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

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

                     FOR THE YEAR ENDED DECEMBER 31, 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:


             TITLE                                 EXCHANGE REGISTERED ON
             -----                                 ----------------------
       Common shares, no par value               The New York Stock Exchange
                                                 The Toronto Stock Exchange
       Subordinated Securities, due 2043         The New York Stock Exchange
                                                 The Toronto Stock Exchange


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

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

                    Yes    [X]               No   [_]

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

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

                    Yes    [X]               No   [_]

On June 30,  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>

                                EXPLANATORY NOTE

This Amendment No. 1 on Form 10-K/A (this "Amendment") amends the Annual Report
on Form 10-K for the year ended  December  31, 2005 filed on February  23, 2006
(the "Original  Filing").  Nexen, Inc. (the "Company") has filed this Amendment
to incorporate  textual changes in Items 1 and 2, Business and  Properties,  in
Item 7, Management's Discussion and Analysis of Financial Condition and Results
of Operations,  in Item 7A,  Quantitative  and  Qualitative  Disclosures  about
Market Risk regarding our reserves process and risk factors.  We made a textual
change  in Item 8,  Financial  Statements  and  Supplementary  Data  (Note  21-
Differences Between Canadian and U.S. Generally Accepted Accounting Principles,
page 110) regarding our  modification of the tandem option plan. This Amendment
has no effect on the Consolidated  Balance Sheets,  Consolidated  Statements of
Income,  Consolidated  Statement of Cash Flows, and Consolidated  Statements of
Changes in Shareholders'  Equity,  and more  specifically,  does not affect net
income,  earnings per share,  total cash flows,  current assets,  total assets,
current  liabilities,  total  shareholders'  equity  or  other  information  as
presented in the Original Filing.

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


                                       1
<PAGE>

                               TABLE OF CONTENTS

PART I                                                                     PAGE
       Items 1 and 2.   Business and Properties                               3

PART II
       Item 7.          Management's Discussion and Analysis of
                             Financial Condition and Results of Operation    24
       Item 7A.         Quantitative and Qualitative Disclosures
                             about Market Risk                               64
       Item 8           Financial Statements and Supplementary Data.         70

Special Note to Canadian Investors - see page 69

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

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,  upon request, by contacting our
investor  relations  department  at  (403)  699-5931.  As  soon  as  reasonably
practicable,  our  filings  are made  available  on our  website  once they are
electronically  filed with the SEC or the OSC.  Alternatively,  the SEC and the
OSC each maintain a website  (www.sec.gov and  www.sedar.com)  that contain our
reports,  proxy and information statements and other published information that
have been filed or furnished with the SEC and the OSC.


                                       2
<PAGE>

PART I

ITEMS 1 AND 2.  BUSINESS AND PROPERTIES


                                                                          Page

About Us ....................................................................4

Strategy ....................................................................5

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

Oil and Gas Operations
    North Sea--United Kingdom ...............................................6
    Gulf of Mexico--United States ...........................................7
    Canada ..................................................................9
    Athabasca Oil Sands .....................................................9
    Middle East--Yemen .....................................................12
    Offshore West Africa ...................................................13
    Other International ....................................................14

Reserves, Production and Related Information ...............................14

Syncrude Mining Operations .................................................18

Oil and Gas Marketing ......................................................20

Chemicals ..................................................................22

Additional Factors Affecting Business
    Government Regulations .................................................23
    Environmental Regulations ..............................................23

Employees ..................................................................23





                                       3
<PAGE>

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.

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.

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

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

Our oil and gas  operations  are broken down  geographically  into the 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.

                                       4
<PAGE>

STRATEGY

Our goal is to grow long-term value for shareholders. We define value growth as
increasing reserves, production and cash flow over the long term. 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.

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.

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.

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 the adverse  impact of  negative  price
changes by investing in projects that we believe will generate positive returns
at relatively low commodity prices.

We  also  have a broad  customer  base  for our  crude  oil  and  natural  gas.
Alternative customers are generally available, and the loss of any one customer
is not  expected  to have a  significant  adverse  effect  on the  price of our
products or our revenues.  Oil and gas producing  operations  are generally not
seasonal.  However,  demand  for  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.

                                       5
<PAGE>

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.

In this Form 10-K/A,  we provide  estimates of remaining  quantities of oil and
gas  reserves  for  our  various  properties.  Such  estimates  are  internally
prepared.  We had 96% of our oil and gas and Syncrude reserves before royalties
(96% after  royalties)  assessed  (either  evaluated or audited as described on
page 17) by independent reserves  consultants.  Their assessments are performed
at varying levels of property  aggregation,  and we work with them to reconcile
the  differences on the portfolio of properties to within 10% in the aggregate.
Estimates pertaining to individual properties within the portfolio often differ
by significantly  more than 10%, either positively or negatively;  however,  we
believe  such  differences  are  not  material  relative  to our  total  proved
reserves.  Refer to the section on Critical Accounting  Estimates - Oil and Gas
Accounting  -  Reserves  Determination  on  page  59 for a  description  of our
reserves  process,  and to the  section on  Reserves,  Production  and  Related
Information  on  page 17 for a  description  of the  nature  and  scope  of the
independent assessments performed and the results thereof.


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

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

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
improve reliability and extend facility life. Upgrades included improvements to
electric, produced water injection, and drilling and metering systems. In 2006,

                                       6
<PAGE>

we plan to invest  approximately  $35  million to drill,  complete,  and tie-in
three development wells and perform workovers.

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>

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

UK fiscal terms are favourable.  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.

GULF OF MEXICO--UNITED STATES (US)

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.

                                       7
<PAGE>

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.

<TABLE>
<CAPTION>
US PRODUCTION
----------------------------------------------- -------------------------------- ---------------------------------
                              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             4.6             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.

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.

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.

                                       8
<PAGE>

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>

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%.

CANADA

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

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.

                                       9
<PAGE>

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  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.

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.

OUR STRATEGIC ADVANTAGE

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  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

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.

                                      10
<PAGE>

FUTURE PHASES

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 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.

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.

                                      11
<PAGE>

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.

MIDDLE EAST--YEMEN

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
12,700 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)

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.

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,  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%.

                                      12
<PAGE>

EAST AL HAJR BLOCK (BLOCK 51)

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 balance                                  75% per year, declining
--------------------------------------------------------------------------------
Development balance                                  75% per year, declining
--------------------------------------------------------------------------------

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%.

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.

OFFSHORE WEST AFRICA

Offshore West Africa is a growing core area where we already have  discoveries.
It offers  prolific  reservoirs  and multiple  opportunities  to invest in this
oil-rich region.  Our strategy here is to explore and develop our portfolio for
medium- to long-term growth.

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>

                                      13
<PAGE>

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.

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

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%.

                                      14
<PAGE>

<TABLE>
<CAPTION>
Sales Prices and Production Costs (excluding Syncrude)
---------------------------------------------------------------------------------------------------------------------
                                      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.)

<TABLE>
<CAPTION>
Producing Oil and Gas Wells
-----------------------------------------------------------------------------------------------------------------------
                                                                       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.

<TABLE>
<CAPTION>
Oil and Gas Acreage
------------------------------------------------------------------------------------------------------------------------
                                                                        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.

