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

                                  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, 2007

|_|    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 LOGO 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, and (2) has been subject to such filing requirements
for the past 90 days.

                     Yes   [X]                  No  [_]

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

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

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

                     Yes  [_]                   No   [X]

On September 30, 2007, there were 527,429,968 common shares issued and
outstanding.

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

                                   NEXEN INC.
                                      INDEX

PART I         FINANCIAL INFORMATION                                       PAGE

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

   Item 2.     Management's Discussion and Analysis of Financial
               Condition and Results of Operations...........................26

   Item 3.     Quantitative and Qualitative Disclosures about Market Risk....46

   Item 4.     Controls and Procedures.......................................46

PART II        OTHER INFORMATION

   Item 4.     Submission of Matters to a Vote of Security Holders...........47

   Item 6.     Exhibits......................................................47

This report should be read in  conjunction  with our 2006 Annual Report on Form
10-K,  our amended  2006 Form  10-K/A and with our current  reports on Form 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
81 of our 2006 Annual Report on Form 10-K.

UNLESS WE INDICATE  OTHERWISE,  ALL DOLLAR AMOUNTS ($) ARE IN CANADIAN DOLLARS,
AND OIL  AND  GAS  VOLUMES,  RESERVES  AND  RELATED  PERFORMANCE  MEASURES  ARE
PRESENTED ON A  WORKING-INTEREST,  BEFORE-ROYALTIES  BASIS.  WHERE APPROPRIATE,
INFORMATION ON AN AFTER-ROYALTIES BASIS IS PRESENTED IN TABULAR FORMAT. VOLUMES
AND RESERVES INCLUDE SYNCRUDE OPERATIONS UNLESS OTHERWISE STATED.

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

<TABLE>
<S>                                                  <C>
/d       =   per day                                 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      =   barrels of oil equivalent               MW     =   Megawatt
mboe     =   thousand barrels of oil equivalent      CBM    =   Coalbed Methane
mmboe    =   million barrels of oil equivalent
</TABLE>

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

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

On September 28, 2007,  the noon-day  exchange rate was US$1.0037 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, 2007 and 2006...............4

Unaudited Consolidated Balance Sheet
as at September 30, 2007 and December 31, 2006................................5

Unaudited Consolidated Statement of Cash Flows
for the Three and Nine Months Ended September 30, 2007 and 2006...............6

Unaudited Consolidated Statement of Shareholders' Equity
for the Three and Nine Months Ended September 30, 2007 and 2006...............7

Unaudited Consolidated Statement of Comprehensive Income
for the Three and Nine Months Ended September 30, 2007 and 2006...............7

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


                                       3
<PAGE>

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

                                                                      Three Months              Nine Months
                                                                   Ended September 30       Ended September 30
                                                                     2007        2006         2007        2006
---------------------------------------------------------------------------------------------------------------
<S>                                                                 <C>         <C>          <C>         <C>
REVENUES AND OTHER INCOME
    Net Sales                                                       1,446         997        3,985       3,016
    Marketing and Other (Note 13)                                     226         287          773       1,089
                                                                  ---------------------------------------------
                                                                    1,672       1,284        4,758       4,105
                                                                  ---------------------------------------------
EXPENSES
    Operating                                                         283         229          862         702
    Depreciation, Depletion, Amortization and Impairment              349         244        1,043         770
    Transportation and Other                                          238         333          694         796
    General and Administrative                                          7          51          247         379
    Exploration                                                        67          82          221         231
    Interest (Note 6)                                                  40          15          134          35
                                                                  ---------------------------------------------
                                                                      984         954        3,201       2,913
                                                                  ---------------------------------------------

INCOME BEFORE INCOME TAXES                                            688         330        1,557       1,192
                                                                  ---------------------------------------------

PROVISION FOR INCOME TAXES
    Current                                                           136         112          347         357
    Future                                                            142          16          303         299
                                                                  ---------------------------------------------
                                                                      278         128          650         656
                                                                  ---------------------------------------------

NET INCOME BEFORE NON-CONTROLLING INTERESTS                           410         202          907         536
    Less: Net Income Attributable to Non-Controlling Interests         (7)         (3)         (15)        (12)
                                                                  ---------------------------------------------

NET INCOME                                                            403         199          892         524
                                                                  =============================================

EARNINGS PER COMMON SHARE ($/share)
    Basic (Note 11)                                                  0.77        0.38         1.69        1.00
                                                                  =============================================

    Diluted (Note 11)                                                0.75        0.37         1.66        0.97
                                                                  =============================================
</TABLE>

SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.

                                       4
<PAGE>

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

                                                                           September 30    December 31
                                                                                   2007           2006
-------------------------------------------------------------------------------------------------------
<S>                                                                        <C>             <C>
ASSETS
    CURRENT ASSETS
      Cash and Cash Equivalents                                                     172            101
      Restricted Cash and Margin Deposits                                           176            197
      Accounts Receivable (Note 2)                                                2,683          2,951
      Inventories and Supplies (Note 3)                                             628            786
      Future Income Tax Assets                                                       73            479
      Other                                                                          77             67
                                                                         ------------------------------
         Total Current Assets                                                     3,809          4,581
                                                                         ------------------------------

    PROPERTY, PLANT AND EQUIPMENT
      Net of Accumulated Depreciation, Depletion, Amortization and
         Impairment of $6,539 (December 31, 2006 - $6,399)                       12,291         11,739
    FUTURE INCOME TAX ASSETS                                                        167            141
    DEFERRED CHARGES AND OTHER ASSETS (Note 4)                                      276            318
    GOODWILL                                                                        328            377
                                                                         ------------------------------
TOTAL ASSETS                                                                     16,871         17,156
                                                                         ==============================

LIABILITIES AND SHAREHOLDERS' EQUITY
    CURRENT LIABILITIES
      Short-Term Borrowings (Note 6)                                                 -             158
      Accounts Payable and Accrued Liabilities                                    3,408          3,879
      Accrued Interest Payable                                                       67             55
      Dividends Payable                                                              13             13
                                                                         ------------------------------
         Total Current Liabilities                                                3,488          4,105
                                                                         ------------------------------

    LONG-TERM DEBT (Note 6)                                                       4,565          4,673
    FUTURE INCOME TAX LIABILITIES                                                 2,231          2,468
    ASSET RETIREMENT OBLIGATIONS (Note 7)                                           701            683
    DEFERRED CREDITS AND OTHER LIABILITIES (Note 8)                                 396            516
    NON-CONTROLLING INTERESTS                                                        75             75

    SHAREHOLDERS' EQUITY (Note 10)
      Common Shares, no par value
        Authorized:        Unlimited
        Outstanding:       2007 - 527,429,968 shares
                           2006 - 525,026,412 shares                                891            821
      Contributed Surplus                                                             3              4
      Retained Earnings                                                           4,825          3,972
      Accumulated Other Comprehensive Income (Note 1)                              (304)          (161)
                                                                         ------------------------------
         Total Shareholders' Equity                                               5,415          4,636
                                                                         ------------------------------
    COMMITMENTS, CONTINGENCIES AND GUARANTEES (Note 14)

                                                                         ------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                                       16,871         17,156
                                                                         ==============================
</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
Cdn$ millions

                                                                      Three Months              Nine Months
                                                                   Ended September 30       Ended September 30
                                                                     2007        2006        2007         2006
---------------------------------------------------------------------------------------------------------------
<S>                                                                 <C>         <C>         <C>          <C>
 OPERATING ACTIVITIES
    Net Income                                                        403         199         892          524
    Charges and Credits to Income not Involving Cash (Note 12)        404         199       1,286        1,164
    Exploration Expense                                                67          82         221          231
    Changes in Non-Cash Working Capital (Note 12)                     253         212         (19)         (92)
    Other                                                             (30)        (16)       (253)         (43)
                                                                -----------------------------------------------
                                                                    1,097         676       2,127        1,784

FINANCING ACTIVITIES
    Proceeds from Long-Term Notes                                       -           -       1,660            -
    Proceeds from (Repayment of) Term Credit Facilities, Net          188         136        (767)         551
    Proceeds from Term Credit Facilities of Canexus                    12           6          45            4
    Repayment of Medium-Term Notes                                   (150)          -        (150)           -
    Proceeds from (Repayment of) Short-Term Borrowings, Net           (60)         37        (152)         122
    Dividends on Common Shares (Note 10)                              (13)        (13)        (39)         (39)
    Issue of Common Shares and Exercise of Stock Options                4           4          44           41
    Other                                                              (8)         (7)        (43)         (21)
                                                                -----------------------------------------------
                                                                      (27)        163         598          658

INVESTING ACTIVITIES
    Capital Expenditures
      Exploration and Development                                    (772)       (844)     (2,309)      (2,330)
      Proved Property Acquisitions                                   (104)         (9)       (150)         (12)
      Chemicals, Corporate and Other                                  (25)        (26)        (72)         (88)
    Business Acquisitions, Net of Cash Acquired                         -           -           -          (78)
    Proceeds on Disposition of Assets                                   -           -           -           25
    Changes in Restricted Cash and Margin Deposits                   (103)        (52)        (21)         (40)
    Changes in Non-Cash Working Capital (Note 12)                     (33)         56          11          115
    Other                                                              (1)        (18)        (15)         (22)
                                                                -----------------------------------------------
                                                                   (1,038)       (893)     (2,556)      (2,430)


EFFECT OF EXCHANGE RATE CHANGES ON CASH
    AND CASH EQUIVALENTS                                              (18)         (1)        (98)         (29)
                                                                -----------------------------------------------

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                       14         (55)         71          (17)

CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD                       158          86         101           48
                                                                -----------------------------------------------

CASH AND CASH EQUIVALENTS - END OF PERIOD                             172          31         172           31
                                                                ===============================================
</TABLE>

SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.

                                       6
<PAGE>

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

                                                                        Three Months              Nine Months
                                                                     Ended September 30       Ended September 30
                                                                       2007        2006         2007        2006
-----------------------------------------------------------------------------------------------------------------
<S>                                                                   <C>         <C>          <C>         <C>
COMMON SHARES
    Balance at Beginning of Period                                      893         799          821         732
      Issue of Common Shares                                              3           2           28          28
      Proceeds from Options Exercised for Shares                          1           2           16          13
      Accrued Liability Relating to Options Exercised for Shares         (6)          6           26          36
                                                                    ---------------------------------------------
    Balance at End of Period                                            891         809          891         809
                                                                    =============================================

CONTRIBUTED SURPLUS
    Balance at Beginning of Period                                        5           3            4           2
      Stock-Based Compensation Expense                                    -           -            1           1
      Exercise of Stock Options                                          (2)          -           (2)          -
                                                                    ---------------------------------------------
    Balance at End of Period                                              3           3            3           3
                                                                    =============================================

RETAINED EARNINGS
    Balance at Beginning of Period                                    4,435       3,722        3,972       3,423
      Net Income                                                        403         199          892         524
      Dividends on Common Shares                                        (13)        (13)         (39)        (39)
                                                                    ---------------------------------------------
    Balance at End of Period                                          4,825       3,908        4,825       3,908
                                                                    =============================================

ACCUMULATED OTHER COMPREHENSIVE INCOME
    Balance at Beginning of Period                                     (253)       (230)        (161)          -
      Opening Cumulative Foreign Currency Translation Adjustment          -           -            -        (161)
      (Note 1)
      Opening Derivatives Designated as Cash Flow Hedges (Note 1)         -           -           61           -
      Other Comprehensive Income                                        (51)         (2)        (204)        (71)
                                                                    ---------------------------------------------
    Balance at End of Period                                           (304)       (232)        (304)       (232)
                                                                    =============================================
</TABLE>
<TABLE>
<CAPTION>
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30
Cdn$ millions
                                                                           Three Months              Nine Months
                                                                        Ended September 30       Ended September 30
                                                                          2007        2006        2007         2006
--------------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>         <C>         <C>          <C>
    Net Income                                                             403         199         892          524
    Other Comprehensive Loss, Net of Income Taxes:
      Foreign Currency Translation Adjustment:
        Net Losses on Investment in Self-Sustaining Foreign Operations    (327)          -        (822)        (218)
        Net Gains on Hedges of Self-Sustaining Foreign Operations (1)      276          (2)        679          145
        Realized Translation Adjustments Recognized in Net Income (2)        -           -           -            2
      Cash Flow Hedges:
        Realized Mark-to-Market Gains Recognized in Net Income               -           -         (61)           -
                                                                       ---------------------------------------------
      Other Comprehensive Loss                                             (51)         (2)       (204)         (71)
                                                                       ---------------------------------------------
    Comprehensive Income                                                   352         197         688          453
                                                                       =============================================
</TABLE>

(1)  Net of income taxes for the three months ended  September  30, 2007 of $47
     million (2006 - $nil) and for the nine months ended  September 30, 2007 of
     $113 million (2006 - $18 million).

(2)  Net of income taxes for the three months ended  September  30, 2007 of nil
     (2006 - $nil) and nine  months  ended  September  30, 2007 of $nil (2006 -
     $nil).

SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.

                                       7
<PAGE>

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

1. ACCOUNTING POLICIES

Our Unaudited Consolidated Financial Statements are prepared in accordance with
Canadian  Generally  Accepted  Accounting  Principles  (GAAP).  The  impact  of
significant  differences  between  Canadian and United  States (US) GAAP on the
Unaudited  Consolidated  Financial  Statements  is disclosed in Note 16. 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, 2007 and
December 31, 2006 and the results of our  operations and our cash flows for the
three and nine months ended September 30, 2007 and 2006.

We make estimates and  assumptions  that affect the reported  amounts of assets
and liabilities and disclosure of contingent assets and liabilities at the date
of the Unaudited Consolidated  Financial Statements,  and revenues and expenses
during the reporting period. Our management reviews these estimates,  including
those  related to  accruals,  litigation,  environmental  and asset  retirement
obligations,  income taxes,  derivative  contract  assets and  liabilities  and
determination  of proved  reserves,  on an ongoing basis.  Changes in facts and
circumstances  may result in revised  estimates  and actual  results may differ
from these  estimates.  The results of operations  and cash flows for the three
and nine months ended September 30, 2007 are not necessarily  indicative of the
results of operations or cash flows to be expected for the year ending December
31, 2007.

These Unaudited Consolidated Financial Statements should be read in conjunction
with our Audited Consolidated  Financial Statements included in our 2006 Annual
Report on Form 10-K.  Except as described  below,  the  accounting  policies we
follow are described in Note 1 of the Audited Consolidated Financial Statements
included in our 2006 Annual Report on Form 10-K.

CHANGE IN ACCOUNTING POLICIES
On January 1, 2007, we adopted the following new accounting standards issued by
the    Canadian     Accounting     Standards     Board    (AcSB):     FINANCIAL
INSTRUMENTS--RECOGNITION  AND MEASUREMENT (Section 3855), HEDGES (Section 3865)
and COMPREHENSIVE INCOME (Section 1530).

FINANCIAL INSTRUMENTS--RECOGNITION AND MEASUREMENT
Section 3855 requires all  financial  assets and  liabilities  to be carried at
fair value in the balance  sheet with the  exception of loans and  receivables,
investments that are intended to be held to maturity and non-trading  financial
liabilities which are to be carried at cost or amortized cost.

Realized and unrealized  gains and losses on financial  assets and  liabilities
carried at fair value are  recognized in the statement of income in the periods
such gains and  losses  arise.  Transaction  costs  related to these  financial
assets and  liabilities  are included in the statement of income when incurred.
Unrealized gains and losses on financial assets and liabilities carried at cost
or amortized  cost are  recognized in the statement of income when these assets
or liabilities settle.

We hold  financial  instruments  that were  carried at fair value  prior to the
adoption of Section 3855 as described in Note 9. The  valuation  methods we use
to determine the fair value of these financial  instruments  remain  unchanged.
Financial  instruments  we carry at cost or amortized cost include our accounts
receivable,  accounts  payable,  short-term and long-term  debt.  Upon adopting
Section 3855 with respect to the amortized  cost using the  effective  interest
rate method of our long-term debt, we have reclassed  deferred  financing costs
previously  included in deferred  charges and other assets as unamortized  debt
issue costs which reduce the carrying value of our long-term debt.

HEDGES
Section 3865 prescribes new standards for hedge accounting.

For cash flow  hedges,  changes  in the fair  value of a  financial  instrument
designated  as a cash flow hedge are  recognized  in the statement of income in
the same  period as the hedged  item.  Any fair value  change in the  financial
instrument before that period is recognized on the balance sheet. The effective
portion of this fair value change is recognized in other  comprehensive  income
with any  ineffectiveness  recognized  in the  statement  of income  during the
period of change.

For fair value hedges, both the financial instrument designated as a fair value
hedge and the underlying commitment are recognized on the balance sheet at fair
value.  Changes in the fair value of both are  reflected  in the  statement  of
income.

Adoption  of these new  standards  for hedge  accounting  required us to record
unrealized  mark-to-market  gains on cash flow hedges that were  previously not
included  on  our  Consolidated  Balance  Sheet  at  December  31,  2006  as an
adjustment to the opening  balance of accumulated  other  comprehensive  income
(see Note 9).

                                       8
<PAGE>

COMPREHENSIVE INCOME
Section  1530  provides  for  a  new  statement  of  comprehensive  income  and
establishes  accumulated other comprehensive  income as a separate component of
shareholders' equity. The statement of comprehensive income reflects changes in
accumulated  other  comprehensive  income and includes the effective portion of
changes  in the fair value of  financial  instruments  designated  as cash flow
hedges, as well as changes in foreign currency  translation  amounts arising in
respect of self-sustaining  foreign operations  together with the impact of any
related hedges.  Amounts included in accumulated other comprehensive income are
reclassified  to the statement of income when realized.  On adoption of Section
1530,  cumulative  foreign  currency  translation  adjustments  relating to our
self-sustaining   foreign   operations  were  reclassed  to  accumulated  other
comprehensive income and comparative amounts have been restated.

