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 September 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  September  30,  2010,  there  were  525,032,386  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 6.  Exhibits .......................................................57

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 September 30, 2010, the noon-day exchange rate was US$0.9711 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 Nine Months Ended September 30, 2010 and 2009...............4

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

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

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

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

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


                                       3


<PAGE>

<TABLE>
<CAPTION>

NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30

                                                                                Three Months                Nine Months
                                                                              Ended September 30          Ended September 30
(Cdn$ millions, except per share amounts)                                     2010          2009          2010          2009
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                         <C>           <C>           <C>           <C>
REVENUES AND OTHER INCOME
     Net Sales                                                               1,416         1,034         4,247         3,176
     Marketing and Other (Note 14)                                             138           296           373           635
                                                                      --------------------------------------------------------
                                                                             1,554         1,330         4,620         3,811
                                                                      --------------------------------------------------------
EXPENSES
     Operating                                                                 420           297         1,218           872
     Depreciation, Depletion, Amortization and Impairment                      477           329         1,234         1,087
     Transportation and Other                                                  142           180           501           606
     General and Administrative                                                132           108           316           363
     Exploration                                                                56            89           199           219
     Interest (Note 9)                                                          81            84           238           226
     Net Loss from Dispositions (Note 15)                                      259             -           179             -
                                                                      --------------------------------------------------------
                                                                             1,567         1,087         3,885         3,373
                                                                      --------------------------------------------------------

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE PROVISION FOR
     INCOME TAXES                                                              (13)          243           735           438
                                                                      --------------------------------------------------------

PROVISION FOR (RECOVERY OF) INCOME TAXES
     Current                                                                   270           190           793           514
     Future                                                                   (234)          (81)         (423)         (390)
                                                                      --------------------------------------------------------
                                                                                36           109           370           124
                                                                      --------------------------------------------------------

NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE NON-CONTROLLING
     INTERESTS                                                                 (49)          134           365           314
     Less: Net Income Attributable to Canexus
       Non-Controlling Interests                                                (4)          (12)           (4)          (17)
                                                                      --------------------------------------------------------

NET INCOME (LOSS) FROM CONTINUING OPERATIONS ATTRIBUTABLE TO NEXEN
     INC.                                                                      (53)          122           361           297
     Net Income (Loss) from Discontinued
       Operations (Note 15)                                                    590             -           616           (20)
                                                                      --------------------------------------------------------

NET INCOME ATTRIBUTABLE TO NEXEN INC.                                          537           122           977           277
                                                                      ========================================================

EARNINGS (LOSS) PER COMMON SHARE FROM CONTINUING OPERATIONS
     ($/share) (Note 16)
     Basic                                                                   (0.10)         0.23          0.69          0.57
                                                                      ========================================================

     Diluted                                                                 (0.10)         0.23          0.69          0.57
                                                                      ========================================================

EARNINGS PER COMMON SHARE ($/share) (Note 16)
     Basic                                                                    1.02          0.23          1.86          0.53
                                                                      ========================================================

     Diluted                                                                  1.02          0.23          1.86          0.53
                                                                      ========================================================

</TABLE>

SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.


                                        4

<PAGE>



NEXEN INC.
UNAUDITED CONSOLIDATED BALANCE SHEET

<TABLE>
<CAPTION>
                                                                                              September 30       December 31
(Cdn$ millions, except share amounts)                                                                 2010              2009
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                 <C>               <C>
ASSETS
   CURRENT ASSETS
      Cash and Cash Equivalents                                                                      1,210             1,700
      Restricted Cash                                                                                   35               198
      Accounts Receivable (Note 2)                                                                   2,305             2,788
      Inventories and Supplies (Note 3)                                                                544               680
      Other                                                                                            142               185
                                                                                          -------------------------------------
         Total Current Assets                                                                        4,236             5,551
                                                                                          -------------------------------------

   PROPERTY, PLANT AND EQUIPMENT
      Net of Accumulated Depreciation, Depletion, Amortization and
         Impairment of $10,414 (December 31, 2009 - $10,807)                                        15,835            15,492
   GOODWILL                                                                                            316               339
   FUTURE INCOME TAX ASSETS                                                                          1,608             1,148
   DEFERRED CHARGES AND OTHER ASSETS (Note 5)                                                          236               370
                                                                                          -------------------------------------
TOTAL ASSETS                                                                                        22,231            22,900
                                                                                          =====================================

LIABILITIES
   CURRENT LIABILITIES
      Accounts Payable and Accrued Liabilities (Note 8)                                              2,943             3,038
      Accrued Interest Payable                                                                          78                89
      Dividends Payable                                                                                 26                26
                                                                                          -------------------------------------
         Total Current Liabilities                                                                   3,047             3,153
                                                                                          -------------------------------------

   LONG-TERM DEBT (Note 9)                                                                           5,678             7,251
   FUTURE INCOME TAX LIABILITIES                                                                     3,127             2,811
   ASSET RETIREMENT OBLIGATIONS (Note 11)                                                            1,007             1,018
   DEFERRED CREDITS AND OTHER LIABILITIES (Note 12)                                                    766             1,021

EQUITY
   Nexen Inc. Shareholders' Equity
      Common Shares, no par value
         Authorized:   Unlimited
         Outstanding:  2010 - 525,032,386 shares
                       2009 - 522,915,843 shares                                                     1,097             1,049
      Contributed Surplus                                                                                -                 1
      Retained Earnings                                                                              7,621             6,722
      Accumulated Other Comprehensive Loss                                                            (196)             (190)
                                                                                          -------------------------------------
   Total Nexen Inc. Shareholders' Equity                                                             8,522             7,582
      Canexus Non-Controlling Interests                                                                 84                64
                                                                                          -------------------------------------
   TOTAL EQUITY                                                                                      8,606             7,646
                                                                                          -------------------------------------
   COMMITMENTS, CONTINGENCIES AND GUARANTEES (Note 17)
                                                                                          -------------------------------------
TOTAL LIABILITIES AND EQUITY                                                                        22,231            22,900
                                                                                          =====================================

</TABLE>

SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.


                                        5

<PAGE>


<TABLE>
<CAPTION>

NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30

                                                                               Three Months                Nine Months
                                                                            Ended September 30         Ended September 30
(Cdn$ millions)                                                            2010           2009          2010         2009
---------------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>             <C>           <C>          <C>
OPERATING ACTIVITIES
   Net Income (Loss) from Continuing Operations                             (49)           134           365          314
   Net Income (Loss) from Discontinued Operations                           590              -           616          (20)
   Charges and Credits to Income not Involving
       Cash (Note 18)                                                      (102)           174           433          887
   Exploration Expense                                                       56             89           199          219
   Changes in Non-Cash Working Capital (Note 18)                            212            113           410          193
   Other                                                                    (39)           (49)          (47)        (234)
                                                                   --------------------------------------------------------
                                                                            668            461         1,976        1,359

FINANCING ACTIVITIES
   Repayment of Short-Term Borrowings, Net                                 (156)            (1)            -           (1)
   Proceeds from Long-Term Notes                                              -          1,081             -        1,081
   Proceeds from (Repayment of) Term Credit
       Facilities, Net                                                     (463)          (915)       (1,540)         728
   Proceeds from (Repayment of) Canexus Term Credit
       Facilities, Net                                                       (4)            (4)           64           48
   Proceeds from Canexus Debentures                                          60             46            60           46
   Dividends Paid on Common Shares                                          (26)           (26)          (78)         (78)
   Distributions Paid to Canexus Non-Controlling Interests                   (6)            (4)          (13)         (11)
   Issue of Common Shares and Exercise of Tandem
       Options for Shares                                                     9             12            44           42
   Other                                                                     (2)           (18)          (15)         (19)
                                                                   --------------------------------------------------------
                                                                           (588)           171        (1,478)       1,836

INVESTING ACTIVITIES
   Capital Expenditures
       Exploration and Development                                         (554)          (586)       (1,793)      (1,921)
       Proved Property Acquisitions                                           -              -             -         (755)
       Energy Marketing, Chemicals, Corporate and Other                     (38)           (69)         (172)        (198)
   Proceeds from Dispositions                                               950              2         1,046           17
   Changes in Non-Cash Working Capital (Note 18)                           (105)            14           (30)         (41)
   Changes in Restricted Cash                                               (43)            93            40         (154)
   Other                                                                     (1)           (15)           (8)         (16)
                                                                   --------------------------------------------------------
                                                                            209           (561)         (917)      (3,068)

EFFECT OF EXCHANGE RATE CHANGES ON CASH AND
       CASH EQUIVALENTS                                                     (49)          (148)          (71)        (233)
                                                                   --------------------------------------------------------

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                            240            (77)         (490)        (106)

CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD                             970          1,974         1,700        2,003
                                                                   --------------------------------------------------------

CASH AND CASH EQUIVALENTS - END OF PERIOD (1)                             1,210          1,897         1,210        1,897
                                                                   ========================================================

</TABLE>
(1)  Cash and cash  equivalents  at  September  30, 2010 consist of cash of $211
     million and short-term  investments  of $999 million  (September 30, 2009 -
     cash of $376 million and short-term investments of $1,521 million).


SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.


                                       6

<PAGE>



NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF EQUITY
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30

<TABLE>
<CAPTION>
                                                                                 Three Months                  Nine Months
                                                                              Ended September 30           Ended September 30
(Cdn$ millions)                                                               2010           2009          2010          2009
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                                          <C>            <C>           <C>           <C>
COMMON SHARES, Beginning of Period                                           1,088          1,011         1,049           981
      Issue of Common Shares                                                     9              8            41            37
      Exercise of Tandem Options for Shares                                      -              4             3             5
      Accrued Liability Relating to Tandem Options
         Exercised for Common Shares                                             -              2             4             2
                                                                      ---------------------------------------------------------
   Balance at End of Period                                                  1,097          1,025         1,097         1,025
                                                                      =========================================================

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

RETAINED EARNINGS, Beginning of Period                                       7,110          6,393         6,722         6,290
      Net Income Attributable to Nexen Inc.                                    537            122           977           277
      Dividends Paid on Common Shares (Note 13)                                (26)           (26)          (78)          (78)
                                                                      ---------------------------------------------------------
   Balance at End of Period                                                  7,621          6,489         7,621         6,489
                                                                      =========================================================

ACCUMULATED OTHER COMPREHENSIVE LOSS,
   Beginning of Period                                                        (189)          (157)         (190)         (134)
      Other Comprehensive Loss Attributable
         to Nexen Inc.                                                          (7)           (26)           (6)          (49)
                                                                      ---------------------------------------------------------
   Balance at End of Period (1)                                               (196)          (183)         (196)         (183)
                                                                      =========================================================

(1) Comprised of unrealized foreign currency translation adjustment.


CANEXUS NON-CONTROLLING INTERESTS,
   Beginning of Period                                                          71             54            64            52
      Net Income Attributable to Non-Controlling Interests                       4             15             4            24
      Distributions Due to Non-Controlling Interests                            (5)            (5)          (15)          (14)
      Issue of Partnership Units to Non-Controlling
         Interests                                                               6              1            23             3
      Estimated Fair Value of Conversion Feature of
         Convertible Debenture Issue Attributable to
         Non-Controlling Interests                                               8              4             8             4
                                                                      ---------------------------------------------------------
   Balance at End of Period                                                     84             69            84            69
                                                                      =========================================================

</TABLE>


SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.


                                        7

<PAGE>



<TABLE>
<CAPTION>
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30

                                                                              Three Months                  Nine Months
                                                                           Ended September 30           Ended September 30
(Cdn$ millions)                                                            2010           2009          2010          2009
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>            <C>          <C>            <C>
NET INCOME ATTRIBUTABLE TO NEXEN INC.                                       537            122          977            277
   Other Comprehensive Loss,
      Net of Income Taxes:
          Foreign Currency Translation Adjustment
            Net Losses on Investment in
             Self-Sustaining Foreign Operations                            (145)          (408)         (83)          (693)
            Net Gains on Foreign-Denominated
              Debt Hedges of Self-Sustaining Foreign
              Operations (1)                                                138            384           77            646
            Realized Translation Adjustments Recognized
                in Net Income                                                 -             (2)           -             (2)
                                                                   -------------------------------------------------------------
      Other Comprehensive Loss Attributable
          to Nexen Inc.                                                      (7)           (26)          (6)           (49)
                                                                   -------------------------------------------------------------
COMPREHENSIVE INCOME ATTRIBUTABLE
   TO NEXEN INC.                                                            530             96          971            228
                                                                   =============================================================

</TABLE>
(1)  Net of income tax expense for the three months ended  September 30, 2010 of
     $20 million (2009 - $55 million  expense) and net of income tax expense for
     the nine months ended September 30, 2010 of $12 million (2009 - $93 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 September 30, 2010 and December
31, 2009 and the results of our  operations and our cash flows for the three and
nine months ended September 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 nine months ended September 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 October 27, 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:  i) expands the  definition  of oil and gas
producing  activities to include  unconventional  sources such as oil sands; ii)
changes  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) requires 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 the three and nine months ended September 30,
2010  increased  by $11  million and $35  million,  net income  decreased  by $7
million and $23 million,  and earnings per common share decreased by $0.02/share
and $0.06/share, respectively.


                                        9

<PAGE>


<TABLE>
<CAPTION>

2.  ACCOUNTS RECEIVABLE

                                                                                              September 30        December 31
                                                                                                      2010               2009
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                  <C>                <C>
Trade
     Energy Marketing                                                                                1,300              1,410
     Energy Marketing Derivative Contracts (Note 6)                                                    172                466
     Oil and Gas                                                                                       712                823
     Chemicals and Other                                                                                47                 44
                                                                                       ---------------------------------------
                                                                                                     2,231              2,743
Non-Trade                                                                                              121                 99
                                                                                       ---------------------------------------
                                                                                                     2,352              2,842
Allowance for Doubtful Receivables                                                                     (47)               (54)
                                                                                       ---------------------------------------
Total                                                                                                2,305              2,788
                                                                                       =======================================
</TABLE>

<TABLE>
<CAPTION>
3.  INVENTORIES AND SUPPLIES

                                                                                              September 30        December 31
                                                                                                      2010               2009
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                  <C>                <C>
Finished Products
     Energy Marketing                                                                                  389                548
     Oil and Gas                                                                                        54                 25
     Chemicals and Other                                                                                10                 12
                                                                                       ---------------------------------------
                                                                                                       453                585
Work in Process                                                                                         10                  7
Field Supplies                                                                                          81                 88
                                                                                       ---------------------------------------
Total                                                                                                  544                680
                                                                                       =======================================
</TABLE>

4.  PROPERTY, PLANT AND EQUIPMENT


DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT


Our DD&A  expense in the third  quarter  of 2010  includes  non-cash  impairment
charges of $61 million at three natural gas properties in the US Gulf of Mexico.
Low natural gas prices made these mature shelf  properties  uneconomic and, as a
result,  the  properties  are being shut down and the carrying value was written
down to their  estimated  fair value.  Fair value was based on estimated  future
cash flows using unobservable Level 3 inputs including  management's estimate of
future production and prices.


SUSPENDED EXPLORATION WELL COSTS

The  following  table shows the changes in  capitalized  exploratory  well costs
during the nine months ended  September 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>
                                                                                        Nine Months Ended          Year Ended
                                                                                             September 30         December 31
                                                                                                     2010                2009
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                 <C>                 <C>
Beginning of Period                                                                                   794                 518
     Exploratory Well Costs Capitalized Pending the Determination of
       Proved Reserves                                                                                350                 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                                                         (10)                (43)
                                                                                       ---------------------------------------
End of Period                                                                                       1,131                 794
                                                                                       =======================================
</TABLE>


                                       10
<PAGE>

The following  table  provides an aging of  capitalized  exploratory  well costs
based on the date drilling was completed as at September 30, 2010.

