontinued Operations (9)        -       70         -       -        13             -         -         -          -        83
------------------------------------------------------------------------------------------ ----------------------------------------
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    2,603     2,249   3,499       535           157     1,030       815        201    13,127
  Less: Accumulated DD&A         1,550    1,195     1,037      16       408            64       155       409         90     4,924
------------------------------------------------------------------------------------------ ----------------------------------------
Net Book Value (4)                 488    1,408(11) 1,212   3,483       127            93       875       406        111     8,203
========================================================================================== ========================================

Goodwill
  Cost                               -        -        -     339          -            60         -         -          -       399
  Less: Accumulated DD&A             -        -        -       -          -            24         -         -          -        24
------------------------------------------------------------------------------------------ ----------------------------------------
Net Book Value                       -        -        -     339          -            36         -         -          -       375
========================================================================================== ========================================
<CAPTION>
<S>  <C>
Notes:
1    Syncrude is considered a mining operation for US reporting purposes. PP&E at December 31, 2004 includes mineral rights of $6
     million.
2    On December 1, 2004 we acquired EnCana (UK) Limited (see Note 3).
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
     PP&E located in Canada:                                        3,198
5    Net sales for our chemicals operations include:
       Canada           135
       United States    184
       Brazil            59
       Total            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. During the third quarter of 2005, we
     concluded the sale of certain Canadian conventional oil and gas properties. The combined results of these dispositions are
     shown as discontinued operations (see Note 14).
10   Approximately 81% of Marketing's identifiable assets are accounts receivable and inventories.
11   Excludes PP&E costs of $860 million and accumulated DD&A of $420 million relating to the Canadian properties disposed of
     during 2005 (see Note 14).
</TABLE>

                                      117
<PAGE>

2003 OPERATING AND GEOGRAPHIC SEGMENTS

<TABLE>
<CAPTION>
                                                                                                                 Corporate
                                                     Oil and Gas                         Syncrude(1)  Chemicals  and Other  Total
--------------------------------------------------------------------------------------- ------------------------------------------
                                                                  Other
(Cdn$ millions)                  Yemen   Canada        US  Countries(2)     Marketing(3)
--------------------------------------------------------------------------------------- ------------------------------------------
<S>                               <C>    <C>          <C>   <C>             <C>           <C>          <C>        <C>       <C>
Net Sales (4)                      827      397       707         65               21        240       375(5)       -       2,632
Marketing and Other                  6        5        14          -              568          -         2         15(6)      610
--------------------------------------------------------------------------------------- ------------------------------------------
                                   833      402       721         65              589        240       377         15       3,242
Less: Expenses
  Operating                         92      110        86         15               22        123       240          -         688
  Depreciation, Depletion,
   Amortization and Impairment     168      409(7)    207         38               15         14        46         17         914
  Transportation and Other           5        4         -          -              398         11        42         29         489
  General and Administrative         5       22        13         20               43          1        21         60         185
  Exploration                       17       28        89         59(8)             -          -         -          -         193
  Interest                           -        -         -          -                -          -         -        169         169
--------------------------------------------------------------------------------------- ------------------------------------------
Income (Loss) from Continuing
  Operations before Income Taxes   546     (171)      326        (67)             111         91        28       (260)        604
Less: Provision for (Recovery of)
  Income Taxes (9)                 191     (140)      115         (1)              39         25        10       (142)         97
Net Income (Loss) from
  Continuing Operations            355      (31)      211        (66)              72         66        18       (118)        507
Add: Net Income from
  Discontinued Operations            -       58(10)     -         13(11)            -          -         -          -          71
--------------------------------------------------------------------------------------- ------------------------------------------
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    2,169     2,153        534              158        821       774        168       8,675
  Less: Accumulated DD&A         1,497    1,106       887        410               57        144       381         71       4,553
--------------------------------------------------------------------------------------- ------------------------------------------
Net Book Value (4)                 401    1,063(14) 1,266        124              101        677       393         97       4,122
======================================================================================= ==========================================

Goodwill
  Cost                               -        -         -          -               60          -         -          -          60
  Less: Accumulated DD&A             -        -         -          -               24          -         -          -          24
--------------------------------------------------------------------------------------- ------------------------------------------
Net Book Value                       -        -         -          -               36          -         -          -          36
======================================================================================= ==========================================
<CAPTION>
<S>  <C>
Notes:
1    Syncrude is considered a mining operation for US reporting purposes. PP&E 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.
4    Net sales made from all segments originating in Canada:        1,218
     PP&E located in Canada:                                        2,566
5    Net sales for our chemicals operations include:
       Canada           142
       United States    179
       Brazil            54
       Total            375
6    Includes interest income of $9 million and foreign exchange gains of $6 million.
7    Includes impairment charge of $269 million (see Note 6).
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. During the third quarter of 2005, we concluded the sale of certain Canadian
     conventional oil and gas properties. The combined results of these dispositions are shown as discontinued operations (see
     Note 14).
11   In the fourth quarter of 2004, we concluded production activities in Australia. These results are shown as discontinued
     operations (see Note 14).
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.
14   Excludes PP&E costs of $782 million and accumulated DD&A of $354 million relating to the Canadian properties disposed of
     during 2005 (see Note 14).
</TABLE>

                                      118
<PAGE>

21.  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:

CONSOLIDATED STATEMENT OF INCOME--US GAAP FOR THE THREE YEARS ENDED DECEMBER 31,
2005

<TABLE>
<CAPTION>
(Cdn$ millions, except per share amounts)                                             2005         2004         2003
---------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>          <C>          <C>
Revenues and Other Income
  Net Sales                                                                          3,932        2,944        2,632
  Marketing and Other (ii); (ix); (x)                                                  687          696          623
  Gain on Dilution of Interest in Chemicals Business                                   193            -            -
---------------------------------------------------------------------------------------------------------------------
                                                                                     4,812        3,640        3,255
Expenses
  Operating (iv)                                                                       903          731          694
  Depreciation, Depletion, Amortization and Impairment (i)                           1,081          716        1,027
  Transportation and Other (ix)                                                        792          524          489
  General and Administrative (viii)                                                    792          263          185
  Exploration                                                                          250          243          193
  Interest                                                                              97          143          169
---------------------------------------------------------------------------------------------------------------------
                                                                                     3,915        2,620        2,757

---------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Income Taxes                                  897        1,020          498

Provision for Income Taxes
  Current                                                                              339          248          214
  Deferred (i) - (x)                                                                  (108)          67         (135)
---------------------------------------------------------------------------------------------------------------------
                                                                                       231          315           79

---------------------------------------------------------------------------------------------------------------------
Net Income from Continuing Operations before Non-Controlling Interests                 666          705          419
  Net Income Attributable to Non-Controlling Interests                                   8            -            -
---------------------------------------------------------------------------------------------------------------------
Net Income from Continuing Operations before Cumulative Effect of Changes in
  Accounting Principles                                                                658          705          419
  Net Income from Discontinued Operations (i)                                          452           83           49
  Cumulative Effect of Changes in Accounting Principles,
    Net of Income Taxes (vii); (x)                                                       -            -          (48)
---------------------------------------------------------------------------------------------------------------------


Net Income--US GAAP (1)                                                              1,110          788          420
=====================================================================================================================

Earnings Per Common Share ($/share)
  Basic (Note 13)
    Net Income from Continuing Operations                                             2.52         2.74         1.69
    Net Income from Discontinued Operations                                           1.74         0.32         0.20
    Cumulative Effect of Changes in Accounting Principles                                -            -        (0.19)
---------------------------------------------------------------------------------------------------------------------
                                                                                      4.26         3.06         1.70
=====================================================================================================================

  Diluted (Note 13)
    Net Income from Continuing Operations                                             2.47         2.71         1.68
    Net Income from Discontinued Operations                                           1.70         0.32         0.19
    Cumulative Effect of Changes in Accounting Principles                                -            -        (0.19)
---------------------------------------------------------------------------------------------------------------------
                                                                                      4.17         3.03         1.68
=====================================================================================================================
</TABLE>

Note:
1    Reconciliation of Canadian and US GAAP Net Income
<TABLE>
<CAPTION>
                                                                                     2005         2004         2003
     ---------------------------------------------------------------------------------------------------------------
<S>                                                                           <C>          <C>          <C>

     Net Income--Canadian GAAP                                                      1,152          793          578
       Impact of US Principles, Net of Income Taxes:
       Fair Value of Preferred Securities (x)                                           -            4            7
       Depreciation, Depletion, Amortization and Impairment (i); (vii)                (29)         (42)         (92)
       Stock Based Compensation Included in Retained Earnings (viii)                    -           36            -
       Loss on Disposition (i)                                                          -            -          (22)
       Other (ii); (iv)                                                               (13)          (3)          (3)
       Cumulative Effect of Changes in Accounting Principles (vii); (x)                 -            -          (48)
     ---------------------------------------------------------------------------------------------------------------
     Net Income--US GAAP                                                            1,110          788          420
     ===============================================================================================================
</TABLE>


                                      119
<PAGE>

CONSOLIDATED BALANCE SHEET--US GAAP

<TABLE>
<CAPTION>
(Cdn$ millions, except share amounts)                                  December 31, 2005    December 31, 2004
--------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>                  <C>
ASSETS
  Current Assets
    Cash and Cash Equivalents                                                         48                   73
    Restricted Cash                                                                   70                    -
    Accounts Receivable (ii)                                                       3,151                2,106
    Inventories and Supplies                                                         504                  351
    Assets of Discontinued Operations                                                  -                   38
    Other                                                                             51                   41
--------------------------------------------------------------------------------------------------------------
      Total Current Assets                                                         3,824                2,609

Property, Plant and Equipment
  Net of Accumulated Depreciation, Depletion, Amortization and
    Impairment of $5,861 (December 31, 2004--$5,290) (i); (iv); (vii)              9,550                8,198
  Goodwill                                                                           364                  375
  Deferred Income Tax Assets                                                         410                  333
  Deferred Charges and Other Assets (v)                                              345                  384
  Assets of Discontinued Operations                                                    -                  440
--------------------------------------------------------------------------------------------------------------

TOTAL ASSETS                                                                      14,493               12,339
==============================================================================================================

LIABILITIES AND SHAREHOLDERS' EQUITY
  Current Liabilities
    Short-Term Borrowings                                                              -                  100
    Accounts Payable and Accrued Liabilities (ii)                                  3,745                2,377
    Accrued Interest Payable                                                          55                   34
    Dividends Payable                                                                 13                   13
    Liabilities of Discontinued Operations                                             -                   39
--------------------------------------------------------------------------------------------------------------
      Total Current Liabilities                                                    3,813                2,563

  Long-Term Debt (v)                                                               3,630                4,214
  Deferred Income Tax Liabilities (i) - (x)                                        1,906                1,993
  Asset Retirement Obligations (vii)                                                 590                  399
  Deferred Credits and Other Liabilities (vi)                                        505                  148
  Liabilities of Discontinued Operations                                               -                  130
  Non-Controlling Interests                                                           88                    -
  Shareholders' Equity
    Common Shares, no par value
      Authorized:     Unlimited
      Outstanding:    2005--261,140,571 shares
                      2004--258,399,166 shares                                       732                  637
    Contributed Surplus                                                                2                    -
    Retained Earnings (i) - (x)                                                    3,418                2,360
    Accumulated Other Comprehensive Income (ii); (iii); (vi)                        (191)                (105)
--------------------------------------------------------------------------------------------------------------
      Total Shareholders' Equity                                                   3,961                2,892
  Commitments, Contingencies and Guarantees
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                                        14,493               12,339
==============================================================================================================
</TABLE>


                                      120
<PAGE>

CONSOLIDATED  STATEMENT OF  COMPREHENSIVE  INCOME--US GAAP FOR THE THREE YEARS
ENDED DECEMBER 31, 2005

<TABLE>
<CAPTION>
(Cdn$ millions)                                             2005       2004        2003
----------------------------------------------------------------------------------------
<S>                                                        <C>         <C>         <C>
Net Income--US GAAP                                        1,110        788         420
  Other Comprehensive Income, Net of Income Taxes:
  Translation Adjustment (iii)                               (56)       (72)       (127)
  Unrealized Mark-to-Market Gain (Loss) (ii)                 (20)        11          (7)
  Minimum Unfunded Pension Liability (vi)                    (10)        (1)         (1)
----------------------------------------------------------------------------------------
Comprehensive Income                                       1,024        726         285
========================================================================================
</TABLE>

CONSOLIDATED STATEMENT OF CASH FLOWS

Under  US  GAAP,  geological  and  geophysical  costs  in 2003 of $62  million
included in investing  activities  would be reported in operating  activities.
See Note 1(u) to our Consolidated Financial Statements.

