================================================================================
                                  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, 2006
                          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 if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act.

                              Yes  [X]      No  [_]

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

                              Yes  [_]      No  [X]

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

                              Yes  [X]      No  [_]

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

Indicate by check mark whether the registrant is a large accelerated  filer, an
accelerated filer, or a non-accelerated filer.

Large accelerated filer [X]   Accelerated filer [_]   Non-accelerated filer [_]

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

                              Yes  [_]      No  [X]

On June 30,  2006,  the  aggregate  market  value of the voting  shares held by
non-affiliates  of the registrant was  approximately Cdn $16.5 billion based on
the Toronto  Stock  Exchange  closing  price on that date. On January 31, 2007,
there were 262,830,108 common shares issued and outstanding.

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<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, 2006 filed on February  26, 2007
(the "Original  Filing").  Nexen, Inc. (the "Company") has filed this Amendment
to incorporate  textual changes in Items 1 and 2, Business and Properties,  and
in Item 7,  Management's  Discussion  and Analysis of Financial  Condition  and
Results of Operations regarding the Company's reserves process.  This Amendment
also includes a change in Item 8, Financial  Statements and Supplementary  Data
(Note 21 - Differences  between Canadian and U.S. Generally Accepted Accounting
Principles)  to remove the  transitional  impact of adopting FASB Statement 158
EMPLOYERS'  ACCOUNTING FOR DEFINED BENEFIT PENSION AND OTHER  RETIREMENT  PLANS
from US GAAP  Comprehensive  Income for the year ended December 31, 2006.  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.

<PAGE>

                               TABLE OF CONTENTS

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


PART II
Item 7.           Management's Discussion and Analysis of Financial
                  Condition and Results of Operations ......................29
Item 8.           Financial Statments and Supplementary Data ...............68


PART IV
Item 15.          Exhibits ................................................122

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.

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

     In this 10-K, we refer to oil and gas in common units called barrel of oil
equivalent (boe). A boe is derived by converting six thousand cubic feet of gas
to  one  barrel  of  oil  (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
     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
     2006          0.8581            0.8818         0.9099       0.8528

     On January 31,  2007,  the noon-day  exchange  rate was US $0.8480 for Cdn
$1.00.

     Electronic copies of our filings with the Securities  Exchange  Commission
(SEC) and the  Ontario  Securities  Commission  (OSC)  (from  November  8, 2002
onward)  are  available,  free of charge,  on our  website  (www.nexeninc.com).
Filings prior to November 8, 2002 are available free of charge, on request,  by
contacting  our  investor  relations  department  at  403.699.5931.  As soon as
reasonably practicable, our filings are made available on our website once they
are electronically  filed with the SEC and/or the OSC.  Alternatively,  the SEC
and the OSC each  maintain  a  website  (www.sec.gov  and  www.sedar.com)  that
contains our reports,  proxy and  information  statements  and other  published
information that have been filed or furnished with the SEC and the OSC.

<PAGE>

                                     PART I
                     ITEMS 1 AND 2. BUSINESS AND PROPERTIES


                                                                          PAGE
                                                                          ----

ABOUT US                                                                   3

STRATEGY                                                                   4

UNDERSTANDING THE OIL AND GAS BUSINESS                                     4

OIL AND GAS OPERATIONS                                                     5
         North Sea--United Kingdom                                         5
         Gulf of Mexico--United States                                     8
         Canada                                                           10
         Middle East--Yemen                                               14
         Offshore West Africa                                             17
         Other International                                              18

RESERVES, PRODUCTION AND RELATED INFORMATION                              18

SYNCRUDE MINING OPERATIONS                                                23

ENERGY MARKETING                                                          25

CHEMICALS                                                                 27

GOVERNMENT REGULATIONS                                                    28

ENVIRONMENTAL REGULATIONS                                                 28

EMPLOYEES                                                                 28


                                       2
<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 211,700 boe/d before royalties  (including Syncrude production) and revenues
of $3.9 billion in 2006. 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  established 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  events:  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 940 million
barrels since start up in 1993. 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.
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 $2.6  billion at  year-end
2006. 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. In 2004,
we acquired  properties in the UK North Sea,  providing us with operatorship of
the Buzzard  discovery,  the  producing  Scott and  Telford  fields and 700,000
exploration acres.

              WE'VE GROWN FROM PRODUCING 10,700 BOE/D IN 1971 TO
  211,700 BOE/D IN 2006. IN 2007, WE EXPECT OUR NET PRODUCTION TO GROW BY 50%.

     In 2005, we sold Canadian  conventional  oil and gas properties  producing
approximately  18,300 boe/d before  royalties and monetized 39% of our chemical
business  through the initial  public  offering of the Canexus  Income Fund. We
also made a potentially  significant  discovery in the Gulf of Mexico at Knotty
Head and commenced  commercial  development of our first coalbed  methane (CBM)
project in the Fort Assiniboine  area in western Canada.  In 2006, we completed
our  major  development  project  at  Buzzard  on budget  and made  significant
construction  progress at our Long Lake project in the Athabasca oil sands.  In
early  January  2007,  Buzzard  produced  first  oil.  With  Buzzard on stream,
followed  by Long  Lake  later in the  year,  we expect  our  production  after
royalties in 2007 to grow by more than 50%, net of declines.  Our  portfolio of
assets,  combined with our talented people and an active  exploration  program,
are expected to provide future growth for our company.

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

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

    Our oil and gas operations are broken down geographically into the UK North
Sea, US Gulf of Mexico, Canada,

                                       3
<PAGE>

Yemen and Other  International  (currently  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.  Energy  marketing  includes our
growing  crude  oil,  natural  gas,  natural  gas  liquids,  ethanol  and power
marketing  business in North  America,  Europe and  southeast  Asia.  Chemicals
includes  operations in North America and Brazil that  manufacture,  market and
distribute  sodium  chlorate,  caustic  soda and  chlorine  through the Canexus
Limited Partnership.

     Production,  revenues,  net income,  capital expenditures and identifiable
assets  for  these  segments  appear in Note 20 to the  Consolidated  Financial
Statements and in Management's  Discussion and Analysis of Financial  Condition
and Results of Operations (MD&A) in this report.

STRATEGY

     Our goal is to grow long-term value for our shareholders.  We define value
growth as increasing  reserves,  production,  cash flow and net income over the
long term. We believe in developing our competitive advantage,  which generates
opportunities  for  long-term  success  in  our  ever-evolving   industry.   As
conventional  basins  in  North  America  mature,  we have  developed  specific
capabilities  in oil sands,  coalbed methane (CBM),  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 less mature basins and exploitation of unconventional resources.

     Today, we are building new sustainable  businesses in western Canada,  the
North Sea,  Gulf of Mexico,  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.  In 2006,  Buzzard  was  completed  on budget and just days
             after  the  original  projected  start  up  date.  At  Long  Lake,
             construction is progressing well and we expect the SAGD production
             operations  to be on  stream by the end of the  first  quarter  in
             2007, followed by the start up of the upgrader late in the year;
        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,  the  United  Kingdom,
             Nigeria, Colombia and Australia; and
        o    From time to time,  we  supplement  our growth with  acquisitions,
             such as our strategic entry into the UK North Sea in 2004.

     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.

         WE ARE BUILDING SUSTAINABLE BUSINESSES WITH MAJOR PROJECTS IN
 ESTABLISHED BASINS, EXPLOITATION OF UNCONVENTIONAL RESOURCES AND EXPLORATION.

     Our long-term  strategy focuses on building capacity by ensuring we have a
sufficient  inventory  of  opportunities  for future  growth.  With  Buzzard on
stream, followed by Long Lake later this year, we expect to deliver significant
production growth. In fact, in 2007 we expect our production after royalties to
grow by more than 50%,  net of  declines.  However,  the  growth  does not stop
there.  Beyond  2007,  we have a number of  opportunities  that are expected to
provide  production  growth  and  create  shareholder  value well into the next
decade. These opportunities  include undeveloped  discoveries at Knotty Head in
the Gulf of Mexico, Usan and Ukot offshore Nigeria,  various discoveries in the
UK North Sea,  together with  development  of our CBM and  additional oil sands
leases in Canada.

     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

                                       4
<PAGE>


the oil or gas,  the fiscal  terms of the host  regime  and the price  products
command in the market based on quality and  marketing  efforts.  Our goal is to
extract the maximum value from each barrel of oil  equivalent,  so every dollar
of capital we invest generates an attractive return.

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

     Realized  prices for our oil and gas  products  are mainly  determined  by
volatile  global  crude oil and  natural  gas  markets.  With many  alternative
customers,  the loss of any one customer is not expected to have a  significant
adverse effect on the price of our products or 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.  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 97% of our oil and gas reserves  before  royalties (97% after
royalties)  and 100% of our  Syncrude  reserves  before  royalties  (100% after
royalties)  assessed  (either  evaluated or audited as described on page 22) 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  62 for a  description  of our
reserves  process,  and to the  section on  Reserves,  Production  and  Related
Information  on  page 18 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,  a 41% operated interest in the
Scott  field,  a 54.3%  operated  interest  in the  Telford  field,  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.


                                       5
<PAGE>

     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  undeveloped   discoveries  near
infrastructure.  Most of our unexplored acreage is near Scott/Telford,  Buzzard
or Ettrick which is currently  being  developed.  As a result,  new discoveries
could be tied-in relatively quickly, upon success.

     During the year, we produced 20,200 boe/d before  royalties  (20,200 after
royalties) in the UK, which was  approximately 10% of Nexen's total production.
At year end,  the UK had proved  reserves of 182 mmboe  before  royalties  (182
after  royalties)  representing  about 17% of our total  proved oil and gas and
Syncrude reserves.

BUZZARD DEVELOPMENT

     The Buzzard field is located in the Outer Moray Firth,  central North Sea,
about 60 miles  northeast  of  Aberdeen,  in 317 feet of  water.  The field was
discovered  in 2001 and  construction  was completed in 2006,  with  production
commencing early January 2007.  During the year, we installed the utilities and
production  topsides,  drilled  the  initial  development  wells and  completed
hook-ups and project commissioning. The facilities have the capacity to process
up to  200,000  bbls/d of oil and 60 mmcf/d of gas,  including  the  removal of
hydrogen sulphide. Based upon recent drilling results, we have experienced more
well-to-well  variability  in  the  concentration  of  hydrogen  sulphide  than
previously  seen. We expect  existing  equipment and processes will allow us to
manage  this  variability  for at  least  the  first  two  to  three  years  of
production.  As  we  continue  to  produce  and  acquire  additional  reservoir
information,  we will determine whether additional equipment will ultimately be
required.  We anticipate the field will be produced through 27 production wells
and  reservoir  pressure  will be  maintained  through  an  active  water-flood
program.  Buzzard is one of the largest  discoveries in the UK North Sea in the
past ten years.


                      BUZZARD IS ON STREAM AND RAMPING UP
              TO ESTIMATED PEAK RATES OF 85,000 BOE/D NET TO US.

ETTRICK DEVELOPMENT

     We are  progressing  development of the Ettrick field which is expected to
begin  producing in the first half of 2008,  with our share expected to average
approximately  16,000 boe/d (before and after royalties).  Development includes
drilling  three  production  wells tied back to a leased  floating  production,
storage and off-loading  vessel (FPSO) and is approximately  30% complete.  Our
share of full-cycle development costs is estimated at $460 million. In 2007, we
plan to invest $235  million in subsea  development  including  drilling  three
development wells and one water injection well.

UK PRODUCTION

     Buzzard  began  producing at the  beginning of January  2007. We expect to
reach peak gross production  rates of  approximately  200,000 bbls/d of oil and
approximately  30 mmcf/d of gas,  with our share about 85,000 boe/d (before and
after  royalties)  in the first half of 2007.  Oil from Buzzard is exported via
the Forties pipeline to the Grangemouth  refinery in Scotland.  Gas is exported
via the Frigg system to the St. Fergus Gas Terminal in northeast  Scotland.  In
2007, we plan to invest approximately $130 million to pre-drill and complete 11
future production and injection wells.

     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 2006,
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 platform wells.
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 Gas
Terminal in


                                       6
<PAGE>

northeast  Scotland.  In 2005,  the  Scott  platform  underwent  a  significant
maintenance turnaround and facilities upgrade to improve reliability and extend
facility life. In 2006,  the flare tip and flare tip supporting  structure were
upgraded.  In 2007,  we plan to  invest  approximately  $45  million  to drill,
complete and tie-in three development wells.

     Our 2004 UK acquisition  included a non-operated  interest in Farragon,  a
small  satellite  discovery,  which was brought on stream in November  2005. In
2006, our 20% share of royalty-free production from Farragon was 3,700 boe/d.

EXPLORATION AND UNDEVELOPED ASSETS

     In early  2007,  we  completed  drilling  operations  at our Golden  Eagle
prospect and we encountered hydrocarbons. A successful sidetrack was drilled to
appraise the accumulation and we are currently evaluating  development options.
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>
Duart                50               non-operated          discovery near Scott; first oil expected in late 2007
-------------------------------------------------------------------------------------------------------------------------
Black Horse          40               operated              discovery near Scott; evaluating development alternatives
-------------------------------------------------------------------------------------------------------------------------
Bugle                82               operated              discovery near Scott; well planned for 2007
-------------------------------------------------------------------------------------------------------------------------
Dolphin              42               operated              discovery near Scott; evaluating development alternatives
-------------------------------------------------------------------------------------------------------------------------
Golden Eagle         34               operated              discovery near Ettrick; evaluating development alternatives
-------------------------------------------------------------------------------------------------------------------------
Perth                42               operated              discovery near Scott; evaluating development alternatives
-------------------------------------------------------------------------------------------------------------------------
Polecat              40               operated              discovery near Buzzard; evaluating development alternatives
-------------------------------------------------------------------------------------------------------------------------
Selkirk              38               operated              appraisal well planned for 2007
-------------------------------------------------------------------------------------------------------------------------
Yeoman               50               operated              discovery near Scott; evaluating development alternatives
=========================================================================================================================
</TABLE>

     Development  is  progressing  at  Duart.  In  2007,  we  plan  to  drill a
development  well and  bring the field on  stream  before  year-end.  The other
discoveries are in various stages of evaluation.

     During 2006,  we drilled  unsuccessful  exploration  wells at Zanzibar and
Black  Cat.  These  wells  encountered  non-commercial  hydrocarbons  and  were
abandoned.  In 2007, we expect to drill five  exploration and appraisal  wells.
The offshore drilling rig market is currently tight,  however,  we have secured
drilling  rigs for most of our  2007  North  Sea  exploration  and  development
program.

COALBED METHANE (CBM)

     In  2006,  we  acquired  an  80%  working  interest  at  an  emerging  CBM
opportunity in the UK. 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.

     During 2006, we drilled two exploratory  wells at our UK CBM  opportunity.
The wells encountered all the coal seams expected. In 2007, we plan to continue
assessing the potential of this  investment  by drilling  additional  wells and
production testing them.

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
2012.  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.  The 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.  The UK
government  increased this charge from 10% to 20%,  effective  January 1, 2006.
The amount and timing of income taxes payable depends on many factors including
price, production, capital investment levels and available tax losses.

                                       7
<PAGE>

GULF OF MEXICO--UNITED STATES (US)

     The Gulf of Mexico  is an  integral  part of our  growth  strategy.  Large
discoveries,  relatively  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,  exploit  our
existing  asset base and acquire  assets with  upside  potential.  We focus our
exploration program on three strategic play types:

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

     These  plays  are  relatively  under-explored,  hold  potential  for large
discoveries and have attractive fiscal terms. The shorter-cycle times for shelf
gas and deep-water  prospects near  infrastructure  complement the longer-cycle
times  for  deep-water  sub-salt  plays.  Although  competition  in the Gulf is
strong,  we expect the availability of expiring acreage over the next few years
to provide us with access to additional exploration opportunities.

     In  2006,  we  invested  $595  million  on  exploration   and  development
activities in the Gulf.  This resulted in discoveries at Alaminos  Canyon Block
856 (Great White West) and Ringo. In 2007, we plan to invest approximately $585
million in the Gulf to further our strategy.

<TABLE>
<CAPTION>
US PRODUCTION
                                         2006                             2005                                 2004
------------------------------------------------------------------------------------------------------------------------------
                                BEFORE            AFTER          BEFORE            AFTER              BEFORE           AFTER
(mboe/d)                     ROYALTIES        ROYALTIES       ROYALTIES        ROYALTIES           ROYALTIES       ROYALTIES
------------------------------------------------------------------------------------------------------------------------------
<S>                          <C>              <C>             <C>              <C>                 <C>             <C>
Deep-water                        19.6             17.5            24.0             21.5                32.1            28.7
------------------------------------------------------------------------------------------------------------------------------
Shallow-water                     15.9             13.2            17.6             14.6                22.6            18.8
------------------------------------------------------------------------------------------------------------------------------
Total                             35.5             30.7            41.6             36.1                54.7            47.5
==============================================================================================================================
</TABLE>

     In 2006, we produced  approximately  35,500 boe/d before royalties (30,700
after  royalties),  representing  approximately 17% of Nexen's total production
including  Syncrude.  This was less than expected due to timing delays at Aspen
and  weather-related  disruptions.  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.   Storms  in  2005  caused  damage  to
third-party  infrastructure and as a result,  approximately  4,000 boe/d of our
pre-storm production was shut-in for nine months of 2006. We carry property and
business  interruption  insurance to mitigate losses caused by adverse weather.
During 2006,  we received $80 million of insurance  proceeds  relating to these
storms.

     At year end, we had proved reserves of 73 mmboe before royalties (63 after
royalties)  representing  about  7% 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 areas. We operate most of
this production.


                                       8
<PAGE>

DEEP-WATER PRODUCTION

     The majority of 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 subsea 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 2006 production  before royalties was  approximately
8,900  boe/d  (8,000  after  royalties).  In 2006,  we  drilled  an  additional
development  well. This well came on stream in late December.  Based on results
from this well,  we see  additional  opportunities  in the Aspen  field and are
currently  sidetracking the Aspen 1 well to exploit deeper sands. We expect our
2007  production  from the Aspen  field to  average  between  15,000 and 20,000
boe/d.

                            THE WRIGLEY DISCOVERY IS
                  EXPECTED TO BEGIN PRODUCING IN EARLY 2007.

     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 2006, our share of production before royalties was approximately
10,600 boe/d (9,300 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 completed the tie-in of our 15% non-operated
Dawson Deep discovery to the Gunnison SPAR.

SHALLOW-WATER PRODUCTION

     Our shelf  producing  assets are  offshore  Louisiana,  primarily  in five
100%-owned field areas: Eugene Island 18, Eugene Island 255/257/258/259, Eugene
Island 295, Vermilion  302/321/339/340,  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 2006  shelf  activities  focused  on
development drilling at Eugene Island 258/259 and Eugene Island 295.

EXPLORATION AND UNDEVELOPED ASSETS

     Our  exploration  program in the Gulf of Mexico  continues  to produce new
discoveries.  In 2006, we had  discoveries at Alaminos  Canyon Block 856 (Great
White West) and Ringo. We are currently evaluating development options for both
of these discoveries.  During the year, we also drilled a successful  sidetrack
well on our 2005  Knotty  Head  discovery.  We are  currently  proceeding  with
facility and subsurface studies.  Access to deep-water rigs remains limited and
we continue to work with  partners to find a rig to complete  the  appraisal of
the field. Our undeveloped deep-water discoveries include:

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
WELL                        INTEREST (%)     OPERATOR STATUS     COMMENTS
---------------------------------------------------------------------------------------------------------------------------------
<S>                         <C>              <C>                 <C>
Wrigley                         50           non-operated        development underway; expected to begin producing in early 2007
---------------------------------------------------------------------------------------------------------------------------------
Alaminos Canyon Block 856       30           non-operated        evaluating development alternatives
---------------------------------------------------------------------------------------------------------------------------------
Tobago                          10           non-operated        development approved; expected to begin producing in 2009
---------------------------------------------------------------------------------------------------------------------------------
Knotty Head                     25           operated            further appraisal required
---------------------------------------------------------------------------------------------------------------------------------
Ringo                           50           non-operated        additional appraisal well to be drilled in 2007
=================================================================================================================================
</TABLE>

     During the year,  we drilled dry holes at  Pathfinder,  West  Cameron 135,
West  Cameron  109,  Eugene  Island  19 and  Vermilion  65.  We  increased  our
deep-water undeveloped land position by 20 blocks to over 200 blocks and expect
this  acreage  and future  exploration  opportunities  to  position us well for
continued  growth.  In 2007,  we plan to  tie-in  our  Wrigley  discovery  to a
third-party facility. We also plan to drill nine exploration wells (four in the
deep water and five on the shelf) and have  drilling rigs secured for more than
half of these wells. We are actively working with partners to find rigs for the
remainder.  In 2005,  we  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.


                                       9
<PAGE>

FISCAL TERMS

     In  2006,   royalty  rates  on  our  US  production   averaged  16.6%  for
shallow-water  volumes and 11.2% for deep-water volumes.  The US government has
proposed  to  increase  royalty  rates from  12.5% to 16.7% for new  deep-water
leases awarded after July 2007. We qualify for royalty relief at our deep-water
Aspen and Gunnison  fields on the first 87.5 mmboe of production.  However,  we
may be 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 (MMS). The oil and gas industry is currently  litigating the
enforceability  of these price thresholds.  In 2006,  commodity prices exceeded
these  thresholds,  and we were  assessed a royalty at Gunnison of 12.5% by the
MMS. If the litigation is not successful, royalties that we have accrued on our
Gunnison  production  will be  payable.  Our Aspen  field is not subject to the
minimum price threshold, however, the US government has proposed legislation to
include  minimum  threshold  prices for  deep-water  leases granted in 1998 and
1999.  If the  legislation  is approved,  our Aspen field could be subject to a
12.5% government royalty on production after October 1, 2006. US taxable income
is subject to federal income tax of 35% and state taxes ranging from 0% to 12%.

             IN CANADA, WE ARE INCREASING OUR CAPACITY BY FOCUSING
 ON UNCONVENTIONAL RESOURCES SUCH AS OIL SANDS, CBM AND ENHANCED OIL RECOVERY.

CANADA

     Our  strategy  in  Canada  is to bring our new  growth  developments  into
production while we maximize value from our established operations. In 2005, we
disposed  of  approximately   18,300  boe/d  before  royalties  of  production,
comprising  approximately  60% oil and 40% gas.  The  assets we  retained  have
upside potential for continued  conventional  development and enhanced recovery
with advancements in extraction technology. During the year, we produced 38,000
boe/d before royalties (31,000 after royalties), which was approximately 18% of
Nexen's total production including Syncrude.  At year end 2006, proved reserves
(including  bitumen and excluding  Syncrude) of 364 mmboe before royalties (319
after  royalties)  were  approximately  35% of our total proved oil and gas and
Syncrude reserves.

     Our remaining Canadian  conventional  assets comprise heavy oil production
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    coalbed methane (CBM)--to extract natural gas primarily from Upper
             Mannville coals.

     In 2006, we invested  $1,609 million in Canada;  $1,416 million into these
growth initiatives.  In 2007, we plan to invest  approximately  $1,070 million;
$944 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  steam-assisted-gravity-drainage  (SAGD)  bitumen  production  with
field  upgrading  technology  to  produce  a premium  synthetic  crude oil that
significantly  reduces our need to purchase  natural  gas. We also have a 7.23%
investment in the Syncrude oil sands mining operation.


                                      10
<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 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  bitumen  extraction  process  and are
responsible for constructing,  developing and operating the SAGD project.  OPTI
is responsible for the design,  construction and operation of the upgrader.  We
share equally in all project reserves, production, 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
conventional   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(degree)  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 is also to 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 provincial  electricity grid. The energy conversion  efficiency
for our  Long  Lake  upgrader  is  about  90%  compared  to 75%  for a  typical
bitumen-fed coker, which we expect will provide us with an approximate  $10/bbl
operating cost 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 and availability 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.

                WE EXPECT OUR INTEGRATED OIL SANDS STRATEGY WILL
       PROVIDE US WITH AN APPROXIMATE $10/BBL OPERATING COST ADVANTAGE.

PROJECT MILESTONES AND COSTS

     The Long Lake project received regulatory approval in 2003 and Nexen board
approval in 2004. Field construction on the SAGD and upgrader  facilities began
in 2004. In 2006, we substantially  completed  module and site  construction of
the SAGD facilities.  Steam injection is expected to commence at the end of the
first  quarter of 2007,  with  bitumen  production  expected to ramp up to peak
rates over a 12 to 24 month period. For the first six months of SAGD operation,
we will  largely be heating the  reservoir.  During this  period,  steam to oil
ratios will be high but will decline with time as bitumen  production  ramps up
to our target  rates.  Depending  on our actual start up date and the amount of
downtime at our facilities,  we expect bitumen  production  before royalties to
reach between 35,000 and 45,000 bbls/d (between 17,500 and 22,500 bbls/d net to
our share) by the end of 2007, with a steam-to-oil


                                      11
<PAGE>

ratio of  between  3.5 and 4.0.  We expect  the  steam-to-oil  ratio to average
approximately 3.0 over the long-term.


     LONG LAKE IS ON TRACK FOR START UP IN 2007 AND EXPECTED TO REACH PEAK
        PRODUCTION OF ABOUT 60,000 BBLS/D (30,000 BBLS/D NET) OF PREMIUM
                  SYNTHETIC CRUDE BY LATE 2008 OR EARLY 2009.

     Upgrader  module  fabrication  is  largely  complete  and  over 95% of the
modules are on site. Construction of the upgrader is approximately 80% complete
and start up is scheduled for late 2007. Peak output of premium synthetic crude
oil is  expected  within 6 to 18 months of  upgrader  start up and we expect to
exit 2007 with synthetic  production  rates of between 28,000 and 36,000 bbls/d
(between  14,000 and 18,000 bbls/d net to our share).  Production  capacity for
the first phase of Long Lake is approximately  60,000 bbls/d (30,000 bbls/d net
to our share) of premium synthetic crude, which we expect to reach by late 2008
or early 2009. We also expect  production  to be maintained  over the project's
life,  estimated  at  40  years,  by  periodically   drilling  additional  SAGD
well-pairs.

     In 2006,  we  invested  $1,050  million  at Long Lake and expect to invest
approximately  $500 million in 2007.  The capital cost  estimate when our board
sanctioned the project in February 2004 was $3.4 billion ($1.7 billion net). 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 ($49 million
net).  In early 2006,  we further  modified the project  design by adding steam
generation capacity and soot handling equipment at a cost of $360 million ($180
million net). These scope changes  increased the estimated project cost to $3.8
billion ($1.9 billion net). While  construction  progress has been significant,
high  activity  in the oil sands 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.  As a result,
the  projected  costs of Long Lake have  increased  from $3.8  billion  to $4.6
billion ($1.9 billion to $2.3 billion net).  Although we are seeing pressure on
capital  costs,  we  expect  to  benefit  from  a  significant  operating  cost
advantage.  Combined  SAGD,  cogeneration  and  upgrading  operating  costs are
expected to average  between  $12/bbl  and  $14/bbl,  substantially  lower than
coking  upgrading.  We expect  ongoing  capital to average  between  $3/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.


                                      12
<PAGE>

FUTURE PHASES

     We have  approximately  240,000  net acres of  bitumen-prone  lands in the
Athabasca  region and plan to acquire 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 invested $119 million for future phases and in 2007, we plan to invest
approximately $170 million on land acquisition,  additional  drilling,  seismic
and engineering to develop our leases and advance  regulatory  applications for
these phases. Phase 2 SAGD production is expected to be on stream by late 2011,
with  upgrader  start up by the second  half of 2012,  followed  by  additional
phases every two or three years.  Each phase will  leverage the  knowledge  and
experience  gained  from  successfully  developing  Long  Lake  and  subsequent
projects will be similar in size and design.  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.

                  PHASE 2 SAGD PRODUCTION IS EXPECTED TO BE ON
          STREAM BY LATE 2011 FOLLOWED BY UPGRADER START UP IN 2012.

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 integrated  project has been designed to virtually  eliminate.  At December
31, 2006, we recognized  proved bitumen  reserves of 246 mmboe before royalties
(219 after  royalties)  for our Long Lake  project,  representing  about 23% of
Nexen's total proved oil and gas and Syncrude reserves before royalties.

HEAVY OIL

     Approximately  52% of our Canadian  conventional  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  receives a lower price than light oil, as more  expensive
and complex refineries are required to refine the heavy crude into higher-value
petroleum products.

     Our heavy oil  operations  are in  east-central  Alberta and  west-central
Saskatchewan.  To maximize heavy oil returns, it is important to manage capital
and operating costs. Our large production base and existing  infrastructure are
advantageous  to us in  managing  these  costs.  In 2007,  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 increase our
heavy oil  recoveries  with  several  ongoing  pilot  projects in  west-central
Saskatchewan.

NATURAL GAS

     Approximately  48% of our Canadian  production  is natural gas  extracted
primarily from shallow sweet  reservoirs in southern  Alberta and Saskatchewan
and from sour gas reservoirs near Calgary.  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.

COALBED METHANE (CBM)

     In 2005, we approved  commercial CBM  developments  at Corbett,  Doris and
Thunder  in the Fort  Assiniboine  area.  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 Upper  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.

                                      13
<PAGE>

     In 2006,  we  invested  approximately  $237  million  in  exploration  and
development  activities.  We have a long-term view of this business and plan to
increase our CBM production to at least 150 mmcf/d by 2011,  more than doubling
our current Canadian  natural gas production.  At the end of 2006, we held more
than 700 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 2007, we plan to invest
$200 million to develop 98 gross (41 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 2007.

SHALE GAS

     As part of our growth strategy in unconventional  Canadian resource plays,
we acquired over 100 sections of land in an emerging  shale gas play in western
Canada in 2006.  Shale gas is natural gas produced from reservoirs  composed of
organic  shale.  The gas is stored in pore spaces,  fractures or adsorbed  into
organic matter.  Currently,  the United States is the largest producer of shale
gas.  In 2007,  we plan to  initiate  a  drilling  and  evaluation  program  to
demonstrate the feasibility of this resource.

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 3.3%, which is reduced to
1.85% for wells completed after October 1, 2002.

     Profits  earned in Canada from resource  properties are subject to federal
and  provincial  income taxes.  In 2006,  legislation  was passed to reduce the
federal  corporate  income  tax  rate  on  income  from  Canadian  oil  and gas
activities from 24% to 19% by 2010.

     For our oil sands  projects,  we elected to 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 changes to 25% on net revenue.  With
the combination of low royalties,  our expected  operating cost advantage and a
premium product,  our oil sands financial returns are expected to be attractive
relative to other oil sands projects.

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 opens doors elsewhere in
the Middle East and around the world.

                    ALTHOUGH OUR MASILA FIELDS HAVE MATURED,
             WE EXPECT TO GENERATE APPROXIMATELY 20% OF THE TOTAL
            PROJECT CASH FLOW FROM THE REMAINING PROVED RESOURCES.

     Our strategy is to maximize the value from our existing  blocks,  while we
continue to search for new reservoirs in deeper horizons. We have two producing
blocks:  Masila  (Block 14) and East Al Hajr (Block  51). In 2006,  we produced
92,900 bbls/d of oil before royalties  (51,800 after  royalties),  representing
approximately 44% of Nexen's total production and 32% of 2006 cash flow. Proved
reserves  of  66  mmboe  before   royalties  (38  after   royalties)   comprise
approximately  6% of Nexen's  total  proved oil and gas and  Syncrude  reserves
before royalties.

                                      14
<PAGE>

MASILA BLOCK (BLOCK 14)

     We have a 52% working  interest in and  operate  the Masila  project.  Our
share of 2006  production  was 70,300  bbls/d  before  royalties  (35,500 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  20% of the  total  project  free  cash  flow  from the
remaining proved reserves recoverable before the PSA expires in 2011.

     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  32(degree) API at very low gas-oil  ratios.  Most of
the oil is produced  from the Upper Qishn  formation,  but we also produce from
deeper formations  including the Lower Qishn,  Upper Saar, Saar,  Madbi,  Basal
Sand and Basement formations.

     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 2007, we
plan to invest approximately $55 million to drill 14 wells.

     The PSA  governing  Masila  production  was  signed  in 1987  between  the
Government of Yemen and the Masila joint venture  partners  (Masila  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
Masila  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 Masila
Partners  and the  Government  and is  calculated  on a sliding  scale based on
production.  The Masila  Partners'  share of profit oil ranges from 20% to 33%.
The structure of the agreement  moderates the impact on Masila  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 73% of the profit oil, which includes a
component  for Yemen income taxes  payable by the Masila  Partners at a rate of
35%. In 2006, the Masila Partners' share of production,  including  recovery of
past costs, was approximately 37%.


                                      15
<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 East Al Hajr partners
(EAH 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.  Our  effective  interest  is 100% and for
purposes  of  accounting  and  reserves  recognition,  we  treat  TYCO's  12.5%
participating   interest  as  a  royalty   interest.   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 EAH  Partners pay a royalty  ranging from 3% to
10% to the Government depending on production volumes. The remaining production
is divided into cost  recovery oil and profit oil.  Cost  recovery oil provides
for the recovery of all of the project's exploration, development and operating
costs,  funded solely by Nexen.  Costs are  recovered  from a maximum of 50% of
production each year after royalties, as follows:


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

     The  remaining  production  is profit oil that is shared  between  the EAH
Partners and the Government on a sliding scale based on production  rates.  The
EAH  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
EAH  Partners at a rate of 35%. In 2006,  the EAH  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.
Production  began in November 2004 and we achieved payout on the project in the
first  quarter of 2006.  During the year,  production  averaged  22,600  bbls/d
before royalties (16,300 after royalties).


          WE ACHIEVED PAYOUT ON BLOCK 51 IN THE FIRST QUARTER OF 2006.

     In 2006, we drilled three  exploration wells on the block and two of these
wells were abandoned.  In 2007, we plan to invest  approximately $80 million to
drill nine  development  wells,  construct  additional  facilities and continue
exploring with three exploration wells.


                                      16
<PAGE>

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.

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
-------------------------------------------------------------------------------------------------------------------------------
<C>      <C>          <C>                   <C>
1998     Ukot-1       Ukot field            encountered three oil-bearing intervals and flowed at restricted rate of 13,900
                      discovery well        bbls/d from two intervals
-------------------------------------------------------------------------------------------------------------------------------
2002     Usan-1       Usan field            encountered several oil-bearing intervals and flowed at restricted rate of 5,000
                      discovery well        bbls/d from one interval
-------------------------------------------------------------------------------------------------------------------------------
2003     Usan-2       3 km west of          appraised up-dip portion of the fault block
                      discovery
-------------------------------------------------------------------------------------------------------------------------------
2003     Usan-3       2 km northwest of     appraised separate fault block and flowed at restricted rate of 5,600 bbls/d from
                      discovery             one interval
-------------------------------------------------------------------------------------------------------------------------------
2003     Ukot-2       3.5 km south of       encountered three oil-bearing intervals
                      discovery
-------------------------------------------------------------------------------------------------------------------------------
2003     Usan-4       5 km south of         flowed at restricted rate of 4,400 bbls/d from first interval and 6,300 bbls/d
                      discovery             from second interval
-------------------------------------------------------------------------------------------------------------------------------
2004     Usan-5       6 km west of          sampled oil in several intervals
                      discovery
-------------------------------------------------------------------------------------------------------------------------------
2004     Usan-6       4 km south of Usan-5  flowed at restricted rate of 5,800 bbls/d from one interval
-------------------------------------------------------------------------------------------------------------------------------
                      9 km southwest of
2005     Usan-7       discovery             confirmed an eastern extension of the field
-------------------------------------------------------------------------------------------------------------------------------
2005     Usan-8       3 km southwest of     confirmed an eastern extension of the field
                      discovery
===============================================================================================================================
</TABLE>

     Appraisal  of this  field  is  complete.  The  Nigerian  authorities  have
provisionally  approved the preliminary Usan field  development plan. We expect
the Usan  development to be formally  sanctioned in 2007, with first production
as early as 2010.

                        USAN IS EXPECTED TO BE PRODUCING
            BY 2011, ADDING ABOUT 30,000 BBLS/D TO OUR PRODUCTION.

The development will include a FPSO with storage capacity of two million
barrels, capable of handling peak production rates of 160,000 bbls/d of oil. In
2007, we plan to invest approximately $140 million to progress development by
completing our cost estimate. We have a 20% interest in this development
program. Proved reserves of 30 mmboe before royalties (25 after royalties)
comprise approximately 3% of Nexen's total proved oil and gas and Syncrude
reserves.

     In 2006,  we  drilled  the  deep-water  Ukot  South  well.  This  well was
unsuccessful and the capital costs were expensed.


Block OML-115
     We relinquished this block during the year.

Block OML-109--Ejulebe
     In 2005,  we sold our  producing  assets and  terminated  our  contractual
interest in this block.


                                      17
<PAGE>

EQUATORIAL GUINEA--BLOCK K

     We relinquished this block during the year.

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 2006 production  averaged
6,300 bbls/d  before  royalties  (5,700 after  royalties),  about 3% of Nexen's
total production including Syncrude.

     Production  from  Guando is subject to a 5% to 25%  royalty  depending  on
daily production.  In 2006,  legislation was introduced to reduce the corporate
income  tax rate  from  38.5%  in 2006 to 34% in  2007,  and to 33% in 2008 and
future years.

Exploration Blocks

     We have  interests  in three  exploration  blocks in the  Upper  Magdalena
Basin.  Villarrica  was acquired in 2000, El Queso in 2003 and Boqueron Deep in
2003. In 2005, we relinquished the Villarrica Block and acquired the Villarrica
Norte Block under improved  fiscal terms.  In 2006, we drilled a well on the El
Queso block which we are currently evaluating.  We are currently  participating
in a well on Boqueron Deep and plan to drill a well on  Villarrica  Norte later
in 2007. In addition,  we are assessing  potential  drilling  opportunities  in
other areas of the Upper Magdelena Basin.

NORWAY

     As part of our growth  strategy in the North Sea, we  participated  in the
2006 bid  round  for  exploration  rights  offshore  Norway  and  were  awarded
interests  in four  licenses  in early  2007.  In 2007,  we  expect  to  invest
approximately $30 million in additional seismic and geologic studies there.

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.

<TABLE>
<CAPTION>
Oil and Gas Acreage
                                                                        2006
                        ------------------------------------------------------------------------------------------------------
                                        DEVELOPED                     UNDEVELOPED (1)                         TOTAL
(thousands of acres)              GROSS           NET            GROSS              NET             GROSS                NET
------------------------------------------------------------------------------------------------------------------------------
<S>                              <C>             <C>           <C>              <C>               <C>                <C>
Yemen (2)                            50            29              756              628               806                657
------------------------------------------------------------------------------------------------------------------------------
Canada                              781           578            2,081            1,095             2,862              1,673
------------------------------------------------------------------------------------------------------------------------------
United States                       183           103            1,396              650             1,579                753
------------------------------------------------------------------------------------------------------------------------------
United Kingdom                       83            27            1,822            1,031             1,905              1,058
------------------------------------------------------------------------------------------------------------------------------
Colombia (4)                          1             -              604              463               605                463
------------------------------------------------------------------------------------------------------------------------------
Nigeria (2), (3)                      -             -              448               90               448                 90
------------------------------------------------------------------------------------------------------------------------------
TOTAL                             1,098           737            7,107            3,957             8,205              4,694
==============================================================================================================================
</TABLE>
NOTES:
(1)  UNDEVELOPED  ACREAGE IS  CONSIDERED TO BE THOSE ACRES ON WHICH WELLS HAVE
     NOT BEEN DRILLED OR COMPLETED TO A POINT THAT WOULD PERMIT  PRODUCTION OF
     COMMERCIAL  QUANTITIES OF CRUDE OIL AND NATURAL GAS REGARDLESS OF WHETHER
     OR NOT SUCH ACREAGE CONTAINS PROVED RESERVES.
(2)  THE ACREAGE IS COVERED BY PRODUCTION SHARING CONTRACTS.
(3)  THE ACREAGE IS COVERED BY A JOINT VENTURE AGREEMENT.
(4)  THE ACREAGE IS COVERED BY AN ASSOCIATION CONTRACT.

