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, 2009

[_]       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]


                                   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 (or for such  shorter  period that the  registrant  was
required  to file  such  reports),  and  (2) has  been  subject  to such  filing
requirements for the past 90 days.

                  Yes   [X]                    No    [ ]

Indicate by check mark whether the registrant has submitted  electronically  and
posted on its corporate Web site, if any, every  Interactive  Data File required
to be submitted and posted pursuant to Rule 405 of Regulation S-T (ss.232.405 of
this chapter)  during the  preceding 12 months (or for such shorter  period that
the registrant was required to submit and post such files).

                  Yes   [ ]                    No    [ ]

Indicate by check mark whether the registrant is a large  accelerated  filer, an
accelerated filer, a non-accelerated  filer, or a smaller reporting company. See
the definitions of "large accelerated  filer",  "accelerated filer" and "smaller
reporting company" in Rule 12b-2 of the Exchange Act.

          Large accelerated filer [X]     Accelerated filer [ ]

           Non-Accelerated filer  [ ]     Smaller reporting company  [ ]

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, 2009, there were 521,205,270 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 (MD&A) ...............................29
    Item 3.   Quantitative and Qualitative Disclosures about Market Risk .....49
    Item 4.   Controls and Procedures ........................................49

PART II       OTHER INFORMATION
    Item 1.   Legal Proceedings ..............................................50
    Item 4.   Submission of Matters to a Vote of Security Holders ............50
    Item 6.   Exhibits .......................................................50

This report  should be read in  conjunction  with our 2008 Annual Report on Form
10-K  (2008  Form  10-K)  and with our  current  reports  on Forms  8-K filed or
furnished during the year.


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
79 of our 2008 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>
<CAPTION>
<S>                                                   <C>
/d      =   per day                                   mcf     =   thousand cubic feet
bbl     =   barrel                                    mmcf    =   million cubic feet
mbbls   =   thousand barrels                          bcf     =   billion cubic feet
mmbbls  =   million barrels                           NGL     =   natural gas liquid
mmbtu   =   million British thermal units             WTI     =   West Texas Intermediate
boe     =   barrel of oil equivalent                  MW      =   megawatt
mboe    =   thousand barrels of oil equivalent        GWh     =   gigawatt hours
mmboe   =   million barrels of oil equivalent         Brent   =   Dated Brent
PSCTM   =   Premium Synthetic CrudeTM                 NYMEX   =   New York Mercantile Exchange
</TABLE>

In this Form 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, 2009,  the noon-day  exchange rate was  US$0.8602  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, 2009 and 2008....................4

Unaudited Consolidated Balance Sheet
as at June 30, 2009 and December 31, 2008....................................5

Unaudited Consolidated Statement of Cash Flows
for the Three and Six Months Ended June 30, 2009 and 2008....................6

Unaudited Consolidated Statement of Shareholders' Equity
for the Three and Six Months Ended June 30, 2009 and 2008....................7

Unaudited Consolidated Statement of Comprehensive Income
for the Three and Six Months Ended June 30, 2009 and 2008....................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

                                                                      Three Months             Six Months
                                                                      Ended June 30           Ended June 30
(Cdn$ millions, except per share amounts)                           2009         2008        2009       2008
-------------------------------------------------------------------------------------------------------------
<S>                                                                <C>          <C>         <C>        <C>
REVENUES AND OTHER INCOME
     Net Sales                                                     1,200        2,071       2,248      3,941
     Marketing and Other (Note 15)                                    82           34         339        256
                                                                  -------------------------------------------
                                                                   1,282        2,105       2,587      4,197
                                                                  -------------------------------------------
EXPENSES
     Operating                                                       320          348         625        657
     Depreciation, Depletion, Amortization and Impairment            413          334         822        698
     Transportation and Other                                        232          195         433        400
     General and Administrative                                      167          418         267        473
     Exploration                                                      77          101         130        133
     Interest (Note 10)                                               74           16         142         43
                                                                  -------------------------------------------
                                                                   1,283        1,412       2,419      2,404
                                                                  -------------------------------------------

INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES                       (1)         693         168      1,793
                                                                  -------------------------------------------

PROVISION FOR (RECOVERY OF) INCOME TAXES
     Current                                                         206          451         324        843
     Future                                                         (229)        (139)       (316)       (62)
                                                                  -------------------------------------------
                                                                     (23)         312           8        781
                                                                  -------------------------------------------

NET INCOME                                                            22          381         160      1,012
     Less: Net Income Attributable to Non-Controlling Interests       (2)          (1)         (5)        (2)
                                                                  -------------------------------------------

NET INCOME ATTRIBUTABLE TO NEXEN INC.                                 20          380         155      1,010
                                                                  ===========================================

EARNINGS PER COMMON SHARE ($/share) (Note 16)
     Basic                                                          0.04         0.72        0.30       1.91
                                                                  ===========================================

     Diluted                                                        0.04         0.70        0.30       1.87
                                                                  ===========================================
</TABLE>


SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.


                                       4
<PAGE>

<TABLE>
<CAPTION>
NEXEN INC.
UNAUDITED CONSOLIDATED BALANCE SHEET

                                                                            June 30     December 31
(Cdn$ millions, except share amounts)                                          2009            2008
----------------------------------------------------------------------------------------------------
<S>                                                                          <C>             <C>
ASSETS
   CURRENT ASSETS
      Cash and Cash Equivalents                                               1,974           2,003
      Restricted Cash (Notes 2 and 8)                                           335             103
      Accounts Receivable (Note 3)                                            3,272           3,163
      Inventories and Supplies (Note 4)                                         598             484
      Other                                                                     167             169
                                                                        ----------------------------
         Total Current Assets                                                 6,346           5,922
                                                                        ----------------------------

   PROPERTY, PLANT AND EQUIPMENT
      Net of Accumulated Depreciation, Depletion, Amortization and
         Impairment of $10,722 (December 31, 2008 - $10,393)                 15,917          14,922
   GOODWILL                                                                     372             390
   FUTURE INCOME TAX ASSETS                                                     921             351
   DEFERRED CHARGES AND OTHER ASSETS (Note 6)                                   370             570
                                                                        ----------------------------
TOTAL ASSETS                                                                 23,926          22,155
                                                                        ============================

LIABILITIES
   CURRENT LIABILITIES
      Accounts Payable and Accrued Liabilities (Note 9)                       3,608           3,326
      Accrued Interest Payable                                                   63              67
      Dividends Payable                                                          26              26
                                                                        ----------------------------
         Total Current Liabilities                                            3,697           3,419
                                                                        ----------------------------

   LONG-TERM DEBT (Note 10)                                                   7,863           6,578
   FUTURE INCOME TAX LIABILITIES                                              2,852           2,619
   ASSET RETIREMENT OBLIGATIONS (Note 12)                                     1,044           1,024
   DEFERRED CREDITS AND OTHER LIABILITIES (Note 13)                           1,167           1,324

SHAREHOLDERS' EQUITY (Note 14)
   Nexen Inc. Shareholders' Equity
      Common Shares, no par value
         Authorized:   Unlimited
         Outstanding:  2009 - 521,205,270 shares
                       2008 - 519,448,590 shares                              1,011             981
      Contributed Surplus                                                         2               2
      Retained Earnings                                                       6,393           6,290
      Accumulated Other Comprehensive Loss                                     (157)           (134)
                                                                        ----------------------------
   Total Nexen Inc. Shareholders' Equity                                      7,249           7,139
      Non-Controlling Interests                                                  54              52
                                                                        ----------------------------
   TOTAL SHAREHOLDERS' EQUITY                                                 7,303           7,191
   COMMITMENTS, CONTINGENCIES AND GUARANTEES (Note 17)
                                                                        ----------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                                   23,926          22,155
                                                                        ============================
</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

                                                                              Three Months             Six Months
                                                                             Ended June 30            Ended June 30
(Cdn$ millions)                                                             2009       2008         2009        2008
---------------------------------------------------------------------------------------------------------------------
<S>                                                                         <C>       <C>          <C>         <C>
OPERATING ACTIVITIES
   Net Income                                                                 22        381          160       1,012
   Charges and Credits to Income not Involving Cash (Note 18)                394        470          713         852
   Exploration Expense                                                        77        101          130         133
   Changes in Non-Cash Working Capital (Note 18)                            (340)       232           80         372
   Other                                                                     (44)       (21)        (185)        (38)
                                                                        ---------------------------------------------
                                                                             109      1,163          898       2,331

FINANCING ACTIVITIES
   Proceeds from (Repayment of) Term Credit Facilities, Net                  632          -        1,643        (228)
   Proceeds from (Repayment of) Canexus Term Credit Facilities, Net           42        (18)          52         (10)
   Proceeds from Canexus Notes                                                 -         51            -          51
   Repayment of Medium-Term Notes                                              -       (125)           -        (125)
   Dividends on Common Shares                                                (26)       (27)         (52)        (40)
   Distributions Paid to Non-Controlling Interests                            (4)        (3)          (7)         (7)
   Issue of Common Shares and Exercise of Tandem Options for Shares            7         14           30          40
   Other                                                                       -         (2)          (1)         (2)
                                                                        ---------------------------------------------
                                                                             651       (110)       1,665        (321)

INVESTING ACTIVITIES
   Capital Expenditures
       Exploration and Development                                          (631)      (606)      (1,335)     (1,375)
       Proved Property Acquisitions                                            -         (2)        (755)         (2)
       Marketing, Chemicals, Corporate and Other                             (84)       (30)        (129)        (47)
   Proceeds on Disposition of Assets                                           1          -           15           -
   Changes in Restricted Cash                                                 67       (174)        (247)        (53)
   Changes in Non-Cash Working Capital (Note 18)                             (74)       (76)         (55)        (54)
   Other                                                                       1        (70)          (1)        (97)
                                                                        ---------------------------------------------
                                                                            (720)      (958)      (2,507)     (1,628)

EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS                (120)        (5)         (85)         26
                                                                        ---------------------------------------------

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                             (80)        90          (29)        408

CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD                            2,054        524        2,003         206
                                                                        ---------------------------------------------

CASH AND CASH EQUIVALENTS - END OF PERIOD (1)                              1,974        614        1,974         614
                                                                        =============================================
</TABLE>

(1) Cash and cash  equivalents  at June 30, 2009 consist of cash of $227 million
    and  short-term  investments  of $1,747 million (June 30, 2008 - cash of $32
    million and short-term investments of $582 million).


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

                                                                                    Three Months            Six Months
                                                                                   Ended June 30           Ended June 30
(Cdn$ millions)                                                                  2009        2008        2009       2008
-------------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>          <C>        <C>         <C>
COMMON SHARES, Beginning of Period                                              1,004         949         981        917
      Issue of Common Shares                                                        6           4          29         24
      Exercise of Tandem Options for Shares                                         1          10           1         16
      Accrued Liability Relating to Tandem Options Exercised for
         Common Shares                                                              -           9           -         15
                                                                             --------------------------------------------
   Balance at End of Period                                                     1,011         972       1,011        972
                                                                             ============================================

CONTRIBUTED SURPLUS, Beginning of Period                                            2           3           2          3
      Exercise of Tandem Options                                                    -          (1)          -         (1)
                                                                             --------------------------------------------
   Balance at End of Period                                                         2           2           2          2
                                                                             ============================================

RETAINED EARNINGS, Beginning of Period                                          6,399       5,600       6,290      4,983
      Net Income Attributable to Nexen Inc.                                        20         380         155      1,010
      Dividends on Common Shares (Note 14)                                        (26)        (27)        (52)       (40)
                                                                             --------------------------------------------
   Balance at End of Period                                                     6,393       5,953       6,393      5,953
                                                                             ============================================

ACCUMULATED OTHER COMPREHENSIVE LOSS, Beginning of Period                        (128)       (266)       (134)      (293)
      Other Comprehensive Income (Loss)                                           (29)         (8)        (23)        19
                                                                             --------------------------------------------
   Balance at End of Period                                                      (157)       (274)       (157)      (274)
                                                                             ============================================

NON-CONTROLLING INTERESTS, Beginning of Period                                     52          64          52         67
      Net Income Attributable to Non-Controlling Interests                          6           1           9          2
      Distributions Declared to Non-Controlling Interests                          (5)         (4)         (9)        (8)
      Issue of Partnership Units to Non-Controlling Interests under
         Distribution Reinvestment Plan                                             1           1           2          1
                                                                             --------------------------------------------
   Balance at End of Period                                                        54          62          54         62
                                                                             ============================================

<CAPTION>
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)
FOR THE THREE AND SIX MONTHS ENDED JUNE 30

                                                                                   Three Months             Six Months
                                                                                   Ended June 30           Ended June 30
(Cdn$ millions)                                                                  2009        2008        2009       2008
-------------------------------------------------------------------------------------------------------------------------
<S>                                                                              <C>         <C>         <C>       <C>
NET INCOME ATTRIBUTABLE TO NEXEN INC.                                              20         380         155      1,010
   Other Comprehensive Income (Loss), Net of Income Taxes:
      Foreign Currency Translation Adjustment
         Net Gains (Losses) on Investment in Self-Sustaining Foreign
              Operations                                                         (459)        (42)       (285)       144
         Net Gains (Losses) on Foreign-Denominated Debt Hedging Self-
             Sustaining Foreign Operations(1)                                     430          34         262       (125)
                                                                             --------------------------------------------
      Other Comprehensive Income (Loss)                                           (29)         (8)        (23)        19
                                                                             --------------------------------------------
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO NEXEN INC.                             (9)        372         132      1,029
                                                                             ============================================
</TABLE>

(1)  Net of income tax expense for the three  months ended June 30, 2009 of $62
     million (2008 - $4 million  expense) and net of income tax expense for the
     six  months  ended  June  30,  2009 of $38  million  (2008  - $19  million
     recovery).

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 GAAP on the Unaudited
Consolidated  Financial  Statements  is  disclosed in Note 20. 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, 2009 and December 31,
2008 and the results of our  operations and our cash flows for the three and six
months ended June 30, 2009 and 2008.


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 on an
ongoing basis,  including those related to accruals,  litigation,  environmental
and asset retirement  obligations,  recoverability of assets, income taxes, fair
values of derivative assets and liabilities,  capital adequacy and determination
of proved  reserves.  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, 2009 are
not  necessarily  indicative  of the results of  operations  or cash flows to be
expected for the year ending  December 31, 2009. As at July 15, 2009,  there are
no material subsequent events requiring additional disclosure in or amendment to
these financial statements.

These Unaudited  Consolidated Financial Statements should be read in conjunction
with our Audited  Consolidated  Financial  Statements  included in our 2008 Form
10-K. Except as described below, the accounting policies we follow are described
in Note 1 of the Audited Consolidated  Financial Statements included in our 2008
Form 10-K.


CHANGES IN ACCOUNTING POLICIES

GOODWILL AND INTANGIBLE ASSETS
On January  1, 2009,  we  retrospectively  adopted  the  Canadian  Institute  of
Chartered Accountants (CICA) Section 3064, GOODWILL AND INTANGIBLE ASSETS issued
by the AcSB. This section  clarifies the criteria for the recognition of assets,
intangible assets and internally developed  intangible assets.  Adoption of this
standard  did not  have a  material  impact  on our  results  of  operations  or
financial position.

Business Combinations
On January  1, 2009,  we  prospectively  adopted  CICA  Section  1582,  BUSINESS
COMBINATIONS  issued  by the  AcSB.  This  section  establishes  principles  and
requirements of the  acquisition  method for business  combinations  and related
disclosures.  Adoption of this  statement did not have a material  impact on our
results of operations or financial position.

CONSOLIDATED FINANCIAL STATEMENTS AND NON-CONTROLLING INTERESTS
On January 1,  2009,  we adopted  CICA  Sections  1601,  CONSOLIDATED  FINANCIAL
STATEMENTS, and 1602, NON-CONTROLLING INTERESTS issued by the AcSB. Section 1601
establishes standards for the preparation of consolidated  financial statements.
Section 1602 provides  guidance on accounting for  non-controlling  interests in
consolidated financial statements subsequent to a business combination. Adoption
of these  statements did not have a material impact on our results of operations
or financial position. The retrospective presentation changes have been included
in the Unaudited Consolidated Financial Statements as applicable.

                                       8
<PAGE>

2.   RESTRICTED CASH

At June 30,  2009,  our  restricted  cash  consists  of margin  deposits of $335
million (December 31, 2008 - $103 million) related to exchange-traded derivative
financial  contracts  used by our  energy  marketing  group  to  hedge  physical
commodities,  and storage,  transportation and customer sales contracts.  We are
required  to  maintain  margin  for net  out-of-the-money  derivative  financial
contracts.  The increase in margin  primarily  relates to  derivative  financial
contracts  hedging our natural gas positions.  Declining  natural gas prices and
widening time spreads  increased  the value of storage and fixed price  customer
sales contracts.  Concurrently, the derivative financial contracts hedging these
positions  declined  in  value.  Additional  margin  was  required  to cover the
increase in the net out-of-the-money derivative financial contracts.

3.   ACCOUNTS RECEIVABLE

<TABLE>
<CAPTION>
                                                                 June 30    December 31
                                                                    2009           2008
-----------------------------------------------------------------------------------------
<S>                                                              <C>        <C>
Trade
     Energy Marketing                                              1,682          1,501
     Energy Marketing Derivative Contracts (Note 7)                  614            755
     Oil and Gas                                                     778            639
     Chemicals and Other                                              47             68
                                                            -----------------------------
                                                                   3,121          2,963
Non-Trade                                                            215            270
                                                            -----------------------------
                                                                   3,336          3,233
Allowance for Doubtful Receivables                                   (64)           (70)
                                                            -----------------------------
Total                                                              3,272          3,163
                                                            =============================
</TABLE>

4.   INVENTORIES AND SUPPLIES

<TABLE>
<CAPTION>
                                                                 June 30    December 31
                                                                    2009           2008
-----------------------------------------------------------------------------------------
<S>                                                              <C>        <C>
Finished Products
     Energy Marketing                                                466            384
     Oil and Gas                                                      21             17
     Chemicals and Other                                              14             16
                                                            -----------------------------
                                                                     501            417
Work in Process                                                        9              6
Field Supplies                                                        88             61
                                                            -----------------------------
Total                                                                598            484
                                                            =============================
</TABLE>

5.   SUSPENDED EXPLORATION WELL COSTS

The  following  table shows the changes in  capitalized  exploratory  well costs
during the six months ended June 30, 2009 and the year ended  December 31, 2008,
and does not include amounts that were initially  capitalized  and  subsequently
expensed in the same period.  Suspended  exploration  well costs are included in
property, plant and equipment.

<TABLE>
<CAPTION>
                                                             Six Months Ended      Year Ended
                                                                      June 30     December 31
                                                                         2009            2008
-----------------------------------------------------------------------------------------------
<S>                                                          <C>                  <C>
Beginning of Period                                                       518             326
     Exploratory Well Costs Capitalized Pending the
       Determination of Proved Reserves                                   175             254
     Capitalized Exploratory Well Costs Charged to Expense                (21)            (81)
     Transfers to Wells, Facilities and Equipment Based on
       Determination of Proved Reserves                                     -             (29)
     Effects of Foreign Exchange Rate Changes                             (21)             48
                                                            -----------------------------------
End of Period                                                             651             518
                                                            ===================================
</TABLE>

                                       9
<PAGE>

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

<TABLE>
<CAPTION>
                                                                  June 30     December 31
                                                                     2009            2008
------------------------------------------------------------------------------------------
<S>                                                               <C>         <C>
Capitalized for a Period of One Year or Less                          356             239
Capitalized for a Period of Greater than One Year                     295             279
                                                            ------------------------------
Total                                                                 651             518
                                                            ==============================

Number of Projects that have Exploratory Well Costs
     Capitalized for a Period Greater than One Year                     9               7
                                                            ------------------------------
</TABLE>

As at June 30, 2009, we have  exploratory  costs that have been  capitalized for
more than one year  relating to our interests in two  exploratory  blocks in the
Gulf of Mexico ($120 million), certain coalbed methane and shale gas exploratory
activities in Canada ($77  million),  four  exploratory  blocks in the North Sea
($78 million),  and our interest in an exploratory  block offshore  Nigeria ($20
million).  These costs relate to projects  with  exploration  wells for which we
have not been able to recognize proved  reserves.  We are assessing all of these
wells and  projects,  and are working with our  partners to prepare  development
plans, drill additional appraisal wells or to assess commercial viability.

6.   DEFERRED CHARGES AND OTHER ASSETS

<TABLE>
<CAPTION>

                                                                  June 30     December 31
                                                                     2009            2008
------------------------------------------------------------------------------------------
<S>                                                               <C>         <C>
Crude Oil Put Options and Natural Gas Swaps (Note 7) (1)                -             234
Long-Term Energy Marketing Derivative Contracts (Note 7)              230             217
Long-Term Capital Prepayments                                          40              61
Asset Retirement Remediation Fund                                       7               9
Defined Benefit Pension Assets                                         47               3
Other                                                                  46              46
                                                            ------------------------------
Total                                                                 370             570
                                                            ==============================
</TABLE>
(1) The crude oil put options were  reclassified  to other current assets in the
    first quarter as they settle within 12 months.