We adopted these standards prospectively. Comparative amounts for prior periods
have not been  restated  with the  exception of amounts  related to  cumulative
foreign  currency  translation  adjustments.  Adoption of these standards as at
January 1, 2007 had the following impact on our Unaudited  Consolidated Balance
Sheet:

<TABLE>
                                                                                                   January 1, 2007
                                                                                               Increase/(Decrease)
-------------------------------------------------------------------------------------------------------------------
<S>                                                                                                           <C>
To Include Unrealized Mark-to-Market Gains on Cash Flow Hedges at December 31, 2006:
    Accounts Receivable                                                                                         25
    Accounts Payable and Accrued Liabilities                                                                   (65)
    Future Income Tax Liabilities                                                                               29
    Accumulated Other Comprehensive Income                                                                      61

To Include Cumulative Foreign Currency Translation in Accumulated Other Comprehensive Income:
    Cumulative Foreign Currency Translation Adjustment                                                         161
    Accumulated Other Comprehensive Income                                                                    (161)

To Include Unamortized Debt Issue Costs with Long-Term Debt:
    Deferred Charges and Other Assets                                                                          (59)
    Long-Term Debt                                                                                             (59)
                                                                                               --------------------
</TABLE>

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

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

In June 2007,  the AcSB issued  Section 3031,  INVENTORIES,  which replaces the
existing guidance. The new section is harmonized with International  Accounting
Standards and provides  additional  guidance on the  measurement and disclosure
requirements for inventories.  Specifically,  Section 3031 requires inventories
to be  measured  at the  lower  of  cost  and  net  realizable  value.  The new
requirements  are effective  for fiscal years  beginning on or after January 1,
2008.  We do not expect the adoption of this section to have a material  impact
on our results of operations or financial position.

<TABLE>
<CAPTION>
2. ACCOUNTS RECEIVABLE

                                                                 September 30    December 31
                                                                         2007           2006
---------------------------------------------------------------------------------------------
<S>                                                              <C>             <C>
Trade
    Marketing                                                           1,803         2,226
    Oil and Gas                                                           721           600
    Chemicals and Other                                                    42            58
                                                                -----------------------------
                                                                        2,566         2,884
Non-Trade                                                                 127            80
                                                                -----------------------------
                                                                        2,693         2,964
Allowance for Doubtful Receivables                                        (10)          (13)
                                                                -----------------------------
Total                                                                   2,683         2,951
                                                                =============================
</TABLE>

                                       9
<PAGE>

<TABLE>
<CAPTION>
3. INVENTORIES AND SUPPLIES

                                                                September 30    December 31
                                                                        2007           2006
---------------------------------------------------------------------------------------------
<S>                                                             <C>              <C>
Finished Products
    Marketing                                                            490            609
    Oil and Gas                                                           13             21
    Chemicals and Other                                                   14             14
                                                               ------------------------------
                                                                         517            644
Work in Process                                                            4              5
Field Supplies                                                           107            137
                                                               ------------------------------
Total                                                                    628            786
                                                               ==============================

4. DEFERRED CHARGES AND OTHER ASSETS

                                                                September 30    December 31
                                                                        2007           2006
---------------------------------------------------------------------------------------------
Long-Term Marketing Derivative Contracts (Note 9)                        172            153
Deferred Financing Costs (Note 1)                                          -             59
Asset Retirement Remediation Fund                                         14             13
Crude Oil Put Options (Note 9)                                            12             19
Other                                                                     78             74
                                                               ------------------------------
Total                                                                    276            318
                                                               ==============================
</TABLE>

5. SUSPENDED WELL COSTS

The following  table shows the changes in  capitalized  exploratory  well costs
during  the nine  month  period  ended  September  30,  2007 and the year ended
December 31, 2006, and does not include amounts that were initially capitalized
and  subsequently  expensed in the same period.  Capitalized  exploratory  well
costs are included in PP&E.

<TABLE>
                                                                  Nine Months Ended      Year Ended
                                                                       September 30     December 31
                                                                               2007            2006
----------------------------------------------------------------------------------------------------
<S>                                                               <C>                  <C>
Balance at Beginning of Period                                                  226             252
    Additions to Capitalized Exploratory Well Costs Pending the
      Determination of Proved Reserves                                          125             129
    Capitalized Exploratory Well Costs Charged to Expense                        (6)            (70)
    Transfers to Wells, Facilities and Equipment Based on
      Determination of Proved Reserves                                          (70)            (84)
    Effects of Foreign Exchange                                                 (28)             (1)
                                                                 -----------------------------------
Balance at End of Period                                                        247             226
                                                                 ===================================
</TABLE>

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

<TABLE>
                                                                        September 30     December 31
                                                                                2007            2006
-----------------------------------------------------------------------------------------------------
<S>                                                                     <C>              <C>
Capitalized for a Period of One Year or Less                                     131            179
Capitalized for a Period of Greater than One Year                                116             47
                                                                       ------------------------------
Balance at End of Period                                                         247            226
                                                                       ==============================
Number of Projects that have Exploratory Well Costs Capitalized
    for a Period Greater than One Year                                             6              4
                                                                       ------------------------------
</TABLE>

As at September 30, 2007, we have exploratory  costs that have been capitalized
for more than one year relating to our interest in an exploratory  block in the
Gulf of Mexico ($50 million),  our coalbed  methane  exploratory  activities in
Canada ($23 million), two exploratory wells on Block 51 in Yemen ($19 million),
our interest in an  exploratory  block  offshore  Nigeria ($18  million) and an
exploratory  block in the North Sea ($6  million).  We have  capitalized  costs
related to successful wells drilled in Nigeria,  Gulf of Mexico, North Sea, and
at Block 51 in Yemen. In Canada, we have capitalized exploratory costs relating
to our  coalbed  methane  projects.  We are  assessing  all of these  wells and
projects, and are working with our partners to prepare development plans, drill
additional appraisal wells or to assess commercial viability.

                                      10
<PAGE>

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

                                                                        September 30      December 31
                                                                                2007             2006
------------------------------------------------------------------------------------------------------
<S>                                                                     <C>              <C>
Term Credit Facilities (US$146 million) (a)                                      146            1,078
Canexus LP Term Credit Facilities (US$189 million)                               188              174
Medium-Term Notes, due 2007 (1)                                                    -              150
Medium-Term Notes, due 2008 (2)                                                  125              125
Notes, due 2013 (US$500 million)                                                 498              583
Notes, due 2015 (US$250 million)                                                 249              291
Notes, due 2017 (US$250 million) (b)                                             249                -
Notes, due 2028 (US$200 million)                                                 200              233
Notes, due 2032 (US$500 million)                                                 498              583
Notes, due 2035 (US$790 million)                                                 787              920
Notes, due 2037 (US$1,250 million) (c)                                         1,246                -
Subordinated Debentures, due 2043 (US$460 million)                               458              536
                                                                        ------------------------------
                                                                               4,644            4,673
Unamortized Debt Issue Costs (Note 1)                                            (79)               -
                                                                        ------------------------------
Total Long-Term Debt                                                           4,565            4,673
                                                                        ==============================
</TABLE>
(1)  Amounts  due July 2007 were not  included  in  current  liabilities  as we
     refinanced this amount with our term credit facilities.

(2)  Amounts due June 2008 are not included in current liabilities as we expect
     to refinance this amount with our term credit facilities.

(a) TERM CREDIT FACILITIES

We have committed,  unsecured term credit facilities of $3.1 billion, which are
available to 2012. At September  30, 2007,  $146 million  (US$146  million) was
drawn on these facilities (December 31, 2006 - $1,078 million).  Borrowings are
available as Canadian bankers'  acceptances,  LIBOR-based loans, Canadian prime
loans,  US-dollar base rate loans or British pound call-rate loans. Interest is
payable monthly at floating rates.  The  weighted-average  interest rate on our
term credit  facilities was 5.9% for the three months ended  September 30, 2007
(2006 - 5.8%) and 5.9% for the nine  months  ended  September  30, 2007 (2006 -
5.7%). At September 30, 2007, $346 million of these facilities were utilized to
support outstanding  letters of credit (December 31, 2006 - $294 million).

(b) NOTES, DUE 2017

In May 2007,  we issued  US$250  million of 10 year notes.  Interest is payable
semi-annually at a rate of 5.65% and the principal is to be repaid in May 2017.
We may redeem part or all of the notes at any time. The  redemption  price will
be the  greater  of par and an  amount  that  provides  the same  yield as a US
Treasury security having a term-to-maturity  equal to the remaining term of the
notes  plus 0.2%.  The  proceeds  were used to repay  outstanding  term  credit
facilities.

(c) NOTES, DUE 2037

In May 2007, we issued US$1,250  million of 30 year notes.  Interest is payable
semi-annually at a rate of 6.40% and the principal is to be repaid in May 2037.
We may redeem part or all of the notes at any time. The  redemption  price will
be the  greater  of par and an  amount  that  provides  the same  yield as a US
Treasury security having a term-to-maturity  equal to the remaining term of the
notes plus  0.35%.  The  proceeds  were used to repay  outstanding  term credit
facilities.

<TABLE>
<CAPTION>
(d) INTEREST EXPENSE
                                                             Three Months            Nine Months
                                                          Ended September 30      Ended September 30
                                                            2007        2006         2007       2006
-----------------------------------------------------------------------------------------------------
<S>                                                         <C>         <C>          <C>        <C>
Long-Term Debt                                                80          72          244        199
Other                                                          5           5           14         15
                                                         --------------------------------------------
                                                              85          77          258        214
   Less: Capitalized                                         (45)        (62)        (124)      (179)
                                                         --------------------------------------------
Total                                                         40          15          134         35
                                                         ============================================
</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.

                                      11
<PAGE>

(e) SHORT-TERM BORROWINGS

Nexen has  uncommitted,  unsecured  credit  facilities  of  approximately  $630
million,  none of which were drawn at September  30, 2007  (December 31, 2006 -
$158  million).  We  utilized  $106  million  of these  facilities  to  support
outstanding  letters of credit at September 30, 2007  (December 31, 2006 - $252
million).  Interest is payable at floating rates. The weighted-average interest
rate on our short-term borrowings was 5.8% for the three months ended September
30, 2007 (2006 - 5.5%) and 5.8% for the nine months  ended  September  30, 2007
(2006 - 5.3%).

7. ASSET RETIREMENT OBLIGATIONS

Changes in carrying amounts of the asset retirement obligations associated with
our property,  plant and equipment for the nine months ended September 30, 2007
and the year ended December 31, 2006, are as follows:

<TABLE>
                                                                            Nine Months Ended     Year Ended
                                                                                 September 30    December 31
                                                                                         2007           2006
-------------------------------------------------------------------------------------------------------------
<S>                                                                         <C>                  <C>
Balance at Beginning of Period                                                            704            611
    Obligations Assumed with Development Activities                                        69             75
    Obligations Discharged with Disposed Properties                                         -             (1)
    Expenditures Made on Asset Retirements                                                (18)           (44)
    Accretion                                                                              33             37
    Revisions to Estimates                                                                 (3)           (10)
    Effects of Foreign Exchange                                                           (63)            36
                                                                           ----------------------------------
Balance at End of Period (1)(2)                                                           722            704
                                                                           ==================================
</TABLE>
(1)  Obligations  due within 12 months of $21 million  (December 31, 2006 - $21
     million) have been included in accounts payable and accrued liabilities.
(2)  Obligations  relating to our oil and gas activities amount to $676 million
     (December  31,  2006 -  $658  million)  and  obligations  relating  to our
     chemicals  business  amount  to  $46  million  (December  31,  2006  - $46
     million).


Our total estimated  undiscounted asset retirement obligations amount to $1,785
million  (December 31, 2006 - $1,770  million).  We have  discounted  the total
estimated   asset   retirement    obligations    using   a    weighted-average,
credit-adjusted  risk-free rate of 5.7%. Approximately $103 million included in
our asset retirement  obligations will be settled over the next five years. The
remaining  obligations  settle  beyond  five years and will be funded by future
cash flows from our operations.

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

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

                                                                               September 30     December 31
                                                                                       2007            2006
------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>              <C>
Long-Term Marketing Derivative Contracts (Note 9)                                        95             199
Deferred Transportation Revenue                                                          83              89
Fixed-Price Natural Gas Contracts and Swaps (Note 9)                                     57              76
Defined Benefit Pension Obligations                                                      52              48
Capital Lease Obligations                                                                50              48
Stock-Based Compensation Liability                                                        7               6
Other                                                                                    52              50
                                                                              ------------------------------
Total                                                                                   396             516
                                                                              ==============================
</TABLE>


                                      12
<PAGE>

9. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

We use derivatives in our marketing group for trading  purposes and we also use
derivatives  to manage  commodity  price  risk for  non-trading  purposes.  Our
derivative  instruments are carried at fair value on the Unaudited Consolidated
Balance Sheet. Our other financial instruments are carried at cost or amortized
cost.

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

The carrying  values,  fair  values,  and  unrecognized  gains or losses on our
outstanding derivatives and other financial liabilities are:

<TABLE>
                                                        SEPTEMBER 30, 2007                    DECEMBER 31, 2006
-----------------------------------------------------------------------------------------------------------------------------
                                                Carrying       Fair    Unrecognized     Carrying       Fair     Unrecognized
                                                   Value      Value     Gain/(Loss)        Value      Value      Gain/(Loss)
                                              --------------------------------------  ---------------------------------------
<S>                                             <C>           <C>      <C>              <C>           <C>       <C>
Derivatives
    Commodity Price Risk
      Non-Trading Activities
        Crude Oil Put Options                         12         12               -           19         19                -
        Fixed-Price Natural Gas Contracts            (68)       (68)              -          (96)       (96)               -
        Natural Gas Swaps                            (17)       (17)              -           (8)        (8)               -

      Trading Activities
        Crude Oil and Natural Gas                    138        138               -          372        372                -
        Future Sale of Gas Inventory                   -          -               -            -         25               25

    Foreign Currency Exchange Rate Risk
      Non-Trading Activities                           1          1               -            -          -                -
      Trading Activities                               -          -               -          (12)       (12)               -
                                              --------------------------------------  ---------------------------------------
Total Derivatives                                     66         66               -          275        300               25
                                              ======================================  =======================================

Other Financial Liabilities
      Long-Term Debt                              (4,565)    (4,605)           (40)       (4,673)    (4,728)             (55)
                                              ======================================  =======================================
</TABLE>

The  estimated  fair  value of all  derivative  instruments  is based on quoted
market prices and, if not available,  on estimates from third-party  brokers or
dealers.  Other financial  assets used in the normal course of business include
cash and cash  equivalents,  restricted  cash and margin  deposits and accounts
receivable.  Other financial  liabilities  include  accounts  payable,  accrued
interest  payable,  short-term  borrowings  and long-term  debt.  Fair value of
long-term  debt is estimated  based on  third-party  brokers and quoted  market
prices.

(b) COMMODITY PRICE RISK MANAGEMENT

NON-TRADING ACTIVITIES

We generally sell our crude oil and natural gas under  short-term  market based
contracts.

CRUDE OIL PUT OPTIONS
In 2006,  we  purchased  WTI crude oil put  options  to provide a base level of
price protection  without  limiting our upside to higher prices.  These options
establish  an annual  average WTI floor price of  US$50/bbl  in 2007 on 105,000
bbls/d at a cost of $26  million.  The crude oil put options are stated at fair
value and are included in accounts  receivable as they settle within 12 months.
Any change in fair value is included in  marketing  and other on the  Unaudited
Consolidated Statement of Income.

During  the second  quarter of 2007,  we  purchased  put  options on 36 million
barrels or about 100,000 bbls/d of our 2008 crude oil production. These options
establish  a Dated  Brent floor  price of  US$50/bbl  on these  volumes and are
settled  annually.  The put  options  were  purchased  for $24  million and are
carried at fair value.  Any change in fair value is included in  marketing  and
other income on the Unaudited Consolidated Statement of Income.

<TABLE>
                                        Notional                  Average               Fair
                                         Volumes       Term         Price              Value
---------------------------------------------------------------------------------------------
                                        (bbls/d)                (US$/bbl)     (Cdn$ millions)
<S>                                      <C>           <C>        <C>                  <C>
WTI Crude Oil Put Options                105,000       2007            50                 -
Dated Brent Crude Oil Put Options        100,000       2008            50                 12
                                                                              ---------------
                                                                                          12
                                                                              ===============
</TABLE>

                                      13
<PAGE>

FIXED-PRICE NATURAL GAS CONTRACTS AND NATURAL GAS SWAPS
In July and August 2005, we sold certain  Canadian oil and gas  properties  and
retained   fixed-price   natural  gas  sales  contracts  that  were  previously
associated with those  properties.  Since these contracts are no longer used in
the normal course of our oil and gas operations, they have been included in the
Unaudited  Consolidated Balance Sheet at fair value. Amounts settling within 12
months are included in accounts  payable and amounts  settling  greater than 12
months are included in deferred  credits and other  liabilities.  Any change in
fair value is included in  marketing  and other in the  Unaudited  Consolidated
Statement of Income.

<TABLE>
<CAPTION>
                                         Notional                           Average            Fair
                                          Volumes             Term            Price           Value
----------------------------------------------------------------------------------------------------
                                           (Gj/d)                            ($/Gj)  (Cdn$ millions)
<S>                                        <C>         <C>              <C>                   <C>
Fixed-Price Natural Gas Contracts          15,514      2007 - 2008             2.46             (20)
                                           15,514      2008 - 2010      2.56 - 2.77             (48)
                                                                                     ---------------
                                                                                                (68)
                                                                                     ===============
</TABLE>

Following  the sale of the  Canadian  oil and gas  properties,  we entered into
natural gas swaps to hedge our fixed price  exposure with floating  natural gas
prices.  Any change in fair value is  included  in  marketing  and other in the
Unaudited  Consolidated  Statement of Income. Amounts settling within 12 months
are included in accounts receivable and amounts settling greater than 12 months
are included in deferred charges and other assets.

<TABLE>
                                       Notional                       Average                 Fair
                                        Volumes             Term        Price                Value
---------------------------------------------------------------------------------------------------
                                         (Gj/d)                        ($/Gj)       (Cdn$ millions)
<S>                                      <C>         <C>              <C>                    <C>
Natural Gas Swaps                        15,514      2007 - 2008         7.60                   (8)
                                         15,514      2008 - 2010         7.60                   (9)
                                                                                    ---------------
                                                                                               (17)
                                                                                    ===============
</TABLE>

TRADING ACTIVITIES

CRUDE OIL AND NATURAL GAS
We enter  into  physical  purchase  and sales  contracts  as well as  financial
commodity  contracts to enhance our price realizations and lock in our margins.
The physical and  financial  commodity  contracts  (derivative  contracts)  are
stated at fair value.  The $138 million fair value of the derivative  contracts
at September 30, 2007 is included in the Unaudited  Consolidated  Balance Sheet
and any change is included in marketing and other in the Unaudited Consolidated
Statement of Income.