<TABLE>
<CAPTION>
                                                       United                          United
Aging of Suspended Exploration Wells                  Kingdom          Canada          States        Nigeria            Total
------------------------------------------------------------------------------------------------------------------------------
<S>                                                      <C>             <C>              <C>                            <C>
Less than 1 year                                          113             190              85              -              388
1-3 years                                                 155             387               -              -              542
4-5 years                                                  55               -             115              -              170
Greater than 5 years                                        -               -               -              31              31
                                                ------------------------------------------------------------------------------
Total                                                     323             577             200              31           1,131
                                                ==============================================================================
</TABLE>

As at September 30, 2010, we have  exploratory  costs that have been capitalized
for more  than one year  relating  to our shale gas  exploratory  activities  in
Canada ($387 million),  interests in eight  exploratory  blocks in the North Sea
($210 million), two exploratory blocks in the Gulf of Mexico ($115 million), and
our interest in an exploratory block offshore Nigeria ($31 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>
                                                                                            September 30          December 31
                                                                                                    2010                 2009
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                <C>                  <C>
Long-Term Energy Marketing Derivative Contracts (Note 6)                                             116                  225
Defined Benefit Pension Assets                                                                        53                   60
Long-Term Capital Prepayments                                                                         16                   27
Other                                                                                                 51                   58
                                                                                   -------------------------------------------
Total                                                                                                236                  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, as well as 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 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 September 30, 2010,  the estimated  fair value of our long-term debt
was $6,385  million  (December  31,  2009 - $7,594  million)  as compared to the
carrying value of $5,678 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


During the quarter, we sold our North American natural gas marketing operations,
as described in Note 15. Our energy  marketing  group  primarily  focuses on our
crude oil marketing activities in North America, Europe and Asia.


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>
                                                                                              September 30        December 31
                                                                                                      2010               2009
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                  <C>                <C>
  Commodity Contracts                                                                                  172                463
  Foreign Exchange Contracts                                                                             -                  3
                                                                                       ---------------------------------------
   Accounts Receivable (Note 2)                                                                        172                466
                                                                                       ---------------------------------------

  Commodity Contracts                                                                                  116                225
                                                                                       ---------------------------------------
   Deferred Charges and Other Assets (Note 5) (1)                                                      116                225
                                                                                       ---------------------------------------

Total Trading Derivative Assets                                                                        288                691
                                                                                       =======================================

  Commodity Contracts                                                                                  152                410
  Foreign Exchange Contracts                                                                             -                 46
                                                                                       ---------------------------------------
   Accounts Payable and Accrued Liabilities (Note 8)                                                   152                456
                                                                                       ---------------------------------------

  Commodity Contracts                                                                                  119                212
                                                                                       ---------------------------------------
   Deferred Credits and Other Liabilities (Note 12) (1)                                                119                212
                                                                                       ---------------------------------------

Total Trading Derivative Liabilities                                                                   271                668
                                                                                       =======================================

Total Net Trading Derivative Contracts                                                                  17                 23
                                                                                       =======================================
</TABLE>

(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:

<TABLE>
<CAPTION>
                                                                                              September 30        December 31
                                                                                                      2010               2009
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                  <C>                <C>
Current Trading Assets                                                                                 582              2,625
Non-Current Trading Assets                                                                             311                716
                                                                                       ---------------------------------------
  Total Trading Derivative Assets                                                                      893              3,341
                                                                                       =======================================

Current Trading Liabilities                                                                            562              2,615
Non-Current Trading Liabilities                                                                        314                703
                                                                                       ---------------------------------------
  Total Trading Derivative Liabilities                                                                 876              3,318
                                                                                       =======================================

                                                                                       ---------------------------------------
Total Net Trading Derivative Contracts                                                                  17                 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 nine  months  ended  September  30,  2010,  the
following trading revenues were recognized in marketing and other income:

<TABLE>
<CAPTION>
                                                                        Three Months Ended              Nine Months Ended
                                                                              September 30                   September 30
                                                                                      2010                           2010
---------------------------------------------------------------------------------------------------------------------------
<S>                                                                                   <C>                           <C>
Commodity                                                                               84                            290
Foreign Exchange                                                                        (2)                            (8)
                                                              -------------------------------------------------------------
  Marketing Revenue                                                                     82                            282
                                                              =============================================================
</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 nine months ended September 30, 2010,
are as follows:

<TABLE>
<CAPTION>
                                                                        Three Months Ended              Nine Months Ended
                                                                              September 30                   September 30
                                                                                      2010                           2010
---------------------------------------------------------------------------------------------------------------------------
<S>                                                                                   <C>                           <C>
Natural Gas                                        bcf/d                               2.9                            7.8
Crude Oil                                       mmbbls/d                               3.0                            3.2
Power                                              GWh/d                               0.2                           92.8
Foreign Exchange                            US$ millions                               548                          2,169
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>
                                                                             September 30                     December 31
                                                                                     2010                            2009
---------------------------------------------------------------------------------------------------------------------------
<S>                                                                                    <C>                            <C>
Accounts Receivable                                                                     4                              13
Deferred Charges and Other Assets (1)                                                   1                               4
                                                              -------------------------------------------------------------
  Total Non-Trading Derivative Assets                                                   5                              17
                                                              =============================================================

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

  Total Net Non-Trading Derivative Assets (2)                                           5                              (9)
                                                              =============================================================
</TABLE>

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

CRUDE OIL PUT OPTIONS
During the quarter,  we purchased put options on 20,000 bbls/d of our 2011 crude
oil  production  for $6 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.  The  options  settle  monthly  and 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.
Higher  forward crude oil prices at September 30, 2010 reduced the fair value of
the options to approximately $5 million.

Subsequent to September 30, 2010, we purchased  additional crude oil put options
on 50,000 bbls/d of our 2011 crude oil production for $17 million. These options
establish a WTI floor price of approximately US$56/bbl.

                                       13

<PAGE>


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.  Options on 60,000 bbls/d settle monthly,  while the
remaining  options  settle  annually.  These  options are recorded at fair value
throughout  their term.  Higher  forward  crude oil prices at September 30, 2010
compared to the end of the previous quarter and a shorter term to expiry reduced
the fair value of the options to nil.

<TABLE>
<CAPTION>
                                                                                                     Change in Fair Value
                                                                                              ------------------------------------
                                                                                                  Three Months        Nine Months
                                                                                                         Ended              Ended
                                              Notional                    Average       Fair      September 30       September 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)            20,000       2011              50          5                (1)                (1)
WTI Crude Oil Put Options (monthly)            60,000       2010              50          -                (2)               (13)
WTI Crude Oil Put Options (annual)             30,000       2010              50          -                 -                 (4)
                                                                                   -----------------------------------------------
                                                                                          5                (3)               (18)
                                                                                   ===============================================
</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  September  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 September 30, 2010                                         Level 1       Level 2       Level 3         Total
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>             <C>          <C>           <C>
Trading Derivatives (Commodity Contracts)                                         (27)            -            44            17
Non-Trading Derivatives                                                             -             5             -             5
                                                                         -------------------------------------------------------
Total                                                                             (27)            5            44            22
                                                                         =======================================================
</TABLE>

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

<TABLE>
<CAPTION>
                                                                                                                     Level 3
-----------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                                    <C>
Beginning of Period                                                                                                       42
  Realized and Unrealized Gains (Losses)                                                                                  21
  Purchases                                                                                                                -
  Settlements                                                                                                            (19)
  Transfers Into Level 3                                                                                                   -
  Transfers Out of Level 3                                                                                                 -
                                                                                                              ---------------
End of Period                                                                                                             44
                                                                                                              ===============

Unsettled gains relating to instruments still held as of September 30, 2010                                               21
                                                                                                              ===============
</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 September 30, 2010 would change by $2
million (December 31, 2009 - $12 million).

                                       14
<PAGE>


7.  RISK MANAGEMENT

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
portions of 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 primarily  focused on  marketing  and trading
physical  crude oil in selected  regions of the world.  We do this by buying and
selling  physical  crude  oil,  by  acquiring  and  holding  rights to  physical
transportation and storage assets, and by building strong relationships with our
customers and suppliers.


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 nine months ended September 30, 2010 are as follows:

<TABLE>
<CAPTION>
                                                                                    Three Months                Nine Months
                                                                                 Ended September 30          Ended September 30
Value-at-Risk                                                                    2010          2009          2010         2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                               <C>          <C>            <C>         <C>
Period End                                                                          8            13             8           13
High                                                                                9            15            15           24
Low                                                                                 4            11             4           11
Average                                                                             7            12            10           16
                                                                         -------------------------------------------------------
</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.


                                       15


<PAGE>



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, long-term debt, and cash & cash equivalents.

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 equity. Our net investment
in  self-sustaining  foreign  operations  and our  designated  US-dollar debt at
September 30, 2010 and December 31, 2009 are as follows:

<TABLE>
<CAPTION>
                                                                                          September 30            December 31
(US$ millions)                                                                                    2010                   2009
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                            <C>                    <C>
Net Investment in Self-Sustaining Foreign Operations                                             4,307                  4,492
Designated US-Dollar Debt                                                                        4,307                  4,492
                                                                                   -------------------------------------------
</TABLE>

For the three and nine months ended September 30, 2010, the ineffective  portion
of our US-dollar debt resulted in a net foreign exchange gain of $12 million and
a net foreign exchange loss of $6 million, respectively (gain of $11 million and
loss of $5 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 $43 million, net of income tax, and would
increase or decrease our net income by approximately  $4 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.


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  76% 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.


                                       16

<PAGE>


At September 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.   Four  other
counterparties made up more than 5% of our credit exposure.  The following table
illustrates the composition of credit exposure by credit rating.

<TABLE>
<CAPTION>
                                                                                              September 30        December 31
CREDIT RATING                                                                                         2010               2009
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                 <C>                 <C>
A or higher                                                                                           67%                 67%
BBB                                                                                                   21%                 26%
Non-Investment Grade                                                                                  12%                  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 $47
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 September 30, 2010 includes $45 million of
cash and $224  million of letters of credit.  The cash  received  is included in
accounts payable and accrued liabilities.


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 September 30, 2010, we had  approximately  $4.4 billion of cash and available
committed lines of credit. This includes  approximately $1.2 billion of cash and
cash equivalents on hand and undrawn term credit facilities of $3.2 billion,  of
which $289 million was supporting letters of credit at September 30, 2010. These
facilities  are available  until 2014 unless  extended.  We also have about $466
million  of  uncommitted  credit  facilities,  none of which  was  drawn and $82
million of which was supporting letters of credit at September 30, 2010.


The following  table details the contractual  maturities for our  non-derivative
financial  liabilities,  including both the principal and interest cash flows at
September 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                                  5,787                   -              345               799            4,643
Interest on Long-Term Debt (1)                  7,668                 357              713               651            5,947
                                       ---------------------------------------------------------------------------------------
Total                                          13,455                 357            1,058             1,450           10,590
                                       =======================================================================================
</TABLE>

(1)  Excludes interest on Canexus term credit facilities of $294 million (US$285
     million) as the amounts drawn on the facilities fluctuate. Based on amounts
     drawn at September 30, 2010 and existing  variable interest rates, we would
     be required to pay $12  million per year until the  outstanding  amounts on
     the term credit facilities are repaid.

The following table details contractual  maturities for our derivative financial
liabilities.  The balance sheet  amounts for  derivative  financial  liabilities
included below are not materially  different from the contractual amounts due on
maturity.

<TABLE>
<CAPTION>
                                                                Less than                                           More than
                                                Total              1 Year        1-3 Years         4-5 Years          5 Years
------------------------------------------------------------------------------------------------------------------------------
<S>                                            <C>                   <C>              <C>               <C>            <C>
Trading Derivatives (Note 6)                       271                152              103                11                5
Non-Trading Derivatives (Note 6)                     -                  -                -                 -                -
                                       ---------------------------------------------------------------------------------------
Total                                              271                152              103                11                5
                                       =======================================================================================
</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 September 30, 2010,  we could be required to post  collateral of up to
$700 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 more  quickly  monetized  as well as
undrawn credit facilities.


                                       17
<PAGE>


At  September  30,  2010,  collateral  posted with  counterparties  includes $15
million of cash and $139  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 $35 million (December 31, 2009 -
$198 million), which have been included in restricted cash.

8.   ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

<TABLE>
<CAPTION>
                                                                                              September 30        December 31
                                                                                                      2010               2009
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                  <C>                <C>
Energy Marketing Payables                                                                            1,203              1,366
Energy Marketing Derivative Contracts (Note 6)                                                         152                456
Accrued Payables                                                                                       653                619
Trade Payables                                                                                         216                210
Income Taxes Payable                                                                                   362                179
Stock-Based Compensation                                                                                28                 72
Other                                                                                                  329                136
                                                                                       ---------------------------------------
Total                                                                                                2,943              3,038
                                                                                       =======================================
</TABLE>

9.   SHORT-TERM BORROWINGS AND LONG-TERM DEBT

<TABLE>
<CAPTION>
                                                                                              September 30        December 31
                                                                                                      2010               2009
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                <C>                <C>
Canexus Term Credit Facilities, due 2012 (US$285 million drawn) (a)                                    294                233
Canexus Notes, due 2013 (US$50 million)                                                                 51                 52
Notes, due 2013 (US$500 million)                                                                       515                523
Term Credit Facilities, due 2014 (b)                                                                     -              1,570
Canexus Convertible Debentures, due 2014                                                                27                 46
Notes, due 2015 (US$250 million)                                                                       257                262
Canexus Convertible Debentures, due 2015 (c)                                                            60                  -
Notes, due 2017 (US$250 million)                                                                       257                262
Notes, due 2019 (US$300 million)                                                                       309                314
Notes, due 2028 (US$200 million)                                                                       206                209
Notes, due 2032 (US$500 million)                                                                       515                523
Notes, due 2035 (US$790 million)                                                                       814                827
Notes, due 2037 (US$1,250 million)                                                                   1,287              1,308
Notes, due 2039 (US$700 million)                                                                       721                733
Subordinated Debentures, due 2043 (US$460 million)                                                     474                481
                                                                                       ---------------------------------------
                                                                                                     5,787              7,343
Unamortized Debt Issue Costs                                                                          (109)               (92)
                                                                                       ---------------------------------------
Total Long-Term Debt                                                                                 5,678              7,251
                                                                                       =======================================
</TABLE>



(A) CANEXUS TERM CREDIT FACILITIES


Canexus has $450  million  (US$437  million) of  committed,  secured term credit
facilities  available  until August 2012.  At September  30, 2010,  $294 million
(US$285 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  September 30, 2010 (three months
ended  September  30, 2009 - 2.0%) and 3.5% for the nine months ended  September
30, 2010 (nine months ended September 30, 2009 - 2.3%).


                                       18

<PAGE>



(B) TERM CREDIT FACILITIES


We have  unsecured  term credit  facilities  of $3.2 billion  (US$3.1  billion),
available  until 2014,  none of which were drawn at September 30, 2010 (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 3.1% for the three months ended  September 30, 2010 (three months
ended  September  30, 2009 - 0.9%) and 1.2% for the nine months ended  September
30, 2010 (nine months ended  September 30, 2009 - 1.0%).  At September 30, 2010,
$289  million  (US$281  million) of these  facilities  were  utilized to support
outstanding  letters  of  credit  (December  31,  2009  - $407  million  (US$389
million)).