                                      18
<PAGE>

<TABLE>
<CAPTION>
Producing Oil and Gas Wells
                                                                        2006
                      ---------------------------------------------------------------------------------------------------------
                                         OIL                                GAS                                TOTAL
(number of wells)           GROSS (1)          NET (2)           GROSS (1)         NET (2)          GROSS (1)         NET (2)
-------------------------------------------------------------------------------------------------------------------------------
<S>                         <C>               <C>               <C>              <C>                <C>             <C>
Yemen                             428              249                   -               -                428             249
-------------------------------------------------------------------------------------------------------------------------------
Canada                          2,196            1,519               2,627           2,279              4,823           3,798
-------------------------------------------------------------------------------------------------------------------------------
United States                     191               91                 199             138                390             229
-------------------------------------------------------------------------------------------------------------------------------
United Kingdom                     39               17                   -               -                 39              17
-------------------------------------------------------------------------------------------------------------------------------
Colombia                           91               19                   -               -                 91              19
-------------------------------------------------------------------------------------------------------------------------------
TOTAL                           2,945            1,895               2,826           2,417              5,771           4,312
===============================================================================================================================
</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>
Drilling Activity
                                                                      2006
                       --------------------------------------------------------------------------------------------------------
                                        NET EXPLORATORY                               NET DEVELOPMENT                   TOTAL
(number of net wells)       PRODUCTIVE        DRY HOLES      TOTAL        PRODUCTIVE        DRY HOLES      TOTAL
-------------------------------------------------------------------------------------------------------------------------------
<S>                            <C>               <C>         <C>             <C>               <C>        <C>         <C>
Yemen                              3.0              5.5        8.5              36.0              1.0       37.0         45.5
-------------------------------------------------------------------------------------------------------------------------------
Canada                            35.4              2.2       37.6             214.3              0.7      215.0        252.6
-------------------------------------------------------------------------------------------------------------------------------
United States                      1.6              2.1        3.7               8.3              2.0       10.3         14.0
-------------------------------------------------------------------------------------------------------------------------------
United Kingdom                     0.8              1.7        2.5               5.5                -        5.5          8.0
-------------------------------------------------------------------------------------------------------------------------------
Colombia                             -                -          -               2.0                -        2.0          2.0
-------------------------------------------------------------------------------------------------------------------------------
Nigeria                              -              0.2        0.2                 -                -          -          0.2
-------------------------------------------------------------------------------------------------------------------------------
TOTAL                             40.8             11.7       52.5             266.1              3.7      269.8        322.3
===============================================================================================================================

<CAPTION>
                                                                        2005
                       --------------------------------------------------------------------------------------------------------
                                        NET EXPLORATORY                               NET DEVELOPMENT                   TOTAL
(number of net wells)       PRODUCTIVE        DRY HOLES      TOTAL        PRODUCTIVE        DRY HOLES      TOTAL
-------------------------------------------------------------------------------------------------------------------------------
<S>                            <C>               <C>         <C>             <C>               <C>        <C>         <C>
Yemen                              0.5              4.6        5.1              33.0              1.6       34.6         39.7
-------------------------------------------------------------------------------------------------------------------------------
Canada                            32.2              8.0       40.2             198.9              0.5      199.4        239.6
-------------------------------------------------------------------------------------------------------------------------------
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
-------------------------------------------------------------------------------------------------------------------------------
Colombia                             -                -          -               1.8                -        1.8          1.8
-------------------------------------------------------------------------------------------------------------------------------
Nigeria                            0.4              0.2        0.6                 -                -          -          0.6
-------------------------------------------------------------------------------------------------------------------------------
Equatorial Guinea                    -              0.5        0.5                 -                -          -          0.5
-------------------------------------------------------------------------------------------------------------------------------
TOTAL                             33.6             16.0       49.6             242.4              3.1      245.5        295.1
===============================================================================================================================

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

Wells in Progress

     At December 31, 2006, we were drilling 5 wells in Yemen (3.6 net), 5 wells
in Canada (5 net),  2 wells in the  United  States  (1.6  net),  3 wells in the
United Kingdom (1.6 net), and 1 well in Colombia (0.5 net).

                                      19
<PAGE>

Net Sales by Product from Continuing Oil and Gas Operations (including Syncrude)

<TABLE>
<CAPTION>
(Cdn$ millions)                                                                         2006     2005      2004
-----------------------------------------------------------------------------------------------------------------
<S>                                                                                    <C>      <C>       <C>
Conventional Crude Oil and Natural Gas Liquids (NGLs)                                  2,479    2,438     1,697
-----------------------------------------------------------------------------------------------------------------
Synthetic Crude Oil                                                                      446      397       321
-----------------------------------------------------------------------------------------------------------------
Natural Gas                                                                              553      671       534
-----------------------------------------------------------------------------------------------------------------
TOTAL                                                                                  3,478    3,506     2,552
=================================================================================================================
</TABLE>

    Crude oil (including synthetic crude oil) and natural gas liquids represent
approximately 84% of our oil and gas net sales, while natural gas represents the
remaining 16%.

Sales Prices and Production Costs (excluding Syncrude)

<TABLE>
<CAPTION>
                                                 AVERAGE SALES PRICE (1)       AVERAGE PRODUCTION COST (1)
                                                2006       2005      2004        2006     2005     2004
---------------------------------------------------------------------------------------------------------
<S>                                           <C>        <C>       <C>          <C>      <C>      <C>
CRUDE OIL AND NGLS (Cdn$/bbl)
---------------------------------------------------------------------------------------------------------
  Yemen                                        71.57      62.07     47.59        8.11     6.75     5.64
---------------------------------------------------------------------------------------------------------
  Canada (2)                                   42.79      40.51     36.60       15.50    14.01    11.76
---------------------------------------------------------------------------------------------------------
  United States                                65.80      57.63     46.60        9.45     7.33     6.09
---------------------------------------------------------------------------------------------------------
  United Kingdom                               71.19      60.55     46.81       11.28    14.90     8.26
---------------------------------------------------------------------------------------------------------
  Australia (2)                                    -          -     51.22           -        -    35.73
---------------------------------------------------------------------------------------------------------
  Other Countries                              66.09      59.96     43.07        3.13     6.08     4.09
---------------------------------------------------------------------------------------------------------

<CAPTION>
NATURAL GAS (Cdn$/mcf)
---------------------------------------------------------------------------------------------------------
<S>                                           <C>        <C>       <C>          <C>      <C>      <C>
  Canada (2)                                    6.49       7.51      5.76        1.65     0.95     0.85
---------------------------------------------------------------------------------------------------------
  United States                                 7.86      10.56      7.89        1.58     1.22     1.02
---------------------------------------------------------------------------------------------------------
  United Kingdom                                7.43       7.86      8.28        1.88     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 FOR 2005 AND 2004. (SEE NOTE
     14 TO OUR CONSOLIDATED FINANCIAL STATEMENTS.)

PROVED RESERVES INCLUDING PROVED UNDEVELOPED RESERVES

     At  December  31,  2006,  we had 725 mmboe of proved oil and gas  reserves
before royalties (637 after  royalties).  This is a 55% increase over the prior
year (62% after royalties).  Including  Syncrude,  our total proved oil and gas
and  Syncrude  reserves  increased  34%  to  1,049  mmboe  (39%  to  911  after
royalties).

     The  following  table  provides a summary of the changes in our proved oil
and gas reserves (before royalties)  excluding our Syncrude reserves.  Refer to
page  116  in  our  2006  Form  10-K  for  proved  reserves  information  on an
after-royalties basis.

<TABLE>
<CAPTION>
                                                           UNITED      UNITED                  OTHER
(mmboe)                                      CANADA       KINGDOM      STATES     YEMEN    COUNTRIES      TOTAL
-----------------------------------------------------------------------------------------------------------------
<S>                                          <C>          <C>          <C>        <C>      <C>            <C>
December 31, 2005                               117           145          90       105           11        468
-----------------------------------------------------------------------------------------------------------------
  Extension and Discoveries                      11            25           7         4           30         77
-----------------------------------------------------------------------------------------------------------------
  Revisions                                     249            20         (11)       (8)           1        251
-----------------------------------------------------------------------------------------------------------------
  Production                                    (13)           (8)        (13)      (35)          (2)       (71)
-----------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2006                               364           182          73        66           40        725
=================================================================================================================
</TABLE>

                                       20
<PAGE>

     Extensions and discoveries contributed 77 mmboe (67 after royalties).  The
majority  of the  increase  results  from  new  development  projects  at Usan,
offshore West Africa,  the Ettrick and Duart fields in the North Sea,  Ringo in
the Gulf of Mexico,  and coalbed methane in Canada.  Other increases  relate to
ongoing exploitation activities in the North Sea, Yemen, the Gulf of Mexico and
Canada.

     The revisions relate primarily to our Long Lake project.  Under SEC rules,
we are  required  to  recognize  bitumen  reserves  rather  than  the  upgraded
synthetic  crude oil that we will produce and sell.  As such,  proved  reserves
recognition depends on year end oil prices, light/heavy differentials,  diluent
prices and natural gas prices. We initially  recognized proved bitumen reserves
at Long Lake in early 2004 when we sanctioned  development of the project.  The
reserves  were,  however,  written  off at the  end of  the  year  due to  wide
light/heavy  differentials  and high  natural  gas  costs.  At the end of 2006,
narrow  light/heavy  differentials  and low  natural  gas costs  allowed  us to
recognize  proved bitumen reserves of 246 mmboe (219 after  royalties).  In the
North  Sea,  the  additions  reflect  increases  at  Buzzard  as  a  result  of
development  drilling and an increase in the proved recovery factor. In Canada,
the  additions  relate  primarily  to our heavy  oil  properties  where  narrow
light/heavy  differentials  increased  the amount of  economically  recoverable
reserves.  Negative revisions occurred on Block 51 in Yemen and the Aspen field
in  the  Gulf  of  Mexico  as  a  result  of  lower  than  expected  production
performance.

PROVED UNDEVELOPED RESERVES

     The following table provides a summary of our proved undeveloped  reserves
(PUDs) for our oil and gas activities at December 31, 2006 and 2005:

<TABLE>
<CAPTION>
                                     BEFORE ROYALTIES        % OF               AFTER ROYALTIES         % OF
(mmboe)                    PUDS       TOTAL PROVED (1)      TOTAL      PUDS     TOTAL PROVED (1)       TOTAL
--------------------------------------------------------------------------------------------------------------
<S>                         <C>      <C>          <C>       <C>       <C>       <C>                     <C>
Canada                      216                   364         59%       188                 319          59%
--------------------------------------------------------------------------------------------------------------
United Kingdom               50                   182         27%        50                 182          27%
--------------------------------------------------------------------------------------------------------------
Yemen                         9                    66         14%         5                  38          13%
--------------------------------------------------------------------------------------------------------------
United States                 9                    73         12%         7                  63          11%
--------------------------------------------------------------------------------------------------------------
Other Countries              31                    40         78%        25                  35          71%
--------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2006           315                   725         43%       275                 637          43%
==============================================================================================================


Canada                       13                   117         11%        11                 101          11%
--------------------------------------------------------------------------------------------------------------
United Kingdom              128                   145         88%       128                 145          88%
--------------------------------------------------------------------------------------------------------------
Yemen                        23                   105         22%        13                  59          22%
--------------------------------------------------------------------------------------------------------------
United States                15                    90         17%        13                  77          17%
--------------------------------------------------------------------------------------------------------------
Other Countries               1                    11          5%         -                  11           5%
--------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2005           180                   468         38%       165                 393          42%
==============================================================================================================
</TABLE>
NOTE:
(1)  EXCLUDES  PROVED  RESERVES FOR OUR SYNCRUDE  OPERATIONS  OF 324 MMBOE (274
     AFTER ROYALTIES) IN 2006 AND 318 MMBOE (264 AFTER ROYALTIES) IN 2005.

     In 2006, our PUDs increased by 135 mmboe (110 after  royalties).  We added
206 mmboe  (179  after  royalties)  at Long Lake  relating  to proved  reserves
outside of the initial 81 well-pair SAGD  development  area. We also added PUDs
from our new development  projects at Usan,  Ettrick,  Ringo, Duart and CBM. We
converted  117 mmboe  (112  after  royalties)  of PUDs to  developed,  with the
majority relating to the completion of the Buzzard development  project.  Other
small additions and conversions occurred from ongoing development activities at
Canada, the United States, Yemen, the United Kingdom and Colombia.

     In Canada,  our PUDs increased  from 13 mmboe (11 after  royalties) to 216
mmboe (188 after royalties).  Substantially all of the increase relates to Long
Lake where we added 206 mmboe (179 after royalties). These PUDs are expected to
be converted to developed over the next 20 years as we drill  additional  wells
to provide feedstock to run the upgrader at capacity. The remaining 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 2007 and 2008. Also, a small portion of the
PUDs  relate to our CBM  properties,  which are  expected  to be  converted  to
producing by infill drilling and field development planned for 2007 and 2008.

                                      21
<PAGE>

     In the  United  Kingdom,  our PUDs  decreased  from 128 mmboe  (128  after
royalties)  to 50 mmboe (50 after  royalties)  primarily  from  completing  the
Buzzard development,  which converted 80% of the related PUDs to developed. The
remaining Buzzard PUDs are expected to be converted to proved over the next few
years as we drill additional wells to keep the platform  operating at capacity.
PUDs were  added by our  Ettrick  development,  which we expect to  convert  to
producing in 2008.

     In Yemen,  the PUDs are split  relatively  equally  between our Masila and
East Al Hajr Blocks.  These reserves relate entirely to infill drilling,  which
we plan to carry-out during 2007 and 2008.

     In the United States,  our PUDS decreased from ongoing  development of our
Gulf of Mexico deep-water and shelf properties.  In 2006, additions principally
relate to the Ringo and Tobago developments, which are expected to be producing
within the next two years.

     In other countries,  our PUDs increased by 30 mmboe (25 after  royalties),
resulting  from   recognizing   proved   reserves   associated  with  our  Usan
development, offshore West Africa.

     Excluding  Long Lake and Usan,  we expect to convert about 80% of our PUDs
to  producing  in 2007 and  2008.  Usan  will be  converted  by 2011 when it is
expected to come on stream.  Long Lake PUDs will be converted  over the next 20
years as initial SAGD wells  deplete.  At the same time,  we expect our ongoing
exploration and development activities to continue to add new PUDs.

BASIS OF RESERVES ESTIMATES

     Reserve  estimates in this report are  internally  prepared.  Refer to the
section on Critical  Accounting  Estimates - Oil and Gas  Accounting - Reserves
Determination  on  page  62 for a  description  of  our  reserves  process.  As
described  therein,  we have at least 80% of our oil and gas reserve  estimates
either  evaluated  or  audited  annually  by  independent   qualified  reserves
consultants.  The nature and scope of the independent evaluations and audits is
determined  by  agreement  between  us and the  engineering  firm.  Independent
assessments for other companies may, therefore, be different.

     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
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,  Yemen Block 51 and Nigeria. A separate opinion was provided on each of
these four 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.

                                      22
<PAGE>

     We engaged McDaniel & Associates Consultants Ltd. ("McDaniel") to evaluate
98% of our Canadian  conventional,  CBM and bitumen  reserves before  royalties
(98% 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 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 82% of our U.S.
Gulf of Mexico shelf  reserves  before  royalties  (82% 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(degree) 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.  Trucks and shovels are
used to  collect  the oil  sands in the  open  pit  mines.  The oil  sands  are
transferred for processing using a hydro-transport system.

     The  extraction  facilities,  which separate  bitumen from oil sands,  are
capable  of  processing  more than 270  million  tons of oil sands per year and
about 160 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 three
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.

     The high quality of Syncrude's synthetic crude oil allows it to be sold at
prices  approximating  WTI. In 2006,  about 40% of the synthetic  crude oil was
sold to Edmonton area refineries,  and the remaining 60% was sold to refineries
in Eastern Canada and the mid-western United States.

     Electricity is provided to Syncrude from two generating  plants on site: a
270 MW plant and an 80 MW plant.


                                      23
<PAGE>

     Since  operations  started in 1978,  Syncrude  has  shipped  more than 1.7
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 December 31, 2006,  our total  investment  in the  property,  plant and
equipment,  including surface mining facilities,  transportation equipment, and
upgrading  facilities,  was  approximately  $1.3 billion.  Based on development
plans, our share of future expansion and equipment  replacement  costs over the
next 35 years is expected to be more than $2.5 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 equaled $2.8 billion (gross). That total
was surpassed at the end of 2001. In 2006, we realized full recovery of allowed
capital costs and, as a result,  Syncrude  royalties are 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.  The next  expansion of Syncrude  came
on-stream in 2006, increasing capacity to 360,000 bbls/d with the completion of
the Stage 3 project.  Our share of capital  spending  in 2007 is expected to be
$50 million.

     In 2006,  Syncrude's  production  of  marketable  synthetic  crude oil was
258,400 bbls/d.  Nexen's share was 18,700 bbls/d before royalties (16,900 after
royalties).

     The  following  table  provides  some  operating  statistics  for Syncrude
operations:

                                                2006        2005        2004
------------------------------------------------------------------------------
TOTAL MINED VOLUME (1)
------------------------------------------------------------------------------
  Millions of Tons                               428         353         389
------------------------------------------------------------------------------
  Mined Volume to Oil Sands Ratio (1)            2.2         2.1         2.1
------------------------------------------------------------------------------
OIL SANDS PROCESSED
------------------------------------------------------------------------------
  Millions of Tons                               192         169         188
------------------------------------------------------------------------------
  Average Bitumen Grade (weight %)              11.3        11.1        11.1
------------------------------------------------------------------------------
BITUMEN IN MINED OIL SANDS
------------------------------------------------------------------------------
  Millions of Tons                                22          19          21
------------------------------------------------------------------------------
  Average Extraction Recovery (%)                 90          89          87
------------------------------------------------------------------------------
BITUMEN PRODUCTION (2)
------------------------------------------------------------------------------
  Millions of Barrels                            112          94         103
------------------------------------------------------------------------------
  Average Upgrading Yield (%)                     85          85          86
------------------------------------------------------------------------------
GROSS SYNTHETIC CRUDE OIL SHIPPED (3)
------------------------------------------------------------------------------
  Millions of Barrels                             94          78          87
------------------------------------------------------------------------------
NEXEN'S SHARE OF MARKETABLE CRUDE OIL
------------------------------------------------------------------------------
  Millions of Barrels Before Royalties           6.8         5.7         6.3
------------------------------------------------------------------------------
  Millions of Barrels After Royalties            6.2         5.6         6.1
==============================================================================
NOTES:
(1)  INCLUDES PRE-STRIPPING OF MINE AREAS.
(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,
     PRIMARILY  FOR DIESEL THAT FUELS THE TRUCKS AND SHOVELS AT  SYNCRUDE.  THE
     REMAINING SYNTHETIC CRUDE OIL IS SOLD EXTERNALLY.


                                      24
<PAGE>

ENERGY MARKETING

     Our marketing group sells  proprietary and third-party  natural gas, crude
oil, natural gas liquids, ethanol and power in certain regional global markets.
We have built a solid strategic presence within various North American regional
markets and extended our presence into certain global markets as well. We focus
on  securing  access to  transportation,  storage  and  facilities,  as well as
commodities we produce or acquire.  We optimize the margin on our base business
by  physically  and  financially  trading  around our access to these  physical
assets.  We also trade financially for profit where we see opportunities in the
market. 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  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;
        o    capitalize on market opportunities  through physical and financial
             trading; and
        o    optimize physical assets or contracts to which we have access.

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


NORTH AMERICAN GAS MARKETING

     The marketing and trading of North  American  natural gas is our marketing
group's largest revenue source.  We focus on key regional markets where we have
a strategic  presence--solid customer relationships,  in-depth understanding of
the market or established physical 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
             locations) using our transportation assets;
        o    capitalizing on time spreads (differences in prices between summer
             and winter) using our storage assets; and
        o    financial trading of location and time spreads.

     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
north-eastern United States and the US mid-continent.  Our Detroit office works
closely  with  Calgary to provide  services to our  customers.  Our presence in
Houston  has  established  us in the Gulf  Coast  region  where we have our own
production.

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

     In 2003 and  2004,  we grew  our  asset  base by  acquiring  physical  gas
purchase and sales contracts, as well as natural


                                      25
<PAGE>

gas transportation  capacity,  on favourable terms. This gives 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.  In 2006,  we  continued  to grow  our  storage  and  transportation
positions through acquisitions as well as bidding processes.  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 2006, we held 3.3 bcf/d of pipeline  capacity,  primarily between
western  Canada and the eastern US, and we continue to expand our presence into
other  markets  within  North  America.  We also use storage  capacity to store
typically  cheaper  summer gas in the ground  until the winter  heating  season
arrives.  We had access to 50 bcf of natural gas storage  facilities at the end
of the year.

           WE USE OUR ACCESS TO TRANSPORTATION AND STORAGE FACILITIES
        TO OPTIMIZE RETURNS, CAPITALIZING ON LOCATION AND TIME SPREADS.

     In  addition  to  transportation  and storage  assets,  we hold  financial
contracts that enable us to capture  profits around time and location  spreads.
The risks we assume on these  contracts are based on  fundamental  analysis and
knowledge of regional markets.  The risk is managed  proactively by our product
group  teams  and  monitored  by our risk  group,  with  regular  reporting  to
management and the board of directors.

INTERNATIONAL 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,  Houston  and  Denver.  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, we continue to expand 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.
At the end of 2006,  we had access to 1.7 mmbbls of storage and over the course
of the year, moved approximately 705 mbbls per day.

     In the last two years,  we acquired two North American  natural gas liquid
(NGL) and ethanol  businesses  that focus on buying and selling NGLs as well as
diesel,  ethanol and natural gasoline.  These businesses  acquire and move NGLs
into the US midwest and Gulf Coast from Canada, as well as providing denaturant
for ethanol  production and the marketing of finished ethanol in the US. At the
end of 2006,  we had access to 550 mbbls of storage  and over the course of the
year, moved approximately 25 mbbls per day of product.

     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. We established an office in
London, United Kingdom to maximize the value of our North Sea production.  With
Buzzard  crude on stream in early 2007,  we expect to increase  our presence in
various global markets, ensuring we maximize the value of this production.

     Our crude oil marketing group also holds financial  contracts  intended to
capture trading  profits around time,  quality and location  spreads.  Like gas
marketing,  the risks assumed are based on fundamental analysis and proprietary
knowledge of regional markets, and are monitored by our risk group.

NORTH AMERICAN POWER MARKETING

     Our power marketing group is responsible for optimizing the use of our 50%
interest in a 100 MW gas-fired,  combined-cycle  power  generation  facility at
Balzac,  Alberta,  as well as our recently completed 70 MW Soderglen wind power
operation  in  southern  Alberta.  We also market  power to larger  commercial,
industrial  and municipal  clients in Alberta.  With the 2005  acquisition of a
commercial/industrial  marketing  business  in  Alberta,  we became the largest
supplier of power to the commercial and industrial sectors in the province. Our
Balzac  facility  began  operations  in 2001 and  Soderglen in October 2006. We
expect to increase our power  generation  capacity with a 170 MW  co-generation
facility at Long Lake in 2007. We have a 50% interest in this project.

                                      26
<PAGE>

EUROPEAN GAS AND POWER MARKETING

     In 2006, we acquired a UK-based European gas and power marketing  business
that focuses on UK gas and power as well as German power. In 2007, we expect to
increase  our  presence  in both the UK and  continental  Europe  gas and power
markets.

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% 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.  The
proximity  of our  manufacturing  plants  to major  customers  and  competitive
freight rates minimize 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 reducing our costs
while maintaining market share,  building a sustainable North American customer
base and capturing new offshore opportunities.

Average Annual Production Capacity

(short tons)                        2006              2005              2004
------------------------------------------------------------------------------
SODIUM CHLORATE
------------------------------------------------------------------------------
  North America                  446,208           446,208           446,617
------------------------------------------------------------------------------
  Brazil                          68,563            68,563            68,563
------------------------------------------------------------------------------
TOTAL                            514,771           514,771           515,180
------------------------------------------------------------------------------
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  adjustment  provisions.  Approximately  32% of this
production is sold in Canada, 61% 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.


                                      27
<PAGE>

     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. In late 2006, we began another expansion of our plant in Brandon
which is  expected to increase  capacity  by 32,300  tonnes per year,  early in
2008.

     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 sodium chlorate  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.

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,  Syncrude  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,  2006,  $704  million  ($1,770  million,  undiscounted)  has been
provided  in  our  Consolidated   Financial  Statements  for  asset  retirement
obligations.  In 2006,  we  increased  our  retirement  obligations  for future
dismantlement   and  site  restoration  by  $75  million   primarily  from  the
development of the Buzzard field in the North Sea.

     In 2006,  our  capital  expenditures  for  environmental-related  matters,
including  environment control facilities,  were approximately $44 million. Our
operating expenditures for environmental-related  matters were approximately $6
million.  In 2007,  we estimate  these  expenditures  to be  approximately  $21
million.

EMPLOYEES

     We had 3,687  employees on December 31, 2006,  of which 266 were  employed
under collective  bargaining schemes.  Information on our executive officers is
presented in Item 10 of this report.

                                      28
<PAGE>

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

     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 9, 2007.

     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 81 in our 2006 Form 10-K,  as filed with the  Securities  and
Exchange Commission on February 26, 2007, which highlights  differences between
our reserve  estimates and related  disclosures that are otherwise  required by
Canadian regulatory authorities.

                                                                           PAGE
                                                                           ----

EXECUTIVE SUMMARY                                                           30

CAPITAL INVESTMENT                                                          31

FINANCIAL RESULTS
     Year-to-Year Change in Net Income                                      35
     Oil & Gas and Syncrude
              Production                                                    36
              Commodity Prices                                              39
              Operating Expenses                                            42
              Depreciation, Depletion, Amortization and Impairment          43
              Exploration Expense                                           45
     Oil & Gas and Syncrude Netbacks                                        47
     Energy Marketing                                                       48
     Chemicals                                                              51
     Corporate Expenses                                                     52

OUTLOOK FOR 2007                                                            55

LIQUIDITY AND CAPITAL RESOURCES                                             56

CRITICAL ACCOUNTING ESTIMATES                                               62

NEW ACCOUNTING PRONOUNCEMENTS                                               65


                                      29
<PAGE>

<TABLE>
<CAPTION>
EXECUTIVE SUMMARY
                                                                             2006           2005       2004
(Cdn$ millions)
-------------------------------------------------------------------------------------------------------------
<S>                                                                         <C>          <C>          <C>
Net Income                                                                    601          1,140        793
-------------------------------------------------------------------------------------------------------------
Earnings per Common Share, Basic ($/share)                                   2.29           4.38       3.08
-------------------------------------------------------------------------------------------------------------
Cash Flow from Operating Activities                                         2,374          2,143      1,606
-------------------------------------------------------------------------------------------------------------
Production before Royalties (mboe/d) (1)                                      212            242        250
-------------------------------------------------------------------------------------------------------------
Production after Royalties (mboe/d)                                           156            173        174
-------------------------------------------------------------------------------------------------------------
Capital Investment, including Acquisitions                                  3,408          2,638      4,264
-------------------------------------------------------------------------------------------------------------
Net Debt (2)                                                                4,730          3,639      4,285
-------------------------------------------------------------------------------------------------------------
Average Foreign Exchange Rate (Canadian to US dollar)                        0.88           0.83       0.77
-------------------------------------------------------------------------------------------------------------
Proved Oil and Gas Reserves before Royalties (mmboe) (3)                      725            468        542
-------------------------------------------------------------------------------------------------------------
Proved Oil and Gas Reserves after Royalties (mmboe) (3)                       637            393        451
-------------------------------------------------------------------------------------------------------------
Proved Syncrude Reserves before Royalties (mmboe) (3)                         324            318        301
-------------------------------------------------------------------------------------------------------------
Proved Syncrude Reserves after Royalties (mmboe) (3)                          274            264        255
=============================================================================================================
</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 AND SHORT-TERM BORROWINGS LESS CASH AND CASH EQUIVALENTS.
(3)  INCLUDES DEVELOPED AND UNDEVELOPED PROVED RESERVES AS AT DECEMBER 31.

     Strong commodity prices and record results from our energy marketing group
contributed to net income and cash flow from operating activities.  WTI reached
new  trading  highs  during  the year and our  realized  oil and gas  price was
$62.92/boe,  9% above 2005. The marketing  group  contributed  record  results,
generating value from the optimization of storage and transportation  capacity,
as well as financially  trading price differences  caused by location,  product
quality and time. At the beginning of the year, the UK government increased the
supplementary  tax on oil and gas activities in the North Sea. As a result,  we
recorded  $277  million of future  income tax  expense.  Our 2006  income  also
included $151 million of expense in connection  with our Block 51  arbitration.
Last  year,  our net income  included  gains of $225  million  from the sale of
Canadian  oil and gas  properties  and a gain of $193  million on the sale of a
portion of our interest in our chemicals business.

     Our combined oil & gas and Syncrude  production was lower than 2005 levels
as we continue to transition  from  maturing  production in Yemen and Canada to
new higher-return  production in 2007,  primarily in the North Sea and the Gulf
of Mexico.  The 2005 sale of Canadian  conventional  oil and gas assets reduced
our 2006 volumes by 10,700 boe/d before royalties (8,100 boe/d after royalties)
as compared to last year. As expected,  our Masila  assets  continued to mature
and production declined 16,800 boe/d (7,600 boe/d after royalties). Our ongoing
investment  in Masila is to maximize  the  recovery of the  remaining  reserves
before our licence  expires in 2011.  With  Buzzard on stream in early  January
2007,  our 2007 net  production  is  expected  to grow 50% to  average  between
230,000 boe/d and 260,000 boe/d, after royalties, and between 275,000 boe/d and
305,000 boe/d, before royalties.

     In 2006,  our  largest  annual  capital  program  was focused on our major
development projects at Buzzard and at Long Lake. Development of Buzzard in the
North Sea was  completed  during  the year and the  field  began  producing  on
January 7, 2007. Peak production rates of 85,000 boe/d, net to us, are expected
by mid 2007. At Long Lake, we invested over $1 billion on the SAGD component of
the project and on construction  of the upgrader.  We expect steam injection to
begin at the end of the first quarter of 2007, with upgrader start up scheduled
for late 2007.  At its peak,  we expect our share of  synthetic  crude oil from
phase 1 of Long Lake to be 30,000  bbls/d.  At Syncrude,  the Stage 3 expansion
was brought on stream in 2006, adding 8,000 bbls/d of production capacity. Late
in the year, we completed an additional  development  well at Aspen in the Gulf
of Mexico,  and we expect 2007 Aspen  production to average  between 15,000 and
20,000 boe/d.

                                      30
<PAGE>

     Our 2006 exploration  program was focused on drilling 20 wells,  primarily
in the Gulf of  Mexico  and the  North  Sea.  We had  successful  results  from
Alaminos  Canyon  Block 856 (Great White West) and Ringo in the Gulf of Mexico,
and Golden Eagle in the North Sea.

     Our net debt  increased from 2005 as a result of our investment in capital
projects,  primarily at Buzzard and Long Lake. We drew upon our committed  term
credit  facilities  during the year as our capital  spending  exceeded our cash
flow by approximately $1 billion.

     Throughout 2006, the Canadian dollar  continued to strengthen  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 and operating costs are lower when translated to
Canadian dollars. Overall, the weaker US dollar reduced our 2006 cash flow from
operating   activities  and  net  income  by  $223  million  and  $98  million,
respectively.

     During  2006,  our  proved  oil and gas and  Syncrude  reserves  additions
replaced more than 400% of our oil and gas and Syncrude  production (500% after
royalties) as shown in the following table:

                                                         BEFORE         AFTER
(mmboe)                                               ROYALTIES      ROYALTIES
-------------------------------------------------------------------------------
PRODUCTION
-------------------------------------------------------------------------------
  Oil and Gas                                                71            51
-------------------------------------------------------------------------------
  Syncrude                                                    7             6
-------------------------------------------------------------------------------
TOTAL                                                        78            57
-------------------------------------------------------------------------------

EXTENSIONS, DISCOVERIES AND REVISIONS
-------------------------------------------------------------------------------
  Oil and Gas                                               328           295
-------------------------------------------------------------------------------
  Syncrude                                                   13            16
-------------------------------------------------------------------------------
TOTAL                                                       341           311
===============================================================================

     The majority of our 2006 additions came from our  development  projects at
Long  Lake in the  Athabasca  oil  sands,  Ettrick  in the  North Sea and Usan,
offshore West Africa. We included 246 mmboe of bitumen (219 after royalties) at
Long Lake as a result of strong  year-end  bitumen prices and lower natural gas
costs. The Ettrick development was sanctioned during the year,  contributing 18
mmboe of proved reserves (18 after royalties).  At Usan,  offshore West Africa,
we added 30 mmboe of proved reserves (25 after  royalties).  Reserves were also
added from ongoing activities in Canada, the Gulf of Mexico and the North Sea.

CAPITAL INVESTMENT

(Cdn$ millions)                             ESTIMATED 2007      2006     2005
-------------------------------------------------------------------------------
  Major Development                                  1,000     1,849    1,550
-------------------------------------------------------------------------------
  Early Stage Development                              400       123       54
-------------------------------------------------------------------------------
  New Growth Exploration                               700       491      456
-------------------------------------------------------------------------------
  Core Asset Development                               700       748      524
-------------------------------------------------------------------------------
Total Oil & Gas and Syncrude                         2,800     3,211    2,584
-------------------------------------------------------------------------------
  Marketing, Corporate, Chemicals and Other            100       197       54
-------------------------------------------------------------------------------
TOTAL CAPITAL                                        2,900     3,408    2,638
===============================================================================

                                      31
<PAGE>

     Our strategy and capital  programs are focused on growing  long-term value
for our 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  coalbed
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 2006,  we  invested  more than $3.4  billion in  capital  expenditures,
mostly in multi-year development projects and long cycle-time  exploration.  In
2007,  we plan to invest $2.8 billion in our oil and gas and  Syncrude  assets.
About 34% of this is focused on multi-year  development  projects,  28% on core
assets to  sustain  production  and  provide  cash  flow,  and 24% on  drilling
high-impact  exploration wells and building our acreage position. The rest will
be spent on early stage development activities.

<TABLE>
<CAPTION>
2006 INVESTMENT PROGRAM

                                                MAJOR       EARLY STAGE        NEW GROWTH       CORE ASSET
(Cdn$ millions)                           DEVELOPMENT       DEVELOPMENT       EXPLORATION      DEVELOPMENT       TOTAL
------------------------------------------------------------------------------------------------------------------------
<S>                                       <C>               <C>               <C>              <C>               <C>
Oil and Gas
------------------------------------------------------------------------------------------------------------------------
  Synthetic (mainly Long Lake)                  1,050                74                45                -       1,169
------------------------------------------------------------------------------------------------------------------------
  United Kingdom                                  552                14                62               31         659
------------------------------------------------------------------------------------------------------------------------
  Yemen                                             -                 -                37              145         182
------------------------------------------------------------------------------------------------------------------------
  United States                                    31                 -               177              387         595
------------------------------------------------------------------------------------------------------------------------
  Canada                                          167                15               118              140         440
------------------------------------------------------------------------------------------------------------------------
  Other Countries                                   -                20                52                8          80
------------------------------------------------------------------------------------------------------------------------
Syncrude                                           49                 -                 -               37          86
------------------------------------------------------------------------------------------------------------------------
                                                1,849               123               491              748       3,211
------------------------------------------------------------------------------------------------------------------------
Marketing, Corporate and Other                      -                 -                 -              197         197
------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITAL                                   1,849               123               491              945       3,408
------------------------------------------------------------------------------------------------------------------------
As a % of Total Capital                           54%                4%               14%              28%        100%
========================================================================================================================

<CAPTION>
2007 ESTIMATED CAPITAL

                                                MAJOR      EARLY STAGE        NEW GROWTH       CORE ASSET
(Cdn$ millions)                           DEVELOPMENT      DEVELOPMENT       EXPLORATION      DEVELOPMENT      TOTAL
------------------------------------------------------------------------------------------------------------------------
<S>                                       <C>              <C>               <C>              <C>              <C>
Oil and Gas
------------------------------------------------------------------------------------------------------------------------
  Synthetic (mainly Long Lake)                    500              170                 -                -        670
------------------------------------------------------------------------------------------------------------------------
  United Kingdom                                  300                -               125              200        625
------------------------------------------------------------------------------------------------------------------------
  Yemen                                             -                -                50              100        150
------------------------------------------------------------------------------------------------------------------------
  United States                                     -               60               325              200        585
------------------------------------------------------------------------------------------------------------------------
  Canada                                          200                -                50              150        400
------------------------------------------------------------------------------------------------------------------------
  Other Countries                                   -              170               150                -        320
------------------------------------------------------------------------------------------------------------------------
Syncrude                                            -                -                 -               50         50
------------------------------------------------------------------------------------------------------------------------
                                                1,000              400               700              700      2,800
------------------------------------------------------------------------------------------------------------------------
Marketing, Corporate and Other                      -                -                 -              100        100
------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITAL                                   1,000              400               700              800      2,900
------------------------------------------------------------------------------------------------------------------------
As a % of Total Capital                           34%              14%               24%              28%       100%
========================================================================================================================
</TABLE>

                                      32
<PAGE>

MAJOR AND EARLY STAGE DEVELOPMENT PROJECTS

     Approximately 58% of our 2006 capital was directed towards early stage and
major development  projects including Buzzard,  Long Lake, Syncrude Stage 3 and
CBM.

SYNTHETIC

     In 2006, we invested  approximately $1.2 billion to develop our insitu oil
sands resource.  This included approximately $1.1 billion invested at our first
phase  of  Long  Lake.  The  SAGD   facilities  are  in  the  final  stages  of
commissioning and start up and we expect steam injection to commence at the end
of the first quarter of 2007, with bitumen  production rates ramping up to peak
rates over a 12 to 24 month  period.  Upgrader  module  fabrication  is largely
complete and over 95% of the modules are on site.  Construction of the upgrader
is  approximately  80%  complete  and  start up is  scheduled  for  late  2007.
Production  capacity for the first phase of Long Lake is  approximately  60,000
bbls/d (30,000 bbls/d net to us) of premium  synthetic crude which we expect to
reach by late 2008 or early 2009.

                     WE HAVE A NUMBER OF MAJOR DEVELOPMENT
                   PROJECTS AT VARIOUS STAGES OF COMPLETION.

     We are  planning to increase  synthetic  crude oil  production  to 240,000
bbls/d (120,000 bbl/s net to us) over the next decade.  We plan to sequentially
develop our oil sands leases with  additional  60,000 bbls/d (30,000 bbls/d net
to us) phases using the same technology and design as Long Lake phase 1. We are
currently  progressing phase 2 development.  We have completed seismic and core
hole drilling programs and we have ordered several major vessels.

UNITED KINGDOM

     At Buzzard,  we installed the utilities and production  topsides,  drilled
the initial development wells and completed hook-ups and project commissioning.
Buzzard came on stream in early January 2007 and  production is ramping up. The
facilities  have the  capacity  to process  up to 200,000  bbls/d of oil and 60
mmcf/d of gas,  including the removal of hydrogen  sulphide.  Based upon recent
drilling  results,  we have  experienced more  well-to-well  variability in the
concentration  of hydrogen  sulphide than  previously  seen. We expect existing
equipment and processes will allow us to manage this  variability  for at least
the first two or three  years of  production.  As we  continue  to produce  and
acquire reservoir  information,  we will determine whether additional equipment
will  ultimately be required.  We have a 43.2%  interest in Buzzard and operate
the project.

     Elsewhere  in the North Sea, we are  progressing  the  development  of the
Ettrick field.  Production at Ettrick is expected to commence in the first half
of 2008,  with our share reaching  approximately  16,000 boe/d.  Development is
approximately  30% complete and includes  drilling three  production wells tied
back to a floating  production,  storage and off-loading vessel. We have an 80%
interest in Ettrick.

CANADA

     In  Canada,  we are  developing  the first  commercial  CBM  project  from
Mannville coals in the Fort Assiniboine  area of Alberta.  In 2006, we invested
$237 million in exploration  and  development  activities on our CBM lands,  of
which $181 million was associated with development. We plan to increase our CBM
production to at least 150 mmcf/d by 2011.

     During the year,  we  acquired  over 100  sections  of land in an emerging
shale gas play in western Canada. We plan to initiate a drilling and evaluation
program in 2007 to demonstrate the feasibility of this opportunity.

                                      33
<PAGE>

OTHER COUNTRIES

     On  Block  OPL-222,   offshore  West  Africa,  Nigerian  authorities  have
provisionally  approved the Usan Field  Development  Plan. Basic engineering of
the facilities is complete and tendering of contracts for all major  components
is proceeding. The development plan includes a floating production, storage and
off-loading  vessel with storage  capacity of two million  barrels,  capable of
handling  peak  production  rates of 160,000  bbls/d of oil. We expect the Usan
development to be formally  sanctioned in 2007, with first  production as early
as 2010.  We have a 20% interest in the  exploration  and  development  of this
block.

SYNCRUDE

     At Syncrude,  we completed the Stage 3 expansion during the year. Start up
was initially delayed by the emission of odours from the flue gas desulphurizer
plant  but  modifications  to  eliminate  the  odours  were  completed  and the
expansion  started  up in late  August.  The Stage 3  expansion  increases  our
production capacity by 8,000 bbls/d.

NEW GROWTH EXPLORATION

     We  invested   approximately  14%  of  our  2006  capital  in  new  growth
exploration,  including seismic data acquisition. We had exploration success in
the Gulf of Mexico at Alaminos  Canyon  Block 856 (Great White West) and Ringo,
and at Golden Eagle in the UK North Sea.

