==============================================================================

                                 UNITED STATES
                      SECURITIES AND EXCHANGE COMMISSION
                            WASHINGTON, D.C. 20549


                                   FORM 10-Q


|X|    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
       EXCHANGE ACT OF 1934
       For the quarterly period ended June 30, 2006

|_|    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
       EXCHANGE ACT OF 1934
       For the transition period from ____________ to ___________

                         COMMISSION FILE NUMBER 1-6702

                              [GRAPHIC OMITTED]

                              [LOGO - 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


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 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, there were 262,142,876 common shares issued and outstanding.

==============================================================================
<PAGE>


                                  NEXEN INC.
                                     INDEX

PART I         FINANCIAL INFORMATION                                       PAGE

    Item 1.    Unaudited Consolidated Financial Statements ...................3

    Item 2.    Management's Discussion and Analysis of Financial Condition
               and Results of Operations.....................................28

    Item 3.    Quantitative and Qualitative Disclosures about Market Risk....47

    Item 4.    Controls and Procedures.......................................47

PART II        OTHER INFORMATION

    Item 4.    Submission of Matters to a Vote of Security Holders...........48

    Item 6.    Exhibits......................................................48

This report should be read in conjunction  with our 2005 Annual Report on Form
10-K and with our current  reports on Form 8-K filed or  furnished on February
17, March 22, April 27, June 13 and July 5, 2006.


SPECIAL NOTE TO CANADIAN INVESTORS

Nexen is a US Securities and Exchange  Commission  (SEC) registrant and a Form
10-K and related forms filer. Therefore, our reserves estimates and securities
regulatory  disclosures  generally follow SEC requirements.  In 2004,  certain
Canadian regulatory authorities adopted NATIONAL INSTRUMENT 51-101 - STANDARDS
OF DISCLOSURE  FOR OIL AND GAS  ACTIVITIES  (NI 51-101) which  prescribe  that
Canadian companies follow certain standards for the preparation and disclosure
of reserves and related  information.  We have been granted certain exemptions
from NI 51-101. Please refer to the SPECIAL NOTE TO CANADIAN INVESTORS on page
80 of our 2005 Annual Report on Form 10-K.

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  PRESENTED  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-Q.

<TABLE>
<S>                                                  <C>
/d        =   per day                                mboe     =   thousand barrels of oil equivalent
bbl       =   barrel                                 mmboe    =   million barrels of oil equivalent
mbbls     =   thousand barrels                       mcf      =   thousand cubic feet
mmbbls    =   million barrels                        mmcf     =   million cubic feet
mmbtu     =   million British thermal units          bcf      =   billion cubic feet
boe       =   barrels of oil equivalent              tcf      =   trillion cubic feet
NGL       =   natural gas liquid                     SAGD     =   steam-assisted gravity drainage
WTI       =   West Texas Intermediate                CBM      =   coalbed methane
                                                     Gj       =   gigajoule
</TABLE>

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

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

On June 30, 2006,  the noon-day  exchange rate was US$0.8969 for Cdn$1.00,  as
reported by the Bank of Canada.

                                      2
<PAGE>

                                    PART I


ITEM 1.  UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


                               TABLE OF CONTENTS

                                                                          Page

Unaudited Consolidated Statement of Income
for the Three and Six Months Ended June 30, 2006 and 2005....................4

Unaudited Consolidated Balance Sheet
as at June 30, 2006 and December 31, 2005....................................5

Unaudited Consolidated Statement of Cash Flows
for the Three and Six Months Ended June 30, 2006 and 2005....................6

Unaudited Consolidated Statement of Shareholders' Equity
for the Three and Six Months Ended June 30, 2006 and 2005....................7

Notes to Unaudited Consolidated Financial Statements.........................8




                                      3
<PAGE>

<TABLE>
<CAPTION>
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
Cdn$ millions, except per share amounts

                                                                   Three Months          Six Months
                                                                   Ended June 30       Ended June 30
                                                                   2006     2005       2006     2005
-----------------------------------------------------------------------------------------------------
<S>                                                               <C>      <C>        <C>      <C>
REVENUES AND OTHER INCOME
    Net Sales                                                     1,039      909      2,019    1,765
    Marketing and Other (Note 15)                                   376      242        802      309
                                                                 ------------------------------------
                                                                  1,415    1,151      2,821    2,074
                                                                 ------------------------------------
EXPENSES
    Operating                                                       223      216        473      429
    Depreciation, Depletion, Amortization and Impairment            260      253        526      492
    Transportation and Other                                        203      169        463      372
    General and Administrative                                      111      124        325      305
    Exploration                                                      46      105        149      132
    Interest (Note 8)                                                11       31         20       65
                                                                 ------------------------------------
                                                                    854      898      1,956    1,795
                                                                 ------------------------------------

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES               561      253        865      279
                                                                 ------------------------------------

PROVISION FOR INCOME TAXES
    Current                                                         136       81        245      160
    Future (Note 19)                                                 13        2        284      (70)
                                                                 ------------------------------------
                                                                    149       83        529       90
                                                                 ------------------------------------

NET INCOME FROM CONTINUING OPERATIONS
   BEFORE NON-CONTROLLING INTERESTS                                 412      170        336      189
    Net Income Attributable to Non-Controlling Interests              6       --          9       --
                                                                 ------------------------------------

NET INCOME FROM CONTINUING OPERATIONS                               406      170        327      189
    Net Income from Discontinued Operations (Note 16)                --       30         --       48
                                                                 ------------------------------------

NET INCOME                                                          406      200        327      237
                                                                 ====================================

EARNINGS PER COMMON SHARE FROM CONTINUING OPERATIONS ($/share)
    Basic (Note 13)                                                1.55     0.65       1.25     0.73
                                                                 ====================================

    Diluted (Note 13)                                              1.52     0.64       1.22     0.72
                                                                 ====================================

EARNINGS PER COMMON SHARE ($/share)
    Basic (Note 13)                                                1.55     0.77       1.25     0.91
                                                                 ====================================

    Diluted (Note 13)                                              1.52     0.76       1.22     0.90
                                                                 ====================================
</TABLE>

SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.

                                      4
<PAGE>

<TABLE>
<CAPTION>
NEXEN INC.
UNAUDITED CONSOLIDATED BALANCE SHEET
Cdn$ millions, except share amounts

                                                                             June 30   December 31
                                                                                2006          2005
---------------------------------------------------------------------------------------------------
<S>                                                                           <C>            <C>
ASSETS
    CURRENT ASSETS
      Cash and Cash Equivalents                                                  86             48
      Restricted Cash and Margin Deposits                                        58             70
      Accounts Receivable (Note 4)                                            2,388          3,151
      Inventories and Supplies (Note 5)                                         745            504
      Other                                                                      29             51
                                                                            -----------------------
         Total Current Assets                                                 3,306          3,824
                                                                            -----------------------

    PROPERTY, PLANT AND EQUIPMENT
      Net of Accumulated Depreciation, Depletion, Amortization and
         Impairment of $5,703 (December 31, 2005 - $5,468) (Note 7)          10,335          9,594
    FUTURE INCOME TAX ASSETS                                                    656            410
    DEFERRED CHARGES AND OTHER ASSETS (Note 6)                                  309            398
    GOODWILL                                                                    362            364
                                                                            -----------------------

                                                                             14,968         14,590
                                                                            =======================
LIABILITIES AND SHAREHOLDERS' EQUITY
    CURRENT LIABILITIES
      Short-Term Borrowings (Note 8)                                             87             --
      Accounts Payable and Accrued Liabilities                                2,990          3,710
      Accrued Interest Payable                                                   52             55
      Dividends Payable                                                          13             13
                                                                            -----------------------
         Total Current Liabilities                                            3,142          3,778
                                                                            -----------------------

    LONG-TERM DEBT (Note 8)                                                   3,929          3,687
    FUTURE INCOME TAX LIABILITIES                                             2,438          1,960
    ASSET RETIREMENT OBLIGATIONS (Note 9)                                       621            590
    DEFERRED CREDITS AND OTHER LIABILITIES (Note 10)                            446            479
    NON-CONTROLLING INTERESTS (Note 2)                                           84             88

    SHAREHOLDERS' EQUITY
      Common Shares, no par value
        Authorized:        Unlimited
        Outstanding:       2006 - 262,142,876 shares
                           2005 - 261,140,571 shares                            799            732
      Contributed Surplus                                                         3              2
      Retained Earnings                                                       3,736          3,435
      Cumulative Foreign Currency Translation Adjustment                       (230)          (161)
                                                                            -----------------------
         Total Shareholders' Equity                                           4,308          4,008
                                                                            -----------------------

COMMITMENTS, CONTINGENCIES AND GUARANTEES (Note 17)
                                                                             14,968         14,590
                                                                            =======================
</TABLE>

SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.

                                      5
<PAGE>

<TABLE>
<CAPTION>
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
Cdn$ millions

                                                                    Three Months           Six Months
                                                                    Ended June 30         Ended June 30
                                                                   2006      2005        2006      2005
--------------------------------------------------------------------------------------------------------
<S>                                                                <C>       <C>         <C>       <C>
 OPERATING ACTIVITIES
    Net Income from Continuing Operations                           406       170         327       189
    Net Income from Discontinued Operations                          --        30          --        48
    Charges and Credits to Income not Involving Cash (Note 14)      295       335         963       808
    Exploration Expense                                              46       105         149       132
    Changes in Non-Cash Working Capital (Note 14)                  (377)      (43)       (304)      (96)
    Other                                                             4        (6)        (27)      (48)
                                                                 ---------------------------------------
                                                                    374       591       1,108     1,033

FINANCING ACTIVITIES
    Proceeds from (Repayment of) Term Credit Facilities, Net        417       124         413       262
    Proceeds from Long-Term Debt                                     --        --          --     1,253
    Repayment of Long-Term Debt                                      --        --          --    (1,241)
    Proceeds from (Repayment of) Short-Term Borrowings, Net          50       (41)         85       (51)
    Dividends on Common Shares (Note 12)                            (13)      (13)        (26)      (26)
    Issue of Common Shares and Exercise of Stock Options             24         8          37        40
    Other                                                            (7)       --         (14)      (16)
                                                                 ---------------------------------------
                                                                    471        78         495       221

INVESTING ACTIVITIES
    Capital Expenditures
      Exploration and Development                                  (767)     (651)     (1,486)   (1,245)
      Proved Property Acquisitions                                   --        (5)         (3)       (6)
      Chemicals, Corporate and Other                                (52)      (20)        (62)      (24)
    Business Acquisitions, Net of Cash Acquired (Note 3)            (57)       --         (78)       --
    Proceeds on Disposition of Assets                                25         5          25         7
    Changes in Restricted Cash and Margin Deposits                   66        --          12        --
    Changes in Non-Cash Working Capital (Note 14)                    36        41          59        27
    Other                                                           (11)       (9)         (4)        7
                                                                 ---------------------------------------
                                                                   (760)     (639)     (1,537)   (1,234)


EFFECT OF EXCHANGE RATE CHANGES ON CASH
    AND CASH EQUIVALENTS                                            (29)        2         (28)        9
                                                                 ---------------------------------------

INCREASE IN CASH AND CASH EQUIVALENTS                                56        32          38        29

CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD                      30        70          48        73
                                                                 ---------------------------------------

CASH AND CASH EQUIVALENTS - END OF PERIOD                            86       102          86       102
                                                                 =======================================
</TABLE>

SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.

                                      6
<PAGE>

<TABLE>
<CAPTION>
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
Cdn$ millions

                                                                            Three Months            Six Months
                                                                            Ended June 30          Ended June 30
                                                                            2006      2005        2006      2005
-----------------------------------------------------------------------------------------------------------------
<S>                                                                         <C>       <C>         <C>       <C>
COMMON SHARES
    Balance at Beginning of Period                                           763       684         732       637
    Issue of Common Shares                                                    21         8          26        40
    Exercise of Stock Options                                                  3        --          11        --
    Previously Recognized Liability Relating to Stock Options Exercised       12         2          30        17
                                                                          ---------------------------------------
    Balance at End of Period                                                 799       694         799       694
                                                                          =======================================

CONTRIBUTED SURPLUS
    Balance at Beginning of Period                                             2         1           2        --
    Stock-Based Compensation Expense                                           1        --           1         1
                                                                          ---------------------------------------
    Balance at End of Period                                                   3         1           3         1
                                                                          =======================================

RETAINED EARNINGS
    Balance at Beginning of Period                                         3,343     2,359       3,435     2,335
    Net Income                                                               406       200         327       237
    Dividends on Common Shares (Note 12)                                     (13)      (13)        (26)      (26)
                                                                          ---------------------------------------
    Balance at End of Period                                               3,736     2,546       3,736     2,546
                                                                          =======================================

CUMULATIVE FOREIGN CURRENCY TRANSLATION ADJUSTMENT
    Balance at Beginning of Period                                          (167)      (95)       (161)     (105)
    Translation Adjustment, Net of Income Taxes                              (63)       13         (69)       23
                                                                          ---------------------------------------
    Balance at End of Period                                                (230)      (82)       (230)      (82)
                                                                          =======================================
</TABLE>

SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.


                                      7
<PAGE>

NEXEN INC.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Cdn$ millions except as noted

1.   ACCOUNTING POLICIES

Our Unaudited 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
Unaudited  Consolidated  Financial  Statements  is disclosed in Note 21. In the
opinion of management,  the Unaudited Consolidated Financial Statements contain
all  adjustments of a normal and recurring  nature  necessary to present fairly
Nexen Inc.'s  (Nexen,  we or our)  financial  position at June 30, 2006 and the
results of our operations and our cash flows for the three and six months ended
June 30, 2006 and 2005.

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 Unaudited Consolidated  Financial Statements,  and revenues and expenses
during the reporting period. Our management reviews these estimates,  including
those  related to  accruals,  litigation,  environmental  and asset  retirement
obligations,  income taxes and 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.  The results of operations and
cash flows for the three and six months ended June 30, 2006 are not necessarily
indicative  of the results of  operations  or cash flows to be expected for the
year ending December 31, 2006.

The note disclosure  requirements for annual consolidated  financial statements
provide  additional  disclosure  to  that  required  for  interim  consolidated
financial  statements.  Accordingly,  these  Unaudited  Consolidated  Financial
Statements  should  be  read  in  conjunction  with  our  Audited  Consolidated
Financial  Statements  included  in our 2005  Annual  Report on Form 10-K.  The
accounting  policies  we  follow  are  described  in  Note  1  of  the  Audited
Consolidated  Financial  Statements  included in our 2005 Annual Report on Form
10-K.

RECLASSIFICATION
Certain  comparative  figures have been reclassified to ensure consistency with
current period presentation.

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.

                                      8
<PAGE>

Our interest in Canexus LP is greater than 50%. As a result,  we have the right
to  nominate a majority  of the  members of the board of Canexus  Limited,  the
corporation with  responsibility  for the strategic  management and operational
decisions of Canexus and Canexus LP. Nexen has nominated two representatives to
the  10-member  board of  Canexus  Limited.  Since we have  retained  effective
control of our chemicals business, the results,  assets and liabilities of this
business  have been  included  in these  financial  statements.  The  non-Nexen
ownership  interests in our  chemicals  business  are shown as  non-controlling
interests.

During the three and six month  periods ended June 20, 2006, $7 million and $14
million  respectively,  of  distributions  were  paid  to  non-Nexen  ownership
interests.

3.   BUSINESS ACQUISITIONS

We  completed  minor  business  acquisitions  in the  first  half of  2006  for
consideration of $78 million,  net of cash acquired.  These  acquisitions  were
accounted for using the purchase method of accounting and we recorded  goodwill
of $12 million.

4.   ACCOUNTS RECEIVABLE

<TABLE>
<CAPTION>
                                                                   June 30      December 31
(Cdn$ millions)                                                       2006             2005
--------------------------------------------------------------------------------------------
<S>                                                                   <C>            <C>
Trade
    Marketing                                                         1,702          2,400
    Oil and Gas                                                         584            614
    Chemicals and Other                                                  58             48
                                                                  --------------------------
                                                                      2,344          3,062
Non-Trade                                                                51             96
                                                                  --------------------------
                                                                      2,395          3,158
Allowance for Doubtful Accounts                                          (7)            (7)
                                                                  --------------------------
Total                                                                 2,388          3,151
                                                                  ==========================

5.   INVENTORIES AND SUPPLIES

                                                                   June 30      December 31
(Cdn$ millions)                                                       2006             2005
--------------------------------------------------------------------------------------------
Finished Products
    Marketing                                                           559            320
    Oil and Gas                                                           4             11
    Chemicals and Other                                                  14             15
                                                                  --------------------------
                                                                        577            346
Work in Process                                                           5              6
Field Supplies                                                          163            152
                                                                  --------------------------
Total                                                                   745            504
                                                                  ==========================

6.   DEFERRED CHARGES AND OTHER ASSETS

                                                                   June 30      December 31
(Cdn$ millions)                                                       2006             2005
--------------------------------------------------------------------------------------------
Long-Term Marketing Derivative Contracts (Note 11)                      131            232
Deferred Financing Costs                                                 61             63
Crude Oil Put Options (Note 11)                                          29              4
Asset Retirement Remediation Fund (Note 9)                               13             14
Other                                                                    75             85
                                                                  --------------------------
Total                                                                   309            398
                                                                  ==========================
</TABLE>

                                      9
<PAGE>

7.   SUSPENDED WELL COSTS

The following  table shows the changes in  capitalized  exploratory  well costs
included in  property,  plant and  equipment  during the six month period ended
June 30,  2006 and the year  ended  December  31,  2005,  and does not  include
amounts that were initially  capitalized and subsequently  expensed in the same
period.