(C) CANEXUS CONVERTIBLE DEBENTURES

In  September  2010,  Canexus  issued  $60  million  of  convertible   unsecured
subordinated  debentures  to  non-controlling  interests.  Interest  is  payable
semi-annually at a rate of 5.75%.  These debentures  mature on December 31, 2015
and are  convertible  at the  holder's  option at any time prior to the close of
business on the earlier of; i) the  maturity  date;  and,  ii) the  business day
immediately  preceding  the date  specified  by Canexus  for  redemption  of the
debentures into trust units. The conversion price is $8.30 per trust unit.

Canexus has the option to redeem the debentures in whole or in part from time to
time subject to the  satisfaction of certain  conditions.  The debentures can be
redeemed  by  Canexus,  after  January  1, 2014 and  before  December  31,  2014
(provided  that  the  current  market  price of the  trust  units on the date of
redemption is not less than 125% of the conversion price) and after December 31,
2014 at a redemption price equal to the principal amount plus accrued and unpaid
interest.  Canexus may elect to satisfy its  obligation to pay interest or repay
the principal by issuing  trust units at 95% of the current  market price at the
time of repayment and to pay interest by delivering a sufficient number of trust
units to the debenture trustee to satisfy the interest obligation.

The estimated fair value of the conversion feature of the convertible debentures
amounted to $8 million and was included in non-controlling interests. The amount
of the convertible  debentures  allocated to long-term debt is accreted over the
term of the debt using the effective interest rate method.


(D) INTEREST EXPENSE

<TABLE>
<CAPTION>
                                                                                   Three Months                Nine Months
                                                                                Ended September 30          Ended September 30
                                                                                2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>           <C>           <C>           <C>
Long-Term Debt                                                                    96            96           284           274
Other                                                                              9             4            18            12
                                                                         -------------------------------------------------------
Total                                                                            105           100           302           286
   Less: Capitalized                                                             (24)          (16)          (64)          (60)
                                                                         -------------------------------------------------------
Total                                                                             81            84           238           226
                                                                         =======================================================
</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.


(E) SHORT-TERM BORROWINGS

Nexen has uncommitted, unsecured credit facilities of approximately $466 million
(US$452  million),  none of which were drawn at September 30, 2010 (December 31,
2009 - nil).  We utilized $82 million  (US$80  million) of these  facilities  to
support outstanding letters of credit at September 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>
                                                                                              September 30        December 31
                                                                                                      2010               2009
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                <C>                <C>
NET DEBT (1)
  Long-Term Debt                                                                                     5,678              7,251
     Less: Cash and Cash Equivalents                                                                (1,210)            (1,700)
                                                                                       ---------------------------------------
Total                                                                                                4,468              5,551
                                                                                       =======================================

EQUITY (2)                                                                                           8,606              7,646
                                                                                       =======================================
</TABLE>

(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.


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  September  30,  2010,  the net debt to  adjusted  cash flow was 1.8 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  for
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 9.4 times at September 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 Ended             Year Ended
                                                                                          September 30            December 31
                                                                                                  2010                   2009
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                             <C>                      <C>
Net Income Attributable to Nexen Inc.                                                            1,236                    536
  Add:
     Interest Expense                                                                              324                    312
     Provision for Income Taxes                                                                    719                    260
     Depreciation, Depletion, Amortization and Impairment                                        1,891                  1,802
     Exploration Expense                                                                           282                    302
     Recovery of Non-Cash Stock-Based Compensation                                                 (77)                   (10)
     Change in Fair Value of Crude Oil Put Options                                                  51                    251
     Other Non-Cash Expenses                                                                      (605)                  (136)
                                                                              ------------------------------------------------
Adjusted EBITDA                                                                                  3,821                  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>
                                                                                    Nine Months Ended              Year Ended
                                                                                         September 30             December 31
                                                                                                 2010                    2009
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                            <C>                     <C>
Balance at Beginning of Period                                                                  1,053                   1,059
  Obligations Incurred with Development Activities                                                 26                      27
  Obligations Settled                                                                             (27)                    (42)
  Accretion Expense                                                                                48                      70
  Revisions to Estimates                                                                          108                      13
  Obligations Associated with Discontinued Activities                                            (122)                      -
  Effects of Changes in Foreign Exchange Rate                                                     (15)                    (74)
                                                                              ------------------------------------------------
Balance at End of Period (1), (2)                                                                1,071                   1,053
                                                                              ================================================
</TABLE>

(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 $1,030 million
     (December  31,  2009 - $1,002  million)  and  obligations  relating  to our
     chemicals business amount to $41 million (December 31, 2009 - $51 million).

Our total estimated undiscounted inflated asset retirement obligations amount to
$2,490  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 6%.  Approximately  $238 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>
                                                                                        September 30             December 31
                                                                                                2010                    2009
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                            <C>                   <C>
Deferred Tax Credit                                                                              409                     503
Long-Term Energy Marketing Derivative Contracts (Note 6)                                         119                     212
Defined Benefit Pension Obligations (1)                                                           79                      76
Capital Lease Obligations                                                                         43                      61
Deferred Transportation Revenue                                                                    -                      55
Other                                                                                            116                     114
                                                                              ------------------------------------------------
Total                                                                                            766                   1,021
                                                                              ================================================
</TABLE>

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


13.  SHAREHOLDERS' EQUITY

DIVIDENDS

Dividends  per common share for the three months ended  September  30, 2010 were
$0.05 per common share (2009 - $0.05).  Dividends  per common share for the nine
months  ended  September  30,  2010 were $0.15 per common  share (2009 - $0.15).
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                Nine Months
                                                                                Ended September 30          Ended September 30
                                                                                2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>          <C>           <C>          <C>
Marketing Revenue, Net                                                            82           188           282           676
Long Lake Purchased Bitumen Sales                                                 25             -            63             -
Change in Fair Value of Crude Oil Put Options                                     (3)          (23)          (18)         (218)
Interest                                                                           1             1             6             4
Foreign Exchange Gain (Loss)                                                     (13)           93            (7)          112
Other                                                                             46            37            47            61
                                                                         -------------------------------------------------------
Total                                                                            138           296           373           635
                                                                         =======================================================
</TABLE>

15.  DISPOSITIONS

Canadian Heavy Oil Asset Disposition
------------------------------------
In May 2010, we signed an agreement to sell our heavy oil  properties in Canada.
The sale closed in July 2010 after  receiving  proceeds of $939 million,  net of
closing  adjustments.  We realized a gain of $781 million in the third  quarter.
The  results  of  operations  of  these   properties   have  been  presented  as
discontinued operations.



<TABLE>
<CAPTION>
                                                                                  Three Months                  Nine Months
                                                                                Ended September 30          Ended September 30
                                                                                2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>           <C>          <C>           <C>
Revenues and Other Income
   Net Sales                                                                      13            63           138           169
   Gain on Disposition of Assets                                                 781             -           781             -
                                                                         -------------------------------------------------------
                                                                                 794            63           919           169

Expenses
   Operating                                                                       5            24            50            74
   Depreciation, Depletion, Amortization and Impairment                            1            29            35            93
   General and Administrative                                                      1             5            10            17
   Transportation and Other                                                        -             5             2            12
                                                                         -------------------------------------------------------
                                                                                   7            63            97           196
                                                                         -------------------------------------------------------

Income (Loss) before Provision for Income Taxes                                  787             -           822           (27)
Provision for (Recovery of) Future Income Taxes                                  197             -           206            (7)
                                                                         -------------------------------------------------------

Net Income (Loss) from Discontinued Operations                                   590             -           616           (20)
                                                                         =======================================================

Earnings (Loss) Per Common Share
   Basic                                                                        1.12             -         1.17          (0.04)
                                                                         =======================================================
   Diluted                                                                      1.12             -         1.17          (0.04)
                                                                         =======================================================
</TABLE>


                                       22
<PAGE>

Assets and liabilities on the  Consolidated  Balance Sheet at December 31, 2009,
include the following amounts for discontinued operations.  There were no assets
and liabilities related to discontinued operations at September 30, 2010.

<TABLE>
<CAPTION>
                                                                                                                  December 31
                                                                                                                         2009
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                                    <C>
Property, Plant and Equipment, Net of Accumulated DD&A                                                                    331
Asset Retirement Obligations                                                                                             (116)
Deferred Credits and Other Liabilities                                                                                    (29)
                                                                                                          ---------------------
Total                                                                                                                     186
                                                                                                          =====================
</TABLE>

Natural Gas Energy Marketing Disposition
----------------------------------------
During  the third  quarter  of 2010,  we sold our  North  American  natural  gas
marketing operations.  The sale, which generated proceeds of $11 million, closed
in the third  quarter and we  recognized  a non-cash  loss of $259  million.  On
closing,  the  purchaser  acquired  our North  American  natural gas storage and
transportation  commitments,  natural gas inventory,  and related  financial and
physical derivative positions.  As is customary with such transactions,  not all
contracts  were  assigned to the  purchaser by the closing date. We have a total
return swap in place with the purchaser to transfer to them the economic results
on the unassigned contracts until they are assigned to the purchaser.  The total
return swap and unassigned contracts are derivative  instruments carried at fair
value on our balance  sheet.  The related gains and losses offset each other for
the quarter and future periods.

In connection  with our natural gas energy  marketing  disposition,  we assigned
substantially  all of our natural  gas  transportation  and  storage  contracts,
reducing  our future  commitments  by $342  million.  We agreed to maintain  our
parental  guarantee  to the  pipeline  provider  related  to one  transportation
commitment.  We are  obligated  to  perform  under  the  guarantee  only  if the
purchaser  does not meet its obligation to the pipeline  provider.  To guarantee
its performance,  the purchaser provided us with collateral of US$43 million for
the  maximum  exposure  under the  guarantee.  This  collateral  is  included in
accounts payable. We expect to cancel this guarantee in the fourth quarter.

Canadian Undeveloped Oil Sand Leases
------------------------------------
During the second  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 a 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                  Nine Months
                                                                                Ended September 30          Ended September 30
(millions of shares)                                                            2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                          <C>           <C>           <C>           <C>
Weighted-average number of common shares outstanding                           525.0         521.7         524.4         521.0
Shares issuable pursuant to tandem options                                       4.6          10.3           5.6          10.7
Shares notionally purchased from proceeds of tandem options                     (3.6)         (7.0)         (4.4)         (7.5)
                                                                         -------------------------------------------------------
Weighted-average number of diluted common shares outstanding                   526.0         525.0         525.6         524.2
                                                                         =======================================================
</TABLE>

In calculating the weighted-average  number of diluted common shares outstanding
for the three and nine months ended  September 30, 2010, we excluded  15,496,237
and 16,074,998  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 nine months ended September 30, 2009, we excluded  13,077,285 and 13,236,034
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.


                                       23


<PAGE>


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  believe  the
resolution  of these  matters  would not have a material  adverse  effect on our
liquidity, consolidated financial position or results of operations.


18.  CASH FLOWS

(A) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH

<TABLE>
<CAPTION>
                                                                                   Three Months                Nine Months
                                                                                Ended September 30          Ended September 30
                                                                                2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>           <C>         <C>           <C>
Depreciation, Depletion, Amortization and Impairment                             477           329         1,234         1,087
Stock-Based Compensation                                                          (3)          (19)          (44)           23
Recovery of Future Income Taxes                                                 (234)          (81)         (423)         (390)
Net Loss on Dispositions                                                         259             -           179             -
Non-cash Items Included in Discontinued Operations                              (583)           29          (540)           86
Change in Fair Value of Crude Oil Put Options                                      3            23            18           218
Foreign Exchange                                                                   1          (117)            2          (154)
Other                                                                            (22)           10             7            17
                                                                         -------------------------------------------------------
Total                                                                           (102)          174           433           887
                                                                         =======================================================
</TABLE>

(B) CHANGES IN NON-CASH WORKING CAPITAL

<TABLE>
<CAPTION>
                                                                                   Three Months                Nine Months
                                                                                Ended September 30          Ended September 30
                                                                                2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>           <C>         <C>           <C>
   Accounts Receivable                                                           240           212             6             39
   Inventories and Supplies                                                      (88)          (13)          (12)          (142)
   Other Current Assets                                                          (32)          (24)           46            (12)
   Accounts Payable and Accrued Liabilities                                       (5)          (68)          350            251
   Other Current Liabilities                                                      (8)           20           (10)            16
                                                                         -------------------------------------------------------
Total                                                                            107           127           380            152
                                                                         =======================================================

Relating to:
   Operating Activities                                                          212           113           410            193
   Investing Activities                                                         (105)           14           (30)           (41)
                                                                         -------------------------------------------------------
Total                                                                            107           127           380            152
                                                                         =======================================================
</TABLE>

(C) OTHER CASH FLOW INFORMATION

<TABLE>
<CAPTION>
                                                                                   Three Months                Nine Months
                                                                                Ended September 30          Ended September 30
                                                                                2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>           <C>         <C>           <C>
Interest Paid                                                                    103            70           293           248
Income Taxes Paid                                                                376           179           626           247
                                                                         -------------------------------------------------------
</TABLE>

Cash flow from other  operating  activities  includes cash  outflows  related to
geological  and  geophysical  expenditures  of $31 million for the three  months
ended  September  30,  2010 (2009 - $16  million)  and $60  million for the nine
months ended September 30, 2010 (2009 - $59 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 SEPTEMBER 30, 2010

<TABLE>
<CAPTION>
                                                                                              Energy             Corporate
                                                       Oil and Gas                         Marketing  Chemicals  and Other    Total
------------------------------------------------------------------------------------------------------------------------------------
                                United                        United              Other
                               Kingdom   Canada(1) Syncrude   States    Yemen Countries(2)
                              ------------------------------------------------------------
<S>                              <C>      <C>        <C>      <C>       <C>        <C>         <C>        <C>      <C>       <C>
Net Sales                          753      117        130       98       179         13           8        118        -      1,416
Marketing and Other                  5       25          2        -         4          -         104         13      (15)(3)    138
                              ------------------------------------------------------------------------------------------------------
Total Revenues                     758      142        132       98       183         13         112        131      (15)     1,554

Less: Expenses
  Operating                         84      112         74       23        38          1           8         80        -        420
  Depreciation, Depletion,
   Amortization and
     Impairment                    212       67         12      127        29          3           4         13       10        477
  Transportation and Other           1       56          5        -         2          1          62         12        3        142
  General and
   Administrative                    5       15          1       17         2          7          19          8       58        132
  Exploration                       11        7          -       18         -         20(4)        -          -        -         56
  Interest                           -        -          -        -         -          -           -          4       77         81
  Net Loss on Dispositions           -        -          -        -         -          -         259          -        -        259
                              ------------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
  before Income Taxes              445     (115)        40      (87)      112        (19)       (240)        14     (163)       (13)
Less: Provision for
  (Recovery Of) Income Taxes       223      (28)        10      (31)       39        (17)        (94)         4      (70)        36
Less: Non-Controlling
  Interests                          -        -          -        -         -          -           -          4        -          4
Add: Net Income from
Discontinued Operations              -      564          -        -         -          -          26          -        -        590
                              ------------------------------------------------------------------------------------------------------
NET INCOME (LOSS)                  222      477         30      (56)       73         (2)       (120)         6      (93)       537
                              ======================================================================================================

IDENTIFIABLE ASSETS              4,912    7,915(5)   1,302    1,675       207       1,344(6)   2,247(7)     771    1,858     22,231
                              ======================================================================================================

Capital Expenditures
                              ------------------------------------------------------------------------------------------------------
EXPLORATION & DEVELOPMENT          187      169         28       28        13         129          9         19       10        592
                              ======================================================================================================

Property, Plant and
Equipment
  Cost                           6,530    8,600      1,531    3,993     2,453       1,267        234      1,244      397     26,249
  Less: Accumulated DD&A         3,170      827        301    2,713     2,367         100         70        592      274     10,414
                              ------------------------------------------------------------------------------------------------------
NET BOOK VALUE                   3,360    7,773(5)   1,230    1,280        86       1,167(6)     164        652      123     15,835
                              ======================================================================================================
</TABLE>

(1) Includes results of operations from conventional,  oilsands,  shale gas and
    CBM.
(2) Includes results of operations from producing activities in Colombia.
(3) Includes  interest  income of $1 million,  foreign  exchange  losses of $13
    million  and a decrease  in the fair  value of crude oil put  options of $3
    million.
(4) Includes exploration activities primarily in Nigeria, Norway and Colombia.
(5) Includes  PP&E  costs of $6,133  million  related  to our  insitu oil sands
    projects (Long Lake and future  phases).
(6) Includes PP&E costs of $1,119 million  related  to  Nigeria.
(7) Approximately 82% of Marketing's identifiable assets are accounts receivable
    and inventories.