7.   FINANCIAL INSTRUMENTS

Financial  instruments  carried at fair value on our balance  sheet include cash
and cash  equivalents,  restricted  cash and  derivatives  used for  trading and
non-trading  purposes.  Our  other  financial  instruments,  including  accounts
receivable,  accounts  payable,  accrued interest  payable,  dividends  payable,
short-term borrowings and long-term debt, are carried at cost or amortized cost.
The carrying values of our short-term receivables and payables approximate their
fair value as the instruments are near maturity.

In our energy  marketing  group,  we enter into  contracts  to purchase and sell
crude  oil,  natural  gas and  other  energy  commodities,  and  use  derivative
contracts,  including  futures,  forwards,  swaps and  options,  for hedging and
trading purposes (collectively  derivatives).  We also use derivatives to manage
commodity  price risk and foreign  currency risk for  non-trading  purposes.  We
categorize our derivative  instruments as trading or non-trading  activities and
carry the  instruments  at fair  value on our  balance  sheet.  The  derivatives
section below details our  derivatives  and fair values as at June 30, 2009. The
fair values are included with accounts  receivable or payable and are classified
as long-term or short-term  based on anticipated  settlement date. Any change in
fair value is included in marketing and other income.

We carry our long-term debt at amortized cost using the effective  interest rate
method.  At June 30, 2009,  the estimated  fair value of our long-term  debt was
$7,571 million  (December 31, 2008 - $5,686 million) as compared to the carrying
value of $7,863 million (December 31, 2008 - $6,578 million).  The fair value of
long-term  debt is  estimated  based on prices  provided  by quoted  markets and
third-party brokers.

                                       10
<PAGE>

DERIVATIVES

(a)  DERIVATIVE CONTRACTS RELATED TO TRADING ACTIVITIES

Our energy marketing group engages in various activities  including the purchase
and sale of physical  commodities and the use of financial  instruments  such as
commodity and foreign exchange futures, forwards and swaps to economically hedge
exposures and generate revenue. These contracts are accounted for as derivatives
and, where applicable, are presented net on the balance sheet in accordance with
netting arrangements.  The fair value and carrying amounts related to derivative
instruments held by our energy marketing operations are as follows:

<TABLE>
<CAPTION>
                                                                        June 30         December 31
                                                                           2009                2008
----------------------------------------------------------------------------------------------------
<S>                                                                     <C>             <C>
  Commodity Contracts                                                       609                 742
  Foreign Exchange Contracts                                                  5                  13
                                                            ----------------------------------------
Accounts Receivable (Note 3)                                                614                 755
                                                            ----------------------------------------

  Commodity Contracts                                                       229                 213
  Foreign Exchange Contracts                                                  1                   4
                                                            ----------------------------------------
Deferred Charges and Other Assets (Note 6) (1)                              230                 217
                                                            ----------------------------------------

  Total Trading Derivative Assets                                           844                 972
                                                            ========================================

  Commodity Contracts                                                       616                 585
  Foreign Exchange Contracts                                                 37                  30
                                                            ----------------------------------------
Accounts Payable and Accrued Liabilities (Note 9)                           653                 615
                                                            ----------------------------------------

  Commodity Contracts                                                       216                 248
  Foreign Exchange Contracts                                                 10                  46
                                                            ----------------------------------------
Deferred Credits and Other Liabilities (Note 13) (1)                        226                 294
                                                            ----------------------------------------

  Total Trading Derivative Liabilities                                      879                 909
                                                            ========================================

  Total Net Trading Derivative Contracts                                    (35)                 63
                                                            ========================================
</TABLE>

(1) These  derivative  contracts  settle  beyond  12 months  and are  considered
    non-current;   once  within  12  months,   they  are  included  in  accounts
    receivable or accounts payable.

Excluding the impact of netting arrangements, the gross fair value of derivative
instruments is as follows:

<TABLE>
<CAPTION>
                                                                                            June 30
                                                                                               2009
-----------------------------------------------------------------------------------------------------
<S>                                                                                         <C>
Current Trading Assets                                                                        4,320
Non-Current Trading Assets                                                                    1,208
                                                                                   ------------------
  Total Trading Derivative Assets                                                             5,528
                                                                                   ==================

Current Trading Liabilities                                                                   4,359
Non-Current Trading Liabilities                                                               1,204
                                                                                   ------------------
  Total Trading Derivative Liabilities                                                        5,563
                                                                                   ==================

                                                                                   ------------------
  Total Net Trading Derivative Contracts                                                        (35)
                                                                                   ==================
</TABLE>

Trading  revenues  generated by our energy  marketing  group  include  gains and
losses on derivative instruments and non-derivative instruments such as physical
inventory.  During the three and six months ended June 30, 2009,  the  following
trading revenues were recognized in marketing and other income:

<TABLE>
<CAPTION>
                                                                    Three Months         Six Months
                                                                   Ended June 30      Ended June 30
                                                                            2009               2009
--------------------------------------------------------------------------------- --------------------
<S>                                                                <C>                <C>
Commodity                                                                    223                571
Foreign Exchange                                                              (2)               (83)
                                                            --------------------- --------------------
  Marketing Revenue                                                          221                488
                                                            ===================== ====================
</TABLE>

                                       11
<PAGE>

As an energy marketer,  we may undertake several transactions during a period to
execute a single sale of physical  product.  Each transaction may be represented
by one or more derivative  instruments  including a physical buy, physical sell,
and in many cases,  numerous financial  instruments for economically hedging and
trading purposes.  The absolute notional volumes  associated with our derivative
instrument transactions are as follows:

<TABLE>
<CAPTION>
                                                                       Three Months Ended            Six Months
                                                                                  June 30         Ended June 30
                                                                                     2009                  2009
----------------------------------------------------------------------------------------------------------------
<S>                                                     <C>            <C>                        <C>
Natural Gas                                                     bcf/d                18.8                  23.7
Crude Oil                                                    mmbbls/d                 3.9                   3.8
Power                                                           GWh/d               244.4                 228.4
Foreign Exchange                                         USD millions                 852                 1,230
Foreign Exchange                                        Euro millions                 107                   260
                                                                       -----------------------------------------
</TABLE>

(b)  DERIVATIVE CONTRACTS RELATED TO NON-TRADING ACTIVITIES

The fair  value and  carrying  amounts  of  derivative  instruments  related  to
non-trading activities are as follows:

<TABLE>
<CAPTION>
                                                                                  June 30          December 31
                                                                                     2009                 2008
---------------------------------------------------------------------------------------------------------------
<S>                                                                               <C>              <C>
Accounts Receivable                                                                    36                    6
Deferred Charges and Other Assets (Note 6) (1)                                          -                  234
                                                                      -----------------------------------------
  Total Non-Trading Derivative Assets                                                  36                  240
                                                                      =========================================

Accounts Payable and Accrued Liabilities                                               28                   21
Deferred Credits and Other Liabilities (Note 13) (1)                                   13                   26
                                                                      -----------------------------------------
  Total Non-Trading Derivative Liabilities                                             41                   47
                                                                      =========================================

  Total Net Non-Trading Derivative Assets (2)                                          (5)                 193
                                                                      =========================================
</TABLE>

(1) These  derivative  contracts  settle  beyond  12 months  and are  considered
    non-current.
(2) The net fair  value of these  derivatives  is equal to the gross  fair value
    before  consideration  of  netting  arrangements  and  collateral  posted or
    received with counterparties.

CRUDE OIL PUT OPTIONS
In 2008,  we purchased  put options on  approximately  70,000 bbls/d of our 2009
crude oil production for $14 million.  These options establish an annual average
Dated Brent floor price of US$60/bbl on these volumes. In September 2008, Lehman
Brothers  filed for bankruptcy  protection.  This impacts  approximately  25,000
bbls/d of our 2009 put options and the  carrying  value of these put options has
been reduced to nil. The crude oil put options are carried at fair value and are
classified  as long-term or  short-term  based on their  anticipated  settlement
date.  Fair value of the put options is  supported by multiple  quotes  obtained
from third party brokers,  which were validated with  observable  market data to
the extent  possible.  With the rise in Dated Brent oil price, the fair value of
the crude oil put options  decreased,  which is included in marketing  and other
income.

<TABLE>
<CAPTION>
                                                                                      Change in Fair Value
                                                                                  ------------------------------
                                                                                  Three Months       Six Months
                                   Notional                Average       Fair            Ended            Ended
                                    Volumes     Term     Floor Price    Value    June 30, 2009    June 30, 2009
----------------------------------------------------------------------------------------------------------------
                                   (bbls/d)                (US$/bbl)
<S>                                <C>          <C>      <C>            <C>      <C>              <C>
Dated Brent Crude Oil Put Options      45,000     2009            60       36             (179)            (195)
Dated Brent Crude Oil Put Options      25,000     2009            60        -                -                -
                                                                      ------------------------------------------
                                                                           36             (179)            (195)
                                                                      ==========================================
</TABLE>

                                       12
<PAGE>

FIXED-PRICE NATURAL GAS CONTRACTS AND NATURAL GAS SWAPS
We have fixed-price natural gas sales contracts and offsetting natural gas swaps
that are not part of our trading activities. These sales contracts and swaps are
carried at fair value and are  classified  as long-term or  short-term  based on
their  anticipated  settlement date. The change in fair value of the fixed price
natural gas  contracts  and natural gas swaps is included in marketing and other
income.

<TABLE>
<CAPTION>
                                                                                      Change in Fair Value
                                                                                  ------------------------------
                                                                                  Three Months       Six Months
                                   Notional                 Average      Fair            Ended            Ended
                                    Volumes     Term          Price     Value    June 30, 2009    June 30, 2009
----------------------------------------------------------------------------------------------------------------
                                      (Gj/d)                 ($/Gj)
<S>                                <C>          <C>     <C>             <C>      <C>              <C>
Fixed-Price Natural Gas Contracts    15,514     2009           2.28      (12)               (1)               9
                                     15,514     2010           2.28       (9)                6               17
Natural Gas Swaps                    15,514     2009           7.60      (16)                -              (22)
                                     15,514     2010           7.60       (4)                2               (5)
                                                                       -----------------------------------------
                                                                         (41)                7               (1)
                                                                       =========================================
</TABLE>

(c)  FAIR VALUE OF DERIVATIVES

Our processes for  estimating and  classifying  the fair value of our derivative
contracts are consistent with those in place at December 31, 2008. The following
table  includes  our  derivatives  carried  at fair  value for our  trading  and
non-trading activities as at June 30, 2009. Financial assets and liabilities are
classified  in the fair value  hierarchy in their  entirety  based on the lowest
level of input that is significant to the fair value measurement.  Assessment of
the  significance of a particular input to the fair value  measurement  requires
judgment and may affect placement within the fair value hierarchy levels.

<TABLE>
<CAPTION>

Net Derivatives                                                  Level 1      Level 2      Level 3       Total
----------------------------------------------------------------------------------------------------------------
<S>                                                              <C>          <C>          <C>           <C>
  Trading Derivatives                                               (201)         162            4         (35)
  Non-Trading Derivatives                                              -           (5)           -          (5)
                                                            ----------------------------------------------------
  Total                                                             (201)         157            4         (40)
                                                            ====================================================

<CAPTION>
A reconciliation  of changes in the fair value of our derivatives  classified as
Level 3 for the six months ended June 30, 2009 is provided below:

                                                                                                       Level 3
---------------------------------------------------------------------------------------------------------------
<S>                                                                                                    <C>
Beginning of Period                                                                                        (82)
  Realized and Unrealized Gains (Losses)                                                                    49
  Purchases, Issuances and Settlements                                                                      46
  Transfers In and/or Out of Level 3                                                                        (9)
                                                                                                  -------------
End of Period                                                                                                4
                                                                                                  =============

Unsettled Gains (Losses) Relating to Instruments Still Held as of June 30, 2009                             41
                                                                                                  =============
</TABLE>

Trading derivatives classified in Level 3 are generally economically hedged such
that  gains or losses on  positions  classified  in Level 3 are often  offset by
gains or losses on positions  classified in Level 1 or 2.  Transfers into or out
of Level 3 represent existing assets and liabilities that were either previously
categorized as a higher level for which the inputs became unobservable or assets
and liabilities that were previously  classified as Level 3 for which the lowest
significant input became observable during the period.

8.   RISK MANAGEMENT

(a)  MARKET RISK

We invest in significant capital projects, purchase and sell commodities,  issue
short-term  borrowings  and long-term  debt,  and invest in foreign  operations.
These  activities  expose us to market risks from  changes in commodity  prices,
foreign  exchange  rates and interest  rates,  which affect our earnings and the
value of the financial  instruments we hold. We use  derivatives for trading and
non-trading  purposes as part of our overall  risk  management  policy to manage
these market exposures.

The following  market risk  discussion  focuses on the commodity  price risk and
foreign  currency risk related to our financial  instruments  as our exposure to
interest rate risk is immaterial.

                                       13
<PAGE>

COMMODITY PRICE RISK

We are exposed to  commodity  price  movements as part of our normal oil and gas
operations,  particularly  in relation to the prices  received for our crude oil
and natural gas.  Commodity  price risk related to  conventional  and  synthetic
crude oil prices is our most  significant  market risk  exposure.  Crude oil and
natural gas are  sensitive  to  numerous  worldwide  factors,  many of which are
beyond our control, and are generally sold at contract or posted prices. Changes
in the  global  supply  and  demand  fundamentals  in the crude oil  market  and
geopolitical events can significantly affect crude oil prices.  Changes in crude
oil and natural gas prices may  significantly  affect our results of  operations
and cash generated from operating  activities.  Consequently,  these changes may
also affect the value of our oil and gas  properties,  our level of spending for
exploration  and  development,  and our ability to meet our  obligations as they
come due.

The majority of our oil and gas production is sold under  short-term  contracts,
exposing us to the risk of price movements. Other energy contracts we enter into
also expose us to  commodity  price risk  between the time we purchase  and sell
contracted  volumes.  We  periodically  manage  these risks by using  derivative
contracts such as commodity put options.

Our energy marketing business is focused on providing services for our customers
and suppliers to meet their energy commodity needs. We market and trade physical
energy  commodities  including  crude oil,  natural gas,  electricity  and other
commodities in selected  regions of the world.  We accomplish this by buying and
selling  physical  commodities,  by  acquiring  and  holding  rights to physical
transportation and storage assets for these commodities,  and by building strong
relationships with our customers and suppliers. In order to manage the commodity
and foreign  exchange price risks that are generated by this physical  business,
we  use  financial  derivative  contracts  including   energy-related   futures,
forwards, swaps and options, as well as foreign currency swaps or forwards.

We also seek to profit from our views on the future movement of energy commodity
pricing  relationships,  primarily between different locations,  time periods or
product  qualities.  We do this by holding  open  positions,  where the terms of
physical  or  financial  contracts  are not  completely  matched  to  offsetting
positions.  We may also carry  exposures  to the  absolute  change in  commodity
prices  based on our market views or as a  consequence  of managing our physical
and financial positions on a daily basis.

Our risk management activities make use of tools such as Value-at-Risk (VaR) and
stress testing  consistent with the  methodology  used at December 31, 2008. Our
period end, high, low and average VaR amounts for the three and six months ended
June 30, 2009 are as follows:

                                           Three Months            Six Months
                                           Ended June 30         Ended June 30
Value-at-Risk                            2009        2008       2009       2008
--------------------------------------------------------------------------------
Period End                                 15          31         15         31
High                                       19          40         24         40
Low                                        13          29         13         21
Average                                    15          34         17         32
                                        ----------------------------------------

If  market  shocks  occur  in 2009  as they  did in  2008,  the key  assumptions
underlying  our VaR estimate  could be exceeded and the potential  loss could be
greater  than our  estimate.  We  perform  stress  tests on a  regular  basis to
complement  VaR and  assess the  impact of  non-normal  changes in prices on our
positions.


FOREIGN CURRENCY RISK

Foreign  currency  risk is created by  fluctuations  in the fair  values or cash
flows of  financial  instruments  due to changes in foreign  exchange  rates.  A
substantial  portion of our  activities  are  transacted  in or referenced to US
dollars including:

    o   sales of crude oil, natural gas and certain chemicals products;
    o   capital  spending  and  expenses  for  our  oil and  gas,  Syncrude  and
        chemicals operations;
    o   commodity  derivative  contracts used primarily by our energy  marketing
        group; and
    o   short-term borrowings and long-term debt.

In our oil and gas operations,  we manage our exposure to  fluctuations  between
the US and  Canadian  dollar  by  matching  our  expected  net  cash  flows  and
borrowings in the same currency. Net revenue from our foreign operations and our
US-dollar  borrowings are generally used to fund US-dollar capital  expenditures
and debt  repayments.  We maintain  revolving  Canadian and US-dollar  borrowing
facilities  that can be used or repaid  depending  on expected  cash  flows.  We
designate a portion of our US-dollar borrowings as a hedge against our US-dollar
net investment in self-sustaining foreign operations.

                                       14
<PAGE>

The effective  portion of the foreign  exchange  gains or losses  related to our
designated US-dollar debt are included in accumulated other comprehensive income
in  shareholders'   equity.  Our  net  investment  in  self-sustaining   foreign
operations and our  designated  US-dollar debt at June 30, 2009 and December 31,
2008 are as follows:

<TABLE>
<CAPTION>
                                                                  June 30     December 31
(US$ millions)                                                       2009            2008
------------------------------------------------------------------------------------------
<S>                                                               <C>         <C>
Net Investment in Self-Sustaining Foreign Operations                4,350           4,662
Designated US-Dollar Debt                                           4,350           4,545
                                                            ------------------------------
</TABLE>

For the three and six months ended June 30, 2009, the ineffective portion of the
net foreign  exchange  gain was $41 million and $57 million,  respectively  ($36
million  and $50  million,  respectively,  net of  income  tax  expense)  and is
included in marketing  and other  income.  A one cent change in the US dollar to
Canadian dollar  exchange rate would increase or decrease our accumulated  other
comprehensive  income by approximately $44 million,  net of income tax and would
increase or decrease our net income by approximately  $8 million,  net of income
tax.

We also have  exposures  to  currencies  other  than the US dollar  including  a
portion  of our  UK  operating  expenses,  capital  spending  and  future  asset
retirement  obligations which are denominated in British Pounds and Euros. We do
not have any material exposure to highly inflationary foreign currencies. In our
energy  marketing  group,  we enter  into  transactions  in  various  currencies
including  Canadian and US dollars,  British  Pounds and Euros.  We may actively
manage significant currency exposures using forward contracts and swaps.

(b)   CREDIT RISK

Credit risk affects both our trading and non-trading  activities and is the risk
of loss if counterparties do not fulfill their contractual obligations.  Most of
our credit exposure is with  counterparties  in the energy  industry,  including
integrated oil companies,  crude oil refiners and utilities,  and are subject to
normal  industry  credit risk.  Approximately  94% of our exposure is with these
large energy companies. This concentration of risk within the energy industry is
reduced because of our broad base of domestic and international  counterparties.
Our processes to manage this risk are consistent with those in place at December
31, 2008.

At June 30, 2009, only one  counterparty  individually  made up more than 10% of
our credit exposure.  This counterparty is a major integrated oil company with a
strong investment grade credit rating. No other counterparties made up more than
5% of our credit  exposure.  The following table  illustrates the composition of
credit exposure by credit rating.

<TABLE>
<CAPTION>
                                                                 June 30      December 31
CREDIT RATING                                                       2009             2008
------------------------------------------------------------------------------------------
<S>                                                              <C>          <C>
A or higher                                                          68%              65%
BBB                                                                  26%              29%
Non-Investment Grade                                                  6%               6%
                                                            ------------------------------
TOTAL                                                               100%             100%
                                                            ==============================
</TABLE>

Our maximum  counterparty  credit  exposure at the balance  sheet date  consists
primarily of the carrying  amounts on  non-derivative  financial  assets such as
cash and cash equivalents,  restricted cash, accounts receivable, as well as the
fair value of  derivative  financial  assets.  We provided an  allowance  of $64
million for credit risk with our counterparties. In addition, we incorporate the
credit risk associated with counterparty  default, as well as Nexen's own credit
risk, into our estimates of fair value.

Collateral  received  from  customers at June 30, 2009  includes $102 million of
cash and $553 million of letters of credit.  The cash received reflects customer
deposits that are included in accounts payable and accrued liabilities.

(c)   LIQUIDITY RISK

Liquidity  risk  is the  risk  that we will  not be able to meet  our  financial
obligations  as they  become  due.  We require  liquidity  specifically  to fund
capital  requirements,  satisfy financial obligations as they become due, and to
operate our energy marketing business. We generally rely on operating cash flows
to provide liquidity and we also maintain  significant  undrawn committed credit
facilities.  At June 30,  2009,  we had  approximately  $2.5 billion of cash and
available committed lines of credit. This includes $2.0 billion of cash and cash
equivalents on hand. In addition, we have undrawn term credit facilities of $0.9
billion,  of which $0.4  billion  was  supporting  letters of credit at June 30,
2009. These facilities are available until 2012. We also have about $0.5 billion
of undrawn, uncommitted credit facilities at June 30, 2009.