<TABLE>
<CAPTION>
                                                                   June 30      December 31
(Cdn$ millions)                                                       2006             2005
--------------------------------------------------------------------------------------------
<S>                                                                    <C>              <C>
Balance at Beginning of Period                                         252              116
    Additions to Capitalized Exploratory Well Costs Pending the
      Determination of Proved Reserves                                 172              174
    Capitalized Exploratory Well Costs Charged to Expense              (33)             (27)
    Transfers to Wells, Facilities and Equipment Based on
      Determination of Proved Reserves                                  (8)              (3)
    Effects of Foreign Exchange                                        (11)              (8)
                                                                  --------------------------
Balance at End of Period                                               372              252
                                                                  ==========================
</TABLE>

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

<TABLE>
<CAPTION>
                                                                   June 30      December 31
(Cdn$ millions)                                                       2006             2005
--------------------------------------------------------------------------------------------
<S>                                                                     <C>            <C>
    Capitalized for a Period of One Year or Less                        240            165
    Capitalized for a Period of Greater than One Year                   132             87
                                                                  --------------------------
Balance at End of Period                                                372            252
                                                                  ==========================
Number of Projects that have Exploratory Well Costs Capitalized
    for a Period Greater than One Year                                    5              3
                                                                  --------------------------
</TABLE>

As at June 30, 2006, we have  exploratory  costs that have been capitalized for
more than one year relating to our interest in an exploratory  block,  offshore
Nigeria ($76 million), our interests in three exploratory blocks in the Gulf of
Mexico ($45 million) and coal bed methane exploratory activities in Canada ($11
million). Exploratory costs offshore Nigeria were first capitalized in 1998 and
we have subsequently drilled a further seven successful wells on the block. The
joint venture partners have finalized  pre-development  design studies and have
submitted  a  field  development  plan  for  government  approval.  When  final
regulatory approvals are received and the project has been sanctioned,  we will
book proved  reserves.  We have  capitalized  costs related to successful wells
drilled in 2004,  2005 and 2006 in the Gulf of Mexico,  and in Canada,  we have
capitalized exploratory costs relating to our coal bed methane projects. We are
currently  assessing all of these wells and  projects,  and we are working with
our partners to prepare development plans.

<TABLE>
<CAPTION>
8.   LONG-TERM DEBT AND SHORT-TERM BORROWINGS

                                                                   June 30      December 31
(Cdn$ millions)                                                       2006             2005
--------------------------------------------------------------------------------------------
<S>                                                                      <C>            <C>
Canexus LP Term Credit Facilities (US$146 million drawn)                 163            171
Term Credit Facilities (US$350 million drawn)                            390             --
Debentures, due 2006 (1)                                                  91             93
Medium-Term Notes, due 2007                                              150            150
Medium-Term Notes, due 2008                                              125            125
Notes, due 2013 (US$500 million)                                         557            583
Notes, due 2015 (US$250 million)                                         279            292
Notes, due 2028 (US$200 million)                                         223            233
Notes, due 2032 (US$500 million)                                         557            583
Notes, due 2035 (US$790 million)                                         881            921
Subordinated Debentures, due 2043 (US$460 million)                       513            536
                                                                  --------------------------
                                                                       3,929          3,687
                                                                  ==========================
</TABLE>
Note:
(1)  Includes $50 million of principal that was effectively converted through a
     currency exchange contract to US$37 million.

                                      10
<PAGE>

<TABLE>
<CAPTION>
(a)  INTEREST EXPENSE

                                                    Three Months           Six Months
                                                   Ended June 30           Ended June 30
(Cdn$ millions)                                   2006        2005        2006        2005
-------------------------------------------------------------------------------------------
<S>                                                 <C>         <C>        <C>         <C>
Long-Term Debt                                      65          70         127         132
Other                                                6           4          10           9
                                                  -----------------------------------------
                                                    71          74         137         141
   Less: Capitalized                               (60)        (43)       (117)        (76)
                                                  -----------------------------------------
Total                                               11          31          20          65
                                                  =========================================
</TABLE>

Capitalized  interest relates to and is included as part of the cost of our oil
and gas and  Syncrude  properties.  The  capitalization  rates are based on our
weighted-average cost of borrowings.

(b)  SHORT-TERM BORROWINGS

Nexen has  uncommitted,  unsecured  credit  facilities  of  approximately  $731
million,  $87 million of which was drawn at June 30, 2006  (December 31, 2005 -
nil).  We have  also  utilized  $69  million  of these  facilities  to  support
outstanding  letters  of  credit at June 30,  2006  (December  31,  2005 - $468
million),  principally relating to our marketing business.  Interest is payable
at  floating  rates.  The  weighted  average  interest  rate on our  short-term
borrowings  was 5.4% for the three months ended June 30, 2006 (2005 - 3.5%) and
5.3% for the six months ended June 30, 2006 (2005 - 3.2%).

(c)  TERM CREDIT FACILITIES

At June 30, 2006, we had committed,  unsecured  term credit  facilities of $2.3
billion,  which are available to 2010. At June 30, 2006,  US$350  million ($390
million) was drawn on these  facilities  (December 31, 2005 - nil).  Borrowings
are available as Canadian bankers'  acceptances,  LIBOR-based  loans,  Canadian
prime  loans,  US-dollar  base rate loans or  British  pound  call-rate  loans.
Interest is payable monthly at floating rates.  The weighted  average  interest
rate on our term credit facilities was 5.7% for the three months ended June 30,
2006  (2005 - 4.0%) and 5.5% for the six  months  ended  June 30,  2006 (2005 -
4.4%).  At June 30, 2006,  $157 million of these  facilities  were  utilized to
support  outstanding  letters of credit  (December  31,  2005 - $250  million),
principally relating to our marketing business.

9.   ASSET RETIREMENT OBLIGATIONS

Changes in carrying amounts of the asset retirement obligations associated with
our  property,  plant and  equipment for the six months ended June 30, 2006 and
the year ended December 31, 2005, are as follows:

<TABLE>
<CAPTION>
                                                                   June 30      December 31
(Cdn$ millions)                                                       2006             2005
--------------------------------------------------------------------------------------------
<S>                                                                    <C>              <C>
Balance at Beginning of Period                                         611              468
    Obligations Assumed with Development Activities                     25               72
    Obligations Discharged with Disposed Properties                     (1)             (37)
    Expenditures Made on Asset Retirements                              (8)             (34)
    Accretion                                                           18               26
    Revisions to Estimates                                              (2)             138
    Effects of Foreign Exchange                                         (1)             (22)
                                                                  --------------------------
Balance at End of Period (1,2)                                         642              611
                                                                  ==========================
</TABLE>

Notes:
(1) Obligations  due within 12 months of $21 million  (December  31, 2005 - $21
    million) have been included in accounts payable and accrued liabilities.
(2) Obligations  relating to our oil and gas activities  amount to $594 million
    (December  31,  2005  -  $564  million)  and  obligations  relating  to our
    chemicals business amount to $48 million (December 31, 2005 - $47 million).


Our total estimated  undiscounted asset retirement obligations amount to $1,547
million  (December 31, 2005 - $1,471  million).  We have  discounted  the total
estimated   asset   retirement    obligations    using   a    weighted-average,
credit-adjusted  risk-free rate of 5.7%.  Approximately $79 million included in
our asset retirement  obligations will be settled over the next five years. The
remaining  obligations  settle  beyond  five years and will be funded by future
cash flows from our operations.

In connection with the sale of our chemicals business in 2005 to Canexus LP, we
contributed  $14  million to a  remediation  fund which is being used for asset
retirement  obligations  associated with the assets sold. We have included this
on our  Unaudited  Consolidated  Balance  Sheet as  deferred  charges and other
assets.

                                      11
<PAGE>

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.

<TABLE>
<CAPTION>
10.  DEFERRED CREDITS AND OTHER LIABILITIES

                                                                   June 30      December 31
(Cdn$ millions)                                                       2006             2005
--------------------------------------------------------------------------------------------
<S>                                                                    <C>             <C>
Fixed-Price Natural Gas Contracts (Note 11)                             92              128
Deferred Transportation                                                 91               87
Long-Term Marketing Derivative Contracts (Note 11)                      86              124
Stock-Based Compensation Liability                                      40               53
Defined Benefit Pension Obligation                                      42               39
Other                                                                   95               48
                                                                  --------------------------
Total                                                                  446              479
                                                                  ==========================
</TABLE>

11.  DERIVATIVE INSTRUMENTS AND FINANCIAL RISK MANAGEMENT

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

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

<TABLE>
<CAPTION>
(Cdn$ millions)                                          JUNE 30, 2006                        DECEMBER 31, 2005
--------------------------------------------------------------------------------    -----------------------------------
                                            Carrying       Fair    Unrecognized     Carrying     Fair     Unrecognized
                                               Value      Value     Gain/(Loss)        Value    Value      Gain/(Loss)
                                           -------------------------------------    -----------------------------------
<S>                                             <C>        <C>              <C>          <C>     <C>             <C>
Commodity Price Risk
    Non-Trading Activities
      Crude Oil Put Options                       29         29              --            4        4             --
      Fixed Price Natural Gas Contracts         (119)      (119)             --         (175)    (175)            --
      Natural Gas Swaps                           (3)        (3)             --           29       29             --

    Trading Activities
      Crude Oil and Natural Gas                  231        231              --          161      161             --
      Future Sale of Gas Inventory                --          6               6           --      (35)           (35)

Foreign Currency Risk
    Non-Trading Activities                        13         13              --           14       14             --
    Trading Activities                             5          5              --            8        8             --
                                           -------------------------------------    -----------------------------------
Total Derivatives                                156        162               6           41        6            (35)
                                           =====================================    ===================================

Financial Assets and Liabilities
      Long-Term Debt                          (3,929)    (3,862)            67        (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 and
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

                                      12
<PAGE>

our oil production in 2005 and 2006. These options  establish an annual average
WTI floor price of  US$43/bbl  in 2005 and  US$38/bbl in 2006 at a cost of $144
million. The 2005 WTI crude oil put options were not used and have expired. The
2006 and 2007 WTI crude oil put options are stated at fair value on our balance
sheet.  Any  change in fair value is  included  in  marketing  and other on the
Unaudited Consolidated Statement of Income.

<TABLE>
<CAPTION>
                                      Notional                                 Average             Fair
                                       Volumes                    Term           Price            Value
--------------------------------------------------------------------------------------------------------
                                      (bbls/d)                                (US$/bbl)  (Cdn$ millions)
<S>                                     <C>                       <C>               <C>              <C>
WTI Crude Oil Put Options               30,000                    2006              39               --
                                        20,000                    2006              38               --
                                        10,000                    2006              36               --
                                       105,000                    2007              50               29
                                                                                         ---------------
                                                                                                     29
                                                                                         ===============
</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.  Since these contracts are no longer used in
the   normal   course   of  our  oil  and  gas   operations,   they  have  been
marked-to-market and are included in the Unaudited  Consolidated Balance Sheet.
Any change in fair value is included in  marketing  and other in the  Unaudited
Consolidated Statement of Income.

<TABLE>
<CAPTION>
                                      Notional                                 Average             Fair
                                       Volumes                    Term           Price            Value
--------------------------------------------------------------------------------------------------------
                                        (Gj/d)                                   ($/Gj)  (Cdn$ millions)
<S>                                     <C>                <C>             <C>                     <C>
Fixed-Price Natural Gas Contracts       15,514             2006 - 2007     2.28 - 2.47              (27)
                                        15,514             2007 - 2010     2.47 - 2.77              (92)
                                                                                         ---------------
                                                                                                   (119)
                                                                                         ===============
</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 sales  contracts.  Any change in fair value is  included in  marketing  and
other in the Unaudited Consolidated Statement of Income.

<TABLE>
<CAPTION>
                                      Notional                                 Average             Fair
                                       Volumes                    Term           Price            Value
--------------------------------------------------------------------------------------------------------
                                        (Gj/d)                                  ($/Gj)   (Cdn$ millions)
<S>                                     <C>                <C>            <C>                       <C>
Natural Gas Swaps                       15,514             2006 - 2007    9.17 - 10.59               (9)
                                        15,514             2007 - 2010            7.60                6
                                                                                         ---------------
                                                                                                     (3)
                                                                                         ===============
</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 $231 million fair value of the derivative contracts
at June 30, 2006 is included in the  Unaudited  Consolidated  Balance Sheet and
any change is included in  marketing  and other in the  Unaudited  Consolidated
Statement of Income.

FUTURE SALE OF GAS INVENTORY
We have certain NYMEX futures  contracts and swaps in place,  which effectively
lock in our margins on the future sale of our natural gas inventory in storage.
We have designated, in writing, some of these derivative contracts as cash flow
hedges of the future  sale of our  storage  inventory.  As a result,  gains and
losses on these  designated  futures  contracts and swaps are recognized in net
income when the  inventory  in storage is sold.  The  principal  terms of these
outstanding contracts and the unrecognized gains at June 30, 2006 are:

<TABLE>
<CAPTION>
                                       Hedged                            Average     Unrecognized
                                      Volumes              Month           Price             Gain
--------------------------------------------------------------------------------------------------
                                       (mmcf)                          (US$/mcf)   (Cdn$ millions)
<S>                                    <C>          <C>                    <C>                <C>
NYMEX Natural Gas Futures              27,190       January 2007           10.61                6
                                                                                  ----------------
                                                                                                6
                                                                                  ================
</TABLE>

                                      13
<PAGE>

(c)  FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT

<TABLE>
<CAPTION>
NON-TRADING ACTIVITIES

                                                                                                                         Fair
                                                                        Amount            Term           Rate           Value
------------------------------------------------------------------------------------------------------------------------------
                                                                                                (for US$1.00)   (Cdn$ millions)
<S>                                                <C>                             <C>           <C>                      <C>
Foreign Currency Call Options - Buzzard (i)          (British pound)49 million            2006           2.00               --
Canadian Dollar Call Options - Canexus (ii)        US$9.5 million/US$5 million     2006 - 2007   0.813 - 0.85                4
Foreign Currency Swap (iii)                                      US$37 million            2006          0.736                9
                                                                                                                --------------
                                                                                                                            13
                                                                                                                ==============
</TABLE>

(i)  FOREIGN CURRENCY CALL OPTIONS - BUZZARD
Our  Buzzard  development  project in the North Sea  creates  foreign  currency
exposure as a portion of the capital costs are  denominated  in British  pounds
and Euros. To reduce our exposure to fluctuations in these currencies  relative
to the US dollar,  we purchased  foreign  currency  call options in early 2005,
which  effectively set a ceiling on most of our British pound and Euro spending
exposure  from March 2005 through to the end of 2006.  Any change in fair value
is included in marketing and other in the Unaudited  Consolidated  Statement of
Income.

(ii) CANADIAN DOLLAR CALL OPTIONS - CANEXUS
The operations of Canexus are exposed to changes in the US-dollar exchange rate
as a portion of its sales are denominated in US dollars. In connection with the
initial public offering of Canexus,  Canexus LP purchased  Canadian dollar call
options to reduce  this  exposure to  fluctuations  in the  Canadian-US  dollar
exchange  rate.  Canexus LP has the right to sell  US$9.5  million  monthly and
purchase Canadian dollars at an exchange rate of US$0.813 until August 2006. On
April 3, 2006,  Canexus LP purchased  additional  Canadian dollar call options.
Under these  option  contracts,  Canexus LP has 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.  Any  change in fair value is
included in  marketing  and other in the  Unaudited  Consolidated  Statement of
Income.

(iii) FOREIGN CURRENCY SWAP
We occasionally  use derivative  instruments to effectively  convert cash flows
from Canadian to US dollars and vice versa. At June 30, 2006, we held a foreign
currency  derivative  instrument  that  obligates  us and the  counterparty  to
exchange  principal and interest  amounts.  In November 2006, we will pay US$37
million and  receive  Cdn$50  million.  Any change in fair value is included in
marketing and other in the Unaudited Consolidated Statement of Income.

TRADING ACTIVITIES

Our sales and purchases of crude oil and natural gas are  generally  transacted
in or  referenced  to the US  dollar,  as are most of the  financial  commodity
contracts used by our marketing group. We enter into forward  contracts to sell
US dollars.  When  combined  with certain  commodity  sales  contracts,  either
physical or financial,  these forward contracts allow us to lock in our margins
on the future sale of crude oil and natural  gas.  The $5 million fair value of
our US dollar  forward  contracts at June 30, 2006 is included in the Unaudited
Consolidated  Balance Sheet.  Any change in fair value is included in marketing
and other in the Unaudited Consolidated Statement of Income.

                                      14
<PAGE>

(d)  TOTAL CARRYING VALUE OF DERIVATIVE CONTRACTS RELATED TO TRADING ACTIVITIES

Amounts  related to derivative  contracts  held by our marketing  operation are
equal to fair value as we use  mark-to-market  accounting.  The  amounts are as
follows:

<TABLE>
<CAPTION>
                                                                             June 30   December 31
(Cdn$ millions)                                                                 2006          2005
---------------------------------------------------------------------------------------------------
<S>                                                                              <C>           <C>
Accounts Receivable                                                              449           382
Deferred Charges and Other Assets (1)                                            131           232
                                                                            -----------------------
    Total Derivative Contract Assets                                             580           614
                                                                            =======================

Accounts Payable and Accrued Liabilities                                         258           321
Deferred Credits and Other Liabilities (1)                                        86           124
                                                                            -----------------------
    Total Derivative Contract Liabilities                                        344           445
                                                                            =======================

    Total Derivative Contract Net Assets (2)                                     236           169
                                                                            =======================
</TABLE>

Notes:
(1) These  derivative  contracts  settle  beyond 12 months  and are  considered
    non-current.
(2) Comprised  of $231  million  (2005 - $161  million)  related  to  commodity
    contracts and $5 million (2005 - $8 million)  related to US-dollar  forward
    contracts and swaps.

Our  exchange-traded   derivative  contracts  are  subject  to  margin  deposit
requirements.  We are  required to advance cash to  counterparties  in order to
satisfy  these  requirements.  We have margin  deposits of US$15  million  ($17
million) at June 30, 2006  (December 31, 2005 - nil),  which have been included
with restricted cash and margin deposits on our Unaudited  Consolidated Balance
Sheet.