     At Alaminos Canyon 856, we are evaluating  development options following a
two-well  exploration  drilling  program  earlier  in the year.  This  block is
located approximately 240 miles south of Houston and is immediately west of the
Great White discovery. We have a 30% interest in this discovery.

     At Ringo, we are evaluating a sub-sea tie-back to nearby facilities, which
could be on stream in late 2008. We have a 50% interest in this discovery.

     We recently completed drilling  operations at our Golden Eagle prospect in
the UK North Sea. The  discovery  well was drilled to a depth of  approximately
7,500  feet and  encountered  hydrocarbons.  A  successful  sidetrack  well was
drilled  to  appraise  the  accumulation   and  we  are  currently   evaluating
development options. We have a 34% operated interest in Golden Eagle.

                       OUR EXPLORATION PROGRAM CONTINUES
                      TO DELIVER RESULTS WITH NEW FINDS IN
                       THE GULF OF MEXICO AND NORTH SEA.

     In 2006, we participated  in the Norwegian  exploration bid round and were
recently awarded four licenses.  The licenses are in water depths from 1,000 to
1,300 feet and are located between 30 and 100 miles offshore  Norway,  situated
close to  existing  infrastructure.  In 2007,  we plan to invest in  additional
seismic and geological studies in this region.

CORE ASSET DEVELOPMENT

     We direct our capital investment in our maturing assets to extract maximum
value over the remaining  life of the assets.  In the Gulf of Mexico,  we began
producing from an additional development well at Aspen in late December.  Based
on results from this well, we see further  opportunities in the Aspen field and
are currently  sidetracking  one of our existing  Aspen wells to exploit deeper
sands. We have a 100% interest in Aspen.

     During the year,  we  commenced  power  production  from our  Soderglen 70
megawatt wind farm in southern Alberta. The wind farm comprises 47 wind towers,
each with a 1.5 megawatt turbine. We have a 50% interest in this project.

                                      34
<PAGE>

FINANCIAL RESULTS
YEAR-TO-YEAR CHANGE IN NET INCOME

<TABLE>
<CAPTION>
(Cdn$ millions)                                                        2006 VS 2005      2005 VS 2004
-------------------------------------------------------------------------------------------------------
<S>                                                                    <C>               <C>
NET INCOME FOR 2005 AND 2004 (1)                                              1,140               793
-------------------------------------------------------------------------------------------------------
Favourable (unfavourable) variances: (2)
-------------------------------------------------------------------------------------------------------
  Production Volumes, After Royalties
-------------------------------------------------------------------------------------------------------
      Crude Oil                                                                (245)               39
-------------------------------------------------------------------------------------------------------
      Natural Gas                                                               (55)              (55)
-------------------------------------------------------------------------------------------------------
      Change in Crude Oil Inventory                                             (74)                4
-------------------------------------------------------------------------------------------------------
       Total Volume Variance                                                   (374)              (12)
-------------------------------------------------------------------------------------------------------
  Realized Commodity Prices
-------------------------------------------------------------------------------------------------------
      Crude Oil                                                                 325               648
-------------------------------------------------------------------------------------------------------
      Natural Gas                                                              (133)              165
-------------------------------------------------------------------------------------------------------
       Total Price Variance                                                     192               813
-------------------------------------------------------------------------------------------------------
  Oil and Gas Operating Expense
-------------------------------------------------------------------------------------------------------
      Conventional                                                               13               (64)
-------------------------------------------------------------------------------------------------------
      Syncrude                                                                  (35)              (27)
-------------------------------------------------------------------------------------------------------
       Total Operating Expense Variance                                         (22)              (91)
-------------------------------------------------------------------------------------------------------
  Depreciation, Depletion, Amortization and Impairment
-------------------------------------------------------------------------------------------------------
      Oil & Gas and Syncrude                                                    (48)             (308)
-------------------------------------------------------------------------------------------------------
      Other                                                                       4               (19)
-------------------------------------------------------------------------------------------------------
       Total Depreciation, Depletion, Amortization and Impairment
        Impairment Variance                                                     (44)             (327)
-------------------------------------------------------------------------------------------------------
  Exploration Expense                                                          (111)               (5)
-------------------------------------------------------------------------------------------------------
  Energy Marketing Contribution                                                 336                49
-------------------------------------------------------------------------------------------------------
  Chemicals Contribution                                                        (12)               31
-------------------------------------------------------------------------------------------------------
  General and Administrative Expense                                            254              (510)
-------------------------------------------------------------------------------------------------------
  Interest Expense                                                               44                46
-------------------------------------------------------------------------------------------------------
  Current Income Taxes                                                          (29)              (91)
-------------------------------------------------------------------------------------------------------
  Future Income Taxes                                                          (549)              353
-------------------------------------------------------------------------------------------------------
  Other
-------------------------------------------------------------------------------------------------------
      Block 51 Arbitration                                                     (151)                -
-------------------------------------------------------------------------------------------------------
      Business Interruption Insurance Proceeds                                  152                (8)
-------------------------------------------------------------------------------------------------------
      Gains from Divestiture Programs                                          (418)              418
-------------------------------------------------------------------------------------------------------
      Increase (Decrease) in Fair Value of Crude Oil Put Options                185              (252)
-------------------------------------------------------------------------------------------------------
      Other                                                                       8               (67)
-------------------------------------------------------------------------------------------------------
NET INCOME FOR 2006 AND 2005 (1)                                                601             1,140
=======================================================================================================
</TABLE>
NOTES:
(1)  2005 AND 2004 INCLUDES RESULTS OF DISCONTINUED  OPERATIONS (SEE NOTE 14 TO
     OUR CONSOLIDATED FINANCIAL STATEMENTS).
(2)  ALL AMOUNTS ARE PRESENTED BEFORE PROVISION FOR INCOME TAXES.

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

                                      35
<PAGE>

<TABLE>
<CAPTION>
OIL & GAS AND SYNCRUDE
PRODUCTION
                                                     2006                          2005                           2004
                                             BEFORE       AFTER            BEFORE        AFTER            BEFORE          AFTER
                                       ROYALTIES (1)  ROYALTIES     ROAYLTIES (1)    ROYALTIES      ROYALTIES (1)     ROYALTIES
-------------------------------------------------------------------------------------------------------------------------------
<S>                                    <C>            <C>           <C>              <C>            <C>               <C>
OIL AND LIQUIDS (mbbls/d)
-------------------------------------------------------------------------------------------------------------------------------
  Yemen                                        92.9        51.8             112.7         60.6             107.3         53.5
-------------------------------------------------------------------------------------------------------------------------------
  Canada (2)                                   20.0        15.8              29.2         22.6              36.2         28.2
-------------------------------------------------------------------------------------------------------------------------------
  United States                                17.0        15.0              22.2         19.6              30.0         26.5
-------------------------------------------------------------------------------------------------------------------------------
  United Kingdom                               16.9        16.9              12.6         12.6               1.5          1.5
-------------------------------------------------------------------------------------------------------------------------------
  Australia (3)                                   -           -                 -            -               2.7          2.5
-------------------------------------------------------------------------------------------------------------------------------
  Other Countries                               6.3         5.7               5.6          5.1               5.3          4.7
-------------------------------------------------------------------------------------------------------------------------------
Syncrude (mbbls/d) (4)                         18.7        16.9              15.5         15.3              17.2         16.6
-------------------------------------------------------------------------------------------------------------------------------
                                              171.8       122.1             197.8        135.8             200.2        133.5

NATURAL GAS (mmcf/d)
-------------------------------------------------------------------------------------------------------------------------------
  Canada (2)                                    108          91               124          101               146          115
-------------------------------------------------------------------------------------------------------------------------------
  United States                                 111          94               116           99               148          126
-------------------------------------------------------------------------------------------------------------------------------
  United Kingdom                                 20          20                23           23                 3            3
-------------------------------------------------------------------------------------------------------------------------------
                                                239         205               263          223               297          244
-------------------------------------------------------------------------------------------------------------------------------

TOTAL (mboe/d)                                  212         156               242          173               250          174
===============================================================================================================================
</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.

                                                 2006    2005    2004
               -------------------------------------------------------
               Before Royalties
               -------------------------------------------------------
                 Oil and Liquids (mbbls/d)          -     6.7    11.7
               -------------------------------------------------------
                 Natural Gas (mmcf/d)               -      24      47
               -------------------------------------------------------
               After Royalties                      -
               -------------------------------------------------------
                 Oil and Liquids (mbbls/d)          -     5.3     9.0
               -------------------------------------------------------
                Natural Gas (mmcf/d)                -      17      33
               ========================================================

(3)  COMPRISES  PRODUCTION  FROM  DISCONTINUED  OPERATIONS.  SEE NOTE 14 TO OUR
     CONSOLIDATED FINANCIAL STATEMENTS.
(4)  CONSIDERED A MINING OPERATION FOR US REPORTING PURPOSES.


2006 VS 2005--LOWER PRODUCTION DECREASED NET INCOME BY $374 MILLION

     Production  before  royalties  decreased 12% from 2005,  while  production
after royalties  decreased 10%. Our 2006 production  excludes  volumes from our
Canadian oil and gas  properties  that were sold in the third  quarter of 2005.
Removing the impact of these property dispositions, production before and after
royalties declined 8% and 5%, respectively.

     The following table summarizes our production changes year over year:

                                                       BEFORE         AFTER
(mboe/d)                                            ROYALTIES     ROYALTIES
-----------------------------------------------------------------------------
2005 Production                                           242           173
-----------------------------------------------------------------------------
Canada--Disposition of Properties                         (11)           (8)
-----------------------------------------------------------------------------
                                                          231           165
-----------------------------------------------------------------------------
Production changes
-----------------------------------------------------------------------------
  Yemen                                                   (20)           (9)
-----------------------------------------------------------------------------
  Canada                                                   (1)           (1)
-----------------------------------------------------------------------------
  United States                                            (6)           (5)
-----------------------------------------------------------------------------
  United Kingdom                                            4             4
-----------------------------------------------------------------------------
  Colombia                                                  1             1
-----------------------------------------------------------------------------
  Syncrude                                                  3             1
-----------------------------------------------------------------------------
2006 PRODUCTION                                           212           156
=============================================================================

                                      36
<PAGE>

     In 2007,  we expect to grow our annual  production  rate  after  royalties
approximately  50% compared to 2006 to between  230,000 and 260,000 boe/d after
royalties (275,000 and 305,000 boe/d before royalties).  Increases are expected
to come from Buzzard in the North Sea (which  commenced  production  January 7,
2007),  from the Gulf of Mexico and a full year of production  from the Stage 3
expansion at Syncrude.  Also, steam injection at Long Lake is expected to begin
at the end of the first  quarter in 2007,  with bitumen  production  ramping up
until the upgrader is scheduled to commence synthetic crude oil production late
in 2007.  Anticipated  field  declines  in Yemen will  partially  offset  these
expected increases.

               OUR PRODUCTION AFTER ROYALTIES IS EXPECTED TO GROW
           APPROXIMATELY 50% IN 2007, WITH INCREMENTAL VOLUMES FROM
         BUZZARD, THE GULF OF MEXICO, SYNCRUDE STAGE 3 AND LONG LAKE.

     Production  volumes  discussed  in  this  section  represent  our  working
interest before royalties.

YEMEN

     Yemen production decreased 18% from 2005. Production from Masila decreased
19%  reflecting  the  maturity  of  the  field  and  the  impact  of a  reduced
development  drilling program.  In 2006, we drilled 28 development wells, eight
fewer than in 2005.  Strong  initial  rates from new wells,  combined with well
optimizations,  helped to minimize expected production declines.  Base declines
at Masila are  expected to continue  as we maximize  recovery of the  remaining
reserves on the block prior to expiry of our license in 2011.  We plan to drill
14 development wells and continue our well optimization program in 2007.

     On Block 51,  production  from the East Al Hajr field declined 12%. In the
first  quarter  of 2006,  we  commissioned  the  permanent  central  processing
facilities  on the block.  Lower than  expected  initial rates on new wells and
higher than  anticipated  decline rates  contributed to the decrease from 2005.
During the year, we drilled 24 development wells and nine development wells are
planned for 2007.

     We expect our share of total  production  from  Yemen to  average  between
60,000 and 75,000 bbls/d in 2007.

CANADA

     Production in Canada decreased 24% from the previous year,  primarily as a
result of the sale of conventional  oil and gas properties in Alberta,  British
Columbia and Saskatchewan. Removing the effect of the dispositions,  production
decreased 3% from 2005.  Natural  field  declines of 7,600 boe/d were offset by
capital investment in our heavy oil and natural gas assets,  contributing 5,500
boe/d in new  production.  Gas production is increasing at our coalbed  methane
projects in Alberta as existing  wells  continue to de-water  and we bring more
wells on  stream.  In 2007,  we  expect  to drill 165  infill  wells,  continue
optimization  activities on our conventional  assets and work on developing new
technologies to increase recoveries on our heavy oil properties.

     We expect 2007  production to average  between  45,000 and 50,000 boe/d in
Canada with the  commencement  of production of premium  synthetic crude oil at
Long Lake and additional coalbed methane volumes.

UNITED STATES

     Gulf of Mexico  production  declined  14%, or about 6,000 boe/d from 2005.
Lower production from Aspen due to natural declines  contributed  approximately
5,400 boe/d of the decrease.  An additional Aspen  development well was brought
on stream in December 2006. This well was expected to come on stream earlier in
the year but  damage to the  drilling  rig from a  work-boat  accident  delayed
completion  of the well. We are  currently  side-tracking  one of the wells and
expect it to be on stream by mid 2007. In 2007, we expect  production  from the
Aspen field to average  between  15,000 and 20,000 boe/d.  Gunnison  production
remained strong,  accounting for 30% of our production from the Gulf of Mexico.
Development  of the Dawson Deep  discovery  was  completed and tied-back to our
Gunnison  SPAR in July.  The Wrigley  development  was delayed by the tight rig
market in the Gulf,  but  completion  is  progressing  and the  development  is
expected  to come on stream in the first half of 2007,  with  production  rates
anticipated of 3,200 boe/d.

                                      37
<PAGE>

     The effects of Hurricanes Katrina and Rita continued to be felt in 2006 as
we slowly  restored  production  from fields shut-in due to damage  received in
2005.  Production  from  Vermilion 321 was restored in September  2006. At year
end,  Vermilion  340 remains  shut-in from damage to the  sub-surface  pipeline
system. This production was restored in early 2007 (400 boe/d).

     During  the  year,  we  received  $80  million  of  business  interruption
insurance proceeds related to the 2005 hurricanes.

     In 2007, we expect  production to average  between 45,000 and 55,000 boe/d
in the Gulf of Mexico.

UNITED KINGDOM

     Production in the UK increased 23%, or 3,800 boe/d from 2005, primarily as
a result of less  downtime on the Scott  platform and new  production  from our
non-operated  Farragon  field.  In 2005,  our  production  was  reduced  by two
generator failures on the Scott platform.  During 2006, we received $74 million
in  business  interruption  proceeds  related  to  these  failures.   Our  2006
production was lower than we expected as planned  maintenance work on the Scott
platform  flare tip took longer than  anticipated  and  operating  capacity was
reduced by maintenance activities on the SAGE export pipeline.

                WITH BUZZARD ON STREAM, WE EXPECT UK PRODUCTION
             TO AVERAGE BETWEEN 90,000 AND 100,000 BOE/D IN 2007.

     Final  commissioning of the facilities at Buzzard was delayed by inclement
weather in the North Sea late in the year.  Buzzard began production on January
7, 2007.  The delay has no impact on our ramp-up  plans and peak  production of
85,000 boe/d is expected to be achieved in the second quarter of 2007.

     In  2007,  we plan to  drill  and  complete  eight  production  and  three
injection  wells at Buzzard and three  development  wells in the  Scott/Telford
area. We expect our total year  production from our North Sea assets to average
between  90,000 and 100,000  boe/d in 2007.  This  compares to the 19,000 boe/d
these assets produced when we purchased them in late 2004.

OTHER COUNTRIES

     Production  from the Guando field in Colombia was consistent with 2005. We
maintained  production  rates from two infill  drilling  programs,  bringing 15
additional  wells on stream during the year.  We expect to maintain  production
rates in Colombia in 2007.

SYNCRUDE

     At  Syncrude,  production  increased  21% from  2005,  but was lower  than
expected.  The  start-up  of the Stage 3  expansion  was delayed by emission of
odours  from the flue gas  desulphurizer  plant.  Production  from the  Stage 3
expansion began in early May and was approaching design capacity rates prior to
shutting in as a result of the odours.  Modifications  to eliminate the problem
were  completed  during the summer and the  facilities  were  restarted in late
August.  Late in the year,  a  turnaround  on coker 8-2 reduced  production  by
approximately 6,000 bbls/d. The turnaround was completed early in 2007.

     Strong  realized  prices on  production  have enabled us to fully  recover
capital  costs  at  Syncrude  including  costs  associated  with  the  Stage  3
expansion. Consequently, our Syncrude royalty in 2006 increased from a 1% gross
revenue  royalty to a 25% net  revenue  royalty.  As a result of the  increased
royalty rate, we receive lower net production  relative to our working interest
production volumes.

     In 2007,  we expect our  total-year  production  from  Syncrude to average
between 20,000 and 25,000 bbls/d.

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

     Production  before  royalties  declined 3% during 2005,  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 2005 to reduce debt
that financed 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 2005.  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.

                                      38
<PAGE>

COMMODITY PRICES
                                                     2006      2005      2004
-------------------------------------------------------------------------------
CRUDE OIL
-------------------------------------------------------------------------------
  West Texas Intermediate (WTI) (US$/bbl)           66.22     56.58     41.40
-------------------------------------------------------------------------------
  Differentials (1) (US$/bbl)
-------------------------------------------------------------------------------
      Heavy Oil - LLK                               21.79     20.82     13.53
-------------------------------------------------------------------------------
      MARS                                           7.34      6.59      6.15
-------------------------------------------------------------------------------
      Masila                                         3.00      5.71      4.84
-------------------------------------------------------------------------------
      Dated Brent                                    1.08      2.20         -
-------------------------------------------------------------------------------

  Producing Assets (Cdn$/bbl)
-------------------------------------------------------------------------------
      Yemen                                         71.57     62.07     47.59
-------------------------------------------------------------------------------
      Canada                                        42.79     40.51     36.60
-------------------------------------------------------------------------------
      United States                                 65.80     57.63     46.60
-------------------------------------------------------------------------------
      United Kingdom                                71.19     60.55     46.81
-------------------------------------------------------------------------------
      Australia                                         -         -     51.22
-------------------------------------------------------------------------------
      Other Countries                               66.09     59.96     43.07
-------------------------------------------------------------------------------
      Syncrude                                      72.32     71.00     52.80
-------------------------------------------------------------------------------

  Corporate Average (Cdn$/bbl)                      67.50     58.98     45.90
-------------------------------------------------------------------------------

NATURAL GAS
-------------------------------------------------------------------------------
  New York Mercantile Exchange (US$/mmbtu)           6.99      8.99      6.19
-------------------------------------------------------------------------------
  AECO (Cdn$/mcf)                                    6.62      8.04      6.44
-------------------------------------------------------------------------------

   Producing Assets (Cdn$/mcf)
-------------------------------------------------------------------------------
      Canada                                         6.49      7.51      5.76
-------------------------------------------------------------------------------
      United States                                  7.86     10.56      7.89
-------------------------------------------------------------------------------
      United Kingdom                                 7.43      7.86      8.28
-------------------------------------------------------------------------------

  Corporate Average (Cdn$/mcf)                       7.18      8.89      6.85
-------------------------------------------------------------------------------
NEXEN'S AVERAGE REALIZED OIL AND GAS
PRICE (Cdn$/boe)                                    62.92     57.97     44.94
-------------------------------------------------------------------------------

Average Foreign Exchange Rate-Canadian to
US Dollar                                          0.8818    0.8253    0.7683
===============================================================================
NOTE:
(1)  THESE DIFFERENTIALS ARE A DISCOUNT TO WTI.

2006 VS 2005--HIGHER REALIZED PRICES INCREASED NET INCOME $192 MILLION

     Average  WTI was 17% higher from the prior  year,  increasing  our average
realized crude oil price 14% to $67.50/bbl. Our realized natural gas price fell
19% from 2005, while NYMEX decreased 22% in the same period. The full impact of
the increase in WTI was not reflected in our higher realized crude oil price as
the Canadian dollar  strengthened  relative to the US dollar. The impact of the
weaker US dollar was offset by narrower crude oil differentials.  The weaker US
dollar  reduced  net sales by  approximately  $250  million,  and  reduced  our
realized  crude oil and  natural  gas  prices by  approximately  $4.85/bbl  and
$0.50/mcf, respectively as compared to 2005.

                                      39
<PAGE>

CRUDE OIL REFERENCE PRICES

     Crude oil prices  remained  strong for most of 2006, with WTI reaching new
highs in July  before  finishing  the year at  US$61.05/bbl,  roughly  where it
began.  WTI traded at an average of  US$66.22/bbl  for the year, with a trading
range of between US$54.86/bbl and US$78.40/bbl, where it peaked on July 14. The
steady  decline in crude  prices from August to the end of the year was largely
driven by warm weather, above average crude oil inventories,  concerns over the
US economy, the perceived reduction of geopolitical tensions in the Middle East
and institution-led sell offs in the crude oil markets.

     Weather has become an  increasingly  significant  factor in the pricing of
crude oil. In North America,  a mild 2005/2006 winter followed by an uneventful
hurricane  season in the Gulf of Mexico and a forecast for a warmer than normal
2006/2007  winter season due to the warming effect of El Nino have put downward
pressure  on prices.  The  resulting  reduced  demand has helped push crude oil
inventories to levels higher than the five-year average. In addition,  concerns
over a slowdown in the US economy due to the weakening of the US housing market
have depressed crude oil prices further.

                     WTI REACHED RECORD HIGHS DURING 2006,
                   INCREASING OUR REALIZED CRUDE OIL PRICES.

     Geopolitical  events were a dominant  theme through the first eight months
of the  year.  Tensions  in the  Middle  East as a  result  of  Iran's  uranium
enrichment  program,  on-going  violence in Iraq,  fighting  between Israel and
Hezbollah  militants in Lebanon,  supply outages in Nigeria caused by continued
violence and the nationalization of Venezuela's energy industry  contributed to
increased  prices and greater market  volatility.  Towards the end of the year,
however,  geopolitical tensions have been discounted by the market following an
end to the conflict in Lebanon and doubts the US will move against Iran.

     A  number  of oil and gas  producers  have  put  option  price  protection
programs in place at WTI strike prices  ranging from US$45 to  US$60/bbl.  With
falling  crude oil prices,  these  programs get closer to being "in the money".
This caused a sell-off in the crude oil  markets by various  institutions  that
wrote these options as they  attempted to manage their option  exposures.  This
sell-off contributed to the downward pressure on crude prices.

     To  mitigate  the  bearish  sentiments  for  crude  oil,  OPEC has shown a
commitment to its US$50 - $55/bbl basket price by agreeing to reduce production
by 1.2 million barrels a day from November 1 and by a further 500,000 barrels a
day from February 1, 2007. On the demand side, global oil demand growth remains
moderate  and is expected to rise by 1.5 million  barrels per day in 2007 to 86
million barrels a day. This growth comes mainly from China and India. We expect
this  demand  increase  and the  commitment  from OPEC to lower  production  to
stabilize crude oil prices in the near term.

     Since the beginning of 2007, WTI has dropped to a low of US$49.90/bbl, but
has since rebounded to approximately US$59/bbl in early February.

CRUDE OIL DIFFERENTIALS

     In Canada,  heavy crude oil  differentials  averaged  US$21.79/bbl (33% of
WTI) for the year,  compared to $20.82/bbl (37% of WTI) in 2005.  Differentials
narrowed in the summer,  as demand increased for heavy blends relative to light
blends.  This reflected normal seasonal  narrowing as we headed into the summer
asphalt season.  Typically,  heavy crude oil differentials widen going into the
fourth quarter but this year, they maintained their summer levels following the
late-year  falloff in WTI.  In  addition,  heavy  crude oil  differentials  are
tighter than usual this winter since OPEC cuts tend to be heavy  barrels.  This
increases the value of heavy barrels relative to lighter barrels.

                                      40
<PAGE>

     The US Gulf Coast Mars differential widened, averaging US$7.34/bbl in 2006
as  compared  to  US$6.59/bbl  in 2005.  This was  primarily  due to higher WTI
prices,  temporary declines in demand due to refinery maintenance schedules and
increased  competition  from Canadian  heavy crude down the Spearhead  pipeline
into Cushing, Oklahoma and the Pegasus pipeline into Nederland,  Texas. Late in
the year,  Mars  differentials  narrowed  in response to falling WTI prices and
OPEC production quota cuts.

     The Yemen  Masila  differential  narrowed  substantially  relative  to WTI
during 2006,  averaging  US$3.00/bbl  compared to US$5.71/bbl  last year.  This
largely  reflects the impact of stronger  Brent  pricing  since Masila crude is
priced off Brent, coupled with continued strong Asian demand.

              THE BRENT/WTI DIFFERENTIAL STRENGTHENED DURING 2006,
         CREATING STRONG CRUDE OIL PRICING FOR OUR NORTH SEA BARRELS.

     The Brent/WTI differential  strengthened during 2006 averaging US$1.08/bbl
as compared to  US$2.20/bbl  in 2005,  resulting in a solid crude oil price for
our North Sea  barrels.  The  spread  between  WTI and  Brent  broke  away from
historical  norms  where WTI  usually  trades at a premium  of  US$1.50/bbl  to
US$2.00/bbl.  Several times during the year, WTI traded at a discount to Brent.
This was  caused by weak US  demand  during a heavier  than  usual  maintenance
season,  coupled with high US crude inventory  levels as production from the US
Gulf Coast came back on stream  following  damage caused by Hurricanes  Katrina
and Rita in 2005.  On-going  production  outages in Nigeria also helped to push
Brent up  relative to the North  American  WTI  benchmark.  Near the end of the
year,  Brent gained more upside  support due to the  production  quota cut from
OPEC. OPEC cuts have a more immediate impact on Brent relative to WTI given the
shorter transit time of Brent to world markets.

NATURAL GAS REFERENCE PRICES

     Natural gas prices averaged  US$6.99/mmbtu,  22% below 2005 levels.  NYMEX
reached record price and volatility  levels in late 2005,  driven mainly by the
impact of  hurricanes  Katrina and Rita and  speculation  around the  2005/2006
North American  winter season.  In 2006, the mildest  January  temperatures  on
record were  experienced  in several key North  American  natural gas consuming
regions which resulted in a weakening of NYMEX.  This created a significant gas
storage  overhang.  Prices  remained soft  throughout the year  reflecting high
storage  levels,  an uneventful  hurricane  season and a mild 2006/2007  winter
prediction  due to the  warming  effect  of El  Nino.  Lack of  sustained  cold
temperatures heading into 2007 will discourage storage withdrawals,  which puts
further downward pressure on prices.

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

     Crude oil prices remained strong in 2005 reaching new highs and new levels
of volatility. 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.

     Natural  gas  prices  reached  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, 2005 with NYMEX gas settling at
US$15.38/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 to
2004.

                                      41
<PAGE>

<TABLE>
<CAPTION>
OPERATING EXPENSES
                                                   2006                            2005                            2004
(Cdn$/boe)                                  BEFORE       AFTER            BEFORE           AFTER           BEFORE       AFTER
                                      ROYALTIES (1)  ROYALTIES      ROYALTIES (1)      ROYALTIES     ROAYLTIES (1)  ROYALTIES
-------------------------------------------------------------------------------------------------------------------------------
<S>                                   <C>            <C>            <C>                 <C>          <C>            <C>
CONVENTIONAL OIL AND GAS
-------------------------------------------------------------------------------------------------------------------------------
  Yemen                                       4.45        8.11               3.63           6.75             2.80        5.64
-------------------------------------------------------------------------------------------------------------------------------
  Canada                                     10.31       12.73               8.21          10.34             7.12        8.98
-------------------------------------------------------------------------------------------------------------------------------
  United States                               8.17        9.45               6.35           7.33             5.30        6.12
-------------------------------------------------------------------------------------------------------------------------------
  United Kingdom                             11.28       11.28              14.90          14.90             8.26        8.26
-------------------------------------------------------------------------------------------------------------------------------
  Australia                                      -           -                  -              -            32.94       35.73
-------------------------------------------------------------------------------------------------------------------------------
  Other Countries                             2.87        3.13               5.55           6.08             3.76        4.09
-------------------------------------------------------------------------------------------------------------------------------
  Average Conventional                        6.95        9.69               6.03           8.70             5.13        7.59
-------------------------------------------------------------------------------------------------------------------------------

SYNTHETIC CRUDE OIL
  Syncrude                                   27.53       30.43              26.95          27.22            19.89       20.61
-------------------------------------------------------------------------------------------------------------------------------
AVERAGE OIL AND GAS                           8.77       11.96               7.36          10.34             6.15        8.83
===============================================================================================================================
</TABLE>
NOTE:
(1)  OPERATING  EXPENSES  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.

2006 VS 2005--HIGHER OPERATING EXPENSES DECREASED NET INCOME BY $22 MILLION

     In Yemen,  operating  costs on a per-unit  basis are  increasing  as fixed
costs from our central  processing  facilities,  combined with increased  water
handling costs,  are spread over lower  production  volumes.  At Masila,  lower
production and increased service rig activity  required to minimize  production
declines,  combined with the costs  associated with the replacement of a single
point  mooring  system used to load oil onto  tankers,  increased our corporate
average by $0.20/boe.  Block 51 operating costs increased our corporate average
by $0.22/boe,  reflecting higher manpower costs, increased water handling costs
at the new facilities,  maintenance costs associated with equipment repairs and
power outages,  and increased fuel consumption and fuel prices. We expect Yemen
operating costs per barrel to continue to increase as our production declines.

     Following  the sale of Canadian  conventional  oil and gas  properties  in
2005, we have proportionately  higher production from our heavy oil properties,
which have higher  operating  costs  compared to the lighter oil  production we
sold. Canadian operating costs increased our corporate average by $0.18/boe. We
are  focused on  increasing  recovery  rates from our heavy oil  properties  by
developing new technologies.

     Operating  costs in the Gulf of  Mexico  increased  from  last year due to
industry cost pressures  caused by the strong  commodity price  environment and
the 2005 hurricane season.  Lower production volumes and workovers on our shelf
properties  at the  start  of the  year  increased  our  corporate  average  by
$0.39/boe.

     With the sale of Canadian  production in 2005,  barrels from the North Sea
are contributing a higher percentage of our total production.  As the North Sea
has higher  operating  costs than our average  cost per  barrel,  the change in
production  mix has  increased our  corporate  average by  $0.32/boe.  This was
offset by lower  operating  costs relative to 2005, as operating  expenses last
year  included  repair  costs  related to turbine  failures.  This  reduced our
corporate  average by  $0.26/boe.  We expect our North Sea  operating  costs to
decrease  on a  per-unit  basis  in 2007,  with  increased  low-operating  cost
production expected from Buzzard.

                WE EXPECT 2007 OPERATING COSTS TO DECREASE ON A
   PER-UNIT BASIS WITH INCREASED LOW-OPERATING COST PRODUCTION FROM BUZZARD.

     Syncrude increased our corporate average operating costs by $0.72/boe as a
result of maintenance activities and the turnaround of a coker during the first
quarter  of 2006,  combined  with  costs  related  to  start-up  of the Stage 3
expansion.

     The stronger Canadian dollar decreased our US-dollar denominated operating
costs, reducing our corporate average by $0.38/boe, compared to 2005.

                                      42
<PAGE>

2005 VS 2004--HIGHER OPERATING EXPENSES DECREASED NET INCOME BY $91 MILLION

     In 2005,  higher operating costs reflect the change in our profile as more
of our production  came from  higher-cost  areas such as the North Sea and from
Canadian heavy oil following the Canadian  property sales  completed that 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, increased our operating costs.

     Our operations at Masila in Yemen reflect the maturing asset base and have
higher operating costs,  mainly from increased service rig activity to minimize
production  declines.  These  higher  costs added  $0.09/boe  to our  corporate
average.  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 $0.53/boe.

     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 have  proportionately  higher production from
our heavy oil properties. These properties have higher operating costs compared
to the lighter oil production that was sold.

     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  $0.10/boe.   Workovers  on  our  shelf
properties, coupled with lower production and property damage costs not covered
by insurance, increased our corporate average by $0.05/boe from 2004.

     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.

     Our Australian  operations  ceased in late 2004 and the exclusion of these
high-cost,  late-life  barrels  reduced  our  corporate  average by  $0.57/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
$0.30/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.  In  addition,  high
levels of industry activity in the oil sands have put upward pressure on costs.
When combined with higher energy costs required in the upgrading  process,  our
corporate average increased by $0.34/boe.

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

                                                     2006                              2005                          2004
                                         ROYALTIES        ROYALTIES       ROYALTIES        AFTER           BEFORE          AFTER
(Cdn$/boe)                            ROYALTIES (1)       ROYALTIES    ROYALTIES (1)    ROYALTIES    ROYALTIES (1)      ROYALTIES
----------------------------------------------------------------------------------------------------------------------------------
<S>                                   <C>                 <C>          <C>              <C>           <C>           <C>
CONVENTIONAL OIL AND GAS
----------------------------------------------------------------------------------------------------------------------------------
  Yemen                                       9.67            17.61            8.56        15.93             4.35           8.77
----------------------------------------------------------------------------------------------------------------------------------
  Canada                                     11.22            13.84            9.26        11.67             9.02          11.37
----------------------------------------------------------------------------------------------------------------------------------
  United States (2)                          16.28            18.84           15.39        17.77            12.93          14.93
----------------------------------------------------------------------------------------------------------------------------------
  United Kingdom                             30.22            30.22           33.25        33.25            22.44          22.44
----------------------------------------------------------------------------------------------------------------------------------
  Australia                                      -                -               -            -             5.82           6.31
----------------------------------------------------------------------------------------------------------------------------------
  Other Countries                             4.30             4.69            6.20         6.79             9.90          10.77
----------------------------------------------------------------------------------------------------------------------------------
  Average Conventional                       13.12            18.30           11.78        17.00             7.87          11.64
----------------------------------------------------------------------------------------------------------------------------------

SYNTHETIC CRUDE OIL
----------------------------------------------------------------------------------------------------------------------------------
  Syncrude                                    4.81             5.32            3.08         3.12             2.75           2.85
----------------------------------------------------------------------------------------------------------------------------------
AVERAGE OIL AND GAS                          12.38            16.88           11.23        15.77             7.52          10.80
==================================================================================================================================
</TABLE>
NOTES:
(1)  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.
(2)  DD&A PER BOE EXCLUDES  THE  IMPAIRMENT  CHARGE  DESCRIBED IN NOTE 6 OF OUR
     CONSOLIDATED FINANCIAL STATEMENTS.

                                      43
<PAGE>

2006 VS 2005--HIGHER OIL AND GAS DD&A DECREASED NET INCOME BY $48 MILLION

     Our 2006 DD&A  expense  includes  $93 million  ($1.21/boe)  of  impairment
expense primarily  related to two natural gas producing  properties in the Gulf
of Mexico. The impairment was caused by disappointing  development programs and
negative  year-end  reserve  revisions.  The  carrying  values of the  impaired
properties have been reduced to their  estimated fair value.  In addition,  our
2006 DD&A expense  includes $15 million  (2005 --$58  million)  relating to the
write down of a portion of our purchase price allocation to unproved properties
purchased in the North Sea as a result of unsuccessful  exploration activities.
Our 2006 average depletion rate excluding impairment charges is $12.38/boe, 10%
above our 2005 average.

     In Yemen, we began depleting the permanent production  facilities on Block
51 during the year.  Strong crude oil prices allowed us to continue to maximize
the recovery of the costs we paid on behalf of the  government.  This increased
our corporate average by $0.64/boe.

                     THE STRONG CANADIAN DOLLAR REDUCED OUR
                  CORPORATE DD&A RATE BY $0.72/BOE FROM 2005.

     The  increased  Canadian  depletion  rate  reflects the depletion of costs
associated with our coalbed methane projects in central Alberta.  Our corporate
average is higher by $0.35/boe as a result.  We expect our  depletion  rate for
our coalbed  methane  projects to decline as the wells de-water and we are able
to recognize additional reserves.  Depletion rates for our deep-water assets in
the Gulf of Mexico increased our average by $0.28/boe  primarily as a result of
reserve revisions late in 2005.

     Our  depletion  rate for our North Sea assets is higher than our  average,
primarily from the allocation of the purchase price we paid for these assets in
2004.  Our  corporate  average is  increasing as the North Sea becomes a larger
proportion  of our  total  production  and  from  lower  production  in  Canada
following  the sale of  conventional  oil and gas assets in 2005.  This  change
increased our corporate  average by $0.42/boe.  We expect our corporate average
will continue to increase in 2007 as we begin to deplete Buzzard.

     The Stage 3 expansion at Syncrude began  producing  during the year and we
started depleting these assets in 2006. This increased our corporate average by
$0.23/boe.

     The strong  Canadian  dollar reduced our DD&A expense  relative to 2005 as
the depletion of our  international and US assets is denominated in US dollars.
This lowered our corporate average by $0.72/boe from last year.

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 $0.23/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.


                                      44
<PAGE>

     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 $0.70/boe compared with 2004.

EXPLORATION EXPENSE (1)

(Cdn$ millions)                                         2006     2005   2004
------------------------------------------------------------------------------
Seismic                                                  128       53     73
------------------------------------------------------------------------------
Unsuccessful Drilling                                    169      143    125
------------------------------------------------------------------------------
Other                                                     65       55     48
------------------------------------------------------------------------------
TOTAL EXPLORATION EXPENSE                                362      251    246
------------------------------------------------------------------------------

New Growth Exploration                                   491      456    266
------------------------------------------------------------------------------
Geological and Geophysical Costs                         128       53     73
------------------------------------------------------------------------------
TOTAL EXPLORATION EXPENDITURES                           619      509    339
------------------------------------------------------------------------------

Exploration Expense as a % of Exploration Expenditures   58%      49%    73%
==============================================================================
NOTE:
(1)  2005 AND 2004 INCLUDES  EXPLORATION EXPENSE FROM DISCONTINUED  OPERATIONS.
     SEE NOTE 14 TO OUR CONSOLIDATED FINANCIAL STATEMENTS.


2006 VS 2005--HIGHER EXPLORATION EXPENSE REDUCED NET INCOME BY $111 MILLION

     Our 2006 exploration  activities were focused on drilling 20 wells, mostly
in the Gulf of Mexico and the North Sea, and  acquiring  seismic  data. We were
successful at Great White West and Ringo in the Gulf of Mexico.  In early 2007,
we completed  drilling  operations at our Golden Eagle prospect on License P928
in the UK North Sea. The discovery well was drilled to a depth of approximately
7,500  feel and  encountered  hydrocarbons.  A  successful  sidetrack  well was
drilled  to  appraise  the  accumulation   and  we  are  currently   evaluating
development options.

     Our  unsuccessful  drilling  results were primarily in the Gulf of Mexico,
where we  expensed  $135  million  in dry hole  costs.  Early in the  year,  we
expensed  $49  million for the  Pathfinder  well,  which  found  non-commercial
quantities  of  hydrocarbons,  after  reaching  a total  depth of 31,196  feet.
Unsuccessful  wells on the shelf in the Gulf of Mexico include West Cameron 135
and 109 ($23  million  and $14  million  respectively)  and  Vermilion  65 ($15
million).  During the year, we also expensed $29 million of  capitalized  costs
related to Big Bend as it was determined  that  development  was uneconomic and
the  block  was  relinquished.  In the  North  Sea,  dry  hole  costs  included
unsuccessful  exploratory  wells at Zanzibar  ($10  million)  and Black Cat ($7
million).  Exploration  expense  also  includes  costs  relating to Ukot South,
offshore  Nigeria,  which  encountered wet sands and was plugged and abandoned,
and costs relating to three unsuccessful wells on Block 51 in Yemen.


                                      45
<PAGE>

     Our geological and geophysical  costs include $128 million of seismic data
acquired  during  the year of which half  relates  to the Gulf of  Mexico.  The
balance was spent on data relating to Canada,  Norway,  the North Sea,  Nigeria
and other international targets.

     We continue to focus on large  unconventional  resource  opportunities  in
Canada.  In 2006, we acquired  approximately  100 sections of prospective shale
gas acreage in northeast  British Columbia for $50 million,  which we intend to
evaluate in 2007.

           WE CONTINUE TO GROW OUR UNCONVENTIONAL RESOURCE IN CANADA.
   IN 2006, WE ACQUIRED A SIZEABLE SHALE GAS LAND POSITION IN NORTHEAST BC.

