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, 2010

|_|  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, 2010, there were 524,565,491 common shares issued and outstanding.

                                       1

<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) ..................33
       Item 3.   Quantitative and Qualitative Disclosures about Market Risk ..56
       Item 4.   Controls and Procedures .....................................56
PART II          OTHER INFORMATION
       Item 1.   Legal Proceedings ...........................................57
       Item 1A.  Risk Factors.................................................57
       Item 6.   Exhibits ....................................................58

This report  should be read in  conjunction  with our 2009 Annual Report on Form
10-K (2009 Form 10-K) and with our  current  reports on Forms 10-Q and 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
97 of our 2009 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 ALSO PRESENTED.

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

/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
                                            Gj    = Gigajoules

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 per 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, 2010, the noon-day exchange rate was US$0.9429 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, 2010 and 2009......................4

Unaudited Consolidated Balance Sheet
as at June 30, 2010 and December 31, 2009......................................5

Unaudited Consolidated Statement of Cash Flows
for the Three and Six Months Ended June 30, 2010 and 2009......................6

Unaudited Consolidated Statement of Equity
for the Three and Six Months Ended June 30, 2010 and 2009......................7

Unaudited Consolidated Statement of Comprehensive Income
for the Three and Six Months Ended June 30, 2010 and 2009......................8

Notes to Unaudited Consolidated Financial Statements...........................9

                                       3

<PAGE>


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

                                                                             Three Months                  Six Months
                                                                             Ended June 30                Ended June 30
(Cdn$ millions, except per share amounts)                                  2010           2009          2010         2009
---------------------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>            <C>           <C>          <C>
REVENUES AND OTHER INCOME
     Net Sales                                                            1,399          1,138         2,831        2,142
     Marketing and Other (Note 14)                                          164             82           315          339
                                                                   --------------------------------------------------------
                                                                          1,563          1,220         3,146        2,481
                                                                   --------------------------------------------------------
EXPENSES
     Operating                                                              399            295           798          575
     Depreciation, Depletion, Amortization and Impairment                   391            381           757          758
     Transportation and Other                                               159            229           359          426
     General and Administrative                                              70            161           184          255
     Exploration                                                             50             77           143          130
     Interest (Note 9)                                                       77             74           157          142
                                                                   --------------------------------------------------------
                                                                          1,146          1,217         2,398        2,286
                                                                   --------------------------------------------------------

INCOME FROM CONTINUING OPERATIONS BEFORE PROVISION
     FOR INCOME TAXES                                                       417              3           748          195
                                                                   --------------------------------------------------------

PROVISION FOR (RECOVERY OF) INCOME TAXES
     Current                                                                264            206           523          324
     Future                                                                 (84)          (228)         (189)        (309)
                                                                   --------------------------------------------------------
                                                                            180            (22)          334           15
                                                                   --------------------------------------------------------

NET INCOME FROM CONTINUING OPERATIONS BEFORE NON-
     CONTROLLING INTERESTS                                                  237             25           414          180
     Less: Net Income (Loss) Attributable to Canexus
       Non-Controlling Interests                                             (5)             2             -            5
                                                                   --------------------------------------------------------

NET INCOME FROM CONTINUING OPERATIONS ATTRIBUTABLE
     TO NEXEN INC.                                                          242             23           414          175
     Net Income (Loss) from Discontinued
       Operations (Note 15)                                                  13             (3)           26          (20)
                                                                   --------------------------------------------------------

NET INCOME ATTRIBUTABLE TO NEXEN INC.                                       255             20           440          155
                                                                   ========================================================

EARNINGS PER COMMON SHARE FROM
     CONTINUING OPERATIONS ($/share)
     (Note 16)
     Basic                                                                 0.46           0.05          0.79          0.33
                                                                   ========================================================

     Diluted                                                               0.46           0.05          0.79          0.33
                                                                   ========================================================

Earnings Per Common Share ($/share) (Note 16)
     Basic                                                                 0.49           0.04          0.84          0.30
                                                                   ========================================================

     Diluted                                                               0.49           0.04          0.84          0.30
                                                                   ========================================================
</TABLE>

SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.


                                       4
<PAGE>


NEXEN INC.
UNAUDITED CONSOLIDATED BALANCE SHEET

<TABLE>
<CAPTION>
                                                                                                     June 30      December 31
(Cdn$ millions, except share amounts)                                                                   2010             2009
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                   <C>              <C>
ASSETS
   CURRENT ASSETS
      Cash and Cash Equivalents                                                                          970            1,700
      Restricted Cash                                                                                    113              198
      Accounts Receivable (Note 2)                                                                     2,675            2,788
      Inventories and Supplies (Note 3)                                                                  621              680
      Other                                                                                              106              185
                                                                                                ------------------------------
         Total Current Assets                                                                          4,485            5,551
                                                                                                ------------------------------

   PROPERTY, PLANT AND EQUIPMENT
      Net of Accumulated Depreciation, Depletion, Amortization and
         Impairment of $10,129 (December 31, 2009 - $10,807)                                          15,755           15,492
   GOODWILL                                                                                              343              339
   FUTURE INCOME TAX ASSETS                                                                            1,340            1,148
   DEFERRED CHARGES AND OTHER ASSETS (NOTE 5)                                                            289              370
   ASSETS HELD FOR SALE (NOTE 15)                                                                        303                -
                                                                                                ------------------------------
TOTAL ASSETS                                                                                          22,515           22,900
                                                                                                ==============================

LIABILITIES
   CURRENT LIABILITIES
      Short-Term Borrowings (Note 9)                                                                     158                -
      Accounts Payable and Accrued Liabilities (Note 8)                                                3,101            3,038
      Accrued Interest Payable                                                                            89               89
      Dividends Payable                                                                                   26               26
                                                                                                ------------------------------
         Total Current Liabilities                                                                     3,374            3,153
                                                                                                ------------------------------

   LONG-TERM DEBT (Note 9)                                                                             6,283            7,251
   FUTURE INCOME TAX LIABILITIES                                                                       2,891            2,811
   ASSET RETIREMENT OBLIGATIONS (Note 11)                                                                859            1,018
   DEFERRED CREDITS AND OTHER LIABILITIES (Note 12)                                                      879            1,021
   LIABILITIES ASSOCIATED WITH ASSETS HELD FOR SALE (Note 15)                                            149                -

EQUITY
   Nexen Inc. Shareholders' Equity
      Common Shares, no par value
         Authorized:   Unlimited
         Outstanding:  2010 - 524,565,491 shares
                       2009 - 522,915,843 shares                                                       1,088            1,049
      Contributed Surplus                                                                                  -                1
      Retained Earnings                                                                                7,110            6,722
      Accumulated Other Comprehensive Loss                                                              (189)            (190)
                                                                                                ------------------------------
   Total Nexen Inc. Shareholders' Equity                                                               8,009            7,582
      Canexus Non-Controlling Interests                                                                   71               64
                                                                                                ------------------------------
   TOTAL EQUITY                                                                                        8,080            7,646
   COMMITMENTS, CONTINGENCIES AND GUARANTEES (NOTE 17)
                                                                                                ------------------------------
TOTAL LIABILITIES AND EQUITY                                                                          22,515           22,900
                                                                                                ==============================
</TABLE>

SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.


                                       5
<PAGE>



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

                                                                             Three Months                  Six Months
                                                                             Ended June 30                Ended June 30
(Cdn$ millions)                                                            2010           2009          2010         2009
---------------------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>             <C>        <C>           <C>
OPERATING ACTIVITIES
   Net Income from Continuing Operations                                    237             25           414          180
   Net Income (Loss) from Discontinued Operations                            13             (3)           26          (20)
   Charges and Credits to Income not Involving
       Cash (Note 18)                                                       270            394           535          713
   Exploration Expense                                                       50             77           143          130
   Changes in Non-Cash Working Capital (Note 18)                            (58)          (340)          198           80
   Other                                                                     (2)           (44)           (8)        (185)
                                                                   --------------------------------------------------------
                                                                            510            109         1,308          898

FINANCING ACTIVITIES
   Proceeds from Short-Term Borrowings                                      156              -           156            -
   Proceeds from (Repayment of) Term Credit
       Facilities, Net                                                   (1,077)           632        (1,077)       1,643
   Proceeds from Canexus Term Credit Facilities, Net                         46             42            68           52
   Dividends Paid on Common Shares                                          (26)           (26)          (52)         (52)
   Distributions Paid to Canexus Non-Controlling Interests                   (2)            (4)           (7)          (7)
   Issue of Common Shares and Exercise of Tandem
       Options for Shares                                                    10              7            35           30
   Other                                                                    (14)             -           (13)          (1)
                                                                   --------------------------------------------------------
                                                                           (907)           651          (890)       1,665

INVESTING ACTIVITIES
   Capital Expenditures
       Exploration and Development                                         (747)          (631)       (1,239)      (1,335)
       Proved Property Acquisitions                                           -              -             -         (755)
       Energy Marketing, Chemicals, Corporate and Other                     (70)           (84)         (134)        (129)
   Proceeds on Disposition of Assets                                         81              1            96           15
   Changes in Non-Cash Working Capital (Note 18)                            (13)           (74)           75          (55)
   Changes in Restricted Cash                                                68             67            83         (247)
   Other                                                                     (4)             1            (7)          (1)
                                                                   --------------------------------------------------------
                                                                           (685)          (720)       (1,126)      (2,507)

EFFECT OF EXCHANGE RATE CHANGES ON CASH AND
       CASH EQUIVALENTS                                                      55           (120)          (22)         (85)
                                                                   --------------------------------------------------------

DECREASE IN CASH AND CASH EQUIVALENTS                                    (1,027)           (80)         (730)         (29)

CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD                           1,997          2,054         1,700        2,003
                                                                   --------------------------------------------------------

CASH AND CASH EQUIVALENTS - END OF PERIOD (1)                               970          1,974           970        1,974
                                                                   ============== =========================================
</TABLE>

(1)  Cash and cash  equivalents at June 30, 2010 consist of cash of $237 million
     and  short-term  investments  of $733 million (June 30, 2009 - cash of $227
     million and short-term investments of $1,747 million).


SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.


                                       6
<PAGE>


NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF EQUITY
FOR THE THREE AND SIX MONTHS ENDED JUNE 30

<TABLE>
<CAPTION>
                                                                               Three Months                 Six Months
                                                                              Ended June 30                Ended June 30
(Cdn$ millions)                                                            2010           2009          2010          2009
----------------------------------------------------------------------------------------------------------------------------

<S>                                                                      <C>            <C>           <C>           <C>
COMMON SHARES, Beginning of Period                                        1,076          1,004         1,049           981
      Issue of Common Shares                                                  8              6            32            29
      Exercise of Tandem Options for Shares                                   2              1             3             1
      Accrued Liability Relating to Tandem Options
         Exercised for Common Shares                                          2              -             4             -
                                                                   ---------------------------------------------------------
   Balance at End of Period                                               1,088          1,011         1,088         1,011
                                                                   =========================================================

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

RETAINED EARNINGS, Beginning of Period                                    6,881          6,399         6,722         6,290
      Net Income Attributable to Nexen Inc.                                 255             20           440           155
      Dividends Paid on Common Shares (Note 13)                             (26)           (26)          (52)          (52)
                                                                   ---------------------------------------------------------
   Balance at End of Period                                               7,110          6,393         7,110         6,393
                                                                   =========================================================

ACCUMULATED OTHER COMPREHENSIVE LOSS,
   Beginning of Period                                                     (201)          (128)         (190)         (134)
      Other Comprehensive Income (Loss) Attributable
         to Nexen Inc.                                                       12            (29)            1           (23)
                                                                   ---------------------------------------------------------
   Balance at End of Period (1)                                            (189)          (157)         (189)         (157)
                                                                   =========================================================
(1) Comprised of unrealized foreign currency translation adjustment.

CANEXUS NON-CONTROLLING INTERESTS,
   Beginning of Period                                                       71             52            64            52
      Net Income Attributable to Non-Controlling Interests                   (6)             6             -             9
      Distributions Paid to Non-Controlling Interests                        (6)            (5)          (10)           (9)
      Issue of Partnership Units to Non-Controlling
         Interests                                                           12              1            17             2
                                                                   ---------------------------------------------------------
   Balance at End of Period                                                  71             54            71            54
                                                                   =========================================================
</TABLE>

SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.


                                       7
<PAGE>


NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
<TABLE>
<CAPTION>
                                                                              Three Months                  Six Months
                                                                              Ended June 30                Ended June 30
(Cdn$ millions)                                                            2010           2009          2010          2009
---------------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>             <C>           <C>           <C>
NET INCOME ATTRIBUTABLE TO NEXEN INC.                                       255             20           440           155
   Other Comprehensive Income (Loss),
      Net of Income Taxes:
          Foreign Currency Translation Adjustment
            Net Gains (Losses) on Investment in
             Self-Sustaining Foreign Operations                             209           (459)           62          (285)
            Net Gains (Losses) on Foreign-Denominated
              Debt Hedges of Self-Sustaining Foreign
              Operations (1)                                               (197)           430           (61)          262
                                                                   --------------------------------------------------------
      Other Comprehensive Income (Loss) Attributable
          to Nexen Inc.                                                      12            (29)            1           (23)
                                                                   --------------------------------------------------------
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE
   TO NEXEN INC.                                                            267             (9)          441           132
                                                                   ========================================================
</TABLE>

(1)  Net of income tax  recovery for the three months ended June 30, 2010 of $28
     million (2009 - $62 million expense) and net of income tax recovery for the
     six months ended June 30, 2010 of $8 million (2009 - $38 million expense).

SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.


                                       8
<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, 2010 and December 31,
2009 and the results of our  operations and our cash flows for the three and six
months ended June 30, 2010 and 2009.

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, 2010 are
not  necessarily  indicative  of the results of  operations  or cash flows to be
expected for the year ending  December 31, 2010. As at July 14, 2010,  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 2009 Form
10-K. The  accounting  policies we follow are described in Note 1 of the Audited
Consolidated Financial Statements included in our 2009 Form 10-K.


CHANGES IN ACCOUNTING POLICIES

OIL AND GAS RESERVE ESTIMATES
In early 2010, the Financial  Accounting Standards Board issued guidance for OIL
AND GAS RESERVE  ESTIMATION AND  DISCLOSURE,  which is effective for years ended
December 31, 2009. The guidance  expands the definition of oil and gas producing
activities to: i) include  unconventional  sources such as oil sands; ii) change
the price  used in  reserve  estimation  from the  year-end  price to the simple
average of the first-day-of-the-month price for the previous 12 months, and iii)
require  disclosures  for geographic  areas that represent 15% or more of proved
reserves.

We  follow  the  successful  efforts  method of  accounting  for our oil and gas
activities,  which use the estimated  proved reserves we believe are recoverable
from our oil and gas properties.  Specifically,  reserves  estimates are used to
calculate our unit-of-production  depletion rates and to assess, when necessary,
our oil and gas assets for impairment.  Adoption of these amendments changed our
estimate of reserves  used to calculate  depletion  in 2010.  As a result of the
amendments,  depletion  expense for continuing  operations for the three and six
months ended June 30, 2010 increased by $11 million and $24 million,  net income
from continuing operations decreased by $7 million and $16 million, and earnings
per common share decreased by $0.02/share and $0.04/share, respectively.


                                        9
<PAGE>

2.   ACCOUNTS RECEIVABLE
<TABLE>
<CAPTION>
                                                                                            June 30        December 31
                                                                                               2010               2009
-----------------------------------------------------------------------------------------------------------------------
<S>                                                                                         <C>            <C>
Trade
     Energy Marketing                                                                         1,515              1,410
     Energy Marketing Derivative Contracts (Note 6)                                             260                466
     Oil and Gas                                                                                793                823
     Chemicals and Other                                                                         49                 44
                                                                                ---------------------------------------
                                                                                              2,617              2,743
Non-Trade                                                                                       111                 99
                                                                                ---------------------------------------
                                                                                              2,728              2,842
Allowance for Doubtful Receivables                                                              (53)               (54)
                                                                                ---------------------------------------
Total                                                                                         2,675              2,788
                                                                                =======================================

3.   INVENTORIES AND SUPPLIES
                                                                                            June 30        December 31
                                                                                               2010               2009
-----------------------------------------------------------------------------------------------------------------------
Finished Products
     Energy Marketing                                                                           473                548
     Oil and Gas                                                                                 32                 25
     Chemicals and Other                                                                         10                 12
                                                                                ---------------------------------------
                                                                                                515                585
Work in Process                                                                                   7                  7
Field Supplies                                                                                   99                 88
                                                                                ---------------------------------------
Total                                                                                           621                680
                                                                                ==================== ==================
</TABLE>

4.   SUSPENDED EXPLORATION WELL COSTS

The  following  table shows the changes in  capitalized  exploratory  well costs
during the six months ended June 30, 2010 and the year ended  December 31, 2009,
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         Year Ended
                                                                                      Ended June 30        December 31
                                                                                               2010               2009
-----------------------------------------------------------------------------------------------------------------------
<S>                                                                                <C>                     <C>
Beginning of Period                                                                             794                518
     Exploratory Well Costs Capitalized Pending the Determination of
       Proved Reserves                                                                          206                396
     Capitalized Exploratory Well Costs Charged to Expense                                       (2)               (56)
     Transfers to Wells, Facilities and Equipment Based on
       Determination of Proved Reserves                                                          (1)               (21)
     Effects of Foreign Exchange Rate Changes                                                     7                (43)
                                                                                ---------------------------------------
End of Period                                                                                 1,004                794
                                                                                =======================================
</TABLE>



                                       10
<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 as at June 30, 2010.

<TABLE>
<CAPTION>
                                                       United                          United
Aging of Suspended Exploration Wells                  Kingdom          Canada          States        Nigeria            Total
------------------------------------------------------------------------------------------------------------------------------
<S>                                                   <C>              <C>             <C>           <C>                <C>
Less than 1 year                                           60             162              89              13             324
1-3 years                                                 136             348              44               -             528
4-5 years                                                  57               -              74               -             131
Greater than 5 years                                        -               -               -              21              21
                                                ------------------------------------------------------------------------------
Total                                                     253             510             207              34           1,004
                                                ==============================================================================
Number of Wells Capitalized for Greater than
   One Year                                                 8              13               2               1              24
                                                ==============================================================================
</TABLE>

As at June 30, 2010, we have  exploratory  costs that have been  capitalized for
more than one year  relating to our shale gas  exploratory  activities in Canada
($348  million),  interests in eight  exploratory  blocks in the North Sea ($193
million),  two exploratory blocks in the Gulf of Mexico ($118 million),  and our
interest in an  exploratory  block offshore  Nigeria ($21 million).  These costs
relate to projects with successful  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 otherwise assess commercial viability.