                                       15
<PAGE>

The following  table details the contractual  maturities for our  non-derivative
financial  liabilities,  including both the principal and interest cash flows at
June 30, 2009:

<TABLE>
<CAPTION>
                                        Less than                            More Than
                                 Total     1 Year  1-3 Years    4-5 Years      5 Years
--------------------------------------------------------------------------------------
<S>                              <C>       <C>     <C>          <C>            <C>
Long-Term Debt (1)               7,935          -        251        3,384        4,300
Interest on Long-Term Debt (2)   7,067        314        628          607        5,518
                                -------------------------------------------------------
Total                           15,002        314        879        3,991        9,818
                                =======================================================
</TABLE>

(1) Excludes cash and cash equivalents currently available.
(2) Excludes interest on term credit facilities of $3.6 billion and Canexus term
    credit  facilities  of $455 million as the amounts  drawn on the  facilities
    fluctuate.  Based on amounts  drawn at June 30,  2009 and  current  interest
    rates,  we  would  be  required  to pay  $33  million  per  year  until  the
    outstanding amounts on the term credit facilities are repaid.

The following table details contractual  maturities for our derivative financial
liabilities.  The balance sheet  amounts for  derivative  financial  liabilities
included below are not materially  different from the contractual amounts due on
maturity.
<TABLE>
<CAPTION>
                                        Less than                            More Than
                                 Total     1 Year  1-3 Years    4-5 Years      5 Years
--------------------------------------------------------------------------------------
<S>                              <C>    <C>        <C>          <C>          <C>
Trading Derivatives (Note 7)     879          653        131           25           70
Non-Trading Derivatives (Note 7)  41           28         13            -            -
                                -------------------------------------------------------
Total                            920          681        144           25           70
                                =======================================================
</TABLE>

The commercial  agreements our energy  marketing  group enter into often include
financial  assurance   provisions  that  allow  us  and  our  counterparties  to
effectively manage credit risk. The agreements normally require collateral to be
posted  if an  adverse  credit-related  event  occurs,  such as a drop in credit
rating.  Based on contracts in place and  commodity  prices at June 30, 2009, we
could be required to post collateral of up to $1.1 billion if we were downgraded
to  non-investment  grade. This represents the maximum amount of collateral that
we would be  required  to post  assuming a severe  event that  causes all rating
agencies to simultaneously  downgrade us. This amount includes trade payables of
$795 million and derivative  contracts with a fair value of $313 million. All of
these  obligations are included on our June 30, 2009 balance sheet. In the event
of  a  ratings  downgrade,   we  could  monetize  our  trading  inventories  and
receivables  and draw on our existing  credit  facilities to meet our collateral
obligations.  Various  actions can be taken, in anticipation of a downgrade that
would reduce the maximum amount of collateral we would need to provide.

At June 30, 2009, collateral posted with counterparties  includes $15 million of
cash and $209  million of letters of credit  related to our trading  activities.
Cash posted is included  with our accounts  receivable.  Cash  collateral is not
normally applied to contract  settlement.  Once a contract has been settled, the
collateral  amounts are refunded.  If there is a default,  the cash is retained.
Our   exchange-traded   derivative   contracts   are  also   subject  to  margin
requirements.  We have margin deposits of $335 million (December 31, 2008 - $103
million), which have been included in restricted cash.

9.   ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

<TABLE>
<CAPTION>
                                                                     June 30       December 31
                                                                        2009              2008
------------------------------------------------------------------------------------------------
<S>                                                                  <C>           <C>
Accrued Payables                                                       1,808             2,033
Energy Marketing Derivative Contracts (Note 7)                           653               615
Trade Payables                                                           505               303
Stock-Based Compensation                                                 130                97
Income Taxes Payable                                                     206                69
Other                                                                    306               209
                                                            ------------------------------------
Total                                                                  3,608             3,326
                                                            ====================================
</TABLE>


                                       16
<PAGE>

10.  SHORT-TERM BORROWINGS AND LONG-TERM DEBT

<TABLE>
<CAPTION>
                                                                             June 30      December 31
                                                                                2009             2008
-------------------------------------------------------------------------------------------------------
<S>                                                                          <C>          <C>
Canexus Term Credit Facilities, due 2011 (US$227 million drawn) (a)              263              223
Term Credit Facilities, due 2012 (US$2.3 billion drawn) (b)                    2,732            1,225
Canexus Notes, due 2013 (US$50 million)                                           58               61
Notes, due 2013 (US$500 million)                                                 581              612
Notes, due 2015 (US$250 million)                                                 291              306
Notes, due 2017 (US$250 million)                                                 291              306
Notes, due 2028 (US$200 million)                                                 232              245
Notes, due 2032 (US$500 million)                                                 581              612
Notes, due 2035 (US$790 million)                                                 918              968
Notes, due 2037 (US$1,250 million)                                             1,453            1,531
Subordinated Debentures, due 2043 (US$460 million)                               535              563
                                                                      ---------------------------------
                                                                               7,935            6,652
Unamortized Debt Issue Costs                                                     (72)             (74)
                                                                      ---------------------------------
Total                                                                          7,863            6,578
                                                                      =================================
</TABLE>

(a)  CANEXUS TERM CREDIT FACILITIES

Canexus has $455  million  (US$391  million) of  committed,  secured term credit
facilities, $432 million (US$371 million) of which is available until 2011, with
the balance due 2013. At June 30, 2009, $263 million (US$227  million) was drawn
on  these  facilities  (December  31,  2008 - $223  million  (US$182  million)).
Borrowings are available as Canadian bankers'  acceptances,  LIBOR-based  loans,
Canadian  prime rate loans or  US-dollar  base rate  loans.  Interest is payable
monthly at floating rates. The term credit  facilities are secured by a floating
charge debenture over all of Canexus' assets.  The credit facility also contains
covenants   with   respect  to  certain   financial   ratios  of  Canexus.   The
weighted-average  interest rate on the Canexus term credit  facilities  was 2.1%
for the three  months  ended June 30, 2009 (three  months  ended June 30, 2008 -
4.6%) and 2.4% for the six months ended June 30, 2009 (six months ended June 30,
2008 - 4.5%).

(b)  TERM CREDIT FACILITIES

We have  unsecured  term credit  facilities  of $3.6  billion  (US$3.1  billion)
available until 2012. At June 30, 2009, $2.7 billion (US$2.3  billion) was drawn
on  these  facilities  (December  31,  2008  -  $1.2  billion  (US$1  billion)).
Borrowings are available as Canadian bankers'  acceptances,  LIBOR-based  loans,
Canadian prime rate loans,  US-dollar base rate loans or British pound call-rate
loans. Interest is payable at floating rates. The weighted-average interest rate
on our term credit  facilities was 1.1% for the three months ended June 30, 2009
(three months ended June 30, 2008 - 3.3%) and 1.1% for the six months ended June
30, 2009 (six months ended June 30, 2008 - 3.7%). At June 30, 2009, $392 million
(US$337  million)  of these  facilities  were  utilized  to support  outstanding
letters of credit (December 31, 2008 - $381 million (US$311 million)).

(c)  INTEREST EXPENSE

<TABLE>
<CAPTION>
                                                                Three Months          Six Months
                                                               Ended June 30         Ended June 30
                                                             2009        2008       2009       2008
-----------------------------------------------------------------------------------------------------
<S>                                                          <C>         <C>        <C>        <C>
Long-Term Debt                                                 89          69        178        145
Other                                                           3           6          8         10
                                                        ---------------------------------------------
Total                                                          92          75        186        155
   Less: Capitalized                                          (18)        (59)       (44)      (112)
                                                        ---------------------------------------------
Total                                                          74          16        142         43
                                                        =============================================
</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.

(d)  SHORT-TERM BORROWINGS

Nexen has uncommitted, unsecured credit facilities of approximately $496 million
(US$427 million), none of which were drawn at June 30, 2009 (December 31, 2008 -
nil).  We utilized $33 million  (US$28  million) of these  facilities to support
outstanding  letters of credit at June 30, 2009 (December 31, 2008 - $29 million
(US$24  million)).  Interest is payable at floating rates. The  weighted-average
interest rate on our  short-term  borrowings was 0.9% for the three months ended
June 30,  2009  (three  months  ended June 30, 2008 - 3.7%) and 2.1% for the six
months ended June 30, 2009 (six months ended June 30, 2008 - 3.8%).


                                       17
<PAGE>

11.  CAPITAL MANAGEMENT

Our objectives  and processes for managing our capital  structure are consistent
with those in place at December 31, 2008. Our capital  consists of shareholders'
equity,  short-term borrowings,  long-term debt and cash and cash equivalents as
follows:

<TABLE>
<CAPTION>
                                                                  June 30      December 31
                                                                     2009             2008
-------------------------------------------------------------------------------------------
<S>                                                               <C>          <C>
NET DEBT (1)
  Long-Term Debt                                                    7,863            6,578
     Less: Cash and Cash Equivalents                               (1,974)          (2,003)
                                                            -------------------------------
Total                                                               5,889            4,575
                                                            ===============================
SHAREHOLDERS' EQUITY                                                7,303            7,191
                                                            ===============================
</TABLE>
(1) Includes all of our  borrowings  and is  calculated  as  long-term  debt and
    short-term borrowings less cash and cash equivalents.


We monitor the leverage in our capital  structure by reviewing  the ratio of net
debt to cash flow from  operating  activities  and interest  coverage  ratios at
various commodity prices.

We use the  ratio of net debt to cash flow from  operating  activities  as a key
indicator of our leverage and to monitor the strength of our balance sheet.  Net
debt is a non-GAAP measure that does not have any standard meaning prescribed by
GAAP and  therefore  may not be  comparable  to similar  measures  presented  by
others.  We calculate  net debt using the GAAP  measures of  long-term  debt and
short-term  borrowings  less  cash and cash  equivalents  (excluding  restricted
cash).

For the  twelve  months  ended  June 30,  2009,  our net debt to cash  flow from
operating  activities  ratio was 2.1 times compared to 1.1 times at December 31,
2008.  While we typically  expect the target ratio to fluctuate  between 1.0 and
2.0 times under normalized commodity prices, this can be higher when we identify
strategic opportunities requiring additional investment.  Whenever we exceed our
target  ratio,  we assess  whether we need to  develop a strategy  to reduce our
leverage and lower this ratio back to target levels over time.

Our  interest   coverage  ratio  monitors  our  ability  to  fund  the  interest
requirements  associated with our debt. Our interest  coverage was 10.4 times at
June 30, 2009 (December 31, 2008 - 15.6 times).  Interest coverage is calculated
by dividing our twelve-month trailing adjusted EBITDA by interest expense before
capitalized interest.  Adjusted EBITDA is a non-GAAP measure. The calculation of
Adjusted  EBITDA  is set  out in  the  following  table  and is  unlikely  to be
comparable to similar measures presented by others.

<TABLE>
<CAPTION>
                                                                Twelve Months           Year Ended
                                                                Ended June 30          December 31
                                                                         2009                 2008
----------------------------------------------------------------------------------------------------
<S>                                                             <C>              <C>
Net Income                                                                860                1,715
  Add:
     Interest Expense                                                     193                   94
     Provision for Income Taxes                                           684                1,457
     Depreciation, Depletion, Amortization and Impairment               2,138                2,014
     Exploration Expense                                                  399                  402
     Recovery of Non-Cash Stock-Based Compensation                       (430)                (272)
     Change in Fair Value of Crude Oil Put Options                        (18)                (203)
     Other Non-Cash Expenses                                              (34)                  (1)
                                                             ---------------------------------------
Adjusted EBITDA                                                         3,792                5,206
                                                             =======================================
</TABLE>

                                       18
<PAGE>

12.  ASSET RETIREMENT OBLIGATIONS

Changes in carrying amounts of the asset retirement  obligations associated with
our Property, Plant & Equipment (PP&E) are as follows:

<TABLE>
<CAPTION>
                                                                  Six Months         Year Ended
                                                               Ended June 30        December 31
                                                                        2009               2008
-------------------------------------------------------------------------------------------------
<S>                                                            <C>                  <C>
Balance at Beginning of Period                                         1,059                832
  Obligations Incurred with Development Activities                        22                 32
  Obligations Settled                                                    (16)               (45)
  Accretion Expense                                                       34                 58
  Revisions to Estimates                                                 (25)               159
  Effects of Changes in Foreign Exchange Rate                              5                 23
                                                            -------------------------------------
Balance at End of Period (1), (2)                                      1,079              1,059
                                                            =====================================
</TABLE>

(1) Obligations  due within 12 months of $35  million  (December  31, 2008 - $35
    million) have been included in accounts payable and accrued liabilities.

(2) Obligations  relating to our oil and gas activities amount to $1,028 million
    (December  31,  2008 -  $1,009  million)  and  obligations  relating  to our
    chemicals business amount to $51 million (December 31, 2008 - $50 million).

Our total estimated undiscounted inflated asset retirement obligations amount to
$2,470  million  (December 31, 2008 - $2,393  million).  We have  discounted the
total  estimated  asset  retirement   obligations   using  a   weighted-average,
credit-adjusted,  risk-free rate of 5.9%. Approximately $396 million included in
our asset  retirement  obligations  is expected to be settled over the next five
years. The remaining obligations settle beyond five years and are expected to be
funded by future cash flows from our operations.

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

                                                                      June 30       December 31
                                                                         2009              2008
-------------------------------------------------------------------------------------------------
<S>                                                                   <C>           <C>
Deferred Tax Credit                                                       616               709
Long-Term Energy Marketing Derivative Contracts (Note 7)                  226               294
Deferred Transportation Revenue                                            61                69
Fixed-Price Natural Gas Contracts and Swaps (Note 7)                       13                26
Defined Benefit Pension Obligations                                        70                67
Capital Lease Obligations                                                  62                53
Other                                                                     119               106
                                                            -------------------------------------
Total                                                                   1,167             1,324
                                                            =====================================
</TABLE>

14.  SHAREHOLDERS' EQUITY

DIVIDENDS

Dividends per common share for the six months ended June 30, 2009 were $0.10 per
common share (2008 - $0.075).  Dividends  paid to holders of common  shares have
been designated as "eligible dividends" for Canadian tax purposes.

<TABLE>
<CAPTION>
15.  MARKETING AND OTHER INCOME

                                                                  Three Months          Six Months
                                                                 Ended June 30         Ended June 30
                                                               2009        2008      2009       2008
-----------------------------------------------------------------------------------------------------
<S>                                                            <C>         <C>       <C>        <C>
Marketing Revenue, Net (Note 7)                                 221          21       488        232
Change in Fair Value of Crude Oil Put Options (Note 7)         (179)        (10)     (195)       (10)
Interest                                                          1           3         3         13
Foreign Exchange Gains (Losses)                                   -          (6)       19         (1)
Other                                                            39          26        24         22
                                                            -----------------------------------------
Total                                                            82          34       339        256
                                                            =========================================
</TABLE>

                                       19
<PAGE>

16.  EARNINGS PER COMMON SHARE

We calculate  basic  earnings  per common share using net income  divided by the
weighted-average  number of common  shares  outstanding.  We  calculate  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)                                                   2009        2008           2009        2008
-------------------------------------------------------------------------------------------------------------------
<S>                                                                   <C>         <C>            <C>         <C>
Weighted-average number of common shares outstanding                  521.2       530.0          520.7       529.5
Shares issuable pursuant to tandem options                             11.1        24.9           11.2        25.7
Shares notionally purchased from proceeds of tandem options            (6.8)      (14.4)          (7.9)      (16.4)
                                                                ---------------------------------------------------
Weighted-average number of diluted common shares outstanding          525.5       540.5          524.0       538.8
                                                                ===================================================
</TABLE>

In calculating the weighted-average  number of diluted common shares outstanding
for the three and six months ended June 30,  2009,  we excluded  13,100,342  and
13,158,635  tandem  options,  respectively,  because  their  exercise  price was
greater than the average common share market price in the period. In calculating
the  weighted-average  number of diluted common shares outstanding for the three
and six months ended June 30, 2008, we excluded 1,667 and 25,833 tandem options,
respectively,  because their  exercise price was greater than the average common
share  market  price in the period.  During the periods  presented,  outstanding
tandem options were the only potential dilutive instruments.

17.  COMMITMENTS, CONTINGENCIES AND GUARANTEES

As  described  in  Note  16 to the  Audited  Consolidated  Financial  Statements
included  in our 2008  Form  10-K,  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 continue to believe
the resolution of these matters would not have a material  adverse effect on our
liquidity,  consolidated financial position or results of operations. There have
been no significant developments since year-end.

18.  CASH FLOWS

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

                                                                    Three Months               Six Months
                                                                   Ended June 30              Ended June 30
                                                                 2009          2008         2009         2008
--------------------------------------------------------------------------------------------------------------
<S>                                                              <C>           <C>          <C>          <C>
Depreciation, Depletion, Amortization and Impairment              413           334          822          698
Stock-Based Compensation                                           42           259           42          200
Recovery of Future Income Taxes                                  (229)         (139)        (316)         (62)
Change in Fair Value of Crude Oil Put Options                     179            10          195           10
Other                                                             (11)            6          (30)           6
                                                            --------------------------------------------------
Total                                                             394           470          713          852
                                                            ==================================================
</TABLE>

(b)  CHANGES IN NON-CASH WORKING CAPITAL
<TABLE>
<CAPTION>

                                                                    Three Months               Six Months
                                                                   Ended June 30              Ended June 30
                                                                 2009          2008         2009         2008
--------------------------------------------------------------------------------------------------------------
<S>                                                              <C>          <C>           <C>        <C>
   Accounts Receivable                                           (471)         (878)        (173)      (1,324)
   Inventories and Supplies                                       (80)         (310)        (129)        (388)
   Other Current Assets                                            20            (6)          12          (16)
   Accounts Payable and Accrued Liabilities                       134         1,349          319        2,032
   Other                                                          (17)            1           (4)          14
                                                            --------------------------------------------------
Total                                                            (414)          156           25          318
                                                            ==================================================
Relating to:
   Operating Activities                                          (340)          232           80          372
   Investing Activities                                           (74)          (76)         (55)         (54)
                                                            --------------------------------------------------
Total                                                            (414)          156           25          318
                                                            ==================================================
</TABLE>

                                       20
<PAGE>

(c)  OTHER CASH FLOW INFORMATION
<TABLE>
<CAPTION>

                                                                    Three Months               Six Months
                                                                   Ended June 30              Ended June 30
                                                                 2009          2008         2009         2008
--------------------------------------------------------------------------------------------------------------
<S>                                                              <C>           <C>          <C>          <C>
Interest Paid                                                      97            82          178          148
Income Taxes Paid                                                  34            76           68          161
                                                            --------------------------------------------------
</TABLE>

Cash flow from other  operating  activities  includes cash  outflows  related to
geological  and  geophysical  expenditures  of $31 million for the three  months
ended June 30,  2009 (2008 - $24  million)  and $43  million  for the six months
ended June 30, 2009 (2008 - $34 million).

19.  OPERATING SEGMENTS AND RELATED INFORMATION

Nexen is  involved in  activities  relating  to Oil and Gas,  Energy  Marketing,
Syncrude and Chemicals in various  geographic  locations as described in Note 22
to the Audited Consolidated Financial Statements included in our 2008 Form 10-K.

<TABLE>
<CAPTION>
THREE MONTHS ENDED JUNE 30, 2009

                                                                                                               Corporate
                                                                                             Energy                  and
                                               Oil and Gas                      Syncrude  Marketing   Chemicals    Other     Total
----------------------------------------------------------------------------------------------------------------------------------
                                                 United   United        Other
                                Yemen   Canada   States  Kingdom  Countries(1)
                              -----------------------------------------------
<S>                             <C>     <C>      <C>     <C>         <C>           <C>      <C>         <C>        <C>       <C>
Net Sales                        175        98       88       618           20        85          7         109        -     1,200
Marketing and Other                4         1        -         4            -         1        221          29     (178)(2)    82

                              -----------------------------------------------------------------------------------------------------
Total Revenues                   179        99       88       622           20        86        228         138     (178)    1,282

Less: Expenses
  Operating                       49        42       27        53            2        77          8          62        -       320
  Depreciation, Depletion,
   Amortization and
     Impairment                   32        62       80       182            4         9          3          29       12       413
  Transportation and Other        15         8        3        14            -         5        166          14        7       232
  General and
     Administrative (3)           (3)       28       24         5           16         1         26          16       54       167
  Exploration                      -         8       37        11           21 (4)     -          -           -        -        77
  Interest                         -         -        -         -            -         -          -           2       72        74
                              -----------------------------------------------------------------------------------------------------
Income (Loss)
  before Income Taxes             86       (49)     (83)      357          (23)       (6)        25          15     (323)       (1)
Less: Provisions for
(Recovery                         30       (13)     (28)      170          (18)       (2)         9           4     (175)      (23)
  of) Income Taxes
Less: Non-Controlling
  Interests                        -         -        -         -            -         -          -           2        -         2
                              -----------------------------------------------------------------------------------------------------
Net Income (Loss)                 56       (36)     (55)      187           (5)       (4)        16           9     (148)       20
                              =====================================================================================================
Identifiable Assets              289     8,349(5) 2,043     5,831          911     1,232      3,332 (6)     618    1,321    23,926
                              =====================================================================================================
Capital Expenditures
  Development and Other           22       138       33       109          140        22          3          72        9       548
  Exploration                      -        53       39        49           26         -          -           -        -       167
                              -----------------------------------------------------------------------------------------------------
                                  22       191       72       158          166        22          3          72        9       715
                              =====================================================================================================
Property, Plant and
Equipment
  Cost                         2,715     9,411    4,270     6,500          723     1,407        259       1,005      349    26,639
  Less: Accumulated DD&A       2,549     1,899    2,680     2,414          116       251         83         507      223    10,722
                              -----------------------------------------------------------------------------------------------------
Net Book Value                   166     7,512(5) 1,590     4,086          607     1,156        176         498      126    15,917
                              =====================================================================================================
</TABLE>
(1) Includes results of operations from producing activities in Colombia.
(2) Includes  interest  income of $1 million  and  decrease in the fair value of
    crude oil put options of $179 million.
(3) Includes stock-based compensation expense of $56 million.
(4) Includes exploration activities primarily in Norway, Nigeria and Colombia.
(5) Includes  costs of $5,832  million  related to our insitu oil sands projects
    (Long Lake and future phases).
(6) Approximately 82% of Marketing's identifiable assets are accounts receivable
    and inventories.