     In 2007,  we plan to invest  approximately  $700 million to drill up to 19
exploration  wells and  acquire  seismic  data and  access  to new  exploratory
acreage.  In the Gulf of  Mexico  we have four  deep-water  and five  shelf-gas
prospects planned,  while we anticipate  drilling five exploration wells in the
North Sea. We expect to drill three exploration wells on Block 51 in Yemen, one
deep-water  exploration  well offshore West Africa and one exploration  well in
Colombia.


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

     Our 2005  exploration  program  was  active,  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.

     Our 2005 exploration  expense includes costs associated with  unsuccessful
wells in the Gulf of Mexico,  North Sea, offshore West Africa and Yemen. In the
Gulf of Mexico,  we expensed $44 million for the Vrede well.  Vrede, a sub-salt
prospect  drilled to a total depth of 32,600 feet,  encountered  non-commercial
quantities of  hydrocarbons  and was temporarily  abandoned.  We also wrote off
costs relating to our Castleton dry hole,  together with trailing costs related
to the 2004 Crested Butte,  Wind River and Fawkes wells.  These wells, with the
exception of Wind River, were located in the deep water.

     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 2005 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.


                                      46
<PAGE>

OIL & GAS AND SYNCRUDE NETBACKS

     Netbacks are the cash margins, before general and administrative expenses,
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
                                                                                    2006
($/boe)                                                 YEMEN    CANADA      US       UK   OTHER    SYNCRUDE    TOTAL
-----------------------------------------------------------------------------------------------------------------------
<S>                                                     <C>       <C>     <C>      <C>     <C>      <C>         <C>
Sales                                                   71.57     40.98   56.12    66.81   66.09       72.32    62.92
-----------------------------------------------------------------------------------------------------------------------
Royalties and Other                                    (32.32)    (7.80)  (7.53)       -   (5.51)      (6.93)  (17.68)
-----------------------------------------------------------------------------------------------------------------------
Operating Expenses                                      (4.45)   (10.31)  (8.17)  (11.28)  (2.87)     (27.53)   (8.77)
-----------------------------------------------------------------------------------------------------------------------
In-country Taxes (1)                                    (8.45)        -       -        -       -           -    (3.72)
-----------------------------------------------------------------------------------------------------------------------
CASH NETBACK                                            26.35     22.87   40.42    55.53   57.71       37.86    32.75
=======================================================================================================================

<CAPTION>
                                                                                    2005
($/boe)                                                 YEMEN    CANADA      US       UK   OTHER    SYNCRUDE    TOTAL
-----------------------------------------------------------------------------------------------------------------------
<S>                                                     <C>       <C>     <C>      <C>     <C>      <C>        <C>
Sales                                                   62.07     42.42   60.26    57.83   59.96       71.00    57.97
-----------------------------------------------------------------------------------------------------------------------
Royalties and Other                                    (28.71)    (8.75)  (8.06)       -   (5.23)      (0.71)  (16.70)
-----------------------------------------------------------------------------------------------------------------------
Operating Expenses                                      (3.63)    (8.21)  (6.35)  (14.90)  (5.55)     (26.95)   (7.36)
-----------------------------------------------------------------------------------------------------------------------
In-country Taxes (1)                                    (7.17)        -       -        -       -           -    (3.34)
-----------------------------------------------------------------------------------------------------------------------
CASH NETBACK                                            22.56     25.46   45.85    42.93   49.18       43.34    30.57
=======================================================================================================================

<CAPTION>
                                                                                    2004
($/boe)                                    AUSTRALIA    YEMEN    CANADA      US       UK   OTHER    SYNCRUDE    TOTAL
-----------------------------------------------------------------------------------------------------------------------
<S>                                        <C>          <C>      <C>      <C>      <C>     <C>      <C>      <C>
Sales                                          51.22    47.59     35.76   46.94    47.45   43.07       52.80    44.94
-----------------------------------------------------------------------------------------------------------------------
Royalties and Other                            (4.00)  (23.98)    (7.40)  (6.29)       -   (3.49)      (1.84)  (13.65)
-----------------------------------------------------------------------------------------------------------------------
Operating Expenses                            (32.94)   (2.80)    (7.12)  (5.30)   (8.26)  (3.76)     (19.89)   (6.15)
-----------------------------------------------------------------------------------------------------------------------
In-country Taxes (1)                               -    (5.82)        -       -        -       -           -    (2.48)
-----------------------------------------------------------------------------------------------------------------------
CASH NETBACK                                   14.28    14.99     21.24   35.35    39.19   35.82       31.07    22.66
=======================================================================================================================

<CAPTION>
AFTER ROYALTIES
                                                                                    2006
($/boe)                                                 YEMEN    CANADA      US       UK   OTHER    SYNCRUDE    TOTAL
-----------------------------------------------------------------------------------------------------------------------
<S>                                                    <C>       <C>     <C>      <C>     <C>         <C>      <C>
Sales                                                   71.57     40.98   56.12    66.81   66.09       72.32    62.92
-----------------------------------------------------------------------------------------------------------------------
Operating Expenses                                      (8.11)   (12.73)  (9.45)  (11.28)  (3.13)     (30.43)  (11.96)
-----------------------------------------------------------------------------------------------------------------------
In-country Taxes (1)                                   (15.40)        -       -        -       -            -   (5.07)
-----------------------------------------------------------------------------------------------------------------------
CASH NETBACK                                            48.06     28.25   46.67    55.53   62.96       41.89    45.89
----------------------------------------------------- --------- --------- ------- -------- ------- ----------- --------

<CAPTION>
                                                                                      2005
($/boe)                                                   YEMEN    CANADA      US       UK   OTHER    SYNCRUDE    TOTAL
-----------------------------------------------------------------------------------------------------------------------
<S>                                                       <C>       <C>     <C>      <C>     <C>      <C>      <C>
Sales                                                     62.07     42.42   60.26    57.83   59.96       71.00    57.97
-----------------------------------------------------------------------------------------------------------------------
Operating Expenses                                        (6.75)   (10.34)  (7.33)  (14.90)  (6.08)     (27.22)  (10.34)
-----------------------------------------------------------------------------------------------------------------------
In-country Taxes (1)                                     (13.35)        -       -        -       -           -    (4.69)
-----------------------------------------------------------------------------------------------------------------------
CASH NETBACK                                              41.97     32.08   52.93    42.93   53.88       43.78    42.94
=======================================================================================================================

<CAPTION>
                                                                                      2004
($/boe)                                       AUSTRALIA    YEMEN    CANADA      US      UK   OTHER    SYNCRUDE   TOTAL
-----------------------------------------------------------------------------------------------------------------------
<S>                                           <C>         <C>       <C>     <C>     <C>      <C>      <C>      <C>
Sales                                            51.22     47.59     35.76   46.94   47.45   43.07       52.80   44.94
-----------------------------------------------------------------------------------------------------------------------
Operating Expenses                              (35.73)    (5.64)    (8.98)  (6.12)  (8.26)  (4.09)     (20.61)  (8.83)
-----------------------------------------------------------------------------------------------------------------------
In-country Taxes (1)                                 -    (11.72)        -       -       -       -           -   (3.57)
-----------------------------------------------------------------------------------------------------------------------
CASH NETBACK                                     15.49     30.23     26.78   40.82   39.19   38.98       32.19   32.54
=======================================================================================================================
</TABLE>
NOTE:
(1)  COMPRISES  INCOME  TAXES  PAYABLE  IN  YEMEN  THAT  ARE  INCLUDED  IN  THE
     GOVERNMENT'S SHARE OF PROFIT OIL.

                                      47
<PAGE>

<TABLE>
<CAPTION>
ENERGY MARKETING

   (Cdn$ millions)                                                2006      2005      2004
--------------------------------------------------------------------------------------------
<S>                                                            <C>       <C>       <C>
   Physical Sales (1)                                           40,920    37,873    28,554
--------------------------------------------------------------------------------------------
   Physical Purchases (1)                                      (39,925)  (36,988)  (28,074)
--------------------------------------------------------------------------------------------
   Net Financial Transactions (1)                                  314       (38)      128
--------------------------------------------------------------------------------------------
   Net Revenue                                                   1,309       847       608
--------------------------------------------------------------------------------------------
   Transportation Expense                                         (789)     (641)     (451)
--------------------------------------------------------------------------------------------
   Other                                                            20        (2)       (2)
--------------------------------------------------------------------------------------------
NET MARKETING REVENUE                                              540       204       155
--------------------------------------------------------------------------------------------

CONTRIBUTION TO NET MARKETING REVENUE BY PRODUCT TYPE:
--------------------------------------------------------------------------------------------
  North American Natural Gas                                       390       117        93
--------------------------------------------------------------------------------------------
  International Crude Oil                                          114        70        52
--------------------------------------------------------------------------------------------
  North American Power                                              16         8         4
--------------------------------------------------------------------------------------------
  Other                                                             20         9         6
--------------------------------------------------------------------------------------------
NET MARKETING REVENUE                                              540       204       155
--------------------------------------------------------------------------------------------
  Depreciation, Depletion, Amortization and Impairment             (12)      (11)      (10)
--------------------------------------------------------------------------------------------
  General and Administrative                                      (112)      (89)      (58)
--------------------------------------------------------------------------------------------
MARKETING CONTRIBUTION TO INCOME FROM CONTINUING
  OPERATIONS BEFORE INCOME TAXES                                   416       104        87
--------------------------------------------------------------------------------------------

NATURAL GAS
--------------------------------------------------------------------------------------------
  Physical Sales Volumes (2) (bcf/d)                               5.4       4.9       4.9
--------------------------------------------------------------------------------------------
  Transportation Capacity (bcf/d)                                  3.3       4.0       3.5
--------------------------------------------------------------------------------------------
  Storage Capacity (bcf)                                            50        30        27
--------------------------------------------------------------------------------------------

CRUDE OIL
--------------------------------------------------------------------------------------------
  Physical Sales Volumes (2) (mbbls/d)                             705       510       465
--------------------------------------------------------------------------------------------
  Storage Capacity (mbbls)                                       1,749       580       408
--------------------------------------------------------------------------------------------

POWER
--------------------------------------------------------------------------------------------
  Physical Sales Volumes - Power (2) (MW/d)                      4,388     2,548     1,191
--------------------------------------------------------------------------------------------
  Generation Capacity (MW/hr)                                       87        53        53
--------------------------------------------------------------------------------------------

VALUE-AT-RISK
--------------------------------------------------------------------------------------------
  Year End                                                          26        24        21
--------------------------------------------------------------------------------------------
  High                                                              33        28        42
--------------------------------------------------------------------------------------------
  Low                                                               17        11        17
--------------------------------------------------------------------------------------------
  Average                                                           23        21        29
============================================================================================
</TABLE>
NOTES:
(1)  MARKETING'S   PHYSICAL  SALES,   PHYSICAL   PURCHASES  AND  NET  FINANCIAL
     TRANSACTIONS ARE REPORTED NET ON THE  CONSOLIDATED  STATEMENT OF INCOME AS
     MARKETING AND OTHER.
(2)  EXCLUDES INTRA-SEGMENT TRANSACTIONS.


2006 VS 2005--NET MARKETING REVENUE INCREASED NET INCOME BY $336 MILLION

     Marketing had record results in 2006, with all groups  achieving new highs
or starting new businesses. The largest contribution continues to come from our
North  American  natural  gas  marketing  group  where  we  capitalized  on our
asset-based  trading strategy.  Time and location spread trading generated most
of our gas gains but we were also successful in generating revenues through the
optimization of our transportation and storage capacity.  Volatility within the
North American gas markets created market  inefficiencies  for us to capitalize
on. North American gas prices started 2006 at US$10.63/mcf  and closed the year
at US$6.30/mcf.  Storage  overhang and speculation  around weather and possible
hurricanes caused  significant  changes in prices during the year. We also took
advantage of opportunities late in the year to add to our storage capacity.

                                      48
<PAGE>

     Our  crude  oil  marketing   group  also   generated   record  results  by
successfully taking advantage of crude quality,  location and time spreads. The
group generated physical and financial trading gains by taking advantage of the
contango  (rising  forward  month  prices) in the crude oil forward  curve.  In
addition, we captured profits around quality spreads by diverting crude oil, or
by blending to enhance the crude quality,  and attract higher prices. While our
strategies remained largely the same in 2006, we executed more transactions and
added more  capacity,  particularly  storage,  during the year.  With our newly
established marine transportation  capabilities,  this group is well positioned
to start marketing our Buzzard production in 2007.

     Our  power  marketing  group  is the  largest  supplier  of  power  to the
commercial  and  industrial  sector in Alberta  and net  revenue  contributions
exceeded expectations.

              OUR POWER MARKETING GROUP IS THE LARGEST SUPPLIER OF
           POWER TO THE COMMERCIAL AND INDUSTRIAL SECTOR IN ALBERTA.

     We  continued  our  expansion  into  new  markets  during  the  year  with
acquisitions  in the North  American NGL trading  business and a UK acquisition
which positioned us in the UK and European gas and power markets.

     Results  from our  marketing  group vary  between  periods and  historical
results are not  necessarily  indicative of future results.  Marketing  results
depend on a variety of factors such as market  volatility,  changes in time and
location  spreads,  the manner in which we use our storage  and  transportation
assets and the  change in value of the  financial  instruments  we use to hedge
these assets.

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  $70 million of net revenue in
2005,  an increase of 35% 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 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.

COMPOSITION OF NET MARKETING REVENUE

(Cdn$ millions)                                                  2006    2005
-------------------------------------------------------------------------------
Trading Activities                                                520     195
-------------------------------------------------------------------------------
Non-Trading Activities                                             20       9
-------------------------------------------------------------------------------
TOTAL NET MARKETING REVENUE                                       540     204
===============================================================================

                                      49
<PAGE>

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,  2006,  the fair value of our  derivative  contracts  not
designated as hedges  totalled $360 million  (2005--$169  million).  Below is a
breakdown of this fair value by valuation method and contract maturity.

<TABLE>
<CAPTION>
                                                                LESS THAN                   MATURITY     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                                             190          (26)          (21)            -         143
--------------------------------------------------------------------------------------------------------------------------------
  From Other External Sources                                         216           (6)           13            (6)        217
--------------------------------------------------------------------------------------------------------------------------------
  Based on Models and Other Valuation Methods                           -            -             -             -           -
--------------------------------------------------------------------------------------------------------------------------------
TOTAL                                                                 406          (32)           (8)           (6)        360
================================================================================================================================

<CAPTION>
CHANGES IN FAIR VALUE OF DERIVATIVE CONTRACTS

(Cdn$ millions)                                                                                 TOTAL
-------------------------------------------------------------------------------------------------------
<S>                                                                                            <C>
Fair Value at December 31, 2005                                                                   169
-------------------------------------------------------------------------------------------------------
  Change in Fair Value of Contracts                                                               576
-------------------------------------------------------------------------------------------------------
  Net Losses (Gains) on Contracts Closed                                                         (385)
-------------------------------------------------------------------------------------------------------
  Changes in Valuation Techniques and Assumptions (1)                                               -
-------------------------------------------------------------------------------------------------------
FAIR VALUE AT DECEMBER 31, 2006                                                                   360
-------------------------------------------------------------------------------------------------------
Unrecognized Gains on Hedges of Future Sale of Gas Inventory at December 31, 2006                  25
-------------------------------------------------------------------------------------------------------
TOTAL OUTSTANDING AT DECEMBER 31, 2006                                                            385
=======================================================================================================
</TABLE>
NOTE:
(1)  OUR VALUATION METHODOLOGY HAS BEEN APPLIED CONSISTENTLY YEAR-OVER-YEAR.

     As a  physical  energy  marketer,  we match  the  contract  months  of our
derivative  contracts  with the  contract  months  of our  physical  sales  and
purchases.  As a  result,  the fair  value of our  derivative  contracts  as at
December 31, 2006 includes  amounts with no ongoing  commodity price or foreign
currency  exchange  risk.  Excluding  these  amounts,  the  fair  value  of our
derivative contracts at December 31, 2006 was $102 million.

     The fair values of our derivative  contracts will be realized over time as
the related contracts  settle.  Until then, the value of certain contracts will
vary with  forward  commodity  prices and price  differentials.  While  forward
prices  vary,  the value of the  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 the majority of this fair value.

                                      50
<PAGE>

     More than 113% of the  unrealized  fair value  relates to  contracts  that
settle within 12 months.  Contract  maturities  vary from a single day up to 12
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  from quoted  markets and  external  sources and the
limited economic exposure combine to lower our portfolio risk.

     As part of our gas marketing strategy, we hold physical transportation and
storage  capacity  contracts  that  allow  us  to  take  advantage  of  pricing
differences  between  locations  (i.e.  west vs. east) and time  periods  (i.e.
summer vs.  winter).  These capacity  contracts  have market value,  similar to
financial  commodity  contracts,  as future margins  realized  depend on future
prices and, more importantly,  pricing  differences.  The market value of these
capacity  contracts varies depending on the change in future prices and pricing
relationships.  We routinely hedge the economic value of our capacity contracts
using various types of derivative contracts, thereby limiting volatility in our
economic  results.  Accounting  rules,  however,  increase  volatility  in  our
reported results since they require us to recognize the change in fair value of
derivative  contracts  hedging our capacity  contracts,  but do not allow us to
recognize the change in fair value of the capacity  contracts  themselves until
the  contracts  are used.  As a result,  when  prices or pricing  relationships
change,  we may be required to include gains or losses in our reported  results
in different periods even though our underlying economic results may be largely
unchanged.  At the end of 2006,  unrecognized future commitments related to our
transportation and storage capacity  contracts was a loss of $81 million.  This
amount  has been  included  in our  contractual  obligations,  commitments  and
guarantees in the MD&A.

     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,  2006,  we had $25 million of
unrecognized  gains on these  derivative  contracts.  These contracts have been
valued from actively  quoted markets and will settle within 12 months.  In late
2006, we  de-designated  certain futures  contracts that had been designated as
cash flow hedges of future  sales of our  natural gas in storage.  Gains of $65
million on the futures  contracts  have been  deferred  and are  expected to be
recognized in net income in the first quarter of 2007.

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  facilities at Balzac and Soderglen.  We earned $20 million from our
non-trading activities in 2006 (2005--$9 million).

CHEMICALS

(Cdn$ millions)                                           2006    2005   2004
-------------------------------------------------------------------------------
Net Sales                                                  407     398    378
-------------------------------------------------------------------------------
Sales Volumes (thousand short tons)
-------------------------------------------------------------------------------
  Sodium Chlorate                                          487     493    506
-------------------------------------------------------------------------------
  Chlor-alkali                                             451     450    403
-------------------------------------------------------------------------------
Operating Profit (1)                                       124     136    105
-------------------------------------------------------------------------------
Operating Margin (2)                                       30%     34%    28%
-------------------------------------------------------------------------------
Chemicals Contribution to Income from Continuing
  Operations Before Income Taxes                            44      37     40
-------------------------------------------------------------------------------
Capacity Utilization                                       95%     96%    95%
===============================================================================
NOTES:
(1)  TOTAL REVENUES LESS OPERATING COSTS, TRANSPORTATION AND OTHER.
(2)  OPERATING PROFIT DIVIDED BY NET SALES.


                                      51
<PAGE>

2006 VS 2005-- LOWER CHEMICALS OPERATING PROFIT DECREASED NET INCOME BY
$12 MILLION

     Our  investment  in our  chemicals  business  is held  through  our  61.4%
interest in the Canexus  Limited  Partnership.  While North American prices for
sodium chlorate  remained strong  throughout  2006, sales volumes fell slightly
from  last year as a result of pulp mill  closures.  Chlor-alkali  volumes  and
prices in North America remained steady.  US-dollar  denominated North American
sales were reduced $12 million from the stronger  Canadian  dollar during 2006.
Sales and operations from the Brazil plant remained solid as a result of strong
demand from  Aracruz  Cellulose,  our primary  customer,  and from the merchant
market.

               DURING THE YEAR, CANEXUS BEGAN AN EXPANSION OF THE
      BRANDON, MANITOBA PLANT, WHICH BENEFITS FROM LOW ELECTRICITY RATES.

     Late in the year, Canexus commenced an expansion of the Brandon,  Manitoba
plant to increase  capacity by 12% by early 2008.  The Brandon  plant  benefits
from low electricity  rates in the province of Manitoba,  where the electricity
market is based on hydroelectric power and is regulated.

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 Limited Partnership,
also  raised  US$167  million  ($200  million)  of bank debt.  Canexus  Limited
Partnership used the proceeds from Canexus Income Fund's IPO and the bank debt,
together  with the issuance of 50.5 million  exchangeable  units of the Canexus
Limited  Partnership to Nexen,  to purchase our chemicals  operations.  We have
retained a 61.4% 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.

<TABLE>
<CAPTION>
CORPORATE EXPENSES

GENERAL AND ADMINISTRATIVE (G&A)
(Cdn$ millions)                                                               2006     2005     2004
------------------------------------------------------------------------------------------------------
<S>                                                                           <C>      <C>      <C>
General and Administrative Expense before Stock-Based Compensation             345      302      206
------------------------------------------------------------------------------------------------------
Stock-Based Compensation (1)                                                   210      507       93
------------------------------------------------------------------------------------------------------
TOTAL GENERAL AND ADMINISTRATIVE EXPENSE                                       555      809      299
======================================================================================================
</TABLE>
NOTE:
(1)  INCLUDES TANDEM OPTION PLAN, STOCK OPTIONS FOR OUR US-BASED  EMPLOYEES AND
     STOCK APPRECIATION RIGHTS PLAN.


                                      52
<PAGE>

2006 VS 2005--LOWER COSTS INCREASED NET INCOME BY $254 MILLION

     Our G&A expense before  stock-based  compensation  increased 14% primarily
from  additional  costs to expand our  marketing  operations  into new markets.
Acquisitions  during the year  enabled us to increase our NGL business in North
America and to expand our  European  trading  operations.  Our G&A expense also
includes  higher  variable  compensation  stemming from our  marketing  group's
strong performance in 2006.

                    TOTAL G&A EXPENSE DECREASED 31% IN 2006
                  FROM LOWER STOCK-BASED COMPENSATION COSTS.

     Changes  in our share  price  creates  volatility  in our net income as we
account for stock-based  compensation using the  intrinsic-value  method.  This
method uses our share price at the end of the reporting period to determine our
stock-based  compensation expense and related  obligations.  In 2006, our share
price  increased  16% from  $55.42 to  $64.20,  creating  over $2.3  billion of
shareholder value. The expense  represents  approximately 9% of the increase in
shareholder value. Cash payments to employees for our stock-based  compensation
programs were $119 million in 2006, a 61% increase over 2005.

2005 VS 2004--HIGHER COSTS REDUCED NET INCOME BY $510 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.
Notwithstanding  this  increase in our share price,  cash payments to employees
under our stock-based compensation programs only amounted to $74 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.

INTEREST

(Cdn$ millions)                                     2006       2005      2004
-------------------------------------------------------------------------------
Interest                                             294        275       194
-------------------------------------------------------------------------------
  Less: Capitalized                                 (241)      (178)      (51)
-------------------------------------------------------------------------------
NET INTEREST EXPENSE                                  53         97       143
-------------------------------------------------------------------------------

Effective Rate                                      6.3%       6.4%      6.6%
===============================================================================

2006 VS 2005--LOWER NET INTEREST EXPENSE INCREASED NET INCOME BY $44 MILLION

     Our  financing  costs have  increased  $19 million  from 2005.  Additional
borrowings to finance our 2006 capital  program  increased  financing  costs by
approximately $28 million.  This was partially offset however,  by the stronger
Canadian  dollar which  decreased  our  US-dollar  denominated  interest by $16
million.  The  Canexus  debt,  consolidated  with our  results,  increased  our
interest expense by $7 million.

     The amount of interest we  capitalized on our major  development  projects
grew by $63  million,  primarily  from  increased  investment  in the North Sea
Buzzard  project,  at Long Lake and the Stage 3 expansion at Syncrude  prior to
its start-up. We expect interest capitalized on projects to decrease in 2007 as
we ceased capitalizing interest on the Syncrude expansion in August 2006 and on
Buzzard in January 2007.  We expect to continue to  capitalize  interest on our
Long Lake project prior to its completion in 2007. Our net interest  expense is
expected to increase once these projects are completed.


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,  increasing our interest
costs by $87  million  in 2005.  Interest  expense  also  increased  $3 million
relating  to the Canexus  debt  consolidated  with our  results.  However,  the
stronger  Canadian  dollar  lowered our US-dollar  denominated  interest by $12
million.  During  the last two  years,  we have taken  advantage  of  declining
interest  rates by replacing  our  higher-cost  preferred  securities  with new
long-term debt at lower rates.


                                      53
<PAGE>

INCOME TAXES

(Cdn$ millions)                                          2006     2005    2004
--------------------------------------------------------------------------------
Current                                                   368      339     248
--------------------------------------------------------------------------------
Future                                                    315     (234)    119
--------------------------------------------------------------------------------
TOTAL PROVISION FOR INCOME TAXES                          683      105     367
--------------------------------------------------------------------------------

Disclosed as:
--------------------------------------------------------------------------------
Provision for Income Taxes--Continuing Operations         683      234     317
--------------------------------------------------------------------------------
Provision for Income Taxes--Discontinued Operations (1)     -     (129)     50
--------------------------------------------------------------------------------
TOTAL PROVISION FOR INCOME TAXES                          683      105     367
--------------------------------------------------------------------------------

Effective Rate                                            53%       8%     32%
================================================================================
NOTE:
(1)  SEE NOTE 14 TO OUR CONSOLIDATED FINANCIAL STATEMENTS.


2006 VS 2005--EFFECTIVE TAX RATE INCREASES FROM 8% TO 53%

     In early 2006, the UK government  substantively  enacted  increases to the
supplementary tax rate on our North Sea oil and gas activities from 10% to 20%,
effective  January 1, 2006.  This increased our future income tax  liabilities,
resulting  in a charge of $277  million  during the first  quarter.  During the
second quarter,  federal and certain  provincial  governments in Canada reduced
corporate income tax rates. These rate reductions lowered our future income tax
liabilities  by $32 million.  Our  effective  tax rate  excluding the effect of
these tax rate changes was 33%.

            IN 2006, AN INCREASE IN THE UK SUPPLEMENTAL TAX RATE ON
 OIL & GAS ACTIVITIES RESULTED IN A FUTURE INCOME TAX EXPENSE OF $277 MILLION.

     Current  income taxes  include cash taxes in Yemen of $286 million (2005 -
$296 million;  2004 - $227  million).  Our current  income tax  provision  also
includes  federal and state taxes in the US, cash taxes in Colombia and capital
taxes in Canada.

2005 VS 2004--EFFECTIVE TAX RATE DECREASES FROM 32% TO 8%

     The recovery of future taxes  payable of $234 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%.


                                      54
<PAGE>

<TABLE>
<CAPTION>
OTHER

(Cdn$ millions)                                                                           2006     2005     2004
------------------------------------------------------------------------------------------------------------------
<S>                                                                                       <C>      <C>      <C>
Block 51 Arbitration                                                                      (151)       -        -
------------------------------------------------------------------------------------------------------------------
Business Interruption Insurance Proceeds                                                   154        2       10
------------------------------------------------------------------------------------------------------------------
Gain on Dilution of Interest in Chemicals Business                                           -      193        -
------------------------------------------------------------------------------------------------------------------
Gain on Disposition of Oil and Gas Assets included as Discontinued Operations                -      225        -
------------------------------------------------------------------------------------------------------------------
Increase (Decrease) in Fair Value of Crude Oil Put Options                                 (11)    (196)      56
==================================================================================================================
</TABLE>

     During the year, a court of arbitration concluded that we breached an Area
of  Mutual   Interest   agreement   with   Occidental   Petroleum   Corporation
(Occidental). As a result, Occidental was entitled to monetary damages. In late
2006, we agreed to settle the arbitration by agreeing to pay Occidental  US$135
million as monetary  damages.  No further  amounts  are  expected to be payable
under the settlement.

     In 2006,  we  received  $154  million of business  interruption  insurance
proceeds  related to production  losses caused by Gulf of Mexico  hurricanes in
2005 and by generator failures in our UK operations in 2005.

     As a result of the sale of our chemicals  business to the Canexus  Limited
Partnership  in 2005,  we recorded a gain on the dilution of our interest  from
100% to 61.4% of $193  million.  Our gain on the 2005 sale of Canadian  oil and
gas properties in Alberta, British Columbia and Saskatchewan was $225 million.

     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  reduced the value of these  options by $196
million.  Strong WTI prices in 2006 reduced the market value of these remaining
options to nil and we expensed $4 million in 2006 as a result.

     During 2006, we purchased put options on  approximately  105,000 bbls/d of
our 2007 crude oil  production.  These  options  establish a WTI floor price of
US$50/bbl on these  volumes,  are settled  annually and provide a base level of
price protection  without limiting our upside to higher prices. The put options
were  purchased  for $26 million  and are carried at fair value.  We recorded a
loss of $7 million during the year for the decrease in fair value.

OUTLOOK FOR 2007

     In 2007, we plan to invest $2.9 billion in capital projects. Approximately
34% of this capital will be invested in  development  projects,  which  include
Long Lake, coalbed methane in Canada, Ettrick in the North Sea, and Wrigley and
Tobago in the Gulf of Mexico.  We are also directing 14% of our 2007 capital to
early-stage  development  projects  expected to contribute  production and cash
flow growth beyond 2007.  These include Knotty Head,  Alaminos Canyon Block 856
(Great  White West) and Ringo in the Gulf of Mexico,  additional  phases of oil
sands in the  Athabasca  region and Block 222,  offshore  West Africa.  We have
allocated 24% of our capital to exploration  opportunities in our growth areas.
The remaining 28% of the 2007 capital will be invested to exploit  potential in
our existing producing assets and in other corporate assets.

     Details of our 2007 capital investment program are included in the Capital
Investment section of the MD&A.

DAILY PRODUCTION

     We expect to grow annual  production  rates after royalties  approximately
50% compared to 2006 to between  230,000 and 260,000 boe/d (275,000 and 305,000
boe/d before royalties).  Our Buzzard  development came on stream early January
2007 and we expect to  achieve  peak  rates of 85,000  boe/d  during the second
quarter of 2007.  Other  contributions  to our expected growth in 2007 are from
the Gulf of Mexico,  a full year of  production  from the Stage 3 expansion  at
Syncrude and bitumen  production from Long Lake. Our annual production for 2007
is expected to be:

                                      55
<PAGE>

2007 ESTIMATED PRODUCTION

<TABLE>
<CAPTION>
                                              2007 ESTIMATED PRODUCTION              2006 PRODUCTION

                                                BEFORE            AFTER           BEFORE         AFTER
(mboe/d)                                       ROYALTIES        ROYALTIES        ROYALTIES     ROYALTIES
----------------------------------------------------------------------------------------------------------
<S>                                          <C>                <C>              <C>           <C>
United States                                 45  -   55        38  -   48              36            31
----------------------------------------------------------------------------------------------------------
United Kingdom                                 90  - 100         90  - 100              20            20
----------------------------------------------------------------------------------------------------------
Yemen                                         60  -   75        35  -   45              93            52
----------------------------------------------------------------------------------------------------------
Canada                                        45  -   50        38  -   42              38            31
----------------------------------------------------------------------------------------------------------
Syncrude                                      20  -   25        18  -   20              19            17
----------------------------------------------------------------------------------------------------------
Other International                           6  -     7        5  -     6               6             5
----------------------------------------------------------------------------------------------------------
TOTAL                                          275 - 305         230 - 260             212           156
==========================================================================================================
</TABLE>

CASH FLOW AND SENSITIVITIES

     We expect to generate  more than $3.3 billion in cash flow from  operating
activities in 2007 (before site  restoration  and  geological  and  geophysical
expenditures), assuming the following:

-------------------------------------------------------------------------------
WTI (US$/bbl)                                                            50.00
-------------------------------------------------------------------------------
NYMEX Natural Gas (US$/mmbtu)                                             6.00
-------------------------------------------------------------------------------
Oil & Gas and Syncrude Operating Costs (Cdn$/boe)                         8.00
-------------------------------------------------------------------------------
US to Canadian Dollar Exchange Rate                                       0.88
===============================================================================

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

(Cdn$ millions)
-------------------------------------------------------------------------------
WTI--US$1/bbl Change above US$50                                            73
-------------------------------------------------------------------------------
WTI--US$1/bbl Change below US$50                                            42
-------------------------------------------------------------------------------
NYMEX Natural Gas--US $1.00/mcf Change                                      66
-------------------------------------------------------------------------------
Exchange Rate--$0.01 Change                                                 35
===============================================================================

LIQUIDITY AND CAPITAL RESOURCES

CAPITAL STRUCTURE

(Cdn$ millions)                                            2006          2005
-------------------------------------------------------------------------------
NET DEBT (1)
-------------------------------------------------------------------------------
  Bank Debt                                               1,410           171
-------------------------------------------------------------------------------
  Public Senior Notes                                     2,885         2,980
-------------------------------------------------------------------------------
      Senior Debt                                         4,295         3,151
-------------------------------------------------------------------------------
  Subordinated Debt                                         536           536
-------------------------------------------------------------------------------
      Total Debt                                          4,831         3,687
-------------------------------------------------------------------------------
  Less: Cash and Cash Equivalents                          (101)          (48)
-------------------------------------------------------------------------------
TOTAL NET DEBT                                            4,730         3,639
===============================================================================

SHAREHOLDERS' EQUITY (2)                                  4,636         3,996
===============================================================================
NOTES:
(1)  INCLUDES  ALL  OF OUR  DEBT  AND  IS  CALCULATED  AS  LONG-TERM  DEBT  AND
     SHORT-TERM BORROWINGS LESS CASH AND CASH EQUIVALENTS.
(2)  AT JANUARY  31,  2007,  THERE WERE  262,830,108  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.


                                      56
<PAGE>

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 $4.7 billion,  an increase of $1.1 billion from 2005.
In 2006, we invested over $3.4 billion in capital projects,  with more than 50%
of this at Long Lake and Buzzard.  These major  projects did not  contribute to
cash flow in 2006 but will start to contribute in 2007 and beyond.  We financed
our 2006 capital program with cash flow from operating  activities and borrowed
US$925 million under our term credit facilities.

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

(Cdn$ millions)                                                2006       2005
--------------------------------------------------------------------------------
Capital Investment                                            3,408      2,638
--------------------------------------------------------------------------------
Cash Flow from Operating Activities                          (2,374)    (2,143)
--------------------------------------------------------------------------------
  Excess of Capital Investment over Cash Flow                 1,034        495
--------------------------------------------------------------------------------
Net Proceeds on Disposition of Assets                           (27)      (911)
--------------------------------------------------------------------------------
Net Proceeds from Canexus Initial Public Offering                 -       (301)
--------------------------------------------------------------------------------
Dividends on Common Shares                                       52         52
--------------------------------------------------------------------------------
Issue of Common Shares                                          (48)       (58)
--------------------------------------------------------------------------------
Foreign Exchange Translation of US-dollar Debt and Cash          31       (113)
--------------------------------------------------------------------------------
Other                                                            49        190
--------------------------------------------------------------------------------
INCREASE (DECREASE) IN NET DEBT                               1,091       (646)
================================================================================

     The change in our net debt has increased our leverage  levels as reflected
in following ratios:

(times)                                             2006       2005      2004
-------------------------------------------------------------------------------
Net Debt to Cash Flow from Operating Activities      2.0        1.7       2.7
-------------------------------------------------------------------------------
Interest Coverage (1)                                9.6        9.7      11.9
===============================================================================
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    repurchase 20 million common shares in 2000;
        o    acquire the remaining interest in Aspen in 2003;
        o    acquire the Buzzard  project and other key assets in the North
             Sea in 2004;
        o    build our first phase of Long Lake,  scheduled  to be on stream
             in late 2007; and
        o    fund remaining development capital.

     Each time,  we exceeded  our  internal  net debt to cash flow target band;
however,  we  successfully  brought our leverage  down through  asset sales and
incremental  cash flows.  In 2006, we again  increased our leverage levels as a
result of capital expenditures on our major development projects at Buzzard and
Long  Lake.  In 2007,  we  anticipate  reducing  our net debt to cash flow from
operating  activities  ratio using cash flows from our Buzzard  operations,  as
well as our Long Lake project, expected to come on stream in 2007.

                                      57
<PAGE>

CHANGE IN WORKING CAPITAL
                                                                     INCREASE/
(Cdn$ millions)                                2006     2005        (DECREASE)
-------------------------------------------------------------------------------
Cash and Cash Equivalents                       101       48               53
-------------------------------------------------------------------------------
Restricted Cash and Margin Deposits             197       70              127
-------------------------------------------------------------------------------
Accounts Receivable                           2,951    3,151             (200)
-------------------------------------------------------------------------------
Inventories and Supplies                        786      504              282
-------------------------------------------------------------------------------
Future Income Tax Assets                        479        -              479
-------------------------------------------------------------------------------
Accounts Payable and Accrued Liabilities     (3,879)  (3,727)            (152)
-------------------------------------------------------------------------------
Other                                            (1)     (17)              16
-------------------------------------------------------------------------------
TOTAL                                           634       29              605
===============================================================================

     Lower  natural gas prices  reduced our year end accruals for our marketing
accounts receivable and accounts payable. This has been offset by higher prices
in crude oil markets.  We expanded our crude oil physical and financial trading
activities  to capture  market  gains.  This  expanded  activity  increased our
marketing accounts  receivable and accounts payable. We took advantage of lower
natural gas prices and  expanded our gas storage  inventories  by 27 bcf during
the year.  Volatile  gas markets  also  increased  the value of our  derivative
contract assets and liabilities.

     Our accounts  payable and accrued  liabilities  have increased  since 2005
from higher  accrued  stock-based  compensation  obligations as a result of our
strong share price,  higher accruals related to our capital investment programs
and our accrual  related to the Block 51  settlement.  We have  reclassed  $479
million of future income tax assets to current assets. This represents tax loss
carry-forward  balances in our UK operations  that we expect to use in the next
twelve months now that Buzzard is on stream.

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. In
addition, we require liquidity for our energy marketing business.  Accordingly,
we maintain significant  committed credit facilities.  At December 31, 2006, we
had committed term credit  facilities of $3.6 billion that are available  until
2011.  At year  end,  $1,078  million  was drawn on these  facilities  and $294
million of these facilities were utilized to support letters of credit. We also
had $632 million of uncommitted,  unsecured  credit  facilities,  of which $158
million was drawn at year end and $252 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  commodity  prices  and  foreign  exchange.  For  example,  we
purchased WTI put options for 2007 to mitigate cash flow  volatility.  Overall,
we manage our  capital  structure  to maintain  flexibility  so we can fund our
capital programs  throughout the highs and lows of the price cycles inherent in
the oil and gas business.

     The following table shows how we finance our business 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.

(Cdn$ millions)                         2006     2005     2004     2003    2002
--------------------------------------------------------------------------------
Cash Flow from Operating Activities    2,374    2,143    1,606    1,405   1,250
--------------------------------------------------------------------------------
Cash Flow from Investing Activities   (3,388)  (1,864)  (4,013)  (1,219) (1,569)
--------------------------------------------------------------------------------
Surplus (Deficiency)                  (1,014)     279   (2,407)     186    (319)
--------------------------------------------------------------------------------
Cash Flow from Financing Activities    1,081     (274)   1,426    1,006     329
--------------------------------------------------------------------------------
                                          67        5     (981)   1,192      10
================================================================================

                                      58
<PAGE>

     In 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 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.  In 2006,  we borrowed  approximately  $1
billion under our committed term credit  facilities and used our cash flow from
operating activities to fund our capital program.

     Our marketing  business also requires liquidity to support its asset-based
trading  strategy.  We require  liquidity for working  capital,  cash or credit
lines to fund collateral requirements and 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$50/bbl,  we expect our 2007 cash
flow to exceed our capital investment program and dividend requirements by more
than $300  million.  In July 2007,  we are  required  to repay $150  million of
medium term notes that become due, however,  we plan to fund this with our term
credit facilities.

     Our cash flow is  sensitive  to changes in  commodity  prices and exchange
rates.  For 2007,  we expect cash flow of  approximately  $3.3 billion  (before
remediation and geological and geophysical expenditures) assuming:

-------------------------------------------------------------------------------
WTI (US$/bbl)                                                            50.00
-------------------------------------------------------------------------------
NYMEX Natural Gas (US$/mmbtu)                                             6.00
-------------------------------------------------------------------------------
US to Canadian Dollar Exchange Rate                                       0.88
===============================================================================

     Changes in commodity  prices and exchange  rates will impact our cash flow
and  borrowing  requirements.  The impact of a variance in any one of the above
assumptions  on our cash flow is  described  in the Outlook for 2007 section on
page 55.

                        FOR 2007, WE EXPECT CASH FLOW OF
                          APPROXIMATELY $3.3 BILLION.