FUTURE SALE OF GAS INVENTORY
In an  attempt to  mitigate  the  exposure  to  fluctuations  in cash flow from
changes in the price of natural gas we have certain NYMEX futures contracts and
swaps in place, which effectively lock in our margins on the future sale of our
natural gas  inventory  in storage.  From time to time we have  designated,  in
writing,  some of these derivative  contracts as cash flow hedges of the future
sale of our storage inventory.

With the adoption of Section 3865 HEDGES as described in Note 1, the  effective
portion of gains and losses  relating to cash flow  hedges are now  included in
other  comprehensive  income  until  the gains or losses  are  realized  in net
income.  Prior to the  adoption of Section  3865,  gains and losses  related to
derivatives classified as cash flow hedges were unrecognized.

At December 31, 2006,  we held NYMEX  natural gas futures  contracts  and swaps
that were  designated  as cash flow  hedges on the future  sale of natural  gas
inventory.  On adoption of Section 3865, the fair value of $25 million  related
to these cash flow hedges was  recognized in accounts  receivable on January 1,
2007.  The fair value gain of $16 million,  net of income  taxes,  was included
with the opening  balance of  accumulated  other  comprehensive  income (AOCI).
During the first quarter of 2007, the inventory was sold and as a result, gains
on these  cash  flow  hedges  were  recognized  in  marketing  and other in the
Unaudited Consolidated Statement of Income.

In late  2006,  we  de-designated  certain  futures  contracts  that  had  been
designated  as cash flow hedges of future  sales of our natural gas in storage.
These contracts were  de-designated  since it became  uncertain that the future
sales of natural gas would occur within the  designated  time frame.  As it was
reasonably  possible that the future sales could have taken place as designated
at the  inception  of the  hedging  relationship,  gains of $65  million on the
futures  contracts were deferred in accounts  payable at December 31, 2006. The
adoption of Section 3865 required that the deferred gains ($45 million,  net of
income  taxes) be  reclassified  to AOCI on  January  1,  2007.  The gains were
recognized in marketing and other in the  Unaudited  Consolidated  Statement of
Income during the first quarter of 2007.

At September 30, 2007, there were no cash flow hedges in place.

                                      14
<PAGE>

(c) FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT

NON-TRADING ACTIVITIES

US DOLLAR CALL OPTIONS - CANEXUS

The operations of Canexus are exposed to changes in the US-dollar exchange rate
as a portion of their sales are denominated in US dollars and they periodically
purchase  financial  contracts  to reduce this  exposure.  During the  quarter,
Canexus  purchased  US-dollar  call  options,  which  allows  them to sell US$5
million  monthly and purchase  Canadian  dollars at an exchange rate of US$0.95
for the  period  September  2007 to  February  2008.  The  fair  value of these
contracts  at  September  30,  2007 was $1  million.  Changes in fair value are
included in  marketing  and other in the  Unaudited  Consolidated  Statement of
Income.

TRADING ACTIVITIES

Our sales and purchases of crude oil and natural gas are  generally  transacted
in or  referenced  to the US  dollar,  as are most of the  financial  commodity
contracts  used  by our  marketing  group.  However,  we pay  for  many  of our
purchases in Canadian  dollars.  We enter into US-dollar  forward contracts and
swaps to manage  this  exposure.  Gains and  losses  on our  US-dollar  forward
contracts and swaps are included in the Unaudited  Consolidated  Balance Sheet,
and any  change  in fair  value  is  included  in  marketing  and  other in the
Unaudited  Consolidated  Statement of Income.  At September 30, 2007,  the fair
value of our US-dollar forward contracts and swaps was immaterial.

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

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

<TABLE>
                                                                         September 30    December 31
                                                                                 2007           2006
------------------------------------------------------------------------------------------------------
<S>                                                                      <C>             <C>
Accounts Receivable                                                               329            731
Deferred Charges and Other Assets (1)                                             172            153
                                                                        ------------------------------
    Total Derivative Contract Assets                                              501            884
                                                                        ==============================

Accounts Payable and Accrued Liabilities                                          268            325
Deferred Credits and Other Liabilities (1)                                         95            199
                                                                        ------------------------------
    Total Derivative Contract Liabilities                                         363            524
                                                                        ==============================

    Total Derivative Contract Net Assets (2)                                      138            360
                                                                        ==============================
</TABLE>

(1)  These  derivative  contracts  settle  beyond 12 months and are  considered
     non-current.
(2)  Comprised  of $138  million  (2006 - $372  million)  related to  commodity
     contracts  and gains of $nil  (2006 - losses of $12  million)  related  to
     US-dollar forward contracts and swaps.

Our  exchange-traded   derivative  contracts  are  subject  to  margin  deposit
requirements.   In   addition,   we  may  be   required  to  post  margin  with
counterparties  in order to satisfy their credit  requirements.  We have margin
deposits of $176 million  (December 31, 2006 - $197  million),  which have been
included in restricted cash and margin  deposits on our Unaudited  Consolidated
Balance Sheet at September 30, 2007.

10.  SHAREHOLDERS' EQUITY

DIVIDENDS
Dividends  per common share for the three months ended  September 30, 2007 were
$0.025  (2006 - $0.025).  Dividends  per common share for the nine months ended
September  30, 2007 were $0.075 (2006 - $0.075).  Dividends  paid to holders of
common  shares have been  designated as "eligible  dividends"  for Canadian tax
purposes.


11.  EARNINGS PER COMMON SHARE

Our shareholders  approved a split of our issued and outstanding  common shares
on a two-for-one basis at our annual and special meeting on April 26, 2007. All
common share and per common share amounts have been  retroactively  restated to
reflect this share split.

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

                                      15
<PAGE>

<TABLE>
                                                                      Three Months            Nine Months
                                                                   Ended September 30      Ended September 30
(millions of shares)                                                 2007        2006          2007      2006
--------------------------------------------------------------------------------------------------------------
<S>                                                                 <C>         <C>           <C>       <C>
Weighted-average number of common shares outstanding                527.4       524.6         526.8     524.0
Shares issuable pursuant to tandem options                           25.7        27.2          27.0      28.2
Shares to be purchased from proceeds of tandem options              (15.3)      (14.2)        (15.2)    (14.4)
                                                                  --------------------------------------------
Weighted-average number of diluted common shares outstanding        537.8       537.6         538.6     537.8
                                                                  ============================================
</TABLE>

In calculating the weighted-average number of diluted common shares outstanding
for the three and nine months ended  September 30, 2007, we excluded 80,000 and
45,445 options respectively,  because their exercise price was greater than the
average  common  share  market  price  in those  periods.  In  calculating  the
weighted-average  number of diluted common shares outstanding for the three and
nine months ended  September 30, 2006, all options were included  because their
exercise  price was less than the average  common  share  market price in those
periods. During the periods presented, outstanding tandem options were the only
potential dilutive instruments.


12.  CASH FLOWS

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

                                                                   Three Months            Nine Months
                                                                Ended September 30      Ended September 30
                                                                  2007        2006         2007       2006
-----------------------------------------------------------------------------------------------------------
<S>                                                               <C>         <C>         <C>         <C>
Depreciation, Depletion, Amortization and Impairment               349         244        1,043        770
Stock-Based Compensation                                          (106)        (68)        (132)        44
Future Income Taxes                                                142          16          303        299
Change in Fair Value of Crude Oil Put Options                       11           5           31          6
Net Income Attributable to Non-Controlling Interests                 7           3           15         12
Other                                                                1          (1)          26         33
                                                               --------------------------------------------
Total                                                              404         199        1,286      1,164
                                                               ============================================
(b) CHANGES IN NON-CASH WORKING CAPITAL

                                                                   Three Months            Nine Months
                                                                Ended September 30      Ended September 30
                                                                  2007        2006         2007       2006
-----------------------------------------------------------------------------------------------------------
   Accounts Receivable                                             122        (280)          55        557
   Inventories and Supplies                                        200          11           21       (247)
   Other Current Assets                                            (29)        (50)         (18)       (29)
   Accounts Payable and Accrued Liabilities                        (76)        603          (80)      (240)
   Accrued Interest Payable                                          3         (16)          14        (18)
                                                               --------------------------------------------
Total                                                              220         268           (8)        23
                                                               ============================================

Relating to:
   Operating Activities                                            253         212          (19)       (92)
   Investing Activities                                            (33)         56           11        115
                                                               --------------------------------------------
Total                                                              220         268           (8)        23
                                                               ============================================
(c) OTHER CASH FLOW INFORMATION

                                                                   Three Months             Nine Months
                                                                Ended September 30      Ended September 30
                                                                  2007        2006          2007      2006
-----------------------------------------------------------------------------------------------------------
Interest Paid                                                       77          87           233       217
Income Taxes Paid                                                  127         109           284       317
                                                               --------------------------------------------
</TABLE>

                                      16
<PAGE>

<TABLE>
<CAPTION>
13.  MARKETING AND OTHER
                                                                   Three Months             Nine Months
                                                                Ended September 30      Ended September 30
                                                                  2007        2006          2007      2006
-----------------------------------------------------------------------------------------------------------
<S>                                                                <C>         <C>           <C>       <C>
Marketing Revenue, Net                                             219         229           750       959
Change in Fair Value of Crude Oil Put Options                      (11)         (5)          (31)       (6)
Interest                                                            10           8            29        27
Foreign Exchange Losses                                            (11)         (1)          (54)      (49)
Other (1)                                                           19          56            79       158
                                                               --------------------------------------------
Total                                                              226         287           773     1,089
                                                               ============================================
</TABLE>

(1)  Other  income  for the three and nine  months  ended  September  30,  2006
     includes $50 million of business interruption  insurance proceeds relating
     to production  losses caused by Gulf of Mexico  Hurricanes in 2005.  Other
     income for the nine months ended  September  30, 2006 includes $74 million
     of business interruption insurance proceeds relating to generator failures
     in 2005 at our UK oil and gas operations.


14.  COMMITMENTS, CONTINGENCIES AND GUARANTEES

As  described  in  Note 15 to the  Audited  Consolidated  Financial  Statements
included in our 2006 Annual Report on 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.


                                      17
<PAGE>

15. OPERATING SEGMENTS AND RELATED INFORMATION

Nexen is involved in  activities  relating  to Oil and Gas,  Energy  Marketing,
Syncrude and Chemicals in various geographic  locations as described in Note 20
to the Audited  Consolidated  Financial  Statements included in our 2006 Annual
Report on Form 10-K.


<TABLE>
<CAPTION>
THREE MONTHS ENDED SEPTEMBER 30, 2007
                                                                                                           Corporate
                                                                               Energy                            and
                                             Oil and Gas                    Marketing  Syncrude  Chemicals     Other       Total
---------------------------------------------------------------------------------------------------------------------------------
                                                                     Other
                                                United    United Countries
                              Yemen   Canada    States   Kingdom       (1)
                             ----------------------------------------------
<S>                           <C>     <C>       <C>      <C>     <C>        <C>        <C>       <C>        <C>            <C>
Net Sales                       280      101       137       608        42         13       160        105         -       1,446
Marketing and Other               2        -         1         7         -        219         -          9       (12)(2)     226
                             ----------------------------------------------------------------------------------------------------
Total Revenues                  282      101       138       615        42        232       160        114       (12)      1,672
Less: Expenses
 Operating                       43       49        21        50         2          7        53         58         -         283
 Depreciation, Depletion,
   Amortization and
    Impairment                   54       41        66       151         2          3        14         11         7         349
 Transportation and Other         2        5         -         -         -        211         4         10         6         238
 General and Administrative(3)   (7)     (10)        5        (2)       (3)        15         1          7         1           7
 Exploration                      -        4        33        12        18(4)       -         -          -         -          67
 Interest                         -        -         -         -         -          -         -          3        37          40
                             ----------------------------------------------------------------------------------------------------
Income (Loss)
 before Income Taxes            190       12        13       404        23         (4)       88         25       (63)        688
Less: Provision for
(Recovery
 of) Income Taxes                63(5)     4         4       206        (3)        (1)       26          8       (29)        278
Less: Non-Controlling
 Interests                        -       -          -         -         -          -         -          7         -           7
                             ----------------------------------------------------------------------------------------------------
Net Income (Loss)               127        8         9       198        26         (3)       62         10       (34)        403
                             ====================================================================================================

Identifiable Assets             378    4,961(6)  1,786     4,616       272      2,983(7)  1,190        470       215      16,871
                             ====================================================================================================

Capital Expenditures
 Development and Other           32      304        98       136        20          1        12         13        11         627
 Exploration                      1       42        90        31         6          -         -          -         -         170
 Proved Property Acquisitions     -        -       104(8)      -         -          -         -          -         -         104
                             ----------------------------------------------------------------------------------------------------
                                 33      346       292       167        26          1        12         13        11         901
                             ====================================================================================================

Property, Plant and Equipment
 Cost                         2,148    6,265     2,921      4,576       243        230    1,324        809       314      18,830
 Less: Accumulated DD&A       1,930    1,560     1,349        746        75         54      209        452       164       6,539
                             ----------------------------------------------------------------------------------------------------
Net Book Value                  218    4,705(6)  1,572      3,830       168        176    1,115        357       150      12,291
                             ====================================================================================================
</TABLE>
(1) Includes results of operations from producing activities in Colombia.
(2) Includes  interest  income of $10 million,  foreign  exchange losses of $11
    million  and  decrease  in the fair  value of crude oil put  options of $11
    million.
(3) Includes recovery of stock-based compensation of $77 million.
(4) Includes exploration activities primarily in Nigeria, Norway and Colombia.
(5) Includes Yemen cash taxes of $65 million.
(6) Includes  costs of $2,533 million  related to our Long Lake project,  which
    are not being depreciated, depleted or amortized.
(7) Approximately   77%  of  Marketing's   identifiable   assets  are  accounts
    receivable and inventories.
(8) Includes acquisition of producing properties in the Gulf of Mexico.

                                      18
<PAGE>

<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30, 2007
                                                                                                           Corporate
                                                                               Energy                            and
                                             Oil and Gas                    Marketing   Syncrude  Chemicals     Other       Total
---------------------------------------------------------------------------------------------------------------------------------
                                                                    Other
                                               United    United Countries
                              Yemen   Canada   States   Kingdom       (1)
                             ----------------------------------------------
<S>                           <C>     <C>      <C>      <C>     <C>         <C>         <C>       <C>       <C>             <C>
Net Sales                       811      329      453     1,544       106          36        394        312         -       3,985
Marketing and Other               8        4        1        35         -         750          -         31       (56)(2)     773
                             -----------------------------------------------------------------------------------------------------
Total Revenues                  819      333      454     1,579       106         786        394        343       (56)      4,758
Less: Expenses
 Operating                      127      130       75       156         6          26        151        191         -         862
 Depreciation, Depletion,
   Amortization and
    Impairment                  176      123      212       423         8          10         39         33        19       1,043
 Transportation and Other         6       18        -         -         -         620         13         29         8         694
 General and Administrative(3)  (10)      30       19         -        22          68          1         24        93         247
 Exploration                      5       18       95        50        53(4)        -          -          -         -         221
 Interest                         -        -        -         -         -           -          -          9       125         134
                             -----------------------------------------------------------------------------------------------------
Income (Loss)
 before Income Taxes            515       14       53       950        17          62        190         57      (301)      1,557
Less: Provision for
(Recovery
 of) Income Taxes               176(5)     4       18       490         4          25         56         17      (140)        650
Less: Non-Controlling
 Interests                        -        -        -         -         -           -          -         15         -          15
                             -----------------------------------------------------------------------------------------------------
Net Income (Loss)               339       10       35       460        13          37        134         25      (161)        892
                             =====================================================================================================

Identifiable Assets             378    4,961(6) 1,786     4,616       272       2,983(7)   1,190        470       215      16,871
                             =====================================================================================================

Capital Expenditures
 Development and Other           95      976      365       434        35           2         27         39        31       2,004
 Exploration                     11       87      153        94        32           -          -          -         -         377
 Proved Property Acquisitions     -        -      104(8)     46(9)      -           -          -          -         -         150
                             -----------------------------------------------------------------------------------------------------
                                106    1,063      622       574        67           2         27         39        31       2,531
                             =====================================================================================================

Property, Plant and Equipment
 Cost                         2,148    6,265    2,921     4,576       243         230      1,324        809       314      18,830
 Less: Accumulated DD&A       1,930    1,560    1,349       746        75          54        209        452       164       6,539
                             -----------------------------------------------------------------------------------------------------
Net Book Value                  218    4,705(6) 1,572     3,830       168         176      1,115        357       150      12,291
                             =====================================================================================================
</TABLE>
(1) Includes results of operations from producing activities in Colombia.
(2) Includes  interest  income of $29 million,  foreign  exchange losses of $54
    million  and  decrease  in the fair  value of crude oil put  options of $31
    million.
(3) Includes recovery of stock-based compensation of $16 million.
(4) Includes exploration activities primarily in Nigeria, Norway and Colombia.
(5) Includes Yemen cash taxes of $174 million.
(6) Includes  costs of $2,533 million  related to our Long Lake project,  which
    are not being depreciated, depleted or amortized.
(7) Approximately   77%  of  Marketing's   identifiable   assets  are  accounts
    receivable and inventories.
(8) Includes acquisition of producing properties in the Gulf of Mexico.
(9) Includes  acquisition  of  additional  interests  in the Scott and  Telford
    fields.

