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


                                  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 March 31, 2009

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

                          COMMISSION FILE NUMBER 1-6702


                                [GRAPHIC OMITTED]


                                   NEXEN INC.

                      Incorporated under the Laws of Canada
                                   98-6000202
                      (I.R.S. Employer Identification No.)

                              801 - 7th Avenue S.W.
                        Calgary, Alberta, Canada T2P 3P7
                            Telephone (403) 699-4000
                           Web site - www.nexeninc.com


Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the  preceding 12 months (or for such  shorter  period that the  registrant  was
required  to file  such  reports),  and  (2) has  been  subject  to such  filing
requirements for the past 90 days.

                  Yes   [X]                    No    [ ]

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

                  Yes   [ ]                    No    [ ]

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

          Large accelerated filer [X]     Accelerated filer [ ]

           Non-Accelerated filer  [ ]     Smaller reporting company  [ ]

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

                  Yes   [ ]                    No    [X]

On March 31, 2009, there were 520,813,961 common shares issued and outstanding.


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

                                   NEXEN INC.
                                      INDEX

PART I              FINANCIAL INFORMATION                                  PAGE

          Item 1.   Unaudited Consolidated Financial Statements ............  3
          Item 2.   Management's Discussion and Analysis of Financial
                    Condition and Results of Operations (MD&A).............. 28
          Item 3.   Quantitative and Qualitative Disclosures about
                    Market Risk ............................................ 46
          Item 4.   Controls and Procedures ................................ 46

PART II             OTHER INFORMATION

          Item 1.   Legal Proceedings .....................................  47
          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 2008 Annual Report on Form
10-K (10-K) and with our current reports on Forms 8-K filed or furnished  during
the year.


SPECIAL NOTE TO CANADIAN INVESTORS

Nexen is a US Securities  and Exchange  Commission  (SEC)  registrant and a Form
10-K and related forms filer.  Therefore,  our reserves estimates and securities
regulatory  disclosures  generally  follow SEC  requirements.  In 2004,  certain
Canadian  regulatory  authorities adopted NATIONAL INSTRUMENT 51-101 - STANDARDS
OF  DISCLOSURE  FOR OIL AND GAS  ACTIVITIES  (NI 51-101)  which  prescribe  that
Canadian  companies follow certain  standards for the preparation and disclosure
of reserves and related  information.  We have been granted  certain  exemptions
from NI 51-101.  Please refer to the SPECIAL NOTE TO CANADIAN  INVESTORS on page
79 of our 2008 Form 10-K.

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

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

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

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

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

On March 31, 2009,  the noon-day  exchange rate was  US$0.7935 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 Months Ended March 31, 2009 and 2008.........................4

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

Unaudited Consolidated Statement of Cash Flows
for the Three Months Ended March 31, 2009 and 2008.........................6

Unaudited Consolidated Statement of Shareholders' Equity
for the Three Months Ended March 31, 2009 and 2008.........................7

Unaudited Consolidated Statement of Comprehensive Income
for the Three Months Ended March 31, 2009 and 2008.........................7

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


                                       3
<PAGE>

NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF INCOME
FOR THE THREE MONTHS ENDED MARCH 31


(Cdn$ millions, except per share amounts)                  2009         2008
------------------------------------------------------------------------------
REVENUES AND OTHER INCOME
  Net Sales                                               1,048        1,870
  Marketing and Other (Note 15)                             257          222
                                                      ------------------------
                                                          1,305        2,092
                                                      ------------------------
EXPENSES
  Operating                                                 305          309
  Depreciation, Depletion,
     Amortization and Impairment                            409          364
  Transportation and Other                                  201          205
  General and Administrative                                100           55
  Exploration                                                53           32
  Interest (Note 10)                                         68           27
                                                      ------------------------
                                                          1,136          992
                                                      ------------------------

INCOME BEFORE PROVISION FOR INCOME TAXES                    169        1,100
                                                      ------------------------

PROVISION FOR (RECOVERY OF) INCOME TAXES
   Current                                                  118          392
   Future                                                   (87)          77
                                                      ------------------------
                                                             31          469
                                                      ------------------------

NET INCOME BEFORE NON-CONTROLLING INTERESTS                 138          631
   Less: Net Income Attributable to
   Non-Controlling Interests                                 (3)          (1)
                                                      ------------------------

NET INCOME ATTRIBUTABLE TO NEXEN INC.                       135          630
                                                      ========================

EARNINGS PER COMMON SHARE ($/share)
  (Note 16)

  Basic                                                    0.26         1.19
                                                      ========================

  Diluted                                                  0.26         1.17
                                                      ========================

SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.