     We are in the  midst of a number  of  development  projects  that  require
capital to bring them on stream. We anticipate that we will spend an additional
$500  million  in 2007 to bring the  first  phase of Long  Lake on  stream.  In
addition,  we expect to spend $200  million in 2007 on  furthering  our coalbed
methane  projects in central  Alberta and $235  million to complete the Ettrick
development in the North Sea by mid 2008.

     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, 2006,  the average term to maturity of our long-term  debt
was 16.6 years.  We have the  following  short and  long-term  debt  maturities
during the next five years:

(Cdn$ millions)                            2007    2008   2009    2010    2011
-------------------------------------------------------------------------------
Uncommitted Credit Facilities               158       -      -       -       -
-------------------------------------------------------------------------------
Term Credit Facilities (1)                    -       -      -       -   1,078
-------------------------------------------------------------------------------
Canexus LP Term Credit Facilities             -       -      -     174       -
-------------------------------------------------------------------------------
Debentures                                    -       -      -       -       -
-------------------------------------------------------------------------------
Medium Term Notes                           150     125      -       -       -
-------------------------------------------------------------------------------
TOTAL                                       308     125      -     174   1,078
===============================================================================
NOTE:
(1)  $3.6 BILLION AVAILABLE UNTIL 2011.


                                      59
<PAGE>

     With  our  expected  cash  flow  streams,   commodity  price  and  hedging
strategies, current levels of liquidity, and access to debt and equity markets,
we  expect  to  be  able  to  fund  our  planned  capital  programs,   dividend
requirements and debt repayments, or meet other obligations that may arise from
our oil and gas, chemicals and marketing operations.

     In  2006  we  declared   common   share   dividends  of  $0.20  per  share
(2005--$0.20,  2004--$0.20).  We expect to declare  common  share  dividends of
$0.20 per share in 2007.

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>
                                                                LESS THAN      PAYMENTS                  MORE THAN
(Cdn$ millions)                                         TOTAL      1 YEAR     1-3 YEARS     4-5 YEARS      5 YEARS
--------------------------------------------------------------------------------------------------------------------
<S>                                                    <C>      <C>           <C>          <C>           <C>
Short-Term and Long-Term Debt                           4,831         308           125         1,252        3,146
--------------------------------------------------------------------------------------------------------------------
Interest on Long-Term Debt                              4,859         215           406           403        3,835
--------------------------------------------------------------------------------------------------------------------
Operating Leases (1)                                      752          44           236           240          232
--------------------------------------------------------------------------------------------------------------------
Capital Leases                                            119           5            10            10           94
--------------------------------------------------------------------------------------------------------------------
Energy Commodity Contract Liabilities                     524         325           191             8            -
--------------------------------------------------------------------------------------------------------------------
Transportation and Storage Commitments (1)                927         424           262           123          118
--------------------------------------------------------------------------------------------------------------------
Work Commitments and Purchase Obligations (2)           1,460         663           419           218          160
--------------------------------------------------------------------------------------------------------------------
Asset Retirement Obligations                            1,770          21            42            34        1,673
--------------------------------------------------------------------------------------------------------------------
TOTAL                                                  15,242       2,005         1,691         2,288        9,258
====================================================================================================================
</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    Short-term and long-term debt amounts are included on our December
             31, 2006 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 that allows our Aspen production to flow
             through Shell's processing  facilities at the Bullwinkle platform.
             The terms of the processing  agreement give Shell an annual option
             to take payment in cash or in kind. For 2007, Shell has elected to
             take payment in kind,  so the 2007  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, 2006.  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 ($157  million) and the Ettrick  development in
             the North Sea ($233  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  2007  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 $414 million over the next five years.

                                      60
<PAGE>

        o    We  have  $1,770   million  of   undiscounted   asset   retirement
             obligations  after  inflation.   As  of  December  31,  2006,  the
             discounted value ($704 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
             plans of $122 million (Nexen--$67  million;  Canexus--$8  million;
             Syncrude--$47  million).  Our  obligations  for Nexen and  Canexus
             include  $54 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  tandem  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
             2007.

        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.

     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.  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 Baa2 by Moody's Investor Service, Inc.
(Moody's),  BBB by Dominion Bond Rating  Service  (DBRS) and BBB- by Standard &
Poor's  (S&P).  In  addition,  Moody's and DBRS  currently  rate our outlook as
stable while S&P has a positive 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,  2006,  we could be required to post  collateral  of up to $1,149
million 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 for amounts owing to us if they are downgraded
to non-investment grade.

OFF-BALANCE SHEET ARRANGEMENTS

     We have no  off-balance  sheet  arrangements  that  would  have a material
adverse effect on our liquidity,  consolidated financial position or results of
operations.  We use  operating  leases  in the  normal  course of  business  as
disclosed in Contractual Obligations, Commitments and Guarantees on page 60 and
in Note 15 to the  Consolidated  Financial  Statements  in  Item  8,  which  is
incorporated  herein by  reference.  At December 31, 2006,  we had  outstanding
letters of credit  amounting to $294 million and $252 million  supported by our
committed  term  credit  facilities  and  our  uncommitted  credit  facilities,
respectively.

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.

                                      61
<PAGE>

CRITICAL ACCOUNTING ESTIMATES

     We make estimates and assumptions  that affect the reported amounts of our
assets and liabilities and the disclosure of contingent  assets and liabilities
at the date of the  Consolidated  Financial  Statements  and our  revenues  and
expenses during the reporting period.  Our management  reviews these estimates,
including  those  related  to  accruals,  litigation,  environmental  and asset
retirement   obligations,   income  taxes,   derivative   contract  assets  and
liabilities  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
judgments 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.

     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 reserve  estimates are based on numerous  assumptions,
interpretations  and  judgments,   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 18.

                                      62
<PAGE>

     The  board of  directors  has  established  a  Reserves  Review  Committee
(Reserves  Committee)  to assist  the board  and the Audit and  Conduct  Review
Committee to oversee the annual  review of our oil and gas reserves and related
disclosures.  The Reserves  Committee is comprised of three or more  directors,
the majority of whom are  independent,  and each being familiar with estimating
oil and gas reserves. The Reserves Committee meets with management periodically
to review the  reserves  process,  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  2006,  $169  million  of  our  total  $289  million  spent  on
             exploration  drilling  was  expensed.  If none of our  exploration
             drilling had been successful,  our net income would have decreased
             by $120 million.

        o    Calculating our  unit-of-production  depletion rates.  Both proved
             and proved  developed  reserves  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 2006, oil and gas depletion
             of  $741   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  $74
             million, 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.


PROPERTY, PLANT AND EQUIPMENT--IMPAIRMENT

     We evaluate our long-lived  assets (oil and gas  properties,  Syncrude and
chemicals)  for  impairment if an adverse event or change  occurs.  Among other
things,  this might include falling oil and gas prices, a significant  negative
revision to our reserves estimates,  changes in operating and capital costs, or
significant

                                      63
<PAGE>

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 assets for impairment at the end of 2006 and
recorded an impairment charge of $93 million,  primarily related to two natural
gas producing properties in the Gulf of Mexico.

     Cash flow estimates for our  impairment  assessments  require  assumptions
about two primary elements--future prices and reserves. Our estimates of future
prices require  significant  judgments  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$18/bbl to
US$79/bbl and US$2/mmbtu to  US$16/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 these estimates
would impact all except our chemicals and energy marketing businesses.

     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.

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,  Syncrude
assets  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,  the carrying value
of 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.

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 made various assumptions in determining the fair values of the acquired
company's  assets  and  liabilities.   The  most  significant  assumptions  and
judgments  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,  (b) additional
reserves potential and (c) 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

                                      64
<PAGE>

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

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

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

FUTURE INCOME TAXES

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

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  available 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,  2006 would  have the  following  impact on our  Consolidated
Financial Statements:

                                                                     INCREASE/
 (Cdn$ millions)                                                    (DECREASE)
--------------------------------------------------------------------------------
Accounts Receivable                                                         25
--------------------------------------------------------------------------------
Future Income Tax Liabilities                                                7
--------------------------------------------------------------------------------
Cumulative Foreign Currency Translation Adjustment                         161
--------------------------------------------------------------------------------
Accumulated Other Comprehensive Income                                    (143)
================================================================================

                                      65
<PAGE>

     In March 2006, the CICA's Emerging Issues  Committee (EIC) issued Abstract
160,  STRIPPING  COSTS INCURRED IN THE PRODUCTION  PHASE OF A MINING  OPERATION
(EIC-160).  EIC-160 outlines accounting for overburden and mine waste materials
removed in the process of accessing  mineral deposits  according to the benefit
received by the entity.  Generally,  stripping costs should be accounted for as
variable  production  costs and included in the costs of inventory  produced in
the  period  the  stripping  costs are  incurred.  If it can be shown  that the
stripping was for betterment of the mineral property, stripping costs should be
capitalized.   The  standard  outlines  the  requirement  for  amortization  of
capitalized  stripping  costs as well as a  reconciliation  of stripping  costs
incurred  in the  production  phase.  EIC-160 is  effective  for  fiscal  years
beginning  on or after July 1, 2006.  We do not expect the  adoption of EIC-160
will have any  material  impact  on our  results  of  operations  or  financial
position.

     In July 2006, the EIC issued Abstract 162,  STOCK-BASED  COMPENSATION  FOR
EMPLOYEES  ELIGIBLE  TO RETIRE  BEFORE  THE  VESTING  DATE  (EIC-162).  EIC-162
provides  that if an  employee  is  eligible  to retire on the grant  date of a
stock-based award,  related  compensation expense is recognized in full at that
date as there is no ongoing service requirement to earn the award. In addition,
if the employee becomes  eligible to retire during the vesting period,  related
compensation  expense is recognized  over the period from the grant date to the
retirement eligibility date on a graded vesting basis. EIC-162 is effective for
interim and annual  periods  ending on or after  December 31, 2006.  We adopted
EIC-162  on a  retroactive  basis in the fourth  quarter of 2006.  For the year
ended December 31, 2006, the impact of adopting EIC-162  decreased  general and
administrative  expense by $9 million,  increased  provision  for future income
taxes by $3 million,  increased net income $6 million,  and increased basic and
diluted  earnings  per share by  $0.02/share.  For the year ended  December 31,
2005,  the impact of adopting  EIC-162  increased  general  and  administrative
expense by $17  million,  decreased  provision  for future  income  taxes by $5
million,  reduced  net income by $12  million,  and  reduced  basic and diluted
earnings per share by  $0.05/share.  The impact on the year ended  December 31,
2004 was immaterial.

     In  December  2006,  the AcSB  issued  two new  Sections  in  relation  to
financial instruments:  Section 3862, FINANCIAL INSTRUMENTS - DISCLOSURES,  and
Section 3863, FINANCIAL  INSTRUMENTS - PRESENTATION.  Both sections will become
effective for annual and interim periods  beginning on or after October 1, 2007
and will require increased disclosure of financial instruments.

     In December  2006,  the AcSB issued  Section  1535,  CAPITAL  DISCLOSURES,
requiring   disclosure  of  information  about  an  entity's  capital  and  the
objectives,  policies,  and  processes  for managing  capital.  The standard is
effective for annual periods beginning on or after October 1, 2007.

US PRONOUNCEMENTS

     On January 1, 2006, we adopted FASB Statement 123  (revised),  SHARE-BASED
PAYMENT  (Statement  123(R))  using  the   modified-prospective   approach  and
graded-vesting  amortization.  Under Statement  123(R),  our tandem options and
stock  appreciation  rights are considered  liability-based  stock compensation
plans.  Under the  modified-prospective  approach,  no amounts are  restated in
prior  periods.  Upon  adoption of Statement  123(R),  we recorded a cumulative
effect of a change in  accounting  principle  of $2  million.  This  amount was
recorded in general and  administrative  expenses  during the first  quarter of
2006 in our US GAAP Consolidated Statement of Income.

     Prior  to  the  adoption  of  Statement   123(R),  we  accounted  for  our
liability-based stock compensation plans in accordance with FASB Interpretation
28, ACCOUNTING FOR STOCK APPRECIATION RIGHTS AND OTHER VARIABLE STOCK OPTION OR
AWARD PLANS (the intrinsic-value method). Accordingly, obligations were accrued
on a  graded-vesting  basis and represented  the difference  between the market
value of our common  shares and the exercise  price of  underlying  options and
rights.   Under  Statement  123(R),   obligations  for  liability-based   stock
compensation  plans are measured at their fair value,  and are  re-measured  at
fair value in each subsequent reporting period.

     Consistent with Statement 123(R), we account for any stock options that do
not include a cash feature  (equity-based stock compensation  plans), using the
fair-value method.



                                      66
<PAGE>

     The impact of adopting  Statement 123(R) on our results for the year ended
December 31, 2006 is as follows:

<TABLE>
<CAPTION>
                                                                                PRIOR TO            AFTER
                                                                             ADOPTION OF      ADOPTION OF        INCREASE/
(Cdn$ millions, except per share amounts)                                      FAS 123(R)       FAS 123(R)      (DECREASE)
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                         <C>              <C>               <C>
Income from Continuing Operations before Income Taxes--US GAAP                     1,306            1,264             (42)
--------------------------------------------------------------------------------------------------------------------------
Net Income--US GAAP                                                                  608              579             (29)
--------------------------------------------------------------------------------------------------------------------------
Basic Earnings per Common Share--US GAAP ($/share)                                  2.32             2.21           (0.11)
--------------------------------------------------------------------------------------------------------------------------
Diluted Earnings per Common Share--US GAAP ($/share)                                2.26             2.15           (0.11)
==========================================================================================================================
</TABLE>

     We  recognize  stock-based   compensation  expense  for  our  retired  and
retirement-eligible  employees  over an  accelerated  graded  vesting period in
accordance  with the  provisions  of Statement  123(R) for  stock-based  awards
granted to employees  after December 31, 2005. For  stock-based  awards granted
prior to the adoption of Statement 123(R), stock-based compensation expense for
our retired  and  retirement-eligible  employees  is  recognized  over a graded
vesting period. If we applied the accelerated  vesting  provisions of Statement
123(R) to  stock-based  awards  granted to our retired and  retirement-eligible
employees prior to the adoption of Statement 123(R), there would be no material
change  to our  stock-based  compensation  expense  for the three  years  ended
December 31, 2006.

     In February  2006, the FASB issued  Statement 155,  ACCOUNTING FOR CERTAIN
HYBRID  INSTRUMENTS,  which amends  Statement  133,  ACCOUNTING  FOR DERIVATIVE
INSTRUMENTS AND HEDGING ACTIVITIES, and Statement 140, ACCOUNTING FOR TRANSFERS
AND SERVICING OF FINANCIAL ASSETS AND EXTINGUISHMENTS OF LIABILITIES. Statement
155 permits fair value  re-measurement  of hybrid  financial  instruments  that
contain an embedded  derivative that otherwise would require  bifurcation  from
its  host  contract  in  accordance  with  Statement  133.  Statement  155 also
clarifies and amends  certain  other  provisions of Statement 133 and Statement
140.  This  statement is effective for all  financial  instruments  acquired or
issued in fiscal years beginning after September 15, 2006. We do not expect the
adoption  of this  statement  will have a  material  impact on our  results  of
operations or financial position.

     In July 2006,  FASB issued FIN 48  ACCOUNTING  FOR  UNCERTAINTY  IN INCOME
TAXES with respect to FAS 109 ACCOUNTING FOR INCOME TAXES regarding  accounting
for and  disclosure  of  uncertain  tax  positions.  FIN 48 seeks to reduce the
diversity in practice  associated  with certain  aspects of the recognition and
measurement  related to accounting for income taxes and is effective for fiscal
years beginning after December 15, 2006.  Adoption of this standard is expected
to increase our future income tax  liabilities  by no more than $30 million and
decrease our retained earnings by a corresponding amount.

     In September  2006,  FASB issued  Statement 157, FAIR VALUE  MEASUREMENTS.
Statement 157 defines fair value,  establishes  a framework for measuring  fair
value under US generally accepted accounting principles and expands disclosures
about fair value  measurements.  This  statement is effective  for fiscal years
beginning  after  November  15,  2007.  We do not expect the  adoption  of this
statement will have a material impact on our results of operations or financial
position.

     In September 2006, FASB issued  Statement 158,  EMPLOYERS'  ACCOUNTING FOR
DEFINED BENEFIT PENSION AND OTHER POSTRETIREMENT PLANS.  Statement 158 requires
an employer to recognize the  over-funded or  under-funded  status of a defined
benefit  post-retirement plan on the balance sheet as an asset or liability and
to  recognize  changes in funded  status  through  comprehensive  income.  This
statement  also requires  measurement  of the funded status of a plan as of the
balance sheet date. The  recognition  and  disclosures  under Statement 158 are
required  for  fiscal  years  ending  after  December  15,  2006  while the new
measurement  date is effective for fiscal years ending after December 15, 2008.
We adopted the  recognition  and disclosure  provisions at December 31, 2006 in
our US GAAP  presentation.  We do not  expect  the  adoption  of the  change in
measurement date in 2008 to have a material impact on our results of operations
or financial position.


                                      67
<PAGE>




                   F I N A N C I A L    S T A T E M E N T S







              STRONG COMMODITY PRICES AND RECORD RESULTS FROM OUR

              MARKETING GROUP RESULTED IN SOLID FINANCIAL RESULTS

          FOR 2006. CASH FLOW FROM OPERATING ACTIVITIES WAS A RECORD

               $2.4 BILLION, WHILE NET INCOME WAS $601 MILLION.










                                      68
<PAGE>

              ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


                                                                           PAGE

REPORT OF MANAGEMENT .......................................................85

REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS .....................86

CONSOLIDATED FINANCIAL STATEMENTS
     Consolidated Statement of Income ......................................87
     Consolidated Balance Sheet ............................................88
     Consolidated Statement of Cash Flows ..................................89
     Consolidated Statement of Shareholders' Equity ........................90
     Notes To Consolidated Financial Statements ............................91

SUPPLEMENTARY DATA (UNAUDITED)
     Quarterly Financial Data In Accordance with Canadian and US GAAP .....130
     Oil And Gas Producing Activities and Syncrude Operations .............131







                                      69
<PAGE>

REPORT OF MANAGEMENT

     February 9, 2007

     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 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  registered  Chartered  Accountants  and also
considers  their  independence,  reviews  their fees and (subject to applicable
securities  laws),  pre-approves  their  retention for any permitted  non-audit
services and their fee for such services. The internal auditors and independent
registered  Chartered  Accountants  have full and unlimited access to the Audit
Committee, with or without the presence of management.



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

                                      70
<PAGE>


REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

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

     We have audited the accompanying consolidated balance sheets of Nexen Inc.
and  subsidiaries  (the  "Company")  as of  December  31, 2006 and 2005 and the
consolidated statements of income, cash flows and shareholders' equity for each
of the three years in the period  ended  December  31,  2006.  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 the
audit to obtain reasonable assurance about 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, such consolidated  financial statements present fairly, in
all material respects, the financial position of Nexen Inc. and subsidiaries as
of December  31, 2006 and 2005 and the  results of their  operations  and their
cash flows for each of the three years in the period ended December 31, 2006 in
conformity 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 of December 31, 2006,
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 9, 2007  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 9, 2007                   Independent Registered Chartered Accountants


COMMENTS BY  INDEPENDENT  REGISTERED  CHARTERED  ACCOUNTANTS  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 when there are changes
in accounting  principles that have a material effect on the  comparability  of
the Company's financial  statements,  such as the change 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 the Company dated
February 9, 2007, 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 9, 2007                   Independent Registered Chartered Accountants


                                      71
<PAGE>

                                   NEXEN INC.
                        CONSOLIDATED STATEMENT OF INCOME
                  FOR THE THREE YEARS ENDED DECEMBER 31, 2006

<TABLE>
<CAPTION>
Cdn$ millions, except per share amounts                                        2006          2005         2004
                                                                                        Note 1(u)    Note 1(u)
----------------------------------------------------------------------------------------------------------------
<S>                                                                         <C>         <C>          <C>
Revenues and Other Income
----------------------------------------------------------------------------------------------------------------
  Net Sales                                                                   3,936         3,932        2,944
----------------------------------------------------------------------------------------------------------------
  Marketing and Other (Note 17)                                               1,450           702          713
----------------------------------------------------------------------------------------------------------------
  Gain on Dilution of Interest in Chemicals Business (Note 2)                     -           193            -
----------------------------------------------------------------------------------------------------------------
                                                                              5,386         4,827        3,657
----------------------------------------------------------------------------------------------------------------
Expenses
----------------------------------------------------------------------------------------------------------------
  Operating                                                                     955           893          722
----------------------------------------------------------------------------------------------------------------
  Depreciation, Depletion, Amortization and Impairment (Note 6)               1,124         1,052          674
----------------------------------------------------------------------------------------------------------------
  Transportation and Other                                                    1,041           796          549
----------------------------------------------------------------------------------------------------------------
  General and Administrative                                                    555           809          299
----------------------------------------------------------------------------------------------------------------
  Exploration                                                                   362           250          243
----------------------------------------------------------------------------------------------------------------
  Interest (Note 8)                                                              53            97          143
----------------------------------------------------------------------------------------------------------------
                                                                              4,090         3,897        2,630
----------------------------------------------------------------------------------------------------------------

Income from Continuing Operations before Income Taxes                         1,296           930        1,027
----------------------------------------------------------------------------------------------------------------

Provision for Income Taxes (Note 18)
----------------------------------------------------------------------------------------------------------------
  Current                                                                       368           339          248
----------------------------------------------------------------------------------------------------------------
  Future                                                                        315          (105)          69
----------------------------------------------------------------------------------------------------------------
                                                                                683           234          317
----------------------------------------------------------------------------------------------------------------

Net Income from Continuing Operations before Non-Controlling Interests          613           696          710
----------------------------------------------------------------------------------------------------------------
  Net Income Attributable to Non-Controlling Interests                           12             8            -
----------------------------------------------------------------------------------------------------------------

Net Income from Continuing Operations                                           601           688          710
----------------------------------------------------------------------------------------------------------------
  Net Income from Discontinued Operations (Note 14)                               -           452           83
----------------------------------------------------------------------------------------------------------------

NET INCOME                                                                      601         1,140          793
----------------------------------------------------------------------------------------------------------------

EARNINGS PER COMMON SHARE FROM CONTINUING OPERATIONS ($/share)
----------------------------------------------------------------------------------------------------------------
  Basic (Note 13)                                                              2.29          2.64         2.76
----------------------------------------------------------------------------------------------------------------
  Diluted (Note 13)                                                            2.24          2.58         2.72
----------------------------------------------------------------------------------------------------------------

EARNINGS PER COMMON SHARE ($/share)
----------------------------------------------------------------------------------------------------------------
  Basic (Note 13)                                                              2.29          4.38         3.08
----------------------------------------------------------------------------------------------------------------
  Diluted (Note 13)                                                            2.24          4.28         3.04
================================================================================================================
</TABLE>

SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

                                      72
<PAGE>

                                   NEXEN INC.
                           CONSOLIDATED BALANCE SHEET
                           DECEMBER 31, 2006 AND 2005

Cdn$ millions, except share amounts                            2006        2005
--------------------------------------------------------------------------------
                                                                      Note 1(u)
--------------------------------------------------------------------------------
ASSETS
--------------------------------------------------------------------------------
  Current Assets
--------------------------------------------------------------------------------
      Cash and Cash Equivalents                                 101          48
--------------------------------------------------------------------------------
      Restricted Cash and Margin Deposits                       197          70
--------------------------------------------------------------------------------
      Accounts Receivable (Note 4)                            2,951       3,151
--------------------------------------------------------------------------------
      Inventories and Supplies (Note 5)                         786         504
--------------------------------------------------------------------------------
      Future Income Tax Assets (Note 18)                        479           -
--------------------------------------------------------------------------------
      Other                                                      67          51
--------------------------------------------------------------------------------
       Total Current Assets                                   4,581       3,824
--------------------------------------------------------------------------------

   Property, Plant and Equipment (Note 6)                    11,739       9,594
--------------------------------------------------------------------------------
   Goodwill                                                     377         364
--------------------------------------------------------------------------------
   Future Income Tax Assets (Note 18)                           141         410
--------------------------------------------------------------------------------
   Deferred Charges and Other Assets (Note 10)                  318         398
--------------------------------------------------------------------------------

TOTAL ASSETS                                                 17,156      14,590
--------------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
--------------------------------------------------------------------------------
  Current Liabilities
--------------------------------------------------------------------------------
      Short-Term Borrowings (Note 8)                            158           -
--------------------------------------------------------------------------------
      Accounts Payable and Accrued Liabilities                3,879       3,727
--------------------------------------------------------------------------------
      Accrued Interest Payable                                   55          55
--------------------------------------------------------------------------------
      Dividends Payable                                          13          13
--------------------------------------------------------------------------------
       Total Current Liabilities                              4,105       3,795
--------------------------------------------------------------------------------

  Long-Term Debt (Note 8)                                     4,673       3,687
--------------------------------------------------------------------------------
  Future Income Tax Liabilities (Note 18)                     2,468       1,955
--------------------------------------------------------------------------------
  Asset Retirement Obligations (Note 9)                         683         590
--------------------------------------------------------------------------------
  Deferred Credits and Other Liabilities (Note 11)              516         479
--------------------------------------------------------------------------------
  Non-Controlling Interests (Note 2)                             75          88
--------------------------------------------------------------------------------
  Shareholders' Equity (Note 12)
--------------------------------------------------------------------------------
      Common Shares, no par value
--------------------------------------------------------------------------------
       Authorized:    Unlimited
--------------------------------------------------------------------------------
       Outstanding: 2006--262,513,206 shares                     821         732
        2005--261,140,571 shares
--------------------------------------------------------------------------------
      Contributed Surplus                                         4           2
--------------------------------------------------------------------------------
      Retained Earnings                                       3,972       3,423
--------------------------------------------------------------------------------
      Cumulative Foreign Currency Translation Adjustment       (161)       (161)
--------------------------------------------------------------------------------
       Total Shareholders' Equity                             4,636       3,996
--------------------------------------------------------------------------------

  Commitments, Contingencies and Guarantees (Notes 15 and 18)

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                   17,156      14,590
================================================================================


SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.


Approved on behalf of the Board:


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

                                      73
<PAGE>

                                   NEXEN INC.
                      CONSOLIDATED STATEMENT OF CASH FLOWS
                  FOR THE THREE YEARS ENDED DECEMBER 31, 2006

<TABLE>
<CAPTION>
Cdn$ millions                                                                            2006           2005            2004
------------------------------------------------------------------------------------------------------------------------------
                                                                                                   Note 1(u)       Note 1(u)
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                  <C>           <C>             <C>
OPERATING ACTIVITIES
------------------------------------------------------------------------------------------------------------------------------
  Net Income from Continuing Operations                                                   601            688             710
------------------------------------------------------------------------------------------------------------------------------
  Net Income from Discontinued Operations                                                   -            452              83
------------------------------------------------------------------------------------------------------------------------------
  Charges and Credits to Income not Involving Cash (Note 19)                            1,629          1,081             906
------------------------------------------------------------------------------------------------------------------------------
  Exploration Expense                                                                     362            250             243
------------------------------------------------------------------------------------------------------------------------------
  Changes in Non-Cash Working Capital (Note 19)                                          (177)          (195)           (122)
------------------------------------------------------------------------------------------------------------------------------
  Other                                                                                   (41)          (133)           (214)
------------------------------------------------------------------------------------------------------------------------------
                                                                                        2,374          2,143           1,606
------------------------------------------------------------------------------------------------------------------------------

FINANCING ACTIVITIES
------------------------------------------------------------------------------------------------------------------------------
  Proceeds from Long-Term Notes and Debentures (Note 8)                                     -          1,253           1,779
------------------------------------------------------------------------------------------------------------------------------
  Repayment of Long-Term Notes and Debentures (Note 8)                                    (93)        (1,818)           (300)
------------------------------------------------------------------------------------------------------------------------------
  Proceeds from (Repayment of) Term Credit Facilities, Net                              1,044            (66)             83
------------------------------------------------------------------------------------------------------------------------------
  Proceeds from (Repayment of) Short-Term Borrowings, Net                                 160            (99)            101
------------------------------------------------------------------------------------------------------------------------------
  Redemption of Preferred Securities                                                        -              -            (289)
------------------------------------------------------------------------------------------------------------------------------
  Dividends on Common Shares                                                              (52)           (52)            (52)
------------------------------------------------------------------------------------------------------------------------------
  Issue of Common Shares and Exercise of Options for Shares                                48             58             124
------------------------------------------------------------------------------------------------------------------------------
  Net Proceeds from Canexus Initial Public Offering (Note 2)                                -            301               -
------------------------------------------------------------------------------------------------------------------------------
  Proceeds from Term Credit Facilities of Canexus, Net (Notes 2 and 8)                      2            176               -
------------------------------------------------------------------------------------------------------------------------------
  Other                                                                                   (28)           (27)            (20)
------------------------------------------------------------------------------------------------------------------------------
                                                                                         1,081          (274)          1,426

INVESTING ACTIVITIES
------------------------------------------------------------------------------------------------------------------------------
  Business Acquisitions, Net of Cash Acquired (Note 3)                                    (78)             -          (2,583)
------------------------------------------------------------------------------------------------------------------------------
  Capital Expenditures
------------------------------------------------------------------------------------------------------------------------------
      Exploration and Development                                                      (3,198)        (2,564)         (1,582)
------------------------------------------------------------------------------------------------------------------------------
      Proved Property Acquisitions                                                        (13)           (20)             (4)
------------------------------------------------------------------------------------------------------------------------------
      Chemicals, Corporate and Other                                                     (119)           (54)            (95)
------------------------------------------------------------------------------------------------------------------------------
  Proceeds on Disposition of Assets                                                        27            911              34
------------------------------------------------------------------------------------------------------------------------------
  Changes in Non-Cash Working Capital (Note 19)                                           134            (54)            244
------------------------------------------------------------------------------------------------------------------------------
  Changes in Restricted Cash and Margin Deposits                                         (127)           (70)              -
------------------------------------------------------------------------------------------------------------------------------
  Other                                                                                   (14)           (13)            (27)
------------------------------------------------------------------------------------------------------------------------------
                                                                                       (3,388)        (1,864)         (4,013)
------------------------------------------------------------------------------------------------------------------------------

Effect of Exchange Rate Changes on Cash and Cash Equivalents                              (14)           (30)            (33)
------------------------------------------------------------------------------------------------------------------------------

Increase (Decrease) in Cash and Cash Equivalents                                           53            (25)         (1,014)
------------------------------------------------------------------------------------------------------------------------------

Cash and Cash Equivalents--Beginning of Year                                                48             73           1,087
------------------------------------------------------------------------------------------------------------------------------

CASH AND CASH EQUIVALENTS--END OF YEAR                                                     101             48              73
==============================================================================================================================
</TABLE>

SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.


                                      74
<PAGE>

                                   NEXEN INC.
                 CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
                  FOR THE THREE YEARS ENDED DECEMBER 31, 2006

<TABLE>
<CAPTION>
Cdn$ millions                                                                        2006         2005             2004
-------------------------------------------------------------------------------------------------------------------------
                                                                                             Note 1(u)        Note 1(u)
-------------------------------------------------------------------------------------------------------------------------
<S>                                                                                <C>       <C>              <C>
COMMON SHARES (Note 12)
-------------------------------------------------------------------------------------------------------------------------
  Balance at Beginning of Year                                                        732          637              513
-------------------------------------------------------------------------------------------------------------------------
      Issue of Common Shares                                                           32           29               31
-------------------------------------------------------------------------------------------------------------------------
      Proceeds from Options Exercised for Shares                                       16           29               93
-------------------------------------------------------------------------------------------------------------------------
      Accrued Liability Relating to Options Exercised                                  41           37                -
-------------------------------------------------------------------------------------------------------------------------
  BALANCE AT END OF YEAR                                                              821          732              637
-------------------------------------------------------------------------------------------------------------------------

CONTRIBUTED SURPLUS
-------------------------------------------------------------------------------------------------------------------------
  Balance at Beginning of Year                                                          2            -                1
-------------------------------------------------------------------------------------------------------------------------
      Stock-Based Compensation Expense (Note 12)                                        2            2                2
-------------------------------------------------------------------------------------------------------------------------
      Modification of Stock Option Plan to Tandem Option Plan (Note 12)                 -            -               (3)
-------------------------------------------------------------------------------------------------------------------------
  BALANCE AT END OF YEAR                                                                4            2                -
-------------------------------------------------------------------------------------------------------------------------

RETAINED EARNINGS
-------------------------------------------------------------------------------------------------------------------------
  Balance at Beginning of Year                                                      3,423        2,335            1,594
-------------------------------------------------------------------------------------------------------------------------
      Net Income                                                                      601        1,140              793
-------------------------------------------------------------------------------------------------------------------------
      Dividends on Common Shares                                                      (52)         (52)             (52)
-------------------------------------------------------------------------------------------------------------------------
  BALANCE AT END OF YEAR                                                            3,972        3,423            2,335
-------------------------------------------------------------------------------------------------------------------------

CUMULATIVE FOREIGN CURRENCY TRANSLATION ADJUSTMENT
-------------------------------------------------------------------------------------------------------------------------
  Balance at Beginning of Year                                                       (161)        (105)             (33)
-------------------------------------------------------------------------------------------------------------------------
      Translation Adjustment, Net of Income Taxes                                       -          (56)             (72)
-------------------------------------------------------------------------------------------------------------------------
  BALANCE AT END OF YEAR                                                             (161)        (161)            (105)
=========================================================================================================================
</TABLE>

SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.


                                      75
<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,  derivative contract assets and liabilities 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 intercompany accounts and transactions have been eliminated.  On August 18,
2005, we sold our chemicals  operations to Canexus LP, but retained  control of
these  operations  through our 61.4% interest in Canexus LP. 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

                                       76
<PAGE>

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.

     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.

                                       77
<PAGE>

(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.

(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. Sales of
our  proprietary  production  are recorded at monthly  market-based  prices and
intercompany  profits and losses  between  segments are  eliminated.  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.

                                       78
<PAGE>

(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.
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 incurred.

(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

                                     79
<PAGE>

payable if we anticipate  settling the instruments within a year of the balance
sheet date.  If we anticipate  settling the  instruments  beyond 12 months,  we
record them as deferred  charges and other assets or deferred credits and other
liabilities.

(o)      EMPLOYEE FUTURE BENEFITS

     The cost of pension  benefits  earned by employees in our defined  benefit
pension plans is  actuarially  determined  using the  projected-benefit  method
prorated on service and our best estimate of the plans' investment performance,
salary  escalations and retirement  ages of employees.  To calculate the plans'
expected returns, assets are measured at fair value. Past service costs arising
from plan amendments, and net actuarial gains and losses that exceed 10% of the
greater of the accrued  benefit  obligation  and the fair value of plan assets,
are expensed in equal amounts over the expected average  remaining service life
of the  employee  group.  We measure the plan  assets and the  accrued  benefit
obligation on October 31 each year.

(p)      STOCK-BASED COMPENSATION

     In 2003, we adopted the fair-value  method of accounting for stock options
granted to  employees  and  directors.  We  recorded  stock-based  compensation
expense in the Consolidated  Statement of Income as general and  administrative
expenses  for  all  options  granted  on or  after  January  1,  2003,  with  a
corresponding increase to contributed surplus. Compensation expense for options
granted  was  based on  estimated  fair  values  at the  time of  grant  and we
recognized the expense over the vesting period of the option.

     In May 2004,  we modified our stock option plan to a tandem option plan by
including a cash feature. The tandem options give the holders a right to either
purchase  common shares at the exercise price or to receive cash payments equal
to the excess of the market value of the common shares over the exercise price.
As a result of the modification,  we record  obligations for the tandem options
using 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 AND MARGIN DEPOSITS

     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 the related  assets are 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.

                                      80
<PAGE>

(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. 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.

(u)      CHANGES IN ACCOUNTING PRINCIPLES

STOCK-BASED  COMPENSATION  FOR EMPLOYEES  ELIGIBLE TO RETIRE BEFORE THE VESTING
DATE

      In  the  fourth  quarter  of  2006,  we  retroactively  adopted  EIC-162,
STOCK-BASED  COMPENSATION  FOR EMPLOYEES  ELIGIBLE TO RETIRE BEFORE THE VESTING
DATE (EIC-162).  EIC-162  provides that if an employee is eligible to retire on
the  grant  date  of a  stock-based  award,  related  compensation  expense  is
recognized in full at that date as there is no ongoing  service  requirement to
earn the award. In addition,  if an employee  becomes eligible to retire during
the vesting period,  related compensation expense is recognized over the period
from the grant  date to the  retirement  eligibility  date on a graded  vesting
basis.  Prior to the adoption of EIC-162,  we did not  consider the  retirement
dates of our employees in the  determination  of our  stock-based  compensation
expense. EIC-162 is effective for interim and annual periods ending on or after
December  31, 2006 and is to be adopted on a  retroactive  basis.  For the year
ended December 31, 2006, the impact of adopting EIC-162  decreased  general and
administrative  expense by $9 million,  increased  provision  for future income
taxes by $3 million,  increased net income by $6 million,  and increased  basic
and diluted earnings per share by $0.02/share.  For the year ended December 31,
2005,  the impact of adopting  EIC-162  increased  general  and  administrative
expense by $17  million,  decreased  provision  for future  income  taxes by $5
million,  reduced  net income by $12  million,  and  reduced  basic and diluted
earnings per share by  $0.05/share.  The impact on the year ended  December 31,
2004 was immaterial.


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 currently
has nominated two  representatives  to the 10-member board of Canexus  Limited.
Since we have retained effective control of our chemicals business, the

                                      81
<PAGE>

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.

     During the year $28 million  (2005 - $10  million) of  distributions  were
paid to non-Nexen ownership interests.


3.       BUSINESS ACQUISITIONS

     In 2006, we completed minor business acquisitions related to our marketing
group for $78 million, net of cash acquired.  These acquisitions were accounted
for using the  purchase  method  of  accounting.  The  assets  and  liabilities
purchased  were  primarily  working  capital  and we  recorded  goodwill of $12
million as a result of the acquisitions.

     On December 1, 2004, we acquired 100% of the issued and outstanding  share
capital of EnCana (UK) Limited (EnCana UK) from EnCana Corporation (EnCana) for
cash consideration of US$2.1 billion, subject to certain adjustments. EnCana UK
held all of EnCana's  offshore oil and gas assets in the North Sea. We acquired
EnCana UK to  establish  a  strategic  presence  in the North Sea by  acquiring
operatorship of the Buzzard field development and operatorship of the producing
Scott and Telford fields.  The acquisition  also gave us access to interests in
several satellite discoveries and more than 700,000 net undeveloped exploration
acres.  In addition,  we acquired the management and technical teams that found
and are developing the Buzzard discovery. Goodwill paid was attributable to the
established  North  Sea  presence  acquired  and  the  knowledge  and  business
relationships acquired through the management team and employees of EnCana UK.

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

Purchase Price, Net of Cash Acquired:
-------------------------------------------------------------------------------
  Cash Paid                                                             2,561
-------------------------------------------------------------------------------
  Transaction Costs                                                        22
-------------------------------------------------------------------------------
TOTAL PURCHASE PRICE                                                    2,583
===============================================================================

Purchase Price Allocated as follows:
-------------------------------------------------------------------------------
  Accounts Receivable                                                     310
-------------------------------------------------------------------------------
  Inventories and Supplies                                                 11
-------------------------------------------------------------------------------
  Other Current Assets                                                      2
-------------------------------------------------------------------------------
  Property, Plant and Equipment                                         3,395
-------------------------------------------------------------------------------
  Future Income Tax Assets                                                239
-------------------------------------------------------------------------------
  Goodwill (1)                                                            334
-------------------------------------------------------------------------------
  Deferred Charges and Other Assets                                        12
-------------------------------------------------------------------------------
  Accounts Payable and Accrued Liabilities                               (289)
-------------------------------------------------------------------------------
  Asset Retirement Obligations                                           (134)
-------------------------------------------------------------------------------
  Future Income Tax Liabilities                                        (1,284)
-------------------------------------------------------------------------------
  Deferred Credits and Other Liabilities                                  (13)
-------------------------------------------------------------------------------
TOTAL PURCHASE PRICE ALLOCATED                                          2,583
===============================================================================
NOTE:
(1)  THE AMOUNT OF GOODWILL DEDUCTIBLE FOR TAX PURPOSES IS NIL.

     The unaudited  pro forma results for the year ended  December 31, 2004 are
shown below as if the  acquisition  had occurred on January 1, 2004.  Pro forma
results are not necessarily indicative of actual results or future performance.