5.   DEFERRED CHARGES AND OTHER ASSETS

<TABLE>
<CAPTION>
                                                                                               June 30            December 31
                                                                                                  2010                   2009
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                            <C>                <C>
Long-Term Energy Marketing Derivative Contracts (Note 6)                                           160                    225
Defined Benefit Pension Assets                                                                      53                     60
Long-Term Capital Prepayments                                                                       23                     27
Other                                                                                               53                     58
                                                                                   -------------------------------------------
Total                                                                                              289                    370
                                                                                   ===========================================
</TABLE>

6.   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 because 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 in the following  section  details our derivatives and fair values as at
June 30, 2010. 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.
Related amounts posted as margin for  exchange-traded  positions are recorded in
restricted cash.

We carry our long-term debt at amortized cost using the effective  interest rate
method.  At June 30, 2010,  the estimated  fair value of our long-term  debt was
$6,736 million  (December 31, 2009 - $7,594 million) as compared to the carrying
value of $6,283 million (December 31, 2009 - $7,251 million).  The fair value of
long-term  debt is  estimated  based on prices  provided  by quoted  markets and
third-party brokers.


                                       11
<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
                                                                                       2010               2009
---------------------------------------------------------------------------------------------------------------
  <S>                                                                               <C>            <C>
  Commodity Contracts                                                                   260                463
  Foreign Exchange Contracts                                                              -                  3
                                                                        ---------------------------------------
   Accounts Receivable (Note 2)                                                         260                466
                                                                        ---------------------------------------

  Commodity Contracts                                                                   160                225
                                                                        ---------------------------------------
   Deferred Charges and Other Assets (Note 5) (1)                                       160                225
                                                                        ---------------------------------------

Total Trading Derivative Assets                                                         420                691
                                                                        =======================================

  Commodity Contracts                                                                   202                410
  Foreign Exchange Contracts                                                              6                 46
                                                                        ---------------------------------------
   Accounts Payable and Accrued Liabilities (Note 8)                                    208                456
                                                                        ---------------------------------------

  Commodity Contracts                                                                   156                212
                                                                        ---------------------------------------
   Deferred Credits and Other Liabilities (Note 12) (1)                                 156                212
                                                                        ---------------------------------------

Total Trading Derivative Liabilities                                                    364                668
                                                                        =======================================

Total Net Trading Derivative Contracts                                                   56                 23
                                                                        =======================================

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

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

                                                                                    June 30        December 31
                                                                                       2010               2009
---------------------------------------------------------------------------------------------------------------
Current Trading Assets                                                                1,687              2,625
Non-Current Trading Assets                                                              511                716
                                                                        ---------------------------------------
  Total Trading Derivative Assets                                                     2,198              3,341
                                                                        =======================================

Current Trading Liabilities                                                           1,635              2,615
Non-Current Trading Liabilities                                                         507                703
                                                                        ---------------------------------------
  Total Trading Derivative Liabilities                                                2,142              3,318
                                                                        =======================================

                                                                        ---------------------------------------
Total Net Trading Derivative Contracts                                                   56                 23
                                                                        =======================================
</TABLE>


                                       12
<PAGE>

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, 2010,  the  following
trading revenues were recognized in marketing and other income:

<TABLE>
<CAPTION>
                                                                               Three Months         Six Months
                                                                              Ended June 30      Ended June 30
                                                                                       2010               2010
---------------------------------------------------------------------------------------------------------------
<S>                                                                           <C>                <C>
Commodity                                                                               113                204
Foreign Exchange                                                                         (1)                (6)
                                                                        ---------------------------------------
  Marketing Revenue                                                                     112                198
                                                                        =======================================
</TABLE>

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  economic  hedging and
trading purposes.  The absolute notional volumes  associated with our derivative
instrument transactions for the three and six months ended June 30, 2010, are as
follows:

<TABLE>
<CAPTION>
                                                                               Three Months         Six Months
                                                                              Ended June 30      Ended June 30
                                                                                       2010               2010
---------------------------------------------------------------------------------------------------------------
<S>                                                 <C>                       <C>                <C>
Natural Gas                                                 bcf/d                       5.5                9.1
Crude Oil                                                mmbbls/d                       3.6                3.4
Power                                                       GWh/d                       0.5                0.9
Foreign Exchange                                     US$ millions                       834              1,621
Foreign Exchange                                    Euro millions                         -                 53
                                                                        ---------------------------------------
</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
                                                                                       2010               2009
---------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>            <C>
Accounts Receivable                                                                       2                 13
Deferred Charges and Other Assets (1)                                                     -                  4
                                                                        ---------------------------------------
  Total Non-Trading Derivative Assets                                                     2                 17
                                                                        =======================================

Accounts Payable and Accrued Liabilities                                                 13                 26
                                                                        ---------------------------------------
  Total Non-Trading Derivative Liabilities                                               13                 26
                                                                        =======================================

  Total Net Non-Trading Derivative Assets (2)                                           (11)                (9)
                                                                        =======================================

(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.
</TABLE>


                                       13
<PAGE>

CRUDE OIL PUT OPTIONS
In 2009,  we  purchased  put  options  on 90,000  bbls/d  of our 2010  crude oil
production  for $39  million.  These  options  establish  a WTI  floor  price of
US$50/bbl on these volumes and provide a base level of price protection  without
limiting our upside to higher prices.  Options on 60,000 bbls/d settle  monthly,
while the remaining options settle annually.  These options are recorded at fair
value  throughout  their term. As a result,  changes in forward crude oil prices
create gains or losses on these options at each period end.  Lower forward crude
oil  prices  at  June  30,  2010  compared  to the end of the  previous  quarter
increased the fair value of the options to approximately $2 million.

<TABLE>
<CAPTION>
                                                                                                  Change in Fair Value
                                                                                             ---------------------------------
                                                                                                Three Months       Six Months
                                                                                                       Ended            Ended
                                              Notional                Average       Fair            June 30,         June 30,
                                              Volumes       Term    Floor Price    Value                2010             2010
------------------------------------------------------------------------------------------------------------------------------
                                              (bbls/d)               (US$/bbl)
<S>                                           <C>           <C>     <C>            <C>          <C>                <C>
WTI Crude Oil Put Options (monthly)            60,000       2010         50            2                   1             (11)
WTI Crude Oil Put Options (annual)             30,000       2010         50            -                   -              (4)
                                                                                   -------------------------------------------
                                                                                       2                   1             (15)
                                                                                   ===========================================
</TABLE>

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 current based on their  anticipated
settlement  date.  Any change in fair value is included in  marketing  and other
income.

<TABLE>
<CAPTION>
                                                                                                   Change in Fair Value
                                                                                             ---------------------------------
                                                                                                 Three Months      Six Months
                                                                                                        Ended           Ended
                                              Notional                 Average        Fair           June 30,        June 30,
                                              Volumes       Term     Floor Price     Value               2010            2010
------------------------------------------------------------------------------------------------------------------------------
                                               (Gj/d)                  ($/Gj)
<S>                                            <C>          <C>      <C>             <C>         <C>               <C>
Fixed-Price Natural Gas Contracts              15,514       2010        2.28           (3)                  -             (4)
Natural Gas Swaps                              15,514       2010        7.60          (10)                  -              4
                                                                                   -------------------------------------------
                                                                                      (13)                  -              -
                                                                                   ===========================================
</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, 2009. The following
table  includes  our  derivatives  carried  at fair  value for our  trading  and
non-trading activities as at June 30, 2010. 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 at June 30, 2010                                          Level 1       Level 2       Level 3         Total
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>           <C>           <C>             <C>
  Commodity Contracts                                                         (85)          123            24            62
  Foreign Exchange Contracts                                                    -            (6)            -            (6)
                                                                     -------------------------------------------------------
Trading Derivatives                                                           (85)          117            24            56
Non-Trading Derivatives                                                         -           (11)            -           (11)
                                                                     -------------------------------------------------------
Total                                                                         (85)          106            24            45
                                                                     =======================================================
</TABLE>


                                       14
<PAGE>

A reconciliation  of changes in the fair value of our derivatives  classified as
Level 3 for the six months ended June 30, 2010 is provided below:

<TABLE>
<CAPTION>
                                                                                   Level 3
-------------------------------------------------------------------------------------------
<S>                                                                                <C>
Beginning of Period                                                                     42
  Realized and Unrealized Gains (Losses)                                                (5)
  Purchases                                                                              -
  Settlements                                                                          (13)
  Transfers Into Level 3                                                                 -
  Transfers Out of Level 3                                                               -
                                                                              -------------
End of Period                                                                           24
                                                                              =============

Unsettled gains relating to instruments still held as of June 30, 2010                  (5)
                                                                              =============
</TABLE>

Items 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. Fair values of instruments in Level 3
are determined using broker quotes,  pricing  services and  internally-developed
inputs. We performed a sensitivity analysis of inputs used to calculate the fair
value of Level 3 instruments. Using reasonably possible alternative assumptions,
the fair  value of Level 3  instruments  at June 30,  2010  would  change by $12
million (December 31, 2009 - $12 million).

7.   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  currency rates and interest rates,  which could 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,  given that the majority of our debt is fixed
rate.

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 actively manage these risks by using derivative contracts
such as commodity put options.

Our energy marketing  business is focused on providing services to our customers
and suppliers to meet their energy commodity needs. We market and trade physical
energy  commodities  in  selected  regions  of the world,  including  crude oil,
natural gas, electricity and other commodities. We do 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.

                                       15
<PAGE>

In order to manage the commodity and foreign exchange price risks that come from
this  physical  business,   we  use  financial  derivative  contracts  including
energy-related futures, forwards, swaps and options, as well as foreign currency
swaps or forwards.

Our risk management  activities include prescribed capital limits and the use of
tools  such as  Value-at-Risk  (VaR)  and  stress  testing  consistent  with the
methodology used at December 31, 2009. Our period end, high, low and average VaR
amounts  for the three and six  months  ended  June 30,  2010 are as follows:

<TABLE>
<CAPTION>
                                                                       Three Months                Six Months
                                                                       Ended June 30              Ended June 30
Value-at-Risk                                                        2010          2009         2010          2009
-------------------------------------------------------------------------------------------------------------------
<S>                                                                  <C>           <C>          <C>           <C>
Period End                                                              8            15             8           15
High                                                                   15            19            15           24
Low                                                                     7            13             7           13
Average                                                                12            15            12           17
                                                             ------------------------------------------------------
</TABLE>

If a market shock  occurred as 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 abnormal 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 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.  Cash  inflows  generated  by  our  foreign
operations and borrowings on our US-dollar debt facilities 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 net cash flows.

We designate  most of our US-dollar  borrowings as a hedge against our US-dollar
net investment in self-sustaining foreign operations. The foreign exchange gains
or losses related to the effective portion of 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, 2010 and December 31, 2009 are as follows:

<TABLE>
<CAPTION>
                                                                                  June 30            December 31
(US$ millions)                                                                       2010                   2009
-----------------------------------------------------------------------------------------------------------------
<S>                                                                               <C>                <C>
Net Investment in Self-Sustaining Foreign Operations                                4,513                  4,492
Designated US-Dollar Debt                                                           4,513                  4,492
                                                                        -----------------------------------------
</TABLE>

For the three and six months ended June 30, 2010, the ineffective portion of our
US-dollar  debt  resulted in a net foreign  exchange loss of $39 million and $18
million,  respectively ($34 million and $16 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  $45 million,  net of
income tax, and would  increase or decrease our net income by  approximately  $5
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.

                                       16
<PAGE>

(b)  CREDIT RISK

Credit risk affects our oil, gas and chemicals  operations,  and our trading and
non-trading derivative 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,
refiners  and  utilities,  and are  subject  to  normal  industry  credit  risk.
Approximately  81% 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, 2009.

At June 30, 2010, only two counterparties  individually made up more than 10% of
our credit  exposure.  These  counterparties  are major integrated oil companies
with a strong  investment grade credit rating.  One other  counterparty  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                                                                          2010               2009
--------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>            <C>
A or higher                                                                            65%                67%
BBB                                                                                    26%                26%
Non-Investment Grade                                                                    9%                 7%
                                                                        --------------------------------------
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 $53
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, 2010 includes $1 million of cash
and $302 million of letters of credit. The cash received is 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 fall due. We require liquidity  specifically to fund capital
requirements, satisfy financial obligations as they come 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,  2010,  we had  approximately  $3.8  billion  of cash and  available
committed lines of credit.  This includes  approximately  $1 billion of cash and
cash equivalents on hand and undrawn term credit facilities of $2.8 billion,  of
which $336  million was  supporting  letters of credit at June 30,  2010.  These
facilities  are available  until 2014 unless  extended.  We also have about $467
million of uncommitted  credit  facilities,  of which $158 million was drawn and
$24 million was supporting letters of credit at June 30, 2010.

The following  table details the contractual  maturities for our  non-derivative
financial  liabilities,  including both the principal and interest cash flows at
June 30, 2010:

<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                         6,383              -             360            1,304           4,719
Interest on Long-Term Debt (1)         7,970            364             728              675           6,203
                                  ---------------------------------------------------------------------------
Total                                 14,353            364           1,088            1,979          10,922
                                  ===========================================================================
</TABLE>

(1)  Excludes  interest  on  term  credit  facilities  of $477  million  (US$450
     million)  and  Canexus  term  credit  facilities  of $307  million  (US$289
     million) as the amounts drawn on the facilities fluctuate. Based on amounts
     drawn at June 30, 2010 and existing  variable  interest  rates, we would be
     required to pay $28 million per year until the  outstanding  amounts on the
     term credit facilities are repaid.

                                       17
<PAGE>

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 6)             364            208             139             17                -
Non-Trading Derivatives (Note 6)          13             13               -              -                -
                                        ---------------------------------------------------------------------
Total                                    377            221             139             17                -
                                        =====================================================================
</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
ratings to  non-investment  grade.  Based on  contracts  in place and  commodity
prices at June 30, 2010,  we could be required to post  collateral of up to $785
million if we were downgraded to  non-investment  grade.  These  obligations are
reflected on our balance sheet. The posting of collateral secures the payment of
such amounts.  In the event of a ratings downgrade,  we have trading inventories
and  receivables  that  can be  quickly  monetized  as  well as  undrawn  credit
facilities.

At June 30, 2010, collateral posted with counterparties includes $133 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 $113 million  (December  31, 2009 - $198  million),  which have been
included in restricted cash.

8.   ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
<TABLE>
<CAPTION>
                                                                                   June 30       December 31
                                                                                      2010              2009
-------------------------------------------------------------------------------------------------------------
<S>                                                                                <C>           <C>
Energy Marketing Payables                                                            1,256             1,366
Energy Marketing Derivative Contracts (Note 6)                                         208               456
Accrued Payables                                                                       658               619
Trade Payables                                                                         198               210
Income Taxes Payable                                                                   449               179
Stock-Based Compensation                                                                30                72
Other                                                                                  302               136
                                                                        -------------------------------------
Total                                                                                3,101             3,038
                                                                        =====================================

9.   SHORT-TERM BORROWINGS AND LONG-TERM DEBT
                                                                                   June 30       December 31
                                                                                      2010              2009
-------------------------------------------------------------------------------------------------------------
Canexus Term Credit Facilities, due 2012 (US$289 million drawn) (a)                    307               233
Canexus Notes, due 2013 (US$50 million)                                                 53                52
Notes, due 2013 (US$500 million)                                                       530               523
Term Credit Facilities, due 2014 (US$450 million drawn) (b)                            477             1,570
Canexus Convertible Debentures, due 2014                                                32                46
Notes, due 2015 (US$250 million)                                                       265               262
Notes, due 2017 (US$250 million)                                                       265               262
Notes, due 2019 (US$300 million)                                                       318               314
Notes, due 2028 (US$200 million)                                                       212               209
Notes, due 2032 (US$500 million)                                                       530               523
Notes, due 2035 (US$790 million)                                                       838               827
Notes, due 2037 (US$1,250 million)                                                   1,326             1,308
Notes, due 2039 (US$700 million)                                                       742               733
Subordinated Debentures, due 2043 (US$460 million)                                     488               481
                                                                        -------------------------------------
                                                                                     6,383             7,343
Unamortized Debt Issue Costs                                                          (100)              (92)
                                                                        -------------------------------------
Total Long-Term Debt                                                                 6,283             7,251
                                                                        =====================================
</TABLE>


                                       18
<PAGE>

(a)      CANEXUS TERM CREDIT FACILITIES

Canexus has $451  million  (US$425  million) of  committed,  secured term credit
facilities  available  until August 2012. At June 30, 2010, $307 million (US$289
million) was drawn on these facilities (December 31, 2009 - $233 million (US$223
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 4.3% for the three months ended June 30, 2010 (three months ended
June 30,  2009 - 2.1%)  and 3.0% for the six  months  ended  June 30,  2010 (six
months ended June 30, 2009 - 2.4%).

(b)      TERM CREDIT FACILITIES

We have unsecured term credit  facilities of $3.2 billion (US$3.1 billion) which
are available until 2014. At June 30, 2010,  $477 million  (US$450  million) was
drawn on these facilities  (December 31, 2009 - $1.6 billion (US$1.5  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  monthly at a floating  rate.  The  weighted-average
interest rate on our term credit  facilities was 1.3% for the three months ended
June 30,  2010  (three  months  ended June 30, 2009 - 1.1%) and 1.1% for the six
months ended June 30, 2010 (six months ended June 30, 2009 - 1.1%).  At June 30,
2010, $336 million (US$317 million) of these facilities were utilized to support
outstanding  letters  of  credit  (December  31,  2009  - $407  million  (US$389
million)).

(c)      INTEREST EXPENSE

<TABLE>
<CAPTION>
                                                                     Three Months                 Six Months
                                                                     Ended June 30               Ended June 30
                                                                   2010          2009          2010          2009
------------------------------------------------------------------------------------------------------------------
<S>                                                                <C>           <C>           <C>           <C>
Long-Term Debt                                                       94            89           188           178
Other                                                                 5             3             9             8
                                                             -----------------------------------------------------
Total                                                                99            92           197           186
   Less: Capitalized                                                (22)          (18)          (40)          (44)
                                                             -----------------------------------------------------
Total                                                                77            74           157           142
                                                             =====================================================
</TABLE>

Capitalized  interest  relates to and is included as part of the cost of our oil
and gas 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 $467 million
(US$446 million),  of which $158 million (US$149 million) were drawn at June 30,
2010 (December 31, 2009 - nil). We also utilized $24 million (US$23  million) of
these  facilities  to support  outstanding  letters  of credit at June 30,  2010
(December  31,  2009 - $86  million  (US$82  million)).  Interest  is payable at
floating rates.