                                      4

<PAGE>

NEXEN INC.
UNAUDITED CONSOLIDATED BALANCE SHEET

                                                     March 31       December 31
(Cdn$ millions, except share amounts)                    2009              2008
--------------------------------------------------------------------------------
ASSETS
   CURRENT ASSETS
      Cash and Cash Equivalents                         2,054             2,003
      Restricted Cash (Notes 2 and 8)                     426               103
      Accounts Receivable (Note 3)                      2,821             3,163
      Inventories and Supplies (Note 4)                   546               484
      Other                                               405               169
                                                      --------------------------
         Total Current Assets                           6,252             5,922
                                                      --------------------------

   PROPERTY, PLANT AND EQUIPMENT
      Net of Accumulated Depreciation, Depletion,
         Amortization and Impairment of $11,021
         (December 31, 2008 - $10,393)                 16,177            14,922
   GOODWILL                                               400               390
   FUTURE INCOME TAX ASSETS                               359               351
   DEFERRED CHARGES AND OTHER ASSETS (Note 6)             431               570
                                                      --------------------------
TOTAL ASSETS                                           23,619            22,155
                                                      ==========================

LIABILITIES
   CURRENT LIABILITIES
      Accounts Payable and Accrued
         Liabilities (Note 9)                           3,455             3,326
      Accrued Interest Payable                             80                67
      Dividends Payable                                    26                26
                                                      --------------------------
         Total Current Liabilities                      3,561             3,419
                                                      --------------------------

   LONG-TERM DEBT (Note 10)                             7,791             6,578
   FUTURE INCOME TAX LIABILITIES                        2,605             2,619
   ASSET RETIREMENT OBLIGATIONS (Note 12)               1,033             1,024
   DEFERRED CREDITS AND OTHER LIABILITIES (Note 13)     1,300             1,324

SHAREHOLDERS' EQUITY (Note 14)
   Nexen Inc. Shareholders' Equity
      Common Shares, no par value
         Authorized:   Unlimited
         Outstanding:  2009 - 520,813,961 shares
                       2008 - 519,448,590 shares        1,004               981
      Contributed Surplus                                   2                 2
      Retained Earnings                                 6,399             6,290
      Accumulated Other Comprehensive Loss               (128)             (134)
                                                      --------------------------
   Total Nexen Inc. Shareholders' Equity                7,277             7,139
      Non-Controlling Interests                            52                52
                                                      --------------------------
   TOTAL SHAREHOLDERS' EQUITY                           7,329             7,191
   COMMITMENTS, CONTINGENCIES AND
      GUARANTEES (Note 17)
                                                      --------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY             23,619            22,155
                                                      ==========================

SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.


                                      5
<PAGE>

NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE MONTHS ENDED MARCH 31


(Cdn$ millions)                                                2009        2008
-------------------------------------------------------------------------------
OPERATING ACTIVITIES
   Net Income                                                   135         630
   Charges and Credits to Income not
         Involving Cash (Note 18)                               322         383
   Exploration Expense                                           53          32
   Changes in Non-Cash Working
         Capital (Note 18)                                      420         140
   Other                                                       (141)        (17)
                                                            -------------------
                                                                789       1,168

FINANCING ACTIVITIES
   Proceeds from (Repayment of) Term Credit
     Facilities, Net                                          1,011        (228)
   Proceeds from Canexus Term Credit Facilities, Net             10           8
   Dividends on Common Shares                                   (26)        (13)
   Distributions Paid to Non-Controlling Interests               (4)         (4)
   Issue of Common Shares and Exercise of Tandem
      Options for Shares                                         23          26
                                                            -------------------
                                                              1,014        (211)

INVESTING ACTIVITIES
   Capital Expenditures
       Exploration and Development                             (702)       (769)
       Proved Property Acquisitions                            (757)          -
       Chemicals, Corporate and Other                           (45)        (17)
   Proceeds on Disposition of Assets                             14           -
   Changes in Restricted Cash                                  (314)        121
   Changes in Non-Cash Working Capital (Note 18)                 19          22
   Other                                                         (2)        (27)
                                                           --------------------
                                                             (1,787)       (670)