                                                                          2004
-------------------------------------------------------------------------------
Revenues                                                                 4,258
-------------------------------------------------------------------------------
Net Income                                                                 841
-------------------------------------------------------------------------------
Earnings Per Common Share--Basic ($/share)                                 3.27
-------------------------------------------------------------------------------
Earnings Per Common Share--Diluted ($/share)                               3.23
===============================================================================

                                      82
<PAGE>

<TABLE>
<CAPTION>
4.       ACCOUNTS RECEIVABLE

                                                                                             2006        2005
---------------------------------------------------------------------------------------------------------------
<S>                                                                                         <C>         <C>
Trade
---------------------------------------------------------------------------------------------------------------
  Marketing                                                                                 2,226       2,400
---------------------------------------------------------------------------------------------------------------
  Oil and Gas                                                                                 600         614
---------------------------------------------------------------------------------------------------------------
  Chemicals and Other                                                                          58          48
---------------------------------------------------------------------------------------------------------------
                                                                                            2,884       3,062
---------------------------------------------------------------------------------------------------------------
Non-Trade                                                                                      80          96
---------------------------------------------------------------------------------------------------------------
                                                                                            2,964       3,158
---------------------------------------------------------------------------------------------------------------
Allowance for Doubtful Receivables                                                            (13)         (7)
===============================================================================================================

TOTAL ACCOUNTS RECEIVABLE                                                                   2,951       3,151
-------------------------------------------------------------------------------- ------------------------------


5.       INVENTORIES AND SUPPLIES

                                                                                             2006        2005
---------------------------------------------------------------------------------------------------------------
Finished Products
---------------------------------------------------------------------------------------------------------------
  Marketing                                                                                   609         320
---------------------------------------------------------------------------------------------------------------
  Oil and Gas                                                                                  21          11
---------------------------------------------------------------------------------------------------------------
  Chemicals and Other                                                                          14          15
---------------------------------------------------------------------------------------------------------------
                                                                                              644         346
---------------------------------------------------------------------------------------------------------------
Work in Process                                                                                 5           6
---------------------------------------------------------------------------------------------------------------
Field Supplies                                                                                137         152
---------------------------------------------------------------------------------------------------------------

TOTAL INVENTORIES AND SUPPLIES                                                                786         504
===============================================================================================================

<CAPTION>
6.       PROPERTY, PLANT AND EQUIPMENT

                                                2006                                      2005
                                             ACCUMULATED     NET BOOK                  ACCUMULATED     NET BOOK
                                    COST            DD&A        VALUE       COST              DD&A        VALUE
-----------------------------------------------------------------------------------------------------------------
<S>                               <C>              <C>         <C>        <C>                <C>          <C>
Oil and Gas
-----------------------------------------------------------------------------------------------------------------
  Yemen                              779             599          180        833               546          287
-----------------------------------------------------------------------------------------------------------------
  Yemen--Carried Interest           1,625           1,529           96      1,410             1,295          115
-----------------------------------------------------------------------------------------------------------------
  Canada                           5,216           1,448        3,768      3,631             1,311        2,320
-----------------------------------------------------------------------------------------------------------------
  United States                    2,889           1,445        1,444      2,437             1,159        1,278
-----------------------------------------------------------------------------------------------------------------
  United Kingdom                   4,710             432        4,278      4,013               216        3,797
-----------------------------------------------------------------------------------------------------------------
  Other Countries                    249              78          171        249               119          130
-----------------------------------------------------------------------------------------------------------------
                                  15,468           5,531        9,937     12,573             4,646        7,927
-----------------------------------------------------------------------------------------------------------------
Marketing                            226              47          179        177                72          105
-----------------------------------------------------------------------------------------------------------------
Syncrude                           1,304             179        1,125      1,240               171        1,069
-----------------------------------------------------------------------------------------------------------------
Chemicals                            854             494          360        827               456          371
-----------------------------------------------------------------------------------------------------------------
Corporate and Other                  286             148          138        245               123          122
-----------------------------------------------------------------------------------------------------------------

TOTAL PP&E                        18,138           6,399       11,739     15,062             5,468        9,594
=================================================================================================================
</TABLE>

     The above table includes capitalized costs of $6,708 million (2005--$5,211
million)  relating to unproved  properties and projects under  construction  or
development.  These costs are not being  depreciated,  depleted  or  amortized.
These costs include $2,399 million  related to our Buzzard project in the North
Sea that began operations in January 2007.

                                      83
<PAGE>

     Our Syncrude operations are considered a mining operation for US reporting
purposes.  PP&E at December  31, 2006 and 2005  includes  mineral  rights of $6
million.

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

     Our  2006  DD&A  expense  includes  $93  million  of  impairment  expense,
primarily  related  to two  natural  gas  producing  properties  in the Gulf of
Mexico.  The impairment  was caused by  unsuccessful  development  programs and
negative  year-end  reserve  revisions.  The  carrying  values of the  impaired
properties have been reduced to their  estimated fair value.  In addition,  our
2006 DD&A  expense  includes $15 million  (2005 - $58 million)  relating to the
write down of a portion of our purchase price allocation to unproved properties
purchased in the North Sea as a result of unsuccessful exploration activities.

RESEARCH AND DEVELOPMENT

     We incurred $53 million  (2005--$54  million) in connection  with research
and  development   activities   related  to  developing  new  technologies  for
increasing oil recoveries.  Research costs of $50 million  (2005--$44  million)
were included in other  expense on the  Consolidated  Statement of Income.  The
development costs have been deferred and are included in PP&E.

<TABLE>
<CAPTION>
                                                                                   2006         2005
------------------------------------------------------------------------------------------------------
<S>                                                                                  <C>          <C>
Development Costs Deferred, Beginning of Year                                        25           15
------------------------------------------------------------------------------------------------------
  Deferred in the Year                                                                3           10
------------------------------------------------------------------------------------------------------
  Amortized in the Year                                                               -            -
------------------------------------------------------------------------------------------------------
DEVELOPMENT COSTS DEFERRED, END OF YEAR                                              28           25
======================================================================================================
</TABLE>

SUSPENDED WELL COSTS

     The  following  table shows the changes in  capitalized  exploratory  well
costs during the years ended  December 31, 2006 and 2005,  and does not include
amounts that were initially  capitalized and subsequently  expensed in the same
period.

<TABLE>
<CAPTION>
                                                                                   2006         2005
------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>          <C>
Balance at Beginning of Year                                                        252          116
------------------------------------------------------------------------------------------------------
  Additions to Capitalized Exploratory Well Costs Pending the
    Determination of Proved Reserves                                                129          174
------------------------------------------------------------------------------------------------------
  Capitalized Exploratory Well Costs Charged to Expense                             (70)         (27)
------------------------------------------------------------------------------------------------------
  Transfers to Wells, Facilities and Equipment Based on Determination
    of Proved Reserves                                                              (84)          (3)
------------------------------------------------------------------------------------------------------
  Effects of Foreign Exchange                                                        (1)          (8)
------------------------------------------------------------------------------------------------------
BALANCE AT END OF YEAR                                                              226          252
======================================================================================================
</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>
                                                                                  2006         2005
-----------------------------------------------------------------------------------------------------
<S>                                                                                <C>          <C>
  Capitalized for a Period of One Year or Less                                     179          165
-----------------------------------------------------------------------------------------------------
  Capitalized for a Period of Greater than One Year                                 47           87
-----------------------------------------------------------------------------------------------------
BALANCE AT END OF YEAR                                                             226          252
=====================================================================================================

Number of Projects that have Exploratory Well Costs Capitalized for a Period
   Greater than One Year                                                             4            3
=====================================================================================================
</TABLE>

     As at  December  31,  2006,  we have  exploratory  costs  that  have  been
capitalized  for more than one year relating to our interest in an  exploratory
block, offshore Nigeria ($14 million),  our interest in an exploratory block in
the Gulf of Mexico ($16 million), our coalbed methane exploratory activities in
Canada ($10  million) and an  exploratory  block in the North Sea ($7 million).
Our

                                      84
<PAGE>

capitalized  costs in Nigeria  include  capital  spending  for four  successful
wells.  Development  plans are currently  being prepared for this area. We have
capitalized costs related to successful wells drilled in the Gulf of Mexico and
the North Sea. In Canada, we have capitalized exploratory costs relating to our
coalbed methane projects. We are assessing all of these wells and projects, and
we are working with our partners to prepare development plans.


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>
                                                      2006                                           2005
                                    CARRYING                      UNRECOGNIZED       CARRYING                   UNRECOGNIZED
                                       VALUE       FAIR VALUE      GAIN (LOSS)          VALUE    FAIR VALUE      GAIN (LOSS)
------------------------------------------------------------------------------------------------------------------------------
<S>                                   <C>              <C>                 <C>         <C>           <C>                <C>
COMMODITY PRICE RISK
------------------------------------------------------------------------------------------------------------------------------
  Non-Trading Activities
------------------------------------------------------------------------------------------------------------------------------
      Crude Oil Put Options               19               19                -              4             4                -
------------------------------------------------------------------------------------------------------------------------------
      Fixed-Price Natural Gas
       Contracts                         (96)             (96)               -           (175)         (175)               -
------------------------------------------------------------------------------------------------------------------------------
      Natural Gas Swaps                   (8)              (8)               -             29            29                -
------------------------------------------------------------------------------------------------------------------------------

  Trading Activities
------------------------------------------------------------------------------------------------------------------------------
      Crude Oil and Natural Gas          372              372                -            161           161                -
------------------------------------------------------------------------------------------------------------------------------
      Future Sale of Gas
       Inventory                           -               25               25              -           (35)             (35)
------------------------------------------------------------------------------------------------------------------------------

FOREIGN CURRENCY RISK
------------------------------------------------------------------------------------------------------------------------------
  Non-Trading Activities                   -                -                -             14            14                -
------------------------------------------------------------------------------------------------------------------------------
  Trading Activities                     (12)             (12)               -              8             8                -
------------------------------------------------------------------------------------------------------------------------------
TOTAL DERIVATIVES                        275              300               25             41             6              (35)
==============================================================================================================================

FINANCIAL ASSETS AND LIABILITIES
  Long-Term Debt                      (4,673)          (4,728)             (55)        (3,687)       (3,863)            (176)
==============================================================================================================================
</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,
margin deposits,  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

     In 2006, we purchased WTI crude oil put options to provide a base level of
price protection  without  limiting our upside to higher prices.  These options
establish  an annual  average WTI floor price of  US$50/bbl  in 2007 on 105,000
bbls/d  at a cost of $26  million.  In 2004,  we  purchased  WTI  crude oil put
options to manage the  commodity  price risk  exposure  of a portion of our oil
production in 2006 and 2005.  These options  established  an annual average WTI
floor  price  of  US$38/bbl  in 2006  and  US$43/bbl  in 2005 at a cost of $144
million.  The 2006 and 2005 WTI  crude oil put  options  were not used and have
expired. The 2007

                                      85
<PAGE>

WTI crude oil put options are stated at fair value and are included in deferred
charges and other  assets as they settle  beyond 12 months  from  December  31,
2006.  Any  change in fair  value is  included  in  marketing  and other on the
Consolidated Statement of Income.

<TABLE>
<CAPTION>
                                            NOTIONAL                          AVERAGE
                                             VOLUMES         TERM         PRICE (WTI)          FAIR VALUE
                                            (bbls/d)                        (US$/bbl)     (Cdn$ millions)
-----------------------------------------------------------------------------------------------------------
<S>                                         <C>             <C>           <C>              <C>
WTI Crude Oil Put Options                    105,000         2007                  50                  19
===========================================================================================================
</TABLE>

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
included in our  Consolidated  Balance Sheet at fair value.  Any change in fair
value is included  in  marketing  and other in the  Consolidated  Statement  of
Income.

<TABLE>
<CAPTION>
                                          NOTIONAL
                                           VOLUMES           TERM               PRICE          FAIR VALUE
                                            (Gj/d)                             ($/Gj)     (Cdn$ millions)
-----------------------------------------------------------------------------------------------------------
<S>                                       <C>           <C>                 <C>            <C>
Fixed-Price Natural Gas Contracts           15,514           2007                2.46                 (22)
-----------------------------------------------------------------------------------------------------------
                                            15,514      2008-2010           2.56-2.77                 (74)
-----------------------------------------------------------------------------------------------------------
                                                                                                      (96)
===========================================================================================================
</TABLE>

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

<TABLE>
<CAPTION>
                                          NOTIONAL
                                           VOLUMES           TERM               PRICE          FAIR VALUE
                                            (Gj/d)                             ($/Gj)     (Cdn$ millions)
-----------------------------------------------------------------------------------------------------------
<S>                                       <C>           <C>                  <C>           <C>
Natural Gas Swaps                           15,514           2007                7.60                  (6)
-----------------------------------------------------------------------------------------------------------
                                            15,514      2008-2010                7.60                  (2)
-----------------------------------------------------------------------------------------------------------
                                                                                                       (8)
===========================================================================================================
</TABLE>

TRADING ACTIVITIES

Crude oil and natural gas

     We enter into physical  purchase and sales  contracts as well as financial
commodity  contracts to enhance our price realizations and lock-in our margins.
The physical and  financial  commodity  contracts  (derivative  contracts)  are
stated at market value. The $372 million fair value of the commodity  contracts
at December  31, 2006 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

                                      86
<PAGE>

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 at December 31, 2006 are:

<TABLE>
<CAPTION>
                                             HEDGED                          AVERAGE        UNRECOGNIZED
                                            VOLUMES        MONTH               PRICE                GAIN
                                             (mmbtu)                        (US$/mcf)     (Cdn$ millions)
----------------------------------------------------------------------------------------------------------
<S>                                       <C>            <C>                <C>           <C>
NYMEX Natural Gas Futures                 5,580,000      January 2007          10.73                  25
==========================================================================================================
</TABLE>

     In late 2006, we  de-designated  certain  futures  contracts that had been
designated  as cash flow hedges of future  sales of our natural gas in storage.
These contracts were  de-designated  since it became  uncertain that the future
sales of natural gas would occur  within the  designated  time frame.  As it is
reasonably  possible  that the future sales may take place as designated at the
inception  of the  hedging  relationship,  gains of $65  million on the futures
contracts  have been  deferred and will be  recognized in net income in 2007 in
the originally designated time frame.

(c)      FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT

NON-TRADING ACTIVITIES

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.  Canexus
periodically  purchases  US-dollar  call  options to reduce  this  exposure  to
fluctuations in the Canadian-US  dollar exchange rate. Under outstanding option
contracts at December  31, 2006,  Canexus LP had the right to sell US$5 million
monthly and purchase  Canadian  dollars at an exchange  rate of US$0.85 for the
period  August  16,  2006 to  January  10,  2007 and has the right to sell US$5
million  monthly and purchase  Canadian  dollars at an exchange rate of US$0.87
for the  period  January  10,  2007 to July 11,  2007.  The fair value of these
contracts  at December  31, 2006 was  immaterial  and changes in fair value are
included in marketing and other in the Consolidated Statement of Income.

Foreign currency swap

     We  occasionally  use derivative  instruments to effectively  convert cash
flows from  Canadian to US dollars and vice versa.  During the year,  we held a
foreign currency  derivative  instrument that obligated us and the counterparty
to exchange  principal and interest  amounts.  In November  2006, we paid US$37
million and received  Cdn$50  million to settle the foreign  currency swap (see
Note 8). The change in fair value was  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)                                                   2006     2005
--------------------------------------------------------------------------------
Net Investment in Self-Sustaining Foreign Operations            4,534    4,357
--------------------------------------------------------------------------------
US-Dollar Debt                                                  3,761    2,700
================================================================================

     We also have small  exposures to  currencies  other than the US dollar.  A
portion of our United Kingdom operating  expenses,  capital spending and future
asset retirement expenditures is denominated in British pounds and Euros. We do
not have any material exposure to highly inflationary foreign currencies.

                                      87
<PAGE>

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.  However,  we pay for many of
our purchases in Canadian  dollars.  We enter into US-dollar  forward contracts
and swaps to manage  this  exposure.  Losses of $12  million  on our  US-dollar
forward  contracts  and  swaps  at  December  31,  2006  are  included  in  the
Consolidated  Balance  Sheet,  and any  change  in fair  value is  included  in
marketing and other in the Consolidated Statement of Income.

(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:

                                                                2006       2005
--------------------------------------------------------------------------------
Accounts Receivable                                              731        382
--------------------------------------------------------------------------------
Deferred Charges and Other Assets 1 (Note 10)                    153        232
--------------------------------------------------------------------------------
TOTAL DERIVATIVE CONTRACT ASSETS                                 884        614
===============================================================================

--------------------------------------------------------------------------------
Accounts Payable and Accrued Liabilities                         325        321
--------------------------------------------------------------------------------
Deferred Credits and Other Liabilities 1 (Note 11)               199        124
--------------------------------------------------------------------------------
TOTAL DERIVATIVE CONTRACT LIABILITIES                            524        445
--------------------------------------------------------------------------------

TOTAL DERIVATIVE CONTRACT NET ASSETS 2                           360        169
===============================================================================
NOTES:
(1)  THESE  DERIVATIVE  INSTRUMENTS  SETTLE BEYOND 12 MONTHS AND ARE CONSIDERED
     NON-CURRENT.
(2)  COMPRISED  OF $372  MILLION  (2005--$161  MILLION)  RELATED  TO  COMMODITY
     CONTRACTS  AND  LOSSES  OF  $12  MILLION  (2005--$8  MILLION)  RELATED  TO
     US-DOLLAR FORWARD CONTRACTS AND SWAPS.

     As a  physical  energy  marketer,  we match  the  contract  months  of our
derivative  instruments  with the  contract  months of our  physical  sales and
purchases.  As a result, our disclosure with respect to derivative  instruments
includes amounts with no ongoing commodity price or foreign currency risk as at
December 31, 2006.  Excluding such amounts,  derivative  contracts  included in
accounts receivable at December 31, 2006 amounted to $460 million (December 31,
2005 - $382 million) and derivative  contracts included in accounts payable and
accrued  liabilities  amounted  to  $312  million  (December  31,  2005  - $290
million).

     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 have margin deposits of $197 million (December
31, 2005--nil), which have been included in restricted cash and margin deposits
on our Consolidated Balance Sheet at December 31, 2006.

(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, 2006,  fixed-rate
borrowings  comprised 73%  (2005--95%)  of our  long-term  debt at an effective
average rate of 6.3% (2005--6.3%). During the year, we periodically drew on our
floating-rate,  unsecured, committed term credit facilities. We had no interest
rate swaps outstanding in 2006 or 2005.

(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,

                                      88
<PAGE>

including credit  concentrations,  is routinely reported to our Risk Management
Committee.  We also use  standard  agreements  that  allow for the  netting  of
exposures associated with a single counterparty.  We believe this minimizes our
overall credit risk.


8.       LONG-TERM DEBT AND SHORT-TERM BORROWINGS

                                                               2006       2005
-------------------------------------------------------------------------------
Canexus LP Term Credit Facilities (US$149 million) (a)          174        171
-------------------------------------------------------------------------------
Term Credit Facilities (US$925 million) (b)                   1,078          -
-------------------------------------------------------------------------------
Debentures, due 2006 (c)                                          -         93
-------------------------------------------------------------------------------
Medium-Term Notes, due 2007 (d)                                 150        150
-------------------------------------------------------------------------------
Medium-Term Notes, due 2008 (e)                                 125        125
-------------------------------------------------------------------------------
Notes, due 2013 (US$500 million) (f)                            583        583
-------------------------------------------------------------------------------
Notes, due 2015 (US$250 million) (g)                            291        292
-------------------------------------------------------------------------------
Notes, due 2028 (US$200 million) (h)                            233        233
-------------------------------------------------------------------------------
Notes, due 2032 (US$500 million) (i)                            583        583
-------------------------------------------------------------------------------
Notes, due 2035 (US$790 million) (j)                            920        921
-------------------------------------------------------------------------------
Subordinated Debentures, due 2043 (US$460 million) (k)          536        536
-------------------------------------------------------------------------------
TOTAL                                                         4,673      3,687
==============================================================================

(a)      CANEXUS LP TERM CREDIT FACILITIES

     Canexus LP has $350 million of committed,  secured term credit facilities,
which are  available  until 2010.  At December 31, 2006,  $174 million  (US$149
million)  was drawn on these  facilities  (December  31,  2005--$171  million).
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 floating rates. 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 2006, the  weighted-average
interest rate on the Canexus LP term credit facilities was 5.9% (2005--4.8%).

(b)      TERM CREDIT FACILITIES

     We have  committed,  unsecured,  term credit  facilities  of $3.6 billion,
which are available  until 2011. At December 31, 2006,  $1,078 million  (US$925
million) was drawn on these facilities (December 31, 2005--nil). Borrowings are
available as Canadian bankers'  acceptances,  LIBOR-based loans, Canadian prime
rate  loans,  US-dollar  base rate  loans or  British  pound  call-rate  loans.
Interest   is  payable   monthly  at   floating   rates.   During   2006,   the
weighted-average  interest  rate was 5.7%  (2005--4.4%).  At December 31, 2006,
$294 million of these facilities were utilized to support  outstanding  letters
of credit (December 31, 2005--$250 million).

(c)      DEBENTURES, DUE 2006

     During  November  1996,  we  issued  $100  million  of  unsecured  10 year
redeemable  debentures.  Interest was payable semi-annually at a rate of 6.85%.
In December 1996,  $50 million of this  obligation  was  effectively  converted
through  a foreign  currency  swap with a  Canadian  chartered  bank to a US$37
million liability bearing interest at 6.75% for the term of the debentures.  In
November  2006,  we repaid  the  outstanding  debentures  of $100  million  and
realized a gain of $7 million on the foreign currency swap.

(d)      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

                                      89
<PAGE>

term of the notes plus 0.125%.  Amounts due July 2007 have not been included in
current  liabilities as we expect to refinance this amount with our term credit
facilities.

(e)      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%.

(f)      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%.

(g)      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%.

(h)      NOTES, DUE 2028

     During April 1998, we issued US$200 million of notes.  Interest is payable
semi-annually at a rate of 7.4%, and the principal is to be repaid in May 2028.
We may redeem part or all of the notes any time. The  redemption  price will be
the greater of par and an amount that  provides the same yield as a US Treasury
security  having a term to maturity  equal to the  remaining  term of the notes
plus 0.25%.

(i)      NOTES, DUE 2032

     During March 2002, we issued US$500 million of notes.  Interest is payable
semi-annually  at a rate of 7.875%,  and the principal is to be repaid in March
2032. We may redeem part or all of the notes at any time. The redemption  price
will be the greater of par and an amount that  provides  the same yield as a US
Treasury  security having a term to maturity equal to the remaining term of the
notes plus 0.375%.

(j)      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%.

(k)      SUBORDINATED DEBENTURES, DUE 2043

     During  November 2003, we issued US$460 million of unsecured  subordinated
debentures. Interest is payable quarterly 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.

(l)      LONG-TERM DEBT REPAYMENTS

-------------------------------------------------------------------------------
2007                                                                       150
-------------------------------------------------------------------------------
2008                                                                       125
-------------------------------------------------------------------------------
2009                                                                         -
-------------------------------------------------------------------------------
2010                                                                       174
-------------------------------------------------------------------------------
2011                                                                     1,078
-------------------------------------------------------------------------------
Thereafter                                                               3,146
-------------------------------------------------------------------------------
TOTAL DEBT REPAYMENTS                                                    4,673
===============================================================================

                                      90
<PAGE>

(m)      DEBT COVENANTS

     Some of our debt  instruments  contain  covenants  with respect to certain
financial  ratios and our ability to grant  security.  At December 31, 2006, we
were in compliance with all covenants.

(n)      SHORT-TERM BORROWINGS

     Nexen has uncommitted,  unsecured credit facilities of approximately  $632
million.  At December 31, 2006, $158 million  (US$136  million) was drawn under
these facilities  (December 31, 2005--nil).  We have also utilized $252 million
of these  facilities to support  outstanding  letters of credit at December 31,
2006 (2005--$468 million).  Interest is payable at floating rates. During 2006,
the  weighted-average  interest  rate on our  short-term  borrowings  was  5.5%
(2005--3.6%).

(o)      INTEREST EXPENSE

                                                     2006       2005      2004
-------------------------------------------------------------------------------
Long-Term Debt                                        275        260       182
-------------------------------------------------------------------------------
Other                                                  19         15        12
-------------------------------------------------------------------------------
Total                                                 294        275       194
-------------------------------------------------------------------------------
  Less: Capitalized                                  (241)      (178)      (51)
-------------------------------------------------------------------------------
TOTAL INTEREST EXPENSE                                 53         97       143
==============================================================================

     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:

                                                               2006      2005
-------------------------------------------------------------------------------
Balance at Beginning of Year                                    611       468
-------------------------------------------------------------------------------
  Obligations Assumed with Development Activities                75        72
-------------------------------------------------------------------------------
  Obligations Discharged with Disposed Properties                (1)      (37)
-------------------------------------------------------------------------------
  Expenditures Made on Asset Retirements                        (44)      (34)
-------------------------------------------------------------------------------
  Accretion                                                      37        26
-------------------------------------------------------------------------------
  Revisions to Estimates                                        (10)      138
-------------------------------------------------------------------------------
  Effects of Foreign Exchange                                    36       (22)
-------------------------------------------------------------------------------
BALANCE AT END OF YEAR 1, 2                                     704       611
==============================================================================

NOTES:

(1)  OBLIGATIONS DUE WITHIN 12 MONTHS OF $21 MILLION  (2005--$21  MILLION) HAVE
     BEEN INCLUDED IN ACCOUNTS PAYABLE AND ACCRUED LIABILITIES.

(2)  OBLIGATIONS  RELATING TO OUR OIL AND GAS ACTIVITIES AMOUNT TO $658 MILLION
     (2005--$564  MILLION) AND OBLIGATIONS  RELATING TO OUR CHEMICALS  BUSINESS
     AMOUNT TO $46 MILLION (2005--$47 MILLION).

                                      91
<PAGE>

     Our total estimated  undiscounted  asset retirement  obligations amount to
$1,770  million.  We have  discounted  the  total  estimated  asset  retirement
obligations using a weighted-average,  credit-adjusted  risk-free rate of 5.7%.
Approximately $97 million included in our asset retirement  obligations will be
settled over the next five years. The remaining  obligations settle beyond five
years and will be funded by future cash flows from our operations.

     We own  interests  in  assets  for  which  the  fair  value  of the  asset
retirement  obligations  cannot be  reasonably  determined  because  the assets
currently have an  indeterminate  life and we cannot determine when remediation
activities  would take place.  These assets  include our interest in Syncrude's
upgrader  and  sulphur  pile.  The  estimated  future  recoverable  reserves at
Syncrude are  significant  and given the long life of this asset, we are unable
to determine when asset retirement  activities  would take place.  Furthermore,
the Syncrude plant can continue to run  indefinitely  with ongoing  maintenance
activities. The retirement obligations for these assets will be recorded in the
first year in which the lives of the assets are determinable.

10.      DEFERRED CHARGES AND OTHER ASSETS

                                                              2006       2005
-------------------------------------------------------------------------------
Long-Term Marketing Derivative Contracts (Note 7d)             153        232
-------------------------------------------------------------------------------
Deferred Financing Costs                                        59         63
-------------------------------------------------------------------------------
Asset Retirement Remediation Fund                               13         14
-------------------------------------------------------------------------------
Crude Oil Put Options (Note 7a)                                 19          4
-------------------------------------------------------------------------------
Other                                                           74         85
-------------------------------------------------------------------------------
TOTAL                                                          318        398
==============================================================================

11.      DEFERRED CREDITS AND OTHER LIABILITIES

                                                              2006       2005
-------------------------------------------------------------------------------
Fixed-Price Natural Gas Contracts (Note 7b)                     74        128
-------------------------------------------------------------------------------
Long-Term Marketing Derivative Contracts (Note 7d)             199        124
-------------------------------------------------------------------------------
Deferred Transportation Revenue                                 89         87
-------------------------------------------------------------------------------
Stock-Based Compensation Liability                               6         53
-------------------------------------------------------------------------------
Defined Benefit Pension Obligations (Note 16)                   48         39
-------------------------------------------------------------------------------
Capital Lease Obligations                                       48          9
-------------------------------------------------------------------------------
Other                                                           52         39
-------------------------------------------------------------------------------
TOTAL                                                          516        479
==============================================================================

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.

                                      92
<PAGE>

(b)      ISSUED COMMON SHARES AND DIVIDENDS

(thousands of shares)                              2006        2005        2004
--------------------------------------------------------------------------------
Beginning of Year                               261,141     258,399     251,212
--------------------------------------------------------------------------------
Issue of Common Shares for Cash
--------------------------------------------------------------------------------
  Exercise of Tandem Options                        846       1,823       5,902
--------------------------------------------------------------------------------
  Dividend Reinvestment Plan                        276         605         895
--------------------------------------------------------------------------------
  Employee Flow-through Shares                      250         314         390
--------------------------------------------------------------------------------
END OF YEAR                                     262,513     261,141     258,399
===============================================================================

DIVIDENDS DECLARED PER COMMON SHARE ($/share)      0.20        0.20        0.20
--------------------------------------------------------------------------------

CASH CONSIDERATION (Cdn$ millions)
--------------------------------------------------------------------------------
  Exercise of Tandem Options                         16          29          93
--------------------------------------------------------------------------------
  Dividend Reinvestment Plan                         16          20          21
--------------------------------------------------------------------------------
  Employee Flow-through Shares                       16           9          10
--------------------------------------------------------------------------------
                                                     48          58         124
===============================================================================

     At December 31, 2006,  there were 498,831  common  shares  (2005--774,915;
2004--1,379,874) reserved for issuance under the Dividend Reinvestment Plan.

(c)      TANDEM 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 2006 of $2 million (2005 --$2 million;  2004--$0.1  million),  which
was included in general and administrative expense. In 2005, US tax regulations
were  modified  and 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.

                                      93
<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>
                                                    2006                       2005                        2004
                                                          WEIGHTED                   WEIGHTED                     WEIGHTED
                                                           AVERAGE                    AVERAGE                      AVERAGE
                                                          EXERCISE                 EXERCISE                       EXERCISE
                                            OPTIONS          PRICE       OPTIONS        PRICE      OPTIONS           PRICE
                                         (thousands)    ($/option)   (thousands)   ($/option)   (thousands)     ($/option)
----------------------------------------------------------------------------------------------------------------------------
<S>                                      <C>             <C>         <C>            <C>         <C>             <C>
Balance at Beginning of Year                 15,315             28        16,276           20       18,406              17
----------------------------------------------------------------------------------------------------------------------------
  Granted                                     2,400             63         3,392           55        4,224              25
----------------------------------------------------------------------------------------------------------------------------
  Exercised for Stock                          (846)            18        (1,823)          16       (5,902)             15
----------------------------------------------------------------------------------------------------------------------------
  Surrendered for Cash                       (1,522)            18        (2,089)          17         (289)             17
----------------------------------------------------------------------------------------------------------------------------
  Forfeited                                    (105)            38          (441)          22         (163)             17
----------------------------------------------------------------------------------------------------------------------------
BALANCE AT END OF YEAR                       15,242             35        15,315           28       16,276              20
============================================================================================================================


----------------------------------------------------------------------------------------------------------------------------
Options Exercisable at End of Year            9,345             24         8,131           19        8,455              17
----------------------------------------------------------------------------------------------------------------------------
Common Shares Reserved
   for Issuance Under the
   Tandem Option Plan                        16,235                       17,290                    19,172
============================================================================================================================
</TABLE>

     The range of exercise  prices of options  outstanding  and  exercisable at
December 31, 2006 is as follows:

<TABLE>
<CAPTION>
                                                                     OUTSTANDING OPTIONS             EXERCISABLE OPTIONS
                                                                            WEIGHTED    WEIGHTED                 WEIGHTED
                                                                             AVERAGE    AVERAGE                   AVERAGE
                                                               NUMBER OF   EXERCISE        YEARS    NUMBER OF   EXERCISE
                                                                 OPTIONS       PRICE   TO EXPIRY      OPTIONS       PRICE
                                                             (thousands)   ($/option)    (years)   (thousands)  ($/option)
---------------------------------------------------------------------------------------------------------------------------
<S>                                                          <C>           <C>         <C>         <C>          <C>
$5.00 to $9.99                                                       178           9           2          178           9
---------------------------------------------------------------------------------------------------------------------------
$10.00 to $14.99                                                     788          14           2          788          14
---------------------------------------------------------------------------------------------------------------------------
$15.00 to $19.99                                                   3,032          18           3        3,032          18
---------------------------------------------------------------------------------------------------------------------------
$20.00 to $24.99                                                   2,792          23           2        2,462          22
---------------------------------------------------------------------------------------------------------------------------
$25.00 to $29.99                                                   2,768          25           3        1,778          25
---------------------------------------------------------------------------------------------------------------------------
$30.00 to $34.99                                                      14          31           3            2          31
---------------------------------------------------------------------------------------------------------------------------
$35.00 to $39.99                                                       -           -           -            -           -
---------------------------------------------------------------------------------------------------------------------------
$40.00 to $44.99                                                       2          40           4            1          40
---------------------------------------------------------------------------------------------------------------------------
$45.00 to $49.99                                                      13          47           4            5          47
---------------------------------------------------------------------------------------------------------------------------
$50.00 to $54.99                                                   3,254          55           4        1,099          54
---------------------------------------------------------------------------------------------------------------------------
$55.00 to $59.99                                                      12          57           4            -           -
---------------------------------------------------------------------------------------------------------------------------
$60.00 to $64.99                                                   2,383          63           5            -           -
---------------------------------------------------------------------------------------------------------------------------
$65.00 to $69.99                                                       3          66           4            -           -
---------------------------------------------------------------------------------------------------------------------------
$70.00 to $74.99                                                       3          71           5            -           -
---------------------------------------------------------------------------------------------------------------------------
TOTAL OPTIONS                                                     15,242                                9,345
===========================================================================================================================
</TABLE>

                                      94
<PAGE>

(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 tandem  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>
                                                             2006                      2005                     2004
                                                                  WEIGHTED                  WEIGHTED                 WEIGHTED
                                                                   AVERAGE                   AVERAGE                  AVERAGE
                                                                 EXERCISE                  EXERCISE                 EXERCISE
                                                         STARS       PRICE         STARS       PRICE        STARS       PRICE
                                                    (thousands)   ($/StAR)   (thousands)    ($/StAR)   (thousands)   ($/StAR)
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                  <C>          <C>         <C>           <C>        <C>          <C>
Balance at Beginning of Year                             5,964          30         6,436          22        4,809          18
-------------------------------------------------------------------------------------------------------------------------------
  Granted                                                2,254          63         1,443          55        2,609          25
-------------------------------------------------------------------------------------------------------------------------------
  Exercised for Cash                                    (1,082)         21        (1,455)         19         (867)         16
-------------------------------------------------------------------------------------------------------------------------------
  Forfeited                                               (191)         38          (460)         23         (115)         18
-------------------------------------------------------------------------------------------------------------------------------
BALANCE AT END OF YEAR                                   6,945          42         5,964          30        6,436          22
===============================================================================================================================

StARs Exercisable at End
   of Year                                               3,076          27         2,426          21        2,021          17
-------------------------------------------------------------------------------------------------------------------------------
</TABLE>

     The range of  exercise  prices of StARs  outstanding  and  exercisable  at
December 31, 2006 is as follows:

<TABLE>
<CAPTION>
                                                         OUTSTANDING STARS                           EXERCISABLE STARS
                                                                WEIGHTED
                                                                 AVERAGE          WEIGHTED                           WEIGHTED
                                                                EXERCISE     AVERAGE YEARS                            AVERAGE
                                          NUMBER OF STARS          PRICE         TO EXPIRY   NUMBER OF STARS   EXERCISE PRICE
                                              (thousands)       ($/StAR)           (years)       (thousands)         ($/StAR)
-------------------------------------------------------------------------------------------------------------------------------
<S>                                       <C>                <C>              <C>             <C>              <C>
$15.00 to $19.99                                      513             17                 1               513               17
-------------------------------------------------------------------------------------------------------------------------------
$20.00 to $24.99                                      991             22                 2               985               22
-------------------------------------------------------------------------------------------------------------------------------
$25.00 to $29.99                                    1,859             25                 3             1,138               25
-------------------------------------------------------------------------------------------------------------------------------
$30.00 to $34.99                                       18             33                 3                 6               33
-------------------------------------------------------------------------------------------------------------------------------
$35.00 to $39.99                                        9             37                 4                 1               37
-------------------------------------------------------------------------------------------------------------------------------
$40.00 to $44.99                                        8             41                 4                 3               41
-------------------------------------------------------------------------------------------------------------------------------
$45.00 to $49.99                                       38             48                 4                12               48
-------------------------------------------------------------------------------------------------------------------------------
$50.00 to $54.99                                    1,256             55                 4               418               55
-------------------------------------------------------------------------------------------------------------------------------
$55.00 to $59.99                                       29             57                 4                 -                -
-------------------------------------------------------------------------------------------------------------------------------
$60.00 to $64.99                                    2,213             63                 5                 -                -
-------------------------------------------------------------------------------------------------------------------------------
$65.00 to $69.99                                       11             66                 4                 -                -
-------------------------------------------------------------------------------------------------------------------------------
TOTAL STARS                                         6,945                                              3,076
===============================================================================================================================
</TABLE>

13.      EARNINGS PER COMMON SHARE

     We calculate  basic earnings per common share from  continuing  operations
using net income from  continuing  operations  divided by the  weighted-average
number of common shares  outstanding.  We calculate  basic  earnings per common
share  using net  income  and the  weighted-average  number  of  common  shares
outstanding.  We calculate  diluted  earnings per common share from  continuing
operations  and diluted  earnings per common share in the same manner as basic,
except we use the weighted-average  number of diluted common shares outstanding
in the denominator.

                                      95
<PAGE>

<TABLE>
<CAPTION>
(millions of shares)                                                     2006       2005      2004
----------------------------------------------------------------------------------------------------
<S>                                                                     <C>        <C>       <C>
Weighted-Average Number of Common Shares Outstanding                    262.1      260.4     257.3
----------------------------------------------------------------------------------------------------
Shares Issuable Pursuant to Stock Options                                13.9       13.4      13.1
----------------------------------------------------------------------------------------------------
Shares to be Purchased from Proceeds of Stock Options                    (7.1)      (7.4)     (9.8)
----------------------------------------------------------------------------------------------------
WEIGHTED-AVERAGE NUMBER OF DILUTED COMMON SHARES OUTSTANDING            268.9      266.4     260.6
====================================================================================================
</TABLE>

     In  calculating  the  weighted-average  number of  diluted  common  shares
outstanding  for the year ended December 31, 2006, we excluded  211,283 options
(2005--280,708;  2004--348,200),  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.

     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
                                                               CANADA     CANADA   AUSTRALIA  TOTAL
-----------------------------------------------------------------------------------------------------
<S>                                                            <C>        <C>      <C>        <C>
Revenues and Other Income
-----------------------------------------------------------------------------------------------------
  Net Sales                                                       154        232         75     307
-----------------------------------------------------------------------------------------------------
  Marketing and Other                                               -          1          -       1
-----------------------------------------------------------------------------------------------------
  Gain on Disposition of Assets                                   225          -          -       -
-----------------------------------------------------------------------------------------------------
                                                                  379        233         75     308
-----------------------------------------------------------------------------------------------------
Expenses
-----------------------------------------------------------------------------------------------------
  Operating                                                        27         40         53      93
-----------------------------------------------------------------------------------------------------
  Depreciation, Depletion, Amortization and Impairment             28         70          9      79
-----------------------------------------------------------------------------------------------------
  Exploration Expense                                               1          3          -       3
-----------------------------------------------------------------------------------------------------
Income before Income Taxes                                        323        120         13     133
-----------------------------------------------------------------------------------------------------
  Provision for Future Income Taxes                              (129)        50          -      50
-----------------------------------------------------------------------------------------------------
NET INCOME FROM DISCONTINUED OPERATIONS                           452         70         13      83
=====================================================================================================

EARNINGS PER COMMON SHARE ($/share)
-----------------------------------------------------------------------------------------------------
  Basic (Note 13)                                                1.74       0.27       0.05    0.32
-----------------------------------------------------------------------------------------------------
  Diluted (Note 13)                                              1.70       0.27       0.05    0.32
=====================================================================================================
</TABLE>

     There were no assets and liabilities related to discontinued operations as
at December 31, 2006.

                                      96
<PAGE>

<TABLE>
<CAPTION>
15.      COMMITMENTS, CONTINGENCIES AND GUARANTEES

                                                  2007   2008   2009    2010   2011   THEREAFTER
--------------------------------------------------------------------------------------------------
<S>                                                <C>    <C>    <C>     <C>    <C>          <C>
Operating Leases                                    44    109    127     123    117          232
--------------------------------------------------------------------------------------------------
Transportation and Storage Commitments             424    165     97      70     53          118
--------------------------------------------------------------------------------------------------
                                                   468    274    224     193    170          350
==================================================================================================
</TABLE>

     In  June  2003,  a  subsidiary   of   Occidental   Petroleum   Corporation
(Occidental)  initiated an arbitration against us at the International Court of
Arbitration of the  International  Chamber of Commerce (ICC Court) regarding an
Area of Mutual Interest  agreement  relating to certain portions of Block 51 in
the Republic of Yemen.  In April 2006, the ICC Court concluded that we breached
this agreement and as a result, Occidental was entitled to monetary damages. In
late  2006,  we agreed to settle the  arbitration  with  Occidental  for US$135
million.  No further  amounts are expected to be payable under the  settlement.
This  amount was accrued and  included  in other  expenses in our  Consolidated
Statement of Income during 2006.