                                       25

<PAGE>



THREE MONTHS ENDED SEPTEMBER 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                          478       29        137       74       176         16           9        115          -    1,034
Marketing and Other                  5       (6)         -        -         3          6         188         29         71(2)   296
                              ------------------------------------------------------------------------------------------------------
Total Revenues                     483       23        137       74       179         22         197        144         71    1,330

Less: Expenses
  Operating                         71       18         62       23        49          2           5         67          -      297
  Depreciation, Depletion,
   Amortization and
     Impairment                    162       30         13       67        19          2          14         12         10      329
  Transportation and Other           3        3          5        2         7          -         141         13          6      180
  General and
   Administrative (3)                8       11          -       13         4          5          19          9         39      108
  Exploration                        7       24          -       40         -         18(4)        -          -          -       89
  Interest                           -        -          -        -         -          -           -          2         82       84
                              ------------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
  before Income Taxes              232      (63)        57      (71)      100         (5)         18         41        (66)     243
Less: Provision for
  (Recovery of) Income Taxes       102      (15)        14      (30)       35         (5)          8          9         (9)     109
Less: Non-Controlling
  Interests                          -        -          -        -         -          -           -         12          -       12
Add: Net Income from
Discontinued Operations              -        -          -        -         -          -           -          -          -        -
                              ------------------------------------------------------------------------------------------------------
NET INCOME (LOSS)                  130      (48)        43      (41)       65          -          10         20        (57)     122
                              ======================================================================================================

IDENTIFIABLE ASSETS              5,157    7,756(5)   1,244    1,880       241        976       3,114(6)     704      1,997   23,069
                              ======================================================================================================

Capital Expenditures
                              ------------------------------------------------------------------------------------------------------
EXPLORATION & DEVELOPMENT          165      177         17       77        11        139           9         53          7      655
                              ======================================================================================================

Property, Plant and
Equipment
  Cost                           6,165    9,558      1,424    3,957     2,516        782         250      1,086        356   26,094
  Less: Accumulated DD&A         2,396    1,955        264    2,507     2,369         97          78        552        234   10,452
                              ------------------------------------------------------------------------------------------------------
NET BOOK VALUE                   3,769    7,603(5)   1,160    1,450       147        685         172        534        122   15,642
                              ======================================================================================================
</TABLE>

(1) Includes results of operations from producing activities in Colombia.
(2) Includes  interest  income of $1  million,  foreign  exchange  gains of $93
    million  and a decrease  in the fair value of crude oil put  options of $23
    million.
(3) Includes recovery of stock-based compensation expense of $5 million.
(4) Includes exploration activities primarily in Norway, Nigeria and Colombia.
(5) Includes  PP&E  costs of $5,946  million  related  to our  insitu oil sands
    projects  (Long  Lake  and  future  phases).
(6) Approximately 80% of Marketing's identifiable assets are accounts receivable
    and inventories.



                                       26

<PAGE>



NINE MONTHS ENDED SEPTEMBER 30, 2010

<TABLE>
<CAPTION>
                                                                                              Energy             Corporate
                                                       Oil and Gas                         Marketing  Chemicals  and Other    Total
------------------------------------------------------------------------------------------------------------------------------------
                                United                        United              Other
                               Kingdom   Canada(1) Syncrude   States    Yemen Countries(2)
                              ------------------------------------------------------------
<S>                              <C>      <C>        <C>      <C>       <C>        <C>         <C>        <C>        <C>      <C>

Net Sales                        2,243        353      416       310      518          42         29        336           -    4,247
Marketing and Other                 14         63        4         1       12           -        282         13         (16)(3)  373
                              ------------------------------------------------------------------------------------------------------
Total Revenues                   2,257        416      420       311      530          42        311        349         (16)   4,620

Less: Expenses
  Operating                        237        327      212        70      115           4         25        228           -    1,218
  Depreciation, Depletion,
   Amortization and
     Impairment                    578        192       39       250       88           7         14         36          30    1,234
  Transportation and Other           4        147       16         2        8           1        274         38          11      501
  General and
   Administrative (4)               18         29        1        41        2          18         51         25         131      316
  Exploration                       42         20        -        47        -          90 (5)      -          -           -      199
  Interest                           -          -        -         -        -           -          -          7         231      238
  Net Loss on Dispositions           -        (80)       -         -        -           -        259          -           -      179
                              ------------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
  before Income Taxes            1,378       (219)     152       (99)     317         (78)      (312)        15        (419)     735
Less: Provision for
  (Recovery of) Income Taxes       689        (55)      38       (35)     111         (70)      (122)         4        (190)     370
Less: Non-Controlling
  Interests                          -          -        -         -        -           -          -          4           -        4
Add: Net Income from
Discontinued Operations              -        590        -         -        -           -         26          -           -      616
                              ------------------------------------------------------------------------------------------------------
NET INCOME (LOSS)                  689        426      114       (64)     206          (8)      (164)         7        (229)     977
                              ======================================================================================================

IDENTIFIABLE ASSETS              4,912      7,915(6) 1,302     1,675      207       1,344(7)   2,247(8)     771       1,858   22,231
                              ======================================================================================================

Capital Expenditures
                              ------------------------------------------------------------------------------------------------------
EXPLORATION & DEVELOPMENT          460        662       71       156       40         404         25        121          26    1,965
                              ======================================================================================================

Property, Plant and
Equipment
  Cost                           6,530      8,600    1,531     3,993    2,453       1,267        234      1,244         397   26,249
  Less: Accumulated DD&A         3,170        827      301     2,713    2,367         100         70        592         274   10,414
                              ------------------------------------------------------------------------------------------------------
NET BOOK VALUE                   3,360      7,773(6) 1,230     1,280       86       1,167(7)     164        652         123   15,835
                              ======================================================================================================
</TABLE>

(1)  Includes results of operations from conventional,  oilsands,  shale gas and
     CBM.
(2)  Includes results of operations from producing activities in Colombia.
(3)  Includes  interest  income of $6  million,  foreign  exchange  losses of $7
     million, decrease in the fair value of crude oil put options of $18 million
     and other gains of $3 million.
(4)  Includes recovery of stock-based compensation expense of $34 million.
(5)  Includes exploration activities primarily in Norway and Colombia.
(6)  Includes  PP&E  costs of $6,133  million  related  to our  insitu oil sands
     projects (Long Lake and future phases).
(7)  Includes PP&E costs of $1,119 million related to Nigeria.
(8)  Approximately   82%  of  Marketing's   identifiable   assets  are  accounts
     receivable and inventories.



                                       27
<PAGE>



NINE MONTHS ENDED SEPTEMBER 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                        1,574        112      320       225      513          55         29        348        -      3,176
Marketing and Other                 13          2        1         -       10           6        676         44     (117)(2)    635
                              ------------------------------------------------------------------------------------------------------
Total Revenues                   1,587        114      321       225      523          61        705        392     (117)     3,811

Less: Expenses
  Operating                        175         51      205        73      145           6         21        196        -        872
  Depreciation, Depletion,
   Amortization and
     Impairment                    537         91       33       215       92          11         21         53       34      1,087
  Transportation and Other          14          7       17        18       25           -        469         37       19        606
  General and
   Administrative (3)               15         41        1        51        5          29         68         34      119        363
  Exploration                       26         53        -        87        -          53(4)       -          -        -        219
  Interest                           -          -        -         -        -           -          -          6      220        226
                              ------------------------------------------------------------------------------------------------------
Income (Loss) from
Continuing Operations
  before Income Taxes              820       (129)      65      (219)     256         (38)       126         66     (509)       438
Less: Provision for
  (Recovery of) Income Taxes       358        (32)      16       (81)      89         (29)        52         15     (264)       124
Less: Non-Controlling
  Interests                          -          -        -         -        -           -          -         17        -         17
Add: Net Loss from
Discontinued Operations              -        (20)       -         -        -           -          -          -        -        (20)
                              ------------------------------------------------------------------------------------------------------
NET INCOME (LOSS)                  462       (117)      49      (138)     167          (9)        74         34     (245)       277
                              ======================================================================================================

IDENTIFIABLE ASSETS              5,157      7,756(5) 1,244     1,880      241         976      3,114(6)     704    1,997     23,069
                              ======================================================================================================

Capital Expenditures
  Exploration & Development        500        708       56       217       62         378         20        161       17      2,119
  Proved Property
     Acquisitions                    -        755        -         -        -           -          -          -        -        755
                              ------------------------------------------------------------------------------------------------------
TOTAL                              500      1,463       56       217       62         378         20        161       17      2,874
                              ======================================================================================================

Property, Plant and
Equipment
  Cost                           6,165      9,558    1,424     3,957    2,516         782        250      1,086      356     26,094
  Less: Accumulated DD&A         2,396      1,955      264     2,507    2,369          97         78        552      234     10,452
                              ------------------------------------------------------------------------------------------------------
NET BOOK VALUE                   3,769      7,603(5) 1,160     1,450      147         685        172        534      122     15,642
                              ======================================================================================================
</TABLE>

(1)  Includes results of operations from producing activities in Colombia.
(2)  Includes  interest  income of $4 million,  foreign  exchange  gains of $112
     million,  decrease  in the  fair  value of crude  oil put  options  of $218
     million and other losses of $15 million.
(3)  Includes stock-based compensation expense of $51 million.
(4)  Includes exploration activities primarily in Norway, Nigeria and Colombia.
(5)  Includes  PP&E  costs of $5,946  million  related  to our  insitu oil sands
     projects (Long Lake and future phases).
(6)  Approximately   80%  of  Marketing's   identifiable   assets  are  accounts
     receivable and inventories.


                                       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:

<TABLE>
<CAPTION>
UNAUDITED CONSOLIDATED STATEMENT OF INCOME - US GAAP
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
                                                                                    Three Months                Nine Months
                                                                                 Ended September 30          Ended September 30
(Cdn$ millions, except per share amounts)                                        2010          2009          2010          2009
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>          <C>            <C>           <C>
REVENUES AND OTHER INCOME
   Net Sales                                                                    1,416        1,034          4,247         3,176
   Marketing and Other (v); (vi)                                                  129          344            432           702
                                                                         --------------------------------------------------------
                                                                                1,545        1,378          4,679         3,878
                                                                         --------------------------------------------------------
EXPENSES
   Operating                                                                      420          297          1,218           872
   Depreciation, Depletion, Amortization and Impairment                           477          329          1,234         1,087
   Transportation and Other (v)                                                   142          186            501           604
   General and Administrative (iv)                                                123           84            295           377
   Exploration                                                                     56           89            199           219
   Interest                                                                        81           84            238           226
  Net Loss on Dispositions                                                        259            -            179             -
                                                                         --------------------------------------------------------
                                                                                1,558        1,069          3,864         3,385
                                                                         --------------------------------------------------------

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE PROVISION FOR INCOME
   TAXES                                                                          (13)         309            815           493
                                                                         --------------------------------------------------------

PROVISION FOR (RECOVERY OF) INCOME TAXES
   Current                                                                        270          190            793           514
   Deferred (iv); (vi)                                                           (235)         (68)          (399)         (377)
                                                                         --------------------------------------------------------
                                                                                   35          122            394           137
                                                                         --------------------------------------------------------

NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE NON-CONTROLLING
   INTERESTS                                                                      (48)         187            421           356
   Less: Net Income Attributable to Canexus Non-Controlling Interests
                                                                                   (4)         (12)            (4)          (17)
                                                                         --------------------------------------------------------

NET INCOME (LOSS) FROM CONTINUING OPERATIONS ATTRIBUTABLE TO NEXEN INC.           (52)         175            417           339

   Net Income (Loss) from Discontinued Operations                                 590            -            616           (20)
                                                                         --------------------------------------------------------

NET INCOME ATTRIBUTABLE TO NEXEN INC. - US GAAP(1)                                538          175          1,033           319
                                                                         ========================================================

EARNINGS (LOSS) PER COMMON SHARE FROM CONTINUING OPERATIONS ($/share)
   Basic                                                                        (0.10)         0.34          0.79           0.65
                                                                         ========================================================
   Diluted                                                                      (0.10)         0.33          0.79           0.65
                                                                         ========================================================

EARNINGS PER COMMON SHARE ($/share)
   Basic                                                                         1.03          0.34          1.97           0.61
                                                                         ========================================================
   Diluted                                                                       1.03          0.33          1.97           0.61
                                                                         ========================================================
</TABLE>



<TABLE>
<CAPTION>
(1) RECONCILIATION OF CANADIAN AND US GAAP NET INCOME                               Three Months                 Nine Months
                                                                                 Ended September 30           Ended September 30
                                                                                 2010          2009          2010           2009
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>          <C>            <C>           <C>
Net Income Attributable to Nexen Inc - Canadian GAAP                              537           122           977            277
Impact of US Principles, Net of Income Taxes:
   Stock-based Compensation (iv)                                                    7            17            16            (11)
   Inventory Valuation (vi)                                                        (6)           29            40             46
   Deferred Taxes (vii)                                                             -             7             -              7
                                                                         --------------------------------------------------------
Net Income Attributable to Nexen Inc - US GAAP                                    538           175         1,033            319
                                                                         ========================================================
</TABLE>


                                       29
<PAGE>


<TABLE>
<CAPTION>
UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP
                                                                                              September 30         December 31
(Cdn$ millions, except share amounts)                                                                 2010                2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                <C>                 <C>
ASSETS
   CURRENT ASSETS
      Cash and Cash Equivalents                                                                      1,210               1,700
      Restricted Cash                                                                                   35                 198
      Accounts Receivable                                                                            2,305               2,788
      Inventories and Supplies (vi)                                                                    533                 610
      Other                                                                                            142                 185
                                                                                        ----------------------------------------
         Total Current Assets                                                                        4,225               5,481
                                                                                        ----------------------------------------

   PROPERTY, PLANT AND EQUIPMENT
      Net of Accumulated Depreciation, Depletion, Amortization and
         Impairment of $10,807 (December 31, 2009 - $11,200) (i); (iii)                             15,786              15,443
   GOODWILL                                                                                            316                 339
   DEFERRED INCOME TAX ASSETS                                                                        1,608               1,148
   DEFERRED CHARGES AND OTHER ASSETS                                                                   236                 370
                                                                                        ----------------------------------------
TOTAL ASSETS                                                                                        22,171              22,781
                                                                                        ========================================

LIABILITIES
   CURRENT LIABILITIES
      Accounts Payable and Accrued Liabilities (iv)                                                  3,015               3,131
      Accrued Interest Payable                                                                          78                  89
      Dividends Payable                                                                                 26                  26
                                                                                        ----------------------------------------
         Total Current Liabilities                                                                   3,119               3,246
                                                                                        ----------------------------------------

   LONG-TERM DEBT                                                                                    5,678               7,251
   DEFERRED INCOME TAX LIABILITIES (i); (ii); (iv); (vi); (vii)                                      3,060               2,720
   ASSET RETIREMENT OBLIGATIONS                                                                      1,007               1,018
   DEFERRED CREDITS AND OTHER LIABILITIES (ii)                                                         871               1,126

EQUITY
   Nexen Inc. Shareholders' Equity
      Common Shares, no par value
         Authorized:   Unlimited
         Outstanding:  2010 - 525,032,386 shares
                       2009 - 522,915,843 shares                                                     1,097               1,049
      Contributed Surplus                                                                                -                   1
      Retained Earnings (i); (iii); (iv); (vi); (vii)                                                7,530               6,575
      Accumulated Other Comprehensive Loss (ii)                                                       (275)               (269)
                                                                                        ----------------------------------------
   Total Nexen Inc. Shareholders' Equity                                                             8,352               7,356
      Canexus Non-Controlling Interests                                                                 84                  64
                                                                                        ----------------------------------------
   TOTAL EQUITY                                                                                      8,436               7,420
                                                                                        ----------------------------------------
   COMMITMENTS, CONTINGENCIES AND GUARANTEES
TOTAL LIABILITIES AND EQUITY                                                                        22,171              22,781
                                                                                        ========================================
</TABLE>

                                       30

<PAGE>


UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - US GAAP
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
<TABLE>
<CAPTION>
                                                                                    Three Months                Nine Months
                                                                                 Ended September 30          Ended September 30
                                                                                 2010          2009          2010          2009
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>           <C>         <C>            <C>
Net Income Attributable to Nexen Inc. - US GAAP                                   538           175         1,033          319
Other Comprehensive Loss, Net of Income Taxes:
   Foreign Currency Translation Adjustment                                         (7)          (26)           (6)         (49)
                                                                         ------------------------------------------------------
Comprehensive Income Attributable to Nexen Inc. - US GAAP                         531           149         1,027          270
                                                                         ======================================================
</TABLE>


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


                                                                                              September 30           December 31
                                                                                                      2010                  2009
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                 <C>                   <C>
Foreign Currency Translation Adjustment                                                               (196)                 (190)
Unamortized Defined Benefit Pension Plan Costs (ii)                                                    (79)                  (79)
                                                                                       ------------------------------------------
Accumulated Other Comprehensive Loss                                                                  (275)                 (269)
                                                                                       ==========================================
</TABLE>

There are  currently no  differences  between our Canadian and US GAAP Cash Flow
and as such we have not presented a separate US GAAP Cash Flow Statement.