NOTES TO THE CONSOLIDATED US GAAP FINANCIAL STATEMENTS:

i.   Under US GAAP,  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 PP&E rather than a
charge to retained earnings. As a result:

o    additional depreciation,  depletion,  amortization and impairment of $29
     million  (2004--$42  million;  2003--$92  million)  was  included  in net
     income; and
o    PP&E is higher under US GAAP at December 31, 2004 by $29 million.

During the third quarter of 2003,  some of these assets were sold as described
in Note 14. 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 previously described.

ii.  Under US GAAP, 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 net income 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 forward contracts we used to hedge
commodity  price risk on the future sale of a portion of our  production  from
the Aspen field.  These contracts  expired in March 2004.  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.


                                      121
<PAGE>

Future sale of gas  inventory:  Included in accounts  payable at December  31,
2003, was $11 million of losses on futures and basis swap contracts we used to
hedge  commodity  price risk on the future  sale of our gas  inventory.  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.

Included in accounts receivable at December 31, 2004, were $6 million of gains
on futures  contracts and swaps we used to hedge  commodity  price risk on the
future  sale of our gas  inventory  as  described  in Note 7. These  contracts
effectively lock-in profits on our stored gas volumes. Gains of $6 million ($4
million, net of income taxes) related to the effective portion and deferred in
AOCI at December 31, 2004,  were  recognized in marketing and other during the
first quarter of 2005.

At December 31, 2005,  losses of $35 million were included in accounts payable
with respect to futures  contracts and swaps we used to hedge  commodity price
risk on the future sale of our gas inventory as described in Note 7. Losses of
$24  million  ($16  million,  net of income  taxes)  related to the  effective
portion have been deferred in AOCI until the underlying gas inventory is sold.
These  losses will be  reclassified  to marketing  and other as the  contracts
settle over the next 12 months.  The ineffective  portion of the losses of $11
million ($7 million,  net of income taxes) was recognized in net income during
the year.

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 net income.  At December 31, 2005, we had no fair value hedges in
place.

iii. Under US GAAP,  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.

iv.  Under  Canadian  GAAP,  we  defer  certain   development  costs  and  all
pre-operating revenues and costs to PP&E. Under US GAAP, these costs have been
included in operating expenses. As a result:

o    operating  expenses  include  pre-operating  costs  of  $10  million  ($6
     million, net of income taxes) (2004--$9 million ($6 million net of income
     taxes); 2003--$4 million ($2 million, net of income taxes)); and
o    PP&E is  lower  under  US GAAP by $25  million  (December  31,  2004--$15
     million).

v.   Under US GAAP,  discounts on long-term debt are classified as a reduction
of long-term debt rather than as deferred charges and other assets.  Discounts
of $57  million  (December  31,  2004--$45  million)  have  been  included  in
long-term debt.

vi.  Under US GAAP, the amount by which our accrued  pension cost is less than
the unfunded  accumulated  benefit  obligation is included in AOCI and accrued
pension liabilities.  As a result,  deferred credits and other liabilities are
higher by $26 million (2004--$6 million) and deferred charges and other assets
are higher by $4 million (2004--nil).  In 2005, AOCI decreased by $10 million,
net of $6 million 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. These standards are consistent, except for the adoption date,
which resulted in our PP&E 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 12(c),  our existing stock option plan was modified
to a tandem option plan in 2004.  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 proforma expense previously disclosed for the
stock options modified. The related proforma 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.


                                      122
<PAGE>

ix.  Under US GAAP, gains and losses on the disposition of assets are shown as
other  expense.  Gains of $4  million  (2004--$24  million;  2003--$nil)  were
reclassed from marketing and other to transportation and other.

x.   In May 2003,  the 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>
(Cdn$ millions)                                                       Gain (Loss)      Tax     Net Gain (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.

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 fiscal years 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.
Upon  implementing  the new rules,  we expect to record an expense for US GAAP
purposes of $3 million ($2  million net of income  taxes) in 2006,  reflecting
the cumulative effect of the change in accounting policy.

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 operations
or financial position.


                                      123
<PAGE>

In March 2005, the FASB issued  Financial  Interpretation  47,  Accounting for
Conditional  Asset Retirement  Obligations (FIN 47). FIN 47 clarifies that the
term  conditional  asset  retirement  obligation as used in FASB Statement No.
143, Accounting for Asset Retirement Obligations, refers to a legal obligation
to perform an asset retirement activity in which the timing and (or) method of
settlement are conditional on a future event that may or may not be within the
control of the entity. The obligation to perform the asset retirement activity
is unconditional even though uncertainty exists about the timing and/or method
of settlement. Thus, the timing and/or method of settlement may be conditional
on a future event. Accordingly, an entity is required to recognize a liability
for the fair value of a conditional  asset  retirement  obligation if the fair
value of the liability can be reasonably estimated. FIN 47 also clarifies when
an entity would have  sufficient  information to reasonably  estimate the fair
value of an asset retirement obligation. FIN 47 is effective no later than the
end of fiscal  years ending  after  December  15,  2005.  The adoption of this
statement  has not had a  material  impact on our  results  of  operations  or
financial position.

In March 2005,  the Emerging  Issues Task Force (EITF)  reached a consensus on
Issue No. 04-6,  Accounting for Stripping Costs Incurred during  Production in
the Mining  Industry.  In the mining  industry,  companies  may be required to
remove  overburden and other mine waste materials to access mineral  deposits.
The EITF concluded that the costs of removing  overburden and waste materials,
often referred to as "stripping  costs",  incurred during the production phase
of a mine are variable  production  costs that should be included in the costs
of the  inventory  produced  during the period  that the  stripping  costs are
incurred. Issue No. 04-6 is effective for the first reporting period in fiscal
years beginning after December 15, 2005, with early adoption permitted.  We do
not expect the adoption of this statement  will have a material  impact on our
results of operations or financial position.

In June 2005,  the FASB issued  Statement  154,  Accounting  Changes and Error
Corrections  which replaces APB Opinion 20 and FASB Statement 3. Statement 154
changes the  requirements  for the  accounting  and  reporting  of a change in
accounting  principle.  Opinion 20  previously  required  that most  voluntary
changes in accounting  principles  be  recognized by including the  cumulative
effect of the new  accounting  principle  in net  income of the  period of the
change. In the absence of explicit  transition  provisions provided for in new
or   existing   accounting   pronouncements,   Statement   154  now   requires
retrospective  application of changes in accounting  principle to prior period
financial  statements,  unless it is  impracticable to do so. The Statement is
effective for fiscal years beginning after December 15, 2005. We do not expect
the adoption of this statement  will have a material  impact on our results of
operations or financial position.

In September 2005, the EITF reached a consensus on Issue No. 04-13, Accounting
for Purchases and Sales of Inventory  with the Same  Counterparty.  This issue
addresses the question of when it is appropriate to measure purchase and sales
of  inventory  at fair value and record them in cost of sales and revenues and
when they should be recorded  as  exchanges  measured at the book value of the
item sold.  The EITF  concluded that purchases and sales of inventory with the
same counterparty that are entered into in contemplation of one another should
be combined and  recorded as exchanges  measured at the book value of the item
sold. The consensus  should be applied to new  arrangements  entered into, and
modifications  or renewals of existing  agreements,  beginning with the second
quarter of 2006. We do not expect the adoption of this  statement  will have a
material impact on our results of operations or financial position.


                                      124
<PAGE>

SUPPLEMENTARY DATA (UNAUDITED)

QUARTERLY FINANCIAL DATA IN ACCORDANCE WITH CANADIAN AND US GAAP

<TABLE>
<CAPTION>
                                                                                Quarter Ended
----------------------------------------------------------------- --------------------- --------------------- ---------------------
                                                    March 31            June 30            September 30          December 31
----------------------------------------------------------------- --------------------- --------------------- ---------------------
(Cdn$ millions)                                 2005        2004      2005        2004      2005        2004      2005        2004
----------------------------------------------------------------- --------------------- --------------------- ---------------------
<S>                                             <C>         <C>       <C>         <C>       <C>         <C>       <C>         <C>
Net Sales (1)                                    856         664       909         697     1,094         778     1,073         805

Operating Profit is Comprised of: (1,2,3,4,5)
  Oil and Gas                                    282         243       250         199       173         296       498         304
  Syncrude                                        19          40        59          40        78          52        50          33
  Chemicals                                        7          10        (2)          6       215          11        10          13
----------------------------------------------------------------- --------------------- --------------------- ---------------------
                                                 308         293       307         245       466         359       558         350
================================================================= ===================== ===================== =====================

Net Income from Continuing
  Operations--Canadian GAAP (6)                   19         167       170         117       211         200       300         226
US GAAP Adjustments                              (11)        (20)      (12)         39       (15)        (12)       (4)        (12)
----------------------------------------------------------------- --------------------- --------------------- ---------------------
Net Income from Continuing
  Operations--US GAAP                              8         147       158         156       196         188       296         214
================================================================= ===================== ===================== =====================

Net Income--Canadian GAAP                         37         184       200         143       615         220       300         246
US GAAP Adjustments                              (11)        (20)      (12)         39       (15)        (12)       (4)        (12)
----------------------------------------------------------------- --------------------- --------------------- ---------------------
Net Income--US GAAP                               26         164       188         182       600         208       296         234
================================================================= ===================== ===================== =====================

Earnings per Common Share from
  Continuing Operations ($/share)
    Canadian GAAP--Basic                        0.08        0.66      0.65        0.45      0.81        0.77      1.15        0.87
    Canadian GAAP--Diluted                      0.08        0.66      0.64        0.44      0.79        0.76      1.12        0.86
    US GAAP--Basic                              0.03        0.58      0.61        0.61      0.75        0.73      1.13        0.82
    US GAAP--Diluted                            0.03        0.57      0.60        0.60      0.73        0.72      1.11        0.82
----------------------------------------------------------------- --------------------- --------------------- ---------------------

Earnings per Common Share ($/share)
    Canadian GAAP--Basic                        0.15        0.73      0.77        0.55      2.36        0.85      1.15        0.95
    Canadian GAAP--Diluted                      0.15        0.72      0.76        0.54      2.30        0.84      1.12        0.94
    US GAAP--Basic                              0.10        0.64      0.72        0.71      2.31        0.81      1.13        0.90
    US GAAP--Diluted                            0.10        0.63      0.71        0.70      2.25        0.80      1.11        0.89
----------------------------------------------------------------- --------------------- --------------------- ---------------------

Dividends Declared (7)                          0.05        0.05      0.05        0.05      0.05        0.05      0.05        0.05
----------------------------------------------------------------- --------------------- --------------------- ---------------------

Common Share Prices ($/share)
----------------------------------------------------------------- --------------------- --------------------- ---------------------
  Toronto Stock Exchange--High                 35.50       26.68     39.85       28.25     60.67       26.85     59.54       29.33
  Toronto Stock Exchange--Low                  23.55       22.50     29.53       23.40     40.25       22.17     43.77       24.09
  New York Stock Exchange--High (US$)          29.18       20.31     32.32       21.15     51.73       21.07     51.69       23.28
  New York Stock Exchange--Low (US$)           19.44       17.05     23.28       17.25     31.95       16.94     36.80       19.60