     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 2006,  total  rental  expense was $49 million  (2005--$47  million;
2004--$45 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.  We believe that payments,  if
any,  related to such matters,  would not have a material adverse effect on our
liquidity, financial condition or results of operations.

16.      PENSION AND OTHER POST-RETIREMENT BENEFITS

     Nexen and Canexus have 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  proportionate  share of this plan. Under the 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 in 2005,  the portion of the projected
benefit  obligation and fair value of plan assets relating to Canexus employees
was transferred to Canexus from Nexen.

                                      97
<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>
                                                                             2006                            2005
                                                                NEXEN     CANEXUS    SYNCRUDE    NEXEN    CANEXUS    SYNCRUDE
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                               <C>          <C>        <C>      <C>         <C>        <C>
CHANGE IN PROJECTED BENEFIT OBLIGATION (PBO)
-------------------------------------------------------------------------------------------------------------------------------
  Beginning of Year                                               223          49         109      217          -          91
-------------------------------------------------------------------------------------------------------------------------------
      Service Cost                                                 16           3           5       15          1           4
-------------------------------------------------------------------------------------------------------------------------------
      Interest Cost                                                12           3           5       12          1           5
-------------------------------------------------------------------------------------------------------------------------------
      Plan Participants' Contributions                              3           1           1        3          -           1
-------------------------------------------------------------------------------------------------------------------------------
      Actuarial Loss/(Gain)                                         9           2           -       33         (2)         11
-------------------------------------------------------------------------------------------------------------------------------
      Benefits Paid                                               (11)          -          (4)      (8)         -          (3)
-------------------------------------------------------------------------------------------------------------------------------
      Transfer to Canexus                                           -           -           -      (49)        49           -
-------------------------------------------------------------------------------------------------------------------------------
  END OF YEAR 1                                                   252          58         116      223         49         109
===============================================================================================================================

CHANGE IN FAIR VALUE OF PLAN ASSETS
-------------------------------------------------------------------------------------------------------------------------------
  Beginning of Year                                               146          40          58      171          -          50
-------------------------------------------------------------------------------------------------------------------------------
      Actual Return on Plan Assets                                 23           6           8       18          -           6
-------------------------------------------------------------------------------------------------------------------------------
      Employer's Contribution                                      24           3           5        2          -           4
-------------------------------------------------------------------------------------------------------------------------------
      Plan Participants' Contributions                              3           1           1        3          -           1
-------------------------------------------------------------------------------------------------------------------------------
      Benefits Paid                                               (11)          -          (3)      (8)         -          (3)
-------------------------------------------------------------------------------------------------------------------------------
      Transfer to Canexus                                           -           -           -      (40)        40           -
-------------------------------------------------------------------------------------------------------------------------------
  END OF YEAR                                                     185          50          69      146         40          58
===============================================================================================================================

RECONCILIATION OF FUNDED STATUS
-------------------------------------------------------------------------------------------------------------------------------
  Funded Status 2                                                 (67)         (8)        (47)     (77)        (9)        (51)
-------------------------------------------------------------------------------------------------------------------------------
  Unamortized Transitional Obligation                               -           -           -        1          -           -
-------------------------------------------------------------------------------------------------------------------------------
  Unamortized Prior Service Costs                                   3           -           -        3          -           -
  Unamortized Net Actuarial Loss                                   39           7          32       44          9          38
-------------------------------------------------------------------------------------------------------------------------------
PENSION LIABILITY                                                 (25)         (1)        (15)     (29)         -         (13)
===============================================================================================================================

PENSION LIABILITY RECOGNIZED
-------------------------------------------------------------------------------------------------------------------------------
  Deferred Charges and Other Assets                                10           -           -        -          -           -
-------------------------------------------------------------------------------------------------------------------------------
  Accounts Payable and Accrued Liabilities                         (1)          -          (2)      (1)         -          (2)
-------------------------------------------------------------------------------------------------------------------------------
  Other Deferred Credits and Liabilities (Note 11)                (34)         (1)        (13)     (28)         -         (11)
-------------------------------------------------------------------------------------------------------------------------------
PENSION LIABILITY                                                 (25)         (1)        (15)     (29)         -         (13)
===============================================================================================================================

<CAPTION>
Assumptions (%)
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>        <C>     <C>     <C>        <C>        <C>
  Accrued Benefit Obligation at December 31
-------------------------------------------------------------------------------------------------------------------------------
      Discount Rate                                                       5.00       5.00    5.00    5.25       5.25       5.00
-------------------------------------------------------------------------------------------------------------------------------
      Long-Term Rate of Employee Compensation Increase                    4.00       4.00    4.00    4.00       4.00       4.00
-------------------------------------------------------------------------------------------------------------------------------
  Benefit Cost for Year Ended December 31 3
-------------------------------------------------------------------------------------------------------------------------------
      Discount Rate                                                       5.25       5.25    5.00    5.00       5.00       5.00
-------------------------------------------------------------------------------------------------------------------------------
      Long-Term Rate of Employee Compensation Increase                    4.00       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       6.50       8.50
===============================================================================================================================
</TABLE>
NOTES:
(1)  THE ACCUMULATED  BENEFIT  OBLIGATIONS  (THE PROJECTED  BENEFIT  OBLIGATION
     EXCLUDING  FUTURE  SALARY  INCREASES)  OF THE NEXEN AND CANEXUS PLANS WERE
     $180  MILLION  AND  $44  MILLION  AT  DECEMBER   31,  2006,   RESPECTIVELY
     (2005--$161 MILLION AND $36 MILLION,  RESPECTIVELY).  NEXEN'S SUPPLEMENTAL
     PENSION PLAN'S ACCUMULATED  BENEFIT OBLIGATION WAS $35 MILLION AT DECEMBER
     31, 2006 (2005--$29 MILLION). NEXEN'S SHARE OF SYNCRUDE'S EMPLOYEE PENSION
     PLAN'S ACCUMULATED BENEFIT OBLIGATION WAS $89 MILLION AT DECEMBER 31, 2006
     (2005--$82 MILLION).
(2)  INCLUDES UNFUNDED OBLIGATIONS FOR SUPPLEMENTAL BENEFITS TO THE EXTENT THAT
     THE BENEFIT IS LIMITED BY STATUTORY GUIDELINES.  AT DECEMBER 31, 2006, THE
     PBO FOR NEXEN'S SUPPLEMENTAL  BENEFITS WAS $53 MILLION (2005--$43 MILLION)
     AND $1 MILLION FOR CANEXUS (2005--$1 MILLION).
(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, 2006.  SYNCRUDE'S  MEASUREMENT DATE WAS
     DECEMBER 31, 2006.
(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.

                                      98
<PAGE>

<TABLE>
<CAPTION>
Net Pension Expense Recognized Under Our Defined Benefit Pension Plans

                                                                            2006     2005    2004
---------------------------------------------------------------------------------------------------
<S>                                                                         <C>      <C>     <C>
NEXEN
---------------------------------------------------------------------------------------------------
      Cost of Benefits Earned by Employees                                    16       15       8
---------------------------------------------------------------------------------------------------
      Interest Cost on Benefits Earned                                        12       12      12
---------------------------------------------------------------------------------------------------
      Actual Return on Plan Assets                                           (23)     (18)    (16)
---------------------------------------------------------------------------------------------------
      Actuarial Losses                                                         9       33      10
---------------------------------------------------------------------------------------------------
  Pension Expense Before Adjustments for the Long-Term Nature of
         Employee Future Benefit Costs                                        14       42      14
---------------------------------------------------------------------------------------------------
      Difference Between Actual and Expected Return on Plan Assets            12        8       5
---------------------------------------------------------------------------------------------------
      Difference Between Actual and Recognized Actuarial Losses               (7)     (32)    (10)
---------------------------------------------------------------------------------------------------
      Difference Between Actual and Recognized Past Service Costs              1        -       1
---------------------------------------------------------------------------------------------------
  NET PENSION EXPENSE                                                         20       18      10
===================================================================================================

CANEXUS
---------------------------------------------------------------------------------------------------
      Cost of Benefits Earned by Employees                                     3        1       -
---------------------------------------------------------------------------------------------------
      Interest Cost on Benefits Earned                                         3        1       -
---------------------------------------------------------------------------------------------------
      Actual Return on Plan Assets                                            (6)       -       -
---------------------------------------------------------------------------------------------------
      Actuarial (Gains)/Losses                                                 2       (2)      -
---------------------------------------------------------------------------------------------------
  Pension Expense Before Adjustments for the Long-Term Nature of
         Employee Future Benefit Costs                                         2        -       -
---------------------------------------------------------------------------------------------------
      Difference Between Actual and Expected Return on Plan Assets             3       (1)      -
---------------------------------------------------------------------------------------------------
      Difference Between Actual and Recognized Actuarial Gains                (2)       2       -
---------------------------------------------------------------------------------------------------
      Difference Between Actual and Recognized Past Service Costs              -        -       -
---------------------------------------------------------------------------------------------------
  NET PENSION EXPENSE                                                          3        1       -
===================================================================================================

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

TOTAL NET PENSION EXPENSE                                                     30       27      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.

                                      99
<PAGE>

     Syncrude's pension plan is governed and administered separately from ours.
Syncrude's  investment assets are subject to similar investment goals, policies
and strategies.

                                                       EXPECTED
(%)                                                        2007    2006   2005
-------------------------------------------------------------------------------
NEXEN
-------------------------------------------------------------------------------
  Equity Securities                                          65      60     60
-------------------------------------------------------------------------------
  Debt Securities                                            35      40     40
-------------------------------------------------------------------------------
  Real Estate                                                 -       -      -
-------------------------------------------------------------------------------
  Other                                                       -       -      -
-------------------------------------------------------------------------------
TOTAL                                                       100     100    100
===============================================================================

-------------------------------------------------------------------------------
CANEXUS
-------------------------------------------------------------------------------
  Equity Securities                                          50      60     60
-------------------------------------------------------------------------------
  Debt Securities                                            50      40     40
-------------------------------------------------------------------------------
  Real Estate                                                 -       -      -
-------------------------------------------------------------------------------
  Other                                                       -       -      -
-------------------------------------------------------------------------------
TOTAL                                                       100     100    100
===============================================================================

-------------------------------------------------------------------------------
SYNCRUDE
-------------------------------------------------------------------------------
  Equity Securities                                          70      70     70
-------------------------------------------------------------------------------
  Debt Securities                                            30      30     30
-------------------------------------------------------------------------------
  Real Estate                                                 -       -      -
-------------------------------------------------------------------------------
  Other                                                       -       -      -
-------------------------------------------------------------------------------
TOTAL                                                       100     100    100
===============================================================================

(c)      DEFINED CONTRIBUTION PENSION PLANS

     Under  these  plans,  pension  benefits  are based on plan  contributions.
During 2006,  Canadian pension expense for these plans was $4 million (2005--$4
million; 2004--$4 million). During 2006, US pension expense for these plans was
$4 million (2005--$4 million; 2004--$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 at December 31, 2006 was $6 million
(2005--$4 million) and $2 million for Canexus (2005--$2 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 make contributions on
behalf  of  our  employees  and  no  further  obligation  exists.  Our  funding
contributions for the defined benefit plans are:

Defined Benefit Contributions                          EXPECTED
                                                           2007    2006   2005
-------------------------------------------------------------------------------
  Nexen                                                      11      24      2
-------------------------------------------------------------------------------
  Canexus                                                     2       3      -
-------------------------------------------------------------------------------
  Syncrude                                                    5       5      4
-------------------------------------------------------------------------------
TOTAL FUNDING CONTRIBUTIONS                                  18      32      6
===============================================================================

                                      100
<PAGE>

     Our most recent  funding  valuation was prepared as of June 30, 2006.  Our
next  funding  valuation  is required by June 30,  2009.  Canexus'  most recent
funding  valuation  was prepared as of August 18, 2005,  and their next funding
valuation  is required by December  31, 2007.  Syncrude's  most recent  funding
valuation  was  prepared  as of  December  31,  2006,  and their  next  funding
valuation is December 31, 2008.

     Our total  benefit  payments in 2006 were $11 million for Nexen  (2005--$8
million). Our share of Syncrude's total benefit payments in 2006 was $4 million
(2005--$3 million). Our estimated future payments are as follows:

<TABLE>
<CAPTION>
                                                   DEFINED BENEFIT                      OTHER
                                            NEXEN     CANEXUS    SYNCRUDE    NEXEN    CANEXUS    SYNCRUDE
-----------------------------------------------------------------------------------------------------------
<S>                                         <C>       <C>        <C>         <C>      <C>        <C>
2007                                            9           1           3        1          -           -
-----------------------------------------------------------------------------------------------------------
2008                                            9           1           3        2          -           -
-----------------------------------------------------------------------------------------------------------
2009                                           10           1           4        2          -           -
-----------------------------------------------------------------------------------------------------------
2010                                           11           1           4        2          -           -
-----------------------------------------------------------------------------------------------------------
2011                                           11           2           4        2          -           -
-----------------------------------------------------------------------------------------------------------
2012--2016                                     71          15          29       18          -           1
===========================================================================================================
</TABLE>

<TABLE>
<CAPTION>
17.      MARKETING AND OTHER

                                                                              2006       2005        2004
-----------------------------------------------------------------------------------------------------------
<S>                                                                          <C>          <C>         <C>
Marketing Revenue, Net                                                       1,309        847         608
-----------------------------------------------------------------------------------------------------------
Business Interruption Insurance Proceeds (1)                                   154          2          10
-----------------------------------------------------------------------------------------------------------
Change in Fair Value of Crude Oil Put Options                                  (11)      (196)         56
-----------------------------------------------------------------------------------------------------------
Interest                                                                        36         29          12
-----------------------------------------------------------------------------------------------------------
Foreign Exchange Losses                                                        (72)       (19)        (13)
-----------------------------------------------------------------------------------------------------------
Gains on Disposition of Assets (2)                                               4          4          24
-----------------------------------------------------------------------------------------------------------
Other                                                                           30         35          16
-----------------------------------------------------------------------------------------------------------
TOTAL MARKETING AND OTHER                                                    1,450        702         713
===========================================================================================================
</TABLE>
NOTES:
(1)  IN 2006, WE RECEIVED BUSINESS  INTERRUPTION  INSURANCE PROCEEDS RELATED TO
     PRODUCTION  LOSSES  CAUSED  BY GULF OF  MEXICO  HURRICANES  IN 2005 AND BY
     GENERATOR FAILURES IN OUR UK OPERATIONS IN 2005.
(2)  GAINS ON DISPOSITION OF ASSETS RESULTED FROM THE SALE OF MINOR OIL AND GAS
     ASSETS IN OUR  CANADIAN  OPERATIONS  IN 2006 AND 2004 AND FROM THE SALE OF
     OUR EJULEBE ASSETS, OFFSHORE NIGERIA IN 2005.


18. INCOME TAXES

<TABLE>
<CAPTION>
(a)      TEMPORARY DIFFERENCES

                                                            2006                      2005
                                                      FUTURE       FUTURE       FUTURE       FUTURE
                                                  INCOME TAX   INCOME TAX   INCOME TAX   INCOME TAX
                                                      ASSETS   LIABILITIES      ASSETS  LIABILITIES
<S>                                                      <C>        <C>            <C>        <C>
Property, Plant and Equipment, Net                        26        2,420           31        1,780
-----------------------------------------------------------------------------------------------------
Tax Losses Carried Forward                               594            -          370            -
-----------------------------------------------------------------------------------------------------
Deferred Income                                            -           48            -          175
-----------------------------------------------------------------------------------------------------
Recoverable Taxes                                          -            -            9            -
-----------------------------------------------------------------------------------------------------
TOTAL (1)                                                620        2,468          410        1,955
=====================================================================================================
</TABLE>
NOTE:
(1)  2006  INCLUDES  FUTURE INCOME TAX ASSETS OF $479 MILLION THAT WE EXPECT TO
     REALIZE IN THE  FOLLOWING  TWELVE  MONTHS  HAVE BEEN  INCLUDED  IN CURRENT
     ASSETS.

                                      101
<PAGE>

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

                                                                  2006        2005        2004
------------------------------------------------------------------------------------------------
<S>                                                              <C>           <C>       <C>
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
------------------------------------------------------------------------------------------------
  Canadian                                                        (352)       (396)         24
------------------------------------------------------------------------------------------------
  Foreign                                                        1,648       1,326       1,003
------------------------------------------------------------------------------------------------
                                                                 1,296         930       1,027
------------------------------------------------------------------------------------------------

PROVISION FOR INCOME TAXES
------------------------------------------------------------------------------------------------
  Current
------------------------------------------------------------------------------------------------
      Canadian                                                      14           1           6
------------------------------------------------------------------------------------------------
      Foreign                                                      354         338         242
------------------------------------------------------------------------------------------------
                                                                   368         339         248
------------------------------------------------------------------------------------------------
  Future
------------------------------------------------------------------------------------------------
      Canadian                                                     (96)       (206)         (3)
------------------------------------------------------------------------------------------------
      Foreign                                                      411         101          72
------------------------------------------------------------------------------------------------
                                                                   315        (105)         69
------------------------------------------------------------------------------------------------
                                                                   683         234         317
TOTAL PROVISION FOR INCOME TAXES
================================================================================================
</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, the United Kingdom and the United States and include Yemen
cash taxes of $286 million (2005--$296 million; 2004--$227 million).

(c)      RECONCILIATION OF EFFECTIVE TAX RATE TO THE CANADIAN STATUTORY TAX RATE

<TABLE>
<CAPTION>
                                                                      2006       2005       2004
--------------------------------------------------------------------------------------------------
<S>                                                                  <C>          <C>      <C>
Income before Income Taxes From Continuing Operations                1,296        930      1,027
--------------------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------
Provision for Income Taxes Computed at the Canadian Statutory Rate     401        318        354
--------------------------------------------------------------------------------------------------
Add (Deduct) the Tax Effect of:
--------------------------------------------------------------------------------------------------
  Royalties, Rentals and Similar Payments to Provincial Governments     15         24         20
--------------------------------------------------------------------------------------------------
  Resource Allowance and Provincial Tax Rebates                        (15)       (24)       (29)
--------------------------------------------------------------------------------------------------
  Lower Foreign Tax Rates                                               (9)       (40)       (22)
--------------------------------------------------------------------------------------------------
  Additional Canadian Tax on Canadian Resource Income                   10          6          7
--------------------------------------------------------------------------------------------------
  Lower Tax Rates on Capital Gains                                      (3)       (54)         -
--------------------------------------------------------------------------------------------------
  Federal and Provincial Capital Tax                                    13          5          6
--------------------------------------------------------------------------------------------------
  Effect of Changes in Tax Rates                                       245          -        (15)
--------------------------------------------------------------------------------------------------
  Non-Deductible Expenses and Other                                     26         (1)        (4)
--------------------------------------------------------------------------------------------------
PROVISION FOR INCOME TAXES                                             683        234        317
==================================================================================================
</TABLE>

     During the first  quarter of 2006, we recorded a future income tax expense
of $277 million related to an increase in the  supplemental tax rate on oil and
gas activities in the United Kingdom.  Legislation was introduced to the United
Kingdom  parliament  during the first quarter to increase the  supplemental tax
rate from 10% to 20%, effective January 1, 2006.

     In 2006 and 2004,  the federal and some  provincial  governments in Canada
reduced  statutory  income tax rates.  This reduced our liability and provision
for  future  income  taxes by $32  million  and $15  million  in 2006 and 2004,
respectively.

                                      102
<PAGE>

(d)      AVAILABLE UNUSED TAX LOSSES AND TAX CONTINGENCIES

     At December 31, 2006 and 2005, we had unused tax losses  totalling  $1,258
million and $965  million,  respectively,  mostly from our UK  operations.  The
majority of these losses have no expiry date.

     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,  a  predecessor   company,  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

                                                                           2006         2005       2004
---------------------------------------------------------------------------------------------------------
<S>                                                                       <C>          <C>          <C>
Depreciation, Depletion, Amortization and Impairment                      1,124        1,052        674
---------------------------------------------------------------------------------------------------------
Stock-Based Compensation                                                    101          428         74
---------------------------------------------------------------------------------------------------------
Gains on Disposition of Assets                                               (4)          (4)       (24)
---------------------------------------------------------------------------------------------------------
Provision for Future Income Taxes                                           315         (105)        69
---------------------------------------------------------------------------------------------------------
Change in Fair Value of Crude Oil Put Options                                11          196        (56)
---------------------------------------------------------------------------------------------------------
Non-Cash Items included in Discontinued Operations                            -         (325)       132
---------------------------------------------------------------------------------------------------------
Unamortized Issue Costs on Preferred Securities Redemption                    -            -         11
---------------------------------------------------------------------------------------------------------
Gain on Dilution of Interest in Chemicals Business                            -         (193)         -
---------------------------------------------------------------------------------------------------------
Net Income Attributable to Non-Controlling Interests                         12            8          -
---------------------------------------------------------------------------------------------------------
Other                                                                        70           24         26
---------------------------------------------------------------------------------------------------------
TOTAL                                                                     1,629        1,081        906
=========================================================================================================

(b)      CHANGES IN NON-CASH WORKING CAPITAL

                                                                           2006         2005       2004
---------------------------------------------------------------------------------------------------------
Accounts Receivable                                                         345       (1,078)      (454)
---------------------------------------------------------------------------------------------------------
Inventories and Supplies                                                   (302)        (163)      (106)
---------------------------------------------------------------------------------------------------------
Other Current Assets                                                        (14)         (10)        44
---------------------------------------------------------------------------------------------------------
Accounts Payable and Accrued Liabilities                                    (72)         982        650
---------------------------------------------------------------------------------------------------------
Other                                                                         -           20        (12)
---------------------------------------------------------------------------------------------------------
TOTAL                                                                       (43)        (249)       122
---------------------------------------------------------------------------------------------------------

---------------------------------------------------------------------------------------------------------
Relating to:
---------------------------------------------------------------------------------------------------------
  Operating Activities                                                     (177)        (195)      (122)
---------------------------------------------------------------------------------------------------------
  Investing Activities                                                      134          (54)       244
---------------------------------------------------------------------------------------------------------
TOTAL                                                                       (43)        (249)       122
=========================================================================================================
</TABLE>

                                      103
<PAGE>

(c)      OTHER CASH FLOW INFORMATION

                                                    2006       2005       2004
-------------------------------------------------------------------------------
Interest Paid                                        278        237        190
-------------------------------------------------------------------------------
Income Taxes Paid                                    398        325        249
===============================================================================

     In 2004,  other operating  activity cash outflows include $144 million for
the purchase of crude oil put options.

20.      OPERATING SEGMENTS AND RELATED INFORMATION

     Nexen has the  following  operating  segments  in various  industries  and
geographic locations:

     OIL AND GAS: We explore for,  develop and produce  crude oil,  natural gas
and related  products  around the world.  We manage our  operations  to reflect
differences in the regulatory  environments  and risk factors for each country.
Our core  operations  are onshore in Yemen and Canada,  and  offshore in the US
Gulf of Mexico and the UK North Sea. Our other operations are primarily in West
Africa and Colombia.

     ENERGY MARKETING: Our marketing group sells our crude oil and natural gas,
markets  third-party  crude oil and natural gas and engages in energy  trading,
including electricity generation.

     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 LP, 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.

                                      104
<PAGE>

<TABLE>
<CAPTION>
2006 OPERATING AND GEOGRAPHIC SEGMENTS

                                                                                                              CORPORATE
                                                                               ENERGY                               AND
                                             OIL AND GAS                    MARKETING    SYNCRUDE   CHEMICALS     OTHER      TOTAL
                            ------------------------------------------------------------------------------------------------------
                                                                    OTHER
                             YEMEN   CANADA      US       UK    COUNTRIES
(Cdn$ millions)                                                       (1)
----------------------------------------------------------------------------------------------------------------------------------
<S>                          <C>        <C>     <C>      <C>          <C>       <C>           <C>        <C>        <C>      <C>
Net Sales (2)                1,328      459     629      477          139          51         446        407(3)       -      3,936
----------------------------------------------------------------------------------------------------------------------------------
Marketing and Other              8        7      81(4)    85(5)         1       1,309           -          6        (47)(6)  1,450
----------------------------------------------------------------------------------------------------------------------------------
                             1,336      466     710      562          140       1,360         446        413        (47)     5,386
----------------------------------------------------------------------------------------------------------------------------------
Less: Expenses
----------------------------------------------------------------------------------------------------------------------------------
  Operating                    151      143     106       80            8          31         187        249          -        955
----------------------------------------------------------------------------------------------------------------------------------
  Depreciation,
    Depletion,
    Amortization and
    Impairment (7)             327      162     296      216           10          12          33         40         28      1,124
----------------------------------------------------------------------------------------------------------------------------------
  Transportation and Other       6       33       -        -            1         789          18         40        154(8)   1,041
----------------------------------------------------------------------------------------------------------------------------------
  General and
    Administrative (9)          17       80      58       14           44         112           1         29        200        555
----------------------------------------------------------------------------------------------------------------------------------
  Exploration                    4       26     214       46           72(10)       -           -          -          -        362
----------------------------------------------------------------------------------------------------------------------------------
  Interest                       -        -       -        -            -           -           -         11         42         53
----------------------------------------------------------------------------------------------------------------------------------
Income (Loss) from
   Continuing Operations
   before Income Taxes         831       22      36      206            5         416         207         44       (471)     1,296
----------------------------------------------------------------------------------------------------------------------------------
Less: Provision for
   (Recovery of) Income
   Taxes (11)                  289        7      13      378(12)        1         151          66         15       (237)       683
----------------------------------------------------------------------------------------------------------------------------------
Net Income (Loss) from
   Continuing Operations       542       15      23    (172)            4         265         141         29       (234)       613
----------------------------------------------------------------------------------------------------------------------------------
Less: Non-Controlling
   Interests                     -        -       -        -            -           -           -         12          -         12
----------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS)              542       15      23    (172)            4         265         141         17       (234)       601
----------------------------------------------------------------------------------------------------------------------------------

IDENTIFIABLE ASSETS            464    3,923   1,620    5,490          245       3,528(13)   1,186        459        241     17,156
----------------------------------------------------------------------------------------------------------------------------------

Capital Expenditures
----------------------------------------------------------------------------------------------------------------------------------
  Development and Other        145    1,434     418      596           28          47          86         27         45      2,826
----------------------------------------------------------------------------------------------------------------------------------
  Exploration                   37      163     177       62           52           -           -          -          -        491
----------------------------------------------------------------------------------------------------------------------------------
  Proved Property
    Acquisitions                 -       12       -        1            -           -           -          -          -         13
----------------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITAL EXPENDITURES     182    1,609     595      659           80          47          86         27         45      3,330
----------------------------------------------------------------------------------------------------------------------------------

Property, Plant and
   Equipment
   Cost                      2,404    5,216   2,889    4,710          249         226       1,304        854        286     18,138
----------------------------------------------------------------------------------------------------------------------------------
  Less: Accumulated DD&A     2,128    1,448   1,445      432           78          47         179        494        148      6,399
----------------------------------------------------------------------------------------------------------------------------------
NET BOOK VALUE (2)             276    3,768   1,444    4,278          171         179       1,125        360        138     11,739
----------------------------------------------------------------------------------------------------------------------------------

GOODWILL                         -        -       -      325            -          52           -          -          -        377
==================================================================================================================================
</TABLE>
NOTES:
(1)  INCLUDES RESULTS OF OPERATIONS FROM PRODUCING ACTIVITIES IN COLOMBIA.
(2)  NET SALES MADE FROM ALL SEGMENTS ORIGINATING IN CANADA:       1,095
     PP&E LOCATED IN CANADA:                                       5,483
(3)  NET SALES FOR OUR CHEMICALS OPERATIONS INCLUDE:
     CANADA            139
     UNITED STATES     185
     BRAZIL             83
                       ---
     TOTAL             407
                       ---
(4)  INCLUDES $80 MILLION OF BUSINESS  INTERRUPTION  INSURANCE PROCEEDS RELATED
     TO PRODUCTION LOSSES CAUSED BY GULF OF MEXICO HURRICANES IN 2005.
(5)  INCLUDES  $74  MILLION OF BUSINESS  INTERRUPTION  INSURANCE  PROCEEDS  FOR
     GENERATOR FAILURES IN 2005.
(6)  INCLUDES  INTEREST INCOME OF $36 MILLION,  FOREIGN  EXCHANGE LOSSES OF $72
     MILLION  AND  DECREASE  IN THE FAIR VALUE OF CRUDE OIL PUT  OPTIONS OF $11
     MILLION.
(7)  INCLUDES AN IMPAIRMENT  CHARGE OF $93 MILLION,  PRIMARILY  RELATING TO TWO
     NATURAL GAS PROPERTIES IN THE GULF OF MEXICO.
(8)  INCLUDES $151 MILLION (US$135  MILLION)  ACCRUAL WITH RESPECT TO THE BLOCK
     51 ARBITRATION SETTLEMENT (SEE NOTE 15).
(9)  INCLUDES STOCK-BASED COMPENSATION EXPENSE OF $210 MILLION.
(10) INCLUDES EXPLORATION ACTIVITIES PRIMARILY IN NIGERIA, NORWAY AND COLOMBIA.
(11) 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.
(12) INCLUDES  FUTURE INCOME TAX EXPENSE OF $277 MILLION RELATED TO AN INCREASE
     IN THE  SUPPLEMENTAL  TAX  RATE ON OIL AND GAS  ACTIVITIES  IN THE  UNITED
     KINGDOM (SEE NOTE 18).
(13) APPROXIMATELY  80%  OF  MARKETING'S   IDENTIFIABLE   ASSETS  ARE  ACCOUNTS
     RECEIVABLE AND INVENTORIES.

                                      105
<PAGE>

<TABLE>
<CAPTION>
2005 OPERATING AND GEOGRAPHIC SEGMENTS

                                                                                                              CORPORATE
                                                                                ENERGY                             AND
                                              OIL AND GAS                    MARKETING    SYNCRUDE   CHEMICALS   OTHER     TOTAL
                             ------------------------------------------------------------------------------------------------------
                                                                     OTHER
                              YEMEN     CANADA      US     UK    COUNTRIES
(Cdn$ millions)                            (1)                          (2)
----------------------------------------------------------------------------------------------------------------------------------
<S>                           <C>        <C>     <C>      <C>          <C>       <C>        <C>        <C>        <C>      <C>
Net Sales (3)                 1,377        455     792    366          119        28        397        398(4)       -      3,932
----------------------------------------------------------------------------------------------------------------------------------
Marketing and Other               8          3       2     16            4       847          -         15       (193)(5)    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(6)      22      1,052
----------------------------------------------------------------------------------------------------------------------------------
  Transportation and Other        6         23       1      -            2       641         21         40         62        796
----------------------------------------------------------------------------------------------------------------------------------
  General and
    Administrative (7)           42        107      88      8          101        89          1         45        328        809
----------------------------------------------------------------------------------------------------------------------------------
  Exploration                    12         23     100     51           64(8)      -          -          -          -        250
----------------------------------------------------------------------------------------------------------------------------------
  Interest                        -          -       -      -            -         -          -          3         94         97
----------------------------------------------------------------------------------------------------------------------------------
Income (Loss) from
   Continuing Operations
   before Income Taxes          821         44     275     18          (69)      104        206        230       (699)       930
----------------------------------------------------------------------------------------------------------------------------------
Less: Provision for
   (Recovery of) Income
   Taxes (9)                    285         13      98      7          (13)       41         60         15       (272)       234
----------------------------------------------------------------------------------------------------------------------------------
Net Income (Loss) from
   Continuing Operations        536         31     177     11          (56)       63        146        215       (427)       696
----------------------------------------------------------------------------------------------------------------------------------
Less: Non-Controlling
   Interests                      -          -       -      -            -         -          -          8          -          8
----------------------------------------------------------------------------------------------------------------------------------
Add: Net Income from
  Discontinued Operations         -        452       -      -            -         -          -          -          -        452
----------------------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS)               536        483     177     11          (56)       63        146        207       (427)     1,140
----------------------------------------------------------------------------------------------------------------------------------

IDENTIFIABLE ASSETS             635      2,449   1,433  4,775          183     3,165(10)  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 (3)              402      2,320   1,278  3,797          130       105      1,069        371        122      9,594
----------------------------------------------------------------------------------------------------------------------------------

GOODWILL                          -          -       -    325            -        39          -          -          -        364
==================================================================================================================================
</TABLE>
NOTES:
(1)  DURING  THE THIRD  QUARTER  OF 2005,  WE  CONCLUDED  THE SALE OF  CANADIAN
     CONVENTIONAL  OIL AND GAS PROPERTIES.  THE RESULTS OF THESE PROPERTIES ARE
     SHOWN AS DISCONTINUED OPERATIONS (SEE NOTE 14).
(2)  INCLUDES  RESULTS OF OPERATIONS  FROM PRODUCING  ACTIVITIES IN NIGERIA AND
     COLOMBIA.
(3)  NET SALES MADE FROM ALL SEGMENTS ORIGINATING IN CANADA:       1,014
     PP&E LOCATED IN CANADA:                                       3,899
(4)  NET SALES FOR OUR CHEMICALS OPERATIONS INCLUDE:
     CANADA            132
     UNITED STATES     198
     BRAZIL             68
                       ---
     TOTAL             398
                       ---
(5)  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.
(6)  INCLUDES  IMPAIRMENT  CHARGE OF $12 MILLION  RELATED TO THE CLOSURE OF OUR
     SODIUM CHLORATE PLANT IN AMHERSTBURG, ONTARIO.
(7)  INCLUDES STOCK-BASED COMPENSATION EXPENSE OF $507 MILLION.
(8)  INCLUDES  EXPLORATION  ACTIVITIES  PRIMARILY  IN  NIGERIA,   COLOMBIA  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) APPROXIMATELY  86%  OF  MARKETING'S   IDENTIFIABLE   ASSETS  ARE  ACCOUNTS
     RECEIVABLE AND INVENTORIES.

                                      106
<PAGE>

<TABLE>
<CAPTION>
2004 OPERATING AND GEOGRAPHIC SEGMENTS

                                                                                                                 CORPORATE
                                                  OIL AND GAS                     ENERGY                               AND
                                                                               MARKETING    SYNCRUDE   CHEMICALS     OTHER    TOTAL
                               ----------------------------------------------------------------------------------------------------
                                                                      OTHER
                                YEMEN  CANADA         US     UK   COUNTRIES
(Cdn$ millions)                                             (1)         (2)
-----------------------------------------------------------------------------------------------------------------------------------
<S>                               <C>     <C>        <C>     <C>         <C>          <C>         <C>        <C>              <C>
Net Sales (3)                     921     390        811     36          73           14          321        378(4)       -   2,944
-----------------------------------------------------------------------------------------------------------------------------------
Marketing and Other                 5      27         11      -           2          608            -          5         55(5)  713
-----------------------------------------------------------------------------------------------------------------------------------
                                  926     417        822     36          75          622          321        383         55   3,657
-----------------------------------------------------------------------------------------------------------------------------------
Less: Expenses
-----------------------------------------------------------------------------------------------------------------------------------
  Operating                       109     116        106      6           7           16          125        237          -     722
-----------------------------------------------------------------------------------------------------------------------------------
  Depreciation, Depletion,
    Amortization and
    Impairment                    169     128        258     18          18           10           18         37         18     674
-----------------------------------------------------------------------------------------------------------------------------------
  Transportation and Other          5      15          -      -           -          451           12         41         25     549
-----------------------------------------------------------------------------------------------------------------------------------
  General and Administrative        4      42         30      -          47           58            1         28         89     299
-----------------------------------------------------------------------------------------------------------------------------------
  Exploration                       2      18        138      3          82(6)         -            -          -          -     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 (7)          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 (8)       -      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(9)       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 (3)                488   1,408(10)  1,212  3,483         127           93          875        406        111   8,203
-----------------------------------------------------------------------------------------------------------------------------------

GOODWILL                            -       -          -    339           -           36            -          -          -     375
===================================================================================================================================
</TABLE>
NOTES:
(1)  ON DECEMBER 1, 2004, WE ACQUIRED ENCANA (UK) LIMITED (SEE NOTE 3).
(2)  INCLUDES  RESULTS OF  OPERATIONS  FROM  PRODUCING  ACTIVITIES  IN NIGERIA,
     COLOMBIA, AND AUSTRALIA.
(3)  NET SALES MADE FROM ALL SEGMENTS ORIGINATING IN CANADA:       1,242
     PP&E LOCATED IN CANADA:                                       3,198
(4)  NET SALES FOR OUR CHEMICALS OPERATIONS INCLUDE:
     CANADA            135
     UNITED STATES     184
     BRAZIL             59
                       ---
     TOTAL             378
                       ---
(5)  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.
(6)  INCLUDES EXPLORATION ACTIVITIES PRIMARILY IN NIGERIA AND COLOMBIA.
(7)  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.
(8)  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).
(9)  APPROXIMATELY  81%  OF  MARKETING'S   IDENTIFIABLE   ASSETS  ARE  ACCOUNTS
     RECEIVABLE AND INVENTORIES.
(10) 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).