EFFECT OF EXCHANGE RATE CHANGES ON CASH
   AND CASH EQUIVALENTS                                          35          31
                                                           --------------------

INCREASE IN CASH AND CASH EQUIVALENTS                            51         318

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

CASH AND CASH EQUIVALENTS - END OF PERIOD                     2,054         524
                                                           ====================


CASH AND CASH EQUIVALENTS AT MARCH 31, 2009 CONSISTS OF CASH OF $182 MILLION
AND SHORT-TERM INVESTMENTS OF $1,872 MILLION (DECEMBER 31, 2008 - CASH OF $355
MILLION AND SHORT-TERM INVESTMENTS OF $1,648 MILLION).


SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.


                                      6
<PAGE>

NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
FOR THE THREE MONTHS ENDED MARCH 31

(Cdn$ millions)                                                2009       2008
-------------------------------------------------------------------------------
COMMON SHARES, Beginning of Period                              981        917
      Issue of Common Shares                                     23         20
      Exercise of Tandem Options for Shares                       -          6
      Accrued Liability Relating to Tandem
          Options Exercised for Common Shares                     -          6
                                                            -------------------
    Balance at End of Period                                  1,004        949
                                                            ===================

CONTRIBUTED SURPLUS, Beginning of Period                          2          3
                                                            -------------------
   Balance at End of Period                                       2          3
                                                            ===================

RETAINED EARNINGS, Beginning of Period                        6,290      4,983
      Net Income                                                135        630
      Dividends on Common Shares (Note 14)                      (26)       (13)
                                                            -------------------
   Balance at End of Period                                   6,399      5,600
                                                            ===================

ACCUMULATED OTHER COMPREHENSIVE LOSS, Beginning of Period      (134)      (293)
      Other Comprehensive Income                                  6         27
                                                            -------------------
   Balance at End of Period                                    (128)      (266)
                                                            ===================

NON-CONTROLLING INTERESTS, Beginning of Period                   52         67
      Net Income Attributable to Non-Controlling Interests        3          1
      Distributions Paid to Non-Controlling Interests            (4)        (4)
      Issue of Partnership Shares to Nexen Inc. under
         Distribution Reinvestment Plan                           1          -
                                                            -------------------
   Balance at End of Period                                      52         64
                                                            ===================


NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
FOR THE THREE MONTHS ENDED MARCH 31

(Cdn$ millions)                                                2009       2008
-------------------------------------------------------------------------------
NET INCOME                                                      135        630
   Other Comprehensive Income (Loss), Net of Income Taxes:
      Foreign Currency Translation Adjustment
         Net Gains (Losses) on Investment in
           Self-Sustaining Foreign Operations                   174        186
         Net Gains (Losses) on Debt Hedges of
           Self-Sustaining Foreign Operations(1)               (168)      (159)
                                                           -------------------
       Other Comprehensive Income                                 6         27
                                                           -------------------
 COMPREHENSIVE INCOME ATTRIBUTABLE TO NEXEN INC.                141        657
                                                            ===================

1    Net of income tax  recovery  for the three  months ended March 31, 2009 of
     $24 million (2008 - net of income tax recovery of $23 million)

SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.


                                      7
<PAGE>

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

1.   ACCOUNTING POLICIES

Our Unaudited Consolidated Financial Statements are prepared in accordance with
Canadian  Generally  Accepted  Accounting  Principles  (GAAP).  The  impact  of
significant  differences  between  Canadian  and  United  States  GAAP  on  the
Unaudited  Consolidated  Financial  Statements  is disclosed in Note 20. In the
opinion of management,  the Unaudited Consolidated Financial Statements contain
all  adjustments of a normal and recurring  nature  necessary to present fairly
Nexen  Inc.'s  (Nexen,  we or our)  financial  position  at March 31,  2009 and
December 31, 2008 and the results of our  operations and our cash flows for the
three months ended March 31, 2009 and 2008.