                                       19
<PAGE>

10.  CAPITAL MANAGEMENT

Our objectives  and processes for managing our capital  structure are consistent
with those in place at  December  31,  2009.  Our  capital  consists  of equity,
short-term borrowings, long-term debt and cash and cash equivalents as follows:

<TABLE>
<CAPTION>
                                                                         June 30       December 31
                                                                            2010              2009
---------------------------------------------------------------------------------------------------
<S>                                                                      <C>           <C>
NET DEBT (1)
  Short-Term Borrowings                                                      158                 -
  Long-Term Debt                                                           6,283             7,251
                                                             --------------------------------------
Total Debt                                                                 6,441             7,251
     Less: Cash and Cash Equivalents                                        (970)           (1,700)
                                                             --------------------------------------
Total                                                                      5,471             5,551
                                                             ======================================
EQUITY (2)                                                                 8,080             7,646
                                                             ======================================

(1)  Includes all of our  borrowings  and is  calculated  as long-term  debt and
     short-term borrowings less cash and cash equivalents.
(2)  Equity is the historical issue of equity and accumulated retained earnings.
</TABLE>

We monitor the leverage in our capital  structure by reviewing  the ratio of net
debt to adjusted cash flow (cash flow from operating  activities  before changes
in non-cash  working capital and other) and interest  coverage ratios at various
commodity prices. Net debt and adjusted cash flow are non-GAAP measures that are
unlikely to 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).

We use the ratio of net debt to  adjusted  cash flow as a key  indicator  of our
leverage and to monitor the strength of our balance sheet. For the twelve months
ended June 30, 2010,  the net debt to adjusted cash flow was 2.3 times  compared
to 2.5 times at December 31, 2009. While we typically expect the target ratio to
fluctuate between 1.0 and 2.0 times under normalized  commodity prices, this can
be higher or lower depending on commodity price volatility,  where we are in the
investment  cycle,  or  when  we  identify  strategic   opportunities  requiring
additional investment. Whenever we exceed our target ratio, we assess whether we
need to identify  specific  actions 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 increased from 8.5
times at the end of 2009 to 9.1 times at June 30,  2010.  Interest  coverage  is
calculated  by  dividing  our  adjusted   EBITDA  by  interest   expense  before
capitalized  interest.  Adjusted EBITDA is a non-GAAP measure that is calculated
using net  income  excluding  interest  expense,  provision  for  income  taxes,
exploration  expenses,   DD&A,  impairment  and  other  non-cash  expenses.  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
                                                                             2010              2009
----------------------------------------------------------------------------------------------------
<S>                                                           <C>                       <C>
Net Income Attributable to Nexen Inc.                                         821               536
  Add:
     Interest Expense                                                         327               312
     Provision for Income Taxes                                               595               260
     Depreciation, Depletion, Amortization and Impairment                   1,771             1,802
     Exploration Expense                                                      315               302
     Recovery of Non-Cash Stock-Based Compensation                            (93)              (10)
     Change in Fair Value of Crude Oil Put Options                             71               251
     Other Non-Cash Expenses                                                 (161)             (136)
                                                              --------------------------------------
Adjusted EBITDA                                                             3,646             3,317
                                                              ======================================
</TABLE>

                                       20
<PAGE>

11.  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
                                                                                                2010              2009
-----------------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>                    <C>
Balance at Beginning of Period                                                                 1,053             1,059
  Obligations Incurred with Development Activities                                                23                27
  Obligations Settled                                                                            (15)              (42)
  Accretion Expense                                                                               33                70
  Revisions to Estimates                                                                         (35)               13
  Obligations Reclassified to Liabilities Associated with Assets Held for Sale                  (121)                -
  Effects of Changes in Foreign Exchange Rate                                                    (15)              (74)
                                                                                 --------------------------------------
Balance at End of Period 1, (2)                                                                  923             1,053
                                                                                 ======================================

(1)  Obligations  due within 12 months of $64 million  (December  31, 2009 - $35
     million) have been included in accounts payable and accrued liabilities.
(2)  Obligations  relating to our oil and gas activities  amount to $889 million
     (December  31,  2009 - $1,002  million)  and  obligations  relating  to our
     chemicals business amount to $34 million (December 31, 2009 - $51 million).
</TABLE>

Our total estimated undiscounted inflated asset retirement obligations amount to
$2,167  million  (December 31, 2009 - $2,341  million).  We discounted the total
estimated   asset    retirement    obligations    using   a    weighted-average,
credit-adjusted,  risk-free rate of 5.9%. Approximately $215 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.

12.  DEFERRED CREDITS AND OTHER LIABILITIES

<TABLE>
<CAPTION>
                                                                                            June 30       December 31
                                                                                               2010              2009
----------------------------------------------------------------------------------------------------------------------
<S>                                                                                         <C>           <C>
Deferred Tax Credit                                                                             451               503
Long-Term Energy Marketing Derivative Contracts (Note 6)                                        156               212
Defined Benefit Pension Obligations (1)                                                          77                76
Capital Lease Obligations                                                                        43                61
Deferred Transportation Revenue                                                                  37                55
Other                                                                                           115               114
                                                                                 -------------------------------------
Total                                                                                           879             1,021
                                                                                 =====================================

(1)  The  obligations  are secured by letters of credit drawn on our term credit
     facilities.
</TABLE>

13.  SHAREHOLDERS' EQUITY

DIVIDENDS

Dividends  per common  share for the three months ended June 30, 2010 were $0.05
per common share (2009 - $0.05).  Dividends  per common share for the six months
ended June 30, 2010 were $0.10 per common share (2009 - $0.10).Dividends paid to
holders of common  shares  have been  designated  as  "eligible  dividends"  for
Canadian tax purposes.



                                       21
<PAGE>
14.  MARKETING AND OTHER INCOME
<TABLE>
<CAPTION>
                                                                      Three Months                 Six Months
                                                                      Ended June 30               Ended June 30
                                                                    2010          2009          2010          2009
-------------------------------------------------------------------------------------------------------------------
<S>                                                                 <C>           <C>           <C>           <C>
Marketing Revenue, Net                                               112           221           198           488
Long Lake Purchased Bitumen Sales                                     10             -            38             -
Gain on Sale of Assets                                                83             1            80             8
Change in Fair Value of Crude Oil Put Options                          1          (179)          (15)         (195)
Interest                                                               1             1             5             3
Foreign Exchange Gain                                                (28)            -             6            19
Other (1)                                                            (15)           38             3            16
                                                             ------------------------------------------------------
Total                                                                164            82           315           339
                                                             ======================================================

(1)  Includes non-cash  mark-to-market losses that will reverse with the sale of
     North America Natural Gas Energy Marketing as described in Note 15.
</TABLE>


15.      ASSET DISPOSITIONS

CANADIAN HEAVY OIL PROPERTIES
During the quarter,  we signed an agreement to sell our heavy oil  properties in
Canada for  proceeds of $975 million  before  closing  adjustments.  The sale is
expected  to  close  in  the  third  quarter  following  receipt  of  regulatory
approvals.  On closing,  we expect to realize a gain of over $750  million.  The
results of operations from these  properties have been presented as discontinued
operations. The properties are considered assets held for sale at June 30, 2010.
The following tables provide the assets and liabilities that are associated with
the heavy oil properties.

<TABLE>
<CAPTION>
                                                                                                        June 30
                                                                                                           2010
-----------------------------------------------------------------------------------------------------------------
<S>                                                                                                     <C>
Property, Plant and Equipment, Net of Accumulated DD&A                                                      303
Asset Retirement Obligations                                                                               (121)
Deferred Credits and Other Liabilities                                                                      (28)
                                                                                             --------------------
Total                                                                                                       154
                                                                                             ====================
</TABLE>

Discontinued operations from these assets are:

<TABLE>
<CAPTION>
                                                                     Three Months                 Six Months
                                                                     Ended June 30               Ended June 30
                                                                   2010          2009          2010          2009
------------------------------------------------------------------------------------------------------------------
<S>                                                                <C>           <C>           <C>           <C>
Revenues and Other Income
   Net Sales                                                         56            62           125           106
                                                             -----------------------------------------------------

Expenses
   Operating                                                         22            25            45            50
   Depreciation, Depletion, Amortization and Impairment              12            32            34            64
   General and Administrative                                         5             6             9            12
   Transportation and Other                                           -             3             2             7
                                                             -----------------------------------------------------
                                                                     39            66            90           133
                                                             -----------------------------------------------------

Income (Loss) before Provision for Income Taxes                      17            (4)           35           (27)
Provision for (Recovery of) Future Income Taxes                       4            (1)            9            (7)
                                                             -----------------------------------------------------

Net Income (Loss) from Discontinued Operations                       13            (3)           26           (20)
                                                             =====================================================

Earnings (Loss) Per Common Share
   Basic                                                           0.03        (0.01)         0.05          (0.03)
                                                             =====================================================
   Diluted                                                         0.03        (0.01)         0.05          (0.03)
                                                             =====================================================
</TABLE>

                                       22
<PAGE>

NORTH AMERICA NATURAL GAS ENERGY MARKETING
During the quarter,  we signed an agreement to sell our North  American  natural
gas  marketing  business.  The  transaction  is  expected  to close in the third
quarter,  subject to customary  closing  conditions.  The sale is expected to be
cash neutral and we expect to  recognize a non-cash  loss on the sale of between
$250 million and $290 million. On closing,  the purchaser will acquire our North
American  natural  gas  business   including  our  storage  and   transportation
commitments,  natural gas inventory,  related financial and physical  derivative
positions,  and margin  collateral  posted.  In the period  between  signing and
closing,  we have  agreements with the purchaser which transfers the market risk
of our contracts and inventory to the purchaser  unless we breach our obligation
to close the sale. These agreements are derivative  instruments  carried at fair
value on our balance sheet with gains and losses included in marketing and other
income.

CANADIAN UNDEVELOPED OIL SAND LEASES
During the  quarter,  we sold our  non-core  lands in the  Athabasca  region for
proceeds of $81 million.  We had no plans to develop  these lands for at least a
decade. We recognized a gain on sale of $80 million.

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)                                                  2010          2009          2010          2009
---------------------------------------------------------------------------------------------------------------------
<S>                                                                  <C>           <C>           <C>           <C>
Weighted-average number of common shares outstanding                 524.5         521.2         524.0         520.7
Shares issuable pursuant to tandem options                             5.8          11.1           6.0          11.2
Shares notionally purchased from proceeds of tandem options           (4.1)         (6.8)         (4.4)         (7.9)
                                                                -----------------------------------------------------
Weighted-average number of diluted common shares outstanding         526.2         525.5         525.6         524.0
                                                                =====================================================
</TABLE>

In calculating the weighted-average  number of diluted common shares outstanding
for the three and six months ended June 30,  2010,  we excluded  16,556,303  and
16,516,379  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, 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.  During  the  periods  presented,
outstanding tandem options were the only potential dilutive instruments.

17.      COMMITMENTS, CONTINGENCIES AND GUARANTEES

As  described  in  Note  15 to the  Audited  Consolidated  Financial  Statements
included  in our 2009  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.

During the first quarter, we sold our European gas and power marketing business.
We agreed to maintain our  parental  guarantees  to the existing  counterparties
until  the  purchaser  is able to  replace  them.  At June 30,  2010,  our total
exposure is $71 million.  The guarantees  expire at the earlier of the purchaser
replacing  the  guarantees  and  September 25, 2010. We are obligated to perform
under the guarantees  only if the purchaser does not meet its obligations to the
counterparties.  To eliminate our exposure under the  guarantees,  the purchaser
has  provided  us an  indemnity  and an  irrevocable  letter  of  credit  from a
highly-rated financial institution.

                                       23
<PAGE>

18.      CASH FLOWS

(a)      CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH

<TABLE>
<CAPTION>
                                                                      Three Months                 Six Months
                                                                      Ended June 30               Ended June 30
                                                                    2010          2009          2010          2009
-------------------------------------------------------------------------------------------------------------------
<S>                                                                 <C>           <C>           <C>           <C>
Depreciation, Depletion, Amortization and Impairment                 391           381           757           758
Stock-Based Compensation                                             (40)           42           (41)           42
Recovery of Future Income Taxes                                      (84)         (228)         (189)         (309)
Gain on Sale of Assets                                               (83)           (1)          (80)           (8)
Non-cash Items Included in Discontinued Operations                    16            31            43            57
Change in Fair Value of Crude Oil Put Options                         (1)          179            15           195
Foreign Exchange                                                      42           (24)            1           (37)
Other                                                                 29            14            29            15
                                                             ------------------------------------------------------
Total                                                                270           394           535           713
                                                             ======================================================

(b)      CHANGES IN NON-CASH WORKING CAPITAL
                                                                      Three Months                 Six Months
                                                                      Ended June 30               Ended June 30
                                                                    2010          2009          2010          2009
-------------------------------------------------------------------------------------------------------------------
   Accounts Receivable                                               (16)         (471)         (234)         (173)
   Inventories and Supplies                                          (37)          (80)           76          (129)
   Other Current Assets                                                5            20            78            12
   Accounts Payable and Accrued Liabilities                          (30)          134           355           319
   Other Current Liabilities                                           7           (17)           (2)           (4)
                                                             ------------------------------------------------------
Total                                                                (71)         (414)          273            25
                                                             ======================================================

Relating to:
   Operating Activities                                              (58)         (340)          198            80
   Investing Activities                                              (13)          (74)           75           (55)
                                                             ------------------------------------------------------
Total                                                                (71)         (414)          273            25
                                                             ======================================================

(c)      OTHER CASH FLOW INFORMATION

                                                                      Three Months                 Six Months
                                                                      Ended June 30               Ended June 30
                                                                    2010          2009          2010          2009
-------------------------------------------------------------------------------------------------------------------
Interest Paid                                                         87            97           190           178
Income Taxes Paid                                                     43            34           250            68
                                                             ------------------------------------------------------
</TABLE>

Cash flow from other  operating  activities  includes cash  outflows  related to
geological  and  geophysical  expenditures  of $17 million for the three  months
ended June 30,  2010 (2009 - $31  million)  and $29  million  for the six months
ended June 30, 2010 (2009 - $43 million).

                                       24
<PAGE>

19.      OPERATING SEGMENTS AND RELATED INFORMATION

Nexen is involved in activities  relating to Oil and Gas,  Energy  Marketing and
Chemicals in various geographic locations as described in Note 20 to the Audited
Consolidated Financial Statements included in our 2009 Form 10-K.

  THREE MONTHS ENDED JUNE 30, 2010

<TABLE>
<CAPTION>
                                                                                            Energy                Corporate
                                                      Oil and Gas                          Marketing   Chemicals  and Other   Total
                               ----------------------------------------------------------------------------------------------------
                                 United                        United               Other
                                Kingdom   Canada    Syncrude   States    Yemen  Countries(1)
-------------------------------------------------------------------------------------------
<S>                             <C>       <C>        <C>       <C>       <C>    <C>         <C>         <C>        <C>        <C>
Net Sales                          735      125        152       99       157         14          12        105        -      1,399
Marketing and Other                  4       90(2)       1        1         3          -          95         (7)     (23)(3)    164
                              -----------------------------------------------------------------------------------------------------
Total Revenues                     739      215        153      100       160         14         107         98      (23)     1,563

Less: Expenses
  Operating                         76      104         71       25        36          2           7         78        -        399
  Depreciation, Depletion,
   Amortization and
     Impairment                    198       67         14       59        24          2           5         12       10        391
  Transportation and Other           4       37          4        -         3          -          89         14        8        159
  General and
     Administrative (4)              -        2          -       13        (1)         3          11          9       33         70
  Exploration                        7        6          -       13         -         24(5)        -          -        -         50
  Interest                           -        -          -        -         -          -           -          2       75         77
                              -----------------------------------------------------------------------------------------------------
Income (Loss) from                 454       (1)        64      (10)       98        (17)         (5)       (17)    (149)       417
Continuing Operations
  before Income Taxes
Less: Provision for
  (Recovery Of) Income Taxes       226       (1)        16       (3)       35        (15)         (5)        (4)     (69)       180
Less: Non-Controlling
  Interests                          -        -          -        -         -          -           -         (5)       -         (5)
Add: Net Income from Assets
    Held for Sale                    -       13          -        -         -          -           -          -        -         13
                              -----------------------------------------------------------------------------------------------------
NET INCOME (LOSS)                  228       13         48       (7)       63         (2)          -         (8)     (80)       255
                              =====================================================================================================

IDENTIFIABLE ASSETS              4,601    8,117(6)   1,293    1,750       248      1,254(7)    2,648(8)     754    1,850     22,515
                              =====================================================================================================

Capital Expenditures
                              -----------------------------------------------------------------------------------------------------
EXPLORATION & DEVELOPMENT          144      355         24       64        17        143           7         53       10        817
                              =====================================================================================================

Property, Plant and
Equipment
  Cost                           6,418    8,433      1,504    4,071     2,521      1,169         228      1,222      318     25,884
  Less: Accumulated DD&A         3,032      769        292    2,679     2,414        102          64        582      195     10,129
                              -----------------------------------------------------------------------------------------------------
NET BOOK VALUE                   3,386    7,664(6)   1,212    1,392       107      1,067(7)      164        640      123     15,755
                              =====================================================================================================

(1)  Includes  results of operations from producing  activities in Colombia.
(2)  Includes  gain of $80  million  from  the  sale of  non-core  lands  in the
     Athabasca region.
(3)  Includes  interest  income of $1 million,  foreign  exchange  losses of $28
     million,  an  increase  in the fair  value of crude oil put  options  of $1
     million and other gains of $3 million.
(4)  Includes recovery of stock-based  compensation  expense of $35 million.
(5)  Includes exploration activities primarily in Nigeria, Norway and Colombia.
(6)  Includes PP&E costs of $6,108 million related to our insitu oil sands (Long
     Lake and future phases).
(7)  Includes PP&E costs of $1,016 million related to Nigeria.
(8)  Approximately   84%  of  Marketing's   identifiable   assets  are  accounts
     receivable and inventories.
</TABLE>

                                       25
<PAGE>

THREE MONTHS ENDED JUNE 30, 2009

<TABLE>
<CAPTION>
                                                                                            Energy                Corporate
                                                      Oil and Gas                          Marketing   Chemicals  and Other   Total
                               ----------------------------------------------------------------------------------------------------
                                 United                        United               Other
                                Kingdom   Canada    Syncrude   States    Yemen  Countries(1)
-------------------------------------------------------------------------------------------
<S>                             <C>       <C>        <C>       <C>       <C>    <C>         <C>         <C>        <C>        <C>
Net Sales                          618       36         85       88       175         20           7        109        -      1,138
Marketing and Other                  4        1          1        -         4          -         221         29     (178)(2)     82
                              -----------------------------------------------------------------------------------------------------
Total Revenues                     622       37         86       88       179         20         228        138     (178)     1,220

Less: Expenses
  Operating                         53       17         77       27        49          2           8         62        -        295
  Depreciation, Depletion,
   Amortization and
     Impairment                    182       30          9       80        32          4           3         29       12        381
  Transportation and Other          14        5          5        3        15          -         166         14        7        229
  General and
     Administrative (3)              5       22          1       24        (3)        16          26         16       54        161
  Exploration                       11        8          -       37         -         21(4)        -          -        -         77
  Interest                           -        -          -        -         -          -           -          2       72         74
                              -----------------------------------------------------------------------------------------------------
Income (Loss) from                 357      (45)        (6)     (83)       86        (23)         25         15     (323)         3
Continuing Operations
  before Income Taxes
Less: Provision for
  (Recovery of) Income Taxes       170      (12)        (2)     (28)       30        (18)          9          4     (175)       (22)
Less: Non-Controlling
  Interests                          -        -          -        -         -          -           -          2        -          2
Add: Net Loss from Assets
    Held for Sale                    -       (3)         -        -         -          -           -          -        -         (3)
                              -----------------------------------------------------------------------------------------------------
NET INCOME (LOSS)                  187      (36)        (4)     (55)       56         (5)         16          9     (148)        20
                              =====================================================================================================