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
     September  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 $9 million and
            $21 million,  ($7 million and $16 million, net of income taxes), for
            the three and nine months ended September 30, 2010, (2009 - lower by
            $24 million and higher by $14  million,  respectively,  ($17 million
            and $11 million, net of income taxes)); and
      o     accounts  payable and accrued  liabilities are higher by $72 million
            as at  September  30, 2010  (December  31, 2009 - $93  million)  and
            deferred  income tax liabilities are $21 million lower (December 31,
            2009 - $26 million).

v.   Under US GAAP,  asset  disposition  gains  and  losses  are  included  with
     transportation  and other  expense.  For the three  and nine  months  ended
     September  30,  2010  there  were no  gains  or  losses  reclassified  from
     marketing and other income to  transportation  and other expense (losses of
     $6 million and gains of $2 million,  respectively were reclassified for the
     three and nine months ended September 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 lower by $9 million and higher by $59
            million  (lower by $6  million  and  higher by $40  million,  net of
            income taxes) for the three and nine months ended September 30, 2010
            (2009 - higher by $42 million and $69 million  ($29  million and $46
            million, net of income taxes)); and
      o     inventories  are  lower by $11  million  as at  September  30,  2010
            (December  31, 2009 - lower by $70 million) and deferred  income tax
            liabilities  are $4 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 September 30, 2010, the total amount of our  unrecognized tax benefit
     was approximately $296 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 September  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 $9 million. We had
     no interest or penalties  included in the US GAAP - Unaudited  Consolidated
     Statement of Income for the three and nine months ended September 30, 2010.

     Our income tax filings are subject to audit by taxation  authorities and as
     at  September  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 OCTOBER 27, 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 THIRD QUARTER RESULTS

<TABLE>
<CAPTION>
                                                                                      Three Months                   Nine Months
                                                                                   Ended September 30            Ended September 30
(Cdn$ millions, except as indicated)                                               2010           2009           2010           2009
------------------------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>            <C>            <C>            <C>
Production before Royalties (mboe/d)                                                239            214            246            235
Production after Royalties (mboe/d)                                                 213            184            218            206
Nexen's Average Realized Oil and Gas Price (Cdn$/boe)                             68.21          63.00          68.60          56.89

Cash Flow from Operating Activities                                                 668            461          1,976          1,359
Net Income Attributable to Nexen Inc.                                               537            122            977            277
Earnings per Common Share, Basic ($/share)                                         1.02           0.23           1.86           0.53

Capital Investment                                                                  592            655          1,965          2,119
Acquisition of Additional Interest in Long Lake                                       -              -              -            755
Net Debt (1)                                                                      4,468          5,532          4,468          5,532
                                                                                ----------------------------------------------------
</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.

Net income increased  significantly  from a year ago as we completed the sale of
our Canadian heavy oil properties during the quarter. Production for the quarter
increased  12% from last  year  despite  the sale of our  heavy oil  properties,
temporary downtime at Scott/Telford and Syncrude, and natural declines in Yemen.
Commodity  prices  were higher than last year and we realized an average oil and
gas price of $68.21/boe,  an increase of 8% over last year. The impact of higher
benchmark crude oil prices is partially mitigated by the weaker US dollar.

At our Long Lake oil sands  project,  bitumen  production  volumes  have doubled
since the  beginning  of the year to over  31,500  bbls/d  (gross).  In the Horn
River,  we completed  fracing the eight shale gas wells we drilled  earlier this
year allowing us to start production here earlier than scheduled.

Investment  during the  quarter  focused on  progressing  our major  development
project at Usan to first oil  production  in 2012,  fracing and  completing  our
shale gas eight  well pad at Horn  River and on  exploration  activities  in the
North Sea. During the quarter, we commenced  activities on the West Rochelle and
Polecat  prospects  in the UK  North  Sea.  At West  Rochelle,  we  successfully
confirmed gas and oil in the reservoir and are  sidetracking the well to further
delineate the discovery.

In the Gulf of Mexico,  the drilling  moratorium has been lifted, and we plan to
move forward with the drilling of our exploration  prospects at Kakuna and Angel
Fire and with the appraisal of our Appomattox discovery.


                                       33
<PAGE>



During the quarter,  we completed the sale of our Canadian heavy oil properties.
The sale generated cash proceeds of $939 million, after closing adjustments, and
we  realized  a  pre-tax  gain of  approximately  $781  million.  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.  We also  completed the
sale of our Energy  Marketing  natural gas  operations,  generating  proceeds of
approximately $11 million and a non-cash loss of $259 million. With these sales,
we achieved our target of generating proceeds of approximately $1.0 billion from
non-core asset sales.  We now expect to generate  approximately  $1.5 billion of
proceeds  once we complete our  disposition  program,  including the sale of our
Canexus investment expected in the next year.

We used the proceeds from the  disposition  of our Canadian heavy oil properties
to pay down our short-term borrowings and term credit facilities.  Our available
liquidity  is   approximately   $4.4  billion  and  includes  cash  on  hand  of
approximately  $1.2 billion and undrawn  lines of credit of  approximately  $3.2
billion.  Debt maturities in the next five years can be repaid from current cash
on hand and cash flow from operating activities. The average term-to-maturity of
our  long-term  debt is  approximately  21 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 area  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 Gulf of Mexico; and
     o    advancing  our Horn River  shale gas play and  building  our shale gas
          land position in northeast British Columbia.

Details of our capital programs are set out below:

                                          Three Months Ended  Nine Months Ended
                                                September 30       September 30
                                                        2010               2010
--------------------------------------------------------------------------------
Oil and Gas
  United Kingdom                                         187                460
  Canada                                                 120                505
  Synthetic (mainly Long Lake Phase 1)                    49                157
  Syncrude                                                28                 71
  United States                                           28                156
  Yemen                                                   13                 40
  Nigeria                                                118                336
  Other Countries                                         11                 68
                                         ---------------------------------------
                                                         554              1,793
Chemicals                                                 19                121
Energy Marketing, Corporate and Other                     19                 51
                                         ---------------------------------------
Total Capital                                            592              1,965
                                         =======================================

UNITED KINGDOM - NORTH SEA
During the quarter,  we commenced  activities  on the West  Rochelle and Polecat
prospects  and  are  evaluating  drilling  results.  At West  Rochelle,  we have
successfully confirmed gas and oil pay in the reservoir and are sidetracking the
well to further  delineate the  discovery.  This well is a potential  tieback to
Scott.  Polecat is a potential tieback to Buzzard. We plan to drill the Bluebell
prospect before year end, a potential southerly extension of the Buzzard field.

Elsewhere  in the North Sea, we  continue to expand our acreage  position in the
Golden Eagle area,  which includes our  discoveries  at Golden Eagle,  Hobby and
Pink. We intend to drill an exploration well here early next year.  Golden Eagle
area development supports standalone  facilities and is economic with oil prices
significantly  lower than they are currently.  We are advancing area development
plans, doing initial engineering and preparing cost


                                       34
<PAGE>

estimates  for  potential  sanctioning  in 2011. We have a 34% interest in both
Golden Eagle and Hobby, a 46% interest in Pink,  and operate all three.  In late
October,  the UK Government  announced that,  subject to completion of the award
process, we were the successful  applicant for 10 licenses covering 18 blocks in
the UK North Sea 26th Offshore Oil and Gas Licensing Round. Most of these blocks
are near our existing acreage and infrastructure.

CANADA - HORN RIVER SHALE GAS
During the quarter, we completed a 144 frac program on our eight-well pad in the
Horn River at a pace of 3.5 fracs per day with a 100% frac success rate. Earlier
this year, we completed  our drilling  campaign here at an average rate of under
25 days per well. Compared to our previous program,  these wells were drilled in
35% fewer days and were 80% longer. We recently started production testing these
wells and expect to reach peak  production  rates of 50 mmcf/d this  winter.  We
plan to follow up this successful  program with a nine well pad that would start
drilling this winter.  The wells would be fraced and completed  next summer with
first  production in the fourth  quarter of 2011.  This allows us to advance our
Horn  River play while we  progress  our plans for an 18-well  pad to be drilled
next winter with first production expected in late 2012.

We have  approximately  90,000  acres at Dilly  Creek in the Horn  River  basin.
Following  our success at a June land sale,  we now have over  300,000  acres of
shale gas lands in the Horn River, Cordova and Liard basins in northeast British
Columbia.

SYNTHETIC
At Long Lake,  bitumen  production  to feed the  upgrader  continues  to ramp up
following the  completion of the  turnaround  last fall. We have improved  steam
reliability   and  are   continuously   optimizing  our  wells.   The  resulting
improvements  in well capability have enabled us to increase our steam injection
to 165,000  bbls/d and gross bitumen  production  volumes to over 31,500 bbls/d,
our  highest  rate yet. 78 of 91 well pairs are now on  production  and steam is
circulating in an additional six pairs.  These circulating wells are expected to
be converted to  production  in the coming  months.  The table below shows gross
monthly bitumen  production  volumes for the current year. We own a 65% operated
interest in the Long Lake project.

                                                                   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                                                                28,700
August 2010                                                              26,500
September 2010                                                           24,000
October 2010 - Month to date                                             30,000

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 65 wells from gas lift to electric  submersible
pumping (ESPs). The remainder will be converted in due course.  This provides us
with more  flexibility to optimize steam injection and grow bitumen  production.
In  addition,  we have  taken the  opportunity  to  upsize  the ESPs in our best
producers.  We have  recently  completed our first set of acid  stimulations  on
eight producing wells. These optimizations allow us to draw more fluids into the
wells,  increasing  bitumen  production.  Third quarter  production volumes were
impacted as we shut in these wells to complete these activities.

Following  the  turnaround  late  last  year,  production  volumes  returned  to
pre-turnaround  rates in December.  Since that time,  we have made the following
progress:

O    Steam injection has increased from 100,000 bbls/d to 165,000 bbls/d;

O    Bitumen production has doubled to over 31,500 bbls/d (gross);

O    The number of wells  producing at an average of design rates has  increased
     from 10 to 24; and

O    The all-in  steam-to-oil  ratio (SOR) has decreased from approximately 6 to
     5.2. This includes 51 wells that are still in the steam  circulation  stage
     or  early  in  their  growth  cycle.  As  these  wells  transition  to SAGD
     production,  the increase in production  rates should result in a continued
     decrease in SOR.



                                       35
<PAGE>

As previously  announced,  we have a number of initiatives  underway to increase
bitumen volumes. These include:

O  Bringing on the remaining 13 wells to SAGD production;

O  Completing our ESP conversion program;

O  Optimizing producing wells; and

O  Developing two additional  well pads and  engineering  two more  once-through
   steam generators,  which will add 10 to 15% to our steam capacity.  We expect
   these to be available over the next 18 to 24 months.

We are committed to the  development of our  significant  oil sands resource and
plan to develop the next phase in two smaller SAGD stages of about 40,000 bbls/d
each with upgrading available after ramp up.

UNITED STATES - GULF OF MEXICO
The drilling  moratorium in the Gulf of Mexico was lifted earlier this month and
we are working to recommence  exploration and appraisal drilling. The moratorium
had no impact on our shelf and  deep-water  production and rig standby costs are
expected to be minimal.  Throughout the duration of the moratorium, the first of
our  deepwater  rigs was used by a  co-contractor  and on the second rig, we are
close to completing discussions with the rig provider regarding our contract.

In the first  quarter,  we made a  significant  discovery in the  deep-water  at
Appomattox,   located  in  Mississippi  Canyon  blocks  391  and  392.  Drilling
activities  resulted in an oil discovery  following an exploration  well and two
appraisal  sidetracks.  We plan to further  appraise this discovery once permits
are received.

Appomattox is the third discovery in the area following  earlier  discoveries at
Shiloh and  Vicksburg.  Our  drilling  plans also include  further  appraisal at
Vicksburg which is located six miles east of Appomattox and has the potential to
be  co-developed.  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 this year (Kakuna and Angel
Fire) with our two new  deep-water  drilling  rigs were  delayed by the drilling
moratorium.  We have  submitted  applications  for  permits  to drill  these two
prospects.

OFFSHORE WEST AFRICA
Development of the Usan field is progressing well with first production on-track
for 2012. The development includes a floating production, storage and 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. Major topside modules have been
lifted  onto the FPSO  deck and the  FPSO  unit is 88%  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.