                                       21
<PAGE>

<TABLE>
<CAPTION>
THREE MONTHS ENDED JUNE 30,2008
                                                                                                             Corporate
                                                                                           Energy                  and
                                             Oil and Gas                      Syncrude  Marketing   Chemicals    Other       Total
-----------------------------------------------------------------------------------------------------------------------------------
                                                 United   United      Other
                             Yemen   Canada      States  Kingdom  Countries(1)
                            -----------------------------------------------
<S>                          <C>     <C>        <C>     <C>         <C>         <C>      <C>         <C>        <C>         <C>
Net Sales                      319      206         198      973         54        189         21         111        -       2,071
Marketing and Other              3        1           3       10          1          -         21           6      (11)(2)      34
                            -------------------------------------------------------------------------------------------------------
Total Revenues                 322      207         201      983         55        189         42         117      (11)      2,105

Less: Expenses
  Operating                     45       47          24       63          2         78         14          75        -         348
  Depreciation, Depletion,
   Amortization and
     Impairment                 40       47          62      143          4         12          4          11       11         334
  Transportation and Other       2        5           -        -          -          2        166          10       10         195
  General and
     Administrative (3)         13       78          45       13         58          -         41           8      162         418
  Exploration                    -       32          23       17         29 (4)      -          -           -        -         101
  Interest                       -        -           -        -          -          -          -           2       14          16
                            -------------------------------------------------------------------------------------------------------
Income (Loss)
  before Income Taxes          222       (2)         47      747        (38)        97       (183)         11     (208)        693
Less: Provisions for
(Recovery                       78       (1)         17      378         (3)        27        (53)          3     (134)        312
  of) Income Taxes
Less: Non-Controlling
  Interests                      -        -           -        -          -          -          -           1        -           1
                            -------------------------------------------------------------------------------------------------------
Net Income (Loss)              144       (1)         30      369        (35)        70       (130)          7      (74)        380
                            =======================================================================================================

Identifiable Assets            340    6,092 (5)   1,856    4,911        494      1,256      5,551 (6)     525      679      21,704
                            =======================================================================================================

Capital Expenditures
  Development and Other         14      259          55      121         10         11          1          20        9         500
  Exploration                    4       26          42       55          9          -          -           -        -         136
  Proved Property
      Acquisition                -        2           -        -          -          -          -           -        -           2
                            -------------------------------------------------------------------------------------------------------
                                18      287          97      176         19         11          1          20        9         638
                            =======================================================================================================

Property, Plant and
Equipment
  Cost                       2,284    7,424       3,480    5,128        310      1,348        264         866      312      21,416
  Less: Accumulated DD&A     2,088    1,682       1,937    1,235         88        223         68         483      187       7,991
                            -------------------------------------------------------------------------------------------------------
Net Book Value                 196    5,742 (5)   1,543    3,893        222      1,125        196         383      125      13,425
                            =======================================================================================================
</TABLE>

(1)  Includes results of operations from producing activities in Colombia.
(2)  Includes  interest  income of $3 million,  foreign  exchange  losses of $6
     million,  decrease  in the  fair  value of crude  oil put  options  of $10
     million and other gains of $2 million.
(3)  Includes stock-based compensation expense of $328 million.
(4)  Includes exploration activities primarily in Norway and Colombia.
(5)  Includes costs of $4,223 million  related to our insitu oil sands projects
     (Long Lake and future phases).
(6)  Approximately  83%  of  Marketing's   identifiable   assets  are  accounts
     receivable and inventories.


                                      22
<PAGE>

<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,2009
                                                                                                             Corporate
                                                                                           Energy                  and
                                             Oil and Gas                      Syncrude  Marketing   Chemicals    Other       Total
-----------------------------------------------------------------------------------------------------------------------------------
                                                 United   United      Other
                             Yemen   Canada      States  Kingdom  Countries(1)
                            -----------------------------------------------
<S>                          <C>     <C>        <C>     <C>         <C>           <C>      <C>         <C>        <C>       <C>
Net Sales                      337      189         151    1,096         39        183         20         233        -       2,248
Marketing and Other              7        8           -        8          -          1        488          15     (188) (2)    339
                            -------------------------------------------------------------------------------------------------------
Total Revenues                 344      197         151    1,104         39        184        508         248     (188)      2,587

Less: Expenses
  Operating                     96       83          50      104          4        143         16         129        -         625
  Depreciation, Depletion,
   Amortization and
     Impairment                 73      125         148      375          9         20          7          41       24         822
  Transportation and Other      18       11          16       11          -         12        328          24       13         433
  General and
     Administrative (3)          1       42          38        7         24          1         49          25       80         267
  Exploration                    -       29          47       19         35 (4)      -          -           -        -         130
  Interest                       -        -           -        -          -          -          -           4      138         142
                            -------------------------------------------------------------------------------------------------------
Income (Loss)
  before Income Taxes          156      (93)       (148)     588        (33)         8        108          25     (443)        168
Less: Provisions for
(Recovery                       54      (24)        (51)     256        (24)         2         44           6     (255)          8
  of) Income Taxes
Less: Non-Controlling
  Interests                      -        -         -          -          -          -          -           5        -           5
                            -------------------------------------------------------------------------------------------------------
Net Income (Loss)              102      (69)        (97)     332         (9)         6         64          14     (188)        155
                            =======================================================================================================

Identifiable Assets            289    8,349 (5)   2,043    5,831        911      1,232      3,332 (6)     618    1,321      23,926
                            =======================================================================================================

Capital Expenditures
  Development and Other         51      384          75      258        198         39         11         108       10       1,134
  Exploration                    -      147          65       77         41          -          -           -        -         330
  Proved Property
     Acquisitions                -      755           -        -          -          -          -           -        -         755
                            -------------------------------------------------------------------------------------------------------
                                51    1,286         140      335        239         39         11         108       10       2,219
                            =======================================================================================================

Property, Plant and
Equipment
  Cost                       2,715    9,411       4,270    6,500        723      1,407        259       1,005      349      26,639
  Less: Accumulated DD&A     2,549    1,899       2,680    2,414        116        251         83         507      223      10,722
                            -------------------------------------------------------------------------------------------------------
Net Book Value                 166    7,512 (5)   1,590    4,086        607      1,156        176         498      126      15,917
                            =======================================================================================================
</TABLE>

(1)   Includes results of operations from producing activities in Colombia.
(2)   Includes  interest  income of $3 million,  foreign  exchange gains of $19
      million,  decrease  in the fair  value of crude oil put  options  of $195
      million and other losses of $15 million.
(3)   Includes stock-based compensation expense of $56 million.
(4)   Includes  exploration   activities  primarily  in  Norway,   Nigeria  and
      Colombia.
(5)   Includes costs of $5,832 million related to our insitu oil sands projects
      (Long Lake and future phases).
(6)   Approximately  82%  of  Marketing's   identifiable  assets  are  accounts
      receivable and inventories.


                                      23
<PAGE>

<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,2008
                                                                                                             Corporate
                                                                                           Energy                  and
                                             Oil and Gas                      Syncrude  Marketing   Chemicals    Other       Total
-----------------------------------------------------------------------------------------------------------------------------------
                                                 United   United      Other
                             Yemen   Canada      States  Kingdom  Countries(1)
                            -----------------------------------------------
<S>                          <C>     <C>        <C>     <C>         <C>           <C>      <C>         <C>        <C>       <C>
Net Sales                      595      353         379    1,912        100        347         35         220        -       3,941
Marketing and Other              7        1           4       11          1          -        232          (1)       1 (2)     256
                            -------------------------------------------------------------------------------------------------------
Total Revenues                 602      354         383    1,923        101        347        267         219        1       4,197

Less: Expenses
  Operating                     90       89          48      120          5        140         23         142        -         657
  Depreciation, Depletion,
   Amortization and
     Impairment                 74       94         136      313          8         24          7          21       21         698
  Transportation and Other       4       10           1        -          -          7        339          29 (3)   10         400
  General and
     Administrative (4)         11       79          51       12         59          1         67          15      178         473
  Exploration                    -       36          29       24         44 (5)      -          -           -        -         133
  Interest                       -        -           -        -          -          -          -           5       38          43
                            -------------------------------------------------------------------------------------------------------
Income (Loss)
  before Income Taxes          423       46         118    1,454        (15)       175       (169)          7     (246)      1,793
Less: Provisions for
(Recovery                      148       13          42      737          -         49        (52)          3     (159)        781
  of) Income Taxes
Less: Non-Controlling
  Interests                      -        -           -        -          -          -          -           2       -            2
                            -------------------------------------------------------------------------------------------------------
Net Income (Loss)              275       33          76      717        (15)       126       (117)          2      (87)      1,010
                            =======================================================================================================

Identifiable Assets            340    6,092 (6)   1,856    4,911        494      1,256      5,551 (7)     525      679      21,704
                            =======================================================================================================

Capital Expenditures
  Development and Other         32      610         134      221         38         20          1          33       13       1,102
  Exploration                    9      112         109       71         19          -          -           -        -         320
  Proved Property
     Acquisitions                -        2           -        -          -          -          -           -        -           2
                            -------------------------------------------------------------------------------------------------------
                                41      724         243      292         57         20          1          33       13       1,424
                            =======================================================================================================

Property, Plant and
Equipment
  Cost                       2,284     7,424      3,480    5,128        310      1,348        264         866      312      21,416
  Less: Accumulated DD&A     2,088     1,682      1,937    1,235         88        223         68         483      187       7,991
                            -------------------------------------------------------------------------------------------------------
Net Book Value                 196     5,742 (6)  1,543    3,893        222      1,125        196         383      125      13,425
                            =======================================================================================================
</TABLE>

(1)   Includes results of operations from producing activities in Colombia.
(2)   Includes  interest income of $13 million,  foreign  exchange losses of $1
      million,  decrease  in the fair  value of crude  oil put  options  of $10
      million and other losses of $1 million.
(3)   Includes  severance  accrual  of $7  million  in  connection  with  North
      Vancouver technology conversion project.
(4)   Includes stock-based compensation expense of $287 million.
(5)   Includes exploration activities primarily in Norway and Colombia.
(6)   Includes costs of $4,223 million related to our insitu oil sands projects
      (Long Lake and future phases).
(7)   Approximately  83%  of  Marketing's   identifiable  assets  are  accounts
      receivable and inventories.


                                      24
<PAGE>

20.   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  Statements and summaries
of differences from Canadian GAAP are as follows:

<TABLE>
<CAPTION>
UNAUDITED CONSOLIDATED STATEMENT OF INCOME (LOSS) - 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)                                     2009          2008         2009         2008
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                         <C>           <C>          <C>          <C>
REVENUES AND OTHER INCOME
   Net Sales                                                                 1,200         2,071        2,248        3,941
   Marketing and Other (v); (vi)                                                66          (102)         358          104
                                                                         ---------------------------------------------------
                                                                             1,266         1,969        2,606        4,045
                                                                         ---------------------------------------------------
EXPENSES
   Operating (i)                                                               320           347          625          657
   Depreciation, Depletion, Amortization and Impairment                        413           334          822          698
   Transportation and Other (v)                                                231           191          425          396
   General and Administrative (iv)                                             197           390          305          452
   Exploration                                                                  77           101          130          133
   Interest                                                                     74            16          142           43
                                                                         ---------------------------------------------------
                                                                             1,312         1,379        2,449        2,379
                                                                         ---------------------------------------------------

INCOME (LOSS) BEFORE PROVISION FOR INCOME TAXES                                (46)          590          157        1,666
                                                                         ---------------------------------------------------

PROVISION FOR (RECOVERY OF) INCOME TAXES
   Current                                                                     206           451          324          843
   Deferred (iv); (vi)                                                        (242)         (180)        (316)        (114)
                                                                         ---------------------------------------------------
                                                                               (36)          271            8          729
                                                                         ---------------------------------------------------

NET INCOME (LOSS)                                                              (10)          319          149          937
   Less: Net Income Attributable to Non-Controlling Interests                   (2)           (1)          (5)          (2)
                                                                         ---------------------------------------------------

NET INCOME (LOSS) ATTRIBUTABLE TO NEXEN INC. - US GAAP (1)                     (12)          318          144          935
                                                                         ===================================================

EARNINGS (LOSS) PER COMMON SHARE ($/share) (Note 16)
   Basic                                                                      (0.02)        0.60         0.28         1.77
                                                                         ===================================================

   Diluted                                                                    (0.02)        0.59         0.28         1.74
                                                                         ---------------------------------------------------
</TABLE>

(1)  RECONCILIATION OF CANADIAN AND US GAAP NET INCOME (LOSS)

<TABLE>
<CAPTION>
                                                                                  Three Months               Six Months
                                                                                  Ended June 30             Ended June 30
                                                                              2009          2008         2009         2008
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                          <C>           <C>          <C>          <C>
Net Income - Canadian GAAP                                                      20           380          155        1,010
Impact of US Principles, Net of Income Taxes:
   Stock-based Compensation (iv)                                               (22)           20          (28)          15
   Inventory Valuation (vi)                                                    (10)          (83)          17          (90)
   Other                                                                         -             1            -            -
                                                                         ---------------------------------------------------
Net Income (Loss) - US GAAP                                                    (12)          318          144          935
                                                                         ===================================================
</TABLE>


                                      25
<PAGE>

<TABLE>
<CAPTION>
UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP
                                                                                     June 30         December 31
(Cdn$ millions, except share amounts)                                                   2009                2008
-----------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>                 <C>
ASSETS
   CURRENT ASSETS
      Cash and Cash Equivalents                                                        1,974               2,003
      Restricted Cash                                                                    335                 103
      Accounts Receivable                                                              3,272               3,163
      Inventories and Supplies (vi)                                                      567                 426
      Other                                                                              167                 169
                                                                              -----------------------------------
         Total Current Assets                                                          6,315               5,864
                                                                              -----------------------------------

   PROPERTY, PLANT AND EQUIPMENT
      Net of Accumulated Depreciation, Depletion, Amortization and
         Impairment of $11,115 (December 31, 2008 - $10,786) (i); (iii)               15,868              14,873
   GOODWILL                                                                              372                 390
   DEFERRED INCOME TAX ASSETS                                                            921                 351
   DEFERRED CHARGES AND OTHER ASSETS                                                     370                 570
                                                                              -----------------------------------
TOTAL ASSETS                                                                          23,846              22,048
                                                                              ===================================

LIABILITIES AND SHAREHOLDERS' EQUITY
   CURRENT LIABILITIES
      Accounts Payable and Accrued Liabilities (iv)                                    3,704               3,384
      Accrued Interest Payable                                                            63                  67
      Dividends Payable                                                                   26                  26
                                                                              -----------------------------------
         Total Current Liabilities                                                     3,793               3,477
                                                                              -----------------------------------

   LONG-TERM DEBT                                                                      7,863               6,578
   DEFERRED INCOME TAX LIABILITIES (i); (ii); (iv); (vi); (vii)                        2,776               2,543
   ASSET RETIREMENT OBLIGATIONS                                                        1,044               1,024
   DEFERRED CREDITS AND OTHER LIABILITIES (ii)                                         1,271               1,428

SHAREHOLDERS' EQUITY
   Nexen Inc. Shareholders' Equity
      Common Shares, no par value
         Authorized:   Unlimited
         Outstanding:  2009 - 521,205,270 shares
                       2008 - 519,448,590 shares                                       1,011                 981
      Contributed Surplus                                                                  2                   2
      Retained Earnings (i) - (vii)                                                    6,264               6,172
      Accumulated Other Comprehensive Loss (ii)                                         (232)               (209)
                                                                              -----------------------------------
   Total Nexen Inc. Shareholders' Equity                                               7,045               6,946
      Non-Controlling Interests                                                           54                  52
                                                                              -----------------------------------
   TOTAL SHAREHOLDERS EQUITY                                                           7,099               6,998
                                                                              -----------------------------------
   COMMITMENTS, CONTINGENCIES AND GUARANTEES
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                                            23,846              22,048
                                                                              ===================================
</TABLE>

UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS) - US GAAP
FOR THE THREE AND SIX MONTHS ENDED JUNE 30

<TABLE>
<CAPTION>
                                                                                 Three Months               Six Months
                                                                                 Ended June 30             Ended June 30
                                                                              2009          2008         2009         2008
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                           <C>           <C>          <C>          <C>
Net Income (Loss) Attributable to Nexen Inc. - US GAAP                         (12)          318          144          935
Other Comprehensive Income (Loss), Net of Income Taxes:
   Foreign Currency Translation Adjustment                                     (29)           (8)         (23)          19
                                                                         ---------------------------------------------------
Comprehensive Income (Loss) Attributable to Nexen Inc.                         (41)          310          121          954
                                                                         ===================================================
</TABLE>

                                       26
<PAGE>

<TABLE>
<CAPTION>
UNAUDITED CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE LOSS - US GAAP

                                                                                         June 30          December 31
                                                                                            2009                 2008
----------------------------------------------------------------------------------------------------------------------
<S>                                                                                      <C>                  <C>
Foreign Currency Translation Adjustment                                                     (157)                (134)
Unamortized Defined Benefit Pension Plan Costs (ii)                                          (75)                 (75)
                                                                              ----------------------------------------
Accumulated Other Comprehensive Loss                                                        (232)                (209)
                                                                              ========================================
</TABLE>

NOTES TO THE UNAUDITED CONSOLIDATED US GAAP FINANCIAL STATEMENTS:
i.    Under Canadian GAAP, we defer certain  development costs to PP&E. Under US
      principles,  these costs have been  included in operating  expenses.  As a
      result PP&E is lower under US GAAP by $30 million (December 31, 2008 - $30
      million).

ii.   US GAAP  requires the  recognition  of the  over-funded  and  under-funded
      status  of a  defined  benefit  plan on the  balance  sheet as an asset or
      liability.  At June 30, 2009, the unfunded  amount of our defined  benefit
      pension  plans  that  was not  included  in the  Pension  Liability  under
      Canadian GAAP was $104 million.  This amount has been included in deferred
      credits and other  liabilities and $75 million,  net of income taxes,  has
      been included in AOCI.

iii.  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 results in our PP&E under US GAAP being lower by $19 million.

iv.   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. In addition, under
      Canadian principles,  we retroactively  adopted EIC-162 which requires the
      accelerated  recognition  of  stock-based  compensation  expense  for  all
      stock-based awards made to our retired and retirement-eligible  employees.
      However,  US GAAP  requires the  accelerated  recognition  of  stock-based
      compensation  expense for such  employees  for awards  granted on or after
      January 1, 2006. As a result:

      o     general and  administrative  (G&A)  expense is higher by $30 million
            and $38 million ($22 million and $28 million,  net of income  taxes)
            for the three and six months ended June 30, 2009, respectively (2008
            - lower by $28 million and $21  million,  respectively  ($20 million
            and $15 million, net of income taxes)); and

      o     accounts  payable and accrued  liabilities are higher by $96 million
            as at June 30, 2009 (December 31, 2008 - $58 million).

v.    Under US GAAP,  asset  disposition  gains and  losses  are  included  with
      transportation  and other expense.  Gains of $1 million and $8 million for
      the  three  and  six  months  ended  June  30,  2009,  respectively,  were
      reclassified from marketing and other income to  transportation  and other
      expense  (gains  of $4  million  were  reclassified  for the three and six
      months ended June 30, 2008).

vi.   Under  Canadian  GAAP, we carry our commodity  inventory  held for trading
      purposes  at fair  value,  less any costs to sell.  Under US GAAP,  we are
      required to carry this  inventory  at the lower of cost or net  realizable
      value. As a result:

      o     marketing and other income is lower by $15 million and higher by $27
            million ($10 million and $17 million,  net of income  taxes) for the
            three and six months ended June 30, 2009, respectively (2008 - lower
            by $132 million and $148  million ($83 million and $90 million,  net
            of income taxes)); and

      o     inventories  are lower by $31 million as at June 30, 2009  (December
            31, 2008 - lower by $58 million).

vii.  On January 1, 2007, we adopted Financial Accounting Standards Board (FASB)
      Interpretation  48,  ACCOUNTING  FOR  UNCERTAINTY IN INCOME TAXES (FIN 48)
      regarding  accounting and  disclosure for uncertain tax positions.  On the
      adoption  of FIN 48,  we  recorded  a  cumulative  effect  of a change  in
      accounting  principle of $28 million.  This amount  increased our deferred
      income tax liabilities,  and decreased our retained earnings as at January
      1, 2007 in our US GAAP - Unaudited Consolidated Balance Sheet.