<CAPTION>
<S>  <C>
Notes:
1    Excludes results of certain Canadian conventional oil and gas properties sold in the third quarter of 2005 in southeast
     Saskatchewan, northwest Saskatchewan, northeast British Columbia and the Alberta foothills, the 2003 sale of non-core
     conventional light oil assets in southeast Saskatchewan and conclusion of production from our Buffalo field, offshore
     Australia in 2004. These results are shown as discontinued operations (see Note 14 to the Consolidated Financial
     Statements).
2    Plant turnarounds and coker maintenance at Syncrude in the fourth quarter of 2004 and first quarter of 2005 increased
     operating costs and temporarily reduced production volumes.
3    In 2004, a gain of $24 million was recorded on the sale of minor assets by our Canadian oil and gas business.
4    Chemicals operating profit includes a dilution gain of $193 million in the third quarter of 2005 as the result of the
     Canexus initial public offering.
5    Operating profit is defined as income (loss) from continuing operations before income taxes.
6    Includes the impact of changes in accounting policies as described in Note 1(u) to the Consolidated Financial Statements.
7    In February 2006, the Board of Directors declared a regular quarterly dividend of $0.05 per common share, payable April 1,
     2006, to shareholders of record on March 10, 2006.
8    At December 31, 2005, there were 1,294 registered holders of common shares and 261,140,571 common shares outstanding.
</TABLE>


                                      125
<PAGE>

OIL AND GAS PRODUCING ACTIVITIES AND SYNCRUDE OPERATIONS (UNAUDITED)

The following oil and gas  information is provided in accordance with the FASB
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 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>
                                                                                                             United        Other
                                        Total       Yemen (1)              Canada          United States    Kingdom     Countries(3)
------------------------------------------------- ----------- --------------------------- -------------- -------------- ----------
Conventional oil and bitumen are in
mmbbls and natural gas is in bcf     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, 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
------------------------------------------------- ----------- --------------------------- -------------- -------------- ----------

  Extensions and Discoveries          15     111        5         4      47          -        1      57      5       7          -
  Purchases of Reserves in Place       2       -        -         2       -          -        -       -      -       -          -
  Sales of Reserves in Place         (28)    (80)       -       (28)    (80)         -        -       -      -       -          -
  Revisions of Previous Estimates      9     (18)      (3)        2       3          -       (5)    (21)    15       -          -
  Production                         (45)    (81)     (23)       (9)    (37)         -       (7)    (36)    (5)     (8)        (1)
------------------------------------------------- ----------- --------------------------- -------------- -------------- ----------
December 31, 2005                    304     532       59        50     305          -       41     215    143      12         11
------------------------------------------------- ----------- --------------------------- -------------- -------------- ----------

Proved Developed Reserves (5)
  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
------------------------------------------------- ----------- --------------------------- -------------- -------------- ----------
  December 31, 2005                  154     438       46        44     275          -       37     161     17       2         10
------------------------------------------------- ----------- --------------------------- -------------- -------------- ----------
<CAPTION>
<S>  <C>
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 its 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)
     as the barrels necessary to achieve cost recovery change with prevailing oil prices. Production includes volumes used for
     fuel.
2    Represents bitumen reserves from the insitu recovery of Canadian oil sands, rather than upgraded synthetic crude oil
     reserves to be sold.
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.
</TABLE>


                                      126
<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 are on pages 20 and 21.  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 1,960 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  4,370  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
3,915 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, 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
--------------------------------------------------------------------------------------------------

  Revision of Previous Estimates                        -                  (4)                 (4)
  Extensions and Discoveries                            -                  19                  19
  Production                                           (3)                 (3)                 (6)
--------------------------------------------------------------------------------------------------
December 31, 2005                                      47                 217                 264
==================================================================================================
</TABLE>

Notes:
1    Leases 17 and 22
2    Leases 10, 12, 31 and 34.


                                      127
<PAGE>

B. CAPITALIZED COSTS (EXCLUDING SYNCRUDE OPERATIONS)

<TABLE>
<CAPTION>
                                                                          Accumulated
                                                                        Depreciation,
                                                                           Depletion,
                                           Proved          Unproved      Amortization       Capitalized
(Cdn$ millions)                        Properties        Properties    and Impairment             Costs
--------------------------------------------------------------------------------------------------------
<S>                              <C>               <C>               <C>               <C>
December 31, 2005
  Yemen                                     2,243                 -             1,841               402
  Canada                                    3,463               143             1,330             2,276
  United States                             2,323               114             1,159             1,278
  United Kingdom                            3,603               410               216             3,797
  Other Countries                              88               161               119               130
--------------------------------------------------------------------------------------------------------
  Total Capitalized Costs                  11,720               828             4,665             7,883
========================================================================================================

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
========================================================================================================
</TABLE>

C. COSTS INCURRED (EXCLUDING SYNCRUDE OPERATIONS)

<TABLE>
<CAPTION>
                                                                          Oil and Gas
                                       ----------------------------------------------------------------------------------
                                             Total                                    United        United
(Cdn$ millions)                        Oil and Gas         Yemen        Canada        States       Kingdom         Other
-------------------------------------------------------------------------------------------------------------------------
<S>                                 <C>             <C>           <C>           <C>           <C>           <C>
Year Ended December 31, 2005
  Property Acquisition Costs
    Proved                                      20             -            17             3             -             -
    Unproved                                    15             -             -             9             6             -
  Exploration Costs                            509            44            97           235            61            72
  Development Costs                          1,896           236           947           139           560            14
  Asset Retirement Costs                       196            13            58            45            80             -
-------------------------------------------------------------------------------------------------------------------------
Total Costs Incurred                         2,636           293         1,119           431           707            86
=========================================================================================================================

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             -
-------------------------------------------------------------------------------------------------------------------------
Total Costs Incurred                         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
-------------------------------------------------------------------------------------------------------------------------
Total Costs Incurred                         1,430           253           379           622             -           176
=========================================================================================================================
</TABLE>


                                      128
<PAGE>

D. RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES (EXCLUDING SYNCRUDE
   OPERATIONS)

<TABLE>
<CAPTION>
                                                                          Oil and Gas
                                       -------------------------------------------------------------------------------------
                                             Total                                       United        United         Other
(Cdn$ millions)                        Oil and Gas         Yemen        Canada (1)       States       Kingdom     Countries (1)
----------------------------------------------------------------------------------------------------------------------------
<S>                                 <C>             <C>           <C>              <C>           <C>           <C>
Year Ended December 31, 2005
  Net Sales                                  3,263         1,377           609              792           366           119
  Production Costs                             511           150           158               96            95            12
  Exploration Expense                          251            12            24              100            51            64
  Depreciation, Depletion,
Amortization and Impairment                  1,008           354           197              234           210            13
  Other Expenses (Income)                      335            40           125               83            (8)           95
----------------------------------------------------------------------------------------------------------------------------
                                             1,158           821           105              279            18           (65)
----------------------------------------------------------------------------------------------------------------------------
  Income Tax Provision (Recovery)              411           285            32               99             7           (12)
----------------------------------------------------------------------------------------------------------------------------
Results of Operations                          747           536            73              180            11           (53)
============================================================================================================================

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)
============================================================================================================================
</TABLE>

Note:
1    Includes results of discontinued operations (see Note 14).

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 oil and
gas  reserves   (excluding  Syncrude   operations).   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.


                                      129
<PAGE>

<TABLE>
<CAPTION>
                                                                                      United        United         Other
(Cdn$ millions)                              Total         Yemen        Canada        States       Kingdom     Countries
-------------------------------------------------------------------------------------------------------------------------
<S>                                   <C>           <C>           <C>           <C>           <C>           <C>
December 31, 2005
  Future Cash Inflows                       23,040         3,675         4,558         5,002         9,190           615
  Future Production Costs                    5,477           807         1,886           811         1,892            81
  Future Development Costs                   1,093           153           124           268           534            14
  Future Dismantlement and Site
    Restoration Costs, Net                     778            20           180           193           381             4
  Future Income Tax                          4,496           795           244         1,107         2,172           178
  Future Net Cash Flows                     11,196         1,900         2,124         2,623         4,211           338
  10% Discount Factor                        3,154           338           811           697         1,209            99
-------------------------------------------------------------------------------------------------------------------------
Standardized Measure                         8,042         1,562         1,313         1,926         3,002           239
=========================================================================================================================

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
=========================================================================================================================
</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>

(Cdn$ millions)                                                                                 2005          2004          2003
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                           <C>           <C>           <C>
Beginning of Year                                                                              6,290         5,517         6,369
  Sales and Transfers of Oil and Gas Produced, Net of Production Costs                        (2,028)       (1,674)       (2,298)
  Net Changes in Prices and Production Costs Related to Future Production                      3,302           142        (1,249)
  Extensions, Discoveries and Improved Recovery, Less Related Costs (1)                          977           (71)          740
  Changes in Estimated Future Development and Dismantlement Costs                               (135)         (122)         (279)
  Previous Estimated Future Development and Dismantlement Costs Incurred During the Period       638           604           456
  Revisions of Previous Quantity Estimates                                                       478          (223)         (291)
  Accretion of Discount                                                                          799           692           884
  Purchases of Reserves in Place                                                                  15         1,764           354
  Sales of Reserves in Place                                                                    (882)          (20)         (252)
  Net Change in Income Taxes                                                                  (1,412)         (319)        1,083
---------------------------------------------------------------------------------------------------------------------------------
End of Year                                                                                    8,042         6,290         5,517
=================================================================================================================================

Note:
1    2004 includes approximately $230 million of negative discounted future net cash flows relating to bitumen reserves based on
     year-end assumptions.
</TABLE>


                                      130
<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,  2005.  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 was one  important  exclusion  from our  assessment.  Our 7.23%  working
interest in the Syncrude  joint venture was excluded from our assessment as 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 7.8% of our consolidated  total assets and 8.2% of our consolidated
revenues  as at and for  the  year  ended  December  31,  2005.  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.  Further  financial
information  with  respect to the  Syncrude  joint  venture is in the Syncrude
segment of Note 20 to our consolidated financial statements.

Our management's  assessment of the effectiveness of our internal control over
financial  reporting as of December  31, 2005,  has been audited by Deloitte &
Touche LLP, independent registered Chartered  Accountants,  as stated in their
report which is on page 132 of this Form 10-K.

CHANGES IN INTERNAL CONTROLS

We have  continually  had in place systems  relative to internal  control over
financial  reporting.  During  2005,  we  continued to improve and enhance our
financial  reporting  systems with the ongoing  implementation of our existing
Systems,  Applications,  and Products in Data Processing (SAP) system into our
chemicals  operations.  We also  improved  our  controls  with  respect to SAP
segregation of duties, database access and password management. The conversion
of data and the  implementation  and  operation  of SAP has  been  continually
monitored and reviewed.

Effective April 27, 2005,  Thomas O'Neill was appointed Chair of our Audit and
Conduct Review Committee.

We have  evaluated  these  changes and  confirm  that there have been no other
changes in our internal  control over  financial  reporting  during the fourth
quarter of 2005 that have  materially  affected,  or are reasonably  likely to
materially  affect,  our internal control over financial  reporting.  Based on
these  evaluations,  there  were no  material  weaknesses  in  these  internal
controls  requiring  corrective action. As a result, no such corrective action
was taken.

In 2006, we expect to implement our SAP system into our UK operations  and, in
keeping  pace  with  growth  in our US  operations,  we  expect  to  implement
additional inventory tracking and procure to pay process controls.


                                      131
<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, 2005,  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 the internal control over financial reporting at the Syncrude
joint  venture  because  the  Company  does not have the ability to dictate or
modify  controls at this  entity and does not have the  ability to assess,  in
practice,  the  controls at this entity.  The  interest in the Syncrude  joint
venture constitutes total assets and revenues of 7.8% and 8.2%,  respectively,
of the related consolidated financial statement amounts as at and for the year
ended December 31, 2005.  Accordingly,  our audit did not include the internal
control over financial reporting at the Syncrude joint venture.  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 or any evaluation
of 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 and
procedures may deteriorate.