                                       36
<PAGE>


FINANCIAL RESULTS

CHANGE IN NET INCOME
<TABLE>
<CAPTION>
                                                                                                 2010 VS 2009
                                                                              --------------------------------------------------
                                                                                     Three Months               Nine Months
                                                                                   Ended September 30        Ended September 30
------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                             <C>                      <C>
NET INCOME AT SEPTEMBER 30, 2009(1)                                                               122                      277
                                                                              -------------------------------------------------
     Favorable (unfavorable) variances(2):

         Realized Commodity Prices
              Crude Oil                                                                            56                      578
              Natural Gas                                                                          21                       33
                                                                              -------------------------------------------------
                  Total Price Variance                                                             77                      611

         Production Volumes, After Royalties
              Crude Oil                                                                           210                      276
              Natural Gas                                                                           5                       55
              Changes in Crude Oil Inventory For Sale                                              38                      110
                                                                              -------------------------------------------------
                  Total Volume Variance                                                           253                      441

         Oil and Gas Operating Expense                                                            (88)                    (286)

         Oil and Gas Depreciation, Depletion, Amortization and
              Impairment                                                                         (129)                    (117)

         Exploration Expense                                                                       33                       20

         Energy Marketing Revenue, Net                                                             (9)                    (203)

         Chemicals Contribution                                                                   (18)                     (46)

         General and Administrative Expense (3)                                                   (20)                      54

         Interest Expense                                                                           3                      (12)

         Current Income Taxes                                                                     (80)                    (279)
         Future Income Taxes                                                                      (44)                    (180)

         Change in Fair Value of Crude Oil Put Options                                             20                      201

         Canadian Heavy Oil Disposition Gain                                                      781                      781

         Natural Gas Energy Marketing Disposition Loss                                           (259)                    (259)

         Other                                                                                   (105)                     (26)
                                                                              -------------------------------------------------

NET INCOME AT SEPTEMBER 30, 2010 (1)                                                              537                      977
                                                                              =================================================
</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              Nine Months
                                                                               Ended September 30        Ended September 30
                                                                               2010         2009         2010          2009
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                           <C>           <C>          <C>           <C>
Crude Oil and Liquids (mbbls/d)
   United Kingdom                                                             106.3         73.7         103.4         91.6
   Yemen                                                                       41.6         48.7          41.8         51.5
   Syncrude                                                                    19.1         22.5          20.7         19.1
   Long Lake Bitumen                                                           16.7          5.5          15.0          7.6
   United States                                                                9.9          9.5           9.9         10.6
   Canada (2)                                                                   2.9         14.2          10.0         14.9
   Other Countries                                                              2.0          2.6           2.1          3.9
                                                                         ---------------------------------------------------
                                                                              198.5        176.7         202.9        199.2
                                                                         ---------------------------------------------------
Natural Gas (mmcf/d)
   United Kingdom                                                                27           17           36            18
   United States                                                                102           63          100            58
   Canada (2)                                                                   113          143          124           139
                                                                         ---------------------------------------------------
                                                                                242          223          260           215
                                                                         ---------------------------------------------------

Total Production (mboe/d)                                                       239          214          246           235
                                                                         ===================================================
</TABLE>

PRODUCTION (AFTER ROYALTIES)

<TABLE>
<CAPTION>
                                                                                   Three Months              Nine Months
                                                                                Ended September 30       Ended September 30
                                                                                2010        2009         2010          2009
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                           <C>           <C>          <C>           <C>
Crude Oil and Liquids (mbbls/d)
   United Kingdom                                                             106.3         73.7         103.4         91.6
   Yemen                                                                       23.5         28.3          22.9         31.0
   Syncrude                                                                    17.9         20.0          19.1         17.6
   Long Lake Bitumen                                                           16.0          5.5          14.3          7.6
   United States                                                                8.9          8.5           8.9          9.6
   Canada (2)                                                                   2.3         10.9           7.7         11.6
   Other Countries                                                              1.9          2.4           2.0          3.6
                                                                         ---------------------------------------------------
                                                                              176.8        149.3         178.3        172.6
                                                                         ---------------------------------------------------
Natural Gas (mmcf/d)
   United Kingdom                                                                27           17            36           17
   United States                                                                 89           56            86           52
   Canada (2)                                                                   104          137           114          130
                                                                         ---------------------------------------------------
                                                                                220          210           236          199
                                                                         ---------------------------------------------------

Total Production (mboe/d)                                                       213          184           218          206
                                                                         ===================================================
</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              Nine Months
                                                                               Ended September 30       Ended September 30
                                                                                2010         2009         2010         2009
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                           <C>         <C>          <C>          <C>
   Before Royalties
       Crude Oil and NGLs (mbbls/d)                                              2.9         14.2         10.0         14.9
       Natural Gas (mmcf/d)                                                      2.2         13.2          8.3         13.7
   After Royalties
       Crude Oil and NGLs (mbbls/d)                                              2.3         10.9          7.7         11.6
       Natural Gas (mmcf/d)                                                      2.1         11.2          7.2         11.6
                                                                         ---------------------------------------------------
</TABLE>



                                       38
<PAGE>



HIGHER VOLUMES INCREASED NET INCOME FOR THE QUARTER BY $253 MILLION
Production  before  royalties  increased  12%  and  production  after  royalties
increased 16%, compared to the third quarter last year. Higher production in the
North Sea, Long Lake and the Gulf of Mexico was partially  offset by the sale of
our Canadian  heavy oil  properties in July and natural field declines in Yemen.
Compared to the second quarter,  production before royalties  increased 1% after
taking  into  account  the  sale of our  heavy  oil  assets.  Temporarily  lower
production at Syncrude was offset by stronger production rates in the North Sea.

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

<TABLE>
<CAPTION>
                                                                                               Before                After
(mboe/d)                                                                                    Royalties            Royalties
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                                             <C>                  <C>
Production, second quarter 2010                                                                   248                  218
   Production related to disposed properties (1)                                                  (12)                  (9)
                                                                                  ------------------------------------------
                                                                                                  236                  209
   Production changes from continuing operations:
       United Kingdom                                                                               6                    6
       Yemen                                                                                        1                    1
       United States                                                                                1                    1
       Canada                                                                                      (1)                  (1)
       Syncrude                                                                                    (4)                  (3)
                                                                                  ------------------------------------------
Production, third quarter 2010                                                                    239                  213
                                                                                  ==========================================
</TABLE>

(1) Heavy oil properties were sold in late July 2010.

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

UNITED KINGDOM
Production  volumes in the UK North Sea increased 45% from last year and 6% from
the previous  quarter as higher  volumes at Buzzard and Ettrick  were  partially
offset by downtime at Scott/Telford.

Buzzard  production  averaged 84,200 boe/d for the quarter.  This was 18% higher
than  the  second  quarter  when  production  from  Buzzard  was  impacted  by a
three-week shutdown to install the fourth platform topsides and complete repairs
to the main separator unit.  Production was 42% higher than the third quarter of
2009 when  Buzzard was shut-in for four weeks of downtime to install the jackets
for the fourth platform and prepare the tie-ins.  We are progressing towards the
start up of the new platform and fourth quarter  Buzzard volumes are expected to
be approximately  70 to 90% of normal.  Production is expected to return to full
rates around year end.

Production  from our Ettrick field increased 33% during the quarter and produced
18,900 boe/d net to us, compared to 14,200 boe/d in the second quarter.

Production at  Scott/Telford  averaged  5,700 boe/d compared to 17,800 boe/d the
previous  quarter.  A valve failure on the  third-party  owned Forties  pipeline
system shut in  production  on the Scott  platform  for eight  weeks  during the
quarter.  We  used  some  of  this  time to  complete  our  planned  maintenance
activities  while the  operator  repaired  the valve.  Production  restarted  in
September and has since returned at rates of about 20,000 boe/d, net to us.

CANADA
During the quarter,  we sold our heavy oil  properties  in Canada that  produced
approximately  15,000 boe/d in the second  quarter.  Production on our remaining
natural gas properties in Canada was 5% and 10% lower than the previous  quarter
and last year, respectively, as a result of natural declines and reduced capital
investment.

At our shale gas  project in the Dilly  Creek  area of the Horn  River  basin in
north-east British Columbia, we successfully completed a 144 frac program on our
eight-well pad. We recently  started  production  testing these wells and expect
to reach peak production rates of 50 mmcf/d this winter.

LONG LAKE
At Long Lake,  quarterly  bitumen  production  volumes  were 26,000  boe/d gross
(17,000  boe/d net to us),  compared to 25,000 boe/d gross (16,000 boe/d net) in
the  previous  quarter.  Production  ramp up over the  summer  was  impacted  by
downtime related to SAGD well  optimization  activities (such as ESP upsizes and
acid stimulations) and temporary steam  interruptions.  These interruptions were
caused by unplanned  upgrader  downtime  related to the air separation  unit and
power  outages  caused by a  lightning  strike.  We are back  on-stream  and are
producing over 31,500 bbls/d (gross) of bitumen.


                                       39
<PAGE>


SYNCRUDE
Our share of Syncrude  production  fell 18% from the prior  quarter and 15% from
last year,  averaging 19,100 boe/d for the quarter. The decrease was a result of
maintenance work on the sour water treatment unit and vacuum  distillation unit,
and the scheduled  turnaround of Coker 8-1 late in the quarter.  This turnaround
is now complete and no further downtime is scheduled at Syncrude this year.

UNITED STATES
Production  in the Gulf of Mexico  averaged  26,900  boe/d,  4% higher  than the
previous quarter. The increased volumes were primarily due to strong performance
at Longhorn  and  Wrigley.  Compared  to the same  period last year,  production
increased  35%  primarily  as a result of the  Longhorn  development  which came
on-stream  in late 2009.  Production  at  Longhorn  averaged  8,600 boe/d in the
quarter.

The drilling  moratorium in the Gulf of Mexico had no significant  impact on our
shelf and deep-water production during the quarter 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  41,600 boe/d for the period,  up slightly  from the
previous  quarter,  but down 15% from  last  year.  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.  During the
quarter,  we drilled two  development  wells with a further three expected to be
drilled by the end of the year.  Production  declines  in Yemen are  expected to
continue as we focus on maximizing recovery of the remaining reserves.

We are continuing  discussions  with the Yemen  government and our partners on a
contract  extension  for the Masila  block  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 2,000 boe/d
for the quarter.  This was 5% lower than the previous quarter and 23% lower than
the same period last year due to natural field declines.



                                       40
<PAGE>

<TABLE>
<CAPTION>

COMMODITY PRICES
                                                                                   Three Months                Nine Months
                                                                                Ended September 30          Ended September 30
                                                                                2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                           <C>           <C>           <C>             <C>
CRUDE OIL
   West Texas Intermediate (WTI) (US$/bbl)                                     76.20         68.30        77.65           57.00
   Dated Brent (Brent) (US$/bbl)                                               76.86         68.27        77.13           57.16
                                                                         -------------------------------------------------------

   Benchmark Differentials (1) (US$/bbl)
         Heavy Oil                                                             15.89         10.39        13.17            9.10
         Mars                                                                   1.53          1.90         1.70            1.17
         Masila                                                                (0.63)        (0.54)        0.11            0.15

   Realized Prices from Producing Assets (Cdn$/bbl)
         United Kingdom                                                        77.45         73.15        77.29           63.78
         Yemen                                                                 79.33         76.31        80.07           65.22
         Syncrude                                                              78.27         74.54        79.78           67.26
         Long Lake Synthetic                                                   70.64             -        74.44               -
         United States                                                         73.72         72.27        75.46           61.60
         Canada                                                                61.56         59.88        61.39           50.10
         Other Countries                                                       75.93         70.49        76.58           55.89

   Corporate Average (Cdn$/bbl)                                                77.03         72.95        77.09           63.15
                                                                         -------------------------------------------------------

NATURAL GAS
   New York Mercantile Exchange (US$/mmbtu)                                     4.24          3.44         4.54            3.91
   AECO (Cdn$/mcf)                                                              3.52          2.87         4.09            3.89
                                                                         -------------------------------------------------------

   Realized Prices from Producing Assets (Cdn$/mcf)
         United Kingdom                                                         5.11          2.64         4.89            4.04
         United States                                                          4.70          3.56         5.27            4.59
         Canada                                                                 3.43          2.85         4.08            3.67

   Corporate Average (Cdn$/mcf)                                                 4.18          3.04         4.67            3.96
                                                                         -------------------------------------------------------

NEXEN'S AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe)                          68.21         63.00        68.60           56.89
                                                                         -------------------------------------------------------

AVERAGE FOREIGN EXCHANGE RATE - Canadian to US Dollar                         0.9624        0.9108       0.9656          0.8546
                                                                         -------------------------------------------------------
</TABLE>

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

HIGHER COMMODITY PRICES INCREASED QUARTERLY NET INCOME BY $77 MILLION
WTI and Brent  prices were down 2% from the previous  quarter.  Compared to last
year,  benchmark  crude prices are 12% higher but the impact of the increase was
mitigated  by a  stronger  Canadian  dollar.  Our  realized  oil price  averaged
$77.03/bbl  for the  quarter,  6% higher  than last year and 1% higher  than the
second quarter.

Natural  gas  prices  fell  from  the  previous  quarter  with  NYMEX  averaging
US$4.24/mmbtu   and  AECO  averaging   $3.52/mcf,   a  decrease  of  2%  and  4%
respectively.  This reduced our  realized gas price by 5%.  Compared to the same
period  last  year,  our  realized  gas  price is 38%  higher  as NYMEX and AECO
increased 23%.

The Canadian  dollar  strengthened  against the US dollar since last year.  This
strengthening  reduced net sales by approximately  $74 million,  as our realized
crude  oil  and  natural  gas  prices  were   $4.36/bbl  and  $0.24/mcf   lower,
respectively.  However,  the weaker US dollar  lowers our US dollar  denominated
costs and debt when translated to Canadian dollars.



                                       41
<PAGE>


CRUDE OIL REFERENCE PRICES
WTI  traded  between  US$70/bbl  and  US$80/bbl  during  the  quarter  as prices
responded  to  shifting  oil  demand  expectations.  Robust  economic  growth in
developing countries accounts for almost 90% of 2010 global oil demand growth of
2 million bbls/day.  In contrast,  developed  countries  burdened with high debt
levels are  suffering  from tepid  economic  growth and  numerous  market  fears
including:  double-dip recession,  deflation,  sovereign debt default in Europe,
and fiscal policy shifts from stimulus to austerity. The forward crude oil price
curve remains in contango  which  indicates  that market  expectations  are that
higher prices will be required in the future to ration supply.

Globally there are two economies.  Developing  countries are experiencing strong
economic growth while developed  countries are recovering slowly and tentatively
from a deep financially-led  recession. The US Federal Reserve flagged deflation
as a significant  concern and signaled  that it will,  if  necessary,  engage in
quantitative  easing to stem this risk. Because oil is a US-dollar priced global
commodity,  quantitative easing would apply upward pressure to crude oil prices,
as well as encourage financial  investments in oil as investors use oil to hedge
their exposure to a declining US dollar.

Global onshore crude oil and refined product  inventory  levels are at five year
highs which is an impediment to higher crude oil prices and a contributor to the
contango  structure in the forward price curve.  However,  oil inventories  have
been drawn down as the  developing  economies  continue  to  increase  their oil
demand.

In October,  crude prices remained above US$80/bbl as the US dollar continued to
weaken.  OPEC  recently  reiterated  that they  believe  no  change  to  current
production levels is required.

CRUDE OIL DIFFERENTIALS
In Canada,  heavy oil differentials  were volatile.  Enbridge pipeline shutdowns
widened heavy oil differentials as heavy crude takeaway capacity was restricted.
With the  resumption  of the  Enbridge  pipelines in late  September,  the heavy
differential has narrowed to more normal levels.

Brent  traded at a premium to WTI for most of the quarter.  Historically,  Brent
has traded at a discount to WTI because surplus North Sea crude oil was exported
to the US market.  With declining North Sea crude  production and exports,  this
differential  can shift to positive or negative  depending  on short term supply
and demand factors. The differential favoured Brent in the third quarter because
high  inventory  levels  at  Cushing  depressed  the  price of WTI and North Sea
maintenance reduced supply available for export.

Mars  is a  medium  sour  crude  that  is  priced  to  compete  with  comparable
international  import alternatives.  The Mars differential  narrowed relative to
WTI mainly due to  downward  pressure  on WTI from  inventory  builds on land at
Cushing.

The Masila  price  strengthened  relative to WTI  following  the movement in the
WTI/Brent differential and the relative strength of Asian demand.

NATURAL GAS REFERENCE PRICES
NYMEX natural gas prices remained low due to warm weather  reducing demand while
supply  remained  strong.  Producers  continue to drill despite low prices.  Gas
prices are  expected to remain low until  inventory  levels are reduced by lower
supply or higher demand from economic growth or weather-related events.