IDENTIFIABLE ASSETS              5,831    8,349(5)   1,232    2,043       289        911(6)    3,332(7)     618    1,321     23,926
                              =====================================================================================================

Capital Expenditures
                              -----------------------------------------------------------------------------------------------------
EXPLORATION & DEVELOPMENT          158      191         22       72        22        166           3         72        9        715
                              =====================================================================================================

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

(1)  Includes results of operations from producing activities in Colombia.
(2)  Includes  interest income of $1 million and a 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 Nigeria, Norway and Colombia.
(5)  Includes PP&E costs of $5,832 million related to our insitu oil sands (Long
     Lake and future phases).
(6)  Includes PP&E costs of $551 million related to Nigeria.
(7)  Approximately   82%  of  Marketing's   identifiable   assets  are  accounts
     receivable and inventories.
</TABLE>

                                       26
<PAGE>

SIX MONTHS ENDED JUNE 30, 2010

<TABLE>
<CAPTION>
                                                                                            Energy                Corporate
                                                      Oil and Gas                          Marketing   Chemicals  and Other   Total
                               ----------------------------------------------------------------------------------------------------
                                 United                        United               Other
                                Kingdom   Canada    Syncrude   States    Yemen  Countries(1)
-------------------------------------------------------------------------------------------
<S>                             <C>       <C>        <C>       <C>       <C>    <C>         <C>         <C>        <C>        <C>
Net Sales                        1,490      236        286      212       339         29          21        218        -      2,831
Marketing and Other                  9      118(2)       2        1         8          -         178          -       (1)(3)    315
                              -----------------------------------------------------------------------------------------------------
Total Revenues                   1,499      354        288      213       347         29         199        218       (1)     3,146

Less: Expenses
  Operating                        153      215        138       47        77          3          17        148        -        798
  Depreciation, Depletion,
   Amortization and
     Impairment                    366      125         27      123        59          4          10         23       20        757
  Transportation and Other           3       91         11        2         6          -         212         26        8        359
  General and
     Administrative(4)              13       14          -       24         -         11          32         17       73        184
  Exploration                       31       13          -       29         -         70(5)        -          -        -        143
  Interest                           -        -          -        -         -          -           -          3      154        157
                              -----------------------------------------------------------------------------------------------------
Income (Loss) from                 933     (104)       112      (12)      205        (59)        (72)         1     (256)       748
Continuing Operations
  before Income Taxes
Less: Provision for
  (Recovery of) Income Taxes       466      (27)        28       (4)       72        (53)        (28)         -     (120)       334
Less: Non-Controlling
  Interests                          -        -          -        -         -          -           -          -        -          -
Add: Net Income from Assets
    Held for Sale                    -       26          -        -         -          -           -          -        -         26
                              -----------------------------------------------------------------------------------------------------
NET INCOME (LOSS)                  467      (51)        84       (8)      133         (6)        (44)         1     (136)       440
                              =====================================================================================================

IDENTIFIABLE ASSETS              4,601    8,117(6)   1,293    1,750       248      1,254(7)    2,648(8)     754    1,850     22,515
                              =====================================================================================================

Capital Expenditures
                              -----------------------------------------------------------------------------------------------------
EXPLORATION & DEVELOPMENT          273      493         43      128        27        275          16        102       16      1,373
                              =====================================================================================================

Property, Plant and
Equipment
  Cost                           6,418    8,433      1,504    4,071     2,521      1,169         228      1,222      318     25,884
  Less: Accumulated DD&A         3,032      769        292    2,679     2,414        102          64        582      195     10,129
                              -----------------------------------------------------------------------------------------------------
NET BOOK VALUE                   3,386    7,664(6)   1,212    1,392       107      1,067(7)      164        640      123     15,755
                              =====================================================================================================

(1)  Includes  results of operations from producing  activities in Colombia.
(2)  Includes  gain of $80  million  from  the  sale of  non-core  lands  in the
     Athabasca region.
(3)  Includes  interest  income  of $5  million,  foreign  exchange  gains of $6
     million, decrease in the fair value of crude oil put options of $15 million
     and other gains of $3 million.
(4)  Includes recovery of stock-based compensation expense of $33 million.
(5)  Includes exploration activities primarily in Norway and Colombia.
(6)  Includes PP&E costs of $6,108 million related to our insitu oil sands (Long
     Lake and future phases).
(7)  Includes PP&E costs of $1,016 million related to Nigeria.
(8)  Approximately   84%  of  Marketing's   identifiable   assets  are  accounts
     receivable and inventories.
</TABLE>

                                       27
<PAGE>

SIX MONTHS ENDED JUNE 30, 2009

<TABLE>
<CAPTION>
                                                                                            Energy                Corporate
                                                      Oil and Gas                          Marketing   Chemicals  and Other   Total
                               ----------------------------------------------------------------------------------------------------
                                 United                        United               Other
                                Kingdom   Canada    Syncrude   States    Yemen  Countries(1)
-------------------------------------------------------------------------------------------
<S>                             <C>       <C>        <C>       <C>       <C>    <C>         <C>         <C>        <C>        <C>
Net Sales                        1,096       83        183      151       337         39          20        233        -      2,142
Marketing and Other                  8        8          1        -         7          -         488         15     (188)(2)    339
                              -----------------------------------------------------------------------------------------------------
Total Revenues                   1,104       91        184      151       344         39         508        248     (188)     2,481

Less: Expenses
  Operating                        104       33        143       50        96          4          16        129        -        575
  Depreciation, Depletion,
   Amortization and
     Impairment                    375       61         20      148        73          9           7         41       24        758
  Transportation and Other          11        4         12       16        18          -         328         24       13        426
  General and
     Administrative (3)              7       30          1       38         1         24          49         25       80        255
  Exploration                       19       29          -       47         -         35(4)        -          -        -        130
  Interest                           -        -          -        -         -          -           -          4      138        142
                              -----------------------------------------------------------------------------------------------------
Income (Loss) from                 588      (66)         8     (148)      156        (33)        108         25     (443)       195
Continuing Operations
  before Income Taxes
Less: Provision for
  (Recovery of) Income Taxes       256      (17)         2      (51)       54        (24)         44          6     (255)        15
Less: Non-Controlling
  Interests                          -        -          -        -         -          -           -          5        -          5
Add: Net Loss from Assets
    Held for Sale                    -      (20)         -        -         -          -           -          -        -        (20)
                              -----------------------------------------------------------------------------------------------------
NET INCOME (LOSS)                  332      (69)         6      (97)      102         (9)         64         14     (188)       155
                              =====================================================================================================

IDENTIFIABLE ASSETS              5,831    8,349(5)   1,232    2,043       289        911(6)    3,332(7)     618    1,321     23,926
                              =====================================================================================================

Capital Expenditures
  Exploration & Development        335      531         39      140        51        239          11        108       10      1,464
  Proved Property
     Acquisitions                    -      755          -        -         -          -           -          -        -        755
                              -----------------------------------------------------------------------------------------------------
TOTAL                              335    1,286         39      140        51        239          11        108       10      2,219
                              =====================================================================================================

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

(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 and Colombia.
(5)  Includes PP&E costs of $5,832 million related to our insitu oil sands (Long
     Lake and future phases).
(6)  Includes PP&E costs of $551 million related to Nigeria.
(7)  Approximately   82%  of  Marketing's   identifiable   assets  are  accounts
     receivable and inventories.
</TABLE>


                                       28
<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:

UNAUDITED CONSOLIDATED STATEMENT OF INCOME - US GAAP
FOR THE THREE AND SIX MONTHS ENDED JUNE 30
<TABLE>
<CAPTION>
                                                                          Three Months                 Six Months
                                                                          Ended June 30               Ended June 30
(Cdn$ millions, except per share amounts)                               2010          2009          2010         2009
----------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>          <C>            <C>          <C>
REVENUES AND OTHER INCOME
   Net Sales                                                           1,399        1,138          2,831        2,142
   Marketing and Other (v); (vi)                                          98           66            303          358
                                                                ------------------------------------------------------
                                                                       1,497        1,204          3,134        2,500
                                                                ------------------------------------------------------
EXPENSES
   Operating                                                             399          295            798          575
   Depreciation, Depletion, Amortization and Impairment                  391          381            757          758
   Transportation and Other (v)                                           76          228            279          418
   General and Administrative (iv)                                        50          191            172          293
   Exploration                                                            50           77            143          130
   Interest                                                               77           74            157          142
                                                                ------------------------------------------------------
                                                                       1,043        1,246          2,306        2,316
                                                                ------------------------------------------------------

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE
   PROVISION FOR INCOME TAXES                                            454          (42)           828          184
                                                                ------------------------------------------------------

PROVISION FOR (RECOVERY OF) INCOME TAXES
   Current                                                               264          206            523          324
   Deferred (iv); (vi)                                                   (73)        (241)          (164)        (309)
                                                                ------------------------------------------------------
                                                                         191          (35)           359           15
                                                                ------------------------------------------------------

NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE
   NON-CONTROLLING INTERESTS                                             263           (7)           469          169
   Less: Net Income (Loss) Attributable to Canexus Non-
       Controlling Interests                                              (5)           2              -            5
                                                                ------------------------------------------------------

NET INCOME (LOSS) FROM CONTINUING OPERATIONS
   ATTRIBUTABLE TO NEXEN INC.                                            268           (9)           469          164
   Net Income (Loss) from Discontinued Operations                         13           (3)            26          (20)
                                                                ------------------------------------------------------

NET INCOME (LOSS) ATTRIBUTABLE TO NEXEN INC. - US GAAP (1)               281          (12)           495          144
                                                                ======================================================

EARNINGS (LOSS) PER COMMON SHARE FROM CONTINUING
OPERATIONS ($/share)
   Basic                                                                0.51         (0.02)         0.89          0.31
                                                                ======================================================
   Diluted                                                              0.51         (0.02)         0.89          0.31
                                                                ======================================================

EARNINGS (LOSS) PER COMMON SHARE ($/share)
   Basic                                                                0.54         (0.02)         0.94          0.28
                                                                ======================================================
   Diluted                                                              0.54         (0.02)         0.94          0.28
                                                                ======================================================
</TABLE>
<TABLE>
<CAPTION>
(1)  RECONCILIATION OF CANADIAN AND US GAAP NET INCOME                    Three Months                Six Months
                                                                          Ended June 30              Ended June 30
                                                                       2010          2009          2010          2009
----------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>           <C>           <C>           <C>
Net Income Attributable to Nexen Inc - Canadian GAAP                    255            20           440           155
Impact of US Principles, Net of Income Taxes:
   Stock-based Compensation (iv)                                         15           (22)            9           (28)
   Inventory Valuation (vi)                                              11           (10)           46            17
                                                                ------------------------------------------------------
Net Income (Loss) Attributable to Nexen Inc - US GAAP                   281           (12)          495           144
                                                                ======================================================
</TABLE>

                                       29
<PAGE>

UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP
<TABLE>
<CAPTION>
                                                                                       June 30        December 31
(Cdn$ millions, except share amounts)                                                     2010               2009
-------------------------------------------------------------------------------------------------------------------
<S>                                                                                    <C>            <C>
ASSETS
   CURRENT ASSETS
      Cash and Cash Equivalents                                                            970              1,700
      Restricted Cash                                                                      113                198
      Accounts Receivable                                                                2,675              2,788
      Inventories and Supplies (vi)                                                        619                610
      Other                                                                                106                185
                                                                             --------------------------------------
         Total Current Assets                                                            4,483              5,481
                                                                             --------------------------------------

   PROPERTY, PLANT AND EQUIPMENT
      Net of Accumulated Depreciation, Depletion, Amortization and
         Impairment of $10,521 (December 31, 2009 - $11,200) (i); (iii)                 15,706             15,443
   GOODWILL                                                                                343                339
   DEFERRED INCOME TAX ASSETS                                                            1,340              1,148
   DEFERRED CHARGES AND OTHER ASSETS                                                       289                370
   ASSETS HELD FOR SALE                                                                    303                  -
                                                                             --------------------------------------
TOTAL ASSETS                                                                            22,464             22,781
                                                                             ======================================

LIABILITIES
   CURRENT LIABILITIES
      Short-Term Borrowings                                                                158                  -
      Accounts Payable and Accrued Liabilities (iv)                                      3,182              3,131
      Accrued Interest Payable                                                              89                 89
      Dividends Payable                                                                     26                 26
                                                                             --------------------------------------
         Total Current Liabilities                                                       3,455              3,246
                                                                             --------------------------------------

   LONG-TERM DEBT                                                                        6,283              7,251
   DEFERRED INCOME TAX LIABILITIES (i); (ii); (iv); (vi); (vii)                          2,825              2,720
   ASSET RETIREMENT OBLIGATIONS                                                            859              1,018
   DEFERRED CREDITS AND OTHER LIABILITIES (ii)                                             984              1,126
   LIABILITIES ASSOCIATED WITH ASSETS HELD FOR SALE                                        149                  -

EQUITY
   Nexen Inc. Shareholders' Equity
      Common Shares, no par value
         Authorized:   Unlimited
         Outstanding:  2010 - 524,565,491 shares
                       2009 - 522,915,843 shares                                         1,088              1,049
      Contributed Surplus                                                                    -                  1
      Retained Earnings (i); (ii); (iv); (vi); (vii)                                     7,018              6,575
      Accumulated Other Comprehensive Loss (ii)                                           (268)              (269)
                                                                             --------------------------------------
   Total Nexen Inc. Shareholders' Equity                                                 7,838              7,356
      Canexus Non-Controlling Interests                                                     71                 64
                                                                             --------------------------------------
   TOTAL EQUITY                                                                          7,909              7,420
                                                                             --------------------------------------
   COMMITMENTS, CONTINGENCIES AND GUARANTEES
TOTAL LIABILITIES AND EQUITY                                                            22,464             22,781
                                                                             ======================================
</TABLE>


                                    30
<PAGE>

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
                                                                    2010          2009          2010         2009
------------------------------------------------------------------------------------------------------------------
<S>                                                                 <C>           <C>           <C>          <C>
Net Income (Loss) Attributable to Nexen Inc. - US GAAP               281           (12)          495          144
Other Comprehensive Income (Loss), Net of Income Taxes:
   Foreign Currency Translation Adjustment                            12           (29)            1          (23)
                                                              ----------------------------------------------------
Comprehensive Income (Loss) Attributable to Nexen Inc. - US
   GAAP                                                              293           (41)          496          121
                                                              ====================================================
</TABLE>

UNAUDITED CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE
LOSS - US GAAP
<TABLE>
<CAPTION>
                                                                                       June 30       December 31
                                                                                          2010              2009
-----------------------------------------------------------------------------------------------------------------
<S>                                                                                    <C>           <C>
Foreign Currency Translation Adjustment                                                   (189)             (190)
Unamortized Defined Benefit Pension Plan Costs (ii)                                        (79)              (79)
                                                                             ------------------------------------
Accumulated Other Comprehensive Loss                                                      (268)             (269)
                                                                             ====================================
</TABLE>

NOTES TO THE UNAUDITED CONSOLIDATED US GAAP FINANCIAL STATEMENTS:
i.   Under Canadian GAAP, we deferred certain  development  costs to PP&E. Under
     US  principles,  these costs have been  included in  operating  expenses in
     prior  years.  As a  result,  PP&E is lower  under  US GAAP by $30  million
     (December 31, 2009 - $30 million) and deferred  income tax  liabilities are
     lower by $11 million (December 31, 2009 - $11 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, 2010 and  December 31,  2009,  the unfunded  amount of our defined
     benefit pension plans that was not included in the pension  liability under
     Canadian GAAP was $105  million.  This amount has been included in deferred
     credits and other  liabilities  and $79 million,  net of income taxes,  has
     been included in Accumulated Other Comprehensive Loss (AOCL).

iii. On January 1, 2003, we adopted ACCOUNTING FOR ASSET RETIREMENT  OBLIGATIONS
     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 required the
     accelerated  recognition  of  stock-based   compensation  expense  for  all
     stock-based awards made to our retired and  retirement-eligible  employees.
     However,  US GAAP  required  the  accelerated  recognition  of  stock-based
     compensation  expense  for such  employees  for awards  granted on or after
     January 1, 2006. As a result under US GAAP:

     o    general and  administrative  (G&A) expense is lower by $20 million and
          $12 million,  ($15 million and $9 million,  net of income taxes),  for
          the three and six months  ended June 30,  2010,  (2009 - higher by $30
          million and $38 million,  respectively,  ($22 million and $28 million,
          net of income taxes)); and
     o    accounts payable and accrued  liabilities are higher by $81 million as
          at June 30, 2010 (December 31, 2009 - $93 million).

v.   Under US GAAP,  asset  disposition  gains  and  losses  are  included  with
     transportation and other expense.  Gains of $83 million and $80 million for
     the  three  and  six  months  ended  June  30,  2010,  respectively,   were
     reclassified  from marketing and other income to  transportation  and other
     expense (gains of $1 million and $8 million, respectively were reclassified
     for the three and six months ended June 30, 2009).

                                       31
<PAGE>

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 higher by $17  million and $68 million
          ($11 million and $46 million,  net of income  taxes) for the three and
          six months ended June 30, 2010 (2009 - lower by $15 million and higher
          by $27 million ($10 million and $17  million,  net of income  taxes));
          and
     o    inventories  are lower by $2 million as at June 30, 2010 (December 31,
          2009 - lower by $70 million) and deferred  income tax  liabilities are
          $1 million lower (December 31, 2009 - lower by $23 million).

vii. Under US GAAP, we are required to apply FIN48 ACCOUNTING FOR UNCERTAINTY IN
     INCOME  TAXES  regarding   accounting  and  disclosure  for  uncertain  tax
     positions.

     As at June 30, 2010, the total amount of our  unrecognized  tax benefit was
     approximately $284 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, 2010, 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 - Unaudited  Consolidated Statement of
     Income for the three and six months ended June 30, 2010.

     Our income tax filings are subject to audit by taxation  authorities and as
     at June 30, 2010 the following tax years remained  subject to  examination,
     (i)  Canada - 1985 to date  (ii)  United  Kingdom  - 2008 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.


NEW ACCOUNTING PRONOUNCEMENTS - US GAAP

In January 2010, the Financial  Accounting  Standards  Board issued  guidance to
improve financial  instrument fair value measurement  disclosures.  The guidance
requires  entities to describe  transfers  between the three  levels of the fair
value hierarchy and present items separately in the level 3 reconciliation. This
guidance  is  consistent  with fair value  measurement  disclosures  adopted for
Canadian  GAAP in 2009.  Adoption of this guidance did not have an impact on our
results of operations or financial position.