      As at June 30, 2009, the total amount of our  unrecognized tax benefit was
      approximately $269 million, all of which, if recognized,  would affect our
      effective tax rate.  To the extent  interest and penalties may be assessed
      by taxing authorities on any underpayment of income tax, such amounts have
      been  accrued and are  classified  as a component  of income  taxes in the
      Unaudited Consolidated Statement of Income. As at June 30, 2009, the total
      amount of  interest  and  penalties  related to  uncertain  tax  positions
      recognized in deferred  income tax  liabilities in the US GAAP - Unaudited
      Consolidated  Balance  Sheet  was  approximately  $8  million.  We  had no
      interest or penalties included in the US GAAP - Consolidated  Statement of
      Income for the three and six months ended June 30, 2009.


                                       27
<PAGE>

      Our income tax filings are subject to audit by taxation authorities and as
      at June 30, 2009 the following tax years remained  subject to examination,
      (i)  Canada - 1985 to date  (ii)  United  Kingdom - 2007 to date and (iii)
      United States - 2005 to date. We do not anticipate any material changes to
      the  unrecognized  tax benefits  previously  disclosed  within the next 12
      months.


CHANGES IN ACCOUNTING POLICIES - US GAAP
Business Combinations
On January 1, 2009, we  prospectively  adopted FASB Statement 141 (R),  BUSINESS
COMBINATIONS.  Statement 141  establishes  principles  and  requirements  of the
acquisition  method for  business  combinations  and  related  disclosures.  The
adoption of this statement did not impact our results of operations or financial
position.

NON-CONTROLLING INTERESTS
On January 1, 2009, we prospectively adopted FASB Statement 160, NON-CONTROLLING
INTERESTS IN CONSOLIDATED FINANCIAL STATEMENTS.  This statement clarifies that a
non-controlling  interest  in a  subsidiary  is an  ownership  interest  in  the
consolidated  entity  that  should be  reported  as  equity in the  consolidated
financial  statements.  The adoption of this  statement  did not have a material
impact on our results of  operations  or financial  position.  The  presentation
changes  have  been  included  in  the  Consolidated  Financial  Statements,  as
applicable.

DERIVATIVE AND HEDGING ACCOUNTING AND DISCLOSURES
On January 1, 2009, we  prospectively  adopted FASB Statement  161,  DISCLOSURES
ABOUT  DERIVATIVE  INSTRUMENTS AND HEDGING  ACTIVITIES.  The statement  requires
qualitative   disclosures   about  the   objectives  and  strategies  for  using
derivatives,  quantitative  data  about the fair  value of gains  and  losses on
derivative contracts and details of  credit-risk-related  contingent features in
their  hedged  position.  The  statement  also  requires the  disclosure  of the
location and amounts of derivative instruments in the financial statements.  The
disclosures required by this standard are provided in Notes 7 and 8.

On April 1, 2009, we prospectively adopted three FASB staff positions to improve
guidance  and  disclosures  on  fair  value  measurement  and  impairments.  The
positions clarify fair value accounting specifically regarding: inactive markets
and distressed transactions; other-than-temporary impairments; and expanded fair
value disclosures for financial  instruments in interim periods. The adoption of
these  positions  did not have a material  impact on our results of operation or
financial position.


SUBSEQUENT EVENTS
On April 1, 2009, we prospectively adopted Statement 165, SUBSEQUENT EVENTS. The
new standard  reflects  the existing  principles  of current  subsequent  events
accounting  guidance and retains the notion and  definition  of "available to be
issued" financial  statements.  The new standard requires disclosure of the date
through which subsequent  events have been evaluated and clarifies that original
issuance  of  financial  statements  means both  "issued"  or  "available  to be
issued".  The adoption of this  standard  did not have a material  impact on our
results of operation or financial position.


NEW ACCOUNTING PRONOUNCEMENTS - US GAAP
In December 2008,  FASB issued FSP FAS 132(R) -1,  EMPLOYERS  DISCLOSURES  ABOUT
POSTRETIREMENT   BENEFIT  PLAN  ASSETS.   This  position  provides  guidance  on
disclosures   about  plan  assets  of  a  defined   benefit   pension  or  other
postretirement  plans.  This position is effective for fiscal years ending after
December 15, 2009. We do not expect the adoption of this statement to materially
impact our results of operations or financial position.

In June 2009, FASB issued Statement 167,  AMENDMENTS TO FASB  INTERPRETATION NO.
46 (R).  It  retains  the scope of  Interpretation  46(R) with the  addition  of
entities  previously   considered   qualifying   special-purpose   entities  and
eliminates  the previous  quantitative  approach for a  qualitative  analysis in
determining  whether the enterprise's  variable  interest or interests give it a
controlling  financial  interest in a variable  interest  entity.  The Statement
further amends  Interpretation 46(R) to require ongoing reassessments of whether
an  enterprise  is the primary  beneficiary  of a variable  interest  entity and
requires enhanced  disclosures  about an enterprise's  involvement in a variable
interest entity. The Statement is effective at the beginning of the first annual
reporting  period after November 15, 2009. We do not expect the adoption of this
statement to have a material  impact on our results of  operations  or financial
position.


                                       28
<PAGE>

ITEM 2. MANAGEMENT'S  DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS (MD&A)
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 20 TO THE  UNAUDITED  CONSOLIDATED
FINANCIAL STATEMENTS. THE DATE OF THIS DISCUSSION IS JULY 15, 2009.

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 79 OF OUR 2008 ANNUAL REPORT OF FORM 10-K (2008 FORM 10-K) WHICH HIGHLIGHTS
DIFFERENCES  BETWEEN OUR RESERVES  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, FAIR VALUES OF DERIVATIVE CONTRACT ASSETS
AND  LIABILITIES AND THE  DETERMINATION  OF PROVED RESERVES ON AN ONGOING BASIS.
CHANGES IN FACTS AND  CIRCUMSTANCES  MAY RESULT IN REVISED  ESTIMATES AND ACTUAL
RESULTS MAY DIFFER FROM THESE ESTIMATES.

<TABLE>
<CAPTION>
EXECUTIVE SUMMARY OF SECOND QUARTER RESULTS
                                                                                 Three Months               Six Months
                                                                                 Ended June 30             Ended June 30
                                                                                2009        2008          2009        2008
---------------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>        <C>            <C>         <C>
Production before Royalties (mboe/d)                                             240         254           246         261
Production after Royalties (mboe/d)                                              208         211           217         217
Nexen's Average Realized Oil and Gas Price (Cdn$/boe)                          61.28      108.26         54.28       96.36

Cash Flow from Operating Activities (1)                                          109       1,163           898       2,331
Net Income Attributable to Nexen Inc.                                             20         380           155       1,010
Earnings per Common Share, Basic ($/share)                                      0.04        0.72          0.30        1.91

Capital Investment                                                               715         638         1,464       1,424
Acquisition of Additional Interest in Long Lake                                    -           -           755           -
Net Debt (2)                                                                   5,889       3,835         5,889       3,835
                                                                         --------------------------------------------------
</TABLE>
(1) Cash flow from  operating  activities  includes $340 million used to finance
    non-cash working capital requirements in the second quarter of 2009.
(2) Net  debt is a  non-GAAP  measure  and is  defined  as  long-term  debt  and
    short-term borrowings less cash and cash equivalents.

Production before royalties averaged 240,000 boe/d in the quarter,  5% below the
previous quarter.  The decrease reflects planned maintenance downtime at Buzzard
and Syncrude, and natural declines in Yemen. Buzzard continues to deliver strong
results,  with rates  averaging  87,500  boe/d,  net to us,  during the quarter.
Excluding the downtime, Buzzard produced at rates averaging 96,700 boe/d, net to
us. In the Gulf of  Mexico,  all of the  shut-in  production  has been  restored
following  the 2008  hurricane  interruptions  with the exception of about 4,000
boe/d  which  is  expected  to  return  to  production  in 2010 or  2011,  after
reconstruction  of a destroyed  platform.  At Long Lake, SAGD bitumen  quarterly
production  averaged  9,300  bbls/d,  net  to us and we  achieved  record  steam
injection rates driven by water treatment modifications.

Commodity prices  strengthened  during the quarter,  but are considerably  lower
than a year ago. Our realized quarterly oil and gas price increased 29% from the
prior  quarter to  average  $61.28/boe,  but was 43% lower than the prior  year.
Despite the drop in commodity prices, our cash netbacks remain strong.

Our second quarter net income was impacted by the reduced value of our crude oil
put options as we are  required  to carry the  options at fair  value.  With oil
prices  increasing  throughout  the  second  quarter,  the fair value of our put
options fell considerably,  reducing our net income $179 million before tax. The
put options have an annual  average  Dated Brent  strike price of US$60/bbl  and
would be in-the-money  if prices average  US$70/bbl or lower for the rest of the
year.  Additional  stock-based  compensation  expense  reduced  our net income a
further $56 million before tax during the quarter.

Our  capital  investment  is focused on  developing  our Usan  project  offshore
Nigeria and on  exploration  activities  in the North Sea,  particularly  in the
Golden Eagle area,  both of which are expected to be economic at current prices.
We achieved  exploration success during the quarter at Hobby in the UK North Sea
and at Owowo,  offshore West Africa.  We are also  advancing  work on the fourth
platform at Buzzard,  which should allow us to extend the production  plateau of
the field for  several  years.  We expect  to bring  our  Ettrick  and  Longhorn
developments on stream later this year.

                                       29
<PAGE>

Our  financial   position  remains  strong.  We  have  available   liquidity  of
approximately  US$2.5  billion,  comprised of cash on hand and undrawn  lines of
credit.  We have no  significant  debt  maturities  until  2012 and the  average
term-to-maturity of our long-term debt is approximately 15 years. We believe our
significant liquidity, combined with strong operating cash netbacks, provides us
with the financial flexibility to carry out our investment programs.

CAPITAL INVESTMENT
Our strategy is to build a sustainable  energy  company  focused in three areas:
oil  sands,   unconventional  gas  and  select   conventional   exploration  and
exploitation.  We are  committed to grow  long-term  value for our  shareholders
responsibly and are advancing our plans to achieve this as described below.

In 2009, we are investing primarily in:
o   bringing  Ettrick  in the  North Sea and  Longhorn  in the Gulf of Mexico on
    stream later this year;
o   ramping up Long Lake safely and reliably;
o   developing  our Usan  project  and  continuing  to  explore  our  additional
    acreage, offshore Nigeria;
o   advancing exploration and appraisal of our Golden Eagle area in the UK North
    Sea;
o   targeting a number of exploration prospects,  primarily in the North Sea and
    Gulf of Mexico; and
o   advancing our Horn River shale gas play in northeastern British Columbia.

Details of our capital programs are set out below:

<TABLE>
<CAPTION>
THREE MONTHS ENDED JUNE 30, 2009
                                                   Major     Early Stage      New Growth     Core Asset
                                             Development     Development     Exploration    Development        Total
---------------------------------------------------------------------------------------------------------------------
<S>                                          <C>             <C>             <C>            <C>                <C>
Oil and Gas
    United Kingdom                                    21               -              49              88         158
    Nigeria                                          139               -              17               -         156
    Synthetic (mainly Long Lake)                      95 (1)          23               -               -         118
    Canada                                             -               -              53              20          73
    United States                                     32               -              39               1          72
    Yemen                                              -               -               -              22          22
    Other Countries                                    -               -               9               1          10
Syncrude                                               -               -               -              22          22
                                          ---------------------------------------------------------------------------
                                                     287              23             167             154         631
Chemicals                                             72               -               -               -          72
Energy Marketing, Corporate and Other                  -               -               -              12          12
                                          ---------------------------------------------------------------------------
Total Capital                                        359              23             167             166         715
                                          =============== =============== =============== ============== ============
As a % of Total Capital                              50%             3%             24%              23%         100%
                                          ---------------------------------------------------------------------------

(1) Includes $60 million of capitalized start-up costs.

<CAPTION>
SIX MONTHS ENDED JUNE 30, 2009
                                                   Major     Early Stage      New Growth     Core Asset
                                             Development     Development     Exploration    Development        Total
---------------------------------------------------------------------------------------------------------------------
<S>                                          <C>             <C>             <C>            <C>                <C>
Oil and Gas
    Long Lake Acquisition                            755               -               -               -         755
    United Kingdom                                   102               6              77             150         335
    Synthetic (mainly Long Lake)                     265 (1)          63               1               -         329
    Nigeria                                          197               -              19               -         216
    Canada                                             -               2             146              54         202
    United States                                     69               -              65               6         140
    Yemen                                              -               -               -              51          51
    Other Countries                                    -               -              22               1          23
Syncrude                                               -               -               -              39          39
                                          ---------------------------------------------------------------------------
                                                   1,388              71             330             301       2,090
Chemicals                                            108               -               -               -         108
Energy Marketing, Corporate and Other                  -               -               -              21          21
                                          ---------------------------------------------------------------------------
Total Capital                                      1,496              71             330             322       2,219
                                          =============== =============== =============== ============== ============
As a % of Total Capital                              67%             3%             15%              15%         100%
                                          ---------------------------------------------------------------------------
</TABLE>
(1) Includes $151 million of capitalized start-up costs.

                                       30
<PAGE>

SYNTHETIC
The ramp up of Long Lake is progressing  and the reservoir  continues to perform
as expected given the amount of steam that has been injected. Steam volumes have
been limited by our ability to treat water.

In May 2009, we successfully  completed a project to add  supplementary  heat to
the hot lime softeners  (HLS) in the water  treatment  plant.  We also completed
routine  maintenance  work to remove  deposits which typically build up in water
treatment plants.  Steam production  increased in June 2009 and we have achieved
record  injection  rates  of  approximately  95,000  bbls/d  and  gross  bitumen
production  rates of approximately  18,000 bbls/d.  There are currently 41 of 81
well pairs on  production  and we are  producing at a  steam-to-oil  ratio (SOR)
which ranges  between 4.0 and 5.0. We continue to expect a long-term  SOR of 3.0
over the life of the project.

Bitumen  production volumes for the second quarter set a new record and averaged
approximately  14,300 bbls/d (gross),  an increase of 7% over the first quarter.
Production  volumes have been impacted by downtime  associated with improvements
made to the HLS units. We plan to replace valves and conduct  maintenance on our
water  treatment  plant during the third  quarter to further  optimize our steam
production. The cost of these activities will not be significant and will result
in  scheduled  downtime  in the third  quarter,  impacting  bitumen  and premium
synthetic crude (PSCTM) production. As steam generation increases, all wells are
expected to be converted to production mode.

With  respect to the  Upgrader,  all major units are  operational  and Syngas is
being used in SAGD  operations.  This allows us to decrease  operating  costs by
reducing the requirement for purchased natural gas. The solvent de-asphalter and
thermal  cracker  units  are  expected  to start  shortly  and will  allow us to
transition from gasifying  vacuum residue,  which contains some lighter parts of
the barrel,  to gasifying  asphaltenes,  the heaviest  part of the barrel.  As a
result, we expect our PSCTM yield to increase from approximately 60% to 80%.

During the ramp up phase,  we expect periods of downtime but anticipate that the
stability of operations will continue to improve. We expect to reach full design
rates of 72,000 bbls/d of gross bitumen  production,  upgraded to  approximately
60,000  bbls/d  (39,000  bbls/d,  net to us) of  PSCTM  in  2010.  We have a 65%
interest  in the Long Lake  project  and joint  venture  lands.  We are the sole
operator of the resource and  upgrader.  This allows us to maximize  operational
efficiencies and reduce the cost of managing the project.


UNITED KINGDOM - NORTH SEA
The Golden  Eagle area is  emerging  as a  potentially  significant  development
opportunity.  Our current estimates of recoverable  resource are at the high end
of our pre-drill  estimates.  We expect development of the area will be economic
at approximately US$40/bbl and should support standalone facilities with project
sanction targeted for 2010.

In 2007, we drilled the initial  Golden Eagle  discovery well in what is now the
Golden Eagle area. This well, and a subsequent sidetrack to the north, indicated
the presence of a high quality  reservoir  and testing of the initial  discovery
well demonstrated production rates of approximately 5,000 boe/d.

In 2008, we drilled our Pink discovery  well further  south,  between the Golden
Eagle discovery well and Buzzard. We encountered  hydrocarbons in a high quality
reservoir.  We  successfully  sidetracked  the  well to the  west.  We  recently
completed an appraisal well here and the results are being assessed.


In January  2009, we drilled the Hobby  discovery.  The well  encountered  light
sweet oil with an API of 37  degrees  and was  tested at a  constrained  rate of
5,550  bbls/d  with a 56/64  inch  choke.  We have  subsequently  drilled  three
successful  sidetracks  from the  discovery  well and an appraisal  well. In the
second half of the year,  we expect to continue the appraisal  drilling  program
for the Hobby  discovery.  We have a 34%  operated  interest  in both  Hobby and
Golden Eagle and a 46% operated working interest in Pink.

Elsewhere  in the UK North Sea, our Ettrick  development  is expected to produce
first oil in the next few weeks.  The project is  expected to add  approximately
12,000 to 16,000 boe/d to our production  volumes for the remainder of the year.
Ettrick will produce to a leased  floating  production,  storage and  offloading
vessel  (FPSO)  designed to handle 30,000 bbls/d of oil and 35 mmcf/d of gas. We
have a discovery at Blackbird  which could be a future  tie-back to Ettrick.  We
operate both Ettrick and Blackbird, with a 79.73% working interest in each.


UNITED STATES - GULF OF MEXICO
In the  Eastern  Gulf of Mexico,  we have  previously  made two  discoveries  at
Vicksburg and Shiloh.  We are currently  reviewing  tie-back options to existing
platforms for the Vicksburg discovery and expect to drill an appraisal well here
in 2010. In addition,  we recently spud the Antietam prospect,  which is located
three miles west of our Shiloh  discovery.  Drilling results are expected in the
third quarter.  Later this year, we also expect to drill an exploration  well at
Appomattox,  about  six  miles  west of  Vicksburg.  We have a 25%  interest  in
Vicksburg  and a 20% interest in  Antietam,  Appomattox  and Shiloh,  with Shell
operating all four.

                                       31
<PAGE>

Longhorn is expected to commence  production  shortly. We expect peak production
of approximately 200 mmcf/d or 33,000 boe/d gross (50 mmcf/d or 8,000 boe/d, net
to us). A fourth  development well for the project,  Leo, exceeded  expectations
and has extended our reserve base. We have a 25%  non-operated  working interest
and ENI is the operator.

At Knotty  Head,  we plan to start  drilling  an  appraisal  well in the  fourth
quarter of 2009 after the first of our two new deep-water drilling rigs arrives.
The rig left the  Singapore  shipyard in  mid-June  and is expected to enter the
Gulf of Mexico in August and begin deep-water sea trials.  This new rig has been
contracted at attractive day rates, which are significantly better than industry
average.  We are  currently  negotiating  the terms of an  agreement  to jointly
develop Knotty Head and Pony. We have a 25% operated interest in Knotty Head.


CANADA - HORN RIVER SHALE GAS
During the quarter,  we put two  horizontal  wells on  production at Dilly Creek
that were  drilled  last  summer  and  completed  in the first  quarter of 2009.
Initial  production rates for the first month averaged 850 mcf/d per frac. These
results are in line with previous tests and those of our competitors. We drilled
three  additional  wells  earlier this year and we recently  began fracing these
wells. We are starting to see  efficiencies in our shale gas program as the time
to complete the initial fracs in our new program is substantially  less than our
previous  experience.  We plan to complete  and tie-in  these wells in the third
quarter.  By the end of the year, we expect to have six wells on production at a
total exit rate ranging between 12 and 18 mmcf/d.

Our drilling activity to date has allowed us to secure tenure on the majority of
our Dilly Creek lands. Only two more wells are required to secure the remainder.
Primary  tenure in the Horn River basin is four years and drilling  activity and
extensions increases this up to 18 years.

The Horn River basin has the potential to become the most significant  shale gas
play in North America as it has the highest  resource density and excellent well
productivity.  We have  approximately  88,000  acres in the Dilly Creek area and
38,000  acres in the Cordova  area in  northeast  British  Columbia  with a 100%
working  interest in each.  Further  appraisal  activity is required  before our
reserve estimates can be finalized and commerciality established.


OFFSHORE WEST AFRICA
We recently  completed  drilling an exploration  well in the southern portion of
Oil Prospecting License (OPL) 223, offshore West Africa.

The Owowo  South B-1 well was  drilled  in a water  depth of 670  metres  and is
located 20 kilometres northeast of the Usan field,  currently under development.
Drilling results are under evaluation.

Under the production  sharing contract  governing OPL 223, the Nigerian National
Petroleum Corporation (NNPC) is concessionaire of the license, which is operated
by Total  Exploration  & Production  Nigeria Ltd.  (18%) with its  co-venturers:
Nexen Petroleum  Exploration & Production  Nigeria Ltd.  (18%),  Chevron Nigeria
Deepwater F Ltd. (27%), Esso Exploration and Production  Nigeria (Upstream) Ltd.
(27%) and  Nigerian  Petroleum  Development  Company  (NPDC) Ltd.  (10%).  As is
typical in many jurisdictions, the Nigerian government is reviewing its existing
petroleum fiscal terms, the impact of which on our projects is not yet known.