                                       42
<PAGE>



OPERATING EXPENSES(1)

<TABLE>
<CAPTION>
                                                                                  Three Months               Nine Months
                                                                               Ended September 30         Ended September 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                                                     9.19        11.56          9.18        9.41
   Long Lake Synthetic (3)                                                     85.20            -        101.73           -
   Syncrude                                                                    41.49        29.50         37.46       39.26
   Average Oil and Gas                                                         15.72        13.60         15.44       11.97
                                                                         ---------------------------------------------------

Operating expenses based on our production after royalties
   Conventional Oil and Gas                                                    10.50        13.45         10.54       10.90
   Long Lake Synthetic (3)                                                     89.19            -        106.46           -
   Syncrude                                                                    44.20        33.19         40.53       42.67
   Average Oil and Gas                                                         17.78        15.76         17.56       13.79
                                                                         ---------------------------------------------------
</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 $88 MILLION
Operating  costs  increased  $88  million or 35% from the third  quarter of 2009
primarily due to costs  associated with our Long Lake project.  As of January 1,
2010,  we  ceased  capitalizing  our Long  Lake  start-up  costs.  As Long  Lake
operating  costs are mainly  fixed,  increasing  volumes  improved  our per unit
operating  cost about 10% from the  previous  quarter.  When fully ramped up, we
expect Long Lake operating costs to be about $25 to $30/bbl.

Our  production  mix has  changed  as a  result  of the  sale of our  heavy  oil
properties  in Canada,  higher  production  at Buzzard and Ettrick,  and natural
declines  in Yemen.  This  reduced our  average  oil and gas  operating  cost by
$0.93/boe.  The  stronger  Canadian  dollar  reduced  our  corporate  average by
$0.42/boe as operating costs of our  international and US assets are denominated
in US dollars.

In Canada,  the sale of our heavy oil properties  reduced operating costs by $19
million from the same period last year.

In the UK North Sea,  Buzzard  operating  costs were  slightly  higher  than the
previous year.  Elsewhere in the UK North Sea, higher production volumes reduced
the average unit cost at Ettrick, while at Scott, the per unit cost increased as
a result of downtime experienced in the quarter.  Combined,  these items reduced
our corporate average by $0.20/boe.

In Yemen,  operating costs were down 20% due to reduced  maintenance costs. This
decreased  our corporate  average cost by  $0.43/boe.  In the US Gulf of Mexico,
higher  production  was only  partially  offset by  increased  operating  costs,
reducing our corporate average by $0.02/boe.

At Syncrude,  maintenance  costs  associated  with the Coker 8-1  turnaround and
lower production volumes increased our corporate average by $0.98/boe.


                                       43
<PAGE>

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

<TABLE>
<CAPTION>
                                                                                Three Months               Nine Months
                                                                             Ended September 30         Ended September 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                                                    18.70        19.14         17.61       18.71
   Long Lake Synthetic                                                         23.90            -         22.48           -
   Syncrude                                                                     7.09         6.12          6.93        6.29
   Average Oil and Gas                                                         18.05        17.66         16.94       17.64
                                                                         ---------------------------------------------------

DD&A based on our production after royalties
   Conventional Oil and Gas                                                    21.38        22.26         20.21       21.67
   Long Lake Synthetic                                                         24.89            -         23.37           -
   Syncrude                                                                     7.56         6.88          7.49        6.83
   Average Oil and Gas                                                         20.39        20.46         19.24       20.32
                                                                         ---------------------------------------------------
</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 $129 MILLION
Our DD&A  expense in the third  quarter  of 2010  includes  non-cash  impairment
charges of $61 million at three small  natural gas  properties in the US Gulf of
Mexico. Low natural gas prices made these mature shelf properties uneconomic and
as a result,  the  properties  are being  shut down and the  carrying  value was
written down to their estimated fair value.

DD&A costs  increased  $68  million or  $0.39/boe,  excluding  the impact of the
impairment.  The change in our  production  mix increased our corporate  average
DD&A rate by $0.97/boe.  Depletion rates at Ettrick,  Longhorn and Long Lake are
higher  than  our  corporate  average.  Depletion  at Long  Lake  increased  our
consolidated  average cost by  $1.22/boe.  Additionally,  the stronger  Canadian
dollar  reduced  our  corporate   average  by  $0.75/boe  as  depletion  of  our
international and US assets is denominated in US dollars.

Canada  increased  our  corporate  average  DD&A  rate by  $0.29/boe,  despite a
decrease in our DD&A expense of $28 million due to the  disposition of the heavy
oil  properties.  This  increase  was driven by higher DD&A rates at our CBM and
natural gas properties,  where low natural gas prices at the end of 2009 reduced
reserves.

At Buzzard,  successful  drilling  last year enabled us to recognize  additional
proved  reserves at the end of 2009,  which lowered the field depletion rate and
reduced our  corporate  average by  $0.72/boe.  The  remainder  of our UK fields
decreased our  corporate  average by  $0.25/boe,  primarily  driven by increased
reserves at Telford and reduced capital costs at Ettrick.

Depletion  rates in Yemen  increased our  corporate  average  $0.53/boe.  As the
fields mature and production declines,  our capital is focused on recovering the
remaining  reserves,  thereby  increasing our depletion rates. In the US 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 by $0.95/boe.



                                       44
<PAGE>

<TABLE>
<CAPTION>

EXPLORATION EXPENSE(1)

                                                                                   Three Months                 Nine Months
                                                                                Ended September 30          Ended September 30
                                                                                2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>           <C>           <C>           <C>
Seismic                                                                           31            16            60            59
Unsuccessful Drilling                                                              -            51            42            78
Other                                                                             25            22            97            82
                                                                         -------------------------------------------------------
Total Exploration Expense                                                         56            89           199           219
                                                                         =======================================================
</TABLE>

(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 $33 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.  The drilling
moratorium in the Gulf of Mexico was lifted earlier in October. Once drilling in
the  Gulf of  Mexico  resumes,  we  plan to  conduct  further  appraisals  here.
Appomattox  is the third  discovery in the area  following  previous  successful
drilling  at Shiloh and  Vicksburg.  Our  drilling  plans also  include  further
appraisal at Vicksburg which is located six miles east of Appomattox and has the
potential to be  co-developed.  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 currently  engaged in an active  exploration  and  development
program. This includes:

o        advancing area development options for the Golden Eagle area, including
         doing initial  engineering  and preparing  cost estimates for potential
         sanctioning  in 2011.  The Golden Eagle area  includes our 34% operated
         interest  in Golden  Eagle and Hobby and our 46%  operated  interest in
         Pink;

o        completing a successful  appraisal  well at Blackbird,  six  kilometres
         south of our  Ettrick  field,  early  in the  quarter.  Blackbird  is a
         potential  tie-back  to the  Ettrick  FPSO.  We  have  an 80%  operated
         interest at Blackbird;

o        evaluating  drilling  results from our Polecat  prospect.  Polecat is a
         potential tie back to Buzzard; and

o        reviewing the results from our appraisal well at West  Rochelle,  where
         we have a 44% non-operated  interest, as we successfully  confirmed gas
         and oil pay there. We are  sidetracking  the well to further  delineate
         the discovery. This well is a potential tieback to Scott.

Exploration  expense  decreased  37% or $33  million,  as we did not  incur  any
unsuccessful drilling costs during the quarter. In the third quarter of 2009, we
expensed  drilling  costs related to our Antietam well in the Gulf of Mexico and
our CBM properties in Canada.  This decrease was partially offset as we incurred
higher  expenditures  in the UK  North  Sea  and US Gulf of  Mexico  to  acquire
additional seismic data for further exploration.


                                       45
<PAGE>

<TABLE>
<CAPTION>

ENERGY MARKETING
                                                                                   Three Months                Nine Months
                                                                                Ended September 30          Ended September 30
                                                                                2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                           <C>           <C>          <C>           <C>
   Physical Sales (1)                                                          7,213         9,711        25,517        29,719
   Physical Purchases (1)                                                     (7,112)       (9,605)      (25,099)      (29,011)
   Net Financial Transactions (2)                                                (20)          117           (48)         (111)
   Change in Fair Market Value of Inventory                                        1           (35)          (88)           79
                                                                         -------------------------------------------------------
Marketing Revenue                                                                 82           188           282           676
   Transportation Expense                                                        (64)         (145)         (275)         (473)
   Other                                                                           -             4             4             8
                                                                         -------------------------------------------------------
NET MARKETING REVENUE                                                             18            47            11           211
                                                                         =======================================================
CONTRIBUTION TO NET MARKETING REVENUE BY REGION
   North America                                                                  18            33             4           192
   International                                                                   -            14             7            19
                                                                         -------------------------------------------------------
NET MARKETING REVENUE                                                             18            47            11           211
   DD&A                                                                           (4)          (14)          (14)          (21)
   General and Administrative                                                    (19)          (19)          (51)          (68)
   Other                                                                          24             4             1             4
   Natural Gas Energy Marketing Disposition Loss                                (259)            -          (259)            -
                                                                         =======================================================
MARKETING CONTRIBUTION TO INCOME BEFORE INCOME TAXES                            (240)           18          (312)          126
                                                                         =======================================================
NORTH AMERICA
   NATURAL GAS
   Physical Sales Volumes (3) (bcf/d)                                            1.8           4.9           3.3           4.9
   Transportation Capacity (bcf/d)                                               0.1           1.5           0.1           1.5
   Storage Capacity (bcf)                                                        0.9          32.5           0.9          32.5
   Financial Volumes (4) (bcf/d)                                                 0.2           8.7           3.0          11.4
   CRUDE OIL
   Physical Sales Volumes (3) (mbbls/d)                                          797           802           795           837
   Storage Capacity (mmbbls)                                                     2.7           3.1           2.7           3.1
   Financial Volumes (4) (mbbls/d)                                               830           699           793           796
   POWER
   Physical Sales Volumes (3) (GWh/d)                                              9            14             9             9
   Generation Capacity (MW)                                                       95            95            95            95
INTERNATIONAL CRUDE OIL
   Physical Sales Volumes (3) (mbbls/d)                                           59            93            81            97
   Financial Volumes (4) (mbbls/d)                                               736           681           921           765
VALUE-AT-RISK (5)
   Quarter-end                                                                     8            13             8            13
   High                                                                            9            15            15            24
   Low                                                                             4            11             4            11
   Average                                                                         7            12            10            16
                                                                         -------------------------------------------------------
</TABLE>

(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)  Refer to our Consolidated  Audited Financial  Statements for the year ended
     December 31, 2009 for a description of Value-at-Risk.


                                       46
<PAGE>

LOWER CONTRIBUTION FROM ENERGY MARKETING DECREASED NET INCOME BY $9 MILLION
During the  quarter,  we  completed  the sale of our North  America  natural gas
marketing  operations.  Net proceeds of $11 million were received and a non-cash
loss of $259  million  was  recognized,  primarily  related to the  transfer  of
long-term physical transportation commitments. The value of these transportation
commitments  decreased  substantially  largely  because of the  increase  in gas
supply in North America reducing the need for transport services.  Subsequent to
the sale,  we retained a small  natural gas  operation  to support our  upstream
production and other third party producers in western Canada.

Overall, third quarter revenue was lower than last year due to lower income from
our North American gas and UK gas and power  operations,  which were sold during
the year.  Revenue from our global crude oil marketing  business was  relatively
consistent compared to last year.

In the third  quarter,  our  crude  oil  marketing  business  captured  gains on
shifting  differentials,  blending  opportunities  and  physical  and  inventory
management. These same strategies generated gains in the third quarter of 2009.

Compared to the second quarter of 2010, third quarter results were improved from
reduced losses from North  American  natural gas. This was offset by losses on a
strengthening  Canadian  dollar  compared to gains on a weakening  dollar in the
second quarter.

COMPOSITION OF NET MARKETING REVENUE

<TABLE>
<CAPTION>
                                                                                   Three Months                Nine Months
                                                                                Ended September 30          Ended September 30
                                                                                2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>           <C>            <C>         <C>
Trading Activities (Physical and Related Financial)                               16            43             3           201
Other Activities                                                                   2             4             8            10
                                                                         -------------------------------------------------------
Total Net Marketing Revenue                                                       18            47            11           211
                                                                         =======================================================
</TABLE>

TRADING ACTIVITIES
In our energy  marketing  group,  we enter into  contracts  to purchase and sell
crude oil, as well as 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 fair values are  included
with  accounts  receivable  or  payable  and  are  classified  as  long-term  or
short-term based on anticipated settlement date.

OTHER ACTIVITIES
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 September 30, 2010, the fair value of our derivative  contracts in our energy
marketing  trading  activities  was $17  million.  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>
  Level 1 - Actively Quoted Markets                                   (13)           (14)           -              -        (27)
  Level 2 - Based on Other Observable Pricing Inputs (1)                -              -            -              -          -
  Level 3 - Based on Unobservable Pricing Inputs                       33             11            -              -         44
                                                                ------------------------------------------------------------------
Total                                                                  20             (3)           -              -         17
                                                                ==================================================================
</TABLE>

(1) As at September 30, 2010, Level 2 unrealized gains and losses net to nil.


                                       47
<PAGE>


CHANGES IN FAIR VALUE OF DERIVATIVE CONTRACTS

                                                                         Total
------------------------------------------------------------------------------
Fair Value at December 31, 2009                                             23
   Change in Fair Value of Contracts                                        61
   Net Losses (Gains) on Contracts Sold                                    (39)
   Net Losses (Gains) on Contracts Closed                                  (28)
   Changes in Valuation Techniques and Assumptions (1)                       -
                                                                   -----------
Fair Value at September 30, 2010                                            17
                                                                   ===========

(1) Our valuation methodology has been applied consistently in each period.

The fair values of our  derivative  contracts  will be realized over time as the
related contracts  settle.  Until then, the value of certain contracts will vary
with forward commodity prices and price  differentials.  The average term of our
derivative contracts is approximately 1.3 years.

CHEMICALS

LOWER CHEMICALS CONTRIBUTION DECREASED NET INCOME BY $18 MILLION
Chlorate revenues in North America  increased  slightly over last year as higher
volumes were offset by a decline in prices due to a stronger Canadian dollar. In
Brazil, higher volumes and prices combined to increase revenues by 17%.

Chlor-alkali  revenue in North America was consistent  with the same period last
year.  In late  June,  the  technology  conversion  project  (TCP) at the  North
Vancouver  chlor-alkali  facility  successfully  started  up and the  facilities
continued  to ramp up  during  the  third  quarter.  We  expect  that  TCP  will
contribute  $35 to $40  million in  incremental  operating  cash flow  annually,
through lower  operating  costs and volume  expansion.  In Brazil,  chlor-alkali
revenues were comparable to the prior year.

Operating  costs  were  higher  during  the  quarter  primarily  as a result  of
expenditures  incurred to source product for  chlor-alkali  customers during the
start up and ramp up of the TCP.

Chemicals net income was lower by $14 million  during the quarter as a result of
reduced foreign exchange gains.

CORPORATE EXPENSES

GENERAL AND ADMINISTRATIVE (G&A)(1)

<TABLE>
<CAPTION>
                                                                                  Three Months                 Nine Months
                                                                               Ended September 30           Ended September 30
                                                                                2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>           <C>           <C>           <C>
General and Administrative Expense before Stock-Based
Compensation                                                                     134           118           360           329
Stock-Based Compensation (2)                                                      (1)           (5)          (34)           51
                                                                         -------------------------------------------------------
Total General and Administrative Expense                                         133           113           326           380
                                                                         =======================================================
</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.