                                      107
<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, 2006

(Cdn$ millions, except per share amounts)                                 2006        2005       2004
-------------------------------------------------------------------------------------------------------
<S>                                                                      <C>         <C>        <C>
Revenues and Other Income
-------------------------------------------------------------------------------------------------------
  Net Sales                                                              3,936       3,932      2,944
-------------------------------------------------------------------------------------------------------
  Marketing and Other (ii); (x); (xi)                                    1,459         687        696
-------------------------------------------------------------------------------------------------------
  Gain on Dilution of Interest in Chemicals Business                         -         193          -
-------------------------------------------------------------------------------------------------------
                                                                         5,395       4,812      3,640
-------------------------------------------------------------------------------------------------------
Expenses
-------------------------------------------------------------------------------------------------------
  Operating (iv)                                                           958         903        731
-------------------------------------------------------------------------------------------------------
  Depreciation, Depletion, Amortization and Impairment (i)               1,124       1,081        716
-------------------------------------------------------------------------------------------------------
  Transportation and Other (x)                                           1,037         792        524
-------------------------------------------------------------------------------------------------------
  General and Administrative (viii); (ix)                                  597         792        263
-------------------------------------------------------------------------------------------------------
  Exploration                                                              362         250        243
-------------------------------------------------------------------------------------------------------
  Interest                                                                  53          97        143
-------------------------------------------------------------------------------------------------------
                                                                         4,131       3,915      2,620

-------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Income Taxes                    1,264         897      1,020
-------------------------------------------------------------------------------------------------------

Provision for Income Taxes
-------------------------------------------------------------------------------------------------------
  Current                                                                  368         339        248
-------------------------------------------------------------------------------------------------------
  Deferred (ii) - (xi)                                                     305        (108)        67
-------------------------------------------------------------------------------------------------------
                                                                           673         231        315
-------------------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------------------
Net Income from Continuing Operations before Non-Controlling Interests     591         666        705
-------------------------------------------------------------------------------------------------------
  Net Income Attributable to Non-Controlling Interests                      12           8          -
-------------------------------------------------------------------------------------------------------
Net Income from Continuing Operations                                      579         658        705
-------------------------------------------------------------------------------------------------------
  Net Income from Discontinued Operations                                    -         452         83
-------------------------------------------------------------------------------------------------------
                                                                           579       1,110        788
NET INCOME--US GAAP (1)
=======================================================================================================

EARNINGS PER COMMON SHARE ($/share)
-------------------------------------------------------------------------------------------------------
  Basic (Note 13)
-------------------------------------------------------------------------------------------------------
      Net Income from Continuing Operations                               2.21        2.52       2.74
-------------------------------------------------------------------------------------------------------
      Net Income from Discontinued Operations                                -        1.74       0.32
-------------------------------------------------------------------------------------------------------
                                                                          2.21        4.26       3.06
-------------------------------------------------------------------------------------------------------

  Diluted (Note 13)
-------------------------------------------------------------------------------------------------------
      Net Income from Continuing Operations                               2.15        2.47       2.71
-------------------------------------------------------------------------------------------------------
      Net Income from Discontinued Operations                                -        1.70       0.32
-------------------------------------------------------------------------------------------------------
                                                                          2.15        4.17       3.03
=======================================================================================================
NOTE:
(1)   RECONCILIATION OF CANADIAN AND US GAAP NET INCOME

(Cdn$ millions)                                                           2006         2005       2004
-------------------------------------------------------------------------------------------------------
Net Income--Canadian GAAP                                                   601        1,140        793
-------------------------------------------------------------------------------------------------------
  Impact of US Principles, Net of Income Taxes:
-------------------------------------------------------------------------------------------------------
  Depreciation, Depletion, Amortization and Impairment (i)                   -          (29)       (42)
-------------------------------------------------------------------------------------------------------
  Stock-Based Compensation (viii); (ix)                                    (29)          12         36
-------------------------------------------------------------------------------------------------------
  Other (ii); (iv); (xi)                                                     7          (13)         1
-------------------------------------------------------------------------------------------------------
NET INCOME--US GAAP                                                         579        1,110        788
=======================================================================================================
</TABLE>

                                      108
<PAGE>

<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEET--US GAAP
DECEMBER 31, 2006 AND 2005

(Cdn$ millions, except share amounts)                                                2006         2005
-------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>          <C>
ASSETS
-------------------------------------------------------------------------------------------------------
  Current Assets
-------------------------------------------------------------------------------------------------------
      Cash and Cash Equivalents                                                       101           48
-------------------------------------------------------------------------------------------------------
      Restricted Cash and Margin Deposits                                             197           70
-------------------------------------------------------------------------------------------------------
      Accounts Receivable (ii)                                                      2,976        3,151
-------------------------------------------------------------------------------------------------------
      Inventories and Supplies                                                        786          504
-------------------------------------------------------------------------------------------------------
      Deferred Income Tax Assets                                                      479            -
-------------------------------------------------------------------------------------------------------
      Other                                                                            67           51
-------------------------------------------------------------------------------------------------------
       Total Current Assets                                                         4,606        3,824
-------------------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------------------
Property, Plant and Equipment                                                      11,692        9,550
  Net of Accumulated Depreciation, Depletion, Amortization and
      Impairment of $6,792 (December 31, 2005--$5,861) (iv); (vii)
-------------------------------------------------------------------------------------------------------
  Goodwill                                                                            377          364
-------------------------------------------------------------------------------------------------------
  Deferred Income Tax Assets                                                          141          410
-------------------------------------------------------------------------------------------------------
  Deferred Charges and Other Assets (v); (vi)                                         263          345
-------------------------------------------------------------------------------------------------------
                                                                                   17,079       14,493
TOTAL ASSETS
=======================================================================================================

-------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
-------------------------------------------------------------------------------------------------------
  Current Liabilities
-------------------------------------------------------------------------------------------------------
      Short-Term Borrowings                                                           158            -
-------------------------------------------------------------------------------------------------------
      Accounts Payable and Accrued Liabilities (ii); (ix)                           3,839        3,745
-------------------------------------------------------------------------------------------------------
      Accrued Interest Payable                                                         55           55
-------------------------------------------------------------------------------------------------------
      Dividends Payable                                                                13           13
-------------------------------------------------------------------------------------------------------
       Total Current Liabilities                                                    4,065        3,813
-------------------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------------------
  Long-Term Debt (v)                                                                4,618        3,630
-------------------------------------------------------------------------------------------------------
  Deferred Income Tax Liabilities (i) - (xi)                                        2,427        1,906
-------------------------------------------------------------------------------------------------------
  Asset Retirement Obligations                                                        683          590
-------------------------------------------------------------------------------------------------------
  Deferred Credits and Other Liabilities (vi)                                         597          505
-------------------------------------------------------------------------------------------------------
  Non-Controlling Interests                                                            75           88
-------------------------------------------------------------------------------------------------------
  Shareholders' Equity
      Common Shares, no par value
-------------------------------------------------------------------------------------------------------
       Authorized:       Unlimited
-------------------------------------------------------------------------------------------------------
       Outstanding:     2006--262,513,206 shares
-------------------------------------------------------------------------------------------------------
                        2005--261,140,571 shares                                      821          732
-------------------------------------------------------------------------------------------------------
      Contributed Surplus                                                               4            2
-------------------------------------------------------------------------------------------------------
      Retained Earnings (i) - (xi)                                                  3,945        3,418
-------------------------------------------------------------------------------------------------------
      Accumulated Other Comprehensive Income (ii); (iii); (vi)                       (156)        (191)
-------------------------------------------------------------------------------------------------------
       Total Shareholders' Equity                                                   4,614        3,961
-------------------------------------------------------------------------------------------------------
  Commitments, Contingencies and Guarantees
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                                         17,079       14,493
=======================================================================================================
</TABLE>

                                      109
<PAGE>

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME--US GAAP

<TABLE>
<CAPTION>
FOR THE THREE YEARS ENDED DECEMBER 31, 2006

(Cdn$ millions)                                                          2006       2005       2004
-----------------------------------------------------------------------------------------------------
<S>                                                                        <C>      <C>          <C>
Net Income--US GAAP                                                        579      1,110        788
-----------------------------------------------------------------------------------------------------
  Other Comprehensive Income, Net of Income Taxes:
-----------------------------------------------------------------------------------------------------
  Translation Adjustment (iii)                                              -        (56)       (72)
-----------------------------------------------------------------------------------------------------
  Unrealized Mark-to-Market Gain (Loss) (ii)                               77        (20)        11
-----------------------------------------------------------------------------------------------------
  Minimum Unfunded Pension Liability (vi)                                   5        (10)        (1)
-----------------------------------------------------------------------------------------------------
COMPREHENSIVE INCOME                                                      661      1,024        726
=====================================================================================================

<CAPTION>
CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE INCOME--US GAAP
DECEMBER 31, 2006 AND 2005

(Cdn$ millions)                                                                       2006      2005
------------------------------------------------------------------------------------------------------
<S>                                                                                   <C>       <C>
Translation Adjustment (iii)                                                          (161)     (161)
------------------------------------------------------------------------------------------------------
Unrealized Mark-to-Market Gains (Losses) (ii)                                           61       (16)
------------------------------------------------------------------------------------------------------
Minimum Pension Liability Adjustment (vi)                                                -       (14)
------------------------------------------------------------------------------------------------------
Unamortized Defined Benefit Pension Plan Costs (vi)                                    (56)        -
------------------------------------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME (AOCI)                                         (156)     (191)
======================================================================================================
</TABLE>

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,  additional
     depreciation,  depletion,  amortization  and impairment of $29 million was
     included in net income during 2005 (2004--$42 million). The difference was
     fully amortized during 2005.

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:  At December 31, 2003,  accounts
     payable  includes 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:  At December 31, 2003,  accounts  payable
     includes $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.
     Losses of $8 million ($5  million,  net of income  taxes),  related to the
     effective  portion  and  deferred  in  AOCI at  December  31,  2003,  were
     recognized  in  marketing  and other in 2004.  Additionally,  losses of $3
     million ($2  million,  net of income  taxes),  related to the  ineffective
     portion,  were  recognized  in marketing  and other under US GAAP in 2003.
     Under Canadian GAAP, the ineffective  portion was recognized in net income
     in 2004.

        At December 31, 2004,  accounts receivable includes $6 million of gains
     on futures  contracts and swaps we used to hedge  commodity  price risk on
     the future sale of our gas inventory.  Gains of $6 million ($4 million net
     of income taxes), related to the effective portion and deferred in AOCI at
     December 31, 2004, were recognized in marketing and other in 2005.

                                      110
<PAGE>

         At December 31, 2005,  accounts payable includes losses of $35 million
      on futures  contracts and swaps we used to hedge  commodity price risk on
      the future sale of our gas inventory. Losses of $24 million ($16 million,
      net of income  taxes),  related to the effective  portion and deferred in
      AOCI at December  31, 2005,  were  recognized  in marketing  and other in
      2006. The  ineffective  portion of the losses of $11 million ($7 million,
      net of income taxes) was recognized in US GAAP net income in 2005.  Under
      Canadian  GAAP, the  ineffective  portion was recognized in marketing and
      other in 2006.

         At  December  31,  2006,  accounts  receivable  includes  gains of $25
      million on futures  contracts and swaps we used to hedge  commodity price
      risk on the future sale of our gas  inventory.  Gains of $23 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
      gains will be reclassified to marketing and other as the contracts settle
      over the next 12  months.  The  ineffective  portion  of the  gains of $2
      million ($2 million,  net of taxes) was recognized in marketing and other
      in 2006.

         Also  included in AOCI at  December  31, 2006 are gains of $65 million
      ($45 million,  net of income taxes)  related to  de-designated  cash flow
      hedges as described  in Note 7(b).  These gains will be  reclassified  to
      marketing and other over the next 12 months.  Under Canadian GAAP,  these
      deferred gains are included in accounts payable and accrued liabilities.

      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, 2006, we had
      no fair value hedges in place.

iii.  Under US GAAP,  exchange gains and losses arising from the translation of
      our net investment in self-sustaining  foreign operations are included in
      comprehensive  income.  Additionally,  exchange gains and losses,  net of
      income  taxes,  from the  translation  of our  US-dollar  long-term  debt
      designated  as a hedge of our  foreign  net  investment  are  included in
      comprehensive  income.  Cumulative  amounts  are  included in AOCI in the
      Consolidated Balance Sheet--US GAAP.

iv.   Under  Canadian  GAAP,  we  defer  certain   development  costs  and  all
      pre-operating revenues and costs to PP&E. Under US GAAP, these costs have
      been included in operating expenses. As a result:

         o    operating expenses include  pre-operating costs of $3 million ($2
              million,  net of income taxes) (2005--$10 million ($6 million net
              of income  taxes);  2004--$9  million ($6 million,  net of income
              taxes)); and

         o    PP&E  is  lower  under  US  GAAP  by $28  million  (December  31,
              2005--$25 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 $55 million  (December  31,  2005--$57  million)  have been
      included in long-term debt.

vi.   On December  31,  2006,  we adopted  FASB  Statement  No. 158  EMPLOYERS'
      ACCOUNTING FOR DEFINED BENEFIT PENSION AND OTHER  POSTRETIREMENT PLANS as
      described under changes in accounting  policy--US GAAP. At year-end,  the
      unfunded  amount of our defined  benefit  pension  plans was $81 million.
      This amount has been included in deferred  credits and other  liabilities
      and $56 million, net of income taxes, has been included in AOCI. Prior to
      the  adoption of FAS 158 on December  31,  2006,  we included our minimum
      unfunded pension  liability in deferred credits and other liabilities and
      in AOCI.  At December  31,  2005,  $26  million was  included in deferred
      credits  and other  liabilities,  $4 million  was  included  in  deferred
      charges  and  other  assets  and $14  million,  net of  income  taxes was
      included in AOCI. During the year, our minimum unfunded pension liability
      decreased  by $5 million,  net of income  taxes (2005 - increased  by $10
      million,  net of income  taxes;  2004 - increased  by $1 million,  net of
      income taxes).

vii.  On January 1, 2003,  we adopted FASB  Statement No. 143,  ACCOUNTING  FOR
      ASSET RETIREMENT OBLIGATIONS (FAS 143) for US GAAP reporting purposes. We
      adopted the equivalent Canadian standard for asset retirement obligations
      on  January 1,  2004.  These  standards  are  consistent,  except for the
      adoption  date,  which  resulted in our PP&E under US GAAP being lower by
      $19 million.

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

                                      111
<PAGE>


      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 Canadian  principles,  we record  obligations  for  liability-based
      stock compensation plans using the intrinsic-value  method of accounting.
      Under  US  principles,   effective   January  1,  2006   obligations  for
      liability-based   stock   compensation   plans  are  recorded  using  the
      fair-value method of accounting.  In addition,  under Canadian principles
      as  disclosed  in Note  1(u),  we  retroactively  adopted  EIC-162  which
      requires the accelerated recognition of stock-based  compensation expense
      for all  stock-based  awards made to our retired and  retirement-eligible
      employees.  However,  under  US  GAAP,  the  accelerated  recognition  of
      stock-based  compensation  expense for such employees is only required in
      respect of  stock-based  awards granted on or after January 1, 2006. As a
      result:

         o    general and administrative  expense is higher by $42 million ($29
              million,  net of income  taxes) for the year ended  December  31,
              2006  (2005--lower  by $17 million  ($12  million,  net of income
              taxes));

         o    accounts  payable  and  accrued  liabilities  are  higher  by $25
              million at December 31, 2006 (2005--lower by $17 million); and

         o    the impact for 2004 is not material.

x.    Under US GAAP, gains and losses on the disposition of assets are included
      with transportation and other expense.  Gains in 2006 of $4 million, 2005
      of $4 million,  and 2004 of $24 million were  reclassified from marketing
      and other to transportation and other.

xi.   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. The $4 million increase in fair value from
      January  1,  2004 to  February  9,  2004  (redemption  date of  preferred
      securities)  was  included in net income for the year ended  December 31,
      2004.

CHANGES IN ACCOUNTING POLICIES--US GAAP

STOCK-BASED COMPENSATION

      On January 1, 2006, we adopted FASB Statement 123 (revised),  SHARE-BASED
PAYMENT (Statement 123(R)) using the modified  prospective  approach and graded
vesting  amortization.  Under  Statement  123(R),  our tandem options and stock
appreciation rights (StARS) are considered  liability-based  stock compensation
plans.  Under the  modified  prospective  approach,  no amounts are restated in
prior  periods.  Upon  adoption of Statement  123(R),  we recorded a cumulative
effect of a change in  accounting  principle  of $2  million.  This  amount was
recorded in general  and  administrative  expenses in our US GAAP  Consolidated
Statement of Income in 2006.

      Prior  to  the  adoption  of  Statement  123(R),  we  accounted  for  our
liability-based stock compensation plans in accordance with FASB Interpretation
28, ACCOUNTING FOR STOCK APPRECIATION RIGHTS AND OTHER VARIABLE STOCK OPTION OR
AWARD PLANS (the intrinsic-value method). Accordingly, obligations were accrued
on a graded vesting basis and  represented  the  difference  between the market
value of our common  shares and the exercise  price of  underlying  options and
rights.   Under  Statement  123(R),   obligations  for  liability-based   stock
compensation plans are measured at their fair value, and are remeasured at fair
value in each subsequent reporting period.

      Consistent with Statement  123(R),  we account for any stock options that
do not include a cash feature  (equity-based stock compensation  plans),  using
the fair-value method.

      The impact of adopting Statement 123(R) on our results for the year ended
December 31, 2006 is as follows:

<TABLE>
<CAPTION>
                                                                            PRIOR TO            AFTER
                                                                         ADOPTION OF      ADOPTION OF       INCREASE/
(Cdn$ millions)                                                            FAS 123(R)       FAS 123(R)     (DECREASE)
----------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>              <C>              <C>
Income from Continuing Operations before Income Taxes --US GAAP                1,306            1,264            (42)
----------------------------------------------------------------------------------------------------------------------
Net Income--US GAAP                                                              608              579            (29)
----------------------------------------------------------------------------------------------------------------------
Basic Earnings per Common Share--US GAAP ($/share)                              2.32             2.21          (0.11)
----------------------------------------------------------------------------------------------------------------------
Diluted Earnings per Common Share--US GAAP ($/share)                            2.26             2.15          (0.11)
======================================================================================================================
</TABLE>

                                      112
<PAGE>

ASSUMPTIONS

      We use the Generalized Black-Scholes option pricing model to estimate the
fair value of our stock-based compensation, with the following assumptions:

<TABLE>
<S>                                                                           <C>
Expected Annual Dividends per Common Share ($/share)                                 0.20
Expected Volatility                                                                   40%
Risk-Free Interest Rate                                                       4.3% - 4.4%
Weighted-Average Expected Life of Compensation Instruments (in years)           2.8 - 3.0
</TABLE>

      These  assumptions are based on multiple  factors,  including  historical
exercise patterns of employees in relatively  homogenous groups with respect to
exercise and post-vesting  employment  termination  behaviors,  expected future
exercising patterns for those same homogenous groups, the implied volatility of
our stock price,  our expected future dividend levels and the interest rate for
Government  of Canada bonds.  Our valuation  methodology  and  assumptions  are
consistent with those previously used under FAS 123.

<TABLE>
<CAPTION>
STOCK OPTIONS
                                                                                 WEIGHTED
                                                                  WEIGHTED        AVERAGE                        WEIGHTED
                                                                   AVERAGE      REMAINING         AGGREGATE       AVERAGE
                                                                  EXERCISE        TERM TO         INTRINSIC         FAIR
                                                    NUMBER           PRICE         EXPIRY             VALUE         VALUE
                                                (thousands)      ($/option)        (years)   (Cdn$ millions)    ($/option)
---------------------------------------------------------------------------------------------------------------------------
<S>                                             <C>              <C>            <C>           <C>               <C>
Outstanding at December 31, 2006                    15,242              35            3.2               450            33
---------------------------------------------------------------------------------------------------------------------------
Outstanding at December 31, 2006
   and Expected to Vest                             15,156              35            3.2               445            34
---------------------------------------------------------------------------------------------------------------------------
Exercisable at December 31, 2006                     9,345              24            2.6               373            39
===========================================================================================================================
</TABLE>

      The total  intrinsic  value of stock  options  exercised  during the year
ended  December  31,  2006 was $109  million  (2005 - $83  million;  2004 - $60
million).  As at  December  31,  2006,  we  had  $77  million  of  unrecognized
compensation expense related to stock options which we expect to recognize over
a weighted-average period of 1.5 years.

<TABLE>
<CAPTION>
STOCK APPRECIATION RIGHTS
                                                                                 WEIGHTED
                                                                  WEIGHTED        AVERAGE                        WEIGHTED
                                                                   AVERAGE      REMAINING         AGGREGATE       AVERAGE
                                                                  EXERCISE        TERM TO         INTRINSIC         FAIR
                                                    NUMBER           PRICE         EXPIRY             VALUE         VALUE
                                                (thousands)      ($/option)        (years)   (Cdn$ millions)    ($/option)
---------------------------------------------------------------------------------------------------------------------------
<S>                                             <C>              <C>            <C>           <C>               <C>
Outstanding at December 31, 2006                     6,945              42            3.5               154            29
---------------------------------------------------------------------------------------------------------------------------
Outstanding at December 31, 2006
    and Expected to Vest                             6,759              42            3.5               151            30
---------------------------------------------------------------------------------------------------------------------------
Exercisable at December 31, 2006                     3,076              27            2.6               115            38
===========================================================================================================================
</TABLE>

      The total intrinsic value of stock  appreciation  rights exercised during
the year ended December 31, 2006 was $46 million (2005--$34  million;  2004--$7
million).  As at  December  31,  2006,  we  had  $54  million  of  unrecognized
compensation  expense related to stock  appreciation  rights which we expect to
recognize over a weighted-average period of 1.6 years.


STOCK-BASED COMPENSATION EXPENSE AND PAYMENTS

      For the year ended December 31, 2006, stock-based compensation expense of
$252 million  (2005--$490  million;  2004--$57 million) was included in general
and administrative expense in the Consolidated Statement of Income--US GAAP.

      For the year ended  December 31, 2006,  cash proceeds of $16 million were
received related to the exercise of stock options (2005--$29 million; 2004--$93
million).

                                      113
<PAGE>

      For the year ended  December  31, 2006,  cash of $119 million  (2005--$74
million;  2004--$10  million) was paid upon the  exercise of stock  options and
stock appreciation rights. The income tax benefit recorded from the exercise of
stock options and stock appreciation rights was $37 million (2005--$24 million;
2004--$3 million) for the period.

STOCK BASED COMPENSATION EXPENSE FOR RETIRED AND RETIREMENT ELIGIBLE EMPLOYEES

      We  recognize  stock-based  compensation  expense  for  our  retired  and
retirement-eligible  employees  over an  accelerated  graded  vesting period in
accordance  with the  provisions  of Statement  123(R) for  stock-based  awards
granted  to  employees  on or after  January 1, 2006.  For  stock-based  awards
granted  prior to the adoption of Statement  123(R),  stock-based  compensation
expense for our retired and retirement-eligible  employees is recognized over a
graded vesting period. If we applied the accelerated  graded vesting provisions
of  Statement  123(R)  to  stock-based   awards  granted  to  our  retired  and
retirement-eligible  employees prior to the adoption of Statement  123(R),  our
stock-based  compensation  expense  would  decrease by $10 million for the year
ended December 31, 2006  (2005--increase  by $19 million;  2004--increase by $2
million).

PENSION AND OTHER POST-RETIREMENT BENEFITS

      On  December  31,  2006,  we  adopted  FASB  Statement  158,   EMPLOYERS'
ACCOUNTING  FOR  DEFINED  BENEFIT  PENSION  AND  OTHER   POSTRETIREMENT   PLANS
(Statement  158),  which requires,  among other things,  the recognition of the
over-funded  and  under-funded  status of a defined benefit plan on the balance
sheet as an asset or  liability.  The  initial  impact of the  standard  due to
unrecognized  prior service costs or credits and net actuarial  gains or losses
as well as subsequent changes in the funded status is recognized as a component
of AOCI in shareholders'  equity.  Additional  minimum pension  liabilities and
related  intangible  assets are also  de-recognized  upon adoption of Statement
158.

      The  impact of  adopting  Statement  158 at  December  31,  2006  reduced
deferred charges and other assets by $4 million, reduced deferred future income
tax  liabilities  by  $22  million,   increased   deferred  credits  and  other
liabilities  by $65  million  and  decreased  AOCI by $47  million.  The impact
considered the additional  minimum pension liability at December 31, 2006 prior
to the adoption of Statement 158.

NEW ACCOUNTING PRONOUNCEMENTS

      In February 2006, the FASB issued  Statement 155,  ACCOUNTING FOR CERTAIN
HYBRID  INSTRUMENTS,  which amends  Statement  133,  ACCOUNTING  FOR DERIVATIVE
INSTRUMENTS AND HEDGING ACTIVITIES, and Statement 140, ACCOUNTING FOR TRANSFERS
AND SERVICING OF FINANCIAL ASSETS AND EXTINGUISHMENTS OF LIABILITIES. Statement
155 permits fair value  re-measurement for any hybrid financial instrument that
contains an embedded  derivative that otherwise would require  bifurcation from
its  host  contract  in  accordance  with  Statement  133.  Statement  155 also
clarifies  other  provisions of Statement 133 and Statement 140. This statement
is effective for all financial  instruments  acquired or issued in fiscal years
beginning after September 15, 2006. We do not expect adoption of this statement
will have a material impact on our results of operations or financial position.

      In July 2006,  FASB issued FIN 48 ACCOUNTING  FOR  UNCERTAINTY  IN INCOME
TAXES with respect to FAS 109 ACCOUNTING FOR INCOME TAXES regarding  accounting
for and  disclosure of uncertain tax  positions.  This guidance seeks to reduce
the diversity in practice  associated  with certain  aspects of the recognition
and measurement  related to accounting for income taxes. This interpretation is
effective for fiscal years beginning after December 15, 2006.  Adoption of this
standard is expected to increase our future income tax  liabilities  by no more
than $30 million and decrease our retained earnings by a corresponding amount.

      In September  2006, FASB issued  Statement 157, FAIR VALUE  MEASUREMENTS.
Statement 157 defines fair value,  establishes  a framework for measuring  fair
value under US generally accepted accounting principles and expands disclosures
about fair value  measurements.  This  statement is effective  for fiscal years
beginning  after  November  15,  2007.  We do not expect the  adoption  of this
statement will have a material impact on our results of operations or financial
position.

                                      114
<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)                                           2006    2005    2006    2005    2006    2005    2006    2005
------------------------------------------------------------------------------------------------------------------------
<S>                                                      <C>     <C>    <C>       <C>     <C>   <C>       <C>   <C>
Net Sales (1)                                              980     856   1,039     909     997   1,094     920   1,073
------------------------------------------------------------------------------------------------------------------------
Income (Loss) from Continuing Operations before
      Income Taxes is Comprised of: (4)
------------------------------------------------------------------------------------------------------------------------
      Oil and Gas (1), (2)                                 196     247     476     193     372     330      56     319
------------------------------------------------------------------------------------------------------------------------
      Energy Marketing                                     166      30      69      54      42    (162)    139     182
------------------------------------------------------------------------------------------------------------------------
      Syncrude                                              20      19      59      59      77      78      51      50
------------------------------------------------------------------------------------------------------------------------
      Chemicals (3)                                         12       7      22      (2)     10     215       -      10
------------------------------------------------------------------------------------------------------------------------
      Corporate and Other                                  (66)   (286)    (92)    (55)   (171)   (230)   (142)   (128)
========================================================================================================================
                                                           328      17     534     249     330     231     104     433
========================================================================================================================

NET INCOME (LOSS) FROM CONTINUING
  OPERATIONS--CANADIAN GAAP (4)                            (83)     13     408     167     199     205      77     303
------------------------------------------------------------------------------------------------------------------------
US GAAP Adjustments                                        282      (5)    (11)     (9)   (283)     (9)    (10)     (7)
========================================================================================================================
NET INCOME (LOSS) FROM CONTINUING
  OPERATIONS--US GAAP                                      199       8     397     158     (84)    196      67     296
========================================================================================================================

NET INCOME (LOSS)--CANADIAN GAAP (4)                       (83)     31     408     197     199     609      77     303
------------------------------------------------------------------------------------------------------------------------
US GAAP Adjustments                                        282      (5)    (11)     (9)   (283)     (9)    (10)     (7)
========================================================================================================================
NET INCOME (LOSS)--US GAAP                                 199      26     397     188     (84)    600      67     296
========================================================================================================================

EARNINGS (LOSS) PER COMMON SHARE FROM CONTINUING OPERATIONS
   ($/share)
------------------------------------------------------------------------------------------------------------------------
      Canadian GAAP--Basic                               (0.32)   0.06    1.56    0.64    0.76    0.79    0.29    1.16
------------------------------------------------------------------------------------------------------------------------
      Canadian GAAP--Diluted                             (0.32)   0.06    1.53    0.63    0.74    0.77    0.29    1.13
------------------------------------------------------------------------------------------------------------------------
      US GAAP--Basic                                      0.76    0.03    1.52    0.61   (0.33)   0.75    0.26    1.13
------------------------------------------------------------------------------------------------------------------------
      US GAAP--Diluted                                    0.74    0.03    1.48    0.60   (0.33)   0.73    0.25    1.11
------------------------------------------------------------------------------------------------------------------------

EARNINGS (LOSS) PER COMMON
  SHARE ($/share)
------------------------------------------------------------------------------------------------------------------------
      Canadian GAAP--Basic                               (0.32)   0.13    1.56    0.76    0.76    2.34    0.29    1.16
------------------------------------------------------------------------------------------------------------------------
      Canadian GAAP--Diluted                             (0.32)   0.13    1.53    0.75    0.74    2.28    0.29    1.13
------------------------------------------------------------------------------------------------------------------------
      US GAAP--Basic                                      0.76    0.10    1.52    0.72   (0.33)   2.31    0.26    1.13
------------------------------------------------------------------------------------------------------------------------
      US GAAP--Diluted                                    0.74    0.10    1.48    0.71   (0.33)   2.25    0.25    1.11
------------------------------------------------------------------------------------------------------------------------

DIVIDENDS DECLARED (5)                                   0.05     0.05    0.05    0.05    0.05    0.05    0.05    0.05
========================================================================================================================

COMMON SHARE PRICES ($/share)
------------------------------------------------------------------------------------------------------------------------
  Toronto Stock Exchange--High                           68.10   35.50   69.50   39.85   71.22   60.67   65.79   59.54
------------------------------------------------------------------------------------------------------------------------
  Toronto Stock Exchange--Low                            54.34   23.55   50.82   29.53   52.13   40.25   52.91   43.77
------------------------------------------------------------------------------------------------------------------------
  New York Stock Exchange--High (US$)                    59.94   29.18   61.68   32.32   63.65   51.73   58.37   51.69
------------------------------------------------------------------------------------------------------------------------
  New York Stock Exchange--Low (US$)                     46.98   19.44   45.63   23.28   46.70   31.95   46.90   36.80
========================================================================================================================
</TABLE>
NOTES:
(1)   EXCLUDES RESULTS OF 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. THESE
      RESULTS  ARE  SHOWN  AS  DISCONTINUED  OPERATIONS  (SEE  NOTE  14 TO  THE
      CONSOLIDATED FINANCIAL STATEMENTS).
(2)   THE FOURTH QUARTER OF 2006 INCLUDES AN IMPAIRMENT  CHARGE OF $93 MILLION,
      PRIMARILY RELATING TO TWO NATURAL GAS PROPERTIES IN THE GULF OF MEXICO.
(3)   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.
(4)   INCLUDES  THE IMPACT OF CHANGES IN  ACCOUNTING  POLICIES AS  DESCRIBED IN
      NOTE 1(U) TO THE CONSOLIDATED FINANCIAL STATEMENTS.
(5)   IN FEBRUARY 2007, THE BOARD OF DIRECTORS DECLARED A QUARTERLY DIVIDEND OF
      $0.05 PER COMMON SHARE,  PAYABLE APRIL 1, 2007, TO SHAREHOLDERS OF RECORD
      ON MARCH 10, 2007.
(6)   AT  DECEMBER  31,  2006,  THERE WERE 1,454  REGISTERED  HOLDERS OF COMMON
      SHARES AND 262,513,206 COMMON SHARES OUTSTANDING.

                                      115
<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 is in bcf     OIL     GAS       OIL       OIL    GAS     BITUMEN    OIL      GAS    OIL   GAS          OIL
                                                                                    (2)
----------------------------------------------------------------------------------------------------------------------------------
<S>                                  <C>     <C>        <C>       <C>   <C>          <C>    <C>     <C>    <C>    <C>          <C>
PROVED DEVELOPED AND
  UNDEVELOPED RESERVES  (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
----------------------------------------------------------------------------------------------------------------------------------
  Extensions and Discoveries          52      89          1        1     54           -      2       26     23     9           25
----------------------------------------------------------------------------------------------------------------------------------
  Purchases of Reserves in Place       -       1          -        -      1           -      -        -      -     -            -
----------------------------------------------------------------------------------------------------------------------------------
  Sales of Reserves in Place           -       -          -        -      -           -      -        -      -     -            -
----------------------------------------------------------------------------------------------------------------------------------
  Revisions of Previous Estimates    231     (16)        (3)       3    (13)         219    (8)     (12)    19     9            1
----------------------------------------------------------------------------------------------------------------------------------
  Production                         (38)    (74)       (19)      (6)   (33)          -     (5)     (34)    (6)   (7)          (2)
==================================================================================================================================
DECEMBER 31, 2006                    549     532         38       48    314          219    30      195    179    23            35
==================================================================================================================================
PROVED DEVELOPED RESERVES (5)
----------------------------------------------------------------------------------------------------------------------------------
  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
----------------------------------------------------------------------------------------------------------------------------------
  DECEMBER 31, 2006                  286     460        33        44    287          40     28      161    131    12           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 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.

                                      116
<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 22 and 23. The net proved reserves represent  management's
best estimate of proved synthetic reserves after royalties.

      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 1,780 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  4,810  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
4,309 million tons at an average bitumen grade of 10.8 weight percent.

<TABLE>
<CAPTION>
                                                                         SYNTHETIC CRUDE OIL
                                                               BASE MINE
                                                               AND NORTH        AURORA (2)       TOTAL
(millions of barrels)                                              MINE (1)
--------------------------------------------------------------------------------------------------------
<S>                                                                    <C>           <C>           <C>
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
--------------------------------------------------------------------------------------------------------
                                                                        -             (4)           (4)
  Revision of Previous Estimates
--------------------------------------------------------------------------------------------------------
  Extensions and Discoveries                                            -             19            19
--------------------------------------------------------------------------------------------------------
  Production                                                           (3)            (3)           (6)
--------------------------------------------------------------------------------------------------------
DECEMBER 31, 2005                                                      47            217           264
--------------------------------------------------------------------------------------------------------

  Revision of Previous Estimates                                        1              4             5
--------------------------------------------------------------------------------------------------------
  Extensions and Discoveries                                            -             11            11
--------------------------------------------------------------------------------------------------------
  Production                                                           (3)            (3)           (6)
--------------------------------------------------------------------------------------------------------
DECEMBER 31, 2006                                                      45            229           274
========================================================================================================
</TABLE>
NOTES:
(1)  LEASES 17 AND 22
(2)  LEASES 10, 12, 31 AND 34.

                                      117
<PAGE>

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

                                                           PROVED     UNPROVED     ACCUMULATED   CAPITALIZED
(Cdn$ millions)                                         PROPERTIES  PROPERTIES            DD&A        COSTS
-------------------------------------------------------------------------------------------------------------
<S>                                                        <C>             <C>          <C>           <C>
DECEMBER 31, 2006
-------------------------------------------------------------------------------------------------------------
  Yemen                                                     2,404            -          (2,128)         276
-------------------------------------------------------------------------------------------------------------
  Canada                                                    3,787          227          (1,467)       2,547
-------------------------------------------------------------------------------------------------------------
  United States                                             2,768          121          (1,445)       1,444
-------------------------------------------------------------------------------------------------------------
  United Kingdom                                            4,325          385            (432)       4,278
-------------------------------------------------------------------------------------------------------------
  Other Countries                                              99          150             (78)         171
-------------------------------------------------------------------------------------------------------------
  TOTAL CAPITALIZED COSTS                                  13,383          883          (5,550)       8,716
=============================================================================================================

DECEMBER 31, 2005
-------------------------------------------------------------------------------------------------------------
  Yemen                                                     2,243            -          (1,841)         402
-------------------------------------------------------------------------------------------------------------
  Canada                                                    3,463          143          (1,330)       2,276
-------------------------------------------------------------------------------------------------------------
  United States                                             2,323          114          (1,159)       1,278
-------------------------------------------------------------------------------------------------------------
  United Kingdom                                            3,603          410            (216)       3,797
-------------------------------------------------------------------------------------------------------------
  Other Countries                                              88          161            (119)         130
-------------------------------------------------------------------------------------------------------------
  TOTAL CAPITALIZED COSTS                                  11,720          828          (4,665)       7,883
=============================================================================================================

DECEMBER 31, 2004
-------------------------------------------------------------------------------------------------------------
  Yemen                                                     2,022           16          (1,550)         488
-------------------------------------------------------------------------------------------------------------
  Canada                                                    3,732          136          (2,025)       1,843
-------------------------------------------------------------------------------------------------------------
  United States                                             2,102          147          (1,037)       1,212
-------------------------------------------------------------------------------------------------------------
  United Kingdom                                            3,117          382             (16)       3,483
-------------------------------------------------------------------------------------------------------------
  Other Countries                                             437           98            (408)         127
-------------------------------------------------------------------------------------------------------------
  TOTAL CAPITALIZED COSTS                                  11,410          779          (5,036)       7,153
=============================================================================================================
</TABLE>

<TABLE>
<CAPTION>
C.       COSTS INCURRED (EXCLUDING SYNCRUDE OPERATIONS)
                                                                                OIL AND GAS
                                                       TOTAL
                                                         OIL
                                                         AND                       UNITED      UNITED
(Cdn$ millions)                                          GAS     YEMEN    CANADA   STATES     KINGDOM   OTHER
---------------------------------------------------------------------------------------------------------------
<S>                                                    <C>       <C>      <C>      <C>        <C>       <C>
YEAR ENDED DECEMBER 31, 2006
---------------------------------------------------------------------------------------------------------------
  Property Acquisition Costs
---------------------------------------------------------------------------------------------------------------
      Proved                                              13         -        12        -           1       -
---------------------------------------------------------------------------------------------------------------
      Unproved                                           125         -       105       19           1       -
---------------------------------------------------------------------------------------------------------------
  Exploration Costs                                      514        37        74      242          71      90
---------------------------------------------------------------------------------------------------------------
  Development Costs                                    2,051       145       884      399         595      28
---------------------------------------------------------------------------------------------------------------
  Asset Retirement Costs                                  69         4         5        4          56       -
---------------------------------------------------------------------------------------------------------------
TOTAL COSTS INCURRED                                   2,772       186     1,080      664         724     118
===============================================================================================================

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
===============================================================================================================
</TABLE>

                                      118
<PAGE>

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

                                                                                  OIL AND GAS
                                                 TOTAL
                                                   OIL                                                  OTHER
                                                   AND             CANADA    UNITED      UNITED     COUNTRIES
(Cdn$ millions)                                    GAS     YEMEN       (1)   STATES     KINGDOM            (1)
--------------------------------------------------------------------------------------------------------------
<S>                                              <C>         <C>       <C>      <C>         <C>           <C>
YEAR ENDED DECEMBER 31, 2006
--------------------------------------------------------------------------------------------------------------
  Net Sales                                      3,032     1,328       459      629         477          139
--------------------------------------------------------------------------------------------------------------
  Production Costs                                 491       151       146      106          80            8
--------------------------------------------------------------------------------------------------------------
  Exploration Expense                              362         4        26      214          46           72
--------------------------------------------------------------------------------------------------------------
  Depreciation, Depletion,
      Amortization and Impairment                1,011       327       162      296         216           10
--------------------------------------------------------------------------------------------------------------
  Other Expenses (Income)                           71        15       106      (23)        (71)          44
--------------------------------------------------------------------------------------------------------------
                                                 1,097       831        19       36         206            5
--------------------------------------------------------------------------------------------------------------
  Income Tax Provision                             687       289         6       13         378            1
--------------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS                              410       542        13       23        (172)           4
==============================================================================================================

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                                   106         4        38       19           -           45
--------------------------------------------------------------------------------------------------------------
                                                 1,037       637       167      290           9          (66)
--------------------------------------------------------------------------------------------------------------
  Income Tax Provision                             406       222        75      104           4            1
--------------------------------------------------------------------------------------------------------------
RESULTS OF OPERATIONS                              631       415        92      186           5          (67)
==============================================================================================================
</TABLE>
NOTE:
(1)  2005 AND 2004 INCLUDE RESULTS OF DISCONTINUED OPERATIONS (SEE NOTE 14).

                                      119
<PAGE>

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.


                                      120
<PAGE>

<TABLE>
<CAPTION>
                                                                              UNITED      UNITED       OTHER
(Cdn$ millions)                                   TOTAL     YEMEN    CANADA   STATES     KINGDOM   COUNTRIES
--------------------------------------------------------------------------------------------------------------
<S>                                               <C>       <C>       <C>      <C>         <C>           <C>
DECEMBER 31, 2006
--------------------------------------------------------------------------------------------------------------
  Future Cash Inflows                            32,247     2,330    12,678    3,151      11,437       2,651
--------------------------------------------------------------------------------------------------------------
  Future Production Costs                         9,523       606     5,615      791       2,236         275
--------------------------------------------------------------------------------------------------------------
  Future Development Costs                        3,190       115     1,156      332         891         696
--------------------------------------------------------------------------------------------------------------
  Future Dismantlement and Site
    Restoration Costs, Net                        1,006        11       289      197         471          38
--------------------------------------------------------------------------------------------------------------
  Future Income Tax                               5,204       489       753      450       3,308         204
==============================================================================================================
  Future Net Cash Flows                          13,324     1,109     4,865    1,381       4,531       1,438
--------------------------------------------------------------------------------------------------------------
  10% Discount Factor                             4,951       106     2,484      321         970       1,070
--------------------------------------------------------------------------------------------------------------
STANDARDIZED MEASURE                              8,373     1,003     2,381    1,060       3,561         368
==============================================================================================================

--------------------------------------------------------------------------------------------------------------
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
==============================================================================================================
</TABLE>

CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

      The  following are the  principal  sources of change in the  standardized
measure of discounted future net cash flows:

<TABLE>
<CAPTION>
(Cdn$ millions)                                                                 2006        2005        2004
--------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>         <C>         <C>
Beginning of Year                                                              8,042       6,290       5,517
--------------------------------------------------------------------------------------------------------------
  Sales and Transfers of Oil and Gas Produced, Net of Production Costs        (2,291)     (2,028)     (1,674)
--------------------------------------------------------------------------------------------------------------
  Net Changes in Prices and Production Costs Related to Future Production     (1,065)      3,302         142
--------------------------------------------------------------------------------------------------------------
  Extensions, Discoveries and Improved Recovery, Less Related Costs 1            695         977         (71)
--------------------------------------------------------------------------------------------------------------
  Changes in Estimated Future Development and Dismantlement Costs               (692)       (135)       (122)
--------------------------------------------------------------------------------------------------------------
  Previous Estimated Future Development and Dismantlement Costs
     Incurred During The Period                                                1,048         638         604
--------------------------------------------------------------------------------------------------------------
  Revisions of Previous Quantity Estimates                                     1,936         478        (223)
--------------------------------------------------------------------------------------------------------------
  Accretion of Discount                                                        1,117         799         692
--------------------------------------------------------------------------------------------------------------
  Purchases of Reserves in Place                                                   2          15       1,764
--------------------------------------------------------------------------------------------------------------
  Sales of Reserves in Place                                                      (2)       (882)        (20)
--------------------------------------------------------------------------------------------------------------
  Net Change in Income Taxes                                                    (417)     (1,412)       (319)
--------------------------------------------------------------------------------------------------------------
END OF YEAR                                                                    8,373       8,042       6,290
==============================================================================================================
</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>

                                    PART IV
               ITEM 15.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES

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 WITH THIS FORM 10-K.


                                      122
<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)




                                      123