                                      19
<PAGE>

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

                                                                                                           Corporate
                                                                               Energy                            and
                                             Oil and Gas                    Marketing  Syncrude  Chemicals     Other        Total
----------------------------------------------------------------------------------------------------------------------------------
                                                                     Other
                                              United     United  Countries
                              Yemen   Canada  States    Kingdom        (1)
                             ----------------------------------------------
<S>                           <C>     <C>     <C>       <C>      <C>        <C>        <C>       <C>       <C>              <C>
Net Sales                       337      118     154        104         41         12       130        101         -          997
Marketing and Other               2        1      51(2)       2          -        229         -          -         2(3)       287
                             -----------------------------------------------------------------------------------------------------
Total Revenues                  339      119     205        106         41        241       130        101         2        1,284
Less: Expenses
 Operating                       36       35      27         21          2          6        42         60         -          229
 Depreciation, Depletion,
   Amortization and
    Impairment                   80       40      51         43          3          2         8         10         7          244
 Transportation and Other         1       11       -          -          -        173         3         11       134(5)       333
 General and Administrative(4)   (3)       5      (1)         -          5         18         -          7        20           51
 Exploration                      1        4      63          5          9(6)       -         -          -         -           82
 Interest                         -        -       -          -          -          -         -          3        12           15
                             -----------------------------------------------------------------------------------------------------
Income (Loss)
 before Income Taxes            224       24      65         37         22         42        77         10      (171)         330
Less: Provision for
(Recovery
 of) Income Taxes                78(7)     8      22          9          8         12        25          3       (37)         128
Less: Non-Controlling
 Interests                        -        -       -          -          -          -         -          3         -            3
                             -----------------------------------------------------------------------------------------------------
Net Income (Loss)               146       16      43         28         14         30        52          4      (134)         199
                             =====================================================================================================

Identifiable Assets             539    3,601   1,539      5,029        185      3,030(8)  1,199        461       312       15,895
                             =====================================================================================================

Capital Expenditures
 Development and Other           35      362     131        131          7          9        17          4        13          709
 Exploration                     13       89      43         10          6          -         -          -         -          161
 Proved Property Acquisitions     -        9       -          -          -          -         -          -         -            9
                             -----------------------------------------------------------------------------------------------------
                                 48      460     174        141         13          9        17          4        13          879
                             =====================================================================================================

Property, Plant and Equipment
 Cost                         2,282    4,825   2,646      4,292        210        219     1,306        836       276       16,892
 Less: Accumulated DD&A       2,003    1,403   1,243        358         73         44       179        483       144        5,930
                             -----------------------------------------------------------------------------------------------------
Net Book Value                  279    3,422   1,403      3,934        137        175     1,127        353       132       10,962
                             =====================================================================================================
</TABLE>
(1) Includes results of operations from producing activities in Colombia.
(2) Includes $50 million of business interruption insurance proceeds related to
    production losses caused by Gulf of Mexico hurricanes in 2005.
(3) Includes  interest  income of $8  million,  foreign  exchange  losses of $1
    million  and  decrease  in the fair  value of crude oil put  options  of $5
    million.
(4) Includes stock-based compensation expense recovery of $23 million.
(5) Includes $134 million accrual with respect to the Block 51 arbitration.
(6) Includes exploration activities primarily in Nigeria and Colombia.
(7) Includes Yemen cash taxes of $76 million.
(8) Approximately   85%  of  Marketing's   identifiable   assets  are  accounts
    receivable and inventories.

                                      20
<PAGE>

<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30, 2006
                                                                                                            Corporate
                                                                               Energy                             and
                                             Oil and Gas                    Marketing   Syncrude  Chemicals     Other       Total
----------------------------------------------------------------------------------------------------------------------------------
                                                                     Other
                                               United    United  Countries
                              Yemen   Canada   States   Kingdom        (1)
                             ---------------------------------------------
<S>                           <C>     <C>      <C>      <C>      <C>        <C>        <C>        <C>       <C>             <C>
Net Sales                     1,029      351      496       372        108         26        328        306         -       3,016
Marketing and Other               6        7       51(2)     81(3)       1        959          -         12       (28)(4)   1,089
                             -----------------------------------------------------------------------------------------------------
Total Revenues                1,035      358      547       453        109        985        328        318       (28)      4,105
Less: Expenses
 Operating                      110      103       79        63          5         18        139        185         -         702
 Depreciation, Depletion,
   Amortization and
    Impairment                  248      115      155       168          8          6         19         30        21         770
 Transportation and Other         4       22        -         -          -        591         14         31       134(5)      796
 General and Administrative(6)   11       56       44         6         30         93          -         20       119         379
 Exploration                      1       18      140        33         39(7)       -          -          -         -         231
 Interest                         -        -        -         -          -          -          -          8        27          35
                             -----------------------------------------------------------------------------------------------------
Income (Loss)
 before Income Taxes            661       44      129       183         27        277        156         44      (329)      1,192
Less: Provision for
(Recovery
 of) Income Taxes               231(8)   (18)      44       333(9)      10        113         51         14      (122)        656
Less: Non-Controlling
 Interests                        -        -        -         -          -          -          -         12         -          12
                             -----------------------------------------------------------------------------------------------------
Net Income (Loss)               430       62       85      (150)        17        164        105         18      (207)        524
                             =====================================================================================================

Identifiable Assets             539    3,601    1,539     5,029        185      3,030(10)  1,199        461       312      15,895
                             =====================================================================================================

Capital Expenditures
 Development and Other          110      996      275       410         20         44         74         14        30       1,973
 Exploration                     28      206      155        35         21          -          -          -         -         445
 Proved Property Acquisitions     -       11        -         1          -          -          -          -         -          12
                             -----------------------------------------------------------------------------------------------------
                                138    1,213      430       446         41         44         74         14        30       2,430
                             =====================================================================================================

Property, Plant and Equipment
 Cost                         2,282    4,825    2,646     4,292        210        219      1,306        836       276      16,892
 Less: Accumulated DD&A       2,003    1,403    1,243       358         73         44        179        483       144       5,930
                             -----------------------------------------------------------------------------------------------------
Net Book Value                  279    3,422    1,403     3,934        137        175      1,127        353       132      10,962
                             =====================================================================================================
</TABLE>
(1) Includes results of operations from producing activities in Colombia.
(2) Includes $50 million of business interruption insurance proceeds related to
    production losses caused by Gulf of Mexico hurricanes in 2005.
(3) Includes  proceeds  of $74 million  from  business  interruption  insurance
    claims for generator failures in 2005 at our UK oil and gas operations.
(4) Includes  interest  income of $27 million,  foreign  exchange losses of $49
    million  and  decrease  in the fair  value of crude oil put  options  of $6
    million.
(5) Includes $134 million accrual with respect to the Block 51 arbitration.
(6) Includes stock-based compensation expense of $133 million.
(7) Includes exploration activities primarily in Nigeria and Colombia.
(8) Includes Yemen cash taxes of $224 million.
(9) Includes  future income tax expense of $277 million  related to an increase
    in the  supplemental  tax  rate  on oil and gas  activities  in the  United
    Kingdom.
(10)Approximately  85%  of  Marketing's   identifiable   assets  are  accounts
    receivable and inventories.

                                      21
<PAGE>

16. DIFFERENCES   BETWEEN  CANADIAN  AND  US  GENERALLY   ACCEPTED   ACCOUNTING
    PRINCIPLES

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

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

                                                                       Three Months                Nine Months
                                                                    Ended September 30         Ended September 30
(Cdn$ millions, except per share amounts)                            2007         2006         2007          2006
------------------------------------------------------------------------------------------------------------------
<S>                                                                 <C>          <C>          <C>           <C>
REVENUES AND OTHER INCOME
    Net Sales                                                       1,446          997        3,985         3,016
    Marketing and Other (i)                                           226          298          771         1,111
                                                               ---------------------------------------------------
                                                                    1,672        1,295        4,756         4,127
                                                               ---------------------------------------------------
EXPENSES
    Operating (ii)                                                    292          231          884           708
    Depreciation, Depletion, Amortization and Impairment              349          244        1,043           770
    Transportation and Other                                          238          333          694           796
    General and Administrative (iv)                                    18           69          268           412
    Exploration                                                        67           82          221           231
    Interest                                                           40           15          134            35
                                                               ---------------------------------------------------
                                                                    1,004          974        3,244         2,952
                                                               ---------------------------------------------------

INCOME BEFORE INCOME TAXES                                            668          321        1,512         1,175
                                                               ---------------------------------------------------

PROVISION FOR INCOME TAXES
    Current                                                           136          112          347           357
    Deferred (i) - (iv)                                               137          290          290           294
                                                               ---------------------------------------------------
                                                                      273          402          637           651
                                                               ---------------------------------------------------

NET INCOME (LOSS) BEFORE NON-CONTROLLING INTERESTS                    395          (81)         875           524
    Less: Net Income Attributable to Non-Controlling Interests         (7)          (3)         (15)          (12)
                                                               ---------------------------------------------------

NET INCOME (LOSS) - US GAAP (1)                                       388          (84)         860           512
                                                               ===================================================

EARNINGS (LOSS) PER COMMON SHARE ($/share)
    Basic (Note 11)                                                  0.74        (0.16)        1.63          0.98
                                                               ===================================================

    Diluted (Note 11)                                                0.72        (0.16)        1.60          0.95
                                                               ===================================================


(1) Reconciliation of Canadian and US GAAP Net Income
                                                                       Three Months               Nine Months
                                                                    Ended September 30         Ended September 30
                                                                     2007         2006         2007          2006
    --------------------------------------------------------------------------------------------------------------
      Net Income - Canadian GAAP                                      403          199          892           524
      Impact of US Principles, Net of Income Taxes:
        Ineffective Portion of Cash Flow Hedges (i)                     -            7           (2)           14
        Pre-operating Costs (ii)                                       (7)          (1)         (15)           (4)
        Deferred Income Taxes (iii)                                     -         (277)           -             -
        Liability-based Stock Compensation Plans (iv)                  (8)         (12)         (15)          (22)
                                                               ---------------------------------------------------
      Net Income (Loss) - US GAAP                                     388          (84)         860           512
                                                               ===================================================
</TABLE>

                                      22
<PAGE>

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

                                                                                  September 30    December 31
(Cdn$ millions, except share amounts)                                                     2007           2006
--------------------------------------------------------------------------------------------------------------
<S>                                                                               <C>            <C>
ASSETS
    CURRENT ASSETS
      Cash and Cash Equivalents                                                            172            101
      Restricted Cash and Margin Deposits                                                  176            197
      Accounts Receivable                                                                2,683          2,976
      Inventories and Supplies                                                             628            786
      Deferred Income Tax Asset                                                             73            479
      Other                                                                                 77             67
                                                                                 -----------------------------
        Total Current Assets                                                             3,809          4,606
                                                                                 -----------------------------

    PROPERTY, PLANT AND EQUIPMENT
      Net of Accumulated Depreciation, Depletion, Amortization and
         Impairment of $6,932 (December 31, 2006 - $6,792) (ii); (vi)                   12,222         11,692
    DEFERRED INCOME TAX ASSETS                                                             167            141
    DEFERRED CHARGES AND OTHER ASSETS                                                      276            263
    GOODWILL                                                                               328            377
                                                                                 -----------------------------
TOTAL ASSETS                                                                            16,802         17,079
                                                                                 =============================

LIABILITIES AND SHAREHOLDERS' EQUITY
    CURRENT LIABILITIES
      Short-Term Borrowings                                                                  -            158
      Accounts Payable and Accrued Liabilities (iv)                                      3,454          3,839
      Accrued Interest Payable                                                              67             55
      Dividends Payable                                                                     13             13
                                                                                 -----------------------------
        Total Current Liabilities                                                        3,534          4,065
                                                                                 -----------------------------

    LONG-TERM DEBT                                                                       4,565          4,618
    DEFERRED INCOME TAX LIABILITIES (i) - (vi)                                           2,178          2,427
    ASSET RETIREMENT OBLIGATIONS                                                           701            683
    DEFERRED CREDITS AND LIABILITIES (v)                                                   477            597
    NON-CONTROLLING INTERESTS                                                               75             75
    SHAREHOLDERS' EQUITY
      Common Shares, no par value
        Authorized:   Unlimited
        Outstanding:  2007 - 527,429,968 shares
                      2006 - 525,026,412 shares                                            891            821
      Contributed Surplus                                                                    3              4
      Retained Earnings (i) - (vi)                                                       4,738          3,945
      Accumulated Other Comprehensive Income (i); (v)                                     (360)          (156)
                                                                                 -----------------------------
          Total Shareholders' Equity                                                     5,272          4,614
                                                                                 -----------------------------
     COMMITMENTS, CONTINGENCIES AND GUARANTEES

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                                              16,802         17,079
                                                                                 =============================
</TABLE>

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

                                                                  Three Months                   Nine Months
                                                               Ended September 30             Ended September 30
(Cdn$ millions)                                              2007            2006           2007            2006
-----------------------------------------------------------------------------------------------------------------
<S>                                                         <C>              <C>           <C>             <C>
Net Income (Loss) - US GAAP                                   388             (84)           860             512
Other Comprehensive Income, Net of Income Taxes:
    Foreign Currency Translation Adjustment                   (51)             (6)          (143)            (71)
    Change in Mark to Market on Cash Flow Hedges (i)            -              46            (61)             66
                                                          -------------------------------------------------------
Comprehensive Income (Loss)                                   337             (44)           656             507
                                                          =======================================================
</TABLE>

                                      23
<PAGE>

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

                                                                 September 30   December 31
(Cdn$ millions)                                                          2007          2006
--------------------------------------------------------------------------------------------
<S>                                                              <C>             <C>
Foreign Currency Translation Adjustment                                  (304)         (161)
Mark to Market on Cash Flow Hedges (i)                                      -            61
Unamortized Defined Benefit Pension Costs (v)                             (56)          (56)
                                                                ----------------------------
                                                                         (360)         (156)
                                                                ============================
</TABLE>

NOTES:
i.    Under US GAAP, all derivative  instruments  are recognized on the balance
      sheet as either an asset or a liability  measured at fair value.  Changes
      in the fair  value of  derivatives  are  recognized  in  earnings  unless
      specific  hedge  criteria  are met.  On January 1, 2007,  we adopted  the
      equivalent Canadian standard for derivative instruments.

      CASH FLOW HEDGES
      Changes in the fair value of derivatives that are designated as cash flow
      hedges are  recognized in earnings in the same period as the hedged item.
      Any fair value change in a derivative before that period is recognized on
      the balance sheet. The effective  portion of that change is recognized in
      other  comprehensive  income with any  ineffectiveness  recognized in net
      income during the period of change.

      FUTURE SALE OF GAS INVENTORY:  At December 31, 2006,  accounts receivable
      includes  gains of $25 million on futures  contracts and swaps we used to
      hedge commodity price risk on the future sale of our gas inventory. Gains
      of  $23  million  ($16  million,  net of  income  taxes)  related  to the
      effective  portion  and  deferred  in AOCI at  December  31,  2006,  were
      recognized  in  marketing  and other in the first  quarter  of 2007.  The
      ineffective portion of the gains of $2 million ($2 million, net of income
      taxes) was recognized in marketing and other in 2006 under US GAAP. Under
      Canadian  GAAP, the  ineffective  portion was recognized in net income in
      the first quarter of 2007.

      Our US GAAP net income  for the nine  months  ended  September  30,  2006
      includes $22 million of gains ($14 million, net of income taxes) relating
      to the ineffective portion of cash flow hedges.

      Also  included in AOCI at December 31, 2006 are gains of $65 million ($45
      million,  net of income taxes) related to de-designated cash flow hedges.
      These gains were  recognized  in marketing and other in the first quarter
      of 2007.  Under  Canadian  GAAP,  these  deferred  gains are  included in
      accounts  payable and accrued  liabilities  at December 31, 2006 and have
      been  recognized  in marketing  and other income in the first  quarter of
      2007.

      At September 30, 2007, there were no cash flow hedges in place.

      FAIR VALUE HEDGES
      Both  the  derivative   instrument  and  the  underlying  commitment  are
      recognized on the balance  sheet at their fair value.  The change in fair
      value of both is  reflected in  earnings.  At  September  30, 2007 and at
      December 31, 2006, we had no fair value hedges in place.

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

      o     operating  expenses include  pre-operating  costs of $9 million and
            $22 million for the three and nine months ended September 30, 2007,
            respectively  ($7 million  and $15  million,  respectively,  net of
            income taxes) (2006 - $2 million and $6 million,  respectively  ($1
            million and $4 million, respectively, net of income taxes)); and

      o     property, plant and equipment is lower under US GAAP by $50 million
            (December 31, 2006 - $28 million).

iii.  Under US GAAP,  enacted tax rates are used to calculate  deferred  income
      taxes, whereas under Canadian GAAP, substantively enacted rates are used.
      During the first quarter of 2006, the UK government substantively enacted
      increases to the  supplementary tax on oil and gas activities from 10% to
      20%, effective January 1, 2006. This created a $277 million future income
      tax expense during the first quarter of 2006 under Canadian GAAP.  During
      the third  quarter of 2006,  the UK  government  enacted  the revised tax
      rates and we recognized the $277 million  deferred  income tax expense in
      our US GAAP net income for the three months ended September 30, 2006.

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. We are also
      required  to  accelerate  the  recognition  of  stock-based  compensation
      expense  for  all  stock-based  awards  made  to our  retirement-eligible
      employees  under Canadian GAAP.  However,  under US GAAP, the accelerated
      recognition  for such employees is only required for  stock-based  awards
      granted on or after January 1, 2006. As a result:

                                      24
<PAGE>

      o     general and administrative expense is higher by $11 million and $21
            million for the three and nine months  ended  September  30,  2007,
            respectively  ($8 million  and $15  million,  respectively,  net of
            income  taxes)  (2006 -  higher  by $18  million  and $33  million,
            respectively  ($12  million and $22 million,  respectively,  net of
            income taxes)); and

      o     accounts payable and accrued  liabilities are higher by $46 million
            as at September 30, 2007 (December 31, 2006 - $25 million).

v.    On December 31, 2006, we adopted FASB Statement 158 EMPLOYERS' ACCOUNTING
      FOR DEFINED BENEFIT PENSION AND OTHER  POSTRETIREMENT PLANS (FAS 158). At
      September 30, 2007, the unfunded  amount of our defined  benefit  pension
      plans was $81 million.  This amount has been included in deferred credits
      and other  liabilities  and $56  million,  net of  income  taxes has been
      included in AOCI.  Prior to the adoption of FAS 158 on December 31, 2006,
      we included our minimum  unfunded  pension  liability in deferred credits
      and other liabilities and in AOCI.

vi.   On January 1, 2003, we adopted FASB Statement  143,  ACCOUNTING FOR ASSET
      RETIREMENT  OBLIGATIONS  (FAS  143) for US GAAP  reporting  purposes.  We
      adopted the equivalent Canadian standard for asset retirement obligations
      on  January  1,  2004.  These  standards  are  consistent  except for the
      adoption date which results in our property, plant and equipment under US
      GAAP being lower by $19 million.