12.  SHAREHOLDERS' EQUITY

DIVIDENDS
Dividends  per common share for the three months ended June 30, 2006 were $0.05
(2005 - $0.05).  Dividends  per common  share for the six months ended June 30,
2006 were $0.10 (2005 - $0.10).


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.

<TABLE>
<CAPTION>
                                                                     Three Months        Six Months
                                                                    Ended June 30       Ended June 30
(millions of shares)                                                2006     2005       2006     2005
------------------------------------------------------------------------------------------------------
<S>                                                                <C>      <C>        <C>      <C>
Weighted-Average Number of Common Shares Outstanding               262.1    260.2      261.9    259.8
Shares Issuable Pursuant to Stock Options                           14.2     13.9       14.4     14.3
Notional Shares to be Purchased from Proceeds of Stock Options      (7.6)    (9.7)      (7.5)   (10.0)
                                                                 -------------------------------------
Weighted-Average Number of Diluted Common Shares Outstanding       268.7    264.4      268.8    264.1
                                                                 =====================================
</TABLE>

In calculating the weighted-average number of diluted common shares outstanding
for the three and six months  ended June 30, 2006 and 2005,  all  options  were
included  because  their  exercise  price was less than the  quarterly  average
common  share  market  price  in the  period.  During  the  periods  presented,
outstanding stock options were the only potentially dilutive instruments.

                                      15
<PAGE>

14.  CASH FLOWS

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

                                                      Three Months       Six Months
                                                     Ended June 30     Ended June 30
(Cdn$ millions)                                       2006    2005      2006    2005
-------------------------------------------------------------------------------------
<S>                                                     <C>     <C>       <C>    <C>
Depreciation, Depletion, Amortization and Impairment    260     253       526    492
Stock-Based Compensation                                  7      63       109    163
Provision for Future Income Taxes (Note 19)              13       2       284    (70)
Change in Fair Value of Crude Oil Put Options            (3)     10         1    183
Non-Cash Items included in Discontinued Operations       --      26        --     56
Net Income Attributable to Non-Controlling Interests      6      --         9     --
Other                                                    12     (19)       34    (16)
                                                      -------------------------------
Total                                                   295     335       963    808
                                                      ===============================

(b)  CHANGES IN NON-CASH WORKING CAPITAL

                                                      Three Months       Six Months
                                                     Ended June 30     Ended June 30
(Cdn$ millions)                                       2006    2005      2006    2005
-------------------------------------------------------------------------------------
   Accounts Receivable                                   8    (245)      837    (178)
   Inventories and Supplies                           (108)   (110)     (258)   (209)
   Other Current Assets                                 16       7        21      11
   Accounts Payable and Accrued Liabilities           (272)    329      (843)    284
   Accrued Interest Payable                             15      17        (2)     23
                                                      -------------------------------
Total                                                 (341)     (2)     (245)    (69)
                                                      ===============================
Relating to:
   Operating Activities                               (377)    (43)     (304)    (96)
   Investing Activities                                 36      41        59      27
                                                      -------------------------------
Total                                                 (341)     (2)     (245)    (69)
                                                      ===============================

(c)  OTHER CASH FLOW INFORMATION

                                                      Three Months       Six Months
                                                     Ended June 30     Ended June 30
(Cdn$ millions)                                       2006    2005      2006    2005
-------------------------------------------------------------------------------------
Interest Paid                                           50      54       130     110
Income Taxes Paid                                      138      90       208     152
                                                      -------------------------------


15.  MARKETING AND OTHER

                                                      Three Months       Six Months
                                                     Ended June 30     Ended June 30
(Cdn$ millions)                                       2006    2005      2006    2005
-------------------------------------------------------------------------------------
Marketing Revenue, Net                                 293     218       730     442
Change in Fair Value of Crude Oil Put Options            3     (10)       (1)   (183)
Interest                                                11      15        19      18
Foreign Exchange Gains (Losses)                        (27)     18       (48)     28
Other (1)                                               96       1       102       4
                                                      -------------------------------
Total                                                  376     242       802     309
                                                      ===============================
</TABLE>

Note:
(1) Other income for the three and six months ended June 30, 2006  includes $74
    million (2005 - $nil) of business  interruption  proceeds received from our
    insurers  relating  to  generator  failures  in  2005 at our UK oil and gas
    operations.

                                      16
<PAGE>

16.  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.

<TABLE>
<CAPTION>
                                                          Three Months    Six Months
                                                         Ended June 30   Ended June 30
(Cdn$ millions, except per share amounts)                 2006    2005    2006    2005
---------------------------------------------------------------------------------------
<S>                                                       <C>     <C>     <C>     <C>
Revenues and Other Income
    Net Sales                                               --      67      --     127
Expenses
    Operating                                               --      11      --      23
    Depreciation, Depletion, Amortization and Impairment    --      11      --      28
    Exploration Expense                                     --      --      --       1
                                                         ------------------------------
Income before Income Taxes                                  --      45      --      75
    Future Income Taxes                                     --      15      --      27
                                                         ------------------------------
Net Income from Discontinued Operations                     --      30      --      48
                                                         ==============================

Earnings Per Common Share ($/share)
   Basic (Note 13)                                          --     0.12     --     0.18
                                                         ==============================
   Diluted (Note 13)                                        --     0.12     --     0.18
                                                         ==============================
</TABLE>

17.  COMMITMENTS, CONTINGENCIES AND GUARANTEES

As  described  in  Note 15 to the  Audited  Consolidated  Financial  Statements
included in our 2005 Annual Report on Form 10-K and described below,  there are
a number of lawsuits and claims pending,  the ultimate  results of which cannot
be  ascertained  at this time.  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.

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 released its tribunal's partial
award that held we were obliged to offer Occidental the right to acquire 50% of
our interest in those areas and that we breached that obligation. The result of
this award is that Occidental is entitled to monetary damages. The ICC tribunal
did not  determine  the amount of damages  due to  Occidental  in this  partial
award.  These damages will be  determined  at the  conclusion of the second and
final phase of the arbitration which will likely occur in late 2007. The amount
of damages  cannot be  reasonably  estimated at this time.  Resolution  of this
matter is not  expected  to have a material  adverse  effect on our  liquidity,
consolidated financial position or operating activities.


                                      17
<PAGE>

18.  PENSION AND OTHER POST RETIREMENT BENEFITS

(a)  NET PENSION EXPENSE RECOGNIZED UNDER OUR DEFINED BENEFIT PENSION PLANS

                                                  Three Months      Six Months
                                                 Ended June 30    Ended June 30
(Cdn$ millions)                                    2006   2005     2006   2005
-------------------------------------------------------------------------------
Nexen
    Cost of Benefits Earned by Employees              4      4        8      6
    Interest Cost on Benefits Earned                  3      4        6      7
    Expected Return on Plan Assets                   (3)    (3)      (6)    (5)
    Net Amortization and Deferral                     1     --        2      1
                                                 ------------------------------
    Net Pension Expense                               5      5       10      9
                                                 ------------------------------

Canexus
    Cost of Benefits Earned by Employees              1     --        2     --
    Interest Cost on Benefits Earned                  1     --        2     --
    Expected Return on Plan Assets                   (1)    --       (2)    --
    Net Amortization and Deferral                    --     --       --     --
                                                 ------------------------------
    Net Pension Expense                               1     --        2     --
                                                 ------------------------------

Syncrude
    Cost of Benefits Earned by Employees              1      1        2      2
    Interest Cost on Benefits Earned                  1      1        2      3
    Expected Return on Plan Assets                   (1)    (1)      (2)    (2)
    Net Amortization and Deferral                     1     --        2     --
                                                 ------------------------------
    Net Pension Expense                               2      1        4      3
                                                 ------------------------------
Total                                                 8      6       16     12
                                                 ==============================

(b)  EMPLOYER FUNDING CONTRIBUTIONS

Our expected total funding  contributions  for 2006 disclosed in Note 16 to the
Audited  Consolidated  Financial  Statements  in our 2005 Annual Report on Form
10-K have not changed for the Nexen and Canexus  defined  benefit pension plans
and our share of Syncrude's defined benefit pension plan.


19.  PROVISION FOR FUTURE INCOME TAXES

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.


                                      18
<PAGE>

20.  OPERATING SEGMENTS AND RELATED INFORMATION

Nexen is involved in activities relating to Oil and Gas, Syncrude and Chemicals
in  various  geographic  locations  as  described  in  Note  20 to the  Audited
Consolidated  Financial  Statements  included in our 2005 Annual Report on Form
10-K.

<TABLE>
<CAPTION>
THREE MONTHS ENDED JUNE 30, 2006

                                                                                                             Corporate
                                                                                                                   and
(Cdn$ millions)                                       Oil and Gas                      Syncrude(1)  Chemicals    Other    Total
--------------------------------------------------------------------------------------------------------------------------------
                                                                       Other
                                                United    United   Countries
                               Yemen   Canada   States   Kingdom         (2) Marketing
                              ---------------------------------------------------------
<S>                            <C>      <C>    <C>       <C>         <C>      <C>         <C>         <C>       <C>       <C>
 Net Sales                       364      122    161       134        39          7         114          98        --     1,039
 Marketing and Other               1        5     --        77 (3)     1        293          --          12       (13)(4)   376
                              --------------------------------------------------------------------------------------------------
                                 365      127    161       211        40        300         114         110       (13)    1,415
 Less: Expenses
  Operating                       38       34     22        20         1          5          44          59        --       223
  Depreciation, Depletion,
    Amortization and
     Impairment                   91       38     49        54         3          1           6          10         8       260
  Transportation and Other         1        1     --        --        --        186           5          10        --       203
  General and Administrative (5)  --        9     11         2        10         39          --           6        34       111
  Exploration                     --        8     15         8        15 (6)     --          --          --        --        46
  Interest                        --       --     --        --        --         --          --           3         8        11
                              --------------------------------------------------------------------------------------------------
 Income (Loss) from
    Continuing Operations
     before Income Taxes         235       37     64       127        11         69          59          22       (63)      561
                              ===========================================================================================
 Less: Provision for Income
  Taxes (7)                                                                                                                 149
 Less: Non-Controlling
  Interests                                                                                                                   6
                                                                                                                         ------
 Net Income                                                                                                                 406
                                                                                                                         ======

 Identifiable Assets             540    3,105  1,437     5,081       173      2,698 (8)   1,177         462       295    14,968
                              ==================================================================================================

 Capital Expenditures
  Development and Other           28      309     80       159         4         34          20           8        10       652
  Exploration                     10       71     72         6         8         --          --          --        --       167
  Proved Property Acquisitions    --       --     --        --        --         --          --          --        --        --
                              --------------------------------------------------------------------------------------------------
                                  38      380    152       165        12         34          20           8        10       819
                              ==================================================================================================

 Property, Plant and Equipment
  Cost                         2,235    4,369  2,512     4,129       202        209       1,292         828       262    16,038
  Less: Accumulated DD&A       1,923    1,369  1,196       319        70         42         174         474       136     5,703
                              --------------------------------------------------------------------------------------------------
 Net Book Value                  312    3,000  1,316     3,810       132        167       1,118         354       126    10,335
                              ==================================================================================================
Notes:
(1) Syncrude is considered a mining operation for US reporting purposes. Property, plant and equipment at June 30, 2006 include
    mineral rights of $6 million.
(2) Includes results of operations from producing activities in Colombia.
(3) Includes proceeds of $74 million from business  interruption  insurance claims for generator failures in 2005 at our UK oil
    and gas operations.
(4) Includes interest income of $11 million, foreign exchange losses of $27 million and increase in the fair value of crude oil
    put options of $3 million.
(5) Includes stock-based compensation expense of $14 million.
(6) Includes exploration activities primarily in Nigeria and Colombia.
(7) Includes Yemen cash taxes of $81 million.
(8) Approximately 84% of Marketing's identifiable assets are accounts receivable and inventories.
</TABLE>

                                                              19
<PAGE>

<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, 2006

                                                                                                             Corporate
                                                                                                                   and
(Cdn$ millions)                                       Oil and Gas                      Syncrude(1)  Chemicals    Other    Total
--------------------------------------------------------------------------------------------------------------------------------
                                                                       Other
                                                United    United   Countries
                               Yemen   Canada   States   Kingdom         (2) Marketing
                              ---------------------------------------------------------
<S>                            <C>      <C>    <C>       <C>         <C>      <C>         <C>         <C>       <C>       <C>
 Net Sales                       692      233    342       268        67         14         198         205        --     2,019
 Marketing and Other               4        6     --        79 (3)     1        730          --          12       (30)(4)   802
                              --------------------------------------------------------------------------------------------------
                                 696      239    342       347        68        744         198         217       (30)    2,821
 Less: Expenses
  Operating                       74       68     52        42         3         12          97         125        --       473
  Depreciation, Depletion,
    Amortization and
     Impairment                  168       75    104       125         5          4          11          20        14       526
  Transportation and Other         3       11     --        --        --        418          11          20        --       463
  General and Administrative (5)  14       50     45         6        25         75          --          13        97       325
  Exploration                     --       14     77        28        30 (6)     --          --          --        --       149
  Interest                        --       --     --        --        --         --          --           5        15        20
                              --------------------------------------------------------------------------------------------------
 Income (Loss) from
    Continuing Operations
     before Income Taxes         437       21     64       146         5        235          79          34      (156)      865
                              ===========================================================================================
 Less: Provision for Income
  Taxes  (7), (8)                                                                                                           529
 Less: Non-Controlling
  Interests                                                                                                                   9
                                                                                                                         -------
 Net Income                                                                                                                 327
                                                                                                                         =======

 Identifiable Assets             540    3,105  1,437     5,081       173      2,698 (9)   1,177         462        295   14,968
                              ==================================================================================================

 Capital Expenditures
  Development and Other           75      634    144       279        13         35          57          10        17     1,264
  Exploration                     15      117    112        25        15         --          --          --        --       284
  Proved Property Acquisitions    --        2     --         1        --         --          --          --        --         3
                              --------------------------------------------------------------------------------------------------
                                  90      753    256       305        28         35          57          10        17     1,551
                              ==================================================================================================

 Property, Plant and Equipment
  Cost                         2,235    4,369  2,512     4,129       202        209       1,292         828       262    16,038
  Less: Accumulated DD&A       1,923    1,369  1,196       319        70         42         174         474       136     5,703
                              --------------------------------------------------------------------------------------------------
 Net Book Value                  312    3,000  1,316     3,810       132        167       1,118         354       126    10,335
                              ==================================================================================================
Notes:
(1) Syncrude is considered a mining operation for US reporting purposes. Property, plant and equipment at June 30, 2006 include
    mineral rights of $6 million.
(2) Includes results of operations from producing activities in Colombia.
(3) Includes proceeds of $74 million from business  interruption  insurance claims for generator failures in 2005 at our UK oil
    and gas operations.
(4) Includes interest income of $19 million, foreign exchange losses of $48 million and decrease in the fair value of crude oil
    put options of $1 million.
(5) Includes stock-based compensation expense of $153 million.
(6) Includes exploration activities primarily in Nigeria and Colombia.
(7) Includes Yemen cash taxes of $148 million.
(8) 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 19).
(9) Approximately 84% of Marketing's identifiable assets are accounts receivable and inventories.
</TABLE>

                                                              20
<PAGE>

<TABLE>
<CAPTION>
THREE MONTHS ENDED JUNE 30, 2005

                                                                                                             Corporate
                                                                                                                   and
(Cdn$ millions)                                       Oil and Gas                      Syncrude(1)  Chemicals    Other    Total
--------------------------------------------------------------------------------------------------------------------------------
                                                                       Other
                                                United    United   Countries
                               Yemen   Canada   States   Kingdom         (2) Marketing
                              ---------------------------------------------------------
<S>                            <C>      <C>    <C>       <C>         <C>      <C>         <C>         <C>       <C>       <C>
 Net Sales                       325       94    184        71        27          6         102         100        --       909
 Marketing and Other               2        1     --        --         4        218          --          --        17 (3)   242
                              --------------------------------------------------------------------------------------------------
                                 327       95    184        71        31        224         102         100        17     1,151
 Less: Expenses
  Operating                       38       27     22        28         5          6          33          57        --       216
  Depreciation, Depletion,
    Amortization and
     Impairment                   84       35     59        36         5          2           5          23 (4)     4       253
  Transportation and Other         1        6     --        --        --        146           5          10         1       169
  General and Administrative (5)   7       22     19         1        12         16          --          12        35       124
  Exploration                      2        6     63        12        22 (6)     --          --          --        --       105
  Interest                        --       --     --        --        --         --          --          --        31        31
                              --------------------------------------------------------------------------------------------------
 Income (Loss) from
    Continuing Operations
     before Income Taxes         195       (1)    21        (6)      (13)        54          59          (2)      (54)      253
                              ===========================================================================================
 Less: Provision for Income
  Taxes  (7)                                                                                                                 83
 Add:  Net Income from
  Discontinued Operations                                                                                                    30
                                                                                                                         -------
 Net Income                                                                                                                 200
                                                                                                                         =======

 Identifiable Assets             688    2,338  1,379     4,454       223      2,403 (8)   1,014         483        465   13,447
                              ==================================================================================================

 Capital Expenditures
  Development and Other           68      216     48       152         3         12          50           3         5       557
  Exploration                      8        7     60        13        26         --          --          --        --       114
  Proved Property Acquisitions    --        1      3         1        --         --          --          --        --         5
                              --------------------------------------------------------------------------------------------------
                                  76      224    111       166        29         12          50           3         5       676
                              ==================================================================================================