In our opinion,  management's assessment that the Company maintained effective
internal  control over financial  reporting as at December 31, 2005, 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, 2005, 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, 2005,  and our report dated February 7, 2006,
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, 2006                Independent Registered Chartered Accountants


                                      132
<PAGE>

Effective governance ensures Nexen
continues to be both economically
successful and globally responsible. Our
Board sets the direction. Management
keeps us on course. And employees
take responsibility every day at work.

see the value

corporate governance



                                      133
<PAGE>

                               PARTS III AND IV

ITEMS 10 TO 15

                                                                          Page
Directors..................................................................135

Independence and Board Committees..........................................136

Executive Officers.........................................................137

Summary Compensation.......................................................139

Compensation and Human Resources Committee.................................145

Share Performance..........................................................149

Security Ownership.........................................................149

Certain Relationships and Related Transactions.............................150

Principal Accountant Fees and Services.....................................151

Exhibits...................................................................152

Certifications.............................................................156


                                      134
<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 our directors' principal occupations or employment during the
past five years and any other  directorships  they held in public companies as
at February 17, 2006.  The  following  directors are  management  nominees for
election to the Board.

<TABLE>
<CAPTION>
                                                                                                                             Nexen
Name (Age)                         Principal Occupation                                 Other Directorships         Director Since
----------------------------------------------------------------------------------------------------------------------------------
<S>                                <C>                                                  <C>                               <C>
Charles W. Fischer (55)            President and Chief Executive Officer (CEO) of Nexen                                       2000
                                   Formerly: Executive Vice President and
                                   Chief Operating Officer (COO)
-----------------------------------------------------------------------------------------------------------------------------------
Dennis G. Flanagan 1, 2, 3 (66)    Retired oil executive.                               Canexus Income Fund (Chair)          2000
                                                                                        NAL Oil & Gas Trust
-----------------------------------------------------------------------------------------------------------------------------------
David A. Hentschel 1, 2 (72)       Retired oil executive.                               Cimarex Energy Co.                    1985
                                   Formerly: Oil and Gas consultant. Prior to that,
                                   Chair and CEO of Occidental Oil and Gas
                                   Corporation.
-----------------------------------------------------------------------------------------------------------------------------------
S. Barry Jackson 1 (53)            Retired oil executive.                               Cordero Energy Inc.                   2001
                                   Formerly: President and CEO of Crestar Energy Inc.   TransCanada Corporation and
                                   and formerly Chair of Resolute Energy Inc. and       TransCanada PipeLines Limited
                                   Chair of Deer Creek Energy Limited.                  (Chair)
-----------------------------------------------------------------------------------------------------------------------------------
Kevin J. Jenkins 1, 2 (49)         Managing Director of TriWest Capital                                                       1996
                                   Management Corp.
                                   Formerly: President and CEO of
                                   The Westaim Corporation.
-----------------------------------------------------------------------------------------------------------------------------------
Eric P. Newell, O.C. (61)          Retired Chair and CEO of Syncrude Canada Ltd.        Canfor Corporation                    2004
-----------------------------------------------------------------------------------------------------------------------------------
Thomas C. O'Neill 1, 2 (60)        Retired Chair of PwC Consulting.                     BCE Inc.                              2002
                                   Formerly: CEO of PwC Consulting. Prior to that,      Loblaw Companies Limited
                                   COO of PricewaterhouseCoopers LLP, Global.           Dofasco Inc. (4)
                                   Prior to that, CEO of                                Adecco S.A.
                                   PricewaterhouseCoopers LLP, Canada.
-----------------------------------------------------------------------------------------------------------------------------------
Francis M. Saville, Q.C. (67)      Chair of Nexen Inc.                                                                        1994
                                   Counsel to Fraser Milner Casgrain LLP,
                                   Barristers and Solicitors.
                                   Formerly: Senior Partner and Vice Chair of Fraser
                                   Milner Casgrain LLP, Barristers and Solicitors.
-----------------------------------------------------------------------------------------------------------------------------------
Richard M. Thomson, O.C. 1, 2 (72) Retired banking executive.                           The Thomson Corporation               1997
                                                                                        Trizec Properties Inc.
-----------------------------------------------------------------------------------------------------------------------------------
John M. Willson (66)               Retired President and CEO of Placer Dome Inc.        Aber Diamond Corporation              1996
                                                                                        Finning International Inc.
                                                                                        Pan American Silver Corporation
-----------------------------------------------------------------------------------------------------------------------------------
Victor J. Zaleschuk (62)           Retired President and CEO of Nexen.                  Cameco Corporation (Chair)            1997
                                                                                        Agrium Inc.
-----------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
<S>  <C>
Notes:
1    Members of Nexen's Audit and Conduct Review Committee as of February 16, 2006. 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.
3    Mr. Flanagan was a director of Elek-Tek Inc., a US public computer retailing company, that was subject to bankruptcy
     proceedings in 1998.
4    Subsequent to February 17, 2006, Dofasco Inc. was acquired by Arcelor S.A., and Mr. O'Neill resigned as a director of Dofasco
     Inc. on February 21, 2006.
</TABLE>


                                      135
<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 17, 2006. 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,  National Policy
58-201 Corporate Governance Guidelines,  Multilateral  Instrument 52-110 Audit
Committees and applicable  provisions of National  Instrument 51-101 Standards
of Disclosure for Oil and Gas Activities.

The  table  below  sets out  committee  memberships  and  whether  or not each
director  has  been  determined  by the  Board to be  independent.  Of the two
non-independent directors:

o    Mr.  Newell  is not  independent,  because  a Nexen  officer  sits on the
     compensation committee of Syncrude, where Mr. Newell was formerly CEO. If
     circumstances  remain the same,  Mr.  Newell  will be  independent  after
     January 2, 2007 (three years after his retirement from Syncrude).
o    Mr. Fischer is not independent as he is the President and CEO of Nexen.

<TABLE>
<CAPTION>
                                                    Committees (Number of Members)
-----------------------------------------------------------------------------------------------------------------------------------
                                                                           Corporate                                         Safety
                                          Audit and     Compensation      Governance                                    Environment
                                            Conduct        and Human             and                       Reserve       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)                          x                x                                             x               x
-----------------------------------------------------------------------------------------------------------------------------------
  S. Barry Jackson                                x                x                                             x           Chair
-----------------------------------------------------------------------------------------------------------------------------------
  Kevin J. Jenkins  (4)                           x                                x           Chair                             x
-----------------------------------------------------------------------------------------------------------------------------------
  Thomas C. O'Neill (4)                       Chair                                x                             x               x
-----------------------------------------------------------------------------------------------------------------------------------
  Francis M. Saville, Q.C. (5, 6)                                  x               x               x                             x
-----------------------------------------------------------------------------------------------------------------------------------
  Richard M. Thomson, O.C. (4)                    x                x           Chair               x
-----------------------------------------------------------------------------------------------------------------------------------
  John M. Willson                                              Chair                               x             x               x
-----------------------------------------------------------------------------------------------------------------------------------
  Victor J. Zaleschuk                                              x               x               x             x
-----------------------------------------------------------------------------------------------------------------------------------
Outside Director--Not Independent
  Eric P. Newell, O.C.                                                                             x             x               x
-----------------------------------------------------------------------------------------------------------------------------------
Management Director--Not Independent
  Charles W. Fischer
-----------------------------------------------------------------------------------------------------------------------------------
<CAPTION>
<S>  <C>
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. Mr. Jackson and Mr. Jenkins were appointed to the Audit and
     Conduct Review Committee on April 27, 2005, but pursuant to the Committee mandate, automatically ceased to be committee
     members when, in each case, his child was a summer student who received employment income from Nexen in the summer of 2005.
     Both were reappointed on February 16, 2006, as they were again independent for audit committee purposes.
2    The Board has considered the circumstances of Mr. O'Neill's service on five public company audit committees, including
     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. Mr. O'Neill was a chartered accountant for more than 30 years, having joined the
     audit firm of Price Waterhouse (now part of PricewaterhouseCoopers) in 1967. Accordingly, the Board has determined that
     service as an audit committee member or chair on four other public companies does not impair Mr. O'Neill's ability to serve
     as Chair of Nexen's Audit and Conduct Review Committee.
3    A majority of the Reserves Review Committee members is 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 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. Saville, Chair of the Board, presides at the regularly scheduled in camera sessions of the non-management directors.
</TABLE>

                                      136
<PAGE>


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

Nexen  receives a 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,  including  prior offices and  non-executive  positions for
officers who have held their current  executive  positions with Nexen for less
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 (55)       President and CEO and a director
                              Formerly: Executive Vice President and COO since May 14, 1997            June 1, 2001           1994
-----------------------------------------------------------------------------------------------------------------------------------
Marvin F. Romanow (50)        Executive Vice President and CFO
                              Formerly: Senior Vice President, Finance and CFO since
                              February 19, 1999                                                        June 1, 2001           1997
-----------------------------------------------------------------------------------------------------------------------------------
Laurence Murphy (54)          Senior Vice President, International Oil and Gas                      January 1, 1999           1998
-----------------------------------------------------------------------------------------------------------------------------------
John B. McWilliams, Q.C. (58) Senior Vice President, General Counsel and Secretary                     May 11, 1993           1987
-----------------------------------------------------------------------------------------------------------------------------------
Douglas B. Otten (63)         Senior Vice President, United States Oil and Gas                         May 12, 1998           1990
-----------------------------------------------------------------------------------------------------------------------------------
Roger D. Thomas (53)          Senior Vice President, Canadian Oil and Gas                         February 19, 1999           1998
-----------------------------------------------------------------------------------------------------------------------------------
Nancy F. Foster (46)          Vice President, Human Resources and Corporate Services                  July 11, 2000           2000
-----------------------------------------------------------------------------------------------------------------------------------
Gary H. Nieuwenburg (47)      Vice President, Synthetic Crude
                              Formerly:  Vice President, Corporate Planning and Business
                              Development since February 16, 2001                                     July 11, 2002           2001
-----------------------------------------------------------------------------------------------------------------------------------
Kevin J. Reinhart (47)        Vice President, Corporate Planning and Business Development
                              Formerly: Treasurer since October 20, 1998                              July 11, 2002           1994
-----------------------------------------------------------------------------------------------------------------------------------
Una M. Power (1) (41)         Treasurer
                              Formerly: Controller and Director, Corporate Insurance since
                              May 2, 2002 Controller and Director, Risk Management since
                              December 1, 1998                                                        July 11, 2002           1998
-----------------------------------------------------------------------------------------------------------------------------------
Michael J. Harris (42)        Controller
                              Formerly: Manager, Corporate Finance--Treasury since
                              December 1, 2000                                                    December 10, 2002           2002
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>

Note:
1    Ms. Power concurrently maintained her position as Controller until
     December 10, 2002.


                                      137
<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 2005.  Our Ethics  Policy  provides  for an external  Integrity
Hotline which has been in place since February 1, 2005.

Our Ethics Policy is available at  www.nexeninc.com,  and we intend 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  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 its duties and  responsibilities  for good
corporate governance seriously. Nexen supports and conducts business according
to the rules of the Toronto Stock Exchange (TSX), NYSE, National Policy 58-201
Corporate  Governance  Guidelines  and  Multilateral  Instrument  52-110 Audit
Committees.  Except as noted  below  with  regard to DSUs,  Nexen's  corporate
governance  practices comply with the corporate  governance practices followed
by domestic companies under NYSE listing standards.

Nexen has a DSU plan for non-executive directors as described on page 144. For
this plan,  Nexen follows the TSX rules which,  unlike the NYSE rules,  exempt
plans from shareowner  approval where the common  shares issued under the plan
are purchased on the open market rather than being newly issued shares.

On February 23, 2006, 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 February
23, 2006 and an Interim Written Affirmation on February 17, 2006. As well, our
CEO and CFO have  certified  the quality of Nexen's  public  disclosure to the
SEC.

All  Committee  Mandates,  including  those for 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 at  www.nexeninc.com,  and we intend to
provide disclosure in this manner.  Shareholders  wishing to receive a copy of
these  documents  may contact the  Assistant  Secretary  by  telephone at 403.
699.4000,     by    facsimile    at    403.716.0468    or    by    email    at
assistant_secretary@nexeninc.com.