STOCK-BASED COMPENSATION EXPENSE FOR RETIRED AND RETIREMENT-ELIGIBLE EMPLOYEES
Under US GAAP, we recognize  stock-based  compensation  expense for our retired
and  retirement-eligible  employees  over  an  accelerated  vesting  period  in
accordance  with the  provisions  of Statement  123(R) for  stock-based  awards
granted  to  employees  on or after  January 1, 2006.  For  stock-based  awards
granted  prior to the adoption of Statement  123(R),  stock-based  compensation
expense for our retired and retirement-eligible  employees is recognized over a
graded vesting  period.  If we applied the  accelerated  vesting  provisions of
Statement   123(R)  to   stock-based   awards   granted  to  our   retired  and
retirement-eligible  employees prior to the adoption of Statement 123(R), there
would be no material  change to our  stock-based  compensation  expense for the
three and nine months ended September 30, 2007 and 2006.


CHANGES IN ACCOUNTING POLICIES - US GAAP
INCOME TAXES
On  January  1,  2007,  we  adopted  FASB   Interpretation  48  ACCOUNTING  FOR
UNCERTAINTY  IN INCOME  TAXES (FIN 48) with respect to FAS 109  ACCOUNTING  FOR
INCOME TAXES  regarding  accounting and disclosure for uncertain tax positions.
On the  adoption  of FIN 48, we  recorded  a  cumulative  effect of a change in
accounting principle of $28 million.  This amount increased our deferred income
tax liabilities,  with a corresponding  decrease to our retained earnings as at
January 1, 2007 in our US GAAP - Unaudited  Consolidated  Balance Sheet.  As at
September  30,  2007,  the total  amount of our  unrecognized  tax benefits was
approximately  $210  million,  all of which,  if  recognized,  would affect our
effective tax rate. As at September 30, 2007,  the total amount of interest and
penalties in relation to uncertain tax positions  recognized in deferred income
tax  liabilities  in the US GAAP -  Unaudited  Consolidated  Balance  Sheet  is
approximately  $10  million.  We had no interest or  penalties in the US GAAP -
Unaudited  Consolidated  Statement of Income for the first nine months of 2007.
Our income tax filings are subject to audit by taxation  authorities  and as at
September 30, 2007 the following tax years remained subject to examination; (i)
Canada - 1985 to date,  (ii)  United  Kingdom - 2002 to date and  (iii)  United
States  - 2004 to  date.  We do not  anticipate  any  material  changes  to the
unrecognized tax benefits previously disclosed within the next twelve months.


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

Effective  December  31,  2006,  we  adopted  the  recognition  and  disclosure
provisions of FASB Statement  158,  EMPLOYERS'  ACCOUNTING FOR DEFINED  BENEFIT
PENSION  AND  OTHER   POSTRETIREMENT   PLANS.   This  statement  also  requires
measurement  of the funded status of a plan as of the balance  sheet date.  The
measurement  provisions  of the statement are effective for fiscal years ending
after  December  15,  2008.  We do not  expect  the  adoption  of the change in
measurement date in 2008 to have a material impact on our results of operations
or financial position.

In  February  2007,  FASB  issued  Statement  159,  THE FAIR  VALUE  OPTION FOR
FINANCIAL  ASSETS  AND  FINANCIAL  LIABILITIES.  The  statement  allows for the
elective measurement of eligible financial  instruments and certain other items
at fair value in order to  mitigate  volatility  in reported  earnings  without
having to apply complex and detailed hedge accounting  rules. This statement is
effective for fiscal years  beginning after November 15, 2007. We do not expect
the  adoption  of this  statement  to have a material  impact on our results of
operations or financial position.

                                      25
<PAGE>

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

THE FOLLOWING  SHOULD BE READ IN  CONJUNCTION  WITH THE UNAUDITED  CONSOLIDATED
FINANCIAL  STATEMENTS  INCLUDED  IN THIS  REPORT.  THE  UNAUDITED  CONSOLIDATED
FINANCIAL  STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE WITH GENERALLY  ACCEPTED
ACCOUNTING   PRINCIPLES  (GAAP)  IN  CANADA.  THE  IMPACT  OF  THE  SIGNIFICANT
DIFFERENCES  BETWEEN  CANADIAN AND UNITED STATES (US) ACCOUNTING  PRINCIPLES ON
THE FINANCIAL STATEMENTS IS DISCLOSED IN NOTE 16 TO THE UNAUDITED  CONSOLIDATED
FINANCIAL STATEMENTS. THE DATE OF THIS DISCUSSION IS OCTOBER 23, 2007.

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

NOTE:  CANADIAN INVESTORS SHOULD READ THE SPECIAL NOTE TO CANADIAN INVESTORS ON
PAGE 81 OF OUR 2006  ANNUAL  REPORT ON FORM 10-K WHICH  HIGHLIGHTS  DIFFERENCES
BETWEEN  OUR  RESERVE  ESTIMATES  AND RELATED  DISCLOSURES  THAT ARE  OTHERWISE
REQUIRED BY CANADIAN REGULATORY AUTHORITIES.

WE MAKE  ESTIMATES  AND  ASSUMPTIONS  THAT AFFECT THE  REPORTED  AMOUNTS OF OUR
ASSETS AND LIABILITIES AND THE DISCLOSURE OF CONTINGENT  ASSETS AND LIABILITIES
AT THE DATE OF THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS AND OUR REVENUES
AND  EXPENSES  DURING  THE  REPORTED  PERIOD.   OUR  MANAGEMENT  REVIEWS  THESE
ESTIMATES, INCLUDING THOSE RELATED TO ACCRUALS,  LITIGATION,  ENVIRONMENTAL AND
ASSET  RETIREMENT  OBLIGATIONS,  INCOME TAXES,  DERIVATIVE  CONTRACT ASSETS AND
LIABILITIES  AND THE  DETERMINATION  OF PROVED  RESERVES  ON AN ONGOING  BASIS.
CHANGES IN FACTS AND  CIRCUMSTANCES  MAY RESULT IN REVISED ESTIMATES AND ACTUAL
RESULTS MAY DIFFER FROM THESE ESTIMATES.

<TABLE>
<CAPTION>
EXECUTIVE SUMMARY OF THIRD QUARTER RESULTS

                                                              Three Months               Nine Months
                                                            Ended September 30       Ended September 30
(Cdn$ millions, unless otherwise stated)                     2007         2006        2007         2006
--------------------------------------------------------------------------------------------------------
<S>                                                         <C>            <C>       <C>          <C>
Net Income                                                    403          199         892          524
Earnings per Common Share ($/share)                          0.77         0.38        1.69         1.00
Cash Flow from Operating Activities                         1,097          676       2,127        1,784

Production, before Royalties (mboe/d)                         261          203         251          213
Production, after Royalties (mboe/d)                          214          148         204          155
Nexen's Average Realized Oil and Gas Price (Cdn$/boe)       69.82        66.82       65.96        64.83

Capital Investment, including Acquisitions                    901          879       2,531        2,508
Net Debt (1)                                                4,393        4,161       4,393        4,161
                                                          ----------------------------------------------
</TABLE>
(1)  Net debt is defined as long-term debt and short-term  borrowings less cash
     and cash equivalents.

Increased  production and high commodity prices generated strong net income and
cash flow from operating  activities during the quarter. Our quarterly realized
oil and gas prices  increased 4% from the same period in 2006, while WTI was 7%
higher than last year.  The full impact of the increase in WTI was not realized
as the Canadian  dollar  strengthened  7% relative to the US dollar.  Our sales
revenue is  denominated  in or  referenced  to US dollars and as a result,  our
reported  revenues  decline as the US-dollar  weakens.  On the other hand,  our
US-dollar  capital  spending,  operating  costs  and net  debt are  lower  when
translated to Canadian  dollars.  During the third quarter,  the  strengthening
Canadian dollar reduced our cash flow from operating  activities and net income
by $63 million and $26 million,  for the quarter  respectively,  as compared to
the third quarter of 2006.

Production  after  royalties  increased 45% from last year  primarily  from new
high-margin  production that came on stream at Buzzard. At Buzzard,  production
has regularly exceeded facility design rates of 200,000 boe/d (85,000 boe/d net
to Nexen).  Production  increases from Buzzard were partially offset by natural
declines  in Yemen as the fields  mature and by declines in the Gulf of Mexico.
Steam  injection  continued  at Long Lake  during the  quarter and we remain on
track to have  sufficient  bitumen  production for the upgrader start up in mid
2008.

Our net debt decreased by $337 million since  December 31, 2006,  which largely
reflects  the impact of the  weakening US dollar as our  US-dollar  denominated
debt was approximately  $800 million lower when translated to Canadian dollars.
This was offset by capital investments in our major development projects,  core
assets  and  exploration  activities  that  exceeded  cash flow from  operating
activities.

                                      26
<PAGE>

CAPITAL INVESTMENT

Our capital investment strategy continues to focus on developing major projects,
exploring our growth basins, maximizing the remaining value of our core assets
and investing in new technology. In 2007, we are investing in:

     o    Major Development projects such as Long Lake Phase 1, Buzzard ongoing
          development drilling and Ettrick in the North Sea and coalbed methane
          in Canada;

     o    Early Stage Developments including Phase 2 of Long Lake, shale gas in
          Canada, the Usan project, offshore West Africa and Longhorn, offshore
          Gulf of Mexico;

     o    New Growth  Exploration  targeting up to 11  high-impact  exploration
          prospects,  primarily  in the Gulf of Mexico and the North  Sea,  and
          enhancing our prospect  inventory in the Gulf of Mexico and shale gas
          in Canada; and

     o    Core Asset  Developments in our existing asset base including Wrigley
          and Aspen in the Gulf of Mexico.

Details of our capital programs are set out below.

<TABLE>
<CAPTION>
THREE MONTHS ENDED SEPTEMBER 30, 2007
                                                 Major     Early Stage     New Growth      Core Asset
(Cdn$ millions)                            Development     Development    Exploration     Development      Total
-----------------------------------------------------------------------------------------------------------------
<S>                                        <C>             <C>            <C>             <C>              <C>
Oil and Gas
   Synthetic (mainly Long Lake)                    222              16              2               -        240
   United Kingdom                                  128               -             31               8        167
   Yemen                                             -               -              1              32         33
   United States                                     4              20             90             178        292
   Canada                                           22               8             40              36        106
   Other Countries                                   -              11              6               9         26
Syncrude                                             -               -              -              12         12
                                          -----------------------------------------------------------------------
                                                   376              55            170             275        876
Chemicals, Marketing, Corporate and Other            -               -              -              25         25
                                          -----------------------------------------------------------------------
Total Capital                                      376              55            170             300        901
                                          =======================================================================
As a % of Total Capital                            42%              6%            19%             33%       100%
                                          -----------------------------------------------------------------------

NINE MONTHS ENDED SEPTEMBER 30, 2007

                                                 Major     Early Stage     New Growth      Core Asset
(Cdn$ millions)                            Development     Development    Exploration     Development      Total
-----------------------------------------------------------------------------------------------------------------
Oil and Gas
   Synthetic (mainly Long Lake)                    735              87              5               -        827
   United Kingdom                                  382               -             94              98        574
   Yemen                                             -               -             11              95        106
   United States                                    27              20            153             422        622
   Canada                                           66              17             82              71        236
   Other Countries                                   -              19             32              16         67
Syncrude                                             -               -              -              27         27
                                          -----------------------------------------------------------------------
                                                 1,210             143            377             729      2,459
Chemicals, Marketing, Corporate and Other            -               -              -              72         72
                                          -----------------------------------------------------------------------
Total Capital                                    1,210             143            377             801      2,531
                                          =======================================================================
As a % of Total Capital                            48%              5%            15%             32%       100%
                                          -----------------------------------------------------------------------
</TABLE>

MAJOR AND EARLY STAGE DEVELOPMENT PROJECTS

SYNTHETIC
At Long  Lake,  we  continue  to inject  steam into the  reservoir  and are now
starting  to see  bitumen  in the  fluid  returns.  We  remain on track to have
sufficient bitumen production for the upgrader start up in mid 2008.  Depending
on production ramp up and new facility uptime,  bitumen production should reach
capacity of approximately 72,000 bbls/d (36,000 bbls/d net to us) in 2009.

Construction and commissioning of the upgrader continues. We recently completed
the construction of the  hydrocracker,  the OrCrude(TM) unit and all main plant
utilities.  We are on track to complete  construction of the gasifier,  the air
separation  unit  and  sulphur  recovery  unit in  sufficient  time  for  first
production of synthetic  crude oil in mid 2008. We anticipate the upgrader will
reach its full  production  capacity of  approximately  60,000  bbls/d  (30,000
bbls/d  net to us) of  premium  synthetic  crude  about 12 to 18  months  after

                                      27
<PAGE>

initial  start  up.  Our cost  estimate  for  Phase 1 ranges  from $5.8 to $6.1
billion ($2.9 to $3.05 billion net to us).

Phase 1 of Long Lake will develop a small  portion of our oils and leases using
our patented process which  significantly  reduces the need to purchase natural
gas,  a key cost  driver  in  competing  technologies.  This  will  result in a
significant cost advantage for us. We plan to sequentially  develop  additional
60,000 bbls/d  (30,000  bbls/d net to us) phases using the same  technology and
design as Long Lake.

UNITED KINGDOM
Our Ettrick field  development  in the North Sea continues to progress well and
is  approximately  80%  complete.  The  project  will  consist of three  subsea
production  wells  and  one  water  injector  tied  back to a  leased  floating
production,  storage  and  offloading  vessel  (FPSO).  The FPSO is designed to
handle 30,000 bbls/d of oil, 35 mmcf/d of gas and to re-inject 55,000 bbls/d of
water.  Production  from the field is expected  to  commence  mid 2008 with our
share averaging approximately 9,000 boe/d for the year. We hold an 80% operated
working interest here.

During  the  quarter,   production  commenced  from  our  Duart  field  located
approximately  100 miles  northeast  of  Aberdeen.  We have a 50%  non-operated
interest here and production is currently  ramping up to expected peak rates of
approximately 3,000 bbls/d, our share.

US - GULF OF MEXICO
Production  commenced at Wrigley on  Mississippi  Canyon Block 506 early in the
third quarter.  Based on production  tests,  Wrigley is capable of producing at
approximately 60 mmcf/d (30 mmcf/d net to us). However,  limited heat exchanger
capability on the third party  processing  facility has restricted our rates to
approximately  40 mmcf/d (20 mmcf/d net to us).  Once  rectified,  we expect to
deliver at full  capacity  rates in 2008. We have a 50%  non-operated  interest
here.

At Longhorn,  located on  Mississippi  Canyon Blocks 546 and 502, we drilled an
appraisal well during the quarter and  encountered  hydrocarbons.  The original
Longhorn  discovery  well was  drilled  in 2006.  Development  of the  Longhorn
discovery,  which would include subsea  tie-backs to an existing  platform,  is
expected to be  sanctioned  later this year with first  production  in 2009. We
have a 25% non-operated interest in Longhorn.

We have a 25%  operated  interest in Knotty Head on Green  Canyon Block 512. We
continue to pursue rig  availability  to allow us to spud an appraisal  well by
mid  2008  and we have  also  contracted  a  new-build  drilling  rig  which is
scheduled to arrive in mid 2009.

OFFSHORE WEST AFRICA
The Usan field  development,  located in Nigeria  on  offshore  Block  OPL-222,
continues  to progress  toward  project  sanction.  The  project  will have the
ability to process  an  average  of  180,000  bbls/d of oil during the  initial
production  plateau  period  through a new FPSO,  which  contains  two  million
barrels of storage  capacity.  We expect the Usan  development  to be  formally
sanctioned this year, at which time the major deep-water  facilities  contracts
will be awarded.  We have a 20% interest in exploration and development on this
block.


NEW GROWTH EXPLORATION

During the  quarter,  we  completed  drilling our  Vicksburg  exploration  well
located on De Soto Canyon Block 353 in the Eastern  Gulf.  The well was drilled
to a depth of approximately 25,400 feet and encountered hydrocarbons.  The well
was sidetracked and core was recovered. We are still completing our analysis of
the data and core samples and early  indications are encouraging.  We expect to
announce more information in the next quarter once our analysis is complete and
future plans have been determined.  We have a 25% non-operated working interest
in the block.

To ensure we can  continue  to  execute  our  deep-water  growth  strategy,  we
recently contracted a second new-build fifth generation  dynamically positioned
semi-submersible  drilling rig which is scheduled for delivery in 2010. The rig
contract is for two years with day rates totaling $340 million and provides for
two optional one year extensions.  This rig, together with the rig scheduled to
arrive in mid 2009,  is capable of  drilling  to depths of 35,000 feet in 8,500
feet of water.

We were  recently  named the high bidder on 30  offshore  blocks in the Central
Gulf of Mexico Outer Continental Shelf Lease Sale 205 for a total investment of
US$113  million  net to us.  These  awards are  subject to the  approval of the
Minerals Management Service section of the US Department of the Interior.

Elsewhere in the North Sea, we completed an appraisal well at Selkirk. The well
confirmed  commercial   quantities  of  hydrocarbons  and  is  currently  being
sidetracked.  We have a 38% operated  working  interest  here. In addition,  we
continue to evaluate development options for our Golden Eagle discovery. Before
year end, we plan to drill appraisal  wells at Bugle and Kildare,  and spud one
exploration well.

                                      28
<PAGE>

CANADA - BRITISH COLUMBIA SHALE GAS
We have secured a material  land position in northeast  British  Columbia on an
emerging  Devonian shale gas play,  which has the potential to be a significant
shale gas play in  Canada.  Last  winter, we  drilled  and  cored two  vertical
exploration wells which will be completed and tested this winter.  With success
at recent land sales, we currently have approximately 123,000 acres with a 100%
working interest on the play, making us a significant player in the area.