Development  of the Usan  field on block  OML  138,  offshore  Nigeria  is fully
underway.  The field  development  plan  includes a FPSO  vessel  with a storage
capacity  of two  million  barrels of oil.  Development  drilling  has begun and
throughout the course of the year, the FPSO hull will be  constructed.  The Usan
field  is  expected  to  come  on  stream  in 2012  and  will  ramp up to a peak
production  rate of 180,000 bbls/d (36,000  bbls/d,  net to us). Nexen has a 20%
interest in exploration  and  development  along with Total E&P Nigeria  Limited
(20% and Operator), Chevron Petroleum Nigeria Limited (30%) and Esso Exploration
and Production Nigeria (Offshore East) Limited (30%).

CHEMICALS
Major  construction  of the  technology  conversion  project  (TCP) at the North
Vancouver  chlor-alkali  facility is progressing and is scheduled for mechanical
completion  in late 2009,  with  start-up  near the end of the first  quarter of
2010.  This  project is expected to provide  Canexus with the ability to produce
chlor-alkali  products  at a lower cost.  This  advantage,  together  with added
capacity,  we believe should generate an estimated  $35-$43 million  annually in
incremental cash flow, beginning in 2010.


                                       32
<PAGE>

FINANCIAL RESULTS

CHANGE IN NET INCOME
<TABLE>
<CAPTION>
                                                                                           2009 VS. 2008
                                                                                  Three Months          Six Months
                                                                                 Ended June 30        Ended June 30
--------------------------------------------------------------------------------------------------------------------
<S>                                                                              <C>                  <C>
NET INCOME AT JUNE 30, 2008                                                                380                1,010
                                                                            ========================================
     Favorable (unfavorable) variances(1):

         Realized Commodity Prices
              Crude Oil                                                                   (689)              (1,413)
              Natural Gas                                                                 (114)                (160)
                                                                            ----------------------------------------
                  Total Price Variance                                                    (803)              (1,573)

         Production Volumes, After Royalties
              Crude Oil                                                                    (84)                 (69)
              Natural Gas                                                                  (15)                 (47)
              Changes in Crude Oil Inventory Pending Sale                                   47                   (2)
                                                                            ----------------------------------------
                  Total Volume Variance                                                    (52)                (118)

         Oil and Gas Operating Expense                                                       9                   12

         Oil and Gas Depreciation, Depletion, Amortization and Impairment                  (61)                (101)

         Exploration Expense                                                                24                    3

         Energy Marketing Revenue, Net                                                     192                  259

         Chemicals Contribution                                                             10                   22

         General and Administrative Expense (2)                                            251                  206

         Interest Expense                                                                  (58)                 (99)

         Current Income Taxes                                                              245                  519
         Future Income Taxes                                                                90                  254

         Other
              Decrease in Fair Value of Crude Oil Put Options                             (169)                (185)
              Other                                                                        (38)                 (54)
                                                                            ----------------------------------------

NET INCOME AT JUNE 30, 2009                                                                 20                  155
                                                                            ========================================
</TABLE>
(1) All amounts are presented before provision for income taxes.
(2) Includes stock-based compensation expense.


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


                                       33
<PAGE>

OIL & GAS AND SYNCRUDE

PRODUCTION (BEFORE ROYALTIES) (1)
<TABLE>
<CAPTION>
                                                                Three Months               Six Months
                                                                Ended June 30             Ended June 30
                                                              2009         2008         2009         2008
----------------------------------------------------------------------------------------------------------
<S>                                                          <C>         <C>            <C>         <C>
Crude Oil and Liquids (mbbls/d)
   United Kingdom                                             97.7         100.3        100.7       103.1
   Yemen                                                      51.5          57.6         52.9        59.9
   Canada                                                     14.9          16.4         15.1        16.3
   United States                                              12.1          11.3         11.2        12.5
   Long Lake Bitumen (2)                                       9.3           3.2          8.7         1.9
   Other Countries                                             3.6           5.7          4.5         5.8
Syncrude (mbbls/d) (3)                                        14.9          19.1         17.3        19.2
                                                       ---------------------------------------------------
                                                             204.0         213.6        210.4       218.7
                                                       ---------------------------------------------------
Natural Gas (mmcf/d)
   United Kingdom                                               18           19           18           20
   Canada                                                      136          126          138          127
   United States                                                61           99           56          105
                                                       ---------------------------------------------------
                                                               215          244          212          252
                                                       ---------------------------------------------------

Total Production (mboe/d)                                      240          254          246          261
                                                       ===================================================
</TABLE>

<TABLE>
<CAPTION>
PRODUCTION (AFTER ROYALTIES)

                                                                Three Months               Six Months
                                                                Ended June 30             Ended June 30
                                                              2009        2008          2009         2008
----------------------------------------------------------------------------------------------------------
<S>                                                           <C>        <C>            <C>         <C>
Crude Oil and Liquids (mbbls/d)
   United Kingdom                                             97.6       100.3          100.6       103.1
   Yemen                                                      29.0        29.2           32.3        30.4
   Canada                                                     11.2        12.6           11.8        12.4
   United States                                              10.9         9.7           10.2        10.9
   Long Lake Bitumen (2)                                       9.2         3.2            8.6         1.9
   Other Countries                                             3.3         5.2            4.2         5.4
Syncrude (mbbls/d) (3)                                        13.0        15.9           16.3        16.4
                                                       ---------------------------------------------------
                                                             174.2       176.1          184.0       180.5
                                                       ---------------------------------------------------
Natural Gas (mmcf/d)
   United Kingdom                                               18          19            18           20
   Canada                                                      129         108           127          107
   United States                                                54          85            50           90
                                                       ---------------------------------------------------
                                                               201         212           195          217
                                                       ---------------------------------------------------

Total Production (mboe/d)                                      208         211           217          217
                                                       ===================================================
</TABLE>
(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) Pre-operating  revenues  and costs  associated  with Long Lake  bitumen  are
    capitalized as development costs until we reach commercial operations.
(3) Considered a mining operation for US reporting purposes.


LOWER VOLUMES DECREASED NET INCOME FOR THE QUARTER BY $52 MILLION
Production before royalties  decreased 5% from the prior quarter and 6% from the
second quarter of 2008.  Planned  downtime at Buzzard to return the drilling rig
after  completing rig  modifications,  natural  declines in Yemen and turnaround
activity at Syncrude all  contributed  to the  decrease.  These  decreases  were
partially offset by higher bitumen  production volumes at Long Lake and restored
production in the Gulf of Mexico following last year's hurricane  interruptions.
The decrease  from the second  quarter of 2008 largely  reflects  lower rates in
Yemen and the UK North Sea and  production  that remains  shut-in in the Gulf of
Mexico,  partially offset by higher bitumen production at Long Lake.  Production
before  royalties  was 8% lower  than the prior  quarter  and 1% lower  from the
second quarter of 2008.


                                       34
<PAGE>

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

                                                       Before            After
(mboe/d)                                            Royalties        Royalties
--------------------------------------------------------------------------------
Production, first quarter 2009                            252              225
   Production changes:
       United States                                        4                3
       Long Lake Bitumen                                    1                1
       Canada                                              (1)               -
       Other                                               (2)              (1)
       Yemen                                               (3)              (7)
       Syncrude                                            (5)              (7)
       United Kingdom                                      (6)              (6)
                                             -----------------------------------
Production, second quarter 2009                           240              208
                                             ===================================

Production volumes discussed in this section represent before-royalties volumes,
net to our working interest.

UNITED KINGDOM
Production  volumes  in the UK North  Sea were 6% and 3%  lower  than the  prior
quarter and the same period last year, respectively.

Our share of production  from the Buzzard field  averaged  87,500 boe/d (202,500
boe/d gross) during the second quarter of 2009.  While this was slightly  higher
than last year,  production  was 5,200 boe/d lower than the previous  quarter as
Buzzard production was shut in for approximately seven days while the Galaxy III
drilling rig was reinstalled on the platform.  Production from Buzzard has since
returned to full rates. Construction of the fourth platform at Buzzard continues
and we plan to install the jackets for this platform  during the third  quarter.
This will result in approximately four weeks of downtime,  which is scheduled to
coincide with an expected six week slowdown of the Forties  pipeline for routine
maintenance.  The  fourth  platform  will  allow us to handle  higher  levels of
hydrogen sulphide and maintain peak production until at least 2014.

Production at Scott/Telford remained consistent with the prior quarter; however,
natural declines and unplanned  maintenance  reduced  production 17% compared to
the second quarter of 2008.  Scott/Telford  will be shut down for  approximately
five weeks for planned  maintenance  during the third quarter,  also  coinciding
with Forties  shutdown.  Production  from our  non-operated  fields at Duart and
Farragon averaged 2,900 boe/d during the quarter.

Our Ettrick  development  is expected to produce first oil in the third quarter.
The  project is  expected  to add  approximately  12,000 to 16,000  boe/d to our
production  volumes for the  remainder  of the year.  Ettrick  will produce to a
leased  floating  production,  storage and offloading  vessel designed to handle
30,000 bbls/d of oil and 35 mmcf/d of gas.

YEMEN
Yemen  production  decreased  6% and 11% from the prior  quarter  and the second
quarter of 2008, respectively.  This decline is consistent with our expectations
as the field  matures.  Our drilling  program is focused on  maximizing  reserve
recoveries and economic returns. In the second quarter of 2009, we drilled seven
development wells.  Production  declines are expected to continue as we focus on
maximizing  recovery of the remaining reserves and on obtaining economic returns
on the block.

CANADA
Production in Canada was 2% lower than the previous  quarter and consistent with
the same period last year. Conventional production from our heavy oil properties
was slightly lower due to natural field declines.  We have reduced our heavy oil
capital  program  and are  focusing  on cost  efficiency  to  maximize  economic
returns.  Lower heavy oil production was offset  somewhat by increasing  coalbed
methane (CBM) production. CBM quarterly production averaged 52 mmcf/d and was 11
mmcf/d higher than the second quarter of 2008.

LONG LAKE
Bitumen production averaged 9,300 boe/d (14,300 boe/d gross) during the quarter,
an increase of 7% from the prior  quarter.  To date,  the  upgrader has produced
approximately  700,000 bbls (gross) of premium  synthetic  crude (PSCTM).  PSCTM
volumes tripled in the quarter by progressing the Upgrader ramp up.

In May 2009, we successfully  completed a project to add  supplementary  heat to
the  HLS  units  in  the  water  treatment  plant.  We  also  completed  routine

                                       35
<PAGE>

maintenance  work to remove deposits which typically build up in water treatment
plants.  Steam  production  increased in the quarter and we have achieved record
injection  rates of  approximately  95,000 bbls/d and gross  bitumen  production
rates of approximately 18,000 bbls/d. There are currently 41 of 81 well pairs on
production  and we are  producing  at a  steam-to-oil  ratio (SOR) which  ranges
between  4.0 and 5.0. We continue to expect a long term SOR of 3.0 over the life
of the project.

Production  volumes have been impacted by downtime  associated with improvements
made to the HLS units. We plan to replace valves and conduct  maintenance on our
water  treatment  plant during the third  quarter to further  optimize our steam
production. The cost of these activities will not be significant and will result
in  scheduled  downtime  in the  third  quarter,  impacting  bitumen  and  PSCTM
production.  As  steam  generation  increases,  all  wells  are  expected  to be
converted to production mode.

With  respect to the  Upgrader,  all major units are  operational  and Syngas is
being used in SAGD  operations.  This allows us to decrease  operating  costs by
reducing the requirement for purchased natural gas. The solvent de-asphalter and
thermal  cracker  units  are  expected  to start  shortly  and will  allow us to
transition from gasifying  vacuum residue,  which contains some lighter parts of
the barrel,  to gasifying  asphaltenes,  the heaviest  part of the barrel.  As a
result, we expect our PSCTM yield to increase from approximately 60% to 80%.

UNITED STATES
Gulf of Mexico  production  volumes were 18% higher than the prior quarter as we
continued to restore shut-in production from our hurricane-affected  properties.
Our Wrigley field came back on stream in late April and we anticipate that field
production  will be  restored to  pre-hurricane  rates in the second half of the
year.  The  increase  was offset  slightly  by natural  production  declines  at
Gunnison.  Production  volumes from  Wrigley  will be limited for  approximately
three weeks in the third quarter to complete corrosion mitigation work.

Production  volumes were 20% lower than the same period last year  primarily due
to production shut-in by the hurricane interruptions.  This was partially offset
by higher rates on the  properties  that are currently  producing as a result of
successful   workovers  and   recompletions.   Following   the  2008   hurricane
interruptions,  approximately  4,000  boe/d  remains  shut in and is expected to
return  to  production  in 2010 or 2011,  after  reconstruction  of a  destroyed
platform.  At the end of the second  quarter 2009, our production in the Gulf of
Mexico was approximately 24,000 boe/d.

We expect production to start up from our non-operated  Longhorn  development in
the deep water shortly.  The  development is a three well subsea tie-back to the
Corral platform located 19 miles northwest of the field,  with plans underway to
tie-in a fourth well that was successfully drilled earlier in the year.

OTHER COUNTRIES
Our share of production  from the Guando field in Colombia  averaged 3,600 boe/d
during the quarter,  approximately  2,000 boe/d lower than the prior quarter and
the second quarter of 2008.  The decrease  reflects the reduction of our working
interest  during  the  quarter.  Under the  terms of our  license,  our  working
interest  in the  Guando  field  decreased  from  20% to  10% in May  2009  when
cumulative production from the field reached 60 million barrels.

SYNCRUDE
Syncrude  production was 25% lower than the previous  quarter and 22% lower than
the second  quarter of 2008.  The scheduled  turnaround of Coker 8-3 took longer
than anticipated,  resulting in lower production  volumes.  Maintenance on Coker
8-1 and fewer shipments of synthetic crude as a result of outages on the Pembina
pipeline also contributed to reduced production. Syncrude is currently producing
25,000 bbls/d (net to us) early in the third quarter.



                                       36
<PAGE>

COMMODITY PRICES
<TABLE>
<CAPTION>
                                                                    Three Months                Six Months
                                                                    Ended June 30             Ended June 30
                                                                  2009         2008         2009         2008
--------------------------------------------------------------------------------------------------------------
<S>                                                             <C>          <C>          <C>          <C>
CRUDE OIL
   West Texas Intermediate (WTI) (US$/bbl)                       59.62       123.98        51.35       110.94
   Dated Brent (Brent) (US$/bbl)                                 58.79       121.38        51.60       109.14
                                                            --------------------------------------------------

   Benchmark Differentials (1) (US$/bbl)
         Heavy Oil                                                7.73        22.08         8.45        21.96
         Mars                                                     2.27         6.96         0.80         6.94
         Masila                                                   0.93         3.92         0.49         3.12

   Realized Prices from Producing Assets (Cdn$/bbl)
         United Kingdom                                          69.42       118.24        60.38       104.56
         Yemen                                                   69.40       120.39        60.63       107.97
         Canada                                                  56.05        93.16        45.49        79.62
         United States                                           66.23       120.77        57.05       106.11
         Other Countries                                         66.83       113.18        51.63       102.21
         Syncrude                                                71.58       130.90        62.44       116.24

   Corporate Average (Cdn$/bbl)                                  68.32       118.00        59.12       104.68
                                                            --------------------------------------------------

NATURAL GAS
   New York Mercantile Exchange (US$/mmbtu)                       3.81        11.48         4.15        10.12
   AECO (Cdn$/mcf)                                                3.47         8.86         4.41         7.81
                                                            --------------------------------------------------

   Realized Prices from Producing Assets (Cdn$/mcf)
         United Kingdom                                           3.67         7.06         4.69         6.95
         Canada                                                   3.42         9.67         4.09         8.50
         United States                                            4.58        11.80         5.19        10.33

   Corporate Average (Cdn$/mcf)                                   3.77        10.21         4.43         9.07
                                                            --------------------------------------------------

NEXEN'S AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe)            61.28       108.26        54.28        96.36
                                                            --------------------------------------------------

AVERAGE FOREIGN EXCHANGE RATE - Canadian to US Dollar           0.8571       0.9900      0.8290       0.9929
                                                            --------------------------------------------------
</TABLE>
(1) These differentials are a discount/(premium) to WTI.

LOWER COMMODITY PRICES DECREASED QUARTERLY NET INCOME BY $803 MILLION
WTI averaged US$59.62/bbl for the quarter, 38% higher than the previous quarter,
but 52% lower than the  second  quarter of 2008.  Brent  increased  32% from the
first  quarter  of 2009 and fell 52% from  last  year.  The  effect of the lower
commodity prices from last year was mitigated  somewhat by the  strengthening US
dollar. Our realized crude oil sales price averaged $68.32/bbl,  36% higher than
the previous quarter and 42% lower than the second quarter of 2008.

NYMEX and AECO natural gas prices decreased 15% and 35%,  respectively  from the
previous quarter and 67% and 61%,  respectively  from the same period last year.
Our realized  average gas sales price  decreased 26% and 63%,  respectively,  as
compared to the same periods.  Most of our natural gas sales are priced based on
NYMEX and AECO benchmark prices.

The US  dollar  strengthened  relative  to last  year,  increasing  our sales by
approximately $147 million compared to the second quarter of 2008. This increase
is represented by higher  realized crude oil and natural gas prices of $9.17/bbl
and  $0.51/mcf,  respectively.  However,  the US  dollar  weakened  against  the
Canadian dollar during the second quarter,  reducing net sales by  approximately
$74 million.  Our second quarter realized crude oil and natural gas sales prices
are $4.62/bbl and $0.25/mcf lower, respectively.

CRUDE OIL REFERENCE PRICES
Crude oil prices  increased  during  the  quarter,  driven  mainly by a rally in
equity markets and positive  investment flows into commodity  markets due to the
weakening US dollar and concerns about rising inflation. Current crude oil price
levels are not supported by near-term demand/supply fundamentals indicating that
the market may be driven  more by medium term  forecasts.  Crude oil prices were
supported by positive signs for the global  economy,  particularly  in Asia, and
optimism that the worst of the recession may be over.  However,  OECD  economies

                                       37
<PAGE>

are still  fragile and global trade  remains  weak.  The  apparent  beginning of
economic  recovery  has  not  yet  improved  short-term  fundamentals  in  these
countries and inventory levels, particularly distillate and product inventories,
remain high  although US gasoline  inventories  are at the lower end of the five
year range. Geopolitical events during the quarter had little impact on price as
OPEC has spare production capacity of almost five million barrels per day. Early
in the third quarter,  this optimism  waned and crude oil benchmark  prices fell
approximately 10%-15% in the first two weeks of July.

CRUDE OIL DIFFERENTIALS
The  narrower  heavy oil  differential  was  driven by cuts in medium  crude oil
quotas by OPEC,  strong fuel oil prices and lower heavy oil supply from  Mexico.
Differentials  are  expected to widen as  refineries  reduce  coking runs due to
lower  margins.  However,  the  approaching  asphalt  season should  continue to
support heavy oil prices.

The Brent/WTI  differential  was volatile during the quarter.  Initial  premiums
over WTI were due to depressed WTI pricing  caused by high  inventory  levels at
Cushing.   However,  as  inventories   decreased  throughout  the  quarter,  the
differential  reverted  to a  discount.  Lower  Cushing  inventory  levels  also
contributed  to the wider Masila  differential.  The Masila  price  strengthened
relative  to  Brent,  reflecting  strong  demand  from  China  and  other  Asian
countries.

The Mars  differential  continued  to widen  during  the second  quarter  due to
stronger WTI prices.

NATURAL GAS REFERENCE PRICES
Lower natural gas prices were driven by declines in industrial  and power demand
and high inventory  levels as natural gas producers have been slow to respond to
lower prices by reducing  supply.  Continuing weak North American gas prices are
forecasted as strong supply additions are expected from shale gas, tight gas and
new LNG volumes from Russia and the Middle East.  Large storage  capacity in the
US is also  expected  to  increase  LNG imports  whenever  international  supply
exceeds demand.


OPERATING EXPENSES
<TABLE>
<CAPTION>
                                                                                   Three Months              Six Months
                                                                                   Ended June 30            Ended June 30
(Cdn$/boe)                                                                      2009         2008         2009         2008
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>          <C>           <C>          <C>
Operating expenses based on our production before royalties (1)
   Conventional Oil and Gas                                                     8.80         9.01         8.53         8.20
   Synthetic Crude Oil
         Syncrude                                                              57.21        45.09        45.70        40.10
   Average Oil and Gas                                                         11.95        11.89        11.27        10.60
                                                                         ---------------------------------------------------

Operating expenses based on our production after royalties
   Conventional Oil and Gas                                                    10.28        10.97         9.86         9.95
   Synthetic Crude Oil
         Syncrude                                                              65.36        54.28        48.59        46.78
   Average Oil and Gas                                                         13.94        14.45        12.95        12.83
                                                                         ---------------------------------------------------
</TABLE>
(1) Operating expenses per boe are our total oil and gas operating costs divided
    by our working  interest  production  before  royalties.  We use  production
    before  royalties to monitor our performance  consistent with other Canadian
    oil and gas companies.