We make estimates and  assumptions  that affect the reported  amounts of assets
and liabilities and disclosure of contingent assets and liabilities at the date
of the Unaudited Consolidated  Financial Statements,  and revenues and expenses
during the reporting  period.  Our  management  reviews  these  estimates on an
ongoing basis, including those related to accruals,  litigation,  environmental
and asset retirement obligations,  recoverability of assets, income taxes, fair
values of derivative assets and liabilities, capital adequacy and determination
of proved reserves.  Changes in facts and  circumstances  may result in revised
estimates and actual  results may differ from these  estimates.  The results of
operations  and cash flows for the three  months  ended  March 31, 2009 are not
necessarily  indicative  of the  results  of  operations  or cash  flows  to be
expected for the year ending December 31, 2009.

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

In February 2008, the Canadian Accounting Standards Board (AcSB) confirmed that
all  Canadian  publicly  accountable  enterprises  will be  required  to  adopt
International  Financial  Reporting  Standards  (IFRS) for  interim  and annual
reporting  purposes for fiscal years  beginning on or after January 1, 2011. We
are  currently  assessing the impact of the  convergence  of Canadian GAAP with
IFRS on our  results of  operations,  financial  position  and  disclosures.  A
project team has been set up to manage this transition and to ensure successful
implementation within the required timeframe.


CHANGE IN ACCOUNTING POLICIES

GOODWILL AND INTANGIBLE ASSETS

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

BUSINESS COMBINATIONS

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

CONSOLIDATED FINANCIAL STATEMENTS AND NON-CONTROLLING INTERESTS

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


                                      8
<PAGE>

2.   RESTRICTED CASH

At March 31, 2009,  our  restricted  cash  consists of margin  deposits of $426
million  (December  31,  2008  -  $103  million)  related  to   exchange-traded
derivative  financial  contracts  used by our energy  marketing  group to hedge
other  derivative  contracts  such as  physical  purchase  and  sale  commodity
contracts.   Certain  exchanges  require  that  we  maintain  margin  for  open
derivative financial contracts. The margin requirements change daily to reflect
the number of outstanding  contracts and the change in net mark-to-market gains
and losses on those contracts.  During the quarter, a portion of the gains were
settled resulting in an increase in margin  requirements to cover unsettled but
previously  recognized  losses.  Additional  margin was  required  to cover net
losses  recognized during the quarter on derivative  financial  contracts which
economically hedge mark-to-market gains on our physical positions.

3.   ACCOUNTS RECEIVABLE

                                                 March 31         December 31
                                                     2009                2008
-------------------------------------------------------------------------------
Trade
     Energy Marketing                               1,252               1,501
     Energy Marketing Derivative
         Contracts (Note 7)                           723                 755
     Oil and Gas                                      662                 639
     Chemicals and Other                               56                  68
                                                 ------------------------------
                                                    2,693               2,963
Non-Trade                                             196                 270
                                                 ------------------------------
                                                    2,889               3,233
Allowance for Doubtful Receivables                    (68)                (70)
                                                 ------------------------------
Total                                               2,821               3,163
                                                 ===============================

4.   INVENTORIES AND SUPPLIES


                                                 March 31         December 31
                                                     2009                2008
-------------------------------------------------------------------------------
Finished Products
     Energy Marketing                                 413                 384
     Oil and Gas                                       21                  17
     Chemicals and Other                               17                  16
                                                 ------------------------------
                                                      451                 417
Work in Process                                         9                   6
Field Supplies                                         86                  61
                                                 ------------------------------
Total                                                 546                 484
                                                 ===============================


5.   SUSPENDED EXPLORATION WELL COSTS


The following  table shows the changes in  capitalized  exploratory  well costs
during the three  months  ended March 31, 2009 and the year ended  December 31,
2008,  and does  not  include  amounts  that  were  initially  capitalized  and
subsequently expensed in the same period.

                                                Three Months         Year Ended
                                              Ended March 31        December 31
                                                        2009               2008
-------------------------------------------------------------------------------
Beginning of Period                                      518                326
     Exploratory Well Costs Capitalized
       Pending the Determination of
       Proved Reserves                                   113                254
     Capitalized Exploratory Well Costs
       Charged to Expense                                 (7)               (81)
     Transfers to Wells, Facilities and
       Equipment Based on
       Determination of Proved Reserves                    -                (29)
     Effects of Foreign Exchange Rate Changes             10                 48
                                                 ------------------------------
End of Period                                            634                518
                                                 ==============================

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.