                                       32

<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 14, 2010.

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,
INFORMATION ON A NET, AFTER-ROYALTIES BASIS IS ALSO PRESENTED.

NOTE:  CANADIAN  INVESTORS SHOULD READ THE SPECIAL NOTE TO CANADIAN INVESTORS ON
PAGE 97 OF OUR 2009 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.

EXECUTIVE SUMMARY OF SECOND QUARTER RESULTS

<TABLE>
<CAPTION>
                                                                                  Three Months                 Six Months
                                                                                  Ended June 30               Ended June 30
(Cdn$ millions, except as indicated)                                            2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                           <C>           <C>           <C>           <C>
Production before Royalties (mboe/d)                                             248           240           250           246
Production after Royalties (mboe/d)                                              218           208           220           217
Nexen's Average Realized Oil and Gas Price (Cdn$/boe)                          67.46         61.28         68.78         54.28

Cash Flow from Operating Activities                                              510           109         1,308           898
Net Income Attributable to Nexen Inc.                                            255            20           440           155
Earnings per Common Share, Basic ($/share)                                      0.49          0.04          0.84          0.30

Capital Investment                                                               817           715         1,373         1,464
Acquisition of Additional Interest in Long Lake                                    -             -             -           755
Net Debt (1)                                                                   5,471         5,889         5,471         5,889
                                                                         -------------------------------------------------------
</TABLE>

(1)  Net  debt is a  non-GAAP  measure  and is  defined  as  long-term  debt and
     short-term borrowings less cash and cash equivalents.

Higher  production  combined with stronger  commodity prices delivered  improved
financial  results  over last year.  Production  for the  quarter  increased  3%
despite  downtime  at  Buzzard  and  natural  field  declines  in Yemen.  Higher
production rates at Long Lake, Syncrude and at our Ettrick and Telford fields in
the UK North Sea more than offset  scheduled  downtime at Buzzard.  Our realized
average oil and gas price averaged  $67.46/boe for the quarter,  10% higher than
last year as a result of  stronger  benchmark  commodity  prices.  The weaker US
dollar reduced some of the commodity price increase benefit.

At our Long Lake oil sands project,  we are steadily growing bitumen  production
volumes each month as we increase steam volumes and the  reservoirs  heat up. We
expect Long Lake to make positive cash flow contributions later this year as our
bitumen volumes grow.

We  successfully  completed the  installation  of the topside  facilities on the
fourth platform at Buzzard during the quarter. Elsewhere, our capital investment
focused on progressing our major development  project at Usan,  offshore Nigeria
to first oil production in 2012,  and on  exploration  activities in the Gulf of
Mexico, the North Sea and shale gas. In addition, we were successful at a recent
land sale in northeast British Columbia where we more than doubled our shale gas
position.  To date,  we have  incurred  approximately  half of our 2010  planned
capital expenditures.

In the Gulf of Mexico,  we continue to evaluate our discovery at Appomattox  and
progress plans for follow-up  appraisal and  exploration,  while in the UK North
Sea we are reviewing development options for the Golden Eagle area. Elsewhere in
the UK North Sea, we drilled a successful appraisal well at Blackbird during the
quarter. Blackbird is adjacent to our Ettrick development.


                                       33
<PAGE>


The six month drilling  moratorium in the Gulf of Mexico has no material  impact
on our current  operations.  Our shelf and deep-water  production are unaffected
and we continue to expect our Gulf of Mexico  production for the year to average
between 20,000 and 28,000 boe/d before royalties  (17,000 and 25,000 boe/d after
royalties).

During the quarter,  we entered into  agreements to sell our heavy oil assets in
Canada and our natural gas marketing business. The heavy oil properties produced
approximately  15,000 boe/d during the second quarter and had proved reserves of
39 million boe at December 31, 2009. Both  transactions are expected to close in
the third  quarter,  generating  net proceeds of almost $1 billion and realizing
net  gains of  approximately  $500  million.  We have  exceeded  our  target  of
generating  $1.0 billion of proceeds  from  non-core  asset  sales.  We have now
increased our target to approximately  $1.5 billion of proceeds once we complete
our disposition program, which includes the sale of our Canexus investment.

Our financial position remains strong with available  liquidity of approximately
$3.8 billion.  This liquidity  includes cash on hand of approximately $1 billion
and undrawn lines of credit of approximately  $2.8 billion.  After the heavy oil
and natural gas marketing transactions close in the third quarter, we expect our
liquidity to increase by approximately $900 million. Debt maturities in the next
five  years  can be  repaid  from  current  cash on hand and the heavy oil sales
proceeds. The average term-to-maturity of our long-term debt is approximately 19
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:
conventional exploration and development,  oil sands, and unconventional gas. We
are committed to growing  long-term value for our  shareholders  responsibly and
are advancing our plans to achieve this as described below.

We are currently investing primarily in:
     o    ramping up Long Lake safely and reliably;
     o    progressing construction of our Usan project and continuing to explore
          our acreage, offshore Nigeria;
     o    advancing  development plans for our Golden Eagle area in the UK North
          Sea;
     o    appraising  exploration successes at Appomattox and Knotty Head in the
          Gulf of Mexico;
     o    targeting a number of  exploration  prospects,  primarily in the North
          Sea; and
     o    advancing our Horn River shale gas play with our fracing  campaign and
          doubling our shale gas land position in northeast British Columbia.

Details of our capital programs are set out below:

                                             Three Months          Six Months
                                            Ended June 30       Ended June 30
                                                     2010                2010
--------------------------------------------------------------------------------
Oil and Gas
    United Kingdom                                    144                 273
    Canada                                            311                 385
    Synthetic (mainly Long Lake)                       44                 108
    Syncrude                                           24                  43
    United States                                      64                 128
    Yemen                                              17                  27
    Nigeria                                           126                 218
    Other Countries                                    17                  57
                                         --------------------------------------
                                                      747               1,239
Chemicals                                              53                 102
Energy Marketing, Corporate and Other                  17                  32
                                         --------------------------------------
Total Capital                                         817               1,373
                                         ======================================

UNITED KINGDOM - NORTH SEA
During the quarter,  we completed  drilling a successful  appraisal  well at our
Blackbird oil discovery,  a potential tie-back to Ettrick.  The well was drilled
in a water depth of  approximately  367 feet to a total measured depth of 12,000
feet. We are currently  acquiring  extensive wireline log and core data over the
reservoir section for further analysis. We plan to complete the well and conduct
a drill stem test later this month.  If  successful,  the well will be suspended
for future use as an oil producer. We have a 79.73% operated interest here.


                                       34
<PAGE>


Elsewhere in the North Sea, the Golden Eagle area is a  significant  development
opportunity  for us. We are in the  process of  completing  the  acquisition  of
additional  acreage in the area and plan to drill an exploration well here later
this year. Golden Eagle area development  supports standalone  facilities and is
economic with oil prices  significantly  lower than they are  currently.  We are
assessing  development  options  for the  area and will  select  an  appropriate
configuration  for  sanctioning  in 2011.  We have a 34% interest in both Golden
Eagle and Hobby, a 46% interest in Pink, and operate all three.

At Buzzard,  we have a number of opportunities  to potentially add reserves.  In
the northern  part of the field,  we are seeing more oil above the water contact
which  should  lead to more  recoverable  oil.  In the  south,  we plan to drill
Bluebell,  a possible  extension of the Buzzard  field.  At Polecat,  a previous
discovery  east of Buzzard,  we plan to drill an  appraisal  well which could be
tied back to the Buzzard platform.

West of the Shetland  Islands,  we are finalizing  plans to drill the North Uist
prospect.  We have a 35% non-operated  working interest here and expect to drill
the well later this year.  This  prospect  has a target  size much  larger  than
typical North Sea targets.

CANADA - HORN RIVER SHALE GAS
In the first quarter,  we completed  drilling our eight-well program in the Horn
River and realized substantial cost savings and productivity  improvements.  Our
average  drilling  days per well were under 25 days,  down 35% from our previous
program while  drilling 80% more  reservoir  length.  We recently  began fracing
these wells and plan to conduct 18 fracs per well.  First production is expected
before year end, ramping up to 50 mmcf/d in early 2011.

As previously  announced,  we have approximately  90,000 acres at Dilly Creek in
the Horn River  basin and 38,000  acres at Cordova.  Following  our success at a
June land sale,  we have  increased  our  position  from  128,000  acres to over
300,000 acres of shale gas lands in northeast British Columbia.

SYNTHETIC
The upgrader is performing well and is consistently  processing virtually all of
our  bitumen  production  as well as 9,000  bbls/d  of  purchased  bitumen.  The
gasification  process is working,  creating a low-cost fuel source which reduces
our need to purchase  natural gas for operations and will generate a significant
margin advantage over our peers, even at current low gas prices.

Bitumen  production  to feed the upgrader  continues  to ramp up  following  the
completion of the turnaround last fall as we have  significantly  improved steam
reliability  and are  optimizing  our wells.  Steam rates have more than doubled
from  pre-turnaround  levels and we are  currently  at  all-time  highs of about
150,000  bbls/d.  As a result,  we are injecting more steam into more wells than
ever before with 68 of 91 well pairs now on production and steam  circulating in
an additional 13 pairs.  These circulating wells will be converted to production
over the next few months.

As we provide  consistent steam to the reservoir,  we are focusing on optimizing
steam  injection and  individual  well  performance.  To support  increased well
productivity,  we have converted 54 wells from gas lift to electric  submersible
pumping and expect to convert the remainder, when appropriate.  This offers more
flexibility to optimize steam injection and grow bitumen production.

Our all-in  steam-to-oil  ratio (SOR) is between five and six and includes steam
to wells that are still in the steam  circulation stage and wells early in their
growth cycle. As our circulating wells start producing bitumen, we expect to see
an increase in production rates with a corresponding decrease in SOR. The SOR of
our mature producing wells is now four and improving.

We continue to pursue  inexpensive  ways to add bitumen  capacity  since bitumen
production in excess of upgrader capacity can be sold for an attractive  return.
As a result,  we are continuing with the development of two additional well pads
and  have  commenced  engineering  work  to  add  two  more  once-through  steam
generators  over the next 18 to 24 months.  These steam  generators can be added
for a cost of about $100 million ($150 million gross).

Phase 1 of our Long Lake project is designed to produce  72,000  bbls/d of gross
bitumen,  upgraded to approximately  60,000 bbls/d (39,000 bbls/d, net to us) of
PSCTM.  We are committed to the  development of our oil sands leases and plan to
develop  Phase 2 in two  smaller  SAGD stages of about  40,000  bbls/d each with
upgrading available after ramp up.

UNITED STATES - GULF OF MEXICO
At Knotty Head, we completed  drilling an appraisal well before the  moratorium.
We are currently  evaluating results,  considering  possible development choices
and continuing our efforts to unitize our lands with adjacent acreage.  No other
drilling was planned in the near term. We are the operator of Knotty Head with a
25% working interest.




                                       35
<PAGE>

In the first  quarter,  we made a  significant  discovery  in the  deepwater  at
Appomattox,  located in  Mississippi  Canyon  blocks  391 and 392.  This has the
potential to be our best  discovery in the Gulf of Mexico.  Drilling  activities
resulted in a light oil discovery with excellent reservoir quality, following an
exploration well and two appraisal sidetracks. Appomattox is the third discovery
in the area following  earlier  discoveries at Shiloh and Vicksburg.  Additional
appraisal wells for Appomattox  were being  considered for later in the year but
have been  delayed  as a result  of the  drilling  moratorium.  We  continue  to
investigate development options for Appomattox and Vicksburg,  located six miles
east. We have a 25% interest in Vicksburg  and a 20% interest in Appomattox  and
Shiloh. Shell Offshore Inc. operates all three discoveries.

Our plans to drill two additional exploration wells later this year with two new
deep-water drilling rigs have been delayed by the drilling moratorium. The first
deep-water rig, the Ensco 8501,  completed  drilling an appraisal well at Knotty
Head and is currently  being used by the third party we share the rig with.  The
second rig, the Ensco 8502, has arrived in the Gulf and is undergoing sea trials
prior to its acceptance.  The drilling  moratorium and new regulations may delay
rig  acceptance.  To date, the moratorium has not resulted in any cash costs and
for the remainder of the six month period,  we expect our costs to be modest, if
anything.

OFFSHORE WEST AFRICA
Development of the Usan field is progressing well with first production expected
in 2012. The development  includes a floating  production and storage offloading
(FPSO) vessel with the ability to process  180,000  bbls/d (36,000 bbls/d net to
us) and store up to two million  barrels of oil. In June,  major topside modules
were lifted onto the FPSO deck and the FPSO unit is almost 80% complete. We have
a 20%  interest  in  exploration  and  development  on this  block and Total E&P
Nigeria Limited is the operator.

We  continue  to  explore  offshore  West  Africa  and  previously  announced  a
successful  exploration well at Owowo in the southern portion of Oil Prospecting
License (OPL) 223. We have an 18% interest in this discovery.

YEMEN
Yemen is an important asset for us and continues to generate cash flow in excess
of capital requirements.  In December 2011, our production sharing contract with
the Yemen government  expires.  We are currently  working on a possible contract
extension.



                                       36
<PAGE>


FINANCIAL RESULTS

CHANGE IN NET INCOME

<TABLE>
<CAPTION>
                                                                                                        2010 VS 2009
                                                                                             Three Months         Six Months
                                                                                            Ended June 30      Ended June 30
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                  <C>                <C>
NET INCOME AT JUNE 30, 2009(1)                                                                         20                155
                                                                                         -------------------------------------
     Favorable (unfavorable) variances(2):

         Realized Commodity Prices
              Crude Oil                                                                               112                522
              Natural Gas                                                                              11                 12
                                                                                         -------------------------------------
                  Total Price Variance                                                                123                534

         Production Volumes, After Royalties
              Crude Oil                                                                                81                 66
              Natural Gas                                                                              16                 50
              Changes in Crude Oil Inventory For Sale                                                  34                 72
                                                                                         -------------------------------------
                  Total Volume Variance                                                               131                188

         Oil and Gas Operating Expense                                                                (86)              (198)

         Oil and Gas Depreciation, Depletion, Amortization and Impairment                              (7)                12

         Exploration Expense                                                                           27                (13)

         Energy Marketing Revenue, Net                                                                (43)              (194)

         Chemicals Contribution                                                                       (32)               (28)

         General and Administrative Expense (3)                                                        92                 74

         Interest Expense                                                                              (3)               (15)

         Current Income Taxes                                                                         (58)              (199)
         Future Income Taxes                                                                         (149)              (136)

         Change in Fair Value of Crude Oil Put Options                                                181                181
         Other                                                                                         59                 79
                                                                                         -------------------------------------

NET INCOME AT JUNE 30, 2010                                                                           255                440
                                                                                         =====================================
</TABLE>

(1)  Includes  results of discontinued  operations (See Note 15 of our Unaudited
     Consolidated  Financial  Statements).
(2)  All amounts are presented  before  provision for income taxes.
(3)  Includes stock-based compensation expense.


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


                                       37
<PAGE>


OIL & GAS

PRODUCTION (BEFORE ROYALTIES)(1)
<TABLE>
<CAPTION>

                                                                                   Three Months              Six Months
                                                                                  Ended June 30             Ended June 30
                                                                                2010         2009         2010         2009
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                          <C>          <C>           <C>          <C>
Crude Oil and Liquids (mbbls/d)
   United Kingdom                                                              98.2         97.7         101.9        100.7
   Canada (2)                                                                  13.1         14.9          13.7         15.1
   Long Lake Bitumen                                                           16.2          9.3          14.2          8.7
   Syncrude                                                                    23.4         14.9          21.5         17.3
   United States                                                                9.9         12.1           9.8         11.2
   Yemen                                                                       40.9         51.5          41.9         52.9
   Other Countries                                                              2.1          3.6           2.2          4.5
                                                                         ---------------------------------------------------
                                                                              203.8        204.0         205.2        210.4
                                                                         ---------------------------------------------------
Natural Gas (mmcf/d)
   United Kingdom                                                                40           18           40            18
   Canada (2)                                                                   128          136          130           138
   United States                                                                 96           61           98            56
                                                                         ---------------------------------------------------
                                                                                264          215          268           212
                                                                         ---------------------------------------------------

Total Production (mboe/d)                                                       248          240          250           246
                                                                         ===================================================
</TABLE>

PRODUCTION (AFTER ROYALTIES)
<TABLE>
<CAPTION>
                                                                                   Three Months              Six Months
                                                                                  Ended June 30             Ended June 30
                                                                                2010         2009         2010         2009
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                         <C>          <C>           <C>          <C>
Crude Oil and Liquids (mbbls/d)
   United Kingdom                                                              98.2         97.6         101.9        100.6
   Canada (2)                                                                  10.0         11.2          10.4         11.8
   Long Lake Bitumen                                                           15.7          9.2          13.5          8.6
   Syncrude                                                                    21.5         13.0          19.7         16.3
   United States                                                                8.9         10.9           8.9         10.2
   Yemen                                                                       22.2         29.0          22.6         32.3
   Other Countries                                                              2.0          3.3           2.1          4.2
                                                                         ---------------------------------------------------
                                                                              178.5        174.2         179.1        184.0
                                                                         ---------------------------------------------------
Natural Gas (mmcf/d)
   United Kingdom                                                                40            18          40            18
   Canada (2)                                                                   117           129         119           127
   United States                                                                 83            54          85            50
                                                                         ---------------------------------------------------
                                                                                240           201         244           195
                                                                         ---------------------------------------------------

Total Production (mboe/d)                                                       218           208         220           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)  Includes the following production from discontinued operations. See Note 15
     of our Unaudited Consolidated Financial Statements.

<TABLE>
<CAPTION>
                                                                                   Three Months               Six Months
                                                                                   Ended June 30             Ended June 30
                                                                                2010         2009         2010         2009
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>          <C>          <C>          <C>
   Before Royalties
       Crude Oil and NGLs (mbbls/d)                                             13.1         14.9         13.7         15.1
       Natural Gas (mmcf/d)                                                       11           13           11           15
   After Royalties
       Crude Oil and NGLs (mbbls/d)                                             10.0         11.2         10.4         11.8
       Natural Gas (mmcf/d)                                                       10           13           10           13
                                                                         ---------------------------------------------------
</TABLE>


                                       38
<PAGE>



HIGHER VOLUMES INCREASED NET INCOME FOR THE QUARTER BY $131 MILLION
Production before royalties  increased 3% from last year as higher Long Lake and
Syncrude  production  were  partially  offset by natural  declines  in Yemen and
Canada. Compared to the previous quarter,  production before royalties decreased
2% where lower production in the UK North Sea as a result of temporary  downtime
at  Buzzard  was  partially  offset  by  production  increases  at Long Lake and
Syncrude.  Production  after royalties was marginally  lower than both the prior
quarter and last year.