                                      15
<PAGE>

<TABLE>
<CAPTION>
Drilling Activity
-----------------------------------------------------------------------------------------------------------------------
                                                                         2005
-----------------------------------------------------------------------------------------------------------------------
                                          Net Exploratory                       Net Development              Total
-----------------------------------------------------------------------------------------------------------------------
(number of net wells)                               Dry                Productive
                                  Productive      Holes      Total          Holes          Dry        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
-----------------------------------------------------------------------------------------------------------------------

-----------------------------------------------------------------------------------------------------------------------
                                                                         2004
-----------------------------------------------------------------------------------------------------------------------
                                          Net Exploratory                       Net Development              Total
-----------------------------------------------------------------------------------------------------------------------
(number of net wells)                               Dry                Productive
                                  Productive      Holes      Total          Holes          Dry        Total
-----------------------------------------------------------------------------------------------------------------------
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
-----------------------------------------------------------------------------------------------------------------------

-----------------------------------------------------------------------------------------------------------------------
                                                                         2003
-----------------------------------------------------------------------------------------------------------------------
                                          Net Exploratory                       Net Development              Total
-----------------------------------------------------------------------------------------------------------------------
(number of net wells)                               Dry                Productive
                                  Productive      Holes      Total          Holes          Dry        Total
-----------------------------------------------------------------------------------------------------------------------
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).

                                      16
<PAGE>

RESERVES

PROVED UNDEVELOPED RESERVES

The  following  table  provides a summary of our  proved  undeveloped  reserves
(PUDs) at December 31, 2005:

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
                                               Before Royalties                    After Royalties
-----------------------------------------------------------------------------------------------------------
(mmboe)                                                Total         % of                  Total      % of
                                            PUDs      Proved        Total        PUDs     Proved     Total
-----------------------------------------------------------------------------------------------------------
<S>                                          <C>         <C>           <C>        <C>        <C>        <C>
United Kingdom                               128         145           88         128        145        88
-----------------------------------------------------------------------------------------------------------
Yemen                                         23         105           22          13         59        22
-----------------------------------------------------------------------------------------------------------
United States                                 15          90           17          13         77        17
-----------------------------------------------------------------------------------------------------------
Canada                                        13         117           11          11        101        11
-----------------------------------------------------------------------------------------------------------
Other                                          1          11            5           -         11         5
-----------------------------------------------------------------------------------------------------------
                                             180         468           38         165        393        42
-----------------------------------------------------------------------------------------------------------
</TABLE>

In the United Kingdom, the PUDs relate almost entirely to our Buzzard Field. We
are in the process of drilling and  completing the initial  development  wells.
Construction and  installation of the facilities is complete and  commissioning
work is  underway.  The field came  on-stream in early 2007.  This  activity is
expected  to  result  in 75% of the PUDs  being  converted  to  producing  upon
start-up of the facility.  The  remaining  PUDs are expected to be converted to
producing  over the next 4 years as we drill the  remaining  development  wells
based on available facility capacity.

In Yemen, the PUDs are split relatively  equally between our Masila and East Al
Hajr Blocks.  These reserves relate entirely to infill drilling,  some of which
occured during 2006 and is planned for 2007.

In the  United  States,  the PUDs are  split  equally  between  our  Shelf  and
deep-water activities. The majority of these reserves relate to infill drilling
programs on 11  properties.  These programs are either taking place during 2006
or are  planned  for 2007.  In  addition,  a portion of the PUDs  relate to our
deep-water Wrigley subsea tie-back development which is currently underway.

In Canada, the majority of the PUDs relate to infill drilling, recompletions or
facilities  enhancements  on our various heavy oil and natural gas fields.  The
majority of these PUDs are expected to be  converted  to producing  reserves in
2006 and 2007.  A small  portion  of the PUDs  relate  to our Coal Bed  Methane
properties which are expected to be converted to producing from infill drilling
and field development from activities in 2006 or planned for 2007.

In total,  we expect to convert  about 85% of these PUDs to producing  over the
next 3  years.  At the  same  time,  we  expect  our  ongoing  exploration  and
development activities to continue to add new PUDs.

Reserve estimates in this report are internally prepared.  Refer to the section
on  Critical  Accounting   Estimates  -  Oil  and  Gas  Accounting  -  Reserves
Determination  on  page  59 for a  description  of  our  reserves  process.  As
described  therein,  we have at least 80% of our oil and gas reserves estimates
either  evaluated  or  audited  annually  by  independent   qualified  reserves
consultants.  The nature and scope of the  evaluations and audits is determined
by agreement between us and the engineering firm.  Independent  assessments for
other companies may, therefore, be different.

BASIS OF RESERVES ESTIMATES

The following  provides an overview of the nature and scope of the  independent
evaluations and audits that we have performed.  An independent  evaluation is a
process  whereby  we  request a  third-party  engineering  firm to  prepare  an
estimate of our reserves by assessing and  interpreting all available data on a
reservoir.  An independent  audit is a process whereby we request a third party
engineering  firm to prepare an  estimate  of our  reserves  by  reviewing  our
estimates,  supporting working papers and other data as they feel is necessary.
The primary  difference  is that an auditor  reviews  our work and  estimate in
preparing  their  estimate  whereas an  evaluator  uses the  reservoir  data to
prepare their estimate.

In  each  case,  we  request  their  estimate  to be  prepared  using  standard
geological  and  engineering   methods  generally  accepted  by  the  petroleum
industry. Generally accepted methods for estimating reserves include volumetric
calculations,  material  balance  techniques,  production and pressure  decline
curve analysis,  analogy with similar reservoirs, and reservoir simulation. The
method or combination of methods used is based on their professional  judgement
and experience.  In preparing their estimates,  they obtain information from us
with respect to property  interests,  production from such properties,  current
costs of operations,  future  development and  abandonment,  current prices for
production,  agreements  relating to current and future  operations and sale of
production,  and  various  other  information  and  data.  They may rely on the
information  without  independent  verification.  However,  if in the course of
their  evaluation they question the validity or sufficiency of any information,
we request that they do not rely on such information until they  satisfactorily
resolve their questions or  independently  verify such  information.  We do not
place any  limitations  on the work to be performed.  Upon  completion of their

                                      17
<PAGE>

work, the independent  evaluator or auditor issues an opinion as to whether our
estimate  of the  proved  reserves  for that  portfolio  of  properties  is, in
aggregate, reasonable relative to the criteria set forth in SEC Rule 4-10(a)(2)
of  Regulation  S-X.  These  rules  define  proved  reserves  as the  estimated
quantities of oil and gas which  geological and  engineering  data  demonstrate
with  reasonable  certainty  to be  recoverable  in  future  years  from  known
reservoirs under existing economic and operating conditions.

Our estimate may differ from the  independent  evaluators  and auditors as they
apply their professional judgement and experience, which may result in applying
different  estimating  methods or  interpreting  data  differently  than us. We
believe our estimate for a portfolio of properties is reasonable when it is, in
aggregate, within 10% of the independent evaluator or auditor.

We engaged  DeGolyer and  MacNaughton  ("D&M") to evaluate 100% of our reserves
before  royalties (100% after  royalties) for the United Kingdom,  Yemen Masila
and Yemen  Block 51. A separate  opinion  was  provided  on each of these three
areas.  D&M  provided an opinion on each of the areas that the proved  reserves
estimate  prepared by us is, in  aggregate,  reasonable  when compared to their
estimate which was prepared in accordance with SEC Rules.

We engaged McDaniel & Associates  Consultants Ltd. ("McDaniel") to evaluate 91%
of our Canadian  conventional  and CBM  reserves  before  royalties  (91% after
royalties) and to audit 100% of our Syncrude mining  reserves before  royalties
(100% after royalties). The properties were selected by management and reviewed
with the Reserves Review Committee of the Board.  All material  properties were
selected.  McDaniel provided an opinion on the combined Canadian  conventional,
CBM and Syncrude  reserves that the proved reserves estimate prepared by us is,
in  aggregate,  within 10% of their  estimate  which was prepared in accordance
with SEC Rules.