 Property, Plant and Equipment
  Cost                         2,227    3,009  2,390     3,857       444        170       1,125         831       208    14,261
  Less: Accumulated DD&A       1,727    1,250  1,136        96       311         69         164         446       100     5,299
                              --------------------------------------------------------------------------------------------------
 Net Book Value                  500    1,759  1,254     3,761       133        101         961         385       108     8,962(9)
                              ==================================================================================================
Notes:
(1) Syncrude is considered a mining operation for US reporting purposes. Property, plant and equipment at June 30, 2005 include
    mineral rights of $6 million.
(2) Includes results of operations from producing activities in Nigeria and Colombia.
(3) Includes interest income of $15 million, foreign exchange gains of $18 million, decrease in the fair value of crude oil put
    options of $10 million and decrease in the fair value of foreign currency options of $6 million.
(4) Includes  impairment  charge of $12 million  related to the pending  closure of our sodium  chlorate plant in  Amherstburg,
    Ontario.
(5) Includes stock-based compensation expense of $65 million.
(6) Includes exploration activities primarily in Nigeria, Colombia and Equatorial Guinea.
(7) Includes Yemen cash taxes of $70 million.
(8) Approximately 81% of marketing's identifiable assets are accounts receivable and inventories.
(9) Excludes property, plant and equipment related to our discontinued operations. See Note 16.
</TABLE>

                                                              21
<PAGE>

<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, 2005
                                                                                                             Corporate
                                                                                                                   and
(Cdn$ millions)                                       Oil and Gas                      Syncrude(1)  Chemicals    Other     Total
---------------------------------------------------------------------------------------------------------------------------------
                                                                       Other
                                                United    United   Countries
                               Yemen   Canada   States   Kingdom         (2) Marketing
                              ---------------------------------------------------------
<S>                            <C>      <C>    <C>       <C>         <C>      <C>         <C>         <C>       <C>        <C>
 Net Sales                       608      180    381       173        49         10         168         196        --      1,765
 Marketing and Other               3        2     --        --         4        442          --           1      (143)(3)    309
                              ---------------------------------------------------------------------------------------------------
                                 611      182    381       173        53        452         168         197      (143)     2,074
 Less: Expenses
  Operating                       73       56     44        53         6         12          73         112        --        429
  Depreciation, Depletion,
    Amortization and
     Impairment                  149       70    125        82         9          5           9          33 (4)    10        492
  Transportation and Other         2       11     --        --        --        318           8          20        13        372
  General and Administrative (5)  17       54     37         2        30         33          --          27       105        305
  Exploration                      3       11     73        15        30 (6)     --          --          --        --        132
  Interest                        --       --     --        --        --         --          --          --        65         65
                              ---------------------------------------------------------------------------------------------------
 Income (Loss) from
    Continuing Operations
     before Income Taxes         367      (20)   102        21       (22)        84          78           5      (336)       279
                              ===========================================================================================
 Less: Provision for Income
  Taxes (7)                                                                                                                   90
 Add: Net Income from
  Discontinued Operations                                                                                                     48
                                                                                                                          -------
 Net Income                                                                                                                  237
                                                                                                                          =======

 Identifiable Assets             688    2,338  1,379     4,454       223      2,403 (8)   1,014         483       465     13,447
                              ===================================================================================================

 Capital Expenditures
  Development and Other          131      430     67       292         7         13          94           4         7      1,045
  Exploration                     16       27    132        16        33         --          --          --        --        224
  Proved Property Acquisitions    --        2      3         1        --         --          --          --        --          6
                              ---------------------------------------------------------------------------------------------------
                                 147      459    202       309        40         13          94           4         7      1,275
                              ===================================================================================================

 Property, Plant and Equipment
  Cost                         2,227    3,009  2,390     3,857       444        170       1,125         831       208     14,261
  Less: Accumulated DD&A       1,727    1,250  1,136        96       311         69         164         446       100      5,299
                              ---------------------------------------------------------------------------------------------------
 Net Book Value                  500    1,759  1,254     3,761       133        101         961         385       108      8,962(9)
                              ===================================================================================================
Notes:
(1) Syncrude is considered a mining operation for US reporting purposes. Property, plant and equipment at June 30, 2005 include
    mineral rights of $6 million.
(2) Includes results of operations from producing activities in Nigeria and Colombia.
(3) Includes interest income of $18 million, foreign exchange gains of $28 million, decrease in the fair value of crude oil put
    options of $183 million and decrease in the fair value of foreign currency options of $6 million.
(4) Includes  impairment  charge of $12 million  related to the pending  closure of our sodium  chlorate plant in  Amherstburg,
    Ontario.
(5) Includes stock-based compensation expense of $190 million.
(6) Includes exploration activities primarily in Nigeria, Colombia and Equatorial Guinea.
(7) Includes Yemen cash taxes of $129 million.
(8) Approximately 81% of marketing's identifiable assets are accounts receivable and inventories.
(9) Excludes property, plant and equipment related to our discontinued operations. See Note 16.
</TABLE>

                                                              22
<PAGE>

21. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

The  Unaudited   Consolidated   Financial  Statements  have  been  prepared  in
accordance with Canadian GAAP. The US GAAP Unaudited  Consolidated Statement of
Income and Balance Sheet and summaries of differences from Canadian GAAP are as
follows:

<TABLE>
<CAPTION>
(a)  UNAUDITED CONSOLIDATED STATEMENT OF INCOME - US GAAP
     FOR THE THREE AND SIX MONTHS ENDED JUNE 30

                                                                  Three Months         Six Months
                                                                 Ended June 30       Ended June 30
(Cdn$ millions, except per share amounts)                        2006     2005       2006     2005
---------------------------------------------------------------------------------------------------
<S>                                                             <C>      <C>        <C>      <C>
REVENUES AND OTHER INCOME
    Net Sales                                                   1,039      909      2,019    1,765
    Marketing and Other (ii)                                      377      242        813      309
                                                               ------------------------------------
                                                                1,416    1,151      2,832    2,074
                                                               ------------------------------------
EXPENSES
    Operating (iv)                                                225      218        477      433
    Depreciation, Depletion, Amortization and Impairment (i)      260      261        526      508
    Transportation and Other                                      203      169        463      372
    General and Administrative (viii)                             122      124        343      305
    Exploration                                                    46      105        149      132
    Interest                                                       11       31         20       65
                                                               ------------------------------------
                                                                  867      908      1,978    1,815
                                                               ------------------------------------

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES             549      243        854      259
                                                               ------------------------------------

PROVISION FOR INCOME TAXES
    Current                                                       136       81        245      160
    Deferred (ii); (iv); (viii); (ix)                              10        2          4      (71)
                                                               ------------------------------------
                                                                  146       83        249       89
                                                               ------------------------------------

NET INCOME FROM CONTINUING OPERATIONS BEFORE NON-CONTROLLING      403      160        605      170
  INTERESTS
    Net Income Attributable to Non-Controlling Interests            6       --          9       --
                                                               ------------------------------------

NET INCOME FROM CONTINUING OPERATIONS                             397      160        596      170
    Net Income from Discontinued Operations (i)                    --       28         --       44
                                                               ------------------------------------

NET INCOME - US GAAP (1)                                          397      188        596      214
                                                               ====================================

EARNINGS PER COMMON SHARE ($/share)
    Basic (Note 13)
      Net Income from Continuing Operations                      1.52     0.61       2.28     0.65
      Net Income from Discontinued Operations                      --     0.11         --     0.17
                                                               ------------------------------------
                                                                 1.52     0.72       2.28     0.82
                                                               ====================================
    Diluted (Note 13)
      Net Income from Continuing Operations                      1.48     0.60       2.22     0.64
      Net Income from Discontinued Operations                      --     0.11         --     0.17
                                                               ------------------------------------
                                                                 1.48     0.71       2.22     0.81
                                                               ====================================
</TABLE>
Note:
(1) RECONCILIATION OF CANADIAN AND US GAAP NET INCOME
<TABLE>
<CAPTION>
                                                                 Three Months         Six Months
                                                                Ended June 30       Ended June 30
(Cdn$ millions)                                                  2006    2005        2006    2005
--------------------------------------------------------------------------------------------------
    <S>                                                           <C>     <C>         <C>     <C>
    Net Income - Canadian GAAP                                    406     200         327     237
    Impact of US Principles, Net of Income Taxes:
      Depreciation, Depletion, Amortization and Impairment (i)     --     (10)         --     (20)
      Liability-Based Stock Compensation Plans (viii)              (8)     --         (12)     --
      Deferred Income Taxes (ix)                                   --      --         277      --
      Other (ii); (iv)                                             (1)     (2)          4      (3)
                                                                 ----------------------------------
    Net Income - US GAAP                                          397     188         596     214
                                                                 ==================================
</TABLE>

                                      23
<PAGE>

<TABLE>
<CAPTION>
(b)      UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP

                                                                               June 30    December 31
(Cdn$ millions, except share amounts)                                             2006           2005
------------------------------------------------------------------------------------------------------
<S>                                                                              <C>            <C>
ASSETS
    CURRENT ASSETS
      Cash and Cash Equivalents                                                     86             48
      Restricted Cash and Margin Deposits                                           58             70
      Accounts Receivable (ii)                                                   2,394          3,151
      Inventories and Supplies                                                     745            504
      Other                                                                         29             51
                                                                            --------------------------
        Total Current Assets                                                     3,312          3,824
                                                                            --------------------------

    PROPERTY, PLANT AND EQUIPMENT
      Net of Accumulated Depreciation, Depletion, Amortization and
         Impairment of $6,096 (December 31, 2005 - $5,861) (iv); (vii)          10,287          9,550
    DEFERRED INCOME TAX ASSETS (ix)                                                550            410
    DEFERRED CHARGES AND OTHER ASSETS (v); (vi)                                    258            345
    GOODWILL                                                                       362            364
                                                                            --------------------------
                                                                                14,769         14,493
                                                                            ==========================

LIABILITIES AND SHAREHOLDERS' EQUITY
    CURRENT LIABILITIES
      Short Term Borrowings                                                         87              -
      Accounts Payable and Accrued Liabilities (ii); (viii)                      3,008          3,745
      Accrued Interest Payable                                                      52             55
      Dividends Payable                                                             13             13
                                                                            --------------------------
        Total Current Liabilities                                                3,160          3,813
                                                                            --------------------------

    LONG-TERM DEBT (v)                                                           3,874          3,630
    DEFERRED INCOME TAX LIABILITIES (i) - (ix)                                   2,004          1,906
    ASSET RETIREMENT OBLIGATIONS                                                   621            590
    DEFERRED CREDITS AND LIABILITIES (vi)                                          472            505
    NON-CONTROLLING INTERESTS                                                       84             88
    SHAREHOLDERS' EQUITY
      Common Shares, no par value
        Authorized:   Unlimited
        Outstanding:  2006   - 262,142,876 shares
                      2005   - 261,140,571 shares                                  799            732
      Contributed Surplus                                                            3              2
      Retained Earnings (ii); (iv); (viii); (ix)                                 3,988          3,418
      Accumulated Other Comprehensive Income (AOCI) (ii); (iii); (vi)             (236)          (191)
                                                                            --------------------------
          Total Shareholders' Equity                                             4,554          3,961
                                                                            --------------------------

    COMMITMENTS, CONTINGENCIES AND GUARANTEES
                                                                                14,769         14,493
                                                                            ==========================
</TABLE>

<TABLE>
<CAPTION>
(c)  UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - US GAAP
     FOR THE THREE AND SIX MONTHS ENDED JUNE 30

                                                                      Three Months       Six Months
                                                                     Ended June 30      Ended June 30
(Cdn$ millions)                                                       2006    2005       2006    2005
------------------------------------------------------------------------------------------------------
<S>                                                                    <C>     <C>        <C>     <C>
Net Income - US GAAP                                                   397     188        596     214
Other Comprehensive Income, Net of Income Taxes:
    Translation Adjustment (iii)                                       (63)     13        (65)     23
    Unrealized Mark-to-Market Gains (Losses) (ii)                        6      (2)        20      (7)
                                                                      --------------------------------
Comprehensive Income                                                   340     199        551     230
                                                                      ================================
</TABLE>

                                      24
<PAGE>

<TABLE>
<CAPTION>
(d)  UNAUDITED CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE
     INCOME - US GAAP

                                                                    June 30   December 31
(Cdn$ millions)                                                        2006          2005
------------------------------------------------------------------------------------------
<S>                                                                   <C>            <C>
Translation Adjustment (iii)                                          (226)          (161)
Unrealized Mark-to-Market Gains (Losses) - Cash Flow Hedges (ii)         4            (16)
Minimum Pension Liability Adjustment (vi)                              (14)           (14)
                                                                   -----------------------
Accumulated Other Comprehensive Income (AOCI)                         (236)          (191)
                                                                   =======================
</TABLE>
NOTES:
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  property,  plant  and  equipment  rather  than a charge to
       retained  earnings.  As a result,  additional  depreciation,  depletion,
       amortization  and impairment  expense of $10 million and $20 million was
       included in net income for the three and six months  ended June 30, 2005
       respectively. 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 earnings in the same period as the hedged
       item.  Any fair  value  change in a  derivative  before  that  period is
       recognized on the balance sheet. The effective portion of that change is
       recognized  in  other  comprehensive  income  with  any  ineffectiveness
       recognized in net income during the period of change.

       FUTURE  SALE OF GAS  INVENTORY:  At  December  31,  2005,  losses of $35
       million  were  included  in  accounts  payable  with  respect to futures
       contracts and swaps we used to hedge  commodity price risk on the future
       sale of our gas inventory as described in Note 11. Losses of $24 million
       ($16 million, net of income taxes) related to the effective portion were
       deferred in AOCI until the  underlying  gas  inventory  was sold.  These
       losses were  reclassified to marketing and other when the contracts were
       settled in the first  quarter of 2006.  The  ineffective  portion of the
       losses of $11 million ($7 million,  net of income taxes) was  recognized
       in net income during 2005.

       At June  30,  2006,  gains  of $6  million  were  included  in  accounts
       receivable with respect to futures  contracts and swaps we used to hedge
       commodity  price  risk  on the  future  sale  of our  gas  inventory  as
       described  in Note 11.  Gains of $6 million ($4  million,  net of income
       taxes) related to the effective portion have been deferred in AOCI until
       the underlying gas inventory is sold.  These losses will be reclassified
       to marketing and other as the contracts  settle over the next 12 months.
       At June 30, 2006, there was no ineffective portion.

       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 is reflected in earnings. At June 30, 2006 and at December
       31, 2005, we had no fair value hedges in place.

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

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

       o   operating expenses include  pre-operating costs of $2 million and $4
           million  for  the  three  and  six  months   ended  June  30,  2006,
           respectively ($2 million and $3 million, respectively, net of income
           taxes) (2005 - $2 million and $4 million,  respectively  ($2 million
           and $3 million, respectively, net of income taxes)); and

       o   property,  plant and equipment is lower under US GAAP by $29 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)  were
       re-classed and included in long-term debt.

                                      25
<PAGE>

vi.    Under US GAAP, the amount by which our accrued pension cost is less than
       the  unfunded  accumulated  benefit  obligation  is included in AOCI and
       accrued pension  liabilities.  As a result,  deferred  credits and other
       liabilities are higher by $26 million (December 31, 2005 - $26 million),
       deferred charges and other assets are higher by $4 million (December 31,
       2005 - $4 million) and $22 million ($14  million,  net of income  taxes)
       was included in AOCI (December 31, 2005 - $22 million ($14 million,  net
       of income taxes)).

vii.   On January 1, 2003, we adopted FASB Statement 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  property,  plant  and
       equipment under US GAAP being lower by $19 million.

viii.  Under Canadian  principles,  we record  obligations for  liability-based
       stock compensation plans using the intrinsic-value method of accounting.
       Under US principles,  obligations for liability-based stock compensation
       plans are  recorded  using the  fair-value  method of  accounting.  As a
       result,  general and  administrative  expense and  accounts  payable and
       accrued  liabilities  are higher  under US GAAP by $11  million  and $18
       million for the three and six months ended June 30,  2006,  respectively
       ($8 million and $12 million, respectively, net of income taxes).

ix.    Under US GAAP,  enacted tax rates are used to calculate  deferred income
       taxes,  whereas under  Canadian  GAAP,  substantively  enacted rates are
       used. During the first quarter of 2006, the UK government  substantively
       enacted  increases to the  supplementary  tax on oil and gas  activities
       from 10% to 20%,  effective January 1, 2006. This created a $277 million
       future  income  tax  expense  during  the first  quarter  of 2006  under
       Canadian GAAP.


(e)  STOCK-BASED COMPENSATION

CHANGE IN ACCOUNTING POLICY - US GAAP
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.

The impact of adopting  Statement  123(R) on our  results for the three  months
ended June 30, 2006 is as follows:

<TABLE>
<CAPTION>
                                                                    Prior to adoption   After adoption    Increase /
(Cdn$ millions, except per share amounts)                                of FAS 123(R)    of FAS 123(R)  (Decrease)
--------------------------------------------------------------------------------------------------------------------
<S>                                                                               <C>             <C>         <C>
Income from Continuing Operations before Income Taxes - US GAAP                   560             549         (11)
Net Income - US GAAP                                                              405             397          (8)
Basic Earnings per Common Share - US GAAP ($/share)                              1.55            1.52       (0.03)
Diluted Earnings per Common Share - US GAAP ($/share)                            1.51            1.48       (0.03)
                                                                    ------------------------------------------------

The impact of adopting Statement 123(R) on our results for the six months ended June 30, 2006 is as follows:

                                                                    Prior to adoption   After adoption    Increase /
(Cdn$ millions, except per share amounts)                                of FAS 123(R)    of FAS 123(R)  (Decrease)
--------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Income Taxes - US GAAP                   872             854         (18)
Net Income - US GAAP                                                              608             596         (12)
Basic Earnings per Common Share - US GAAP ($/share)                              2.32            2.28       (0.04)
Diluted Earnings per Common Share - US GAAP ($/share)                            2.26            2.22       (0.04)
                                                                    ------------------------------------------------
</TABLE>

                                      26
<PAGE>

We   recognize   stock-based   compensation   expense   for  our   retired  and
retirement-eligible  employees over an accelerated 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 months ended June 30, 2006
and 2005 and for the six months ended June 30, 2006 and 2005.