CORE ASSET DEVELOPMENT

At Buzzard,  daily  production  volumes  continued to increase and  contributed
76,000 boe/d to our third quarter  volumes.  Production has regularly  exceeded
facility design rates and we continue to look for debottlenecking opportunities
to  increase  the  processing  capacity  of the  platform.  We  currently  have
sufficient well  deliverability  to take advantage of additional  capacity that
may be available.

In  September,  Buzzard was producing at rates as high as 220,000 boe/d (95,000
boe/d,  net to us).  However,  as a result  of a  damaged  pipe in the acid gas
removal system,  Buzzard  production has averaged  approximately  175,000 boe/d
(76,000 boe/d net to us) so far this month.  The damaged pipe has been repaired
and rates are currently ramping back up to approximately  220,000 boe/d (95,000
boe/d, net to us).

As we continue to develop the field,  we are acquiring  additional  information
regarding  hydrogen  sulphide in the  reservoir.  We are confident  that we can
maintain   deliverability   through  existing  equipment  and  processes  until
additional  equipment is brought on stream in 2010. We have recently  submitted
an  environmental   impact  assessment  for  an  additional  hydrogen  sulphide
treatment  facility.  The proposed  facilities  comprise a fourth platform with
production sweetening  capabilities.  We plan to sanction this project early in
2008.  Our  preliminary   analysis  indicates  additional  capital  of  between
approximately $350 million and $400 million net to us for the facilities.

At Aspen,  we began  producing from an additional  development  well in August.
Current production from this well is averaging approximately 2,100 boe/d and we
are  reviewing the well  completion  to determine if  mechanical  issues in the
wellbore are  limiting  production  volumes.  We have a 100%  operated  working
interest at Aspen.


                                      29
<PAGE>

<TABLE>
<CAPTION>
FINANCIAL RESULTS

CHANGE IN NET INCOME

                                                                                            2007 VS. 2006
                                                                                 Three Months           Nine Months
(Cdn$ millions)                                                                Ended September 30    Ended September 30
-------------------------------------------------------------------------------------------------------------------------
<S>                                                                            <C>                   <C>
NET INCOME AT SEPTEMBER 30, 2006                                                              199                   524
                                                                              ===========================================
    Favourable (unfavourable) variances:

       Production Volumes, After Royalties
         Crude Oil                                                                            462                 1,055
         Natural Gas                                                                            5                   (31)
         Change in Crude Oil Inventory                                                        (41)                  (39)
                                                                              -------------------------------------------
           Total Volume Variance                                                              426                   985

       Realized Commodity Prices
         Crude Oil                                                                             30                   (17)
         Natural Gas                                                                          (12)                  (15)
                                                                              -------------------------------------------
           Total Price Variance                                                                18                   (32)

       Oil and Gas Operating Expense
         Conventional                                                                         (44)                 (134)
         Syncrude                                                                             (11)                  (12)
                                                                              -------------------------------------------
           Total Operating Expense Variance                                                   (55)                 (146)

       Depreciation, Depletion, Amortization and Impairment
         Oil & Gas and Syncrude                                                              (103)                 (268)
         Other                                                                                 (2)                   (5)
                                                                              -------------------------------------------
           Total Depreciation, Depletion, Amortization and Impairment Variance               (105)                 (273)

       Exploration Expense                                                                     15                    10

       Energy Marketing                                                                       (48)                 (236)

       Chemicals                                                                               16                    21

       General and Administrative Expense                                                      44                   132

       Interest Expense                                                                       (25)                  (99)

       Current Income Taxes                                                                   (24)                   10
       Future Income Taxes                                                                   (126)                   (4)

       Other
         Decrease in Fair Value of Crude Oil Put Options                                       (6)                  (25)
         Business Interruption Insurance Proceeds                                             (50)                 (124)
         Block 51 Arbitration                                                                 134                   134
         Other                                                                                (10)                   15
                                                                              -------------------------------------------

NET INCOME AT SEPTEMBER 30, 2007                                                              403                   892
                                                                              ===========================================
</TABLE>

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

                                      30
<PAGE>

<TABLE>
<CAPTION>
OIL & GAS AND SYNCRUDE

PRODUCTION (BEFORE ROYALTIES) (1)

                                                               Three Months             Nine Months
                                                            Ended September 30      Ended September 30
                                                              2007        2006         2007       2006
-------------------------------------------------------------------------------------------------------
<S>                                                           <C>         <C>          <C>        <C>
Crude Oil and NGLs (mbbls/d)
    Yemen                                                     69.8        90.5         73.3       96.0
    Canada                                                    17.0        19.2         17.3       20.7
    United States                                             14.2        16.7         17.3       17.9
    United Kingdom                                            90.0        12.8         77.2       15.2
    Other Countries                                            6.5         6.7          6.2        6.4
Syncrude (2)                                                  25.2        20.5         21.9       17.6
                                                           --------------------------------------------
                                                             222.7       166.4        213.2      173.8
                                                           --------------------------------------------
Natural Gas (mmcf/d)
    Canada                                                     111         106          115        105
    United States                                               98         105           95        111
    United Kingdom                                              18          11           15         22
                                                           --------------------------------------------
                                                               227         222          225        238
                                                           --------------------------------------------

Total (mboe/d)                                                 261         203          251        213
                                                           ============================================

PRODUCTION (AFTER ROYALTIES)

                                                               Three Months             Nine Months
                                                            Ended September 30      Ended September 30
                                                              2007        2006         2007       2006
-------------------------------------------------------------------------------------------------------
Crude Oil and NGLs (mbbls/d)
    Yemen                                                     39.0        49.5         41.8       51.8
    Canada                                                    12.9        14.6         13.5       16.2
    United States                                             12.5        14.6         15.3       15.7
    United Kingdom                                            90.0        12.8         77.2       15.2
    Other Countries                                            6.0         6.2          5.7        5.8
Syncrude (2)                                                  21.1        18.2         18.8       15.8
                                                           --------------------------------------------
                                                             181.5       115.9        172.3      120.5
                                                           --------------------------------------------

Natural Gas (mmcf/d)
    Canada                                                      94          90           96         89
    United States                                               83          89           81         94
    United Kingdom                                              18          11           15         22
                                                           --------------------------------------------
                                                               195         190          192        205
                                                           --------------------------------------------

Total (mboe/d)                                                 214         148          204        155
                                                           ============================================
</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)  Considered a mining operation for US reporting purposes.


                                      31
<PAGE>

HIGHER PRODUCTION INCREASED NET INCOME FOR THE QUARTER BY $426 MILLION
Production after royalties increased 3% from the prior quarter and 45% from the
third  quarter  of  2006  reflecting  the  successful  ramp  up of our  Buzzard
development in the UK North Sea.  Production before royalties increased 3% from
the previous quarter and 29% from the third quarter of 2006.

<TABLE>
<CAPTION>
The following table summarizes our production volume changes:

                                                              Period from      |        Period from
                                                             June 30, 2007     |     September 30, 2006
                                                         ----------------------|------------------------
                                                            Before       After |     Before       After
(mboe/d)                                                 Royalties   Royalties |  Royalties   Royalties
-------------------------------------------------------------------------------|------------------------
<S>                                                         <C>          <C>         <C>          <C>
Production, prior quarter                                      253         208 |        203         148
    Production changes:                                                        |
      United Kingdom                                             5           5 |         78          78
      Yemen                                                     (3)         (3)|        (20)        (11)
      United States                                              -           - |         (4)         (3)
      Canada                                                     -           - |         (1)         (1)
      Syncrude                                                   6           4 |          5           3
                                                         ----------------------|------------------------
Production, third quarter 2007                                 261         214 |        261         214
                                                         ======================|========================
</TABLE>

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

YEMEN
Production  from the Masila field  decreased 5% from the prior  quarter and 19%
from the third  quarter of 2006.  Production  declines  at Masila  reflect  the
maturity  of the field and the impact of a reduced  2007  development  drilling
program.  We have drilled 12 development wells and eight sidetrack wells on the
Masila block to date this year.  We plan to drill five  additional  development
wells and five sidetrack  wells in the fourth quarter of 2007. Base declines at
Masila are expected to continue as most of the development  opportunities  were
drilled in prior years to maximize  recovery of the  remaining  reserves on the
block and to maximize economic returns.

Block 51 production  decreased 5% from the prior quarter and 34% from the third
quarter  of 2006 as a result of  natural  declines.  We have  drilled  10 of 13
planned development wells to date this year and plan to further develop the BAK
A field in the fourth  quarter.  We are also  de-bottlenecking  the  production
facilities  to  handle  additional  water,  as well  as  optimizing  wells  and
expanding  power  facilities,  which are  expected to be completed in the first
quarter of 2008.

CANADA
Production  in Canada was 3% lower than the previous  quarter and 4% lower than
the  third  quarter  of  2006  primarily  due to  the  extensive  Balzac  plant
turnaround  during the quarter.  Our capital  investment  programs  continue to
partially offset natural declines at our heavy oil properties.  Declines in our
natural gas properties in the Medicine Hat region have been more than offset by
our capital  investments in infill drilling and well  optimization  activities.
CBM production  continues to increase as our wells in the Fort Assiniboine area
de-water and we bring additional development wells and facilities on stream.

UNITED STATES
Production  in the Gulf of Mexico  was  consistent  with the prior  quarter  as
equipment  maintenance  downtime  and  natural  field  declines  were offset by
improved  performance.  At Aspen,  production for the quarter was approximately
2,100 boe/d  lower than the second  quarter  due to  downtime  and  performance
issues.   Processing   facilities   for  our  Aspen  field  were  shut  in  for
approximately 14 days due to weather and hurricanes in the Gulf. We completed a
sidetrack  well at Aspen to exploit a deeper sand during the  quarter.  Current
production  from this well is  averaging  approximately  2,100 boe/d and we are
reviewing the well completion to determine if mechanical issues in the wellbore
are limiting production volumes.

Our Wrigley  development  commenced  production  in early July but limited heat
exchanger  capability on the  third-party  processing  facility has  restricted
production.  Wrigley  contributed  8  mmcf/d  for  the  quarter  and we  expect
production to be  approximately  20 mmcf/d,  net to us for the remainder of the
year.

Gunnison  production  decreased  13% from the  prior  quarter  and 40% from the
previous  year due to natural  declines  and  mechanical  problems  in one high
volume well.  This was offset by successful  sidetracks at Vermillion 340 where
production rates have been better than anticipated. Production on the shelf was
also higher than the third quarter last year as fields shut in by hurricanes in
2005 came back on stream in the fourth quarter of 2006.

Late  in  the  quarter,  we  acquired  three  deep-water  properties  producing
approximately  3,500 boe/d. We plan to drill a development well on one of these
properties in the fourth quarter.

                                      32
<PAGE>

UNITED  KINGDOM
Buzzard  production for the quarter averaged 177,000 boe/d (76,000 boe/d net to
us), an increase of 12% from the prior quarter. Third-party processing facility
maintenance  and pipeline  restrictions,  combined with acid gas removal system
delays,  prevented  us  from  operating  at  peak  rates  during  the  quarter.
Production has regularly exceeded facility design rates and we continue to look
for  debottlenecking  opportunities to increase the processing  capacity of the
platform.

In  September,  Buzzard was producing at rates as high as 220,000 boe/d (95,000
boe/d,  net to us).  However,  as a result  of a  damaged  pipe in the acid gas
removal system,  Buzzard  production has averaged  approximately  175,000 boe/d
(76,000 boe/d net to us) so far this month.  The damaged pipe has been repaired
and rates are currently ramping back up to approximately  220,000 boe/d (95,000
boe/d, net to us).

Production  from the  Scott/Telford  fields  was  2,000  boe/d  lower  than the
previous  quarter due to natural  declines and downtime  related to maintenance
and workover activity.  The non-operated Farragon field produced  approximately
1,500 boe/d  during the quarter,  lower than normal as a result of  maintenance
activities on the platform. Production from Duart began late in the quarter and
is currently  ramping up to expected peak rates of approximately  3,000 bbls/d,
our share.

OTHER COUNTRIES
Production  from our Guando field in Colombia  averaged 6,500 bbls/d during the
quarter, 5% above the prior quarter. We began a 35 well infill drilling program
earlier in the year and  completed 11 wells  during the quarter.  At the end of
the third quarter, 23 wells of the program were on stream.

SYNCRUDE
Syncrude production  increased 33% from the prior quarter when we experienced a
reduction in production due to downtime caused by an extended turnaround on the
LC Finer and the Coker 8-3 turnaround.  Production is 23% higher than the third
quarter  of  2006,  primarily  from  new  production  related  to the  Stage  3
expansion.  In early October, Coker 8-3 was shut in due to coke build up and is
expected to return to full production by late October.


                                      33
<PAGE>

<TABLE>
<CAPTION>
COMMODITY PRICES

                                                                    Three Months              Nine Months
                                                                 Ended September 30       Ended September 30
                                                                   2007        2006         2007        2006
-------------------------------------------------------------------------------------------------------------
<S>                                                               <C>         <C>          <C>         <C>
CRUDE OIL AND NGLS
    West Texas Intermediate (WTI) (US$/bbl)                       75.38       70.48        66.19       68.22
                                                                ---------------------------------------------

    Differentials (1) (US$/bbl)
      Heavy Oil                                                   23.04       19.17        19.87       21.98
      Mars                                                         5.83        7.61         4.58        7.49
      Masila                                                       0.66        2.96        (0.22)       3.14
      Dated Brent                                                  0.51        0.99        (0.94)       1.26

    Producing Assets (Cdn$/bbl)
      Yemen                                                       78.27       76.08        72.65       73.58
      Canada                                                      46.76       52.95        43.43       44.37
      United States                                               74.43       70.23        65.90       67.92
      United Kingdom                                              78.06       77.73        73.08       73.02
      Other Countries                                             76.29       74.05        68.42       67.96
      Syncrude                                                    82.09       77.53        76.77       76.08

    Corporate Average (Cdn$/bbl)                                  75.86       73.06        70.17       69.57
                                                                ---------------------------------------------

NATURAL GAS
    New York Mercantile Exchange (NYMEX) (US$/mmbtu)               6.24        6.14         7.02        6.89
    AECO (Cdn$/GJ)                                                 5.32        5.72         6.46        6.82
                                                                ---------------------------------------------

    Producing Assets (Cdn$/mcf)
      Canada                                                       5.17        5.78         6.48        6.54
      United States                                                6.75        7.18         8.03        7.96
      United Kingdom                                               4.99        5.57         4.13        7.88

    Corporate Average (Cdn$/mcf)                                   5.80        6.39         6.95        7.29
                                                                ---------------------------------------------

NEXEN'S AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe)             69.82       66.82        65.96       64.83
                                                                ---------------------------------------------

AVERAGE FOREIGN EXCHANGE RATE
    Canadian to US Dollar                                        0.9573      0.8920       0.9052      0.8829
                                                                ---------------------------------------------
</TABLE>
(1)  These differentials are a discount/(premium) to WTI.

HIGHER REALIZED COMMODITY PRICES INCREASED QUARTERLY NET INCOME BY $18 MILLION
WTI continued to increase in the third quarter,  gaining 16% from last quarter.
Approximately  80% of our production is priced based on Brent,  which increased
9% in the same  period.  These  increases  were  muted as the  Canadian  dollar
strengthened  5% relative to the US dollar since the end of June.  As a result,
our realized oil price in Canadian dollars increased 5% from the second quarter
to average  $75.86/bbl.  Our realized gas price decreased 23% from the previous
quarter to average $5.80/mcf, compared with a 19% decrease in NYMEX in the same
period.

The weaker US dollar reduced  reported net sales by  approximately  $98 million
and reduced  our  realized  crude oil and  natural gas prices by  approximately
$5.59/bbl and $0.43/mcf, respectively as compared to the previous quarter.

CRUDE OIL REFERENCE PRICES
Crude  oil  prices  were  strong   during  the  quarter,   with  WTI  averaging
US$75.38/bbl.  WTI peaked in September at a record high of US$83.90/bbl  before
closing at  US$81.66/bbl  at the end of the quarter.  Prices have  continued to
reach new  highs  into  October.  Strong  crude  fundamentals  in the  physical
markets,  including declining inventory levels,  contributed to the increase in
spot prices.

Global crude oil demand continued to be strong in the third quarter.  Demand in
China,  the  world's  second  largest oil  consumer,  India and the Middle East
continued  to grow  from last  year.  In the US,  strong  demand  and  refinery
problems  mid-continent  resulted in a 10 million barrel  decrease in crude oil
inventories at Cushing.  North American  refinery outages  increased the demand
for light sweet crude as a result of not being able to process  heavier  crude.
In response to strong crude demand,  declining  inventories and anemic Non-OPEC
supply growth, OPEC announced that it would raise oil output by 500,000 barrels
per day, effective November 1, 2007.

                                      34
<PAGE>

In addition to strong market fundamentals, a weakening US dollar and continuing
geopolitical risk placed upward pressure on crude oil prices. Supply outages in
Nigeria,  Africa's  largest oil  producer,  continued to reduce  production  by
approximately  25% of the  country's  capacity.  In the Middle  East,  on-going
tensions between the US and Iran over its uranium enrichment program,  and more
recently,  potential  conflict  between  Turkey and Kurdish  rebels in Northern
Iraq, continued to add to geopolitical instability.

CRUDE OIL DIFFERENTIALS
In Canada, heavy crude oil differentials averaged US$23.04/bbl (31% of WTI) for
the quarter,  compared to  US$19.17/bbl  (27% of WTI) for the third  quarter of
2006.  Heavy oil  differentials  widened due to weak demand for Canadian  heavy
crude after the summer asphalt  season and the increased  strength of crude oil
reference prices.

The Brent/WTI  differential narrowed with Brent trading at a discount to WTI of
US$0.51/bbl during the quarter,  compared to US$0.99/bbl for the same period in
2006.  The Brent index is relevant for us as  approximately  80% of our current
crude  production  is  priced  based  on  Brent.  The  Brent/WTI   differential
fluctuated  during the quarter.  In July,  the North Sea benchmark  traded at a
large  premium over WTI due to strong Asian  demand and  significant  North Sea
production turnarounds which reduced supply. However, WTI regained its strength
and traded at a premium to Brent in August reflecting more normal differentials
for the summer  months  given the  increased  demand for WTI as a result of the
summer driving season.  Inventory  drawdowns at Cushing were also supportive of
WTI prices.