We engaged Ryder Scott Company ("Ryder Scott") to audit 76% of our U.S. Gulf of
Mexico shelf reserves before  royalties (76% after  royalties).  The properties
were selected by management and reviewed with the Reserves Review  Committee of
the Board.  All material  properties  were  selected.  Ryder Scott  provided an
opinion that the difference between their estimate and ours is within the range
of  reasonable  differences  and that  the  estimates  have  been  prepared  in
accordance with SEC Rules.

We engaged  William M. Cobb &  Associates,  Inc.  ("Cobb") to audit 100% of our
U.S.  Gulf  of  Mexico   deep-water   reserves  before  royalties  (100%  after
royalties). Cobb provided an opinion that the difference between their estimate
and ours is within the range of reasonable  differences  and that the estimates
have been prepared in accordance with SEC Rules.

SYNCRUDE MINING OPERATIONS

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

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.

                                      18
<PAGE>

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  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.

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).

                                      19
<PAGE>

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.

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

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.

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

                                      20
<PAGE>

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.

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

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

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.

                                      21
<PAGE>

CHEMICALS

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.

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

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.

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.

                                      22
<PAGE>

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

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.

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.


                                      23
<PAGE>

PART II

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

                                                                           Page

Executive Summary of 2005 Results ...........................................25

Capital Investment ..........................................................26

Financial Results
    Year-to-Year Change in Net Income .......................................30
    Oil & Gas and Syncrude
        Production ..........................................................31
        Commodity Prices ....................................................34
        Operating Costs .....................................................36
        Depreciation, Depletion, Amortization and Impairment ................37
        Exploration Expense .................................................38
    Oil & Gas and Syncrude Netbacks .........................................40
    Oil and Gas Marketing ...................................................41
    Chemicals ...............................................................43
    Corporate Expenses ......................................................44

Outlook for 2006 ............................................................46

Liquidity and Capital Resources .............................................48

Risk Factors ................................................................53

Critical Accounting Estimates ...............................................59

Quantitative and Qualitative Disclosures about Market Risk ..................64

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 69 which highlights  differences between our reserve estimates and related
disclosures that are otherwise required by Canadian regulatory authorities.

                                      24
<PAGE>

<TABLE>
<CAPTION>
EXECUTIVE SUMMARY OF 2005 RESULTS
-----------------------------------------------------------------------------------------
 (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.

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.  Our Long Lake  project  is now more than 30%
complete and 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.

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.

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

                                      25
<PAGE>

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.

During 2005, our proved oil and gas and Syncrude  reserves  additions  replaced
the  majority of our 2005 oil and gas and Syncrude  production  as shown in the
following table:

------------------------------------------------------------------------------
                                                             Before      After
(mmboe)                                                   Royalties  Royalties
------------------------------------------------------------------------------
Production
------------------------------------------------------------------------------
    Oil and Gas                                                  84        57
------------------------------------------------------------------------------
    Syncrude                                                      6         6
------------------------------------------------------------------------------
                                                                 90        63
------------------------------------------------------------------------------
Additions
------------------------------------------------------------------------------
    Oil and Gas                                                  59        41
------------------------------------------------------------------------------
    Syncrude                                                     23        15
------------------------------------------------------------------------------
                                                                 82        56
------------------------------------------------------------------------------

Our  major  development  activities,   principally  at  Buzzard  and  Syncrude,
contributed 45 mmboe of the additions (36 mmboe after royalties). Reserves were
also added from ongoing  exploitation in Yemen,  Canada, the Gulf of Mexico and
the North  Sea.  Similar  to last  year,  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.

We also sold 49 mmboe of proved  reserves (41 mmboe after  royalties) 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
-------------------------------------------------------------------------------
 (Cdn$ millions)                                Estimated 2006    2005    2004
-------------------------------------------------------------------------------
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
-------------------------------------------------------------------------------

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.

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.

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.

<TABLE>
<CAPTION>
2005 INVESTMENT PROGRAM
----------------------------------------------------------------------------------------------------------------
(Cdn$ millions)                                                                  New
                                                Major      Early Stage        Growth     Core Asset
                                          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%
----------------------------------------------------------------------------------------------------------------

<CAPTION>
2006 ESTIMATED CAPITAL
----------------------------------------------------------------------------------------------------------------
(Cdn$ millions)                                                                  New
                                                Major      Early Stage        Growth     Core Asset
                                          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>

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.

SYNTHETIC

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

                                       27
<PAGE>

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

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 approximately 150 mmcf/d 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.

NEW GROWTH EXPLORATION

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.

                                       28
<PAGE>

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.

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.


                                       29
<PAGE>

FINANCIAL RESULTS

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

------------------------------------------------------------------------------------------------------------
                                                                                                  MD&A PAGE
(Cdn$                                                             2005 vs 2004   2004 vs 2003     REFERENCE
millions)
------------------------------------------------------------------------------------------------------------
<S>                                                               <C>            <C>              <C>
Net Income for 2004 and 2003 (1)                                           793            578
------------------------------------------------------------------------------------------------------------
Favourable (unfavourable) variances:
------------------------------------------------------------------------------------------------------------
Cash Items
------------------------------------------------------------------------------------------------------------
  Production Volumes, After Royalties
------------------------------------------------------------------------------------------------------------
    Crude Oil                                                               39           (116)
------------------------------------------------------------------------------------------------------------
    Natural Gas                                                            (55)            (8)
------------------------------------------------------------------------------------------------------------
    Change in Crude Oil Inventory                                            4             40
------------------------------------------------------------------------------------------------------------
      Total Volume Variance                                                (12)           (84)       page 31
------------------------------------------------------------------------------------------------------------
  Realized Commodity Prices
------------------------------------------------------------------------------------------------------------
    Crude Oil                                                              648            365
------------------------------------------------------------------------------------------------------------
    Natural Gas                                                            165              -
------------------------------------------------------------------------------------------------------------
      Total Price Variance                                                 813            365        page 34
------------------------------------------------------------------------------------------------------------
  Oil and Gas Operating Expense
------------------------------------------------------------------------------------------------------------
    Conventional                                                           (64)           (55)
------------------------------------------------------------------------------------------------------------
    Synthetic                                                              (27)            (2)
------------------------------------------------------------------------------------------------------------
      Total Operating Expense Variance                                     (91)           (57)       page 36
------------------------------------------------------------------------------------------------------------
  Marketing Contribution                                                    49            (14)       page 41
------------------------------------------------------------------------------------------------------------
  Chemicals Contribution                                                    31             10        page 43
------------------------------------------------------------------------------------------------------------
  General and Administrative                                               (96)           (30)       page 44
------------------------------------------------------------------------------------------------------------
  General and Administrative--Stock-Based Compensation Paid                (60)            (9)
------------------------------------------------------------------------------------------------------------
  Interest Expense                                                          46             26        page 45
------------------------------------------------------------------------------------------------------------
  Current Income Taxes                                                     (91)           (38)       page 45
------------------------------------------------------------------------------------------------------------
  Other                                                                    (69)           (22)
------------------------------------------------------------------------------------------------------------
Total Cash Variance                                                        520            147
------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------
Non-Cash Items
------------------------------------------------------------------------------------------------------------
  Depreciation, Depletion, Amortization and  Impairment                                              page 37
------------------------------------------------------------------------------------------------------------
    Oil & Gas and Syncrude                                                (308)           271
------------------------------------------------------------------------------------------------------------
Other                                                                      (19)            13
------------------------------------------------------------------------------------------------------------
  Exploration Expense                                                       (5)           (45)       page 38
------------------------------------------------------------------------------------------------------------
  General and Administrative--Stock-Based Compensation Accrual            (337)           (70)       page 44
------------------------------------------------------------------------------------------------------------
  Future Income Taxes                                                      348           (176)       page 45
------------------------------------------------------------------------------------------------------------
  Increase (Decrease) in Fair Value of Crude Oil Put Options              (252)            56        page 46
------------------------------------------------------------------------------------------------------------
  Gains from Divestiture Programs                                          418              -        page 46
------------------------------------------------------------------------------------------------------------
Other                                                                       (6)            19
------------------------------------------------------------------------------------------------------------
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 46.