NEW ACCOUNTING PRONOUNCEMENTS

In February  2006,  the  Financial  Accounting  Standards  Board (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 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.  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. We have not yet
determined  the  impact  this  interpretation  will  have on our  results  from
operations or financial position.


                                      27
<PAGE>

ITEM 2.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
           RESULTS OF OPERATIONS

THE FOLLOWING  SHOULD BE READ IN CONJUNCTION  WITH THE UNAUDITED  CONSOLIDATED
FINANCIAL  STATEMENTS  INCLUDED IN THIS  REPORT.  THE  UNAUDITED  CONSOLIDATED
FINANCIAL  STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE WITH GENERALLY ACCEPTED
ACCOUNTING  PRINCIPLES  (GAAP)  IN  CANADA.  THE  IMPACT  OF  THE  SIGNIFICANT
DIFFERENCES  BETWEEN CANADIAN AND UNITED STATES (US) ACCOUNTING  PRINCIPLES ON
THE FINANCIAL STATEMENTS IS DISCLOSED IN NOTE 21 TO THE UNAUDITED CONSOLIDATED
FINANCIAL STATEMENTS. THE DATE OF THIS DISCUSSION IS JULY 14, 2006.

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

NOTE: CANADIAN INVESTORS SHOULD READ THE SPECIAL NOTE TO CANADIAN INVESTORS ON
PAGE 80 OF OUR 2005 ANNUAL  REPORT ON FORM 10-K WHICH  HIGHLIGHTS  DIFFERENCES
BETWEEN  OUR RESERVE  ESTIMATES  AND RELATED  DISCLOSURES  THAT ARE  OTHERWISE
REQUIRED BY CANADIAN REGULATORY AUTHORITIES.

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  UNAUDITED  CONSOLIDATED  FINANCIAL  STATEMENTS  AND  OUR
REVENUES AND EXPENSES DURING THE REPORTED PERIOD. OUR MANAGEMENT REVIEWS THESE
ESTIMATES, INCLUDING THOSE RELATED TO ACCRUALS, LITIGATION,  ENVIRONMENTAL AND
ASSET  RETIREMENT  OBLIGATIONS,  INCOME TAXES AND THE  DETERMINATION OF PROVED
RESERVES ON AN ONGOING BASIS. CHANGES IN FACTS AND CIRCUMSTANCES MAY RESULT IN
REVISED ESTIMATES AND ACTUAL RESULTS MAY DIFFER FROM THESE ESTIMATES.

<TABLE>
<CAPTION>
EXECUTIVE SUMMARY OF SECOND QUARTER RESULTS
                                                                Three Months             Six Months
                                                                Ended June 30           Ended June 30
(Cdn$ millions)                                                2006         2005       2006        2005
--------------------------------------------------------------------------------------------------------
<S>                                                           <C>          <C>        <C>         <C>
Net Income                                                      406          200        327         237
Earnings per Common Share ($/share)                            1.55         0.77       1.25        0.91
Cash Flow from Operating Activities                             374          591      1,108       1,033

Production, before Royalties (mboe/d)                           215          251        219         255
Production, after Royalties (mboe/d)                            158          180        159         182
Nexen's Average Realized Oil and Gas Price (Cdn$/boe)         66.78        53.45      63.90       51.47

Capital Expenditures                                            819          676      1,551       1,275
Net Debt (1)                                                  3,765        4,492      3,765       4,492
                                                             -------------------------------------------
</TABLE>
Note:
(1) Net debt is defined as long-term debt less net working capital.

Commodity  prices  remained  strong  throughout the second  quarter,  with WTI
averaging  US$70.70/bbl.  Strong  reference  crude oil prices,  together  with
narrowing quality  differentials,  allowed us to realize strong prices for our
crude oil sales. The impact of these strong prices was, however, offset by the
weakening  US  dollar  since  the  majority  of our  oil  and  gas  sales  are
denominated  in or referenced to US dollars.  This is mitigated to some extent
as our  US-dollar  denominated  expenses  and  capital  expenditures  are also
reduced when  translated to Canadian  dollars.  Overall,  the higher  Canadian
dollar reduced our cash flow from operating activities by $116 million and our
net income by $53 million during the first half of the year compared to 2005.

Our second  quarter net income  includes $74 million of business  interruption
insurance  proceeds relating to generator failures in our North Sea operations
in 2005 and $32  million of reduced  future  income tax expense as a result of
corporate tax rate reductions in Canada. Our net income year-to-date  includes
strong  results from our marketing  group.  The marketing  division  generated
solid results by using our storage and  transportation  infrastructure to move
gas to markets and by taking  advantage  of  location  and time  spreads.  The
marketing group  recognized $235 million of net income before tax in the first
half of the year. These gains were offset by $277 million of future income tax
expense  recognized  in the first  quarter  related to a 10%  increase  in the
supplemental  tax rate  applicable  to our North Sea  operations in the United
Kingdom.

We have  taken  advantage  of low  natural  gas  prices to build  our  storage
positions  and we  expect  to sell this gas in the  2006/2007  winter  heating
season. As a result, our marketing  inventories have increased by $239 million
since the end of 2005. This build in inventories has contributed to lower cash
flow from  operating  activities  in the second  quarter  relative to the same
period last year. These storage positions have been economically hedged.

                                      28
<PAGE>

Our second quarter production  averaged 215 mboe/d, 36 mboe/d below the second
quarter of 2005. Of this  decrease,  19 mboe/d relates to Canadian oil and gas
properties we sold in the third quarter of 2005. The remainder of the decrease
relates to reduced volumes in Yemen and the United States. These lower volumes
result from  natural  declines  and from  temporary  downtime  related to 2005
hurricanes in the Gulf of Mexico.

Significant  progress was made on our major  development  projects  during the
quarter.  At Buzzard, we completed the installation of the two remaining decks
onto the  permanent  jackets  in the North Sea and we  installed  the  bridges
connecting all three decks. We are commissioning the facilities and completing
final  hook-ups  with  start-up  expected  late this year.  The  project is on
schedule  and  on  budget  and  is  expected  to  significantly  increase  our
production volumes in 2007, adding  approximately  85,000 boe/d to our volumes
when peak rates are achieved. At Syncrude,  the Stage 3 expansion came on-line
in early May,  increasing our share of production from Syncrude to over 25,000
bbls/d.  The  expansion  was  subsequently  shut  down on May 18 due to  odour
emissions.  The modifications required to eliminate the odour are underway and
the  expansion is expected to resume  operations  to late July.  The expansion
adds 8,000 bbls/d to our production  capacity.  Site construction at Long Lake
is progressing on schedule, with steam injection scheduled to commence in late
2006 followed by start-up of the upgrader in the second half of 2007.

CAPITAL INVESTMENT

A large portion of our capital  investment through 2007 is focused on bringing
our major development projects on-stream.  To date, we have invested over $4.3
billion in Buzzard and Long Lake.  These projects will start to come on-stream
in 2006 and contribute to significant growth in 2007.

In  addition  to  developing  these  projects,   we  are  also  targeting  new
opportunities   through  on-going  exploration  and  the  application  of  new
technologies. Details of our capital programs are set out below.

<TABLE>
<CAPTION>
THREE MONTHS ENDED JUNE 30, 2006

                                                   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)                      247               15              23               --         285
   United Kingdom                                    145                3               6               11         165
   United States                                       7               --              72               73         152
   Canada                                             10                3              48               34          95
   Yemen                                              --               --              10               28          38
   Other Countries                                    --                3               8                1          12
Syncrude                                              12               --              --                8          20
                                             --------------------------------------------------------------------------
                                                     421               24             167              155         767

Chemicals, Marketing, Corporate and Other             --               --              --               52          52
                                             --------------------------------------------------------------------------
Total Capital                                        421               24             167              207         819
                                             ==========================================================================
As a % of Total Capital                              52%               3%             20%              25%        100%
                                             --------------------------------------------------------------------------

SIX MONTHS ENDED JUNE 30, 2006

                                                   Major      Early Stage      New Growth       Core Asset
(Cdn$ millions)                              Development      Development     Exploration      Development       Total
-----------------------------------------------------------------------------------------------------------------------
Oil and Gas
   Synthetic (mainly Long Lake)                      494               53              39               --         586
   United Kingdom                                    250               12              25               18         305
   United States                                       9               --             112              135         256
   Canada                                             29               10              78               50         167
   Yemen                                              --               --              15               75          90
   Other Countries                                    --                9              15                4          28
Syncrude                                              43               --              --               14          57
                                             --------------------------------------------------------------------------
                                                     825               84             284              296       1,489

Chemicals, Marketing, Corporate and Other             --               --              --               62          62
                                             --------------------------------------------------------------------------
Total Capital                                        825               84             284              358       1,551
                                             ==========================================================================
As a % of Total Capital                              53%               6%             18%              23%        100%
                                             --------------------------------------------------------------------------
</TABLE>

                                      29
<PAGE>

MAJOR AND EARLY STAGE DEVELOPMENT PROJECTS

SYNTHETIC
The Long Lake  project  remains on  schedule.  With over 75% of the  project's
costs committed, field labour is the major remaining cost uncertainty.  Labour
and  associated  support  costs  have been  higher  than  forecast  and labour
productivity  has been lower than  forecast.  We are taking actions to improve
productivity  and are  seeing  improvements.  However,  incorporating  current
market  conditions and labour  productivity to date, our projections  indicate
that total costs could be up to 10% higher than the $3.8 billion  budget ($1.9
billion, net to Nexen).

All  steam-assisted  gravity  drainage  (SAGD)  wells  have been  drilled  and
completed. SAGD module fabrication is complete with over 90% of the modules on
site.  Upgrader  module  fabrication is advancing with over 90% of our modules
completed and  approximately 80% of the modules are on site. SAGD construction
is over 75% complete, while the upgrader is approximately 50% complete.

We are on track to begin steam  injection in late 2006 and begin  operation of
the upgrader in the second half of 2007. Production capacity for this phase is
approximately 60,000 bbls/d (30,000 bbls/d, net to Nexen) of premium synthetic
crude.

Our plan is to expand oil sands  production to  approximately  240,000  bbls/d
(120,000 bbls/d, net to Nexen) over the next 10 years. Three additional phases
of 60,000  bbls/d  (30,000  bbls/d,  net to Nexen) are planned  using the same
technology  and  design as Long Lake.  We are  currently  progressing  Phase 2
development.  We have  completed the seismic and core hole drilling  programs,
ordered several major vessels and are finalizing regulatory applications. With
sanctioning  anticipated  in 2008,  Phase 2 is expected to commence  synthetic
crude oil production in 2011.

UNITED KINGDOM
Our Buzzard project remains on schedule and on budget. It is approximately 95%
complete and first oil is scheduled for late this year. During the quarter, we
installed the production  deck and the utilities and quarters  deck,  together
with  the  connecting   bridges  and  the  flare  boom.  With  the  successful
installation of the facilities, final hook-ups and commissioning are underway.

The initial  field  development  will  consist of eight  development  and four
injection wells. To date, six development wells and three injection wells have
been drilled.  Additional  drilling will follow to sustain  deliverability and
optimize  field  recovery.  The Buzzard  facility is designed to process up to
200,000  bbls/d  of oil and 60  mmcf/d  of gas.  At its  peak,  our  share  of
production  is  expected to be  approximately  85,000  boe/d.  We have a 43.2%
operated working interest in Buzzard.

CANADA
In Canada,  we continue to develop coalbed methane (CBM) from Mannville coals.
We currently have eight rigs drilling and have completed  construction  of gas
processing  facilities with a capacity of 94 mmcf/d (38 mmcf/d, net to Nexen).
Our CBM  production is currently five mmcf/d and we expect this to increase to
over 30 mmcf/d by year-end.  We expect  further growth as we continue to drill
development wells and complete additional  processing  capacity.  We expect to
add at least 150 mmcf/d of production by 2011.

OTHER COUNTRIES
On Nigeria block OPL-222,  the preliminary Usan field development plan remains
with  Nigerian  governmental  agencies for  approval.  Basic  engineering  and
tendering of contracts for a multi-well  development  plan is proceeding.  The
current plan consists of a floating production,  storage and offloading vessel
capable of handling peak production rates of 160,000 bbls/d of oil, and with a
storage  capacity of two million barrels.  We expect to formally  sanction the
project  following   government   approval  of  the  field  development  plan.
Exploration and appraisal of additional  opportunities on the block continues.
We have a 20%  non-operated  interest  in  this  exploration  and  development
program.

NEW GROWTH EXPLORATION
In the Gulf of Mexico,  the Alaminos  Canyon Block 856 No. 2 well  encountered
oil. This well was a follow up to the Alaminos Canyon Block 856 No. 1 well. We
are  currently  evaluating  development  options  for  this  block,  which  is
immediately  west of the Great  White  discovery.  We have a 30%  non-operated
interest in the block.

In the Gulf of Mexico,  we are currently  drilling  exploration  wells at West
Cameron  135 and at Ringo  Shallow on  Mississippi  Canyon  546. We have a 60%
operated  working  interest  at West  Cameron 135 and a 50%  operated  working
interest at Ringo Shallow.

To date, we have drilled five exploration wells at BAK-K on Block 51 in Yemen.
One well is a small oil discovery,  three wells were dry and abandoned and one
will  be  tested  during  the  third  quarter.  We plan  to  drill  a  further
exploration  well in the third  quarter.  BAK-K is  located  approximately  65
kilometers northwest of our processing facilities.

                                      30
<PAGE>

FINANCIAL RESULTS

<TABLE>
<CAPTION>
CHANGE IN NET INCOME
                                                                                          2006 VS. 2005
                                                                                 Three Months      Six Months
(Cdn$ millions)                                                                 Ended June 30    Ended June 30
----------------------------------------------------------------------------------------------------------------
<S>                                                                                       <C>              <C>
NET INCOME AT JUNE 30, 2005 (1)                                                           200              237
                                                                                ================================
    Favourable (Unfavourable) Variances:

     Cash Items:
       Production Volumes, after Royalties:
         Crude Oil                                                                        (97)            (185)
         Natural Gas                                                                      (10)             (31)
         Change in Crude Oil Inventory                                                    (10)             (15)
                                                                                --------------------------------
           Total Volume Variance                                                         (117)            (231)

       Realized Commodity Prices:
         Crude Oil                                                                        195              325
         Natural Gas                                                                      (14)              20
                                                                                --------------------------------
           Total Price Variance                                                           181              345

       Oil and Gas Operating Expense:
         Conventional                                                                      16               16
         Syncrude                                                                         (11)             (24)
                                                                                --------------------------------
           Total Operating Expense Variance                                                 5               (8)

       Marketing                                                                           37              192
       Chemicals                                                                            8                7
       General and Administrative                                                         (38)             (57)
       General and Administrative - Stock-Based Compensation Paid                          (5)             (17)
       Interest Expense                                                                    20               45
       Current Income Taxes                                                               (55)             (85)
       Business Interruption Insurance Proceeds                                            74               74
       Other                                                                               (3)              (3)
                                                                                --------------------------------
     Total Cash Variance                                                                  107              262

     Non-Cash Items:
       Depreciation, Depletion, Amortization and Impairment
           Oil and Gas                                                                     (6)             (16)
           Other                                                                           10               10
       Exploration Expense                                                                 59              (16)
       General and Administrative - Stock-Based Compensation Accrual                       56               54
       Future Income Taxes                                                                  4             (327)
       Change in Fair Value of Crude Oil Put Options                                       13              182
       Other                                                                              (37)             (59)
                                                                                --------------------------------
     Total Non-Cash Variance                                                               99             (172)
                                                                                --------------------------------

NET INCOME AT JUNE 30, 2006                                                               406              327
                                                                                ================================
</TABLE>
Note:
(1) Includes results of discontinued  operations (see Note 16 to our Unaudited
    Consolidated Financial Statements).

Significant  variances in net income are  explained  further in the  following
sections.

                                      31
<PAGE>

OIL & GAS AND SYNCRUDE

<TABLE>
<CAPTION>
PRODUCTION (BEFORE ROYALTIES) (1)
                                                             Three Months                Six Months
                                                             Ended June 30              Ended June 30
                                                            2006         2005          2006        2005
--------------------------------------------------------------------------------------------------------
<S>                                                        <C>          <C>           <C>         <C>
Crude Oil and NGLs (mbbls/d)
    Yemen                                                   95.2        115.0          98.8       114.6
    Canada (2)                                              20.6         34.5          21.4        34.6
    United States                                           17.8         23.0          18.5        25.7
    United Kingdom                                          17.2          9.8          16.5        12.3
    Other Countries                                          6.6          5.9           6.2         5.9
Syncrude (3)                                                17.4         16.9          16.1        14.1
                                                          ----------------------------------------------
                                                           174.8        205.1         177.5       207.2
                                                          ----------------------------------------------
Natural Gas (mmcf/d)
    Canada (2)                                               104          141           105         142
    United States                                            107          120           114         123
    United Kingdom                                            32           15            27          22
                                                          ----------------------------------------------
                                                             243          276           246         287
                                                          ----------------------------------------------

Total (mboe/d)                                               215          251           219         255
                                                          ==============================================

PRODUCTION (AFTER ROYALTIES)

                                                              Three Months                Six Months
                                                              Ended June 30              Ended June 30
                                                             2006         2005          2006        2005
---------------------------------------------------------------------------------------------------------
Crude Oil and NGLs (mbbls/d)
    Yemen                                                    52.3         63.6          53.0        60.7
    Canada (2)                                               16.2         26.6          17.0        27.0
    United States                                            15.6         20.3          16.3        22.8
    United Kingdom                                           17.2          9.8          16.5        12.3
    Other Countries                                           6.0          5.3           5.7         5.4
Syncrude (3)                                                 15.7         16.7          14.5        14.0
                                                           ----------------------------------------------
                                                            123.0        142.3         123.0       142.2
                                                           ----------------------------------------------

Natural Gas (mmcf/d)
    Canada (2)                                                 88          110            89         111
    United States                                              91          102            97         105
    United Kingdom                                             32           15            27          22
                                                           ----------------------------------------------
                                                              211          227           213         238
                                                           ----------------------------------------------

Total (mboe/d)                                                158          180           159         182
                                                           ==============================================

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
    16 to our Unaudited Consolidated Financial Statements.