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

                                                Before                After
(mboe/d)                                     Royalties            Royalties
-----------------------------------------------------------------------------
Production, first quarter 2010                     252                 221
   Production changes:
       Syncrude                                      4                   4
       Long Lake Bitumen                             4                   4
       United Kingdom                               (7)                 (7)
       Canada                                       (2)                 (2)
       Yemen                                        (2)                 (1)
       United States                                (1)                 (1)
                                          -----------------------------------
Production, second quarter 2010                    248                 218
                                          ===================================

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

UNITED KINGDOM
Production  volumes in the UK North Sea decreased 7% from the previous  quarter,
while increasing 4% from the second quarter of 2009. The decrease from the prior
quarter was  primarily  due to the planned  downtime at Buzzard to complete  the
installation  of the new platform to handle  produced H2S.  While  downtime also
reduced  production  compared  to the same  period  last year,  it was more than
offset by higher volumes at Scott/Telford and Ettrick.

Buzzard  production  averaged  71,100 boe/d for the quarter,  16% lower than the
prior  quarter  and 19% lower than the second  quarter  of 2009.  As  previously
announced,  production  was  shut in at  Buzzard  in  early  May to  accommodate
installation of the topsides on the fourth  platform.  During this time, we also
permanently  repaired a separator unit that contributed to downtime in the first
quarter.  On  completion  of the  installation  and  maintenance  work,  Buzzard
produced at reduced rates of  approximately  55,000 boe/d.  Full  production was
restored in late May, two days ahead of schedule.

Production at  Scott/Telford  averaged 17,800 boe/d.  Water  injection  flowline
limitations  at Telford  decreased  production  13% from the  previous  quarter.
However,  compared to the same period last year, production has increased 75% as
a result of a successful  step-out  development well, which was tied back to our
Scott  platform in the third  quarter of 2009. In early July, a valve failure on
the Forties pipeline system required us to shut in our production from the Scott
platform. The operator is currently determining the root cause and the nature of
the repairs.  While the operator  undertakes  this work,  we are  advancing  our
shutdown at Scott that was planned for later this summer.

Production  from our Ettrick  field more than doubled over the prior quarter and
averaged 14,000 boe/d net to us. Ettrick is currently producing at approximately
24,000 boe/d gross (20,000 boe/d net to us) and continues to ramp up.

CANADA
Production  in Canada was 5% lower than the  previous  quarter and 9% lower than
the second  quarter of 2009  primarily  as a result of natural  declines  at our
heavy oil  properties.  CBM  production  was  slightly  reduced  due to  natural
declines and maintenance work.  During the quarter,  we agreed to sell our heavy
oil properties to a third party.  These  properties are producing  approximately
15,000  boe/d and the sale is expected to close in the third  quarter  following
receipt of regulatory approvals.

We  continue  to invest in our shale gas  project in the Dilly Creek area of the
Horn River basin in north-east British Columbia.  We currently have six wells on
production and they are meeting production and decline profile expectations.  In
the first  quarter,  we completed  drilling our  eight-well  program in the Horn
River and realized  substantial cost savings and productivity  improvements.  We
recently began fracing these wells and plan to conduct 18 fracs per well.  First
production from these wells is expected before year end, ramping up to 50 mmcf/d
in early 2011.


                                       39
<PAGE>

LONG LAKE

Bitumen  production  to feed the upgrader  continues  to ramp up  following  the
completion of the turnaround last fall as we have  significantly  improved steam
reliability  and are  optimizing  our wells.  Steam rates have more than doubled
from  pre-turnaround  levels and we are  currently  at  all-time  highs of about
150,000  bbls/d.  As a result,  we are injecting more steam into more wells than
ever before with 68 of 91 well pairs now on production and steam  circulating in
an additional 13 pairs.  These circulating wells will be converted to production
over the next few months. The table below shows gross monthly bitumen production
volumes for the current year.

                                                           Gross Bitumen
Month                                                    Volumes (bbls/d)
-------------------------------------------------------------------------
January 2010                                                      16,300
February 2010                                                     17,700
March 2010                                                        21,900
April 2010                                                        24,400
May 2010                                                          23,600
June 2010                                                         26,900
July 2010 - Month to date                                         28,500
-------------------------------------------------------------------------

As we provide  consistent steam to the reservoir,  we are focusing on optimizing
steam  injection and  individual  well  performance.  To support  increased well
productivity,  we have converted 54 wells from gas lift to electric  submersible
pumping and expect to convert the remainder, when appropriate.  This offers more
flexibility to optimize steam injection and grow bitumen production.

SYNCRUDE
Syncrude production  averaged 23,400 boe/d for the quarter.  This was 20% higher
than  the  previous  quarter  when  production  was  reduced  as a  result  of a
turnaround of the LC finer.  Production was 57% higher than last year when Coker
8-3 was undergoing  regular  maintenance.  Additionally,  outages in the Pembina
pipeline reduced shipments of synthetic crude in the second quarter of 2009.

UNITED STATES
Production  in the Gulf of  Mexico  averaged  25,900  boe/d,  3% lower  than the
previous  quarter.  The reduced  volumes were  primarily  due to downtime at the
Longhorn field for maintenance  work and tie-in of a third-party  development to
the  Corral  platform.  Elsewhere  in  the  Gulf,  production  decreases  due to
additional maintenance downtime were offset by successful recompletion projects.

Compared to the same period last year,  production  increased 16% as a result of
the  Longhorn  development  which came  on-stream  in late 2009.  Production  at
Longhorn  averaged  7,800 boe/d in the  quarter.  The impact of this  production
increase was partially  offset by natural field declines at Aspen,  Gunnison and
Wrigley.

The six month drilling  moratorium in the Gulf of Mexico has no material  impact
on our current  operations.  Our shelf and deep-water  production are unaffected
and we continue to expect our Gulf of Mexico  production for the year to average
between 20,000 and 28,000 boe/d before royalties  (17,000 and 25,000 boe/d after
royalties).

YEMEN
Yemen production averaged 40,900 boe/d for the quarter, down 4% and 21% from the
previous  quarter  and  last  year,  respectively.  The  production  decline  is
consistent with  expectations  as the fields mature and development  drilling is
reduced as we approach the  scheduled  end of the contract  term.  Decline rates
have been  moderated as we  undertake  well  recompletions  and  maintenance  to
maximize the existing  wells. At Masila,  we completed our development  drilling
program by drilling 11 wells in the first half of the year. At Block 51, we have
drilled two development wells to date and expect to drill three additional wells
in the second half of the year.  Production  declines  in Yemen are  expected to
continue as we focus on maximizing recovery of the remaining reserves.

We  continue  to work with the Yemen  government  and our  partners to obtain an
extension to our production-sharing  agreement beyond the current expiry date of
December 17, 2011. There is no assurance that this extension will be received.

OTHER COUNTRIES
Our share of production  from the Guando field in Colombia  averaged 2,100 boe/d
for the quarter.  This was 9% lower than the previous quarter and 42% lower than
the same period last year.  The decrease in volumes is a result of the reduction
in our working  interest in the Guando field,  effective  the second  quarter of
2009, on achieving pre-set production levels.



                                       40
<PAGE>


COMMODITY PRICES
<TABLE>
<CAPTION>
                                                                                  Three Months                 Six Months
                                                                                 Ended June 30               Ended June 30
                                                                               2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                         <C>           <C>           <C>          <C>
CRUDE OIL
   West Texas Intermediate (WTI) (US$/bbl)                                    78.03         59.62         78.37        51.35
   Dated Brent (Brent) (US$/bbl)                                              78.30         58.79         77.26        51.60
                                                                         -------------------------------------------------------

   Benchmark Differentials (1) (US$/bbl)
         Heavy Oil                                                            14.37          7.73         11.81         8.45
         Mars                                                                  0.60          2.27          1.79         0.80
         Masila                                                               (0.68)         0.93          0.47         0.49

   Realized Prices from Producing Assets (Cdn$/bbl)
         United Kingdom                                                       77.18         69.42         77.21        60.38
         Canada                                                               57.24         56.05         61.37        45.49
         Long Lake Synthetic                                                  74.08             -         76.80            -
         Syncrude                                                             77.93         71.58         80.46        62.44
         United States                                                        73.60         66.23         76.34        57.05
         Yemen                                                                80.50         69.40         80.44        60.63
         Other Countries                                                      74.77         66.83         76.88        51.63

   Corporate Average (Cdn$/bbl)                                               76.23         68.32         77.11        59.12
                                                                         -------------------------------------------------------

NATURAL GAS
   New York Mercantile Exchange (US$/mmbtu)                                    4.34          3.81          4.69         4.15
   AECO (Cdn$/mcf)                                                             3.66          3.47          4.37         4.41
                                                                         -------------------------------------------------------

   Realized Prices from Producing Assets (Cdn$/mcf)
         United Kingdom                                                        4.80          3.67          4.80         4.69
         Canada                                                                3.72          3.42          4.38         4.09
         United States                                                         5.14          4.58          5.58         5.19

   Corporate Average (Cdn$/mcf)                                                4.42          3.77          4.89         4.43
                                                                         -------------------------------------------------------

NEXEN'S AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe)                         67.46         61.28         68.78        54.28
                                                                         -------------------------------------------------------

AVERAGE FOREIGN EXCHANGE RATE - Canadian to US Dollar                        0.9731         0.8571       0.9673       0.8290
                                                                         -------------------------------------------------------
</TABLE>

(1)  These differentials are a discount/(premium) to WTI.

HIGHER COMMODITY PRICES INCREASED QUARTERLY NET INCOME BY $123 MILLION
WTI averaged US$78.03/bbl for the quarter,  consistent with the previous quarter
but 31% higher when compared to last year. Dated Brent averaged US$78.30/bbl for
the  quarter,  3% and 33%  higher  than the  previous  quarter  and prior  year,
respectively.  These price increases have been mitigated  somewhat by the weaker
US dollar.  Our  realized  oil price  averaged  $76.23/bbl,  12% higher than the
second quarter of 2009.

Natural  gas  prices  decreased   during  the  quarter,   with  NYMEX  averaging
US$4.34/mmbtu and AECO averaging $3.66/mcf, 14% and 28% lower, respectively than
the previous  quarter.  As a result,  our realized  gas price  decreased  18% to
average $4.42/mcf. Compared to the same period last year, our realized gas price
is 17% higher as NYMEX increased 14% and AECO increased 6%.

The US dollar has weakened  considerably against the Canadian dollar since 2009.
This has reduced our net sales by  approximately  $181 million,  as our realized
crude oil and gas prices were  $10.32/bbl  and  $0.60/mcf  lower,  respectively.
However,  our US-denominated  costs and US-denominated  debt are also lower when
translated to Canadian dollars as a result of the weaker US dollar.




                                       41
<PAGE>


CRUDE OIL REFERENCE PRICES
Crude oil  prices  were 31%  higher  than the second  quarter  2009.  WTI traded
between  US$65/bbl and  US$80/bbl  for the quarter.  Prices were volatile due to
conflicting  drivers.  Weak  near-term  market  fundamentals  and concerns about
sovereign debt levels and a double-dip  recession  placed  downward  pressure on
crude oil prices,  whereas continued  investment in commodity markets and strong
oil market  fundamentals in the medium term due to stronger demand from emerging
markets and tightening supply, supported prices.

Global crude oil inventory  levels remain high and recent OPEC supply growth has
diminished expectations that inventories will be reduced by the typical seasonal
increase in demand.  Higher OPEC  supply  increased  US imports of crude oil and
contributed to higher inventory levels at Cushing.

The global  economy  continues  to  recover  from the  financial  crisis but the
recovery is tentative  and risks remain that could lead to slower  global growth
and lower demand for crude oil.  There are concerns that the US and Europe could
experience  a  sustained  period of low  growth  and  deflation  similar to that
experienced  in Japan over the last  decade.  Countries  are facing  pressure to
impose fiscal restraints to avoid a debt crisis similar to Greece,  and China is
withdrawing  economic and financial  stimuli because of concerns about inflation
and an  overheating  economy.  Despite  these  concerns,  recent  macro-economic
indicators have been positive.  Increased world trade flows,  higher  industrial
production  and  positive   manufacturing   surveys   results  all  point  to  a
strengthening global economy.

Geopolitical  events such as expectations of United Nation's  sanctions  against
Iran,  escalating tensions between North and South Korea,  continuing attacks to
oil  infrastructure in Nigeria and the ongoing wars in Iraq and Afghanistan have
not had a material  impact on oil prices  during the  quarter.  However,  a much
tighter   supply/demand   environment   will  increase   price   sensitivity  to
geopolitical  events. The six month drilling moratorium in the US is expected to
delay new field start-ups and accelerate decline rates reducing crude oil supply
which should support future crude oil prices.

CRUDE OIL DIFFERENTIALS
Unplanned turnarounds and refinery downtime caused the heavy oil differential to
fluctuate  during the quarter.  In June, the  differential  returned to narrower
levels seen earlier this year. In the longer term, differentials are expected to
be narrower  than  historic  levels due to declining  heavy oil  production  and
excess heavy refinery capacity.

The  Brent/WTI  differential  traded at a premium to WTI for most of the quarter
primarily  due to lower WTI prices caused by high  inventory  levels at Cushing.
Brent  prices were also  supported by  maintenance  downtime at North Sea fields
which reduced supply.

The Masila  price  strengthened  relative to WTI  following  the movement in the
WTI/Brent  differential and reflecting  strong demand from China and other Asian
countries that are the primary buyers of Masila crude.

Excess global refining capacity,  OPEC cuts in medium crude, declining heavy oil
production  and  high  inventory  levels  at  Cushing  also  supported  the Mars
differential.

NATURAL GAS REFERENCE PRICES
NYMEX  natural  gas prices  continued  to decline due to warm  weather  reducing
demand while supply  remained  strong.  Natural gas producers  continue to drill
despite low prices,  partly to avoid losing land leases. Gas prices are expected
to remain low until  inventory  levels are reduced by lower  supply or increased
demand from strong economic growth, a hot summer or an active hurricane season.




                                       42
<PAGE>


OPERATING EXPENSES(1)

<TABLE>
<CAPTION>
                                                                                  Three Months                Six Months
                                                                                 Ended June 30              Ended June 30
(Cdn$/boe)                                                                      2010         2009         2010         2009
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                           <C>          <C>           <C>         <C>
Operating expenses based on our production before royalties (2)
   Conventional Oil and Gas                                                     9.42         8.80          9.18        8.53
   Long Lake Synthetic (3)                                                     88.39            -        112.71           -
   Syncrude                                                                    33.33        57.21         35.64       45.70
   Average Oil and Gas                                                         15.07        11.95         15.12       11.27
                                                                         ---------------------------------------------------

Operating expenses based on our production after royalties
   Conventional Oil and Gas                                                    10.75        10.28         10.56        9.86
   Long Lake Synthetic (3)                                                     91.67            -        117.63           -
   Syncrude                                                                    36.22        65.36         38.83       48.59
   Average Oil and Gas                                                         17.05        13.94         17.24       12.95
                                                                         ---------------------------------------------------
</TABLE>
(1)  Includes  results of discontinued  operations (See Note 15 of our Unaudited
     Consolidated Financial Statements).
(2)  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.
(3)  Excludes activities related to third-party bitumen purchased, processed and
     sold.

HIGHER OPERATING EXPENSES REDUCED QUARTERLY NET INCOME BY $86 MILLION
Operating  costs  increased $86 million or 34% from the previous year  primarily
due to costs  associated  with our Long Lake project.  As of January 1, 2010, we
ceased  capitalizing our Long Lake start-up costs. Total operating costs at Long
Lake have largely remained flat since the first quarter as most of the costs are
fixed.  With  growing  volumes,  our Long  Lake per unit  operating  costs  have
improved  43% over the  previous  quarter.  When fully ramped up, we expect Long
Lake operating costs to be about $25 to $30/bbl.

Changes in  production  mix with i) natural  declines  in Canada and Yemen;  ii)
higher  production  at  Scott/Telford  in the  North  Sea,  partially  offset by
decreases at Buzzard;  iii) increased production at Syncrude;  and iv) inclusion
of Long Lake operating costs, have increased our corporate average by $2.48/boe.
The  stronger  Canadian  dollar  reduced our  corporate  average by $1.16/boe as
operating  costs  of our  international  and US  assets  are  denominated  in US
dollars.

In the UK North Sea,  Buzzard  operating costs were consistent with the previous
year;  however,  production was temporarily  lower following the installation of
the new platform  topside  facilities and other planned  maintenance  work. This
increased our corporate average operating cost by $0.31/boe. Elsewhere in the UK
North Sea, our corporate  average was lower by $0.61/boe as higher production at
Scott/Telford  and Ettrick reduced our average cost per barrel. We expect to see
these unit costs decrease further as Ettrick ramps up to full production.

As expected, increased maintenance costs and natural declines in Yemen increased
our corporate  average cost per barrel by $0.33/boe.  We continue to incur costs
to maintain existing well  productivity to maximize reserve  recoveries and slow
the natural decline of the field.  In the US Gulf of Mexico,  increased costs of
recompletions   and  maintenance   were  partially  offset  by  higher  volumes,
increasing our corporate average operating cost by $0.14/boe.

In Canada, lower heavy oil downhole and surface maintenance costs were partially
offset by an  increase  in natural  gas  maintenance  activities.  These  costs,
combined with lower production due to natural declines,  increased our corporate
average by $0.15/boe. At Syncrude, lower maintenance costs and higher production
volumes  decreased our corporate  average by $2.30/boe.  Coker 8-3 was operating
for the  majority of the quarter  compared to the same period last year,  when a
major scheduled turnaround shut in production for most of the quarter.


                                       43
<PAGE>



DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT (DD&A)(1)

<TABLE>
<CAPTION>
                                                                                  Three Months                Six Months
                                                                                  Ended June 30             Ended June 30
(Cdn$/boe)                                                                      2010         2009         2010         2009
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                          <C>          <C>           <C>         <C>
DD&A based on our production before royalties (2)
   Conventional Oil and Gas                                                    17.64        18.49         17.09       18.53
   Long Lake Synthetic                                                         21.10            -         21.60           -
   Syncrude                                                                     6.71         6.31          6.85        6.40
   Average Oil and Gas                                                         16.79        17.69         16.41       17.64
                                                                         ---------------------------------------------------

DD&A based on our production after royalties
   Conventional Oil and Gas                                                    20.14        21.59         19.65       21.43
   Long Lake Synthetic                                                         21.85            -         22.43           -
   Syncrude                                                                     7.29         7.21          7.47        6.80
   Average Oil and Gas                                                         18.97        20.64         18.69       20.26
                                                                         ---------------------------------------------------
</TABLE>

(1)  Includes  results of discontinued  operations (See Note 15 of our Unaudited
     Consolidated Financial Statements).
(2)  DD&A per boe is our DD&A for oil and gas operations  divided by our working
     interest production before royalties. We use production before royalties to
     monitor  our  performance  consistent  with  other  Canadian  oil  and  gas
     companies.