                                       30
<PAGE>

<TABLE>
<CAPTION>
OIL & GAS AND SYNCRUDE

PRODUCTION
---------------------------------------------------------------------------------------------------------------------------
                                             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

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.


                                       31
<PAGE>

<TABLE>
<CAPTION>
The following table summarizes our production changes year over year:

---------------------------------------------------------------------------------------------
 (mboe/d)                                                Before Royalties    After Royalties
---------------------------------------------------------------------------------------------
<C>                                                                   <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>

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

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

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.

                                       32
<PAGE>

NORTH SEA

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

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.


                                      33
<PAGE>

<TABLE>
<CAPTION>
COMMODITY PRICES
---------------------------------------------------------------------------------------------
                                                              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

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.


                                      34
<PAGE>

CRUDE OIL REFERENCE PRICES

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.

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

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.

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

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.

                                      35
<PAGE>

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).

<TABLE>
<CAPTION>
OPERATING COSTS
-------------------------------------------------------------------------------------------------------------------------------
                                                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>
-------------------------------------------------------------------------------------------------------------------------------
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

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.

                                      36
<PAGE>

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.

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.

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.

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

                                      37
<PAGE>

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

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.

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.

<TABLE>
<CAPTION>
EXPLORATION EXPENSE (1)
--------------------------------------------------------------------------------------
(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.

                                      38
<PAGE>

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.

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-commerical 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.

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.


                                      39
<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.

<TABLE>
<CAPTION>
BEFORE ROYALTIES
-------------------------------------------------------------------------------------------------------------------
                                                 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
-------------------------------------------------------------------------------------------------------------------

<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)     (7.36)
-------------------------------------------------------------------------------------------------------------------
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
-------------------------------------------------------------------------------------------------------------------

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

<CAPTION>
AFTER ROYALTIES
-------------------------------------------------------------------------------------------------------------------
                                                 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
-------------------------------------------------------------------------------------------------------------------

<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
-------------------------------------------------------------------------------------------------------------------

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

                                      40
<PAGE>

OIL AND GAS MARKETING
--------------------------------------------------------------------------------
 (Cdn$ millions)                                      2005      2004       2003
--------------------------------------------------------------------------------
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
--------------------------------------------------------------------------------
Note:
(1)  Excludes intra-segment transactions.


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

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.

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.

                                      41
<PAGE>

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

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.

<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  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.

                                      42
<PAGE>

<TABLE>
<CAPTION>
CHANGES IN FAIR VALUE OF DERIVATIVE CONTRACTS
--------------------------------------------------------------------------------------------------------------------------
                                                                                  Contracts         Contracts
(Cdn$ millions)                                                              Outstanding at      Entered into
                                                                          Beginning of Year       During Year       Total
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                          <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                           169
--------------------------------------------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------------------------------
  Unrecognized Losses on Hedges of Future Sale of Gas Inventory at December 31,                                      (35)
2005
--------------------------------------------------------------------------------------------------------------------------
Total Outstanding at December 31, 2005                                                                                134
--------------------------------------------------------------------------------------------------------------------------
</TABLE>
Note:
(1)  Our valuation methodology has been applied consistently year-over-year.

<TABLE>
<CAPTION>
TOTAL CARRYING VALUE OF DERIVATIVE CONTRACTS
--------------------------------------------------------------------------------------------------------------------------
 (Cdn$ millions)                                                                                          2005        2004
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                       <C>         <C>
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
--------------------------------------------------------------------------------------------------------------------------
</TABLE>
Note:
(1)  Excludes  derivative  contracts  that have been  designated  as accounting
     hedges.

NON-TRADING ACTIVITIES

We enter into fee-for-service contracts related to transportation and storage of
third-party oil and gas. We also earn income from our power generation facility.
We  earned  $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.

<TABLE>
<CAPTION>
CHEMICALS
--------------------------------------------------------------------------------------------------------------------------
 (Cdn$ millions)                                                                                  2005      2004     2003
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                                               <C>       <C>      <C>
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                           37        40       28
Taxes
--------------------------------------------------------------------------------------------------------------------------
Capacity Utilization                                                                               96%       95%      95%
--------------------------------------------------------------------------------------------------------------------------
</TABLE>
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

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

                                      43
<PAGE>

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.

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.

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

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.

                                      44
<PAGE>

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

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.

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
-------------------------------------------------------------------------------
 (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%.

                                      45
<PAGE>

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.

OTHER
-------------------------------------------------------------------------------
 (Cdn$ millions)                                          2005    2004    2003
-------------------------------------------------------------------------------
Gain on Dilution of Interest in Chemicals Business         193       -       -
-------------------------------------------------------------------------------
Gain on Disposition of Oil and Gas Asset 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

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

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.

                                      46
<PAGE>

DAILY PRODUCTION

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
-------------------------------------------------------------------------------
                                                      Before            After
(mboe/d)                                            Royalties        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

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.


                                      47
<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.

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:

-------------------------------------------------------------------------------
 (Cdn$ millions)                                               2005       2004
-------------------------------------------------------------------------------
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
-------------------------------------------------------------------------------


                                      48
<PAGE>

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:

-------------------------------------------------------------------------------
 (times)                                                 2005     2004    2003
-------------------------------------------------------------------------------
Net Debt to Cash Flow from Operating Activities           1.7      2.6     1.2
-------------------------------------------------------------------------------
Interest Coverage (1)                                     9.8     11.9    10.1
-------------------------------------------------------------------------------
Note:
(1)  Earnings before interest,  taxes, DD&A and exploration  expense divided by
     interest expense (before capitalized interest).


Our  business  strategy is focused on  value-based  growth  through  full-cycle
exploration  and  development,  supplemented  by  strategic  acquisitions  when
appropriate.  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
-------------------------------------------------------------------------------
                                                                     Increase/
(Cdn$ millions)                                   2005       2004   (Decrease)
-------------------------------------------------------------------------------
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)
-------------------------------------------------------------------------------

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

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.

                                      49
<PAGE>

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.

<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

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 46.

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 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.

                                      50
<PAGE>

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:

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------
(Cdn$ millions)                                 2006      2007     2008       2009      2010
---------------------------------------------------------------------------------------------
<S>                                             <C>       <C>      <C>        <C>       <C>
Term Credit Facilities (1)                         -         -        -          -         -
---------------------------------------------------------------------------------------------
Canexus LP Term Credit Facilities                  -         -        -        171         -
---------------------------------------------------------------------------------------------
Debentures                                        93         -        -          -         -
---------------------------------------------------------------------------------------------
Medium Term Notes                                  -       150      125          -         -
---------------------------------------------------------------------------------------------
Total                                             93       150      125        171         -
---------------------------------------------------------------------------------------------
</TABLE>
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.

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.

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


                                      51
<PAGE>

          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.

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.

                                      52
<PAGE>

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 51 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.

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.

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 has been
producing  sour  gas  for  over 40  years.  In  North  Vancouver,  we  operate,
indirectly  through  ownership in Canexus Limited  Partnership,  a chlor-alkali
plant that has been producing chlorine for almost 50 years.

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.