                                                             Three Months              Six Months
                                                             Ended June 30            Ended June 30
                                                           2006         2005         2006        2005
   ---------------------------------------------------------------------------------------------------
   Before Royalties
     Crude Oil and NGLs (mbbls/d)                            --         11.6           --        11.3
     Natural Gas (mmcf/d)                                    --           42           --          43
   After Royalties
     Crude Oil and NGLs (mbbls/d)                            --          9.2           --         8.9
     Natural Gas (mmcf/d)                                    --           29           --          29
                                                          --------------------------------------------
(3) Considered a mining operation for US reporting purposes.
</TABLE>

                                      32
<PAGE>

LOWER PRODUCTION DECREASED NET INCOME FOR THE QUARTER BY $117 MILLION
Production before royalties  decreased 14% from the second quarter in 2005 and
was 3% below the first  quarter of this  year.  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 declined 7% from the second quarter of 2005.

The following  table  summarizes our production  volume changes since the last
quarter:

                                                             Before       After
(mboe/d)                                                  Royalties   Royalties
--------------------------------------------------------------------------------
Production, First Quarter 2006                                 222          159
    Production changes:
      Yemen                                                     (7)          (2)
      Canada                                                    (2)          (2)
      United States                                             (4)          (3)
      United Kingdom                                             3            3
      Syncrude                                                   2            2
      Other Countries                                            1            1
                                                         -----------------------
Production, Second Quarter 2006                                215          158
                                                         =======================

We expect production  increases to come from our major development projects at
Syncrude  Stage 3 and Buzzard in the North Sea later this year.  At Long Lake,
steam  injection  is  expected  to begin  in late  2006  and the  upgrader  is
scheduled to commence  synthetic  crude oil  production  in the second half of
2007. Production volumes discussed in this section represent  before-royalties
volumes, net to our working interest.

YEMEN
Production  from Yemen  decreased  7% from the  previous  quarter.  Production
declines  at Masila  reflect  the  maturity  of the field and the  impact of a
reduced  2006  development  drilling  program.  Base  declines  at Masila  are
expected to continue as we maximize recovery of the remaining  reserves on the
block.  We have  drilled  13 wells on the  Masila  block to date this year and
expect to drill a total of 30 wells in 2006.  Strong  initial  rates  from new
wells and well optimizations have helped to minimize the production declines.

Block 51  production  was less than the first  quarter due  primarily to lower
well  productivity at BAK-B. In 2006, we have drilled 18 development  wells on
the block. We are  accelerating  the drilling  program in the remainder of the
year through the use of a second drilling rig.

CANADA
Production  in Canada  decreased  5% from the previous  quarter,  largely as a
result of natural declines.  Canadian production was 35% lower than the second
quarter of 2005 primarily as a result of the sale of certain  conventional oil
and gas  properties  in the  third  quarter  of last  year.  These  properties
produced  approximately  18,600  boe/d in the  second  quarter  of last  year.
Production volumes in Canada are expected to increase later this year with gas
production from our coalbed methane  projects.  We expect further increases in
2007  with the  production  of  premium  synthetic  crude oil at Long Lake and
additional volumes from our coalbed methane projects.

UNITED STATES
Gulf of Mexico production was 9% lower than the previous quarter and 17% lower
than the second quarter of 2005.  Production  from Vermilion 321 and Vermilion
340 remains shut-in due to damage from Hurricane Rita last year,  reducing our
quarterly  volumes  by 4,000  boe/d  based on  production  rates  prior to the
storms.  The damage  relates to  pipelines  accessed by our  platforms  and we
expect  this  infrastructure  will be repaired  later this year.  We have also
experienced  delays to our 2006  development  drilling  program as a result of
damage to drilling rigs caused by the 2005 hurricanes. We are working with our
insurers to settle our  property  damage and business  interruption  insurance
claims related to these storms.

Production  from Aspen was  comparable to the previous  quarter and water cuts
have moderated since last year. We are currently drilling another  development
well at Aspen, but drilling was delayed in the second quarter following damage
to the  drilling  rig caused by a work  boat.  The rig has been  repaired  and
drilling has since  resumed.  We expect to complete the well and tie-in to the
Aspen infrastructure in the fourth quarter. Gunnison production remains strong
with solid production rates from the #10 well.  Development of the Dawson Deep
discovery was completed in July while the Wrigley development has been delayed
by the tight  drilling  rig  market in the Gulf.  A rig has been  secured  and
production is expected in early 2007.

UNITED KINGDOM
Production  from the Scott and Telford fields was 10,200 boe/d higher than the
second quarter of 2005 and 3,000 boe/d higher than the previous  quarter.  Our
production  in 2005  was  impacted  by two  generator  failures  on the  Scott
platform,  which forced the shut-in of production  during the second  quarter.
Production  resumed in the third quarter of 2005  following

                                      33
<PAGE>

the completion of turbine repairs. During the quarter, we received $74 million
in business interruption insurance proceeds related to these failures. Minimal
downtime and successful  workovers helped to improve production rates from the
Scott and Telford  fields this year.  Production  was also higher  relative to
last year with the addition of new production  from the Farragon field in late
2005. Our Buzzard development is on time and on budget, and we expect to begin
producing from this field in late 2006.

OTHER COUNTRIES
Production from our Guando field in Colombia  averaged 6,600 bbls/d during the
quarter,  20% higher than the second  quarter of 2005. We completed a ten well
infill  drilling  program  during  the first  half of 2006 and we  started  an
additional five well infill drilling program in the second quarter.  We expect
to maintain  current  production rates for the remainder of the year. Our 2005
second  quarter  production  included  small  volumes from our Ejulebe  field,
offshore Nigeria, which was sold in 2005.

SYNCRUDE
At Syncrude, the start-up of the Stage 3 expansion was delayed by the emission
of odours from the flue gas  desulphurizer  (FGD) plant.  Production  from the
Stage 3 expansion  started in early May and was  approaching  design  capacity
rates  prior to  shutting  in as a  result  of the  emission  of  odours.  The
modifications  required to eliminate the odours are underway and the expansion
is expected to resume operations in late July. The Stage 3 expansion increases
our production  capacity by 8,000 bbls/d.  Strong realized prices have enabled
us to fully  recover  capital  costs  associated  with the Stage 3  expansion.
Consequently,  our Syncrude  royalty in 2006 increases from a 1% gross revenue
royalty to a 25% net revenue  royalty.  As a result of the  increased  royalty
rates,  we receive  lower net  production  relative  to our  working  interest
production volumes.

<TABLE>
<CAPTION>
COMMODITY PRICES
                                                                    Three Months                Six Months
                                                                    Ended June 30              Ended June 30
                                                                   2006         2005          2006         2005
----------------------------------------------------------------------------------------------------------------
<S>                                                               <C>          <C>           <C>          <C>
CRUDE OIL AND NGLS
    West Texas Intermediate (WTI) (US$/bbl)                       70.70        53.17         67.09        51.51
                                                                ------------------------------------------------

    Differentials (1) (US$/bbl)
      Masila (Yemen)                                               2.71         5.12          3.24         5.90
      Heavy Oil (Canada)                                          17.88        21.15         23.39        20.24
      Mars (US)                                                    6.97         5.74          7.43         6.45
      Dated Brent (UK)                                             1.08         1.58          1.40         1.96

    Producing Assets (Cdn$/bbl)
      Yemen                                                       76.86        58.08         72.44        56.22
      Canada                                                      51.67        40.47         40.44        38.24
      United States                                               70.23        54.96         66.86        52.73
      United Kingdom                                              73.24        59.02         71.16        56.35
      Other Countries                                             69.63        53.70         64.60        50.37
      Syncrude                                                    79.50        66.93         75.14        66.22

    Corporate Average (Cdn$/bbl)                                  72.90        55.45         67.92        53.36
                                                                ------------------------------------------------

NATURAL GAS
    New York Mercantile Exchange (NYMEX) (US$/mmbtu)               6.67         6.95          7.27         6.71
    AECO (Cdn$/mcf)                                                5.95         6.99          7.37         6.67
                                                                ------------------------------------------------

    Producing Assets (Cdn$/mcf)
      Canada                                                       6.21         6.30          6.93         6.05
      United States                                                7.51         9.01          8.33         8.66
      United Kingdom                                               5.52         5.45          8.31         6.38

    Corporate Average (Cdn$/mcf)                                   6.68         7.39          7.70         7.20
                                                                ------------------------------------------------

NEXEN'S AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe)             66.78        53.45         63.90        51.47
                                                                ------------------------------------------------

AVERAGE FOREIGN EXCHANGE RATE
    Canadian to US Dollar (US$)                                  0.8918       0.8039        0.8786       0.8096
                                                                ------------------------------------------------
</TABLE>
Note:
(1) These differentials represent a discount relative to WTI.

                                      34
<PAGE>

HIGHER REALIZED COMMODITY PRICES INCREASED QUARTERLY NET INCOME BY $181 MILLION
WTI continued to rise,  gaining 11% over the previous quarter and 33% over the
second quarter of 2005. As a result of strong benchmark  commodity  prices, we
realized higher prices for our crude oil, averaging $72.90/bbl in the quarter,
31% higher than the second quarter of 2005.  Our realized gas price  decreased
10% from the second quarter of 2005 to average $6.68/mcf while NYMEX decreased
4% in the same period averaging US$6.67/mmbtu.

The full  benefit  of higher  benchmark  prices  did not flow  through  to our
realized  prices as a result of a weaker US dollar during the quarter.  All of
our oil sales and most of our gas sales are denominated in or referenced to US
dollars.  As a result,  the  weakening US dollar  decreased  net sales for the
quarter by approximately $103 million ($158 million year to date), and reduced
our realized crude oil and natural gas prices by  approximately  $7.97/bbl and
$0.73/mcf, respectively, compared to the second quarter of 2005.

Although WTI was higher than last year by 33% and our crude oil  differentials
were 34% narrower,  our average  realized oil and gas price was only higher by
25%. The lower average  realized  price reflects the impact of gas prices that
were 10% below the second  quarter of 2005,  coupled with the impact of a weak
US dollar which was 11% softer than 2005.

CRUDE OIL REFERENCE PRICES
Crude oil prices remained  strong  throughout the second quarter of 2006, with
WTI  averaging  US$70.70/bbl.  WTI reached  new highs in early July.  The main
drivers for strong  crude  prices  continue to be  geopolitical  issues in the
Middle East and Nigeria,  the threat of another severe hurricane season in the
Gulf of Mexico and strong demand for gasoline in North America.

Political  instability  remains an issue  throughout  the  Middle  East due to
persistent  concerns over the Iranian  nuclear issue, as well as concerns over
on-going  violence in Iraq. In Nigeria,  militant attacks continued to disrupt
over  500,000  barrels per day of  production.  More  recently,  North  Korean
nuclear missile testing has added new geopolitical concerns to the mix.

In the US, speculation around the impact of the summer driving season, as well
as the start of the hurricane season, caused prices to creep higher during the
quarter.  Although  days of  forward  cover are higher  than  normal and crude
inventory  levels are higher than the five-year  average,  supply concerns are
supporting higher prices.  In particular,  there is concern over the supply of
light sweet barrels needed to feed gasoline, diesel and jet-fuel requirements.
In addition,  new US gasoline  regulations  aimed at improving the environment
are making it difficult for some  refiners to secure  enough  ethanol to be in
compliance before the peak summer driving season starts.

With another active hurricane season expected in 2006,  speculation around the
impact storms might have on  infrastructure,  refining capacity and production
in the US is  expected  to keep  crude  oil  prices  high.  Additionally,  any
speculation  related to  hurricanes,  geopolitical  concerns  or the impact of
gasoline demand will likely continue to generate volatility in the market.


CRUDE OIL DIFFERENTIALS
Crude oil differentials  narrowed  considerably in the second quarter compared
to the first quarter.  Seasonal  demand for asphalt is expected to keep prices
for heavy grades  strong  throughout  the summer,  but this is not expected to
last beyond the end of summer.

In Canada, heavy crude oil differentials  averaged  US$17.88/bbl (25% of WTI),
compared to US$28.89/bbl  in the first quarter (46% of WTI). The  differential
narrowed  substantially  with  increases  in pipeline  capacity  to  transport
Canadian  heavy  production  to the  US  Gulf  Coast  and  mid-continent.  Key
contributors  were the start-up of the Enbridge  Spearhead and the  ExxonMobil
Patoka pipelines. The start-up of Gulf Coast refineries that were shutdown for
maintenance also contributed to the narrowing of the differential.

On the US Gulf Coast, the Mars differential  averaged US$6.97/bbl (10% of WTI)
compared  to  US$7.90/bbl  (12%  of  WTI)  in  the  first  quarter.  The  Mars
differential  strengthened in the second quarter as refineries completed their
maintenance work.

The Yemen Masila differential  narrowed  substantially  relative to WTI due to
strong demand during the second quarter, averaging US$2.71/bbl.  Masila crude,
unlike other sour grades worldwide,  strengthened mainly from higher demand in
Asia after an  exceptionally  cold winter depleted  heating fuel stocks in the
region.

The Brent/WTI  differential  strengthened  during the second quarter averaging
US$1.08/bbl, resulting in higher pricing for our North Sea barrels. The spread
between WTI and Brent has broken away from historical  norms where WTI usually
trades at a premium  of  US$1.50  to  US$2.00  and in April,  WTI  traded at a
discount to Brent.  On-going  production  outages in Nigeria and strong demand
from Asia helped to push Brent up relative to WTI.

                                      35
<PAGE>

NATURAL GAS REFERENCE PRICES
Natural gas prices  weakened  considerably  from record highs in late 2005 when
prices   peaked  above   US$15/mmbtu.   NYMEX   natural  gas  prices   averaged
US$6.67/mmbtu  in the  second  quarter.  Prices  have  softened  due to reduced
shoulder  season demand and  historically  high storage  levels coming out of a
mild winter season. In late June, North American storage levels were almost 20%
higher than the same time last year.  While high  storage  levels put  downward
pressure on gas prices,  support has been  provided by strong crude oil prices,
the  possibility  of hot summer  weather and the  possible  impact of an active
hurricane season.

<TABLE>
<CAPTION>
OPERATING COSTS
                                                                      Three Months               Six Months
                                                                      Ended June 30             Ended June 30
(Cdn$/boe)                                                           2006        2005          2006        2005
----------------------------------------------------------------------------------------------------------------
<S>                                                                 <C>         <C>           <C>         <C>
Operating costs based on our working interest production before
royalties (1)
     Conventional Oil and Gas (2)                                    6.47        6.20          6.52        5.81
     Synthetic Crude Oil
       Syncrude                                                     27.84       20.76         33.45       28.42
     Total Oil and Gas (2)                                           8.21        7.18          8.50        7.06
                                                                   ---------------------------------------------

Operating costs based on our net production after royalties
     Conventional Oil and Gas (2)                                    9.29        8.87          9.41        8.34
     Synthetic Crude Oil
       Syncrude                                                     30.93       20.97         37.09       28.71
     Total Oil and Gas (2)                                          11.46        9.99         11.96        9.90
                                                                   ---------------------------------------------
</TABLE>
Notes:
(1) Operating  costs per boe are our total oil and gas operating costs divided
    by our working interest  production  before  royalties.  We use production
    before royalties to monitor our performance consistent with other Canadian
    oil and gas companies.
(2) 2005 operating costs include results of discontinued  operations (see Note
    16 to our Unaudited Consolidated Financial Statements).

LOWER OIL AND GAS OPERATING  COSTS INCREASED NET  INCOME FOR THE QUARTER BY $5
MILLION
During the second  quarter,  we replaced a single point mooring system used to
load oil onto tankers in Yemen.  These costs and lower volumes from our Masila
field  increased our  corporate  unit average  operating  cost by $0.25/boe as
compared  to the second  quarter of 2005.  Higher  costs at our Block 51 field
increased our corporate average by $0.20/boe.  Higher Block 51 operating costs
reflect  increased  employee  headcount,  an  increase  in the amount of water
handled at the new facilities, and increased fuel consumption and fuel prices.

Operating  costs in the Gulf of Mexico  have  increased  from last year due to
industry cost pressures caused primarily by the 2005 hurricane season.  Higher
costs in the Gulf of Mexico increased our corporate  average by $0.30/boe from
the prior year.

Following 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 $1.05/boe.  This was
offset by  reduced  operating  costs in the North Sea  relative  to 2005.  Our
operating  expense in the second quarter of 2005 included repair costs related
to  the  turbine  failures  and  pipeline  tariff  costs  on our  Telford  gas
production.  The tariff  was  eliminated  in late 2005 and the  repairs to the
turbines were  completed  last year.  The reduction in these costs reduced our
corporate average by $1.20/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 $0.35/boe as a result.

Syncrude  increased our corporate average operating cost by $0.85/boe from the
second  quarter of 2005  primarily as a result of operating  costs  related to
start-up of the Stage 3 expansion.

                                      36
<PAGE>

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

                                                                        Three Months                Six Months
                                                                        Ended June 30              Ended June 30
(Cdn$/boe)                                                             2006         2005          2006        2005
-------------------------------------------------------------------------------------------------------------------
<S>                                                                   <C>          <C>           <C>         <C>
DD&A based on our working interest production before royalties (1)
     Conventional Oil and Gas (2)                                     13.18        10.76         13.01       10.58
     Synthetic Crude Oil
       Syncrude                                                        3.47         3.29          3.61        3.40
     Average Oil and Gas (2)                                          12.39        10.26         12.31       10.18
                                                                     ----------------------------------------------

DD&A based on our net production after royalties
     Conventional Oil and Gas (2)                                     18.93        15.41         18.78       15.19
     Synthetic Crude Oil
       Syncrude                                                        3.85         3.32          4.00        3.43
     Average Oil and Gas (2)                                          17.31        14.28         17.33       14.28
                                                                     ----------------------------------------------
</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) 2005 DD&A includes results of discontinued  operations (see Note 16 to our
    Unaudited Consolidated Financial Statements).