On the US Gulf  Coast,  the Mars  differential  narrowed  during  the  quarter,
averaging  US$5.83/bbl (8% of WTI) compared to US$7.61/bbl  (11% of WTI) in the
third  quarter of 2006.  The Mars  differential  tightened  in response to OPEC
production  cuts from late last year,  which saw OPEC reduce its supply of sour
crude.

The Yemen  Masila  differential  narrowed  substantially  relative  to WTI with
Masila  trading at a discount of US$0.66/bbl  compared to  US$2.96/bbl  for the
same period in 2006.  Strong crude  demand in Asia has been the primary  driver
for the strengthening of Masila crude.

NATURAL GAS REFERENCE PRICES
NYMEX natural gas prices averaged US$6.24/mmbtu for the quarter,  comparable to
the price for the same  period in 2006 of  US$6.14/mmbtu.  Natural  gas  prices
softened during the quarter as gas storage levels approached record levels. The
key drivers behind the large storage  position  include mild summer weather and
an increase in liquefied natural gas (LNG) imports.  The mild weather created a
lack of demand for cooling and the relatively quiet hurricane season brought no
major supply disruptions to the Gulf of Mexico. In addition,  when European gas
prices  declined in April from mild weather,  a  significant  amount of LNG was
diverted to the US market contributing to the ample supply situation.

<TABLE>
<CAPTION>
OPERATING COSTS

                                                                       Three Months             Nine Months
                                                                    Ended September 30      Ended September 30
(Cdn$/boe)                                                             2007       2006         2007       2006
---------------------------------------------------------------------------------------------------------------
<S>                                                                   <C>        <C>          <C>        <C>
Operating costs based on our working interest production before
royalties (1)
     Conventional Oil and Gas                                          7.81       7.25         7.93       6.75
     Synthetic Crude Oil
       Syncrude                                                       22.37      21.69        25.20      28.84
     Average Oil and Gas                                               9.26       8.72         9.44       8.57
                                                                   --------------------------------------------

Operating costs based on our net production after royalties
     Conventional Oil and Gas                                          9.60      10.26         9.84       9.50
     Synthetic Crude Oil
       Syncrude                                                       26.73      24.38        29.31      32.14
     Average Oil and Gas                                              11.34      12.01        11.65      11.81
                                                                   --------------------------------------------
</TABLE>
(1)  Operating  costs per boe are our total oil and gas operating costs divided
     by our working interest  production  before  royalties.  We use production
     before royalties to monitor our performance consistent with other Canadian
     oil and gas companies.

HIGHER OIL AND GAS OPERATING  COSTS DECREASED NET INCOME FOR THE QUARTER BY $55
MILLION
Buzzard in the North Sea and Syncrude  continue to increase their  contribution
to our total  production  in the  quarter,  impacting  our  production  mix and
average  operating cost per boe.  Operating  costs on the Buzzard  platform are
lower  than  our  corporate  average,  reducing  our  consolidated  average  by
$2.10/boe  during the quarter.  On the other hand,  Syncrude's  production from
Stage  3  and  higher  operating  costs  increased  our  corporate  average  by
$0.84/boe.

                                      35
<PAGE>

In Yemen, lower production at Masila and Block 51, together with higher service
rig activity and maintenance programs have increased our corporate unit average
cost by  $0.81/boe.  Our Gulf of Mexico  operating  costs reduced our corporate
average  for the  quarter  by  $0.07/boe  as  lower  maintenance  activity  was
primarily offset by lower volumes.

In Canada,  operating  costs  increased  our  corporate  average by  $1.06/boe.
Turnaround  activity  at our  Balzac  plant,  combined  with  well  maintenance
activity,  increased our operating  costs.  Our average unit operating costs in
Canada are higher from industry cost pressures and by lower production rates on
our  heavy  oil  properties.  Operating  costs  also  increased  as a result of
bringing  additional CBM wells on stream with high initial  operating costs. In
the North Sea, our  Scott/Telford  costs  increased  our  corporate  average by
$0.23/boe during the quarter primarily from maintenance on wells and turbines.

US-dollar  denominated  operating  costs were lower when translated to Canadian
dollars as a result of the  weaker US  dollar.  This  decreased  our  corporate
average by $0.37/boe for the quarter.

Syncrude  operating  costs per barrel have decreased 25% from the prior quarter
due to the  completion  of the  Coker  8-3 and LC  Finer  turnarounds  in June.
Average  operating  costs per boe are 3% higher than the third  quarter of 2006
primarily  as a result of  increased  labour  costs.  The  impact of the higher
Syncrude costs increased our corporate average by $0.09/boe during the quarter.

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

                                                                        Three Months             Nine Months
                                                                     Ended September 30      Ended September 30
(Cdn$/boe)                                                             2007        2006         2007       2006
----------------------------------------------------------------------------------------------------------------
<S>                                                                   <C>         <C>          <C>        <C>
DD&A based on our working interest production before royalties (1)
     Conventional Oil and Gas                                         14.89       12.90        15.12      12.97
     Synthetic Crude Oil
       Syncrude                                                        6.40        4.73         6.59       4.05
     Average Oil and Gas                                              14.05       12.08        14.58      12.24
                                                                    --------------------------------------------

DD&A based on our net production after royalties
     Conventional Oil and Gas                                         18.29       18.25        18.77      18.27
     Synthetic Crude Oil
       Syncrude                                                        7.65        5.32         7.67       4.51
     Average Oil and Gas                                              17.21       16.64        17.74      16.86
                                                                    --------------------------------------------
</TABLE>
(1)  DD&A per boe is our DD&A for oil and gas operations divided by our working
     interest  production before royalties.  We use production before royalties
     to monitor our  performance  consistent  with other  Canadian  oil and gas
     companies.

HIGHER OIL AND GAS DD&A DECREASED NET INCOME FOR THE QUARTER BY $103 MILLION
New volumes  from the Buzzard  development  in the North Sea continue to change
our  production  mix.  Costs  relating to Buzzard are higher than our corporate
average as they  include our  acquisition  cost and the costs to  complete  the
project.  This  increased  our  corporate  average by  $2.23/boe.  Buzzard unit
depletion rates are expected to decrease in the next few years as we anticipate
booking additional proved reserves from production  experience and from further
development  drilling.  DD&A on our other North Sea  properties  decreased  our
corporate average by $0.91/boe.

Lower  capital  expenditures  due to our  reduced  drilling  program  in Yemen,
combined with lower production volumes,  decreased our corporate unit depletion
rate by  $0.82/boe  compared  to the  third  quarter  of 2006.  Despite  higher
realized  oil prices,  lower  production  volumes  have  resulted in the slower
recovery of capital costs we have paid on behalf of the government.

Depletion of our Canadian assets  increased our corporate  average by $0.37/boe
reflecting  the timing of reserve  bookings  from our CBM  projects  in central
Alberta, as well as land acquisitions in 2006. We expect our depletion rate for
our CBM projects to decline as the wells  de-water and we are able to recognize
additional proved reserves.  Our depletion rate in the Gulf of Mexico increased
our corporate average depletion rate by $1.52/boe compared to the third quarter
of 2006 from  additional  development  costs at Aspen and  Eugene  Island,  new
production from Wrigley and from reserve reductions at the end of 2006.

The  strengthening  of the Canadian dollar  decreased our corporate  average by
$0.86/boe  relative  to the third  quarter  of 2006,  as the  depletion  of our
international and US assets is denominated in US dollars.

Syncrude  DD&A  includes  costs to develop the Stage 3  expansion  that came on
stream in mid 2006. The depletion of the expansion  costs increased our average
by $0.42/boe.

                                      36
<PAGE>

<TABLE>
<CAPTION>
EXPLORATION EXPENSE

                                                                 Three Months              Nine Months
                                                              Ended September 30       Ended September 30
                                                                2007        2006        2007         2006
----------------------------------------------------------------------------------------------------------
<S>                                                             <C>         <C>          <C>         <C>
Seismic                                                           19          30          79           77
Unsuccessful Exploration Drilling                                 31          39          85          110
Other                                                             17          13          57           44
                                                             ---------------------------------------------
Total Exploration Expense                                         67          82         221          231
                                                             =============================================

New Growth Exploration                                           170         161         377          445
Geological and Geophysical Costs                                  19          30          79           77
                                                             ---------------------------------------------
Total Exploration Expenditures                                   189         191         456          522
                                                             ---------------------------------------------

                                                             ---------------------------------------------
Exploration Expense as a % of Exploration Expenditures           35%         43%         48%          44%
                                                             =============================================
</TABLE>

LOWER EXPLORATION EXPENSE INCREASED NET INCOME FOR THE QUARTER BY $15 MILLION
Exploration  activity in the third quarter was primarily focused in the Gulf of
Mexico and the UK North Sea.

In the  Gulf of  Mexico,  we  incurred  dry  hole  costs  of $23  million  from
unsuccessful drilling of four wells on the shelf. We are currently drilling two
exploration wells on the shelf. In the deep water, a successful  appraisal well
was drilled at Longhorn and we are currently evaluating our resource estimates.
Also in the deep water, our Vicksburg prospect was drilled to a depth of 25,400
feet and encountered  hydrocarbons.  We are currently  analyzing data from this
well.

In  the UK  North  Sea,  we  expensed  $6  million  of  costs  relating  to the
unsuccessful  Stag exploration  well. At Selkirk located on Block 22/22b in the
North Sea, we successfully  completed an appraisal well during the quarter. The
well confirmed  commercial  quantities of  hydrocarbons  and is currently being
sidetracked. Additional appraisal wells at Bugle and Kildare and an exploration
well.

We acquired  seismic  data in the Gulf of Mexico and offshore  Norway.  Seismic
investment  was lower  during the quarter as  compared to the third  quarter of
2006.  During the fourth  quarter,  we expect to drill two appraisal  wells and
three exploration wells in the Gulf of Mexico and UK North Sea.


                                      37
<PAGE>

<TABLE>
<CAPTION>
ENERGY MARKETING

                                                                 Three Months              Nine Months
                                                              Ended September 30       Ended September 30
                                                                2007        2006         2007        2006
----------------------------------------------------------------------------------------------------------
<S>                                                           <C>          <C>         <C>         <C>
    Physical Sales (1)                                        11,579       9,264       33,980      28,705
    Physical Purchases (1)                                   (11,424)     (9,054)     (33,308)    (27,943)
    Net Financial Transactions (1)                                64          19           78         197
                                                            ----------------------------------------------
Net Revenue                                                      219         229          750         959
    Transportation Expense                                      (211)       (173)        (620)       (591)
    Other                                                          6           6           10           8
                                                            ----------------------------------------------
NET MARKETING REVENUE                                             14          62          140         376
                                                            ==============================================

CONTRIBUTION TO NET MARKETING REVENUE BY PRODUCT TYPE:
    North American Natural Gas                                    32          29          106         287
    Global Crude Oil                                             (16)         34           (2)         79
    North American Power                                           3           3           11           9
    Other                                                         (5)         (4)          25           1
                                                            ----------------------------------------------
NET MARKETING REVENUE                                             14          62          140         376
    General and Administrative                                   (15)        (18)         (68)        (93)
                                                            ----------------------------------------------
NET MARKETING REVENUE AFTER GENERAL AND ADMINISTRATIVE            (1)         44           72         283
    Depreciation, Depletion, Amortization and Impairment          (3)         (2)         (10)         (6)
                                                            ----------------------------------------------
MARKETING CONTRIBUTION TO INCOME BEFORE INCOME TAXES              (4)         42           62         277
                                                            ==============================================

PHYSICAL SALES VOLUMES (2)
    North American Natural Gas (bcf/d)                           6.1         5.3          5.5         5.4
    Global Crude Oil (mbbls/d)                                   803         712          827         654
    North American Power (MW/d)                                4,494       4,582        4,436       4,361

VALUE-AT-RISK
    Quarter-end                                                   34          20           34          20
    High                                                          38          27           38          27
    Low                                                           28          19           24          17
    Average                                                       33          23           31          21
                                                            ----------------------------------------------
</TABLE>
(1)  Marketing's   physical  sales,   physical   purchases  and  net  financial
     transactions are reported net on the Unaudited  Consolidated  Statement of
     Income as marketing and other.
(2)  Excludes intra-segment transactions.

LOWER NET MARKETING REVENUE DECREASED NET INCOME BY $48 MILLION
Results  from our  marketing  group were lower than the same  quarter last year
primarily as a result of reduced  contributions from our global crude oil team.
A significant  change in the structure of the WTI forward curve  contributed to
the shortfall. In addition,  decreases in natural gas prices during the quarter
resulted  in an  impairment  of $32 million on our  natural  gas  inventory  in
storage as we are required to carry our inventories at the lower of cost or net
realizable value.

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

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

                                      38
<PAGE>

<TABLE>
<CAPTION>
COMPOSITION OF NET MARKETING REVENUE
                                                                           Three Months              Nine Months
                                                                        Ended September 30       Ended September 30
                                                                          2007        2006         2007        2006
--------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>         <C>          <C>         <C>
Trading Activities                                                           6          58         127          367
Non-Trading Activities                                                       8           4          13            9
                                                                    ------------------------------------------------
                                                                            14          62         140          376
                                                                    ================================================
</TABLE>

TRADING ACTIVITIES

In  marketing,  we enter into  contracts to purchase and sell energy  products,
primarily for crude oil and natural gas. We also use  financial and  derivative
contracts,  including  futures,  forwards,  swaps and  options  for hedging and
trading  purposes.  We account for all  derivative  contracts not designated as
hedges for accounting purposes using  mark-to-market  accounting and record the
net gain or loss from their revaluation in marketing and other income. The fair
value of these  instruments  is included with  accounts  receivable or payable.
They are  classified  as long-term  or  short-term  based on their  anticipated
settlement date.

We value  derivative  trading  contracts daily using:

     o    actively quoted markets such as the New York Mercantile  Exchange and
          the International Petroleum Exchange; and

     o    other external sources such as the Natural Gas Exchange,  independent
          price publications and over-the-counter broker quotes.

FAIR VALUE OF DERIVATIVE CONTRACTS

At September 30, 2007, the fair value of our derivative contracts totalled $138
million.  Below is a  breakdown  of this fair  value by  valuation  method  and
contract maturity.

<TABLE>
                                                                               MATURITY
---------------------------------------------------------------------------------------------------------------------
                                                    less than                                 more than
                                                       1 year     1-3 years     4-5 years       5 years       Total
                                                   ------------------------------------------------------------------
<S>                                                 <C>           <C>           <C>           <C>             <C>
Prices
    Actively Quoted Markets                               (62)           52            (1)            -         (11)
    From Other External Sources                           123            11            21            (6)        149
    Based on Models and Other Valuation Methods             -             -             -             -           -
                                                   ------------------------------------------------------------------
Total                                                      61            63            20            (6)        138
                                                   ==================================================================
</TABLE>

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

                                                                                                              Total
---------------------------------------------------------------------------------------------------------------------
<S>                                                                                                           <C>
Fair Value at December 31, 2006                                                                                 360
    Change in Fair Value of Contracts                                                                            50
    Net Losses (Gains) on Contracts Closed                                                                     (272)
    Changes in Valuation Techniques and Assumptions (1)                                                           -
                                                                                                            ---------
Fair Value at September 30, 2007                                                                                138
                                                                                                            =========
</TABLE>
(1) Our valuation methodology has been applied consistently in each period.

The fair values of our  derivative  contracts will be realized over time as the
contracts  settle.  Until then,  the value of certain  contracts will vary with
forward  commodity prices and price  differentials.  While forward prices vary,
the value of the  contracts  only  varies to the extent  they are  economically
exposed  or  unprotected.  The  average  term of our  derivative  contracts  is
approximately  1.5 years.  Those maturing  beyond one year primarily  relate to
North American natural gas positions.


NON-TRADING ACTIVITIES

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

                                      39
<PAGE>

CHEMICALS

HIGHER CHEMICALS CONTRIBUTION INCREASED NET INCOME BY $16 MILLION
Volumes  increased  from  the  prior  quarter  when  Canexus  experienced  some
unplanned plant outages. Strength in North American sodium chlorate prices were
partially eroded by the strengthening Canadian dollar. Our operations in Brazil
remain  strong as a result of  continued  demand from  Aracruz  Cellulose,  our
primary customer in Brazil.

Chemical's third quarter income includes  unrealized  foreign exchange gains of
$11 million on Canexus  US-dollar  denominated debt and a $2 million fair value
increase in derivative contracts.

<TABLE>
<CAPTION>
CORPORATE EXPENSES

GENERAL AND ADMINISTRATIVE (G&A)

                                                                          Three Months              Nine Months
                                                                       Ended September 30       Ended September 30
                                                                         2007        2006        2007         2006
-------------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>         <C>          <C>         <C>
General and Administrative Expense before Stock-Based Compensation         84          74         263          246
Stock-Based Compensation (1)                                              (77)        (23)        (16)         133
                                                                      ---------------------------------------------
Total General and Administrative Expense                                    7          51         247          379
                                                                      =============================================
</TABLE>
(1)  Includes the tandem option plan, stock options for our US-based  employees
     and stock appreciation rights.

LOWER COSTS INCREASED QUARTERLY NET INCOME BY $44 MILLION
Changes in our share price  create  volatility  in our net income as we account
for  stock-based  compensation  using the  intrinsic-value  method.  During the
quarter,  we recorded a recovery  of  stock-based  compensation  expense as our
share price has declined since the end of the prior  quarter.  Cash payments to
employees for our stock-based compensation programs were $29 million during the
third quarter and $116 million year-to-date.

Reduced  performance  by our marketing  group relative to last year lowered our
accrual for results-based  compensation programs. This was offset by additional
employee   costs  as  we  continue  to  expand  our  oil  and  gas   operations
internationally  and  expand  our  marketing  operations  in  Europe  and North
America.