REPORTING CONCERNS

Any concerns  about  Nexen's  financial  statements,  accounting  practices or
internal controls may be directed to the Chair of the Audit and Conduct Review
Committee as set out in the Ethics Policy or reported through EthicsPoint, the
independent, third-party service provider, as set out below.

If  Nexen  employees,   customers,  suppliers,  partners  and  other  external
stakeholders  have a concern,  they are  encouraged  to raise it with  Nexen's
Integrity Resource Centre:

    By mail to:          Nexen Inc.
                         801 - 7th Avenue S.W., Calgary, Alberta, T2P 3P7
    Attention:           Integrity Resource Centre
    or by email to:      integrity@nexeninc.com
    or by telephone to:  403.699.4727

They may also report concerns through Nexen's Integrity Hotline. The Integrity
Hotline  is  a  secure   reporting  system  which  is  owned  and  managed  by
EthicsPoint,  an independent  third-party  service provider.  To find out more
about Nexen's Integrity Hotline and for toll free numbers for other countries,
refer to  www.nexeninc.com,  and click on the "Integrity  Hotline" link at the
top of the page.

The Integrity Hotline can also be accessed:

    Through the internet:        www.ethicspoint.com
    By telephone (toll-free):    North America 1.866.ETHICSP (1.866.384.4277)


                                      138
<PAGE>

ITEM 11. EXECUTIVE COMPENSATION

SUMMARY COMPENSATION

<TABLE>
<CAPTION>
                                         Annual Compensation                              Long-Term Compensation Awards
------------------------------------------------------------------------------- ---------------------------------------------------
                                                                                  Securities      Restricted
                                                                                  Underlying       Shares or
                                                                  Other Annual       Options       Restricted           All Other
Name and Principal Positions    Year      Salary        Bonus (1) Compensation       Granted (2)  Share Units        Compensation
                                             ($)          ($)              ($)           (#)              ($)                 ($)
------------------------------------------------------------------------------- ---------------------------------------------------
<S>                             <C>     <C>         <C>             <C>             <C>             <C>           <C>
Charles W. Fischer              2005     975,000    1,200,000                -        200,000               -             58,500(3)
President and CEO               2004     847,917    1,310,000                -        300,000               -             50,875(3)
                                2003     725,000      600,000                -        200,000               -             43,500(3)
------------------------------------------------------------------------------- ---------------------------------------------------
Marvin F. Romanow               2005     486,000      525,000                -         62,000               -             29,160(3)
Executive Vice President        2004     462,500      555,000                -        114,000               -             27,750(3)
and CFO                         2003     440,500      267,000                -        110,000               -             26,430(3)
------------------------------------------------------------------------------- ---------------------------------------------------
Douglas B. Otten                2005     423,489      212,048                -         50,000               -  13,813(3)/ 61,654(4)
Senior Vice President,          2004     438,005      299,345                -         80,000               -  26,280(3)/ 63,536(4)
United States Oil and Gas       2003     416,152      226,170                -         74,000               -  24,969(3)/ 60,221(4)
------------------------------------------------------------------------------- ---------------------------------------------------
Laurence Murphy                 2005     405,000      205,000                -         50,000               -             24,300(3)
Senior Vice President,          2004     385,500      565,000                -         80,000               -             23,130(3)
International Oil and Gas       2003     366,500      196,000                -         74,000               -             21,990(3)
------------------------------------------------------------------------------- ---------------------------------------------------
Roger D. Thomas                 2005     394,250      400,000                -         50,000               -             18,000(3)
Senior Vice President,          2004     373,250      225,000                -         80,000               -             16,740(3)
Canadian Oil and Gas            2003     356,500      190,000                -         64,000               -             21,390(3)
------------------------------------------------------------------------------- ---------------------------------------------------
Thomas A. Sugalski (5)          2005     232,367    1,437,440                -              -               -  16,214(3)/ 39,335(6)
Senior Vice President,          2004     403,465      208,240                -         60,000               -  24,208(3)/ 56,165(6)
Chemicals                       2003     384,439      156,380                -         60,000               -  23,066(3)/ 53,395(6)
------------------------------------------------------------------------------- ---------------------------------------------------
<CAPTION>
Notes:

For the CEO and five other highest compensated officers, which include the CFO and the former Senior Vice President, Chemicals
who retired on August 1, 2005:
<S>  <C>
1    Annual bonuses are determined based on performance during the year and are paid to the employee in the following year
     pursuant to the annual incentive plan. The bonuses indicated were the payments made in the year shown and include special
     bonuses of $300,000, $175,000 and $200,000 for Messrs. Fischer, Romanow and Thomas, respectively, for the successful
     divestitures. The bonus for Mr. Sugalski includes a payment of $1,239,933 under a Special Separation Agreement dated January
     28, 2005, effective August 1, 2005.
2    Reflect the two-for-one split of issued and outstanding common shares that occurred on May 10, 2005 (TSX) and on May 18,
     2005 (NYSE).
3    Reflect Nexen contributions to the Employee Savings Plan.
4    Nexen contributed to a Qualified Defined Contribution Plan and a Restoration Plan with Nexen Petroleum U.S.A. Inc. for Mr.
     Otten.
5    Mr. Sugalski retired on August 1, 2005, and is included because he would have been one of the highest compensated officers,
     except that he was not serving as an officer of Nexen at December 31, 2005.
6    Nexen contributed to a Qualified Defined Contribution Plan and a Restoration Plan with Nexen Chemicals U.S.A. Inc. for Mr.
     Sugalski.
</TABLE>

OPTIONS

Pursuant to Nexen's Tandem Option Plan (TOP), 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 option  exercise price is the market price of Nexen's common
shares on the TSX for  Canadian-based  employees  or on 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,  options
have a term of ten years; 20% of the grant vests after six months and then 20%
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  that  each  option  granted  has a term of  five  years  and  vests
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.


                                      139
<PAGE>

OPTION GRANTS DURING 2005

<TABLE>
<CAPTION>
                                              % of Total
                                           Options/Stock                                    Potential Realizable Value at Assumed
                                            Appreciation                                         Annual Rates of Stock Price
                            Securities    Rights Granted                                        Appreciation for Option Term
                            Underlying   To Employees in    Exercise or                     ---------------------------------------
Name                   Options Granted    Financial Year     Base Price (1) Expiration Date                5%                  10%
-----------------------------------------------------------------------------------------------------------------------------------
                                  (#)                      ($/Security)                                   ($)                  ($)
-----------------------------------------------------------------------------------------------------------------------------------
<S>                    <C>                <C>             <C>            <C>                <C>                <C>
Charles W. Fischer             200,000               4.1          54.57    December 6, 2010         3,015,337            6,663,106
Marvin F. Romanow               62,000               1.3          54.57    December 6, 2010           934,754            2,065,563
Douglas B. Otten                50,000               1.0       US$47.21    December 6, 2010           790,225            1,746,192
Laurence Murphy                 50,000               1.0          54.57    December 6, 2010           753,834            1,665,777
Roger D. Thomas                 50,000               1.0          54.57    December 6, 2010           753,834            1,665,777
Thomas A. Sugalski                   -                 -              -                   -                 -                    -

Note:
1    Equal to the market value of securities underlying the options on the date of grant.
</TABLE>

OPTIONS EXERCISED DURING 2005 AND FINANCIAL YEAR-END OPTION VALUES

<TABLE>
<CAPTION>
                                                                     Number of Securities           Value of Unexercised
                                Securities                          Underlying Unexercised        In-The-Money-Options at
                                Acquired                    Options at Financial Year-end             Financial Year-end
Name                            on Exercise    Value Realized (1)  Exercisable/Unexercisable      Exercisable/Unexercisable
--------------------------------------------------------------------------------------------------------------------------
                                     (#)               ($)                            (#)                             ($)
--------------------------------------------------------------------------------------------------------------------------
<S>                          <C>            <C>               <C>                            <C>
Charles W. Fisher                116,000         4,375,840            1,146,000 / 464,000         44,538,700 / 8,329,250
Marvin F. Romanow                 20,000           710,000              492,460 / 173,540         18,515,798 / 3,530,992
Douglas B. Otten                  51,694           789,490              246,636 / 127,220          9,690,667 / 2,634,443
Laurence Murphy                  182,900         4,226,207               99,880 / 127,220          3,373,261 / 2,447,929
Roger D. Thomas                  136,000         1,975,320              160,080 / 123,920          5,684,112 / 2,336,818
Thomas A. Sugalski               131,600         5,133,093                   - /   59,400                  - / 2,012,420
</TABLE>

Note:
1    Equals market price at the time of the exercise, minus the exercise price,
     as defined in the TOP Plan.


EMPLOYEE SAVINGS PLAN

The Summary  Compensation Table includes Nexen's  contribution to the employee
savings plan made on behalf of executive officers. Through payroll deductions,
all regular  employees may contribute any percentage of their regular earnings
to purchase Nexen common shares or mutual fund units or a combination of both.
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 US, the  savings  plan is  intended  to  qualify  under
Sections  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 provided in cash,  which 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. Mr.
Otten is  employed  in the US and is a member of a  qualified  401(k)  savings
plan,  a  qualified  defined  contribution  pension  plan and a  non-qualified
restoration  plan.  Mr.  Sugalski  participated  in the 401(k) savings plan, a
qualified defined  contribution  pension plan and a non-qualified  restoration
plan until his retirement.


                                      140
<PAGE>

DEFINED BENEFIT PENSION PLAN (CANADA)

Under this registered plan,  participants  must contribute 3% of their regular
gross earnings,  up to an allowable maximum.  On retirement,  participants are
entitled to receive a benefit  equal to 1.8% (1.7% for years prior to 2005) 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) to provide
a maximum  offset of one-half of the  prevailing  CPP  benefit.  Nexen was not
required to contribute to the Defined Benefit Pension Plan in 2005.

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
annually at an amount between 0% and 5% 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  participants  to
periodically  switch  between  the Defined  Benefit  and Defined  Contribution
Pension  Plans at different  stages in their career.  In addition,  the plan's
benefit accrual formula  increased from 1.7% to 1.8% for  participation  after
January 1, 2005.  Plan  participants  have 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 choose 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
Canadian  participants  who have earned a retirement  benefit in excess of the
statutory limits. Ten executive officers, together with all employees who have
exceeded  the  statutory   limit  with  their  earned   retirement   benefits,
participate  in the EBP.  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 that
accrue  under the EBP are similar to the  underlying  registered  pension plan
formula which provides for benefits of 1.7% for credited service prior to 2005
and 1.8% or 2% for credited service after that. For executive officers, annual
incentive payments 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 reduce 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
Defined Benefit Pension Plan, which is funded. The service cost for the letter
of credit was $187,132 in 2005.

At December 31, 2005, as indicated in the notes to our  financial  statements,
Nexen's  accumulated  benefit  obligation  (the projected  benefit  obligation
excluding  future salary  increases)  for the EBP was $29.1  million,  and the
projected  benefit  obligation  was  $42.5  million.   The  projected  benefit
obligation is an estimate  based on contractual  entitlements  that may change
over time. The method used to determine this estimate will not be identical to
the method  used by other  issuers  and,  as a result,  the figures may not be
directly  comparable  across  companies.  The  key  assumptions  used  for the
projected  benefit  obligation  were a  discount  rate of 5.25%  per  year,  a
long-term  compensation  rate increase of 4% per year and an expected  average
remaining service life of ten years.

Effective  January 1,  2005,  the EBP was  amended  to provide a  supplemental
pension allocation for Defined  Contribution Pension Plan participants who are
affected by annual statutory  contribution  limits.  In 2005, the supplemental
allocation for eligible participants was $18,000 and in 2006, the supplemental
allocation for eligible  participants will be $25,390.  No Canadian  executive
officer participates in the Defined Contribution Pension Plan.

DEFINED CONTRIBUTION PENSION PLAN (US)

Under this qualified  retirement plan, Nexen provides plan 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 2005, the maximum amount of contributions  permitted by
legislation  to  qualified   defined   contribution   plans  was  $42,000  per
participant.