Our  operations in the Gulf of Mexico have been  suspended,  from time to time,
due to hurricanes or tropical storms. In the last five years, we have had a few
instances  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

                                      53
<PAGE>

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.  Our  profitability  and success at finding  replacement  reserves may be
reduced by extended delays or higher costs of obtaining drilling rigs.

UNCERTAINTY OF RESERVE ESTIMATES

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

Over the past three years, we experienced net negative revisions of 337 million
boe to our proved  reserves  (including  Syncrude and before  royalties).  This
includes 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.

INCREASE IN PROVED UNDEVELOPED RESERVES

The definition of proved reserves includes proved undeveloped reserves that are
expected to be recovered  from new wells on certain  undrilled  acreage or from
existing wells where a relatively  major  expenditure is still required  before
such wells may begin production. Such reserves may be recognized when plans are
in place to make the required investments to convert these undeveloped reserves
to producing.  Circumstances such as a sustained decline in commodity prices or
poorer than expected  results from initial  activities  could cause a change in
the plans which could result in a material change in our reserves estimates.

During the past 3 years, our total proved undeveloped reserves before royalties
have  increased  from 125  mmboe to 180  mmboe  (87  mmboe to 165  mmboe  after
royalties).  As a result, our proved  undeveloped  reserves have increased from
24%  to 38% of  our  proved  reserves  excluding  Syncrude  (22%  to 42%  after
royalties).  Proved  undeveloped  reserves increased in the United Kingdom as a
result of our acquisition and ongoing  development of the Buzzard Field. In all
other  areas,  they  have  declined  primarily  due  to the  completion  of the
development of Block 51 in Yemen and the drilling of a portion of the undrilled
acreage elsewhere.

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<PAGE>

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 conventional  distillation,  de-asphalting and
thermal   cracking  (the   proprietary   OrCrude(TM)   process),   followed  by
conventional hydrocracking to produce a sweet, premium synthetic crude oil. All
the individual  components of the technology  used in the process are currently
used in commercial  applications around the world. 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 $2.3 billion ($4.6 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.

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.  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).  In early 2006 we further  modified the project
design by adding steam  generation  capacity and soot  handling  equipment at a
cost of $360 million (gross).  High activity in the oil sands region is placing
ongoing  pressure  on the costs of labour and  services.  In  addition,  labour
productivity has been lower than  anticipated,  requiring a larger workforce to
maintain  progress.  After a review of all trends,  the projected  cost of Long
Lake has been increased to $4.6 billion (gross).

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<PAGE>

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 state 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. There can be no assurance that our SAGD operation will produce  bitumen at
the expected levels or steam-to-oil  ratio. If the assumed  production rates or
steam-to-oil ratio are not achieved, we might have to drill additional wells to
maintain  optimal  production  levels,  construct  additional  steam generating
capacity and/or purchase  natural gas for additional  steam  generation.  These
could have a significant  adverse impact on the future  activities and economic
return of the Long Lake project.

BITUMEN UPGRADING PROCESS

The  proprietary  OrCrude(TM)  process we are using to upgrade  raw  bitumen to
synthetic  crude  will  be the  first  commercial  application  of the  process
although we have operated it in a 500 bbls/d  demonstration plant. 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.

DEPENDANCE 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.

DEPENDANCE ON 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.

                                      56
<PAGE>

OPERATIONAL HAZARDS

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

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

The Long Lake SAGD  operation  and  upgrader  will  process  large  volumes  of
hydrocarbons at high pressure and 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.  Canada's
commitments  under the Kyoto Protocol are expected to come into effect in 2008.
Risk factors relating to climate change initiatives are provided under "Climate
Change".

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.


                                      57
<PAGE>

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.  Our insurance for physical damage and business  interruption  does
not provide for losses arising from equipment failures.

COAL BED METHANE

Coal bed methane  (CBM) is commonly  referred to as an  unconventional  form of
natural gas  because it is  primarily  stored  through  adsorption  by the coal
itself  rather than in the pore space of the rock like most  conventional  gas.
The gas is released in response to a drop in pressure in the coal.  If the coal
is water  saturated,  water  generally  needs to be  extracted  to  reduce  the
pressure and allow gas  production  to occur.  CBM wells  typically  have lower
producing  rates and reserves per well than  conventional  gas wells,  although
this  varies by area.  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. 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.

Final  hookups and  commissioning  with respect to the Buzzard  platform in the
North Sea are nearing  completion,  and we expect production  start-up prior to
the end of the  year.  We are  exposed  to the  possibility  of  delays  in the
commencement  of  commercial  production,  which  may be due to  many  factors,
including:

     o    commissioning delays;
     o    contractor or operator errors;
     o    breakdown or failure of equipment or processes;
     o    quality of oil and gas produced;
     o    violation of permit requirements; and
     o    catastrophic events such as fires, storms or explosions.

At Long Lake,  all SAGD wells have been  drilled  and  completed,  SAGD  module
fabrication  is  complete,   all  modules  are  on  site  and  construction  is
approximately  90%  complete.  With respect to the Long Lake  upgrader,  module
fabrication  is  largely  complete  and  over 90% of the  modules  are on site.
Construction of the upgrader is approximately 60% complete and start-up remains
scheduled  for the second  half of 2007.  At Long Lake,  we are  exposed to the
possibility of cost overruns  and/or delays in the  commencement  of commercial
production,  which may be  significant.  Specific risk factors  relating to our
Long Lake oil sands  project  are  provided  under the  heading  "Risk  Factors
Relating to Long Lake".

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.
For  instance,  on  September  15,  2006 our oil export  terminal  in Yemen was
assaulted by two explosive laden vehicles. One worker was killed and two others
received minor  injuries.  None of the attackers  survived.  The ability of the
terminal  to  receive  and  export  oil was not  affected  and  operations  are
continuing as normal.  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.

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.

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<PAGE>

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).  Since that time the Canadian federal  government and various provincial
governments  have  grappled  with the issue of  climate  change and a number of
proposals have come and gone. Most recently, Bill C-30 (Canada's Clean Air Act)
was introduced to Parliament for first reading. This Bill contains proposals to
deal with  criteria air  contaminants  (CACs) and  greenhouse  gases (GHGs) and
outlines  proposed changes to the Canadian  Environmental  Protection Act 1999,
the Energy  Efficiency  Act and the Motor Vehicle Fuel  Conservation  Standards
Act. The proposals seek to apply intensity-based  targets for GHGs and absolute
caps on CACs in the period up to 2020-2025  ultimately leading to absolute caps
on GHGs. It is unclear if and when Bill C-30 will become law.

Any required reductions in the GHGs emitted from our operations could result in
increases in our capital or operating  expenses,  or reduced  operating  rates,
especially those related to the Long Lake project,  which could have an adverse
effect on our results of operations and financial condition.

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 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.


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<PAGE>

Our reserves are based on internal estimates. To increase our confidence in our
estimates, we have at least 80% of our oil and gas and Syncrude reserves either
evaluated or audited annually by independent  qualified  reserves  consultants.
Given   that   reserves   estimates   are   based  on   numerous   assumptions,
interpretations  and  judgements,  differences  frequently  arise  between  the
estimates prepared by different qualified estimators. When the initial estimate
on the  portfolio of  properties  differs by greater than 10%, we work with the
independent  reserves  consultant  to reconcile  the  difference to within 10%.
Estimates pertaining to individual properties within the portfolio often differ
by  significantly  more than 10%,  either  positively or negatively.  We do not
attempt to  resolve  each  property  to within 10% as it would be time and cost
prohibitive given the number of wells in which we have an interest.

The  nature and  extent of the  independent  evaluations  and  audits,  and the
results  thereof,  are  provided in the  section on  Reserves,  Production  and
Related Information on page 17.

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,  the portfolio of properties  selected by management for
independent assessment, 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 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.