HIGHER OIL AND GAS DD&A DECREASED NET INCOME FOR THE QUARTER BY $7 MILLION
Our average DD&A per-unit cost  decreased  $0.90/boe  despite an increase in our
DD&A expense of $7 million.  The stronger  Canadian dollar reduced our corporate
average  by  $2.29/boe  as  depletion  of our  international  and US  assets  is
denominated  in US  dollars.  This  was  partially  offset  by  changes  in  our
production  mix as temporary  decreases  in Buzzard  production  were  partially
offset by new  production at Ettrick and the  commencement  of depletion at Long
Lake. This increased our average DD&A rate by $2.18/boe.  Buzzard DD&A rates are
lower than our corporate  average,  whereas per-unit  depletion rates at Ettrick
and Long Lake are higher.  Depletion  at Long Lake  increased  our  consolidated
average cost by $0.90/boe.

In the UK North Sea,  additional proved reserves booked at Buzzard at the end of
2009 lowered the depletion rate and reduced our corporate  average by $0.55/boe.
The remainder of our UK fields decreased our corporate average by $0.26/boe.

Depletion  rates in Yemen  increased our  corporate  average  $0.24/boe.  As the
fields mature and production  declines,  our capital is focused on accessing the
remaining  reserves,  thereby  increasing  our depletion  rates.  In the Gulf of
Mexico,  positive  reserve  revisions  at the end of 2009,  combined  with lower
estimates for future abandonment costs,  reduced our corporate average depletion
rate of $1.02/boe.

Canadian  depletion  costs were lower than the second quarter of 2009 decreasing
our corporate average by $0.12/boe.  DD&A at our heavy oil properties  decreased
$20  million or 63% from last year as: i)  depletion  rates were lower than last
year due to positive price-related reserve revisions at the end of 2009; and ii)
depletion of these  assets  ceased when the assets were  classified  as held for
sale.  The effect of this was partially  offset by higher natural gas depletion.
Lower  natural  gas prices at the end of 2009  reduced  our CBM and  natural gas
reserve estimates and increased our depletion rate.



                                       44
<PAGE>


EXPLORATION EXPENSE(1)

                                      Three Months              Six Months
                                     Ended June 30             Ended June 30
                                   2010          2009       2010          2009
--------------------------------------------------------------------------------
Seismic                              17            31         29            43
Unsuccessful Drilling                 1            16         42            27
Other                                32            30         72            60
                               -------------------------------------------------
Total Exploration Expense            50            77        143           130
                               =================================================

(1)  Includes  results of discontinued  operations (See Note 15 of our Unaudited
     Consolidated Financial Statements).

LOWER EXPLORATION EXPENSE INCREASED NET INCOME FOR THE QUARTER BY $27 MILLION
In the Gulf of Mexico, we continue to evaluate our discovery at Appomattox where
we have drilled an exploratory well and two appraisal sidetracks.  Appomattox is
the third discovery in the area following previous successful drilling at Shiloh
and  Vicksburg.   We  continue  to  review  potential  development  options  for
Appomattox and Vicksburg.  Additional  appraisal drilling at Appomattox has been
delayed as a result of the six-month drilling  moratorium in the Gulf of Mexico.
We have a 25% interest in Vicksburg and a 20% interest in Appomattox and Shiloh,
with Shell Offshore Inc. operating all three.

In the UK, we are  assessing  development  options  for the Golden  Eagle  area.
Concept engineering is nearing completion and we expect to sanction  development
in the next year.  The Golden Eagle area  includes our 34% operated  interest in
Golden  Eagle  and Hobby  and our 46%  operated  interest  in Pink.  During  the
quarter,  we drilled a successful  appraisal  well at Blackbird,  six kilometres
south of our Ettrick  field.  Blackbird  is a potential  tie-back to the Ettrick
FPSO. We have an 80% operated interest at Blackbird. Later this year, we plan to
drill an exploration well at North Uist, west of the Shetlands,  where we have a
35% non-operated interest.

Exploration  expense  decreased  35% or $27  million  due to lower  seismic  and
unsuccessful  drilling  costs in the Gulf of Mexico.  In the  second  quarter of
2009,  we expensed  costs  related to  non-commercial  wells at Green Canyon and
Sapphire.

                                       45

<PAGE>


<TABLE>
<CAPTION>

ENERGY MARKETING
                                                                                   Three Months                 Six Months
                                                                                  Ended June 30               Ended June 30
                                                                                2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                           <C>           <C>          <C>           <C>
   Physical Sales (1)                                                          8,188        10,063        18,302        20,008
   Physical Purchases (1)                                                     (8,091)       (9,604)      (17,987)      (19,406)
   Net Financial Transactions (2)                                                 36          (276)          (28)         (228)
   Change in Fair Market Value of Inventory                                      (21)           38           (89)          114
                                                                         -------------------------------------------------------
Marketing Revenue                                                                112           221           198           488
   Transportation Expense                                                        (89)         (163)         (211)         (328)
   Other                                                                           7            (1)            6             4
                                                                         -------------------------------------------------------
NET MARKETING REVENUE                                                             30            57            (7)          164
                                                                         =======================================================
CONTRIBUTION TO NET MARKETING REVENUE BY REGION
   North America                                                                  22            55           (13)          159
   Asia                                                                            1             6             2            18
   Europe                                                                          7            (4)            4           (13)
                                                                         -------------------------------------------------------
NET MARKETING REVENUE                                                             30            57            (7)          164
   DD&A                                                                           (5)           (3)          (10)           (7)
   General and Administrative                                                    (11)          (26)          (32)          (49)
   Other (5)                                                                     (19)           (3)          (23)            -
                                                                         -------------------------------------------------------
MARKETING CONTRIBUTION TO INCOME BEFORE INCOME TAXES                              (5)           25           (72)          108
                                                                         =======================================================
NORTH AMERICA
   NATURAL GAS
   Physical Sales Volumes (3)  (bcf/d)                                           3.1           4.6           4.0            4.8
   Transportation Capacity (bcf/d)                                               1.4           1.3           1.4            1.3
   Storage Capacity (bcf)                                                       31.0          33.9          31.5           33.9
   Financial Volumes (4) (bcf/d)                                                 2.7          10.0           4.3           12.7
   CRUDE OIL
   Physical Sales Volumes (3) (mbbls/d)                                          889           873           822            835
   Storage Capacity (mbbls)                                                    2,750         2,644         2,858          2,644
   Financial Volumes (4) (mbbls/d)                                               794           667           775            789
   POWER
   Physical Sales Volumes (3) (GWh/d)                                              9            10             9              7
   Generation Capacity (MW)                                                       87            87            87             87
ASIA
   Physical Sales Volumes (3) (mbbls/d)                                          104           115            92             99
   Financial Volumes (4) (mbbls/d)                                               306           531           330            425
EUROPE
   Financial Volumes (4) (mbbls/d)                                               761           259           685            378
VALUE-AT-RISK
   Quarter-end                                                                     8            15             8             15
   High                                                                           15            19            15             24
   Low                                                                             7            13             7             13
   Average                                                                        12            15            12             17
                                                                         -------------------------------------------------------

(1)  Marketing's   physical   sales,   physical   purchases  and  net  financial
     transactions are reported within marketing revenue as detailed in the notes
     to the unaudited consolidated financial statements.
(2)  Net  financial  transactions  include  all  gains and  losses on  financial
     derivatives  and the  unrealized  portion of gains and  losses on  physical
     purchase and sale contracts.
(3)  Excludes  inter-segment  transactions.  Physical volumes  represent amounts
     delivered during the quarter.
(4)  Financial volumes represent amounts largely acquired to economically  hedge
     physical transactions during the quarter.
(5)  Includes non-cash  mark-to-market losses that will reverse with the sale of
     North America  Natural Gas Energy  Marketing as described in Note 15 of our
     Unaudited Consolidated Financial Statements.

</TABLE>



                                       46
<PAGE>



LOWER CONTRIBUTION FROM ENERGY MARKETING DECREASED NET INCOME BY $43 MILLION
During the quarter, we signed an agreement to sell our North America natural gas
marketing  business.  The transaction is expected to close in the third quarter,
subject to customary closing conditions. The sale is expected to be cash neutral
and we expect to recognize a non-cash  loss on the sale of between $250 and $290
million on closing.  This loss  primarily  relates to the  transfer of long-term
natural gas physical  transportation  commitments  that are less  valuable  with
increased  gas  supplies  that reduce the need for  transport  services.  In the
period between signing and closing,  we have agreements with the purchaser which
transfers the market risk of our contracts and inventory to the purchaser unless
we breach our  obligation  to close the sale.  Although  volatile on a quarterly
basis,  we have had success with our marketing  business over the last 10 years,
generating about $800 million of cash flow.

Our crude oil team generated  modest gains during the quarter  through  blending
opportunities and a weakening Canadian dollar. At this time last year, our crude
oil group  generated  modest  losses  largely  due to a  strengthening  Canadian
dollar. Gains were recognized in the first quarter of 2010 from our blending and
physical business.

Overall,  second quarter revenue from energy  marketing was lower than the prior
year largely driven by losses from North America  natural gas.  Since  mid-2008,
low natural  gas  prices,  high  inventory  levels and weak demand in  consuming
regions have  contributed to narrow location spreads making  transportation  and
storage assets less valuable.  In 2010, the team incurred losses associated with
transportation  used in the quarter,  while  generating  gains last year.  Those
gains were  generated  from the hedges in place to protect  the assets in future
periods which more than offset losses associated with transportation used in the
quarter.  Both our location and time spread  strategies  showed improved results
from the first quarter due to slightly improved market conditions.

COMPOSITION OF NET MARKETING REVENUE

<TABLE>
<CAPTION>
                                                                                   Three Months                 Six Months
                                                                                  Ended June 30                Ended June 30
                                                                                2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                              <C>           <C>           <C>          <C>
Trading Activities (Physical and related Financial)                               23            58           (13)          160
Other Activities                                                                   7            (1)            6             4
                                                                         -------------------------------------------------------
Total Net Marketing Revenue                                                       30            57            (7)          164
                                                                         =======================================================
</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, 2009.

At June 30,  2010,  the fair  value of our  derivative  contracts  in our energy
marketing  trading  activities was $56 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                                  (10)          (67)           (8)             -        (85)
  Level 2 - Based on Other Observable Pricing Inputs                  51            61             2              3        117
  Level 3 - Based on Unobservable Pricing Inputs                      11            13             -              -         24
                                                               -----------------------------------------------------------------
Total                                                                 52             7            (6)             3         56
                                                               =================================================================
</TABLE>



                                       47
<PAGE>



CHANGES IN FAIR VALUE OF DERIVATIVE CONTRACTS

                                                                          Total
-------------------------------------------------------------------------------
Fair Value at December 31, 2009                                              23
   Change in Fair Value of Contracts                                         27
   Net Losses (Gains) on Contracts Closed                                     6
   Changes in Valuation Techniques and Assumptions (1)                        -
                                                            -------------------
Fair Value at June 30, 2010                                                  56
                                                            ===================

(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 two years. Those maturing beyond one year
primarily relate to North American natural gas positions.

CHEMICALS

LOWER CHEMICALS CONTRIBUTION DECREASED NET INCOME BY $32 MILLION
Chlorate revenues in North America were marginally down from last year as higher
sales volumes were offset by a decline in realized prices.  Chlorate revenues in
Brazil were  consistent  with the second quarter of 2009 as higher prices offset
lower volumes.

Chlor-alkali revenue in North America fell 12% from the same period last year as
the  impact of a  decrease  in  realized  prices  was only  partially  offset by
increased volumes. In late June, the technology  conversion project (TCP) at the
North Vancouver  chlor-alkali  facility  successfully started up. It is expected
that TCP will  contribute $35 to $40 million in incremental  operating cash flow
annually,  beginning  in the third  quarter.  These  benefits are expected to be
generated  by lower  operating  costs and volume  expansion.  In Brazil,  higher
chlor-alkali prices were offset by lower volumes.

Chemicals net income includes foreign  exchange losses of $13 million,  compared
to the previous  year when it included  foreign  exchange  gains of $24 million.
Additionally, gains of $5 million related to interest swaps and foreign exchange
options and forwards were realized in the second quarter of 2009.

CORPORATE EXPENSES

<TABLE>
<CAPTION>
GENERAL AND ADMINISTRATIVE (G&A)(1)
                                                                                   Three Months                 Six Months
                                                                                  Ended June 30                Ended June 30
                                                                                2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                              <C>           <C>           <C>           <C>
General and Administrative Expense before Stock-Based                            110           111           226           211
Compensation
Stock-Based Compensation (2)                                                     (35)           56           (33)           56
                                                                         -------------------------------------------------------
Total General and Administrative Expense                                          75           167           193           267
                                                                         =======================================================
</TABLE>

(1)  Includes  results of discontinued  operations (See Note 15 of our Unaudited
     Consolidated Financial Statements).
(2)  Includes cash and non-cash  expenses related to our tandem option and stock
     appreciation rights plans.

LOWER G&A COSTS INCREASED NET INCOME BY $92 MILLION
Total G&A expenditures  for the quarter  decreased 55% from the same period last
year as a result of a decrease in stock-based compensation expense. Fluctuations
in our  share  price  create  volatility  in our net  income as we  account  for
stock-based  compensation using the intrinsic-value  method. During the quarter,
we reversed approximately $40 million of non-cash stock-based  compensation that
was recognized in prior periods as our share price  decreased 17%. Cash payments
made in connection with our stock-based  compensation  programs during the three
and six month  period  ended  June 30,  2010  were $5  million  and $8  million,
respectively (2009 - $14 million).



                                       48
<PAGE>



<TABLE>
<CAPTION>
INTEREST
                                                                                   Three Months                 Six Months
                                                                                  Ended June 30               Ended June 30
                                                                                2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>           <C>           <C>           <C>
Interest                                                                          99            92           197           186
   Less: Capitalized                                                             (22)          (18)          (40)          (44)
                                                                         -------------------------------------------------------
Net Interest Expense                                                              77            74           157           142
                                                                         =======================================================

Effective Interest Rate                                                         5.6%          4.5%          5.4%          4.7%
                                                                         -------------------------------------------------------
</TABLE>

HIGHER NET INTEREST EXPENSE REDUCED NET INCOME BY $3 MILLION
Our  financing  costs  increased $7 million from the second  quarter of 2009. In
July 2009, we issued US$1 billion of long-term notes which generated  additional
interest costs of $20 million.  This was partially  offset by the  strengthening
Canadian  dollar which  decreased  our  US-denominated  interest  expense by $14
million.

Capitalized  interest  was $4  million  higher  than  2009.  We  are  no  longer
capitalizing interest on our Ettrick development in the North Sea. This decrease
has been offset by higher capitalized  interest on our major development project
at Usan,  offshore West Africa.  We also continue to capitalize  interest on the
construction of the new platform at Buzzard and future phases of Long Lake.


<TABLE>
<CAPTION>
INCOME TAXES(1)
                                                                                   Three Months                 Six Months
                                                                                   Ended June 30               Ended June 30
                                                                                2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>           <C>           <C>           <C>
Current                                                                          264           206           523           324
Future                                                                           (80)         (229)         (180)         (316)
                                                                         -------------------------------------------------------
Total Provision for Income Taxes                                                 184           (23)          343             8
                                                                         =======================================================

(1)  Includes  results of discontinued  operations (See Note 15 of our Unaudited
     Consolidated Financial Statements).
</TABLE>

HIGHER TAXES REDUCED NET INCOME BY $207 MILLION
Stronger  commodity  prices  compared  to the same  period  last year  caused an
increase to our tax expense. Our future tax expense in 2009 was also impacted by
the  significant  decrease  in the value of our crude  oil put  options  and the
effect of a reduction in Canadian tax rates.  Our income tax provision  includes
current  taxes in the United  Kingdom,  Yemen,  Norway,  Colombia and the United
States.


<TABLE>
<CAPTION>
OTHER
                                                                                   Three Months                 Six Months
                                                                                   Ended June 30               Ended June 30
                                                                                2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>        <C>            <C>          <C>
Increase (Decrease) in Fair Value of Crude Oil Put Options                         1          (179)          (15)         (195)
                                                                         -------------------------------------------------------
</TABLE>

In the fourth  quarter of 2009, we purchased put options on 90,000 bbls/d of our
2010  crude  oil  production.  These  options  establish  a WTI  floor  price of
US$50/bbl  and provide a base level of price  protection  without  limiting  our
upside to higher  prices.  Options on 60,000  bbls/d settle  monthly,  while the
remaining  options  settle  annually.  These  options are recorded at fair value
throughout  their term. As a result,  changes in forward crude oil prices create
gains or losses on these  options  at each  period  end.  The put  options  were
purchased  for $39 million and are carried at fair value.  As at June 30,  2010,
the fair value of the options was  approximately  $2 million,  $1 million higher
than the end of the previous quarter but $15 million lower than the end of 2009.
For the three and six month  periods ended June 30, 2009, we recorded fair value
losses of $179 million and $195 million, respectively, on our 2009 crude oil put
option program.


During the  quarter,  we sold our  non-core  lands in the  Athabasca  region for
proceeds of $81 million.  We had no plans to develop  these lands for at least a
decade. We recognized a gain on the sale of $80 million.



                                       49
<PAGE>



LIQUIDITY AND CAPITAL RESOURCES

<TABLE>
<CAPTION>
CAPITAL STRUCTURE
                                                                                                   June 30        December 31
                                                                                                      2010               2009
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                 <C>                <C>
NET DEBT (1)
       Bank Debt                                                                                       930              1,803
       Public Senior Notes                                                                           5,038              4,982
                                                                                       ---------------------------------------
      Total Senior Debt                                                                              5,968              6,785
       Subordinated Debt                                                                               473                466
                                                                                       ---------------------------------------
      Total Debt                                                                                     6,441              7,251
       Less: Cash and Cash Equivalents                                                                (970)            (1,700)
                                                                                       ---------------------------------------
TOTAL NET DEBT                                                                                       5,471              5,551
                                                                                       =======================================

EQUITY AT HISTORIC ISSUE COST                                                                        8,080              7,646
                                                                                       =======================================

(1) Includes  all of our  borrowings  and is  calculated  as long-term  debt and
short-term borrowings less cash and cash equivalents.
</TABLE>

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
                                                                                                   2010                  2010
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                             <C>                 <C>
Capital Investment                                                                                 (817)               (1,373)
Cash Flow from Operating Activities (1)                                                             510                 1,308
                                                                                       ---------------------------------------
                                                                                                   (307)                  (65)

Proceeds on Disposition of Assets                                                                    81                    96
Dividends on Common Shares                                                                          (26)                  (52)
Issue of Common Shares                                                                               10                    35
Changes in Restricted Cash Requirements                                                              68                    83
Foreign Exchange Translation of US-dollar Debt and Cash                                            (227)                  (86)
Other                                                                                               (13)                   69
                                                                                       ---------------------------------------
Decrease/(Increase) in Net Debt                                                                    (414)                   80
                                                                                       =======================================
</TABLE>

(1)  Includes changes in non-cash working capital.  For the three and six months
     ended June 30, 2010,  outflows of $58 million and inflows of $198  million,
     respectively, was included.