                                      141
<PAGE>

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 by Nexen for the purpose of providing  benefits in
excess of applicable legislative limits.

ESTIMATED PENSION BENEFIT

The table shows the  estimated  annual  pension a retiring  executive  officer
would  receive for  credited  service up to and  including  December 31, 2004,
assuming that the amount in the Summary  Compensation  Table (page 139) is the
officer's  final  average  salary.  The  annual  benefit is based on a pension
accrual  formula of 1.7% of average  earnings less a plan offset.  It includes
benefits from both the Defined  Benefit Pension Plan and the EBP and assumes a
retirement  age of 65. The normal  benefits paid from this plan are joint life
and survivor benefits with a five-year  guarantee.  The benefit is payable for
the participant's  lifetime and provides the spouse with a survivor benefit of
66 2/3% of the monthly  payment.  The  five-year  guarantee  means that if the
participant  dies before receiving 60 monthly  payments,  the surviving spouse
receives  the  balance  of  those 60  monthly  payments  and then the  reduced
survivor pension of 66 2/3%.


<TABLE>
<CAPTION>
                                        Years of Services Before January 1, 2005
-----------------------------------------------------------------------------------------------
Renumeration ($)                     5            10            15            20            25
-----------------------------------------------------------------------------------------------
<S>                             <C>           <C>           <C>           <C>           <C>
400,000                         33,290        66,579        99,869       133,159       166,448
600,000                         50,290       100,579       150,869       201,159       251,448
800,000                         67,290       134,579       201,869       269,159       336,448
1,000,000                       84,290       168,579       252,869       337,159       421,448
1,200,000                      101,290       202,579       303,869       405,159       506,448
1,400,000                      118,290       236,579       354,869       473,159       591,448
1,600,000                      135,290       270,579       405,869       541,159       676,448
1,800,000                      152,290       304,579       456,869       609,159       761,448
2,000,000                      169,290       338,579       507,869       677,159       846,448
2,200,000                      186,290       372,579       558,869       745,159       931,448
2,400,000                      203,290       406,579       609,869       813,159     1,016,448
2,600,000                      220,290       440,579       660,869       881,159     1,101,448
2,800,000                      237,290       474,579       711,869       949,159     1,186,448
</TABLE>

The following  table shows the estimated  annual pension for credited  service
earned on and after  January  1,  2005,  based on a  forward  looking  benefit
accrual rate of 2% of final average  earnings less a plan offset.  It includes
benefits  from both the Defined  Benefit Plan and EBP and assumes a retirement
age of 65.

<TABLE>
<CAPTION>
                                        Years of Services Before January 1, 2005
-----------------------------------------------------------------------------------------------
Renumeration ($)                     5            10            15            20            25
-----------------------------------------------------------------------------------------------
<S>                              <C>           <C>           <C>           <C>           <C>
400,000                         39,290        78,579       117,869       157,159       196,448
600,000                         59,290       118,579       177,869       237,159       296,448
800,000                         79,290       158,579       237,869       317,159       396,448
1,000,000                       99,290       198,579       297,869       397,159       496,448
1,200,000                      119,290       238,579       357,869       477,159       596,448
1,400,000                      139,290       278,579       417,869       557,159       696,448
1,600,000                      159,290       318,579       477,869       637,159       796,448
1,800,000                      179,290       358,579       537,869       717,159       896,448
2,000,000                      199,290       398,579       597,869       797,159       996,448
2,200,000                      219,290       438,579       657,869       877,159     1,096,448
2,400,000                      239,290       478,579       717,869       957,159     1,196,448
2,600,000                      259,290       518,579       777,869     1,037,159     1,296,448
2,800,000                      279,290       558,579       837,869     1,117,159     1,396,448
</TABLE>

When  determining  the  estimated  value of  future  pension  benefits  for an
executive  officer,  both tables above need to be referenced.  For example,  a
pension estimate based on 35 years of credited service would require the first
table for actual credited  service up to and including  December 31, 2004, and
the second table for projected  credited service on and after January 1, 2005.
When  estimating  future  pension  benefits,  the final average  earnings used
should be the same for both tables.


                                      142
<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 four 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 for Executives on page
139.

<TABLE>
<CAPTION>
                           Years of Credited    Years of Credited                                               Estimated Amount
                                  Service to         Service from                Final       Accrued Annual      Pension Benefit
Name                       December 31, 2004      January 1, 2005     Average Earnings (1)  Pension Benefit (1)        at Age 60 (2)
------------------------------------------------------------------------------------------------------------------------------------
                                                              (#)                  ($)                  ($)                  ($)
------------------------------------------------------------------------------------------------------------------------------------
<S>                        <C>                  <C>                   <C>                   <C>                  <C>
Charles W. Fischer                 20.58 (3)                 1.00            1,377,639              506,544              792,219
Marvin F. Romanow                  17.50 (3, 4)              1.00              679,300              239,708              418,678
Laurence Murphy                    18.67                     1.00              533,933              177,322              252,045
Roger D. Thomas                    24.5  (3)                 1.00              518,533              222,717              317,953

<CAPTION>
<S>  <C>
Notes:
1    All information as of December 31, 2005.
2    Earliest age at which an individual receives full retirement benefits.
3    Ten years of additional past service credits were granted to each of Messrs. Fischer, Romanow and Thomas by the Board
     in 2001.
4    Mr. Romanow is entitled to additional  pension  benefit based on pensionable  bonus, in recognition of his 7.25 years of
     service as a participant in Nexen's defined contribution pension plan up to December 31, 2004.
</TABLE>


COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

The members of the Compensation and Human Resources Committee are in the table
on page 136. 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 150.  Mr.  Hentschel  and Mr.
Zaleschuk were both formerly officers of Nexen, until June 1, 1997 and May 31,
2001,  respectively.  There are no compensation  committee  interlocks  during
2005.

CHANGE OF CONTROL AGREEMENTS

Nexen has entered  into Change of Control  Agreements  with  Messrs.  Fischer,
Romanow,  Otten, Murphy, Thomas and other key executives.  The agreements were
effective  October 1999,  amended in December 2000 and amended and restated in
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  caused by a change in control and
treat them in a fair and equitable manner,  consistent with industry standards
for executives in similar circumstances.

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 that 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.
Mr. Fischer and Mr. Romanow 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,  Murphy and Thomas,  the severance
period is 30 months.

DIRECTOR COMPENSATION

In December 2005, all director  compensation was reviewed and confirmed at the
then-current  levels,  except for an additional  annual fee of $14,400 for the
Chair of the  Audit  and  Conduct  Review  Committee.  The  additional  amount
reflects the complex  duties of the position.  Nexen  reimburses the directors
for  out-of-pocket  expenses  incurred to attend meetings.  Directors are paid
meeting  fees  for  attending  meetings  either  in  person  or  by  telephone
conference call. From January 1, 2006, all directors who are not employees are
paid:

<TABLE>
<S>                                                                                  <C>
Annual Board Chair Retainer                                                       $150,000
Annual Board Retainer                                                              $28,100
Annual Committee Retainer                                                           $9,100
Annual Committee Chair Retainer                                                     $5,300
Annual Audit and Conduct Review Committee Additional Annual Chair Retainer (1)     $14,400
Board Committee Meeting Fees                                                        $1,800
</TABLE>

Note:
1    The total  annual  retainer of $28,800 paid to the Chair of the Audit and
     Conduct Review Committee and includes the Annual Committee Retainer,  the
     Annual  Committee  Chair Retainer and the Annual Audit and Conduct Review
     Committee Additional Chair Retainer.



                                      143
<PAGE>

Annual Board and Committee retainers are paid quarterly,  in advance,  and are
pro-rated for partial  service,  if appropriate.  This table sets out the full
dollar value of retainers and fees, whether received in cash or Deferred Share
Units.  All  payments  were  received  in cash  unless  otherwise  noted.  See
"Deferred  Share  Units"  for DSUs  granted  as  directors'  performance-based
compensation.

<TABLE>
<CAPTION>
                                                    Annual
                                                 Committee        Annual
                                   Annual       Retainers/     Committee        Board      Committee     Total Fees     Total Fees
                                    Board        Number of         Chair      Meeting        Meeting        Paid in    Credited in
Director                         Retainer       Committees      Retainer         Fees           Fees           Cash           DSUs
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                   <C>          <C>                <C>         <C>            <C>            <C>            <C>
Charles W. Fischer (1)                n/a              n/a           n/a          n/a            n/a            n/a            n/a
Dennis G. Flanagan                $28,100        $36,400/4        $5,300      $16,200        $45,000       $131,000              -
David A. Hentschel                $28,100        $36,400/4        $1,325      $18,000        $39,600       $123,425              -
S. Barry Jackson (4)              $28,100        $31,887/3 (4)    $5,300      $18,000        $32,400       $115,687              -
Kevin J. Jenkins (4)              $28,100        $30,317/3 (4)    $5,300      $16,200        $34,200       $114,117              -
Eric P. Newell, O.C. (2)          $28,100        $27,300/3             -      $16,200        $25,200              -        $96,800
Thomas C. O'Neill                 $28,100        $36,400/4        $3,975      $16,200        $48,600       $133,275              -
Francis M. Saville, Q.C. (3)     $140,600        $36,400/4        $1,325      $18,000        $55,800       $252,125              -
Richard M. Thomson, O.C. (2,3)    $76,314        $36,400/4        $3,597      $18,000        $55,800              -       $190,111
John M. Willson                   $28,100        $36,400/4        $5,300      $16,200        $43,200       $129,200              -
Victor J. Zaleschuk               $28,100        $36,400/4             -      $18,000        $52,200       $134,700              -
-----------------------------------------------------------------------------------------------------------------------------------
Total                            $441,714        $ 344,304       $31,422     $171,000       $432,000     $1,133,529       $286,911
===================================================================================================================================
<CAPTION>
<S>  <C>
Notes:
1    As an executive of Nexen, Mr. Fischer is not paid retainers or meeting fees.
2    Details of DSU holdings are set out in the table below.
3    Mr. Saville was appointed Chair of the Board on April 27, 2005, and Mr. Thomson stepped down as Chair of the Board on the
     same date. Their retainers were pro-rated. Mr. Thomson continues to serve as a Director.
4    Audit and Conduct Review Committee retainer fees were pro-rated to May 2, 2005, for Mr. Jenkins and to July 4, 2005, for Mr.
     Jackson, the respective dates they ceased to be members of the Committee.
</TABLE>

DEFERRED SHARE UNITS

In 2001, a Deferred Share Unit (DSU) plan was approved as an alternative  form
of  compensation  for  non-executive  directors.   Under  the  plan,  eligible
directors  may elect  annually  to receive  all or part of their fees as DSUs,
rather than cash.  A DSU is a  bookkeeping  entry that tracks the value of one
Nexen  common  share.  On the date  cash  dividends  are paid on Nexen  common
shares,  eligible  directors are credited with additional  DSUs. The number of
DSUs is calculated  by dividing the total amount of the  dividends  that would
have been paid if the DSUs on account  were  common  shares by the fair market
value on the dividend  payment date.  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 stating 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
2005,  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 values of the
grants were $114,597 and $174,624,  respectively,  at the closing market price
of Nexen shares on the TSX on December 5, 2005 of $54.57.

                                                           DSUs Held as of
Director                                                 December 31, 2005 (1)
------------------------------------------------------------------------------
Charles W. Fischer                                                    None
Dennis G. Flanagan                                                  10,582
David A. Hentschel                                                  10,580
S. Barry Jackson                                                    10,582
Kevin J. Jenkins                                                    17,073
Eric P. Newell, O.C.                                                16,139
Thomas C. O'Neill                                                   15,505
Francis M. Saville, Q.C.                                            11,682
Richard M. Thomson, O.C.                                            22,576
John M. Willson                                                     16,782
Victor J. Zaleschuk                                                 10,582

Note:
1    Number of DSUs has been  adjusted to account for Nexen's share split that
     occurred on May 10, 2005 (TSX) and on May 18, 2005 (NYSE).