LOWER OPERATING EXPENSES INCREASED NET INCOME FOR THE QUARTER BY $9 MILLION
Our  corporate  average  decreased  $1.03/boe  as a result of lower  maintenance
expenses in the UK North Sea,  Canada and the US Gulf of Mexico.  These  savings
were offset by the stronger US dollar,  which increased our corporate average by
$1.09/boe for the quarter.  Production from our lower cost areas such as Buzzard
made up more of our total consolidated  production  relative to last year, which
lowered our overall corporate average by $0.78/boe.

In the UK North Sea, lower  production  tariffs at Buzzard reduced our corporate
average by  $0.54/boe.  The other UK North Sea  operating  areas  decreased  our
corporate average by $0.28/boe as production  declines only partially offset the
impact of lower operating costs.

In  Yemen,  we  continue  to  concentrate  our  efforts  on  maximizing  reserve
recoveries and slowing the natural decline of the fields by maintaining existing
wells.  At Block  51,  a  combination  of  higher  production  rates  and  lower
maintenance costs lowered our corporate average by $0.11/boe.  In the US Gulf of
Mexico,  lower  downhole  maintenance  costs  were  offset  by lower  production
volumes, increasing our corporate average by $0.15/boe.

In Canada,  lower  utility and downhole  workover  costs  reduced our  corporate
average  by  $0.24/boe.  At  Syncrude,  maintenance  and  turnaround  costs were
consistent with the same period last year. However, the downtime associated with
the  maintenance  activity was longer this year  resulting in lower  production.
This increased our corporate average by $0.79/boe.

                                       38
<PAGE>

DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT (DD&A)
<TABLE>
<CAPTION>
                                                                   Three Months               Six Months
                                                                   Ended June 30             Ended June 30
(Cdn$/boe)                                                       2009         2008         2009         2008
-------------------------------------------------------------------------------------------------------------
<S>                                                             <C>          <C>          <C>          <C>
DD&A based on our production before royalties (1)
   Conventional Oil and Gas                                     18.49        14.72        18.53        14.55
   Synthetic Crude Oil
         Syncrude                                                6.31         6.53         6.40         6.70
   Average Oil and Gas                                          17.69        14.07        17.64        13.96
                                                          ---------------------------------------------------

DD&A based on our production after royalties
   Conventional Oil and Gas                                     21.59        17.91        21.43        17.65
   Synthetic Crude Oil
         Syncrude                                                7.21         7.86         6.80         7.81
   Average Oil and Gas                                          20.64        17.11        20.26        16.88
                                                          ---------------------------------------------------
</TABLE>
(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.


HIGHER OIL AND GAS DD&A DECREASED NET INCOME FOR THE QUARTER BY $61 MILLION
Our oil and gas DD&A expense  increased 20% over the same period last year.  The
strengthening  US dollar  relative to the second  quarter of 2008  increased our
corporate average by $2.48/boe,  as depletion of our international and US assets
is denominated in US dollars.

In the UK North Sea, our Buzzard  depletion  rate was lower than the same period
last year as  successful  development  drilling  increased  our  proved  reserve
estimates at the end of 2008.  The lower  depletion  rate reduced our  corporate
average by $0.23/boe.  Elsewhere in the UK, our  corporate  average is $0.29/boe
higher primarily as a result of downward  economic reserve  revisions due to low
2008 year end prices at our mature Scott/Telford fields at the end of 2008.

In  Yemen,  the  impact  of  lower  capital  expenditures  from  drilling  fewer
development  wells  decreased our corporate  unit depletion rate by $0.51/boe as
compared to the second quarter of 2008. In the Gulf of Mexico,  higher estimates
for  future  abandonment  costs  and  downward  year end  price-related  reserve
revisions at the end of 2008 resulted in higher depletion rates,  increasing our
corporate average rate by $0.81/boe.

Canadian  depletion  increased our corporate  average by $0.71/boe from the same
period last year.  Higher depletion rates for heavy oil properties were realized
as lower  year-end  commodity  prices  reduced  our  proved  reserves.  This was
partially  offset by lower  depletion rates for our CBM properties as additional
proved reserves were recognized through improved recovery rates.


                                       39
<PAGE>

EXPLORATION EXPENSE
<TABLE>
<CAPTION>
                                                                                  Three Months               Six Months
                                                                                  Ended June 30            Ended June 30
                                                                                2009         2008        2009          2008
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                              <C>          <C>         <C>           <C>
Seismic                                                                           31           24          43            34
Unsuccessful Drilling                                                             16           51          27            51
Other                                                                             30           26          60            48
                                                                         ---------------------------------------------------
Total Exploration Expense                                                         77          101         130           133
                                                                         ===================================================

New Growth Exploration                                                           167          136         330           320
Geological and Geophysical Costs                                                  31           24          43            34
                                                                         ---------------------------------------------------
Total Exploration Expenditures                                                   198          160         373           354
                                                                         ===================================================

Exploration Expense as a % of Exploration Expenditures                           39%          63%         35%           38%
                                                                         ---------------------------------------------------
</TABLE>

LOWER EXPLORATION EXPENSE INCREASED NET INCOME FOR THE QUARTER BY $24 MILLION
Our exploration  expenditures  were $38 million higher than the same period last
year as we  invested  in our  shale  gas  exploration  program  at Dilly  Creek,
successfully  drilled the Owowo  exploration well offshore Nigeria and continued
to appraise the Golden Eagle area in the UK North Sea.

In 2007, we drilled the initial  Golden Eagle  discovery well in what is now the
Golden Eagle area, and followed up with another success further south at Pink in
2008.  In January  2009, we drilled the Hobby  discovery.  We have  subsequently
drilled  successful  sidetracks and appraisal wells on the Pink and Hobby wells.
In the second half of the year,  we expect to continue  the  appraisal  drilling
program for the Hobby discovery.

In the Eastern Gulf of Mexico,  we previously  made two discoveries at Vicksburg
and Shiloh. We are currently  reviewing  tie-back options to existing  platforms
for the Vicksburg  discovery and expect to drill an appraisal well here in 2010.
In addition,  we recently  spud the Antietam  prospect,  which is located  three
miles west of our Shiloh  discovery.  Drilling results are expected in the third
quarter.  Later  this  year,  we also  expect  to drill an  exploration  well at
Appomattox,  about  six  miles  west of  Vicksburg.  We have a 25%  interest  in
Vicksburg  and a 20% interest in  Antietam,  Appomattox  and Shiloh,  with Shell
operating all four.

We recently  completed  drilling an exploration  well in the southern portion of
Oil  Prospecting  License (OPL) 223,  offshore West Africa.  The Owowo South B-1
well was  drilled in a water  depth of 670  metres and is located 20  kilometres
northeast of the Usan field,  currently under development.  Drilling results are
under evaluation.

Exploration  expense was lower by $24 million  compared  with the same period in
the prior year.  In 2008,  we expensed $30 million of  unsuccessful  exploration
drilling associated with our CBM plays in Canada.

Our  exploration  expense also includes costs of $25 million to acquire  seismic
data in the US Gulf of Mexico and North Sea.


                                       40
<PAGE>

ENERGY MARKETING
<TABLE>
<CAPTION>
                                                                   Three Months               Six Months
                                                                   Ended June 30             Ended June 30
                                                                 2009         2008         2009         2008
-------------------------------------------------------------------------------------------------------------
<S>                                                            <C>          <C>          <C>          <C>
   Physical Sales (1)                                          10,063       18,281       20,008       32,508
   Physical Purchases (1)                                      (9,604)     (18,084)     (19,406)     (31,822)
   Net Financial Transactions (1)                                (276)        (317)        (228)        (604)
   Change in Fair Market Value of Inventory                        38          141          114          150
                                                          ---------------------------------------------------
Marketing Revenue                                                 221           21          488          232
   Transportation Expense                                        (163)        (166)        (328)        (339)
   Other                                                           (1)           7            4           12
                                                          ---------------------------------------------------
NET MARKETING REVENUE                                              57         (138)         164          (95)
                                                          ===================================================

CONTRIBUTION TO NET MARKETING REVENUE BY REGION
   North America                                                   55         (123)         159          (78)
   Asia                                                             6            4           18            8
   Europe                                                          (4)         (19)         (13)         (25)
                                                          ---------------------------------------------------
NET MARKETING REVENUE                                              57         (138)         164          (95)
   DD&A                                                            (3)          (4)          (7)          (7)
   General and Administrative                                     (26)         (41)         (49)         (67)
   Allowance for Doubtful Receivables                              (3)           -            -            -
                                                          ---------------------------------------------------
MARKETING CONTRIBUTION TO INCOME BEFORE INCOME TAXES               25         (183)         108         (169)
                                                          ===================================================
NORTH AMERICA
   NATURAL GAS
   Physical Sales Volumes (2)  (bcf/d)                            4.6          7.3          4.8          7.0
   Transportation Capacity (bcf/d)                                1.3          2.0          1.3          2.0
   Storage Capacity (bcf)                                        33.9         54.2         33.9         54.2
   Financial Volumes (3) (bcf/d)                                 10.0         18.8         12.7         22.6
   CRUDE OIL
   Physical Sales Volumes (2) (mbbls/d)                           873          689          835          669
   Storage Capacity (mbbls)                                     2,644        2,699        2,644        2,699
   Financial Volumes (3) (mbbls/d)                                667        1,420          789        1,416
   POWER
   Physical Sales Volumes (2) (GWh/d)                              10            5            7            5
   Generation Capacity (MW)                                        87           87           87           87

ASIA
   Physical Sales Volumes (2) (mbbls/d)                           115          113           99          114
   Financial Volumes (3) (mbbls/d)                                531          337          425          302

EUROPE
   NATURAL GAS
   Physical Sales Volumes (2)  (bcf/d)                            0.9          1.0          1.1          1.2
   Storage Capacity (bcf)                                         3.1          3.7          3.1          3.7
   CRUDE OIL
   Financial Volumes (3) (mbbls/d)                                259          598          378        1,352
   POWER
   Physical Sales Volumes (2) (GWh/d)                               5            5            6            5

VALUE-AT-RISK
   Quarter-end                                                     15           31           15           31
   High                                                            19           40           24           40
   Low                                                             13           29           13           21
   Average                                                         15           34           17           32
                                                          ---------------------------------------------------
</TABLE>
(1) Marketing's   physical   sales,   physical   purchases   and  net  financial
    transactions  are reported net on the  Unaudited  Consolidated  Statement of
    Income as marketing and other.
(2) Excludes  intra-segment  transactions.  Physical volumes  represent  amounts
    delivered  during the  quarter.
(3) Financial volumes  represent amounts largely acquired to economically  hedge
    physical transactions during the quarter.

                                       41
<PAGE>

HIGHER CONTRIBUTION FROM ENERGY MARKETING INCREASED NET INCOME BY $192 MILLION
Energy  marketing  strategies  and positions  focused on optimizing our physical
marketing business during the quarter with the North America natural gas storage
strategy benefiting economically from widening time spreads and the global crude
oil teams continuing to profit from the contango forward curve.

In 2008, the North America natural gas team incurred  financial  losses on basis
positions  that were designed to take  advantage of narrowing  locational  price
differentials  between the western supply regions and eastern  consuming markets
in North  America with the addition of new pipeline  capacity.  Strong NYMEX gas
prices  worked  against  these  physical  gas market  fundamentals  widening out
location  differentials  in supply  regions last year.  We have since  refocused
energy marketing on the physical business of marketing and optimization for both
the gas and crude oil teams which involves buying,  selling,  holding and moving
product.

Relative to the first  quarter of 2009,  the second  quarter  began the seasonal
injection  cycle with low natural gas prices and high inventory  levels in North
America.  Weak demand in the market caused location spreads to narrow across the
entire transportation portfolio. Despite this economic environment, time spreads
widened  supporting our storage  strategy as we continue to build  inventory for
the  winter  season.  On a  reported  basis,  we  recognized  net  gains  on the
derivatives  that protect our economic  exposure of our physical  transportation
and storage  strategies.  The North America crude oil group  continued to profit
from  contango in the market during the second  quarter,  although the crude oil
contango curve was flatter than the first quarter.  The gains from this strategy
were offset by widening  differentials and the significant  strengthening of the
Canadian dollar.

Results from our marketing group vary by quarter and historical  results 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 change in value of the financial  instruments  we
use to hedge these assets.

COMPOSITION OF NET MARKETING REVENUE
<TABLE>
<CAPTION>
                                                                                  Three Months                Six Months
                                                                                  Ended June 30             Ended June 30
                                                                                2009         2008         2009         2008
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>          <C>          <C>          <C>
Trading Activities (Physical and related Financial)                               58         (145)         160         (108)
Non-Trading Activities                                                            (1)           7            4           13
                                                                         ---------------------------------------------------
Total Net Marketing Revenue                                                       57         (138)         164          (95)
                                                                         ===================================================
</TABLE>

TRADING ACTIVITIES
In energy marketing,  we enter into contracts to purchase and sell crude oil and
natural gas as well as storage and transportation  contracts to capture time and
location differences. We also use financial and derivative contracts,  including
futures,  forwards,  swaps and options for  hedging  and  trading  purposes.  We
account for all financial and derivative  contracts not designated as hedges for
accounting  purposes  using fair value  accounting and record the change in fair
value in marketing  and other  income.  The fair value of these  instruments  is
included with amounts receivable or payable and they are classified as long-term
or short-term based on their anticipated settlement date.

OTHER ACTIVITIES
We enter into fee for service contracts related to  transportation,  storage and
sales of  third-party  oil and gas. In  addition,  we earn income from our power
generation facilities at Balzac and Soderglen.


FAIR VALUE OF DERIVATIVE CONTRACTS
Our processes for  estimating and  classifying  the fair value of our derivative
contracts are consistent with those in place at December 31, 2008.

At June 30,  2009,  the fair  value of our  derivative  contracts  in our energy
marketing  trading  activities was a net loss of $35 million.  These derivatives
are used to economically hedge our physical storage and transportation contracts
which cannot be carried at fair value until they are used.  Below is a breakdown
of the derivative fair value by valuation method and contract maturity.

<TABLE>
<CAPTION>
                                                                                  MATURITY
--------------------------------------------------------------------------------------------------------------------
                                                          Less than                            More than
                                                             1 year    1-3 years   4-5 years     5 years       Total
                                                         -----------------------------------------------------------
   <S>                                                    <C>          <C>         <C>         <C>             <C>
   Level 1 - Actively Quoted Markets                          (124)         (56)        (21)           -       (201)
   Level 2 - Based on Other Observable Pricing Inputs           92           58           7            5        162
   Level 3 - Based on Unobservable Pricing Inputs               (7)          10           1            -          4
                                                         -----------------------------------------------------------
Total                                                          (39)          12         (13)           5        (35)
                                                         ===========================================================
</TABLE>

                                       42
<PAGE>

CHANGES IN FAIR VALUE OF DERIVATIVE CONTRACTS
<TABLE>
<CAPTION>
                                                                                                          Total
----------------------------------------------------------------------------------------------------------------
<S>                                                                                                       <C>
Fair Value at December 31, 2008                                                                              63
   Change in Fair Value of Contracts                                                                         37
   Net Losses (Gains) on Contracts Closed                                                                  (135)
   Changes in Valuation Techniques and Assumptions (1)                                                        -
                                                                                                 ---------------
Fair Value at June 30, 2009                                                                                 (35)
                                                                                                 ===============
</TABLE>
(1) Our valuation methodology has been applied consistently in each period.

The fair values of our  derivative  contracts  will be realized over time as the
related contracts  settle.  Until then, the value of certain contracts will vary
with forward commodity prices and price  differentials.  The average term of our
derivative  contracts is approximately 1.2 years. Those maturing beyond one year
primarily relate to North American natural gas positions.


CHEMICALS

HIGHER CHEMICALS CONTRIBUTION INCREASED NET INCOME BY $10 MILLION
North America chlorate sales decreased  slightly from the second quarter of 2008
as the effect of stronger  prices was offset by a 21% decrease in sales  volumes
as a result of the global economic downturn.  Chlor-alkali revenue increased 17%
from the same period last year primarily as a result of higher  caustic  prices.
In Brazil,  chlorate  revenues declined slightly as higher prices were offset by
lower sales volumes,  while  chlor-alkali  revenues were down 33% as a result of
fewer sales of purchased product as this activity generates no gross margin.

Chemicals  net income  includes  foreign  exchange  gains of $24  million on the
Canexus  US-dollar  denominated  debt, as well as gains of $5 million related to
interest rate swaps and foreign exchange options and forward  contracts.  During
the quarter,  we reduced the carrying value of the sodium chlorate assets at the
Bruderheim plant by $17 million as it is no longer in use. They also incurred $3
million of decommissioning and other costs in connection with the plant closure.


CORPORATE EXPENSES

GENERAL AND ADMINISTRATIVE (G&A)
<TABLE>
<CAPTION>
                                                                            Three Months           Six Months
                                                                           Ended June 30          Ended June 30
                                                                          2009       2008        2009      2008
----------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>         <C>        <C>       <C>
General and Administrative Expense before Stock-Based Compensation         111         90         211       186
Stock-Based Compensation (1)                                                56        328          56       287
                                                                      ------------------------------------------
Total General and Administrative Expense                                   167        418         267       473
                                                                      ==========================================
</TABLE>
(1) Includes cash and non-cash  expenses  related to our tandem option and stock
    appreciation rights plans.

LOWER G&A COSTS INCREASED NET INCOME BY $251 MILLION
Lower  stock-based  compensation  expense reduced our second quarter G&A expense
from  the  prior  year  by $272  million.  Changes  in our  share  price  create
volatility in our net income as we account for  stock-based  compensation  using
the  intrinsic-value  method.  Our share price increased 18% during the quarter,
compared to a 33% increase last year. The impact of the current  increase in our
share  price on  stock-based  compensation  expense  is  reduced  as many of our
stock-based  awards  are below  their  exercise  price.  Cash  payments  made in
connection with our stock-based  compensation  programs during the three and six
month  periods  ended June 30, 2009 were $14 million (2008 - $69 million and $87
million, respectively).

G&A expense before stock-based compensation increased $14 million primarily as a
result  of  higher  employee  costs  in the US  where  we have  been  recruiting
experienced  staff to prepare for the two new-build Ensco rigs, due to arrive on
location later this year and mid 2010.


                                       43
<PAGE>

INTEREST
<TABLE>
<CAPTION>
                                                           Three Months          Six Months
                                                          Ended June 30         Ended June 30
                                                         2009       2008        2009      2008
-----------------------------------------------------------------------------------------------
<S>                                                      <C>        <C>         <C>       <C>
Interest                                                   92         75         186       155
   Less: Capitalized                                      (18)       (59)        (44)     (112)
                                                    -------------------------------------------
Net Interest Expense                                       74         16         142        43
                                                    ===========================================

Effective Interest Rate                                  4.5%       6.3%        4.7%      3.1%
                                                    -------------------------------------------
</TABLE>

HIGHER NET INTEREST EXPENSE REDUCED NET INCOME BY $58 MILLION
Our financing costs increased $17 million from the second quarter of 2008 as the
stronger US dollar  increased  our interest  expense by $15 million.  Additional
borrowings on our term credit  facilities  increased our interest  expense by $5
million.  This was partially offset by lower interest rates on our floating rate
debt and by repaying medium-term notes in June 2008.

Capitalized  interest on our Long Lake  Project  was $49 million  lower than the
previous year as  construction  of the facilities  was completed  earlier in the
year. This decrease was partially offset by capitalizing  additional interest on
construction  of  the  fourth  platform  at  Buzzard  and  on  our  other  major
developments at Ettrick in the UK North Sea and at Usan, offshore West Africa.

INCOME TAXES
<TABLE>
<CAPTION>
                                                          Three Months           Six Months
                                                          Ended June 30         Ended June 30
                                                         2009       2008        2009      2008
-----------------------------------------------------------------------------------------------
<S>                                                      <C>        <C>         <C>       <C>
Current                                                   206        451         324       843
Future                                                   (229)      (139)       (316)      (62)
                                                    -------------------------------------------
Total Provision for (Recovery of) Income Taxes            (23)       312           8       781
                                                    ===========================================
</TABLE>

LOWER TAXES INCREASED NET INCOME BY $335 MILLION
During the second quarter, lower commodity prices and a decrease in the value of
our crude oil put options  contributed to lower tax expense. We also reduced tax
expense  relative  to last year as we  continue  to  amortize  a portion  of the
deferred tax credit arising from the 2008 internal  reorganization  of our North
Sea assets.  Our income tax provision  includes  current taxes in the UK, Yemen,
Norway, Colombia and the US.


OTHER
<TABLE>
<CAPTION>
                                                          Three Months           Six Months
                                                          Ended June 30         Ended June 30
                                                         2009       2008        2009      2008
-----------------------------------------------------------------------------------------------
<S>                                                      <C>        <C>         <C>       <C>
Decrease in Fair Value of Crude Oil Put Options          (179)       (10)       (195)      (10)
                                                    -------------------------------------------
</TABLE>

During the first  quarter of 2008,  we  purchased  put options on  approximately
70,000 bbls/d of our 2009 crude oil production.  These options establish a Dated
Brent floor price of US$60/bbl, are settled annually and provide a base level of
price protection  without limiting our upside to higher prices.  The put options
were  purchased for $14 million and are carried at fair value.  During the third
quarter of 2008, Lehman Brothers,  one of the put option  counterparties,  filed
for bankruptcy  protection  impacting 25,000 bbls/d of our 2009 put options. The
carrying  value of these put options has been  reduced to nil. At June 30, 2009,
the remaining  options had a fair value of $36 million,  $195 million lower than
the  end  of  2008.  The  decrease  in  fair  value  this  year  was  caused  by
strengthening Dated Brent crude oil prices. The put options will be in-the-money
at the end of the year if prices average US$70/bbl or lower for the remainder of
the year.