HIGHER OIL AND GAS DD&A REDUCED NET INCOME FOR THE QUARTER BY $6 MILLION
In Yemen,  Block 51 increased our corporate  unit  depletion rate by $1.40/boe
compared  to the  second  quarter  of 2005 as a  result  of  carried  interest
accounting  for the recovery of Block 51 capital  costs.  Higher  realized oil
prices have resulted in the faster recovery of capital costs we paid on behalf
of the  government.  In  addition,  we have  started to deplete the  permanent
facilities, which were completed in late 2005 and early 2006.

The  sale  of  Canadian  production  in 2005  has  effectively  increased  our
corporate  depletion  rate since a greater  proportion of our  production  now
comes  from the North Sea.  Our North Sea  assets  have  higher  than  average
depletion  rates.  This change in  production  mix has increased our corporate
average by  $1.30/boe.  During the first  quarter of the year, we expensed $15
million  of our  North Sea  purchase  price  that was  allocated  to  unproved
properties where we had unsuccessful exploration results.

Depletion  rates for our  deep-water  assets  in the Gulf of Mexico  increased
relative  to the prior  year as a result of  reserve  revisions  late in 2005.
Consequently,  our corporate  average was higher by $0.25/boe  compared to the
second quarter of 2005.

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 $0.85/boe compared to the second quarter of 2005.

<TABLE>
<CAPTION>
EXPLORATION EXPENSE

                                                                       Three Months                Six Months
                                                                       Ended June 30              Ended June 30
(Cdn$ millions)                                                       2006         2005          2006        2005
------------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>          <C>           <C>         <C>
Seismic                                                                 25           15            47          20
Unsuccessful Exploration Drilling                                        6           76            71          84
Other                                                                   15           14            31          29
                                                                     ---------------------------------------------
Total Exploration Expense (1)                                           46          105           149         133
                                                                     =============================================

New Growth Exploration                                                 167          114           284         224
Geological and Geophysical Costs                                        25           15            47          20
                                                                     ---------------------------------------------
Total Exploration Expenditures                                         192          129           331         244
                                                                     =============================================
</TABLE>
Note:
(1) Includes exploration expense from discontinued  operations (see Note 16 to
    our Unaudited Consolidated Financial Statements).

LOWER EXPLORATION EXPENSE INCREASED NET INCOME FOR THE QUARTER BY $59 MILLION
Exploration  activity in the quarter included drilling a successful  appraisal
well to delineate  our  discovery on Alaminos  Canyon Block 856 in the Gulf of
Mexico.  At the end of the quarter,  we have two exploration wells drilling in
the Gulf of Mexico  (Ringo  Shallow in deep water and West  Cameron 135 on the
shelf)  and two  exploration  wells  drilling  on Block 51 in  Yemen.  We have
exploration wells planned for the remainder in the year in the Gulf of Mexico,
the North Sea and on Block 51 in Yemen.

                                      37
<PAGE>

Our year-to-date  exploration  expense includes first quarter costs related to
unsuccessful wells at Pathfinder in the Gulf of Mexico, Zanzibar and Black Cat
in the North Sea, and Ukot South,  offshore  Nigeria.  We incurred  additional
costs  during the year by  acquiring  seismic  data,  primarily in the Gulf of
Mexico.

<TABLE>
<CAPTION>
OIL AND GAS MARKETING
                                                                       Three Months                Six Months
                                                                       Ended June 30              Ended June 30
(Cdn$ millions)                                                       2006         2005          2006        2005
------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>          <C>           <C>         <C>
    Marketing Revenue, net                                             293          218           730         442
    Transportation                                                    (186)        (146)         (418)       (318)
    Other                                                                2           --             2          (2)
                                                                     ---------------------------------------------
Net Revenue                                                            109           72           314         122
                                                                     =============================================

Physical Sales Volumes (excluding intra-segment transactions)
    Crude Oil (mboe/d)                                                 660          476           624         478
    Natural Gas (bcf/d)                                                5.4          4.6           5.4         4.8

Value-at-Risk
    Quarter-end                                                         20           20            20          20
    High                                                                27           28            27          30
    Low                                                                 18           17            17          17
    Average                                                             21           24            21          24
                                                                     ---------------------------------------------
</TABLE>

HIGHER CONTRIBUTION FROM MARKETING INCREASED NET INCOME BY $37 MILLION
During the quarter,  our gas marketing group took advantage of soft,  near-term
North American gas prices  resulting  from warmer than expected  winter weather
which pushed gas storage levels to record highs early in the injection season.

We have  maintained  our  focus  on  trading  within  markets  where we have a
physical presence, taking advantage of both time and location spreads. We have
also taken  advantage  of the lower price  environment  and  injected gas into
storage,  which we expect to  withdraw  during the  2006/2007  winter  heating
season.  These storage  positions  have been  economically  hedged.  While our
storage assets have increased in value,  we are unable to recognize this value
until the gas in storage is sold or the storage capacity is used.

Our crude oil marketing  group  realized gains during the quarter from selling
crude oil volumes from inventory to take  advantage of both narrowing  quality
differentials as well as rising WTI prices. We also took advantage of contango
(increasing  prices) in the forward curve, as well as volatility,  to generate
trading  gains.  Our crude oil  marketing  team  recently  enhanced  their NGL
business by acquiring Wittig Energy Ltd., a privately-held  marketing  company
based in Kansas.

During the  quarter,  we expanded  our  marketing  business in the UK with the
acquisition of Foundation  Energy Ltd., a privately-held  London-based gas and
power marketing company.  This acquisition  complements our existing crude oil
marketing  activities that are focused on supporting the sale of our North Sea
production including the production expected from Buzzard later this year.

Results from our marketing  group vary by quarter and results for each quarter
are not necessarily  indicative of results to be expected in future  quarters.
Quarterly  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  value  of  the  financial
instruments we use to hedge these assets.

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 versus east) and time periods (i.e.
summer versus 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.  Like financial commodity
contracts,  the market value of our capacity  contracts varies with changes in
prices and pricing relationships. We routinely hedge the economic value of our
capacity  contracts  using various  financial  derivative  contracts,  thereby
limiting  volatility  in our  economic  results.  Accounting  rules,  however,
increase  volatility  in our reported  results since these rules require us to
recognize the change in fair value of financial  derivative  contracts hedging
our capacity  contracts,  but do not allow us to recognize  the change in fair
value of the  capacity  contracts  themselves.  As a  result,  when  prices or
pricing relationships change, we may be required to include gains or losses in
our  reported  results  even  though our  underlying  economic  results may be
largely unchanged.

                                      38
<PAGE>

<TABLE>
<CAPTION>
COMPOSITION OF NET MARKETING REVENUE
                                                                       Three Months                Six Months
                                                                       Ended June 30              Ended June 30
(Cdn$ millions)                                                       2006         2005          2006        2005
------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>           <C>          <C>         <C>
Trading Activities                                                     107           65           309         109
Non-Trading Activities                                                   2            7             5          13
                                                                     ---------------------------------------------
                                                                       109           72           314         122
                                                                     =============================================
</TABLE>

TRADING ACTIVITIES
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. These derivative contracts
are valued as described in the MD&A included in our 2005 Annual Report on Form
10-K.  Results from trading  activities  include physical purchases and sales,
gains and losses on derivative  contracts  and income  relating to our storage
and transportation assets.

FAIR VALUE OF DERIVATIVE CONTRACTS
At June 30, 2006, the fair value of our derivative contracts not designated as
accounting  hedges  totalled  $236  million.  The  following  table  shows the
valuation methods underlying these contracts together with details of contract
maturity:

<TABLE>
<CAPTION>
(Cdn$ millions)                                                               MATURITY
---------------------------------------------------------------------------------------------------------------
                                                      less than                             more than
                                                        1 year     1-3 years    4-5 years     5 years    Total
                                                     ----------------------------------------------------------
<S>                                                        <C>            <C>          <C>                 <C>
Prices
    Actively Quoted Markets                                 53           (11)          (5)         --       37
    From Other External Sources                            138            41           20          --      199
    Based on Models and Other Valuation Methods             --            --           --          --       --
                                                     ----------------------------------------------------------
Total                                                      191            30           15          --      236
                                                     ==========================================================
</TABLE>

At June 30, 2006, we had $6 million of  unrecognized  gains on our  derivative
contracts  designated  as  accounting  hedges  of the  future  sale of our gas
inventory.  These gains will be  recognized  in income when the  inventory  is
sold.  These  contracts  were valued from actively  quoted  markets and settle
within 12 months.

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

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

(Cdn$ millions)
------------------------------------------------------------------------------------------------------------
<S>                                                                                                    <C>
Fair Value at December 31, 2005                                                                         169
    Change in Fair Value of Contracts                                                                   317
    Net Losses (Gains) on Contracts Closed                                                             (250)
    Changes in Valuation Techniques and Assumptions (1)                                                  --
                                                                                                    --------
Fair Value at June 30, 2006                                                                             236
Unrecognized Gains on Hedges of Future Sale of Gas Inventory
    at June 30, 2006                                                                                      6
                                                                                                    --------
Total Outstanding at June 30, 2006                                                                      242
                                                                                                    ========
</TABLE>
Note:
(1) Our valuation methodology has been applied consistently in each period.

<TABLE>
<CAPTION>
TOTAL CARRYING VALUE OF DERIVATIVE CONTRACTS
                                                                                      June 30    December 31
(Cdn$ millions)                                                                          2006           2005
-------------------------------------------------------------------------------------------------------------
<S>                                                                                        <C>          <C>
Current Assets                                                                             449          382
Non Current Assets                                                                         131          232
                                                                                     ------------------------
   Total Derivative Contract Assets                                                        580          614
                                                                                     ========================

Current Liabilities                                                                        258          321
Non Current Liabilities                                                                     86          124
                                                                                     ------------------------
   Total Derivative Contract Liabilities                                                   344          445
                                                                                     ========================

   Total Derivative Contract Net Assets (1)                                                236          169
                                                                                     ========================
</TABLE>
Note:
(1) Does not include designated hedges. We recognize gains and losses on
   effective hedges in the same period as the hedged item.

                                      39
<PAGE>

NON-TRADING ACTIVITIES
We enter into fee-for-service  contracts related to transportation and storage
of third  party  oil and gas.  In  addition,  we earn  income  from our  power
generation facility.  We earned $2 million from these activities in the second
quarter (2005 - $7 million) and $5 million year to date (2005 - $13 million).

CHEMICALS

HIGHER CHEMICALS CONTRIBUTION INCREASED NET INCOME BY $8 MILLION
In North  America,  stronger  sodium  chlorate  prices  were  offset by weaker
chlor-alkali prices and lower sodium chlorate volumes.  Operating costs are up
reflecting  higher  electricity  costs. In Brazil,  sales remained strong as a
result of continued  demand from Aracruz  Cellulose,  our primary  customer in
Brazil, and from higher merchant market demand.

The weaker US dollar  reduced  quarterly  sales by  approximately  $4 million,
however,  this was offset by  mark-to-market  gains of $3 million on  Canadian
dollar  call  options  and by  foreign  exchange  gains of $7  million  on the
US-dollar denominated debt of Canexus. Depreciation,  depletion,  amortization
and impairment  expense for chemicals in the second quarter of 2005 included a
charge of $12  million  relating to the  closure of our  Amherstburg,  Ontario
chemicals plant.


CORPORATE EXPENSES

<TABLE>
<CAPTION>
GENERAL AND ADMINISTRATIVE (G&A)
                                                                       Three Months                Six Months
                                                                       Ended June 30              Ended June 30
(Cdn$ millions)                                                       2006         2005          2006        2005
------------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>          <C>          <C>         <C>
General and Administrative Expense before Stock-Based Compensation      97           59           172         115
Stock-Based Compensation (1)                                            14           65           153         190
                                                                     ---------------------------------------------
Total General and Administrative Expense                               111          124           325         305
                                                                     =============================================
</TABLE>
Note:
(1) Includes the tandem option plan, stock options for our US-based  employees
    and stock appreciation rights.

LOWER COSTS INCREASED QUARTERLY NET INCOME BY $13 MILLION
Higher G&A expenses  reflect higher  employee levels as we continue to develop
our  oil  and  gas  operations   internationally   and  expand  our  marketing
operations.  Strong  performance  from our  marketing  group  during  the year
increased our accrual for results-based compensation programs.

Changes in our share price create  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 each quarter to determine  our  share-based
compensation  expense and related  obligations.  For the second  quarter,  our
share  price  was  largely  unchanged  and  we  recorded  nominal  stock-based
compensation expense as a result.

<TABLE>
<CAPTION>
INTEREST AND FINANCING COSTS
                                                                       Three Months                Six Months
                                                                       Ended June 30              Ended June 30
(Cdn$ millions)                                                       2006         2005          2006        2005
------------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>          <C>          <C>         <C>
Interest                                                                71           74           137         141
    Less: Capitalized Interest                                         (60)         (43)         (117)        (76)
                                                                     ---------------------------------------------
Net Interest Expense                                                    11           31            20          65
                                                                     =============================================
</TABLE>

LOWER INTEREST EXPENSE INCREASED QUARTERLY NET INCOME BY $20 MILLION
Our financing costs were  comparable  with the second quarter of 2005.  During
the quarter,  the stronger  Canadian dollar lowered our US-dollar  denominated
interest by $5 million. The credit facilities of Canexus are included with our
results. This increased our expense by $3 million in the quarter.

We are capitalizing  interest on our major  development  projects in the North
Sea,  Stage 3 expansion at Syncrude and at Long Lake until  completion  of the
projects.  Capitalized  interest  in  2006  increased  primarily  from  higher
cumulative  investment in these projects.  We expect that capitalized interest
will  continue to increase as we spend  additional  capital on these  projects
prior to their completion later this year and in 2007.

                                      40
<PAGE>

<TABLE>
<CAPTION>
INCOME TAXES
                                                                Three Months                Six Months
                                                                Ended June 30              Ended June 30
(Cdn$ millions)                                                2006        2005           2006        2005
-----------------------------------------------------------------------------------------------------------
<S>                                                             <C>          <C>           <C>         <C>
Current                                                         136          81            245         160
Future                                                           13          17            284         (43)
                                                              ---------------------------------------------
Total Provision for Income Taxes                                149          98            529         117
                                                              =============================================

Disclosed as:
Provision for Income Taxes - Continuing Operations              149          83            529          90
Provision for Income Taxes - Discontinued Operations (1)         --          15             --          27
                                                              ---------------------------------------------
Total Provision for Income Taxes                                149          98            529         117
                                                              =============================================

Effective Tax Rate (%)                                          27%         33%            61%         33%
                                                              ---------------------------------------------
</TABLE>
Note:
(1) See Note 16 to our Unaudited Consolidated Financial Statements.

EFFECTIVE TAX RATE FOR THE QUARTER DECREASED TO 27%
In the first quarter, 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 has  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
provision for future income taxes during the quarter by $32 million.

Current  income taxes  include cash taxes in Yemen of $81 million  (2005 - $70
million) for the quarter and $148 million  (2005 - $129 million) year to date.
Our current  income tax  provision  also  includes  current taxes in Colombia,
federal and state taxes in the US and provincial capital taxes in Canada.

<TABLE>
<CAPTION>
OTHER
                                                                Three Months                Six Months
                                                                Ended June 30              Ended June 30
(Cdn$ millions)                                                2006         2005          2006        2005
-----------------------------------------------------------------------------------------------------------
<S>                                                              <C>         <C>            <C>       <C>
Change in Fair Value of Crude Oil Put Options                     3          (10)           (1)       (183)
                                                              ---------------------------------------------
</TABLE>

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 WTI 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 the first six
months of 2005, a significant  increase in forward crude prices  resulted in a
value loss of $183 million.  Strong WTI prices in 2006 have reduced the market
value of these  options to nil and we expensed $4 million in the first quarter
as a result.

Late in the second quarter, 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  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 gain of
$3 million for the change in fair value during the second quarter.

                                      41
<PAGE>

LIQUIDITY

<TABLE>
<CAPTION>
CAPITAL STRUCTURE

                                                                              June 30    December 31
(Cdn$ millions)                                                                  2006           2005
-----------------------------------------------------------------------------------------------------
<S>                                                                             <C>           <C>
NET DEBT (1)
   Bank Debt                                                                      640           171
   Public Senior Notes                                                          2,863         2,980
                                                                             ------------------------
     Senior Debt                                                                3,503         3,151
   Subordinated Debt                                                              513           536
                                                                             ------------------------
     Total Debt                                                                 4,016         3,687
   Less: Cash and Cash Equivalents                                                (86)          (48)
                                                                             ------------------------
                                                                                3,930         3,639
   Less: Non-Cash Working Capital, Restricted Cash and Margin Deposits (2)       (165)            2
                                                                             ------------------------
TOTAL NET DEBT                                                                  3,765         3,641
                                                                             ========================

SHAREHOLDERS' EQUITY (3)                                                        4,308         4,008
                                                                             ========================
</TABLE>

Notes:
(1) Includes  all of our debt and is  calculated  as  long-term  debt less net
    working capital.
(2) Excludes short-term borrowings since these are included in bank debt.
(3) At June 30, 2006, there were 262,142,876  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.