                                      144
<PAGE>

DIRECTORS' AND OFFICERS' LIABILITY INSURANCE

Nexen maintains a directors' and officers'  liability  insurance policy.  This
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$5  million  deductible  per  occurrence.  The cost of coverage for 2005 was
approximately US$0.9 million.

SHARE OWNERSHIP GUIDELINES FOR DIRECTORS

The Board believes it is important that directors demonstrate their commitment
to Nexen's growth through share ownership.  The Board has approved a guideline
setting  out that  directors  are  expected  to own or control at least  6,000
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.  Ownership  can be  achieved  by  purchasing  common
shares,  participating  in the Nexen Dividend  Reinvestment  Plan or directing
retainer fees into DSUs. All directors meet the ownership requirement.

COMPENSATION AND HUMAN RESOURCES COMMITTEE

The Compensation and Human Resources Committee (Committee) is comprised of six
independent  directors,  and its  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 annual  incentive  plan, the 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 consistent with and linked to its strategic
business objectives and increased  shareowner returns.  Within that framework,
the Committee's goal is to compensate  executives  based on performance,  at a
level  competitive with the market, in a manner designed to 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  our
executive  compensation  practices to peers,  primarily major Canadian oil and
gas and, where relevant,  marketing companies. The Committee receives a report
annually on CEO compensation from its own independent  consultant.  The report
includes  competitive  compensation  data  from a  predetermined  list of peer
companies.  The  information  is used to  determine  the  annual  compensation
recommendation for the CEO by the Committee.

COMPENSATION OBJECTIVES

Nexen's   compensation   programs  are  designed  to  meet   performance   and
competitiveness  objectives.  They are pay-for-performance plans, with rewards
directly linked to planned performance for Nexen and its divisions. Individual
performance and contributions are considered in determining  awards.  Measures
are aligned with financial and non-financial goals and shareowner interests.

Competitiveness is assessed using compensation  survey information from peers,
including  energy  companies  with whom Nexen  competes for talent.  We assess
total compensation and consider the competitiveness of each component.

Our  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  with  compensation  levels of peer  companies.
Nexen's position compared with the market is reviewed annually.  The following
table provides an overview of the three elements:

<TABLE>
<CAPTION>
Component of Compensation     Type of Compensation    Element                 Form             Performance Period
----------------------------------------------------------------------------------------------------------------------
<S>                           <C>                     <C>                     <C>              <C>
Fixed                         Annual                  Base Salary             Cash             1 Year
Variable                      Annual                  Short-Term Incentive    Cash             1 Year
Variable                      Long-Term               Long-Term Incentive     TOPs or StARs    Greater than 1 Year (1)
</TABLE>

Note:
1    TOPs and StARs have a five-year  term and vest one-third each year of the
     first three years of the term on the anniversary date of the grant.


                                      145
<PAGE>

PAY MIX

The majority of  compensation  paid to senior  executives  is  at-risk-pay  to
ensure  alignment  with  shareowners.  The actual mix varies  depending on the
ability of the  executive  to  influence  short-term  and  long-term  business
results,  the level and location of the executive and competitive local market
practices. The following table summarizes the target weightings of the various
compensation components as a percentage of total compensation.

<TABLE>
<CAPTION>
Position                              Base      Annual Incentive   Long-Term Incentive
---------------------------------------------------------------------------------------
<S>                                   <C>                   <C>                   <C>
Chief Executive Officer                26%                   19%                   55%
Chief Financial Officer                33%                   19%                   48%
Senior Vice Presidents                 34%                   14%                   52%
</TABLE>

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,
skills and potential.

ANNUAL INCENTIVES

The Board  approves  awards under the annual  incentive  plan.  The  Committee
determines the total cash available for annual  incentive awards by evaluating
financial and  non-financial  criteria,  including  net income,  cash flow and
specific goals outlined in a balanced scorecard.  Net income and cash flow are
commonly used metrics in our industry,  and each represents one-quarter of the
overall assessment.  The remaining one-half of the overall assessment 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 cash incentives is 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
the ratio of at risk versus fixed compensation is greater for higher levels of
management.  Individual awards are intended to reflect a combination of Nexen,
personal and business  unit  performance,  along with market  competitiveness.
Annual  incentive  awards are typically  within a range of 0% to approximately
200% of targeted amounts.

The  incentive  plan is  reviewed  annually  to ensure we continue to attract,
motivate,  reward and retain the high-performing and high-potential  employees
needed to achieve Nexen's business objectives,  while demonstrating  long-term
fiscal responsibility to our shareowners.

Consistent with industry  practice,  we have a separate annual  incentive plan
for our marketing group, which is a profit sharing arrangement.

STOCK AND LONG-TERM INCENTIVES

The Board  believes  employees  should have a stake in Nexen's future and that
their interests  should be aligned with the interests of our  shareowners.  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 TOPs and the StARs plans.

Under these plans, participating officers and employees receive grants of TOPs
or StARs as a long-term incentive to increase shareowner value. The StARs Plan
was  introduced  in 2001,  and the TOP Plan  (which is  described  below)  was
introduced in 2004. For employees below mid-level department  managers,  StARs
are typically  granted  instead of TOPs.  The grants have a five-year term and
vest one-third each year of the first three years on the  anniversary  date of
the  grant.  This  plan is  distinct  from the  annual  incentive  plan and is
intended to increase the pay-at-risk component.  TOPs do not provide employees
the right to vote the shares that are subject to 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 dilutive impact of the programs on shareowners.  The focus in 2005 was
on  providing  differentiated  awards  based  on  performance,  potential  and
retention risk. The total TOPs and StARs granted and shares reserved for issue
under all of our stock-based  compensation programs will not exceed 10% of our
total outstanding shares.


                                      146
<PAGE>

TOPS AND STARS GRANTED IN THE LAST THREE YEARS

<TABLE>
<CAPTION>
                            Issued to           Issued to                               Percentage of
                        Non-Executive           Executive           Issued to       Employees Granted         Total Number of
Year                        Directors           Directors           Employees              TOPs/StARs      TOPs/StARs Granted
------------------------------------------------------------------------------------------------------------------------------
<S>                     <C>                 <C>                  <C>                <C>                    <C>
TOPS
  2005                              -             592,000           2,799,500                     20%               3,391,500
  2004 (1)                          -           1,022,000           3,202,400                     11%               4,224,400
  2003 (1)                          -             840,000           2,913,000                     11%               3,753,000
STARS
  2005                              -                   -           1,443,050                     39%               1,443,050
  2004 (1)                          -                   -           2,608,900                     34%               2,608,900
  2003 (1)                          -                   -           2,033,218                     28%               2,033,218
</TABLE>

Note:
1    Reflects the two-for-one  split of issued and  outstanding  common shares
     that occurred on May 10, 2005 (TSX) and on May 18, 2005 (NYSE).


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  shares is five years, and
shareholdings  include  the net  value of  exercisable  options,  flow-through
shares,  shares  purchased and held within the Nexen Employee Savings Plan and
any other personal holdings. All executives hold the required number of shares
directly or through the net value of their exercisable options. 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
that compare  similar  positions in oil and gas  companies.  Target total cash
compensation  (base salary plus  incentive  bonus) is  competitive  within the
range of the oil and gas comparator group. CEO compensation is approved by the
independent directors of the Board.

Based on the Board  assessment of Mr.  Fischer's  achievement of objectives in
2004,  his base salary was  increased  to  $1,000,000  in April  2005.  He was
awarded a bonus of $900,000 under the annual incentive plan, which was 133% of
his target bonus.

<TABLE>
<CAPTION>
2004 Results                                       Comments                                       Results
-----------------------------------------------------------------------------------------------------------------------
<S>                                                <C>                                           <C>
Financial Performance Measures (50%)
  Net Income (25%)                                 Net Income was $793 million                    Exceeded Target
  Cash Flow (25%)                                  Cash Flow was $1,942 million                   Exceeded Target
Other Key Qualitative and Quantitative Targets
  for Growth and Operation Performance (50%)
  Annual Stock Performance                         5% annual rate of return including dividends   Below Target
  Reserves Growth                                  Reserve life index of 9.2 years                Met Target
  Production Volumes                               250 million barrels of oil equivalent per day  Slightly Below Target
  Operating Costs                                  Operating costs per unit of $6.15              Below Target
  Environment                                      Zero major environmental incidents             Met Target
</TABLE>

Mr. Fischer's responsibility is to provide direction and leadership in setting
and achieving  goals,  which will create value for Nexen's  shareowners in the
short term and the long term. More specifically, his goals in 2005 were to:

o    develop and implement 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 shareowners;
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.


                                      147
<PAGE>

Mr. Fischer was also granted options to purchase 200,000 shares at an exercise
price of $54.57  under the TOP  Plan.  Awards  under the TOP Plan are a direct
link  to  share   performance  and  form  part  of  the  competitive   overall
compensation package.

In 2006,  the Committee  reviewed an analysis of total CEO pay and  shareowner
value created from the date Mr. Fischer became CEO.

CEO TOTAL COMPENSATION--THREE-YEAR LOOK-BACK

<TABLE>
<CAPTION>
                                                           Total 2003-2005             2005            2004              2003
------------------------------------------------------------------------------------------------------------------------------
<S>                                                        <C>                <C>              <C>             <C>
Base Salary                                                      2,547,917          975,000         847,917           725,000
Annual Incentive                                                 3,110,000        1,200,000       1,310,000           600,000
------------------------------------------------------------------------------------------------------------------------------
    Sub-Total Annual                                             5,657,917        2,175,000       2,157,917         1,325,000
CEO Long-Term Compensation
    Value of TOPs Granted under Annual Awards (1)                6,399,490        3,110,490       1,983,000         1,306,000
------------------------------------------------------------------------------------------------------------------------------
Total Direct Compensation                                       12,057,407        5,285,490       4,140,917         2,631,000
Perquisites (Vehicle Allowance)                                     93,600           31,200          31,200            31,200
------------------------------------------------------------------------------------------------------------------------------
Total Consideration Paid/Owing to CEO                           12,151,007        5,316,690       4,172,117         2,662,200
==============================================================================================================================

Annual Average                                                   4,050,336
------------------------------------------------------------------------------------------------------------------------------
Annual Pension Service Cost                                      2,668,000          724,000       1,341,000           603,000
Year-End Market Capitalization (billions)                                              14.5             6.3               5.8
Change over 2003-2005 in Year-End Market Capitalization               249%
</TABLE>

Note:
1    Estimated fair value of TOPs using the Generalized  Black-Scholes  option
     pricing model.


EXTERNAL RECOGNITION AND VERIFICATION

Nexen was named one of the 100 Top  Employers  in Canada by Macleans  magazine
and one of Alberta's Top 20 employers by Mediacorp Canada Inc. in 2005.

INDEPENDENT CONSULTANT

The Committee has engaged Mercer Human Resource Consulting (Mercer) to provide
market data on CEO and other executive officers'  compensation and a technical
analysis  of the  market  data in  light of  Nexen's  compensation  plans  and
practices.  The decisions made by the Committee are the  responsibility of the
Committee  and  may  reflect  factors  and   considerations   other  than  the
information and recommendations provided by Mercer.

In  addition  to  this  mandate,  Mercer  provided  limited  general  employee
compensation  consulting  services to Nexen during the year.  In 2005,  Mercer
conducted  a  compensation  practices  survey on behalf of Nexen,  completed a
small research project and a brief review of Nexen's savings plan in the UK.

For 2005, Mercer received $33,500 for the independent  assessment of executive
compensation  completed on behalf of the  Committee  and $24,400 for the other
services provided to management.  As well, Nexen has participated in a variety
of compensation surveys both in Canada and in international  locations and has
purchased some of the published results.