                                       44
<PAGE>

LIQUIDITY AND CAPITAL RESOURCES

CAPITAL STRUCTURE
<TABLE>
<CAPTION>
                                                                                    June 30         December 31
                                                                                       2009                2008
----------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>             <C>
NET DEBT (1)
     Bank Debt                                                                        2,995               1,448
     Public Senior Notes                                                              4,348               4,582
                                                                          --------------------------------------
       Total Senior Debt                                                              7,343               6,030
     Subordinated Debt                                                                  520                 548
                                                                          --------------------------------------
       Total Debt                                                                     7,863               6,578
     Less: Cash and Cash Equivalents                                                 (1,974)             (2,003)
                                                                          --------------------------------------
TOTAL NET DEBT                                                                        5,889               4,575
                                                                          ======================================

SHAREHOLDERS' EQUITY                                                                  7,303               7,191
                                                                          ======================================
</TABLE>
(1) Includes all of our  borrowings  and is  calculated  as  long-term  debt and
    short-term borrowings less cash and cash equivalents.

NET DEBT

Our net debt levels are  directly  related to our  operating  cash flows and our
capital expenditure activities. Changes in net debt are related to:
<TABLE>
<CAPTION>
                                                                                Three Months         Six Months
                                                                               Ended June 30      Ended June 30
                                                                                        2009               2009
----------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>                <C>
Capital Investment                                                                       715              1,464
Acquisition of Additional Working Interest at Long Lake                                    -                755
Cash Flow from Operating Activities (1)                                                 (109)              (898)
                                                                            ------------------------------------
   Deficiency                                                                            606              1,321

Dividends on Common Shares                                                                26                 52
Issue of Common Shares                                                                    (7)               (30)
Changes in Restricted Cash                                                               (67)               247
Foreign Exchange Translation of US-dollar Debt and Cash                                 (465)              (327)
Other                                                                                     59                 51
                                                                            ------------------------------------
Increase in Net Debt                                                                     152              1,314
                                                                            ====================================
</TABLE>
(1) Includes  use of cash for the three months ended June 30 of $340 million for
    changes in non-cash  working capital and a source of cash for the six months
    ended June 30 of $80 million for changes in non-cash working capital.

Our net  debt  increased  from  March  31,  2009  despite  the  Canadian  dollar
strengthening  against the US dollar during the quarter.  This impact was offset
as our second quarter capital  investment  exceeded our cash flow from operating
activities.  Our available  liquidity at June 30, 2009 was approximately  US$2.5
billion, comprised of cash on hand and undrawn credit facilities. Operating cash
flows in the oil and gas industry can be volatile as short-term commodity prices
are driven by existing supply and demand fundamentals and market volatility.  We
invest through the lows of the current  commodity market to create future growth
and  value for our  shareholders  for the  long-term.  Changes  in our  non-cash
working  capital can vary between  quarters as our energy  marketing net working
capital  position  fluctuates  depending on timing of settlement of  outstanding
positions and the movement in commodity prices.

CHANGE IN WORKING CAPITAL
<TABLE>
<CAPTION>
                                                                     June 30       December 31        Increase/
                                                                        2009              2008        (Decrease)
---------------------------------------------------------------------------------------------------------------
<S>                                                                  <C>           <C>                <C>
Cash and Cash Equivalents                                              1,974             2,003             (29)
Restricted Cash                                                          335               103             232
Accounts Receivable                                                    3,272             3,163             109
Inventories and Supplies                                                 598               484             114
Accounts Payable and Accrued Liabilities                              (3,608)           (3,326)            282
Other                                                                     78                76               2
                                                             --------------------------------------------------
Net Working Capital                                                    2,649             2,503
                                                             ==================================
</TABLE>

                                       45
<PAGE>

Accounts receivable and accounts payable in our energy marketing group increased
since year end primarily as a result of higher crude oil prices. These increases
have been  partially  offset by lower  natural  gas  volumes  caused by reducing
activity   to   focus  on   supporting   our  core   physical   business   as  a
producer/marketer.  Earlier in the year,  our  energy  marketing  group  reduced
commodity  inventory by selling natural gas in storage during the winter season.
We took  advantage of low seasonal  natural gas markets and acquired  additional
volumes in the second  quarter for storage  until the 2009/2010  winter  heating
season.  In June,  we  liquidated a portion of our crude oil  inventory  and the
proceeds will be received in July.

At June 30,  2009,  our  restricted  cash  consists  of margin  deposits of $335
million (December 31, 2008 - $103 million) related to exchange-traded derivative
financial  contracts  used by our  energy  marketing  group  to  hedge  physical
commodities,  and storage,  transportation and customer sales contracts.  We are
required  to  maintain  margin  for net  out-of-the-money  derivative  financial
contracts.  The increase in margin  primarily  relates to  derivative  financial
contracts  hedging our natural gas positions.  Declining  natural gas prices and
widening time spreads  increased  the value of storage and fixed price  customer
sales contracts.  Concurrently, the derivative financial contracts hedging these
positions  declined  in  value.  Additional  margin  was  required  to cover the
increase in the net out-of-the-money derivative financial contracts.

The increase in other assets is primarily  represented  by the Dated Brent crude
oil put options fair value of $36 million.  The annual options mature at the end
of 2009 and were  reclassed  from  long-term to current  assets during the first
quarter.

OUTLOOK FOR REMAINDER OF 2009

We expected  our 2009  production  to range  between  255,000 and 270,000  boe/d
before royalties.  With the longer than expected  turnaround at Syncrude and the
ongoing  ramp-up  of Long Lake,  we now expect to be towards  the low end of our
annual guidance.

Our future liquidity and ability to fund capital requirements  generally depends
upon operating cash flows, our existing  working  capital,  our unused committed
credit facilities,  and our ability to access debt and equity markets. Given the
long cycle  time of some of our  development  projects  and  volatile  commodity
prices,  it is not  unusual in any year for capital  expenditures  to exceed our
cash flow. Changes in commodity prices,  particularly crude oil as it represents
over  85% of our  production,  can  impact  our  operating  cash  flows.  We use
short-term  contracts  to sell  the  majority  of our  oil  and gas  production,
exposing  us to  short-term  price  movements.  A  US$1/bbl  change in WTI above
US$60/bbl is projected to increase or decrease our 2009 cash flow from operating
activities,  after cash taxes, by approximately $26 million for the remainder of
2009. Our exposure to a $0.01 change in the US to Canadian  dollar exchange rate
is  projected to increase or decrease  our 2009 cash flow by  approximately  $15
million  for the  remainder  of  2009.  While  commodity  prices  can  fluctuate
significantly in the short term, we believe that over the longer term, commodity
prices  will  increase  as a result  of  growth in world  demand  and  delays or
shortages in supply growth.  We believe that our existing  liquidity and balance
sheet capacity and capital investment  flexibility  provides us with the ability
to fund our obligations during periods of lower commodity prices.

We have incurred  approximately 55% of our 2009 planned capital  expenditures to
date and acquired the additional 15% working  interest in Long Lake.  During the
quarter,  our capital  has been  concentrated  on  developing  our Usan  project
offshore Nigeria,  appraising our Golden Eagle/Hobby area, advancing work on the
fourth  platform at Buzzard,  bringing our Ettrick and Longhorn  developments on
stream in the third quarter and on progressing  our Horn River shale gas play in
northeastern  British Columbia.  We expect to invest capital of approximately $1
billion during the remainder of the year on our development  projects  described
above.

During the first six months of 2009,  lower  commodity  prices  reduced our cash
flow from operating  activities  relative to the same period last year. Over the
same  period,  we have  invested  almost $1.5  billion in capital  projects  and
another $755 million to acquire an additional  15% in the Long Lake Project.  As
our capital expenditures  exceeded our cash flow from operating  activities,  we
drew upon our available liquidity.  We currently have approximately $2.0 billion
of cash  and  cash  equivalents  on hand  and as  well  as  significant  undrawn
committed credit facilities  available.  At June 30, 2009, we had unsecured term
credit  facilities of US$3.1 billion in place that are available  until 2012, of
which  US$2.3  billion  was  drawn  and  US$337  million  was  used  to  support
outstanding  letters  of  credit.  We also have  approximately  $496  million of
undrawn, uncommitted, unsecured credit facilities, of which $33 million was used
to support outstanding letters of credit. The average  length-to-maturity of our
public debt is approximately 15 years.

In June 2009, we filed a universal  base shelf  prospectus in the US and Canada,
allowing us to potentially  issue up to US$3.5 billion of debt,  equity or other
hybrid  securities,  should the need arise.  This  replaces our  existing  shelf
prospectus that expired during the quarter.

In the second quarter,  our board of directors declared a quarterly common share
dividend of $0.05 per share.

                                       46
<PAGE>

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 2008 Form 10-K.  There have been
no significant developments since year-end.

CONTINGENCIES

There are a number of lawsuits and claims pending,  the ultimate result 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 2008 Form 10-K.  There have been no significant  developments
since year-end.

NEW ACCOUNTING PRONOUNCEMENTS


CANADIAN PRONOUNCEMENTS
All  Canadian  publicly  accountable  enterprises  will  be  required  to  adopt
International  Financial  Reporting  Standards  (IFRS)  for  interim  and annual
reporting  purposes for fiscal years  beginning on or after  January 1, 2011. We
are currently assessing the impact of the convergence of Canadian GAAP with IFRS
on our results of operations, financial position and disclosures. A project team
has  been  set  up  to  manage  this   transition   and  to  ensure   successful
implementation within the required timeframe.  Details of our IFRS adoption plan
can be found in our 2008 Form 10-K. We will provide  additional  disclosures  of
key elements of our plan and progress of the project as the information  becomes
available.


US PRONOUNCEMENTS
In December 2008, the Financial Accounting Standards Board (FASB) issued FSP FAS
132(R)-1,  EMPLOYERS DISCLOSURES ABOUT POSTRETIREMENT  BENEFIT PLAN ASSETS. This
position provides guidance on disclosures about plan assets of a defined benefit
pension plan or other  postretirement  plans.  This  position is  effective  for
fiscal years ending  after  December 15, 2009.  We do not expect the adoption of
this  statement  to  materially  impact our results of  operations  or financial
position.

In June 2009, FASB issued Statement 167,  AMENDMENTS TO FASB  INTERPRETATION NO.
46 (R).  It  retains  the scope of  Interpretation  46(R) with the  addition  of
entities  previously   considered   qualifying   special-purpose   entities  and
eliminates  the previous  quantitative  approach for a  qualitative  analysis in
determining  whether the enterprise's  variable  interest or interests give it a
controlling  financial  interest in a variable  interest  entity.  The Statement
further amends  Interpretation 46(R) to require ongoing reassessments of whether
an  enterprise  is the primary  beneficiary  of a variable  interest  entity and
requires enhanced  disclosures  about an enterprise's  involvement in a variable
interest  entity.  The  Statement is effective at the beginning the first annual
reporting  period after November 15, 2009. We do not expect the adoption of this
statement to have a material  impact on our results of  operations  or financial
position.

EQUITY SECURITY REPURCHASES

During the quarter, we made no purchases of our own equity securities.


SUMMARY OF QUARTERLY RESULTS
<TABLE>
<CAPTION>
                                                         2007        |                2008                  |       2009
(Cdn$ millions, except per share amounts)           Sept       Dec   |   Mar      Jun       Sep       Dec   |      Mar     Jun
---------------------------------------------------------------------|--------------------------------------|------------------
<S>                                                <C>       <C>       <C>      <C>       <C>        <C>         <C>     <C>
Net Sales                                          1,446     1,598     1,870    2,071     2,213      1,270       1,048   1,200

Net Income (Loss)                                    403       194       630      380       886      (181)         135      20

Earnings (Loss) Per Common Share ($/share)
     Basic                                          0.77      0.37      1.19     0.72      1.68      (0.35)        0.26   0.04
     Diluted                                        0.75      0.36      1.17     0.70      1.66      (0.35)        0.26   0.04
                                                  ----------------------------------------------------- -----------------------
</TABLE>


                                       47
<PAGE>

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain  statements in this report,  including  those  appearing in MANAGEMENT'S
DISCUSSION  AND  ANALYSIS OF  FINANCIAL  CONDITION  AND  RESULTS OF  OPERATIONS,
constitute "forward-looking statements" (within the meaning of the United States
PRIVATE   SECURITIES   LITIGATION   REFORM   ACT  OF  1995,   as   amended)   or
"forward-looking   information"  (within  the  meaning  of  applicable  Canadian
securities    legislation).    Such   statements   or   information    (together
"forward-looking  statements") are generally identifiable by the forward-looking
terminology used such as "ANTICIPATE",  "BELIEVE",  "INTEND",  "PLAN", "EXPECT",
"ESTIMATE",  "BUDGET", "OUTLOOK", "FORECAST" or other similar words, and include
statements relating to or associated with individual wells, regions or projects.
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 Yemen operations;
o   future  capital   expenditures  and  their  allocation  to  exploration  and
    development activities;
o   future earnings;
o   future asset acquisitions or dispositions;
o   future sources of funding for our capital program;
o   future debt levels;
o   availability of committed credit facilities;
o   possible commerciality;
o   development plans or capacity expansions;
o   future ability to execute dispositions of assets or businesses;
o   future sources of liquidity, cash flows and their uses;
o   future drilling of new wells;
o   ultimate recoverability of current and long-term assets;
o   ultimate recoverability of reserves or resources;
o   expected finding and development costs;
o   expected operations costs;
o   future demand for chemical products;
o   estimates on a per share basis;
o   future foreign currency exchange rates;
o   future expenditures and future allowances relating to environmental matters;
o   dates by which certain areas will be developed, will come on-stream or reach
    expected operating capacity; and
o   changes in any of the foregoing.

Statements relating to "reserves" or "resources" are forward-looking statements,
as they involve the implied assessment, based on estimates and assumptions, that
the  reserves  and  resources  described  exist in the  quantities  predicted or
estimated, and can be profitably produced in the future.

The  forward-looking  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. Such factors include, among others:

o   market prices for oil and gas and chemical products;
o   our ability to explore, develop, produce and transport crude oil and natural
    gas to markets;
o   ultimate effectiveness of design modification to facilities;
o   the results of exploration and development drilling and related activities;
o   volatility in energy trading markets;
o   foreign-currency exchange rates;
o   economic  conditions  in the  countries  and  regions  in  which we carry on
    business;
o   governmental  actions  including  changes to taxes or royalties,  changes in
    environmental and other laws and regulations;
o   renegotiations of contracts;
o   results of litigation, arbitration or regulatory proceedings;
o   political uncertainty,  including actions by terrorists,  insurgent or other
    groups, or other armed conflict, including conflict between states; and
o   other factors, many of which are beyond our control.

These  risks,  uncertainties  and other  factors and their  possible  impact are
discussed  more  fully  in the  sections  titled  RISK  FACTORS  in  Item 1A and
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and in Item 7A of our

                                       48
<PAGE>

2008  Form  10-K.  The  impact  of any one  risk,  uncertainty  or  factor  on a
particular forward-looking statement is not determinable with certainty as these
factors are  interdependent,  and  management's  future  course of action  would
depend on an assessment of all information at that time.

Although  we  believe  that the  expectations  conveyed  by the  forward-looking
statements are reasonable based on information  available to us on the date such
forward-looking  statements  were made, no assurances  can be given as to future
results,  levels of activity  and  achievements.  Undue  reliance  should not be
placed on the statements  contained herein, which are made as of the date hereof
and, except as required by law, we undertake no obligation to update publicly or
revise any forward-looking  statements,  whether as a result of new information,
future events or otherwise. The forward-looking  statements contained herein are
expressly qualified by this cautionary statement.


ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are  exposed  to normal  market  risks  inherent  in the oil and gas,  energy
marketing   and   chemicals   business,    including   commodity   price   risk,
foreign-currency  exchange  rate risk,  interest  rate risk and credit risk.  We
recognize these risks and manage our operations to minimize our exposures to the
extent practical.

Most of our credit  exposures are with  counterparties  in the energy  industry,
including  integrated  oil  companies,  crude oil refiners and utilities and are
subject to normal industry credit risk.

At June 30, 2009:

    o   over 94% of our credit exposures were investment grade;
    o   approximately  94% of our  credit  exposures  were with  integrated  oil
        companies, crude oil refiners and marketers and large utilities; and
    o   only one counterparty  individually  made up more than 10% of our credit
        exposure.  This  counterparty  is a major  integrated oil company with a
        strong investment grade credit rating.

Further  information  presented on market risks can be found in Item 7A on pages
75 - 78 in our 2008 Form 10-K and have not materially changed since December 31,
2008.


ITEM 4.  CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

The Company's Chief Executive  Officer and Chief Financial Officer have designed
disclosure  controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)
under the SECURITIES  EXCHANGE ACT OF 1934), or caused such disclosure  controls
and procedures to be designed under their  supervision,  to ensure that material
information  relating to the Company is made known to them,  particularly during
the  period  in  which  this  report  is  prepared.   They  have  evaluated  the
effectiveness  of such  disclosure  controls and procedures as of the end of the
period covered by this report ("Evaluation  Date").  Based upon that evaluation,
the Chief Executive  Officer and Chief Financial  Officer  concluded that, as of
the  Evaluation  Date,  the Company's  disclosure  controls and  procedures  are
effective  (i) to ensure  that  information  required to be  disclosed  by us in
reports  that the Company  files or submits  under the Exchange Act is recorded,
processed,  summarized  and reported  within the time  periods  specified in the
Securities  and  Exchange  Commission  rules and forms;  and (ii) to ensure that
information  required to be disclosed  in the reports that the Company  files or
submits  under  the  Exchange  Act  is  accumulated  and   communicated  to  our
management,  including the Company's Chief Executive Officer and Chief Financial
Officer, to allow timely decisions regarding required disclosures.

The  Company's  management,  including  its Chief  Executive  Officer  and Chief
Financial Officer,  does not expect that the Company's  disclosure  controls and
procedures or internal  controls will prevent all possible error and fraud.  The
Company's  disclosure controls and procedures are, however,  designed to provide
reasonable  assurance of achieving  their  objectives,  and the Company's  Chief
Executive  Officer and Chief Financial Officer have concluded that the Company's
financial  controls and  procedures are effective at that  reasonable  assurance
level.


CHANGES IN INTERNAL CONTROLS

We have  continually  had in place  systems  relating to internal  control  over
financial  reporting.  There has not been any change in the  Company's  internal
control over  financial  reporting  during the first six months of 2009 that has
materially affected, or is reasonably likely to materially affect, the Company's
internal control over financial reporting.


                                       49
<PAGE>

                                     PART II


ITEM 1.  LEGAL PROCEEDINGS

Information  in  response  to this item is included in Part I, Item 1 in Note 17
"Commitments,  Contingencies  and  Guarantees"  and is incorporated by reference
into Part II of this Quarterly Report on Form 10-Q.


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

Our Annual General Meeting of Shareowners  (the "Meeting") was held on April 28,
2009.  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 twelve director  nominees proposed by management were elected by
a vote, conducted by ballot as follows:

<TABLE>
<CAPTION>

     Director                                    For         %        Withheld        %
     -----------------------------------------------------------------------------------
     <S>                                  <C>            <C>         <C>           <C>
     William B. Berry                     323,405,852    97.43       8,546,464     2.57
     Robert G. Bertram                    328,579,673    98.98       3,372,643     1.02
     Dennis G. Flanagan                   328,542,912    98.97       3,409,404     1.03
     S. Barry Jackson                     295,817,201    89.11      36,135,115    10.89
     Kevin J. Jenkins                     295,664,095    89.07      36,288,221    10.93
     A. Anne McLellan, P.C.               267,038,872    80.44      64,913,444    19.56
     Eric P. Newell, O.C.                 328,524,629    98.97       3,427,687     1.03
     Thomas C. O'Neill                    287,426,933    86.59      44,525,383    13.41
     Marvin F. Romanow                    328,470,752    98.95       3,481,564     1.05
     Francis M. Saville, Q.C.             262,005,721    78.93      69,946,595    21.07
     John M. Willson                      295,702,503    89.08      36,249,813    10.92
     Victor J. Zaleschuk                  328,427,870    98.94       3,524,446     1.06
</TABLE>

(b)  The appointment of Deloitte & Touche LLP, Chartered  Accountants,  to serve
     as the  independent  auditors  for 2009 was  approved  by a show of  hands.
     Proxies of  330,644,003  (99.66%) for and 1,133,157  (0.34%)  withheld were
     received.


ITEM 6.  EXHIBITS

10.57    Termination  of  Employment  and  Retirement   Agreement   between  the
         Registrant and Roger D. Thomas dated May 12, 2009.

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 21, 2009.

                                    NEXEN INC.


                                    /s/ Marvin F. Romanow
                                    -------------------------
                                    Marvin F. Romanow
                                    President and Chief Executive Officer
                                    (Principal Executive Officer)


                                    /s/ Brendon T. Muller
                                    -------------------------
                                    Brendon T. Muller
                                    Controller
                                    (Principal Accounting Officer)



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