                                      60
<PAGE>

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.

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

                                      61
<PAGE>

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.

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;


                                      62
<PAGE>

     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.

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.

                                      63
<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.

                                      64
<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
----------------------------------------------------------------------------------------------------
                                                      Cash        Net                    Long-Term
(Cdn$ millions)                                       Flow     Income   Expenditures          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


                                      65
<PAGE>

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.

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  nil  (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;

                                      66
<PAGE>

     o    stop loss limits; and
     o    stress testing.

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

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

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


                                      67
<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.


                                      68
<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 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 prescribe the nature of the information  required in
          connection with proved  undeveloped  reserves and future  development
          costs  whereas  NI  51-101  requires  certain  detailed   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.

                                      69
<PAGE>


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


                                                                           Page

REPORT OF MANAGEMENT ........................................................71

REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS ......................72

CONSOLIDATED FINANCIAL STATEMENTS

    Consolidated Statement of Income ........................................73
    Consolidated Balance Sheet ..............................................74
    Consolidated Statement of Cash Flows ....................................75
    Consolidated Statement of Shareholders' Equity ..........................76
    Notes To Consolidated Financial Statements ..............................77

SUPPLEMENTARY DATA (UNAUDITED)

    Quarterly Financial Data In Accordance with Canadian and US GAAP .......116
    Oil And Gas Producing Activities and Syncrude Operations ...............117





                                      70
<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.



/s/ Charles W. Fischer                      /s/ Marvin F. Romanow
--------------------------------            -------------------------------
President and Chief Executive               Executive Vice President and
Officer                                     Chief Financial Officer


                                      71
<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                               /s/ 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                               /s/ Deloitte & Touche LLP
February 7, 2006                              Independent Registered Chartered
                                              Accountants




                                      72
<PAGE>

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

--------------------------------------------------------------------------------------------------------------
Cdn$ million, except per share amounts                                         2005         2004         2003
--------------------------------------------------------------------------------------------------------------
<S>                                                                          <C>          <C>          <C>
  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
--------------------------------------------------------------------------------------------------------------
                                                                              (100)           69        (117)
Future
--------------------------------------------------------------------------------------------------------------
                                                                                239          317           97
--------------------------------------------------------------------------------------------------------------

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


                                      73
<PAGE>

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

-------------------------------------------------------------------------------
Cdn$ million, except share amounts                              2005      2004
-------------------------------------------------------------------------------
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
-------------------------------------------------------------------------------

See accompanying notes to Consolidated Financial Statements.


Approved on behalf of the Board:


/s/ Charles W. Fischer                          /s/ Thomas C. O'Neill
-------------------------                       -----------------------
Director                                        Director


                                      74
<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.


                                      75
<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.


                                      76
<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.

                                      77
<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.

                                      78
<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.

                                      79
<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.

                                      80
<PAGE>

In May 2004,  we  modified  our stock  option  plan to a tandem  option plan by
including a cash feature. The tandem options give the holders a right to either
purchase  common shares at the exercise price or to receive cash payments equal
to the excess of the market value of the common shares over the exercise price.
As a result of the modification,  we record  obligations for the tandem options
using the  intrinsic-value  method of  accounting  and  recognize  compensation
expense.  Obligations  are accrued on a graded  vesting basis and represent the
difference between the market value of our common shares and the exercise price
of the options. The obligations are revalued each reporting period based on the
change in the market value of our common shares and the number of graded vested
options  outstanding.  We reduce the liability when the options are surrendered
for cash.  When the options are  exercised  for stock,  the recorded  liability
amount is transferred to share capital.

Stock options awarded to our US employees 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


                                      81
<PAGE>

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.

(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.

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.


                                      82
<PAGE>

The  acquisition  has been  accounted  for using the purchase  method,  and the
results  of EnCana UK have been  consolidated  with the  results  of Nexen from
December 1, 2004.  The  following  table shows the  allocation  of the purchase
price  based  on the  estimated  fair  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
------------------------------------------------------------------------------


                                      83
<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                              Accumulated
                                                  Net Book                                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
Interest
------------------------------------------------------------------------------------------------------------------
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.

                                      84
<PAGE>

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

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                        (3)           -
  of Proved Reserves
-------------------------------------------------------------------------------------------------------------
  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 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.

                                      85
<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        Fair   Unrecognized       Carrying       Fair     Unrecognized
                                        Value      Value           Gain          Value       Value     Gain (Loss)
                                                                 (Loss)
-------------------------------------------------------------------------------------------------------------------
Cdn$ millions
-------------------------------------------------------------------------------------------------------------------
<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.

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

                             Notional                  Average
                              Volumes              Price (WTI)     Fair Value
WTI Crude Oil Put Options    (bbls/d)       Term     (US$/bbl)          (Cdn$
                                                                    millions)
------------------------------------------------------------------------------
                               30,000       2006            39              2
------------------------------------------------------------------------------
                               20,000       2006            38              1
------------------------------------------------------------------------------
                               10,000       2006            36              1
------------------------------------------------------------------------------
                                                                            4
------------------------------------------------------------------------------

                                      86
<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.

------------------------------------------------------------------------------
                               Notional                  Average   Fair Value
                                Volumes                    Price        (Cdn$
                                 (Gj/d)         Term      ($/Gj)    millions)
------------------------------------------------------------------------------
Fixed Price Natural
Gas Contracts                    22,034    2005-2006   2.28-3.72         (47)
------------------------------------------------------------------------------
                                 15,514    2007-2010   2.47-2.77        (128)
------------------------------------------------------------------------------
                                                                        (175)
------------------------------------------------------------------------------

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.

------------------------------------------------------------------------------
                               Notional                   Average   Fair Value
                                Volumes                     Price        (Cdn$
                                 (Gj/d)         Term       ($/Gj)    millions)
------------------------------------------------------------------------------
Natural Gas Swaps                22,034    2005-2006   9.02-11.81           1
------------------------------------------------------------------------------
                                 15,514    2007-2010         7.45          28
------------------------------------------------------------------------------
                                                                           29
------------------------------------------------------------------------------

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                         Average      Unrecognized
                                                  Volumes                           Price        Loss (Cdn$
                                                   (mmcf)                Month   (US$/mcf)        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>

                                      87
<PAGE>

(c) FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT

<TABLE>
<CAPTION>
NON-TRADING ACTIVITIES
------------------------------------------------------------------------------------------------------------------------
                                                                                            Rate (for         Fair Value
                                                                    Amount          Term      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.

                                      88
<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.


                                      89
<PAGE>


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.

(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.

                                      90
<PAGE>

(e) MEDIUM-TERM NOTES, DUE 2007

During  July  1997,  we issued  $150  million  of notes.  Interest  is  payable
semi-annually  at a rate of 6.45%,  and the  principal  is to be repaid in July
2007. We may redeem part or all of the notes at any time. The redemption  price
will be the  greater  of par and an amount  that  provides  the same yield as a
Government of Canada Bond having a term to maturity equal to the remaining term
of the notes plus 0.125%.

(f) MEDIUM-TERM NOTES, DUE 2008

During  October  1997,  we issued  $125  million of notes.  Interest is payable
semi-annually  at a rate of 6.3%,  and the  principal  is to be  repaid in June
2008. We may redeem part or all of the notes at any time. The redemption  price
will be the  greater  of par and an amount  that  provides  the same yield as a
Government of Canada Bond having a term to maturity equal to the remaining term
of the notes plus 0.125%.

(g) NOTES, DUE 2013

During  November 2003, we issued US$500  million of notes.  Interest is payable
semi-annually at a rate of 5.05%, and the principal is to be repaid in November
2013. We may redeem part or all of the notes at any time. The redemption  price
will be the greater of par and an amount that  provides  the same yield as a US
Treasury  security having a term to maturity equal to the remaining term of the
notes plus 0.2%.