<TABLE>
<CAPTION>
CHANGE IN WORKING CAPITAL

                                                               June 30     December 31       Increase/
(Cdn$ millions)                                                   2006            2005      (Decrease)
-------------------------------------------------------------------------------------------------------
<S>                                                             <C>             <C>               <C>
Cash and Cash Equivalents                                           86              48             38
Restricted Cash and Margin Deposits                                 58              70            (12)
Accounts Receivable                                              2,388           3,151           (763)
Inventories and Supplies                                           745             504            241
Accounts Payable and Accrued Liabilities                        (2,990)         (3,710)           720
Other                                                              (36)            (17)           (19)
                                                              -----------------------------------------
   Net Working Capital                                             251              46            205
                                                              =========================================
</TABLE>

Accounts  receivable and payable related to our marketing  operation decreased
from year end as a result of lower  natural  gas  prices.  Natural  gas prices
spiked in December 2005,  which  increased our accrued gas sales and purchases
at the end of the year.  Natural gas prices have fallen since the beginning of
the  year,  lowering  our  accruals  at the end of the  quarter.  We also took
advantage  of low gas prices  during the year and  increased  our gas  storage
inventories  to 43 bcf at the end of the quarter.  Offsetting  the decrease in
marketing  payables  was  an  increase  in  accrued  stock-based  compensation
obligations  since the  beginning  of the year as a result of our strong share
price.

NET DEBT

Our net debt levels are directly  related to our operating  cash flows and our
capital expenditure activities. Changes in net debt since the beginning of the
year are related to:

<TABLE>
<CAPTION>
(Cdn$ millions)
-------------------------------------------------------------------------------------------------------
<S>                                                                                             <C>
Capital Expenditures                                                                            1,551
Cash Flow from Operating Activities                                                            (1,108)
Changes in Non-Cash Working Capital                                                              (245)
                                                                                             ----------
   Excess                                                                                         198

Dividends on Common Shares                                                                         26
Issue of Common Shares and Exercise of Stock Options                                              (37)
Foreign Exchange Translation of US-dollar Debt and Cash                                          (134)
Increase in Current Obligation Related to Stock-Based Compensation                                 90
Other                                                                                             (19)
                                                                                             ----------
   Increase in Net Debt                                                                           124
                                                                                             ==========
</TABLE>

                                      42
<PAGE>

OUTLOOK FOR REMAINDER OF 2006
We continue to expect our 2006 full year production to average between 220,000
and 240,000 boe/d before  royalties.  Production is expected to increase later
this year as we bring the Syncrude  expansion  back on-line,  bring on another
development  well at Aspen in the Gulf of Mexico and  commence  production  at
Buzzard.  Where we end up in our  range  will  largely  be  determined  by the
productivity  of the Aspen well and the timing of first oil from  Buzzard.  We
expect to generate approximately $2.7 billion in cash flow (before remediation
and geological and geophysical  expenditures) in 2006,  assuming the following
for the remainder of the year:


--------------------------------------------------------------------------------
WTI (US$/bbl)                                                             65.00
NYMEX Natural Gas (US$/mmbtu)                                              7.25
US to Canadian Dollar Exchange Rate                                        0.90
                                                                    ------------

To date, we have  incurred over 50% of our planned 2006 capital  investment of
$2.9 billion.  Our 2006 capital program is largely  targeted towards our major
development  projects  in the North  Sea,  Long  Lake,  coalbed  methane,  and
Syncrude  Stage 3, all  planned to come  on-stream  within the next two years.
Accelerated investments in CBM projects, additional drilling opportunities and
higher costs at Aspen and Long Lake could increase our 2006 capital investment
program by 10%.

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.  We are well advanced in developing a number of major
projects  and there  remain  additional  capital  requirements  to bring  them
on-stream.  Based on the  assumptions  noted  above,  our  capital  investment
program and dividend  requirements  could exceed our cash flow in 2006 by $340
million.  We plan to fund this  shortfall  by drawing on our unused  committed
credit facilities. In the fourth quarter of 2006, we must repay $90 million of
medium term notes that become due, which we expect to fund using our committed
credit  facilities.  At June 30, 2006, we had committed term credit facilities
of $2.3 billion that are available until 2010, of which $390 million was drawn
and $157 million was  utilized to support  outstanding  letters of credit.  In
July 2006, we amended our committed term credit  facilities by increasing them
to $3.4 billion and extending the  availability  until 2011. We also have $731
million of uncommitted,  unsecured credit facilities, of which $87 million was
drawn and $69 million was utilized to support outstanding letters of credit as
at June 30, 2006.

Late in the  second  quarter,  we  implemented  a crude oil  price  protection
strategy on a portion of our 2007 crude oil  production.  We purchased WTI put
options on 105,000 bbls/d for $26 million. These options establish a WTI floor
price of US$50/bbl on these volumes in 2007.

In the first and second quarters,  we declared common share dividends of $0.05
per share each quarter.  We expect to declare quarterly common share dividends
of $0.05 per share in the remainder of the year.

CONTRACTUAL OBLIGATIONS, COMMITMENTS AND GUARANTEES
We have assumed various contractual  obligations and commitments in the normal
course of our  operations  and financing  activities.  We have included  these
obligations  and  commitments  in our MD&A in our 2005  Annual  Report on Form
10-K.  During the six months ended June 30, 2006,  we entered into  additional
operating leases and work commitments  totaling $433 million,  mainly relating
to the signing of contracts  relating to our Ettrick  development in the North
Sea. Of the increase,  we expect to incur  approximately $46 million in one to
three years  time,  $225  million in four to five years time and $162  million
after five years.


CONTINGENCIES
There are a number of lawsuits and claims  pending,  the  ultimate  results of
which cannot be ascertained at this time. 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.  These  matters  are  described  in LEGAL
PROCEEDINGS in Item 3 contained in our 2005 Annual Report on Form 10-K.  There
have been no significant developments since year end except as noted below.

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  released  its  tribunal's
partial  award  that held we were  obliged  to offer  Occidental  the right to
acquire  50% of our  interest  in  those  areas  and  that  we  breached  that
obligation.  The  result  of this  award is that  Occidental  is  entitled  to
monetary damages. The ICC tribunal did not determine the amount of damages due
to Occidental in this partial  award.  These damages will be determined at the
conclusion of the second and final phase of the arbitration  which will likely
occur in late 2007.  The amount of damages  cannot be reasonably  estimated at
this  time.  Resolution  of this  matter is not  expected  to have a  material
adverse effect on our liquidity,  consolidated financial position or operating
activities.

                                      43
<PAGE>

NEW ACCOUNTING PRONOUNCEMENTS

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

o  1530,  COMPREHENSIVE  INCOME;
o  3855,  FINANCIAL  INSTRUMENTS  --  RECOGNITION  AND  MEASUREMENT;  and
o  3865,  HEDGES.

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

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

o  financial  assets held for sale, for which unrealized gains and losses are
   deferred in other comprehensive income until sold or impaired; and
o  certain financial instruments that qualify for hedge accounting.

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

These new  standards  are  effective  for fiscal  years  beginning on or after
October 1, 2006 and early adoption is permitted.  Adoption of these  standards
as at June 30, 2006 would  increase  our  accounts  receivable  by $6 million,
increase  our  future  income  tax  liabilities  by $2  million  and  increase
shareholders' equity by $4 million.

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
clarifies the accounting  for  stock-based  compensation  plans that allow for
vesting of stock-based awards after an employee's retirement.  If the employee
is eligible to retire on the grant date of an award, related compensation cost
is to be  recognized  in full at that  date as  there  is no  ongoing  service
requirement  to earn the award.  If the  employee  becomes  eligible to retire
during the vesting period,  the compensation cost is to be recognized over the
period  from the grant date to the  retirement  eligibility  date.  EIC-162 is
effective for interim and annual periods ending on or after December 31, 2006.
We do not expect the adoption of EIC-162 will have any material  impact on our
results of operations or financial position.

US PRONOUNCEMENTS
In February  2006,  the  Financial  Accounting  Standards  Board (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 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.

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

                                      44
<PAGE>

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  Unaudited  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.

The impact of adopting Statement 123(R) on our results for the three months
ended June 30, 2006 is as follows:

<TABLE>
<CAPTION>
                                                                   Prior to adoption    After adoption      Increase /
(Cdn$ millions, except per share amounts)                            of FAS 123(R)       of FAS 123(R)      (Decrease)
----------------------------------------------------------------------------------------------------------------------
<S>                                                                          <C>                 <C>             <C>
Income from Continuing Operations before Income Taxes - US GAAP               560                 549             (11)
Net Income - US GAAP                                                          405                 397              (8)
Basic Earnings per Common Share - US GAAP ($/share)                          1.55                1.52           (0.03)
Diluted Earnings per Common Share - US GAAP ($/share)                        1.51                1.48           (0.03)
                                                                   ---------------------------------------------------

The impact of adopting Statement 123(R) on our results for the six months
ended June 30, 2006 is as follows:

                                                                   Prior to adoption    After adoption      Increase /
(Cdn$ millions, except per share amounts)                            of FAS 123(R)       of FAS 123(R)      (Decrease)
----------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Income Taxes - US GAAP               872                 854             (18)
Net Income - US GAAP                                                          608                 596             (12)
Basic Earnings per Common Share - US GAAP ($/share)                          2.32                2.28           (0.04)
Diluted Earnings per Common Share - US GAAP ($/share)                        2.26                2.22           (0.04)
                                                                   ---------------------------------------------------
</TABLE>

We   recognize   stock-based   compensation   expense   for  our  retired  and
retirement-eligible employees over an accelerated 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 months ended June 30,
2006 and 2005 and for the six months ended June 30, 2006 and 2005.

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. We have not yet
determined  the  impact  this  interpretation  will  have on our  results  from
operations or financial position.

EQUITY SECURITY REPURCHASES
During the quarter we made no purchases of our own equity securities.


                                      45
<PAGE>

<TABLE>
<CAPTION>
SUMMARY OF QUARTERLY RESULTS
                                                                          Three Months Ended
                                                        2004                    2005                        2006
(Cdn$ millions, except per share amounts)            Sep     Dec     Mar    Jun      Sep        Dec     Mar      Jun
----------------------------------------------------------------- ---------------------------------- ----------------
<S>                                                  <C>     <C>     <C>    <C>    <C>        <C>       <C>    <C>
Net Sales from Continuing Operations                 778     805     856    909    1,094      1,073     980    1,039
Net Income (Loss) from Continuing Operations         200     226      19    170      211        300     (79)     406
Net Income from Discontinued Operations               20      20      18     30      404         --      --       --
                                                   ------------------------------------------------------------------
Net Income (Loss)                                    220     246      37    200      615        300     (79)     406
                                                   ==================================================================

Earnings (Loss) per Common Share from
     Continuing Operations ($/share)
   Basic                                            0.77    0.87    0.07   0.65     0.81       1.15   (0.30)    1.55
   Diluted                                          0.76    0.86    0.07   0.64     0.79       1.12   (0.30)    1.52

Earnings (Loss) per Common Share ($/share)
   Basic                                            0.85    0.95    0.14   0.77     2.36       1.15   (0.30)    1.55
   Diluted                                          0.84    0.94    0.14   0.76     2.30       1.12   (0.30)    1.52
                                                   ------------------------------------------------------------------
</TABLE>

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain  statements  in this  report,  including  those  appearing in ITEM 2 -
MANAGEMENT'S  DISCUSSION  AND ANALYSIS OF FINANCIAL  CONDITION  AND RESULTS OF
OPERATIONS, are forward-looking  statements.(1) Forward-looking statements are
generally  identifiable by terms such as ANTICIPATE,  BELIEVE,  INTEND,  PLAN,
EXPECT,  ESTIMATE,  BUDGET,  OUTLOOK  or  other  similar  words,  and  include
statements relating to future production  associated with our coalbed methane,
Long Lake, Syncrude, North Sea, West Africa and other projects.

These statements are subject to known and unknown risks and  uncertainties and
other  factors  which  may  cause  actual  results,  levels  of  activity  and
achievements  to differ  materially  from those  expressed  or implied by such
statements. These risks, uncertainties and other factors include:

o    market prices for oil, natural gas and chemicals products;
o    our ability to produce and transport crude oil and natural gas to markets;
o    the  results  of  exploration  and   development   drilling  and  related
     activities;
o    foreign-currency exchange rates;
o    economic  conditions  in the  countries  and regions in which we carry on
     business;
o    governmental  actions that increase taxes, change environmental and other
     laws and regulations;
o    renegotiations of contracts;
o    results of litigation, arbitration or regulatory proceedings; and
o    political  uncertainty,  including  actions by  terrorists,  insurgent or
     other groups, or other armed conflict, including conflict between states.

The above  items and their  possible  impact are  discussed  more fully in the
section  titled  RISK  FACTORS  in  Item 7 and  QUANTITATIVE  AND  QUALITATIVE
DISCLOSURES  ABOUT  MARKET RISK in Item 7A of our 2005  Annual  Report on Form
10-K.


--------
(1)  Within the meaning of the United  States  PRIVATE  SECURITIES  LITIGATION
     REFORM ACT OF 1995, Section 21E of the United States SECURITIES  EXCHANGE
     ACT OF 1934, as amended,  and Section 27A of the United States SECURITIES
     ACT OF 1933, as amended.

                                      46
<PAGE>

The  impact  of  any  one  risk,   uncertainty   or  factor  on  a  particular
forward-looking  statement  is not  determinable  with  certainty as these are
interdependent  and  management's  future  course of action  depends  upon our
assessment of all information available at that time. Any statements regarding
the following are forward-looking statements:

o    future crude oil, natural gas or chemicals prices;
o    future production levels;
o    future cost recovery oil revenues from our operations in Yemen;
o    future  capital  expenditures  and their  allocation to  exploration  and
     development activities;
o    future asset dispositions;
o    future sources of funding for our capital program;
o    future debt levels;
o    future cash flows and their uses;
o    future drilling of new wells;
o    ultimate recoverability of reserves;
o    expected finding and development costs;
o    expected operating costs;
o    future demand for chemicals products;
o    future  expenditures  and future  allowances  relating  to  environmental
     matters; and
o    dates by which certain areas will be developed or will come on-stream.

We believe that any  forward-looking  statements made are reasonable  based on
information available to us on the date such statements were made. However, no
assurance  can  be  given  as  to  future  results,  levels  of  activity  and
achievements.  We undertake  no  obligation  to update  publicly or revise any
forward-looking   statements   contained  in  this  report.   All   subsequent
forward-looking  statements,  whether  written or oral,  attributable to us or
persons  acting on our behalf are  expressly  qualified  in their  entirety by
these cautionary statements.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are  exposed  to  normal  market  risks  inherent  in the  oil  and gas and
chemicals  business,  including  commodity price risk,  foreign-currency  rate
risk,  interest rate risk and credit risk. We recognize these risks and manage
our  operations  to  minimize  our  exposures  to the  extent  practical.  The
information  presented on market risks in Item 7A on pages 75 - 78 in our 2005
Annual Report on Form 10-K has not changed materially since December 31, 2005.

ITEM 4.    CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Our Chief  Executive  Officer and Chief  Financial  Officer have evaluated the
effectiveness  of our  disclosure  controls  and  procedures  (as  defined  in
Exchange  Act Rules  13a-15(e)  and  15-d-15(e))  as of the end of the  period
covered  by this  report.  They  concluded  that,  as of the end of the period
covered by this report,  our disclosure  controls and procedures were adequate
and effective in ensuring that  material  information  relating to the Company
and its consolidated subsidiaries would be made known to them by others within
those entities,  particularly during the period in which this report was being
prepared.  Management  recognizes that any controls and procedures,  no matter
how well  designed  and  operated,  can provide only  reasonable  assurance of
achieving the desired control  objectives,  and in reaching a reasonable level
of  assurance,  management  necessarily  is required to apply its  judgment in
evaluating the cost-benefit relationship of possible controls and procedures.

CHANGES IN INTERNAL CONTROLS

We have  continually  had in place systems  relating to internal  control over
financial  reporting.  To keep pace with growth in our US  operations,  we are
implementing   additional   inventory  tracking  and  procure-to-pay   process
controls.  We have evaluated these changes and confirm that there has not been
any change in the Company's  internal control over financial  reporting during
the second  quarter of 2006 that has  materially  affected,  or is  reasonably
likely to materially  affect,  the Company's  internal  control over financial
reporting.  As well,  based  on  these  evaluations,  there  were no  material
weaknesses  in these  internal  controls  requiring  corrective  action.  As a
result, no such corrective actions were taken.



                                      47
<PAGE>

                                    PART II

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

Our Annual  General  Meeting of  Shareowners  was held on April 27, 2006.  The
following actions were taken at the Meeting,  for which proxies were solicited
pursuant to Section 85 of the Securities Act (Ontario).

(a)  Each of the eleven director  nominees  proposed by management was elected
     by a show of hands. Proxies were received as follows:

     Director                                           For           Withheld
     --------------------------------------------------------------------------
     Charles W. Fischer                            180,451,075       1,966,039
     Dennis G. Flanagan                            181,623,004         794,110
     David A. Hentschel                            110,630,199      71,786,915
     S. Barry Jackson                              162,122,014      20,295,100
     Kevin J. Jenkins                              182,237,058         180,056
     Eric P. Newell, O.C.                          182,196,102         221,012
     Thomas C. O'Neill                             181,262,782       1,154,332
     Francis M. Saville, Q.C.                      160,997,089      21,420,025
     Richard M. Thomson, O.C.                      162,133,251      20,283,863
     John M. Willson                               162,135,336      20,281,778
     Victor J. Zaleschuk                           109,818,876      72,598,238

(b)  The appointment of Deloitte & Touche LLP, Chartered Accountants, to serve
     as the  independent  auditor  for 2006 was  approved  by a show of hands.
     Proxies of 180,272,674  (98.82%) for and 2,144,440  (1.18%) withheld were
     received.


ITEM 6.    EXHIBITS

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

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

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

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

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 July 14, 2006.

                                         NEXEN INC.

                                         /s/ Charles W. Fischer
                                         -------------------------------------
                                         Charles W. Fischer
                                         President and Chief Executive Officer
                                         (Principal Executive Officer)


                                         /s/ Michael J. Harris
                                         -------------------------------------
                                         Michael J. Harris
                                         Controller
                                         (Principal Accounting Officer)



                                      48