HIGHER G&A COSTS DECREASED NET INCOME BY $20 MILLION
During the quarter, G&A expenditures before stock-based  compensation  increased
14% from the same period last year.  The increase  was  primarily as a result of
costs related to our non-core asset disposition program.

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, our share price decreased marginally and we reversed  approximately
$3 million of non-cash  stock-based  compensation  that was  recognized in prior
periods.


                                       48
<PAGE>


INTEREST
<TABLE>
<CAPTION>

                                                                                   Three Months                Nine Months
                                                                                Ended September 30          Ended September 30
                                                                                2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                           <C>           <C>           <C>           <C>
Interest                                                                         105           100           302           286
   Less: Capitalized                                                             (24)          (16)          (64)          (60)
                                                                         -------------------------------------------------------
Net Interest Expense                                                              81            84           238           226
                                                                         =======================================================

Effective Interest Rate                                                          6.3%          5.2%          5.7%          4.9%
                                                                         -------------------------------------------------------
</TABLE>

LOWER NET INTEREST EXPENSE INCREASED NET INCOME BY $3 MILLION
Interest costs before capitalized  interest increased $12 million as a result of
higher  interest on  fixed-term  debt issued in July 2009 and  additional  costs
related  to the  Canexus  facilities.  This was  partially  offset by a stronger
Canadian  dollar  which  decreased  our  US-denominated  interest  expense by $7
million.

Capitalized  interest was $8 million higher than 2009. We continue to capitalize
interest on the Usan  project,  offshore  West  Africa,  the fourth  platform at
Buzzard and future phases of Long Lake.


INCOME TAXES(1)
<TABLE>
<CAPTION>
                                                                                   Three Months                Nine Months
                                                                                Ended September 30          Ended September 30
                                                                                2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>           <C>           <C>           <C>
Current                                                                          270           190           793           514
Future                                                                           (37)          (81)         (217)         (397)
                                                                         -------------------------------------------------------
Total Provision for Income Taxes                                                 233           109           576           117
                                                                         =======================================================
</TABLE>

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

HIGHER TAXES REDUCED NET INCOME BY $124 MILLION
Our total provision for income taxes increased during the quarter primarily as a
result of the net gains on our non-core asset disposition program. Additionally,
our operating  results improved  relative to last year,  resulting in higher tax
expense.  Our future tax expense in 2009  includes the impact of the decrease in
the value of our crude oil put  options and the effect of reduced  Canadian  tax
rates.  Our income tax provision  includes  current taxes in the United Kingdom,
Yemen, Norway, Colombia and the United States.


OTHER
<TABLE>
<CAPTION>
                                                                                   Three Months                Nine Months
                                                                                Ended September 30          Ended September 30
                                                                                2010          2009          2010          2009
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                               <C>          <C>           <C>          <C>
Decrease in Fair Value of Crude Oil Put Options                                   (3)          (23)          (18)         (218)
                                                                         -------------------------------------------------------
</TABLE>

During the quarter,  we purchased put options on 20,000 bbls/d of our 2011 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.  The options  settle  monthly and 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
$6 million  and are  carried at fair value.  As at  September  30, 2010 the fair
value of the options was  approximately  $5 million and we recorded a fair value
loss of $1 million for the quarter.

Subsequent to September 30, 2010, we purchased  additional crude oil put options
on 50,000 bbls/d of our 2011 crude oil production for $17 million. These options
establish a WTI floor price of approximately US$56/bbl.

In the fourth  quarter of 2009, we purchased put options on 90,000 bbls/d of our
2010 crude oil production,  establishing a WTI floor price of US$50/bbl. Options
on 60,000 bbls/d settle monthly,  while the remaining  options settle  annually.
These options are recorded at fair value  throughout their term. The put options
were  purchased  for $39 million and are carried at fair value.  As at September
30, 2010,  higher forward crude oil prices reduced the fair value of the options
to nil.


                                       49
<PAGE>


LIQUIDITY AND CAPITAL RESOURCES

CAPITAL STRUCTURE
                                                  September 30     December 31
                                                          2010            2009
-------------------------------------------------------------------------------
NET DEBT (1)
       Bank Debt                                           282           1,803
       Public Senior Notes                               4,936           4,982
                                              ---------------------------------
      Total Senior Debt                                  5,218           6,785
       Subordinated Debt                                   460             466
                                              ---------------------------------
      Total Debt                                         5,678           7,251
       Less: Cash and Cash Equivalents                  (1,210)         (1,700)
                                              ---------------------------------
TOTAL NET DEBT                                           4,468           5,551
                                              =================================

EQUITY AT HISTORIC ISSUE COST                            8,606           7,646
                                              =================================

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

NET DEBT

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

<TABLE>
<CAPTION>
                                                                                    Three Months Ended       Nine Months Ended
                                                                                          September 30            September 30
                                                                                                  2010                    2010
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                             <C>                   <C>
Capital Investment                                                                                (592)                 (1,965)
Cash Flow from Operating Activities (1)                                                            668                   1,976
                                                                                ------------------------------------------------
                                                                                                    76                      11

Proceeds on Disposition of Assets                                                                  950                   1,046
Dividends on Common Shares                                                                         (26)                    (78)
Issue of Common Shares                                                                               9                      44
Changes in Restricted Cash Requirements                                                            (43)                     40
Foreign Exchange Translation of US-dollar Debt and Cash                                            136                      50
Other                                                                                              (99)                    (30)
                                                                                ------------------------------------------------
Decrease in Net Debt                                                                             1,003                   1,083
                                                                                ================================================
</TABLE>

(1)  Includes changes in non-cash working capital. For the three and nine months
     ended  September  30,  2010,  inflows  of $212  million  and $410  million,
     respectively, was included.

Net debt was reduced by over $1 billion since the end of last year, primarily as
a result of proceeds received from our non-core asset dispositions. The proceeds
were used to repay our short-term  borrowings and drawn term credit  facilities.
The stronger  Canadian dollar also reduced our US-dollar  denominated  debt when
translated into Canadian dollars.

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>


CHANGE IN WORKING CAPITAL
<TABLE>
<CAPTION>
                                                                         September 30       December 31           Increase/
                                                                                 2010              2009          (Decrease)
----------------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>               <C>                     <C>
Cash and Cash Equivalents                                                       1,210             1,700                (490)
Restricted Cash                                                                    35               198                (163)
Accounts Receivable                                                             2,305             2,788                (483)
Inventories and Supplies                                                          544               680                (136)
Accounts Payable and Accrued Liabilities                                       (2,943)           (3,038)                 95
Other                                                                              38                70                 (32)
                                                                      ------------------------------------------------------
Net Working Capital                                                             1,189             2,398
                                                                      ==================================
</TABLE>

Our working  capital has been reduced since year end as we used cash to fund our
2010 capital program and repay  outstanding  term credit  facilities.  Timing of
cash tax remittances to governments during the year create  fluctuations in cash
taxes payable between quarters. In addition, our working capital decreased since
year end from the sale of our  North  American  natural  gas  operations,  which
included   transferring    derivative   contracts,    natural   gas   inventory,
transportation and storage commitments and cash margins (restricted cash) to the
purchaser.


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  $9 million for the
remainder  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  $7 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.

We have  incurred  approximately  80% of our  2010  planned  capital  investment
program to date. During the quarter,  our capital investment was concentrated on
i) exploration  and appraisal  drilling in the UK North Sea; ii) progressing our
northeast  British Columbia shale gas play; and iii) developing our Usan project
offshore  Nigeria.  We expect our capital  investment  in the fourth  quarter to
continue to focus on these projects.

At September 30, 2010, our available liquidity is $4.4 billion. This consists of
approximately  $1.2 billion cash on hand and unsecured term credit facilities of
$3.2  billion,  which are  available  until  2014.  Our term  credit  facilities
supported  $289  million  of  outstanding  letters  of  credit at the end of the
quarter. We also have $466 million of uncommitted,  unsecured credit facilities,
none of which was drawn and $82  million is being  used to  support  outstanding
letters  of  credit.  The  average  length-to-maturity  of our  public  debt  is
approximately 21 years.

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.

In connection  with our natural gas energy  marketing  disposition,  we assigned
substantially all of our natural gas transportation and storage contracts to the
purchaser,  reducing  our  future  commitments  by $342  million.  We  agreed to
maintain  our  parental  guarantee  to  the  pipeline  provider  related  to one
transportation  commitment. We are obligated to perform under the guarantee only
if the  purchaser  does not meet its  obligation  to the pipeline  provider.  To
guarantee its  performance,  the purchaser  provided us with collateral of US$43
million  which is  included  in  accounts  payable.  We expect  to  cancel  this
guarantee in the fourth quarter.


                                       51
<PAGE>


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.

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.  During  the  quarter,   work  continued  on  reviewing  our  opening
transitional IFRS differences at January 1, 2010 and reviewing the impact on our
2010 results of operations and financial position.

SUMMARY OF ACCOUNTING DIFFERENCES BETWEEN CANADIAN GAAP AND IFRS

We  determined  that the  majority  of our  existing  Canadian  GAAP oil and gas
accounting  policies  are  acceptable  under IFRS as we use  successful  efforts
accounting  for our  oil and gas  activities.  However,  detailed  analysis  has
identified  differences,  the most  significant  of which  will  impact  certain
aspects of our accounting for property,  plant and equipment,  asset  retirement
obligations,  accounting  for income  taxes,  and  share-based  payments on IFRS
adoption on January 1, 2010.  In addition,  IFRS  provides for certain  one-time
mandatory  and optional  adjustments  to our opening IFRS balance  sheet.  These
impacts on our opening IFRS balance sheet are described below.  Generally,  most
of these  transitional  adjustments  will be  offset  through  opening  retained
earnings on January 1, 2010.

PROPERTY, PLANT AND EQUIPMENT
Significant  components of property,  plant and equipment  (PP&E) with different
useful  lives must be accounted  for and  depreciated  separately.  Instances of
major  maintenance,  turnarounds  or inspections  must also be  capitalized  and
depreciated  until the next scheduled major  maintenance  activity.  Our current
policy is to  expense  these  items  unless  they  result in  improvements  that
increase  capacity  or extend  the useful  life.  We expect  that  retrospective
application will increase our net PP&E on January 1, 2010.

ASSET RETIREMENT OBLIGATIONS
There are  differences in the  calculation  methodology  for  determining  asset
retirement obligations,  the most significant of which is the use of a risk-free
rate  to  discount  our  obligations   under  IFRS.  Under  Canadian  GAAP,  our
obligations were discounted  using a  credit-adjusted  risk-free  discount rate.
Additionally,  liabilities  must be re-measured at each balance sheet date using
current discount rates under IFRS,  whereas under Canadian GAAP,  discount rates
do not change once the liability is recorded.  We expect the transitional impact
of these  adjustments will increase our accrued asset retirement  obligations on
January 1, 2010.

ACCOUNTING FOR INCOME TAXES
IFRS requires us to recognize tax credits related to a one-time tax deduction in
the UK in the period in which they  occur.  Canadian  GAAP  requires us to defer
recognition of the benefit until the assets are recognized in income by way of a
sale to a third party or depletion through use.  Additionally,  in transitioning
to  IFRS,  our  deferred  tax  liability  will be  impacted  by the tax  effects
resulting from the IFRS changes discussed in this section.

SHARE-BASED PAYMENTS
We use  the  intrinsic  method  to  account  for  our  cash-settled  stock-based
compensation  under  Canadian  GAAP.  We will  use a fair  value  model  such as
Black-Scholes to value our stock-based  compensation  under IFRS. We expect that
the IFRS  requirement  to value  stock-based  compensation  at fair  value  each
reporting  period may result in less  volatility  in our reported  earnings each
period.  We expect the transitional  impact of this adjustment will increase our
accrued liabilities on January 1, 2010.


                                       52
<PAGE>


ONE TIME ADJUSTMENTS ON TRANSITION TO IFRS
IFRS allows  certain  adjustments to financial  information on transition  where
retrospective  restatement  would  either be onerous or would not  provide  more
useful  information.  We expect to make  one-time  transitional  adjustments  on
January 1, 2010 as follows:
o  PP&E will be  decreased  to reflect  the use of fair value as deemed  cost on
   transition for certain of our assets where the carrying  values of the assets
   are in excess of their fair values.
o  Defined benefit pension  obligations will be increased to reflect  previously
   unrecognized actuarial losses.
o  Accumulated  foreign  exchange  gains and  losses  within  accumulated  other
   comprehensive  income  will be  reclassed  to retained  earnings  rather than
   retrospectively restating the balance.

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.  We
expect that the net impact of adopting IFRS will reduce our shareholders' equity
by less than 5% and the impact on our cash flows from operating  activities will
be immaterial.

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.

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.



                                       53
<PAGE>

SUMMARY OF QUARTERLY RESULTS

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

<S>                                                <C>      <C>       <C>       <C>       <C>       <C>      <C>       <C>
Net Sales from Continuing Operations                 1,214    1,004     1,138     1,034     1,486     1,432    1,399    1,416

Net Income (Loss) from Continuing Operations         (185)      152        23       122       256       172      242      (53)
Net Income (Loss) from Discontinued Operations          4       (17)       (3)        -         3        13       13      590
                                                  -----------------------------------------------------------------------------
Net Income (Loss)                                    (181)      135        20       122       259       185      255      537
                                                  =============================================================================

Earnings (Loss) Per Common Share from
  Continuing Operations ($/share)
     Basic                                          (0.36)     0.28      0.05      0.23      0.49      0.33     0.46    (0.10)
     Diluted                                        (0.36)     0.28      0.05      0.23      0.48      0.33     0.46    (0.10)

Earnings (Loss) Per Common Share ($/share)
     Basic                                          (0.35)     0.26      0.04      0.23      0.50      0.35     0.49     1.02
     Diluted                                        (0.35)     0.26      0.04      0.23      0.49      0.35     0.49     1.02
                                                  -----------------------------------------------------------------------------
</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, their timing 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;
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;



                                       54
<PAGE>


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.

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 and in Part II, Item 1A of our 2010 second quarter Form 10-Q. 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 our
assessment of all information at that time.


                                       55
<PAGE>


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 September 30, 2010:
o  approximately 88% of our credit exposures were investment grade;
o  approximately  76% of our  credit  exposures  were  with a  diverse  group of
   integrated  oil  companies,  crude  oil  refiners  and  marketers,  and large
   utilities; and
o  only two  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 nine 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.

On October 22, 2010,  Syncrude  Canada Ltd., in which Nexen owns a non-operating
7.23%  interest,  was  sentenced  by the  Alberta  Provincial  Court  under  the
provincial   Environmental  Protection  and  Enhancement  Act  and  the  federal
Migratory Birds  Convention Act for harming  wildlife.  The total sentence under
both acts was approximately $3 million ($216,900 net to Nexen).

ITEM 4.  (REMOVED AND RESERVED)

ITEM 6.  EXHIBITS

31.1 Certification  of Chief  Executive  Officer  pursuant to Section 302 of the
     Sarbanes-Oxley Act of 2002.
31.2 Certification  of Chief  Financial  Officer  pursuant to Section 302 of the
     Sarbanes-Oxley Act of 2002.
32.1 Certification of periodic report by Chief Executive  Officer pursuant to 18
     U.S.C.   Section  1350,   as  adopted   pursuant  to  Section  906  of  the
     Sarbanes-Oxley Act of 2002.
32.2 Certification of periodic report by Chief Financial  Officer pursuant to 18
     U.S.C.   Section  1350,   as  adopted   pursuant  to  Section  906  of  the
     Sarbanes-Oxley Act of 2002.

SIGNATURES

Pursuant to the  requirements of Section 13 or 15(d) of the Securities  Exchange
Act of 1934,  the Company has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized, on November 3, 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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