(h) NOTES, DUE 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.

                                      91
<PAGE>

(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%).

(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.

                                      92
<PAGE>

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


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.


                                      93
<PAGE>

(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.

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.


                                      94
<PAGE>

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
                                                           Exercise                    Exercise                    Exercise
                                            Options           Price      Options          Price      Options         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
                                                       Average        Average        Weighted        Average
                                     Number of        Exercise       Years to       Number of       Exercise
                                       Options           Price         Expiry         Options          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>

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

                                      95
<PAGE>

The  following  shows pro forma net income and earnings per common share had we
applied the fair-value method to account for all stock options outstanding that
were granted up to December 31, 2002.  Stock  options  granted  after that date
have been expensed as general and administrative costs.

-------------------------------------------------------------------------------
                                                                          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
                                                             Exercise                   Exercise                      Exercise
                                                    StARs       Price         StARs        Price          StARs          Price
-------------------------------------------------------------------------------------------------------------------------------
                                               (thousands)   ($/right)   (thousands)    ($/right)    (thousands)      ($/right)
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                 <C>            <C>        <C>             <C>         <C>               <C>
Balance at Beginning of Year                        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>

                                      96
<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
                                                          Average         Average                      Average
                                       Number of         Exercise       Years  to     Number of       Exercise
                                           StARs            Price          Expiry         StARs          Price
---------------------------------------------------------------------------------------------------------------
                                     (thousands) ($/right)
(years) (thousands) ($/right)
---------------------------------------------------------------------------------------------------------------

                                        <C>                 <C>              <C>       <C>               <C>
$15.00 to                                  1,028               16               2         1,024             16
$19.99
---------------------------------------------------------------------------------------------------------------
$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.

                                       97
<PAGE>

The results of  operations  from these  properties  in Australia and Canada are
detailed  below  and  shown  as  discontinued  operations  in our  Consolidated
Statement of Income.

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------------
                                                 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          28         70          9        79        101           22        123
Impairment
-------------------------------------------------------------------------------------------------------------------------
  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>
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

                                       98
<PAGE>

payments,  if any,  related to such matters,  would not have a material adverse
effect on our liquidity, financial condition or results of operations.

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.

                                       99
<PAGE>

(a) DEFINED BENEFIT PENSION PLANS

The cost of  pension  benefits  earned by  employees  is  determined  using the
projected-benefit  method  prorated on  employment  services and is expensed as
services are rendered.  We fund these plans according to federal and provincial
government  regulations  by  contributing  to trust  funds  administered  by an
independent trustee. These funds are invested primarily in equities and bonds.

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------
                                                                         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)
---------------------------------------------------------------------------------------------------------------------

---------------------------------------------------------------------------------------------------------------------
         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.

                                      100
<PAGE>

<TABLE>
<CAPTION>
NET PENSION EXPENSE RECOGNIZED UNDER OUR DEFINED BENEFIT PENSION PLANS

----------------------------------------------------------------------------------------------------------
                                                                          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.

                                      101
<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.

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------
                                                                Expected
(%)                                                                 2006          2005          2004
-----------------------------------------------------------------------------------------------------
<S>                                                                 <C>           <C>           <C>
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
-----------------------------------------------------------------------------------------------------
</TABLE>

(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:

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------
                                                                 Expected
                                                                     2006           2005          2004
-------------------------------------------------------------------------------------------------------
<S>                                                                  <C>            <C>           <C>
Defined Benefit Contributions
-------------------------------------------------------------------------------------------------------
  Nexen                                                                18              2             6
-------------------------------------------------------------------------------------------------------
  Canexus                                                               2              -             -
-------------------------------------------------------------------------------------------------------
  Syncrude                                                              5              4             4
-------------------------------------------------------------------------------------------------------
Total Funding Contributions                                            25              6            10
-------------------------------------------------------------------------------------------------------
</TABLE>

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.

                                      102
<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>

<TABLE>
<CAPTION>
17. MARKETING AND OTHER

-------------------------------------------------------------------------------------------------------------
                                                                          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.

                                      103
<PAGE>

18. INCOME TAXES

<TABLE>
<CAPTION>
(a) TEMPORARY DIFFERENCES

---------------------------------------------------------------------------------------------------------------------
                                                             2005                                2004
---------------------------------------------------------------------------------------------------------------------
                                                 Future Income      Future Income    Future Income     Future Income
                                                           Tax                Tax              Tax               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>

<TABLE>
<CAPTION>
(b) CANADIAN AND FOREIGN INCOME TAXES

---------------------------------------------------------------------------------------------------------------------
                                                                                    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>

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).

<TABLE>
<CAPTION>
(c) RECONCILIATION OF EFFECTIVE TAX RATE TO THE CANADIAN FEDERAL TAX RATE

--------------------------------------------------------------------------------------------------------------------
                                                                                    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.

                                      104
<PAGE>

(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

<TABLE>
<CAPTION>
(a) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH
----------------------------------------------------------------------------------------------
                                                                    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
----------------------------------------------------------------------------------------------

(B) CHANGES IN NON-CASH WORKING CAPITAL
-----------------------------------------------------------------------------------------------
                                                                    2005       2004      2003
-----------------------------------------------------------------------------------------------
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)
-----------------------------------------------------------------------------------------------

(C) OTHER CASH FLOW INFORMATION
-----------------------------------------------------------------------------------------------
                                                                    2005      2004       2003
-----------------------------------------------------------------------------------------------
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.

                                      105
<PAGE>

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.


                                      106
<PAGE>

<TABLE>
<CAPTION>
2005 OPERATING AND GEOGRAPHIC SEGMENTS

--------------------------------------------------------------------------------------------------------------------------------
                                                Oil and Gas                          Syncrude(1)  Chemicals  Corporate    Total
                                                                                                             and Other
--------------------------------------------------------------------------------------------------------------------------------
(Cdn$                                                              Other
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
--------------------------------------------------------------------------------------------------------------------------------
</TABLE>
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.

                                      107
<PAGE>

<TABLE>
<CAPTION>
2004 OPERATING AND GEOGRAPHIC SEGMENTS

--------------------------------------------------------------------------------------------------------------------------------
                                                Oil and Gas                          Syncrude(1)  Chemicals  Corporate    Total
                                                                                                             and Other
--------------------------------------------------------------------------------------------------------------------------------
(Cdn$                                                              Other
millions)                  Yemen      Canada(2)  US      UK    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
--------------------------------------------------------------------------------------------------------------------------------
                             826         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 (10)                   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        -          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  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
--------------------------------------------------------------------------------------------------------------------------------
</TABLE>
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).

                                      108
<PAGE>

<TABLE>
<CAPTION>
2003 OPERATING AND GEOGRAPHIC SEGMENTS

---------------------------------------------------------------------------------------------------------------------------
                                                Oil and Gas                     Syncrude(1)  Chemicals  Corporate  Total
                                                                                                        and Other
---------------------------------------------------------------------------------------------------------------------------
(Cdn$                                                     Other
millions)                  Yemen      Canada(2)    US   Countries(3)  Marketing
--------------------------------------------------------------------------------------------------------------------------
<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         114        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
--------------------------------------------------------------------------------------------------------------------------
</TABLE>
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).