Our net debt increased  approximately $400 million from March 31, primarily as a
result of i) capital  investment  exceeding  cash flow  generated from operating
activities;  and ii) foreign exchange  translation  losses on our US-denominated
debt.  Net debt is also  impacted  by  changes  in  working  capital.  Timing of
receipts from strong June oil and gas sales will be received in July.  These are
offset by  fluctuations  in cash tax  remittances to  governments.  We used cash
generated from operating activities and existing cash on hand to repay a portion
of our outstanding term credit facilities during the quarter,  while at the same
time, our available liquidity increased by $200 million during the quarter.  Our
available  liquidity at June 30, 2010 was approximately $3.8 billion,  comprised
of cash on hand and undrawn credit facilities. We expect our available liquidity
to increase by $900 million following the completion of our heavy oil and energy
marketing natural gas sales, anticipated for the third quarter.

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  periodically  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,  the movement in commodity  prices and
inventory cycles.



                                       50
<PAGE>



<TABLE>
<CAPTION>
CHANGE IN WORKING CAPITAL
                                                                              June 30       December 31           Increase/
                                                                                 2010              2009           (Decrease)
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>               <C>                    <C>
Cash and Cash Equivalents                                                         970             1,700                (730)
Restricted Cash                                                                   113               198                 (85)
Accounts Receivable                                                             2,675             2,788                (113)
Inventories and Supplies                                                          621               680                 (59)
Short-Term Borrowings                                                            (158)                -                (158)
Accounts Payable and Accrued Liabilities                                       (3,101)           (3,038)                (63)
Other                                                                              (9)               70                 (79)
                                                                      ------------------------------------------------------
Net Working Capital                                                             1,111             2,398
                                                                      ===================================
</TABLE>

Our non-cash working capital  balances remain largely  unchanged from the end of
2009.  Timing of cash tax  remittances  to  governments  during the year  create
fluctuations in cash taxes payable between quarters.

At June 30,  2010,  our  restricted  cash  consists  of margin  deposits of $113
million (December 31, 2009 - $198 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.

OUTLOOK FOR REMAINDER OF 2010

We expect  our 2010  production  to range  between  230,000  and  280,000  boe/d
(200,000 and 250,000 boe/d after royalties).

Our future  liquidity and ability to fully fund capital  requirements  generally
depend upon operating cash flows,  existing  working  capital,  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
approximately  85% of our  current  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$50/bbl  is  projected  to  increase  or  decrease  our cash  flow from
operating  activities,  after cash taxes, by  approximately  $23 million for the
second half of the year.  Our  exposure to a $0.01  change in the US to Canadian
dollar  exchange  rate is  projected  to increase  or decrease  our cash flow by
approximately  $17 million for the remainder of 2010. While commodity prices can
fluctuate significantly in the short term, we believe that over the longer term,
commodity  prices will continue to remain strong as a result of continued growth
in world demand and delays or shortages  in supply  growth.  We believe that our
existing  liquidity,  balance sheet capacity and capital investment  flexibility
provide us with the ability to fund our ongoing  obligations  during  periods of
lower commodity prices.

During the first half of the year,  we incurred  approximately  half of our 2010
capital  budget.  We currently  have  approximately  $1 billion of cash and cash
equivalents  on  hand  and as  well  as  significant  undrawn  committed  credit
facilities available. We also expect to generate over $900 million of additional
liquidity  in the  third  quarter,  upon  closing  the  sales of our  heavy  oil
properties  and natural  gas  marketing  businesses.  At June 30,  2010,  we had
unsecured  term credit  facilities  of US$3.1  billion in place of which  US$450
million  was drawn and  US$317  million  is being  used to  support  outstanding
letters of  credit.  We also have  approximately  $467  million of  uncommitted,
unsecured credit facilities,  of which $158 million was drawn and $24 million is
being   used  to  support   outstanding   letters   of   credit.   The   average
length-to-maturity of our public debt is approximately 19 years.


                                       51
<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 included these obligations
and commitments in our MD&A in our 2009 Form 10-K.

During the first quarter, we sold our European gas and power marketing business.
We agreed to maintain our  parental  guarantees  to the existing  counterparties
until the purchaser is able to replace them. At June 30, 2010 our total exposure
is $71 million.  The guarantees expire at the earlier of the purchaser replacing
the  guarantees  and  September  25, 2010. We are obligated to perform under the
guarantees  only  if  the  purchaser  does  not  meet  its  obligations  to  the
counterparties. To eliminate our exposure under the guarantees the purchaser has
provided us an indemnity and an irrevocable letter of credit from a highly rated
financial institution.

There have been no other 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 2009 Form 10-K.  There have been no significant  developments
since year-end.


                                       52
<PAGE>


NEW ACCOUNTING PRONOUNCEMENTS

CANADIAN PRONOUNCEMENTS
INTERNATIONAL FINANCIAL REPORTING STANDARDS ADOPTION PLAN

We are required to adopt International  Financial Reporting Standards (IFRS) for
our interim and annual financial reporting purposes beginning January 1, 2011. A
project team,  consisting of dedicated and  experienced  personnel who have IFRS
knowledge,  has been set up to manage this  transition and to ensure  successful
implementation within the required timeframe.

We provided an update on the status of our project in our 2009 Annual  Report on
Form 10-K,  including a summary of accounting  differences between Canadian GAAP
and IFRS.

The following chart is a summary of our transition project progress.
<TABLE>
<CAPTION>

------------------------------------------- ------------------------------------------ -----------------------------------------
KEY ACTIVITY                                KEY MILESTONE                              STATUS
------------------------------------------- ------------------------------------------ -----------------------------------------
Financial Information
------------------------------------------- ------------------------------------------ -----------------------------------------
<S>                                         <C>                                        <C>
o   Identify differences between Canadian   o   Comprehensive analysis of IFRS         o   Comprehensive analysis completed
    GAAP and IFRS                               differences identified in the              mid 2009
o   Revise accounting policies under            diagnostics phase                      o   Received senior management
    IFRS                                    o   Senior management approval of              approval of IFRS accounting policies
o   Identify potential adjustments to           IFRS accounting policies               o   Areas of potential adjustment to
    initial IFRS financial statements       o   Develop draft IFRS financial               opening balance sheet identified
o   Develop IFRS-compliant financial            statements and disclosures             o   Analysis to support opening balance
    statements, including transition                                                       sheet adjustments is ongoing
    period disclosures                                                                 o   No significant impact on key
                                                                                           performance indicators identified
                                                                                           to date
                                                                                       o   Preparation and assessment of Q1
                                                                                           IFRS data is underway
                                                                                       o   Data source testing for draft Q1 IFRS
                                                                                           financial statements and note
                                                                                           disclosures are substantially
                                                                                           complete
------------------------------------------- ------------------------------------------ -----------------------------------------
Training and Communication
------------------------------------------- ------------------------------------------ -----------------------------------------
o   Develop and deliver targeted IFRS       o   Delivery of training in 2009 targeted  o   Targeted training completed in 2009
    training to employees and                   to affected employees                  o   Strategy for follow-up training in
    management                              o   Ongoing communication with major           2010 developed
o   Ensure internal and external                internal and external stakeholders     o   Training sustainment plan prepared
    stakeholders receive ongoing                                                       o   Regular communication with Project
    appropriate communications                                                             Steering Committee, senior
o   Develop and deliver targeted IFRS                                                      management and Audit Committee
    training to senior management and                                                      throughout the year
    Board of Directors                                                                 o   Quarterly disclosure of project
                                                                                           status in MD&A
------------------------------------------- ------------------------------------------ -----------------------------------------
Information Technology
------------------------------------------- ------------------------------------------ -----------------------------------------
o   Ensure systems are able to              o   Be IFRS data capture ready January     o   System testing for IFRS data capture
    adequately support conversion to            1, 2010                                    complete
    IFRS and ongoing  financial             o   Ensure dual GAAP reporting             o   Dual GAAP reporting capability for
    reporting                                   capability throughout 2010                 2010 testing complete
                                                                                       o   IFRS data capture in the financial
                                                                                           system for Q1 was successful
------------------------------------------- ------------------------------------------ -----------------------------------------
Business Process
------------------------------------------- ------------------------------------------ -----------------------------------------
o   Ensure business processes and           o   Implement necessary business           o   Necessary changes to business
    control environment properly                process and key control changes to         process have been designed
    support conversion to IFRS and              ensure adequate internal control       o   Key controls designed to ensure
    ongoing financial reporting                 over financial reporting                   adequate internal control over
                                                                                           financial reporting on IFRS results
                                                                                           throughout 2010
                                                                                       o   Changes to business processes
                                                                                           being tested
------------------------------------------- ------------------------------------------ -----------------------------------------
</TABLE>

At this time, we cannot  quantify with certainty the impact that the adoption of
IFRS will have on our  future  results  of  operations  or  financial  position.
Additional  disclosure  of the key  elements  of our  plan and  progress  on the
project will be provided as we move toward the  changeover  date. We continue to
monitor the development of new standards and any changes will be incorporated as
required.


                                       53
<PAGE>

US PRONOUNCEMENTS
In January 2010, the Financial  Accounting  Standards  Board issued  guidance to
improve fair value  measurement  disclosures.  The guidance requires entities to
describe  transfers  between the three  levels of the fair value  hierarchy  and
present  items  separately  in the  level 3  reconciliation.  This  guidance  is
consistent with fair value measurement  disclosures adopted for Canadian GAAP in
2009.  Adoption  of this  guidance  did not have an  impact  on our  results  of
operations or financial position.

EQUITY SECURITY REPURCHASES

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

SUMMARY OF QUARTERLY RESULTS

<TABLE>
<CAPTION>
                                                 |        2008       |                  2009                |        2010
-------------------------------------------------|-------------------|--------------------------------------|------------------
(Cdn$ millions, except per share amounts)        |     Sep       Dec |    Mar       Jun       Sep       Dec |    Mar       Jun
-------------------------------------------------------------------------------------------------------------------------------

<S>                                                  <C>       <C>      <C>       <C>       <C>       <C>      <C>       <C>
Net Sales from Continuing Operations                 2,094     1,214    1,004     1,138     1,034     1,486    1,432     1,399

Net Income (Loss) from Continuing Operations           830     (185)      152        23       122       256      172       242
Net Income (Loss) from Discontinued Operations          56         4     (17)       (3)         -         3       13        13
                                                  -----------------------------------------------------------------------------
Net Income (Loss)                                      886     (181)      135        20       122       259      185       255
                                                  =============================================================================

Earnings (Loss) Per Common Share from
  Continuing Operations ($/share)
     Basic                                            1.58    (0.36)     0.28      0.05      0.23      0.49     0.33      0.46
     Diluted                                          1.56    (0.36)     0.28      0.05      0.23      0.48     0.33      0.46

Earnings (Loss) Per Common Share ($/share)
     Basic                                            1.68    (0.35)     0.26      0.04      0.23      0.50     0.35      0.49
     Diluted                                          1.66    (0.35)     0.26      0.04      0.23      0.49     0.35      0.49
                                                  -----------------------------------------------------------------------------
</TABLE>

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  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    the expectation that we have the ability to  substantially  grow production
     at our oil sands facilities through controlled expansions;
o    the expectation of achieving the production design rates from our oil sands
     facilities;
o    the  expectation  that our oil  sands  production  facilities  continue  to
     develop better and more sustainable practices;
o    the expectation of cheaper and more technologically advanced operations;


                                       54
<PAGE>


o    the  expected  timing  and  associated   production  impact  of  facilities
     turnarounds and maintenance;
o    the expectation  that we can continue to operate our offshore  exploration,
     development and production facilities safely and profitably;
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 operating costs;
o    future cost recovery oil revenues from our Yemen operations;
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, upgrade and transport crude oil
     and natural gas to markets;
o    ultimate effectiveness of design or design modification to facilities;
o    the results of exploration and development drilling and related activities;
o    the cumulative impact of oil sands development on the environment;
o    the impact of technology  on  operations  and processes and how new complex
     technology may not perform as expected;
o    the availability of pipeline and global refining capacity;
o    risks  inherent to the  operations of any large,  complex  refinery  units,
     especially the integration  between  production  operations and an upgrader
     facility;
o    availability  of  third-party  bitumen for use in our oil sands  production
     facilities;
o    labour and material shortages;
o    risk  related to  accidents,  blowouts  and spills in  connection  with our
     offshore exploration,  development and production activities,  particularly
     our deepwater activities;
o    direct  and  indirect  risk  related  to  the  imposition  of  moratoriums,
     suspensions or cancellations of our offshore  exploration,  development and
     production operations, particular our deepwater activities;
o    the impact of severe weather on our offshore  exploration,  development and
     production activities, particularly our deepwater activities;
o    the   effectiveness   and  reliability  of  our  technology  in  harsh  and
     unpredictable environments;
o    risks related to the actions of our agents and contractors;
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  including without limitation,
     those  related to our  offshore  exploration,  development  and  production
     activities;
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.




                                       55
<PAGE>

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
2009  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.  These are addressed in the unaudited  consolidated  financial
statements.

CREDIT RISK
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, 2010:
o    over 95% of our credit exposures were investment grade;
o    approximately  81% of our  credit  exposures  were with a diverse  group of
     integrated  oil  companies,  crude oil  refiners and  marketers,  and large
     utilities; and
o    only 2  counterparties  individually  made up more  than 10% of our  credit
     exposure.  These  counterparties  are major  integrated  oil companies with
     strong investment grade credit ratings.

Further  information  presented on market risks can be found in Item 7A on pages
92-94 in our 2009 Form 10-K and have not  materially  changed since December 31,
2009.


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.



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<PAGE>

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 during the first six months of 2010 that has materially affected,  or is
reasonably  likely to materially  affect,  the Company's  internal  control over
financial reporting.

                                     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 1A. RISK FACTORS

We are also  exposed to normal  risks  typical  in the oil and gas  exploration,
development and production  business,  including  operational risks,  regulatory
risks and the inherent uncertainty of discovery and producability of oil and gas
deposits.


DEEP WATER OPERATIONS

Our deep water operations take place in difficult and unpredictable environments
and are subject to the risk of blowouts and other catastrophic events that could
result in suspension of operations, damage to equipment, harm to individuals and
damage to the  environment.  While various  precautions  are taken to reduce the
risks,  such efforts cannot  eliminate the risk that such events may occur.  The
consequences of such catastrophic  events occurring in deep water operations can
be more difficult and  time-consuming to remedy. As well, the remedy may be made
more difficult or uncertain by the water depths, pressures and cold temperatures
encountered  in deep water  operations,  shortages of equipment and  specialists
required to work in these  conditions,  or the absence of  appropriate  means to
effectively remedy such  consequences.  Emergency response plans that we have in
place, to address the environmental impact from spills, leaks, blowouts or other
events in  connection  with our  operations  may not be  entirely  effective  in
mitigating the consequences of blowouts or other  catastrophic  events. Our deep
water  operations  could also be affected by the actions of our  contractors and
agents that could result in similar catastrophic events at their facilities,  or
could be indirectly  affected by  catastrophic  events  occurring at third-party
deep water  operations,  which, in either case, could give rise to liability for
us,  damage to our  equipment,  harm to  individuals,  force a  shutdown  of our
facilities or operations,  or result in a shortage of  appropriate  equipment or
specialists required to perform our planned operations.  It is possible that the
allocation of liabilities and risk of loss arising from deepwater operations and
associated  insurance  coverage  will not be  sufficient  to  address  the costs
arising out of such events.

The costs in  connection  with a blowout or other  catastrophic  event  could be
material and we may not maintain sufficient  insurance to address such costs. As
it pertains to these types of deep water risks, we maintain  insurance for costs
relating  to  property  damage  to our  facilities,  control  of well  including
drilling relief wells,  removal of wreck,  pollution cleanup,  bodily injury and
property damage to third parties. We are covered for a maximum loss up to US$1.5
billion,  net to our working interest in the well, subject to certain sub-limits
for each of the areas  covered.  We also carry  coverage up to US$50 million for
each of the costs relating to damage to natural  resources,  and civil fines and
penalties.

The recent  explosion  and sinking of the  Deepwater  Horizon rig in the Gulf of
Mexico and the resulting  oil spill have resulted in increased  scrutiny of deep
water operations by governments, environmental groups, investors and the general
public, not only in the United States but globally.  It is anticipated this will
result in  increased  regulation  of deep water  operations,  increased  cost of
compliance with applicable laws, and greater difficulty in permitting deep water
operations.  For example,  the Obama  administration  has  announced a six-month
moratorium on new deep water well permits.  This  moratorium has delayed current
exploration  and appraisal  activities  until it is lifted and could  ultimately
increase their cost.  Possible  extensions and/or regulatory changes limiting or
delaying the issuance of drilling  permits  could delay future  exploration  and
appraisal  programs and  ultimately  increase  their cost.  There is a risk that
liability limits under existing regulations could be increased  substantially by
the US Government,  which would increase our potential liability in the event of
a  blowout  or  other  catastrophic  event.  We also  may not be able to  access
sufficient  pooled  liability  funds set up in the Gulf of Mexico for costs of a
blowout or other catastrophic event.

Catastrophic  events  in  connection  with our deep  water  operations,  such as
blowouts and oil spills, could result in material costs and reputational damage,
and could have a material  adverse impact on our credit  rating,  our ability to
raise capital or the cost of such capital.

Further  information on market and operational  risks can be found in Item 1A on
pages  40-47 and Item 7A on pages 92 - 94 in our 2009 Form 10-K,  which have not
materially changed.


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<PAGE>


ITEM 4.  (REMOVED AND RESERVED)


                                       58

<PAGE>

ITEM 6.  EXHIBITS

10.62   Amended and Restated Credit  Agreement  dated June 21, 2010  (originally
        dated as of July 22,  2005) by and  among  Nexen  Inc.,  Nexen  Holdings
        U.S.A. Inc. and Nexen Petroleum U.K. Limited as borrowers, the financial
        institutions  named  therein  and other  institutions  from time to time
        party thereto as lenders and The Toronto-Dominion Bank, Toronto Dominion
        (Texas) LLC abs The  Toronto-Dominion  Bank,  London Branch as agents of
        the  lenders  (filed as  Exhibit  10.1 to Form 8-K filed with the SEC on
        June 24, 2010).
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, 2010.

                                                  NEXEN INC.



/s/ Marvin F. Romanow                             /s/ Brendon T. Muller
---------------------                             ---------------------
Marvin F. Romanow                                 Brendon T. Muller
President and Chief Executive Officer             Controller
(Principal Executive Officer)                     (Principal Accounting Officer)


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