Submitted on behalf of the Compensation and Human Resources Committee:

                                                           John Willson, Chair
                                                                Dave Hentschel
                                                                 Barry Jackson
                                                               Francis Saville
                                                                  Dick Thomson
                                                                 Vic Zaleschuk



                                      148
<PAGE>

SHARE PERFORMANCE GRAPH

The following  graph shows five years of change,  ending December 31, 2005, 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.  Our common  shares are included in each of
these indices. [GRAPH OMITTED: Total Return Index Value]

<TABLE>
<CAPTION>
                                                   2000/12    2001/12    2002/12    2003/12    2004/12    2005/12
------------------------------------------------------------------------------------------------------------------
<S>                                                <C>        <C>        <C>        <C>        <C>        <C>
Nexen Inc.                                          100.00      84.76      94.15     130.12     136.11     311.18
S&P/TSX Energy Sector Index                         100.00     106.91     121.60     151.96     197.99     323.58
S&P/TSX Oil & Gas Exploration & Production Index    100.00     103.23     119.92     144.08     202.69     351.97
S&P/TSX Composite Index                             100.00      87.43      76.55      97.01     111.06     137.85

Note:
Assuming an investment of $100 and the reinvestment of dividends.
</TABLE>

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, 2005.

<TABLE>
<CAPTION>
                                                                                    # of Shares
Name and Address of Beneficial Owner                                         Beneficially Owned       % of Shares
------------------------------------------------------------------------------------------------------------------
<S>                                                                                  <C>                     <C>
Jarislowsky Fraser Limited (1)
Suite 2005, 1010 Sherbrooke Street West
Montreal, Quebec, Canada, H3A 2R7                                                    36,163,441              13.8
------------------------------------------------------------------------------------------------------------------
Ontario Teachers' Pension Plan Board (2)
5650 Yonge Street
Toronto, Ontario, Canada, M2M 4H5                                                    30,088,836              11.5
------------------------------------------------------------------------------------------------------------------
Capital Research and Management Co. (3)
333 South Hope Street, 55 Floor
Los Angeles, California, USA, 90071-1406                                             14,206,170               5.4
------------------------------------------------------------------------------------------------------------------
</TABLE>

Notes:
1    The beneficial owner has sole voting power over 30,636,605 shares, shared
     voting  power  over  5,526,836  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 voting power over 5,712,000  shares,  sole
     power  to  dispose  of all  shares  and  disclaims  beneficial  ownership
     pursuant to Rule 13d-4.


                                     149
<PAGE>

SECURITY OWNERSHIP OF MANAGEMENT

At February 17, 2006, the following directors, certain executive officers, and
all  directors  and  executive  officers  as a group  beneficially  owned  the
following Nexen common shares:


<TABLE>
<CAPTION>
                                                                                           Exercisable
Name of Beneficial Owner                                           Number of Shares (1)    Stock Options (2)
------------------------------------------------------------------------------------------------------------
<S>                                                                <C>                    <C>
Charles W. Fischer                                                           74,440          1,146,000
Dennis G. Flanagan                                                           12,002             13,630
David A. Hentschel                                                           11,354             74,000
S. Barry Jackson                                                             12,000             24,000
Kevin J. Jenkins                                                              6,154             41,000
Eric P. Newell, O.C.                                                          6,000                Nil
Thomas C. O'Neill                                                             8,000             11,000
Francis M. Saville, Q.C.                                                     20,800             39,132
Richard M. Thomson, O.C.                                                     46,002            111,200
John M. Willson                                                              14,002              3,666
Victor J. Zaleschuk                                                          31,410            144,000
Laurence Murphy                                                              48,376             99,880
Douglas B. Otten                                                             55,873            171,460
Marvin F. Romanow                                                            46,254            492,460
Roger D. Thomas                                                               1,527            160,080
Thomas A. Sugalski                                                               34                Nil
All directors and executive officers as a group (22 persons)                491,815          2,975,268
</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 17, 2006. 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>
                                                                                                              Number of Securities
                                                    Number of Securities to         Weighted-Average       Remaining Available for
                                                   be issued on Exercise of        Exercise Price of  Future Issuance under Equity
Plan Category                                           Outstanding Options      Outstanding Options            Compensation Plans
-----------------------------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>                        <C>                      <C>
Equity compensation plans approved by shareowners                15,314,575               $28/option                    17,290,038
Equity compensation plans not approved by
  shareowners                                                           nil                      nil                           nil
-----------------------------------------------------------------------------------------------------------------------------------
Total                                                            15,314,575               $28/option                    17,290,038
===================================================================================================================================
</TABLE>

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 then, 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 by  Nexen to FMC.  In
addition, he is an independent director pursuant to our Categorical Standards.

Pursuant to a short-form  prospectus dated October 4, 2005,  Ontario Teachers'
Pension  Plan  Board  (Teachers)  sold  7,500,000  shares  of Nexen  for gross
proceeds of $406,785,000 by way of a secondary public offering.  Teachers paid
or reimbursed Nexen for legal, audit and filing fees in an aggregate amount of
$635,000.


                                      150
<PAGE>

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

In connection with its responsibilities, the Audit and Conduct Review Committee:

o    met with management and the independent auditor to review and discuss the
     December 31, 2005 Consolidated Financial Statements;
o    discussed with the independent  auditor the matters  required by Canadian
     regulators  according to 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  according  to  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  according  to  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, 2005.

AUDIT FEES

<TABLE>
<CAPTION>
                                                                                                              Percentage of Total
Type of Fee                                                              Billed in 2004       Billed in 2005  Fees Billed in 2005
----------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                <C>                  <C>                  <C>
Audit Fees
  For the Audit of Nexen's Consolidated Financial Statements
    Included in our Annual Report on Form 10-K                               $1,041,000             $806,500 (1)
  For the First, Second and Third Quarter Reviews of
    Nexen's Consolidated Financial Statements Included in Form 10-Qs            $45,000              $69,000
  For Comfort Letters and Submissions to Commissions                             $9,500             $149,000
  For the Audit of Internal Control Over Financial Reporting                   $630,000           $1,269,000 (2)
----------------------------------------------------------------------------------------------------------------------------------
Total Audit Fees                                                             $1,725,500           $2,293,500                  66%

Audit-Related Fees
  For the Annual Audits and Quarterly Reviews of our Subsidiary
    Financial Statements and Employee Benefit Plans                            $296,000             $466,500
  For Audit-Related Work in Connection with Acquisitions
    and Divestitures                                                                Nil             $391,000
----------------------------------------------------------------------------------------------------------------------------------
Total Audit-Related Fees                                                       $296,000             $857,500                  25%

Tax Fees
  For Tax Return Preparation Assistance and Tax-Related Consultation            $60,000             $234,000
----------------------------------------------------------------------------------------------------------------------------------
Total Tax Fees                                                                  $60,000             $234,000                   7%

All Other Fees                                                                      Nil              $66,000 (3)               2%
----------------------------------------------------------------------------------------------------------------------------------
Total Annual Fees                                                            $2,081,500           $3,451,000                 100%
==================================================================================================================================
</TABLE>

Notes:
1    Consisting  of  $336,500  to  complete  the 2004  audit and  $470,000  to
     commence the 2005 audit.
2    Consisting  of  $549,000  to  complete  the 2004  audit and  $720,000  to
     commence the 2005 audit.
3    Annual renewal fees for an upstream  information  database used in our UK
     office.


AUDIT & CONDUCT REVIEW 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,  tax and other 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:

                                                            Tom O'Neill, Chair
                                                               Dennis Flanagan
                                                                Dave Hentschel
                                                                 Barry Jackson
                                                                 Kevin Jenkins
                                                                  Dick Thomson


                                      151
<PAGE>

                                    PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

FINANCIAL STATEMENTS AND SCHEDULES

We refer you to the index to Financial  Statements and  Supplementary  Data in
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 (U.K.)  Limited,  between
      EnCana (U.K.) 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).
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).
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).
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).
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).
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).
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).
3.12  Certificate  of  Amendment  dated April 28, 2005 to effect a division of
      the issued and outstanding  common shares of the Registrant on the basis
      of a two-for-one common share held (filed as Exhibit 3(i)(a) to Form 8-K
      dated May 2, 2005).
3.13  Articles of  Amendment  dated April 28, 2005 to effect a division of the
      issued and outstanding common shares of the Registrant on the basis of a
      two-for-one  common  share held  (filed as  Exhibit  3(i)(b) to Form 8-K
      dated May 2, 2005).
3.14  Restated  Certificate  and Articles of  Incorporation  of the Registrant
      dated May 20, 2005 (filed as Exhibit 3.12 to Form 10-Q for the quarterly
      period ended June 30, 2005).
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).
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).
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).

                                      152
<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).
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).
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).
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).
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).
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).
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).
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).
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).
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).
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).
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).
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).
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).
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).

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<PAGE>

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).
4.53  Fifth Supplemental Indenture dated March 10, 2005 to the Trust Indenture
      dated April 28,  1998,  between  the  Registrant  and CIBC Mellon  Trust
      Company  pertaining to the issuance of US$250  million,  5.20% notes due
      2015 and the issuance of US$790 million, 5.875% notes due 2035 (filed as
      Exhibit 10.1 to Form 8-K dated March 11, 2005).
4.54* Amended and Restated  Shareholder  Rights Plan Agreement dated April 27,
      2005 between the  Registrant  and CIBC Mellon Trust  Company,  as Rights
      Agent, which includes the Form of Rights Certificate as Exhibit A.
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).
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).
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).
10.43 Credit  Agreement  dated as of July 22, 2005 between the  Registrant and
      the Toronto  Dominion Bank, as Agent,  and the Lenders (filed as Exhibit
      10.1 to Form 8-K dated July 28, 2005).
10.44 Guarantee  dated  as of  July  22,  2005  as  Schedule  K to the  Credit
      Agreement (filed as Exhibit 10.2 to Form 8-K dated July 28, 2005).
10.45 Termination of Employment and Special  Separation  Agreement between the
      Registrant  and Mr.  Sugalski  dated  January 28, 2005 (filed as Exhibit
      10.1 to Form 8-K/A dated August 18, 2005).
11.1* Statement  regarding the Computation of Per Share Earnings for the three
      years ended December 31, 2005.
16.1  Letter re change in certifying accountant (filed as Exhibit 16.1 to Form
      8-K filed July 17, 2002).
21.1* Subsidiaries of the Registrant.
23.1* Consent of Independent Registered Chartered Accountants.
31.1* Certification of Chief Executive  Officer pursuant to Section 302 of the
      Sarbanes-Oxley Act of 2002.
31.2* Certification of Chief Financial  Officer pursuant to Section 302 of the
      Sarbanes-Oxley Act of 2002.
32.1* Certification of periodic report by Chief Executive  Officer pursuant to
      18 U.S.C.,  Section  1350,  as adopted  pursuant  to Section  906 of the
      Sarbanes-Oxley Act of 2002.
32.2* Certification of periodic report by Chief Financial  Officer pursuant to
      18 U.S.C.,  Section  1350,  as adopted  pursuant  to Section  906 of the
      Sarbanes-Oxley Act of 2002.
99.1* Opinion of Internal Qualified Reserves Evaluator on National  Instrument
      51-101  Form F2 as required by certain  Canadian  securities  regulatory
      authorities.

     * Filed with this 10-K.


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<PAGE>

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934,  the  Company  has duly  caused  this  report to be signed on its
behalf by the undersigned, thereunto duly authorized, on February 23, 2006.


                                     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 February 23, 2006.

/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/ Marvin F. Romanow
/s/ S. Barry Jackson                 ---------------------
--------------------                 Marvin F. Romanow
S. Barry Jackson, Director           Executive Vice President and
                                     Chief Financial Officer
/s/ Kevin J. Jenkins                 (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/ Francis M. Saville               /s/ John B. McWilliams
----------------------               ----------------------
Francis M. Saville, Director         John B. McWilliams
                                     Senior Vice President,
/s/ Richard M. Thomson               General Counsel and Secretary
----------------------
Richard M. Thomson, Director
                                     /s/ Kevin J. Reinhart
/s/ John M. Willson                  ---------------------
-------------------                  Kevin J. Reinhart
John M. Willson, Director            Vice President, Corporate Planning
                                     and Business Development
/s/ Victor J. Zaleschuk
-----------------------
Victor J. Zaleschuk, Director




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