<TABLE>
<CAPTION>
INTEREST AND FINANCING COSTS
                                                                          Three Months              Nine Months
                                                                       Ended September 30       Ended September 30
                                                                         2007        2006        2007         2006
-------------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>         <C>          <C>         <C>
Interest                                                                   85          77         258          214
    Less: Capitalized Interest                                            (45)        (62)       (124)        (179)
                                                                      ---------------------------------------------
Net Interest Expense                                                       40          15         134           35
                                                                      =============================================
</TABLE>

HIGHER INTEREST EXPENSE DECREASED QUARTERLY NET INCOME BY $25 MILLION
Our financing  costs increased $18 million from the third quarter of 2006 as we
funded capital  requirements  for  investments of our Long Lake project and the
Ettrick  development in the North Sea. The strong  Canadian  dollar relative to
the US dollar reduced our US-dollar  denominated  interest costs by $10 million
and reduced the carrying value of our US-denominated debt by approximately $300
million in the quarter and over $800 million since year end 2006.

We  capitalized  less  interest on our major  development  projects  during the
quarter as we completed the Buzzard and Syncrude  Stage 3 development  projects
in 2006. In 2007, we are capitalizing  interest on our Long Lake development in
the Athabasca oil sands and on our Ettrick project in the North Sea.


                                      40
<PAGE>

<TABLE>
<CAPTION>
INCOME TAXES

                                                           Three Months              Nine Months
                                                        Ended September 30       Ended September 30
                                                          2007        2006         2007        2006
----------------------------------------------------------------------------------------------------
<S>                                                       <C>         <C>          <C>         <C>
Current                                                    136         112          347         357
Future                                                     142          16          303         299
                                                       ---------------------------------------------
Total Provision for Income Taxes                           278         128          650         656
                                                       =============================================

Effective Tax Rate (%)                                      40%         39%          42%         55%
                                                       ---------------------------------------------
</TABLE>

EFFECTIVE TAX RATE INCREASED TO 40%
Current  income taxes  include  cash taxes in Yemen of $65 million  (2006 - $76
million) for the quarter and $174 million (2006 - $224  million)  year-to-date.
Strong  production from Buzzard in the North Sea,  combined with high commodity
prices,  resulted in a current tax provision of $62 million for the quarter and
$134 million  year-to-date in the United Kingdom. Our income tax provision also
includes current taxes in Colombia and the United States.

Our  provision  for future income taxes in the first quarter of 2006 included a
one-time  non-cash  expense of $277 million  related to tax rate changes in the
UK. In early 2006,  the UK government  substantively  enacted  increases to the
supplementary  charge on our North Sea oil and gas activities  from 10% to 20%,
effective   January  1,  2006.   Excluding  the  charge,   our  effective  2006
year-to-date  tax rate was 32%. Our effective tax rate in 2007 is approximately
40%.  We  expect  our  effective  tax rate to  increase  marginally  in 2008 as
production  from  Buzzard  in the UK will  provide a larger  proportion  of our
taxable income.

<TABLE>
<CAPTION>
OTHER

                                                          Three Months              Nine Months
                                                       Ended September 30       Ended September 30
                                                         2007        2006         2007        2006
---------------------------------------------------------------------------------------------------
<S>                                                      <C>         <C>          <C>         <C>
Change in Fair Value of Crude Oil Put Options             (11)         (5)         (31)         (6)
Block 51 Arbitration Accrual                                -         134            -         134
                                                      ---------------------------------------------
</TABLE>

In 2006, we purchased put options on  approximately  105,000 bbls/d of our 2007
crude oil production. These options establish a WTI floor price of US$50/bbl on
these  volumes,  are  settled  annually  and  provide  a base  level  of  price
protection  without limiting our upside to higher prices.  The put options were
purchased for $26 million and are carried at fair value.  At December 31, 2006,
the options had a fair value of $19 million. Strong WTI prices have reduced the
market  value of these  options to nil and we expensed $19 million in the first
half of 2007.

During  the  second  quarter  of 2007,  we  expanded  our cash flow  protection
strategy  into  2008  by  purchasing  put  options  on 36  million  barrels  or
approximately  100,000 bbls/d of our 2008 crude oil  production.  These options
establish an annual Dated Brent floor price of US$50/bbl on these volumes.  The
put options were  purchased  for $24 million and are carried at fair value.  At
September 30, 2007, the options had a fair value of $12 million and we recorded
a loss of $12 million for the change in fair value.

During  2006,  a court of  arbitration  concluded  that we  breached an Area of
Mutual Interest agreement with Occidental Petroleum  Corporation  (Occidental).
As a result,  Occidental was entitled to monetary damages. In the third quarter
of  2006,  we  recorded  an  accrual  of $134  million  for  settlement  of the
arbitration.


                                      41
<PAGE>

<TABLE>
<CAPTION>
LIQUIDITY

CAPITAL STRUCTURE
                                                                     September 30   December 31
                                                                             2007          2006
-------------------------------------------------------------------------------------------------
<S>                                                                  <C>             <c>
NET DEBT (1)
   Bank Debt                                                                  334         1,410
   Public Senior Notes                                                      3,788         2,885
                                                                    -----------------------------
     Senior Debt                                                            4,122         4,295
   Subordinated Debt                                                          443           536
                                                                    -----------------------------
     Total Debt                                                             4,565         4,831
   Less: Cash and Cash Equivalents                                           (172)         (101)
                                                                    -----------------------------
TOTAL NET DEBT                                                              4,393         4,730
                                                                    =============================

SHAREHOLDERS' EQUITY (2)                                                    5,415         4,636
                                                                    =============================
</TABLE>
(1)  Includes  all  of our  debt  and  is  calculated  as  long-term  debt  and
     short-term borrowings less cash and cash equivalents.
(2)  At September  30, 2007,  there were  527,429,968  common shares and US$460
     million  of   unsecured   subordinated   securities   outstanding.   These
     subordinated  securities  may be redeemed by issuing  common shares at our
     option after  November 8, 2008. The number of shares  issuable  depends on
     the common share price on the redemption date.

During the third quarter, we repaid our $150 million medium-term notes.


NET DEBT

Our net debt levels are directly  related to our  operating  cash flows and our
capital expenditure  activities.  Changes in net debt for the first nine months
of 2007 are related to:

<TABLE>
-------------------------------------------------------------------------------------------------
<S>                                                                                      <C>
Capital Investment                                                                        2,531
Cash Flow from Operating Activities                                                      (2,127)
                                                                                    -------------
   Excess of Capital Investment over Cash Flow                                              404

Dividends on Common Shares                                                                   39
Issue of Common Shares and Exercises of Stock Options                                       (44)
Foreign Exchange Translation of US-dollar Debt and Cash                                    (725)
Other                                                                                       (11)
                                                                                    -------------
Decrease in Net Debt                                                                       (337)
                                                                                    =============
</TABLE>

<TABLE>
<CAPTION>
CHANGE IN WORKING CAPITAL

                                                       September 30    December 31      Increase/
                                                               2007           2006     (Decrease)
--------------------------------------------------------------------------------------------------
<S>                                                            <C>            <C>       <C>
Cash and Cash Equivalents                                       172            101            71
Restricted Cash                                                 176            197           (21)
Accounts Receivable                                           2,683          2,951          (268)
Inventories and Supplies                                        628            786          (158)
Future Income Tax Assets                                         73            479          (406)
Accounts Payable and Accrued Liabilities                     (3,408)        (3,879)          471
Other                                                            (3)            (1)           (2)
                                                       -------------------------------------------
Net Working Capital                                             321            634          (313)
                                                       ===========================================
</TABLE>

Accounts  receivable  were  lower  than  year  end as  gains  from  2006 on our
marketing  derivative contracts were realized during the first quarter of 2007,
partially  offset  by  increases  in  our  oil  and  gas  production  accruals.
Inventories in our marketing  group were lower from year end as we sold natural
gas and crude oil  inventory to take  advantage of trading  opportunities.  Our
accrued  liabilities  decreased from the end of 2006 as we settled the Block 51
arbitration  early in 2007.  Lower  accruals for our  stock-based  compensation
obligations  also  reduced  accounts  payable  and  accrued  liabilities.   The
strengthening  of the Canadian dollar relative to the US dollar impacted our US
dollar  denominated  working  capital  by  reducing  our  accounts  receivable,
inventories  and accounts  payable $229 million,  $79 million and $232 million,
respectively.

                                      42
<PAGE>

OUTLOOK FOR REMAINDER OF 2007
Our production  has increased  since the beginning of the year and we expect to
show continued growth in the fourth quarter. We expect to generate $3.3 to $3.6
billion  in cash  flow  (before  remediation  and  geological  and  geophysical
expenditures) in 2007, assuming the following for the remainder of the year:

-------------------------------------------------------------------------------
WTI (US$/bbl)                                                            70.00
Brent (US$/bbl)                                                          70.00
NYMEX natural gas (US$/mmbtu)                                             6.50
US to Canadian dollar exchange rate                                       0.95
                                                                     ----------

To date,  we have incurred  almost 70% of our planned 2007 capital  investment.
Our 2007 capital  program is largely  focused on bringing  Long Lake on stream,
advancing the Ettrick  development in the North Sea towards  completion in 2008
and  investing  in our core asset  developments.  In  addition,  we continue to
invest in building and assessing our  exploration  opportunities  in our growth
areas.

Our future  liquidity is primarily  dependent on cash flows  generated from our
operations, existing committed credit facilities and our ability to access debt
and equity  markets.  At  September  30,  2007,  we had  committed  term credit
facilities  of $3.1 billion that are  available  until 2012.  At the end of the
quarter,  $146 million was drawn on these  facilities and we also utilized $346
million of these  facilities  to  support  outstanding  letters  of credit.  At
September  30,  2007,  we had $630 million of undrawn,  uncommitted,  unsecured
credit  facilities  available,  of which $106  million was  utilized to support
outstanding letters of credit.

In the third quarter, we declared common share dividends of $0.025 per share.

CONTRACTUAL OBLIGATIONS, COMMITMENTS AND GUARANTEES
We have assumed various  contractual  obligations and commitments in the normal
course of our  operations  and financing  activities.  We have  included  these
obligations and commitments in our MD&A in our 2006 Annual Report on Form 10-K.
In 2007, we entered into work commitments  related to three drilling rigs which
have been  contracted  to work for us in the North Sea and the Gulf of  Mexico,
totaling  $549  million  over the next five years.  In  addition,  we have been
identified  as high bidder on 30 offshore  blocks at a recent lease sale in the
Gulf of Mexico.  Our  commitment  on the lease sale is $113  million,  which is
subject  to  approval  by US  government  agencies.  There  have  been no other
significant developments since year end.


CONTINGENCIES

There are a number of lawsuits  and claims  pending,  the  ultimate  results of
which cannot be  ascertained at this time. We record costs as they are incurred
or become  determinable.  We believe the  resolution of these matters would not
have a  material  adverse  effect  on  our  liquidity,  consolidated  financial
position  or  results of  operations.  These  matters  are  described  in LEGAL
PROCEEDINGS  in Item 3 contained in our 2006 Annual Report on Form 10-K.  There
have been no significant developments since year end.


NEW ACCOUNTING PRONOUNCEMENTS

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

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

In June 2007,  the AcSB issued  Section 3031,  INVENTORIES,  which replaces the
existing inventories standard. The new section is harmonized with International
Accounting  Standards and provides  additional  guidance on the measurement and
disclosure  requirements for inventories.  Specifically,  Section 3031 requires
inventories to be measured at the lower of cost and net realizable  value.  The
new  requirements  are effective for fiscal years beginning on or after January
1,  2008.  We do not  expect the  adoption  of this  section to have a material
impact on our results of operations or financial position.

                                      43
<PAGE>

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

Effective  December  31,  2006,  we  adopted  the  recognition  and  disclosure
provisions of FASB Statement  158,  EMPLOYERS'  ACCOUNTING FOR DEFINED  BENEFIT
PENSION  AND  OTHER   POSTRETIREMENT   PLANS.   This  statement  also  requires
measurement  of the funded status of a plan as of the balance  sheet date.  The
measurement  provisions  of the statement are effective for fiscal years ending
after  December  15,  2008.  We do not  expect  the  adoption  of the change in
measurement date in 2008 to have a material impact on our results of operations
or financial position.


In  February  2007,  FASB  issued  Statement  159,  THE FAIR  VALUE  OPTION FOR
FINANCIAL  ASSETS  AND  FINANCIAL  LIABILITIES.  The  statement  allows for the
elective measurement of eligible financial  instruments and certain other items
at fair value in order to  mitigate  volatility  in reported  earnings  without
having to apply complex and detailed hedge accounting  rules. This statement is
effective for fiscal years  beginning after November 15, 2007. We do not expect
the  adoption  of this  statement  to have a material  impact on our results of
operations or financial position.


EQUITY SECURITY REPURCHASES

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

<TABLE>
<CAPTION>
SUMMARY OF QUARTERLY RESULTS

                                                                       Three Months Ended
                                                --------|-------------------------------|---------------------
                                                  2005  |              2006             |          2007
                                                   Dec  |   Mar     Jun     Sep     Dec |   Mar    Jun    Sep
--------------------------------------------------------|-------------------------------|---------------------
<S>                                              <C>        <C>   <C>       <C>     <C>   <C>    <C>    <C>
Net Sales                                        1,073      980   1,039     997     920   1,140  1,399  1,446

Net Income (Loss)                                  303      (83)    408     199      77     121    368    403
                                                --------------------------------------------------------------

Earnings (Loss) per Common Share ($/share)
   Basic                                          0.58    (0.16)   0.78    0.38    0.15    0.23   0.70   0.77
   Diluted                                        0.56    (0.16)   0.76    0.37    0.14    0.22   0.68   0.75
                                                --------------------------------------------------------------
</TABLE>


                                      44
<PAGE>

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain  statements in this report,  including  those appearing in MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL  CONDITION AND RESULTS OF OPERATIONS,  are
forward-looking   statements.(1)   Forward-looking   statements  are  generally
identifiable  by terms  such as  ANTICIPATE,  BELIEVE,  INTEND,  PLAN,  EXPECT,
ESTIMATE,  BUDGET,  OUTLOOK or other  similar  words,  and  include  statements
relating to expected full year production,  cash flow and capital  expenditures
as well as future  production  associated with our coalbed methane,  Long Lake,
Syncrude, North Sea, Gulf of Mexico, Yemen, West Africa and other projects.

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

o    market prices for oil, natural gas and chemicals products;

o    our  ability to explore,  develop,  produce  and  transport  crude oil and
     natural gas to markets;

o    the  results  of  exploration   and   development   drilling  and  related
     activities;

o    volatility in energy trading markets;

o    foreign-currency exchange rates;

o    economic  conditions  in the  countries  and  regions in which we carry on
     business;

o    governmental  actions including changes to taxes or royalties,  changes in
     environmental  and  other  laws  and  regulations;

o    renegotiations of contracts;

o    results of litigation, arbitration or regulatory proceedings; and

o    political uncertainty, including actions by terrorists, insurgent or other
     groups, or other armed conflict, including conflict between states.

The above  items and their  possible  impact  are  discussed  more fully in the
sections  titled  RISK  FACTORS  in Item 1A and  QUANTITATIVE  AND  QUALITATIVE
DISCLOSURES  ABOUT  MARKET  RISK in Item 7A of our 2006  Annual  Report on Form
10-K.

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

o    future crude oil, natural gas or chemicals prices;

o    future production levels;

o    future cost recovery oil revenues from our operations in Yemen;

o    future  capital  expenditures  and their  allocation  to  exploration  and
     development activities;

o    future asset dispositions;

o    future sources of funding for our capital program;

o    possible commerciality, development plans or capacity expansions;

o    future ability to execute dispositions of assets or businesses;

o    future debt levels;

o    future cash flows and their uses;

o    future drilling of new wells;

o    ultimate recoverability of reserves;

o    expected finding and development costs;

o    expected operating costs;

o    future demand for chemicals products;

o    future  expenditures  and  future  allowances  relating  to  environmental
     matters; and

o    dates by which certain areas will be developed or will come on-stream.

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

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

                                      45
<PAGE>

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to normal  market risks  inherent in the oil and gas,  chemicals
and   energy   marketing   businesses,    including   commodity   price   risk,
foreign-currency  rate risk,  interest  rate risk and credit risk. We recognize
these risks and manage our  operations  to minimize our exposures to the extent
practical.  The information  presented on market risks in Item 7A on pages 77 -
80 in our 2006  Annual  Report on Form 10-K has not  changed  materially  since
December 31, 2006.

ITEM 4.    CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Our Chief  Executive  Officer and Chief Financial  Officer,  have evaluated the
effectiveness of our disclosure controls and procedures (as defined in Exchange
Act Rules  13a-15(e) and 15d-15(e)) as of the end of the period covered by this
report.  They  concluded  that,  as of the end of the  period  covered  by this
report,  our disclosure  controls and  procedures  were designed to be and were
adequate and effective in ensuring that  material  information  relating to the
Company and its consolidated subsidiaries would be made known to them by others
within those entities and that the information  required to be disclosed by the
Company in the reports that it files or submits under the  Securities  Exchange
Act is recorded,  processed,  summarized  and reported  within the time periods
specified in the SEC's rules and forms. Management recognizes that any controls
and  procedures,  no matter how well  designed and  operated,  can provide only
reasonable  assurance of achieving the desired  control  objectives and they do
not expect that the Company's  disclosure  controls and  procedures or internal
controls over financial reporting will prevent all errors or fraud. In reaching
a reasonable  level of assurance,  management  necessarily is required to apply
its judgment in evaluating the cost-benefit  relationship of possible  controls
and procedures.

CHANGES IN INTERNAL CONTROLS

We have  continually  had in place  systems  relating to internal  control over
financial  reporting.  There has not been any change in the Company's  internal
control  over  financial  reporting  during the third  quarter of 2007 that has
materially  affected,  or  is  reasonably  likely  to  materially  affect,  the
Company's  internal control over financial  reporting.  As well, based on these
evaluations,  there were no  material  weaknesses  in these  internal  controls
requiring  corrective  action.  As a result,  no such  corrective  actions were
taken.


                                      46
<PAGE>

                                     PART II

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

None


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 October 26, 2007.

                                         NEXEN INC.

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

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


                                      47