                                      109
<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:

<TABLE>
<CAPTION>
CONSOLIDATED  STATEMENT OF INCOME--US  GAAP FOR THE THREE YEARS ENDED  DECEMBER
31, 2005

-------------------------------------------------------------------------------------------------------------------
 (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                                                                        658           705          419
Principles
-------------------------------------------------------------------------------------------------------------------
  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
-------------------------------------------------------------------------------------------------------------------

Note:
1    Reconciliation of Canadian and US GAAP Net Income
-------------------------------------------------------------------------------------------------------------------
                                                                                   2005          2004         2003
-------------------------------------------------------------------------------------------------------------------
     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>

                                      110
<PAGE>

<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEET--US GAAP

------------------------------------------------------------------------------------------------------------------
 (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
------------------------------------------------------------------------------------------------------------------
                                                                                          51                   41
Other
------------------------------------------------------------------------------------------------------------------
      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>

                                      111
<PAGE>

<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME--US GAAP FOR THE THREE YEARS ENDED DECEMBER 31, 2005

------------------------------------------------------------------------------------------------------------------
 (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.

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

                                      112
<PAGE>

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 gain 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 to  include  a cash  feature.  Prior  to the
modification of our stock option plan, we accounted for stock options using the
fair-value method.  Following the addition of the cash feature,  we account for
stock  options  using  the  intrinsic-value  method.  As a  result  of the plan
modification, we recognized an obligation of $85 million for our tandem options
under both Canadian and US GAAP. This resulted in a one-time,  non-cash expense
to net income for Canadian  GAAP  purposes of $54  million,  net of tax, in the
second quarter of 2004.  For US GAAP purposes,  $36 million of this expense was
recognized  as a reduction  of US GAAP  retained  earnings  and $18 million was
recognized  as an expense to our second  quarter  2004 US GAAP net income.  The
reduction of US GAAP  retained  earnings  was made in respect of stock  options
granted prior to the adoption of FAS 123 on January 1, 2003.

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.

                                      113
<PAGE>

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>
------------------------------------------------------------------------------------------------------------
                                                                                                    Net Gain
 (Cdn$ millions)                                                          Gain (Loss)      Tax        (Loss)
------------------------------------------------------------------------------------------------------------
<S>                                                                              <C>        <C>         <C>
Fair Value Change up to June 30, 2003 (2)                                        (16)        5          (11)
------------------------------------------------------------------------------------------------------------
Fair Value Change from July 1, 2003 to December 31, 2003 (1)                       12       (5)           7
------------------------------------------------------------------------------------------------------------
Fair Value Change from January 1, 2004 to February 9, 2004 (1), (3)                 4        -            4
------------------------------------------------------------------------------------------------------------
</TABLE>
Notes:
(1)  Included in marketing and other.
(2)  Reported as cumulative effect of a change in accounting principle.
(3)  Redemption date of preferred securities.

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.

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.

                                      114
<PAGE>

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.


                                      115
<PAGE>

SUPPLEMENTARY DATA (UNAUDITED)

<TABLE>
<CAPTION>
QUARTERLY FINANCIAL DATA IN ACCORDANCE WITH CANADIAN AND US GAAP
-----------------------------------------------------------------------------------------------------------------------------
                                                                               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
-----------------------------------------------------------------------------------------------------------------------------
</TABLE>
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.

                                      116
<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>
--------------------------------------------------------------------------------------------------------------------------------
                                                                                                                          Other
                                                                                                           United     Countries
                                        Total       Yemen (1)           Canada            United States    Kingdom          (3)
--------------------------------------------------------------------------------------------------------------------------------
 Conventional oil and bitumen
 are in mmbbls and natural gas                                                 Bitumen
 is in bcf                          Oil      Gas         Oil     Oil    Gas       (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
--------------------------------------------------------------------------------------------------------------------------------
</TABLE>
Notes:
(1) Under  the  terms  of the  Masila  and  the  Block  51  production  sharing
    contracts,  production  is divided  into cost  recovery oil and profit oil.
    Cost  recovery  oil provides for the recovery of all our costs and those of
    our partners.  Remaining  production is profit oil, which is shared between
    the partners and the  Government of Yemen based on production  rates,  with
    the  partners'  share  ranging from 20% to 33%. The  Government's  share of
    profit oil represents  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.

                                      117
<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 18 - 20. The net proved  reserves  represent  management's
best estimate of proved synthetic  reserves after royalties.  Reserve estimates
are prepared  internally each year, and at least 80% of our reserves (including
oil and gas activities)  have been assessed by independent  qualified  reserves
consultants.

Estimates  of  Syncrude's  synthetic  crude oil  reserves are based on detailed
geological and  engineering  assessments of the bitumen  volume  in-place,  the
mining plan,  historical  extraction  recovery  and  upgrading  yield  factors,
installed plant operating  capacity and operating approval limits. The in-place
volume,  depth and grade are established  through  extensive and closely spaced
core  drilling.  In  accordance  with the approved  mining  plan,  there are an
estimated 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
---------------------------------------------------------------------------------------------
                                                           (3)            (3)             (6)
Production
---------------------------------------------------------------------------------------------
December 31, 2005                                          47            217             264
---------------------------------------------------------------------------------------------
</TABLE>
Notes:
(1)  Leases 17 and 22
(2)  Leases 10, 12, 31 and 34.

                                      118
<PAGE>

<TABLE>
<CAPTION>
B. CAPITALIZED COSTS (EXCLUDING SYNCRUDE OPERATIONS)

---------------------------------------------------------------------------------------------------------
                                                                         Accumulated
                                                                       Depreciation,
                                                                          Depletion,
                                    Proved           Unproved       Amortization and
                                Properties         Properties             Impairment   Capitalized Costs
---------------------------------------------------------------------------------------------------------
(Cdn$ millions)
---------------------------------------------------------------------------------------------------------
<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
---------------------------------------------------------------------------------------------------------
                                     2,022                 16                  1,550                 488
Yemen
---------------------------------------------------------------------------------------------------------
                                     3,732                136                  2,025               1,843
Canada
---------------------------------------------------------------------------------------------------------
  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
---------------------------------------------------------------------------------------------------------
                                     1,881                 17                  1,497                 401
Yemen
---------------------------------------------------------------------------------------------------------
                                     3,271                129                  1,863               1,537
Canada
---------------------------------------------------------------------------------------------------------
  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>

<TABLE>
<CAPTION>
C. COSTS INCURRED (EXCLUDING SYNCRUDE OPERATIONS)

---------------------------------------------------------------------------------------------------------
                                                                       Oil and Gas
---------------------------------------------------------------------------------------------------------
                                      Total Oil                              United       United
(Cdn$ millions)                         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>

                                      119
<PAGE>

<TABLE>
<CAPTION>
D. RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES (EXCLUDING SYNCRUDE
OPERATIONS)

-------------------------------------------------------------------------------------------------------------
                                                                                  Oil and Gas
-------------------------------------------------------------------------------------------------------------
                                                                                                       Other
                                           Total Oil      Yemen     Canada     United    United    Countries
(Cdn$ millions)                              and Gas                    (1)    States     Kingdom         (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.

<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>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------
 (Cdn$                                                                            2005           2004          2003
millions)
--------------------------------------------------------------------------------------------------------------------
<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
--------------------------------------------------------------------------------------------------------------------
</TABLE>
Note:
(1) 2004 includes  approximately $230 million of negative discounted future net
    cash flows relating to bitumen reserves based on year-end assumptions.

                                      121
<PAGE>


                                    EXHIBITS


23.1*   Consent of Independent Registered Chartered Accountants

23.2*   Consent of William M. Cobb & Associates, Inc.

23.3*   Consent of Ryder Scott Company, L.P.

23.4*   Consent of McDaniel & Associates Consultants Ltd.

23.5*   Consent of DeGolyer and MacNaughton.

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

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

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

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


*       Filed herewith.

<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 April 2, 2007.


                                        NEXEN INC.



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