                                      9
<PAGE>

                                                  March 31          December 31
                                                      2009                 2008
--------------------------------------------------------------------------------
Capitalized for a Period of One Year or Less           314                  239
Capitalized for a Period of Greater than One Year      320                  279
                                                 ------------------------------
Total                                                  634                  518
                                                 ==============================

Number of Projects that have Exploratory Well
     Costs Capitalized for a Period
     Greater than One Year                             10                    7
                                                 ------------------------------

As at March 31, 2009, we have exploratory  costs that have been capitalized for
more than one year relating to our interests in three exploratory blocks in the
Gulf  of  Mexico  ($140  million),   certain  coalbed  methane  and  shale  gas
exploratory activities in Canada ($79 million),  four exploratory blocks in the
North Sea ($78  million),  and our interest in an  exploratory  block  offshore
Nigeria ($23 million).  These costs relate to projects with  exploration  wells
for which we have not been able to record proved reserves. We are assessing all
of these  wells and  projects,  and are  working  with our  partners to prepare
development  plans,  drill additional  appraisal wells or to assess  commercial
viability.


6.   DEFERRED CHARGES AND OTHER ASSETS

                                                  March 31         December 31
                                                      2009                2008
--------------------------------------------------------------------------------
Crude Oil Put Options and Natural
   Gas Swaps (Note 7) (1)                                -                 234
Long-Term Energy Marketing Derivative
   Contracts (Note 7)                                  262                 217
Long-Term Capital Prepayments                           62                  61
Asset Retirement Remediation Fund                        8                   9
Defined Benefit Pension Assets                          48                   3
Other                                                   51                  46
                                                     ---------------------------
Total                                                  431                 570
                                                     ---------------------------

(1)  The crude oil put options were  reclassified  to other  current  assets as
     they settle within 12 months.

7.   FINANCIAL INSTRUMENTS

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

In our Energy  Marketing  group,  we enter into  contracts to purchase and sell
crude  oil,  natural  gas and  other  energy  commodities,  and use  derivative
contracts,  including  futures,  forwards,  swaps and options,  for hedging and
trading purposes (collectively derivatives).  We also use derivatives to manage
commodity  price risk and foreign  currency risk for non-trading  purposes.  We
categorize our derivative  instruments as trading or non-trading activities and
carry the  instruments  at fair value on our  balance  sheet.  The  derivatives
section below details our derivatives and fair values as at March 31, 2009. The
fair values are included with accounts receivable or payable and are classified
as long-term or short-term based on anticipated  settlement date. Any change in
fair value is included in marketing and other income.

We carry our long-term debt at amortized cost using the effective interest rate
method.  At March 31, 2009,  the estimated fair value of our long-term debt was
$6,595 million (December 31, 2008 - $5,686 million) as compared to the carrying
value of $7,791 million (December 31, 2008 - $6,578 million). The fair value of
long-term  debt is  estimated  based on prices  provided by quoted  markets and
third-party brokers.


                                      10
<PAGE>

DERIVATIVES

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

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

                                                   March 31         December 31
                                                       2009                2008
-------------------------------------------------------------------------------
  Commodity Contracts                                   709                 742
  Foreign Exchange Contracts                             14                  13
                                                   ----------------------------
Accounts Receivable (Note 3)                            723                 755
                                                   ----------------------------

  Commodity Contracts                                   259                 213
  Foreign Exchange Contracts                              3                   4
                                                   ----------------------------
Deferred Charges and Other Assets (Note 6) (1)          262                 217
                                                   ----------------------------

  Total Trading Derivative Assets                       985                 972
                                                   ============================

  Commodity Contracts                                   746                 585
  Foreign Exchange Contracts                             41                  30
                                                   ----------------------------
Accounts Payable and Accrued Liabilities (Note 9)       787                 615
                                                   ----------------------------

  Commodity Contracts                                   260                 248
  Foreign Exchange Contracts                             10                  46
                                                   ----------------------------
Deferred Credits and Other Liabilities
    (Note 13) (1)                                       270                 294
                                                   ----------------------------

  Total Trading Derivative Liabilities                1,057                 909
                                                   ============================

  Total Net Trading Derivative Contracts                (72)                 63
                                                   ============================

(1)  These  derivative  contracts  settle  beyond 12 months and are  considered
     non-current.

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

                                                                      March 31
                                                                          2009
--------------------------------------------------------------------------------
Current Trading Assets                                                   5,396
Non-Current Trading Assets                                               1,433
                                                                      ---------
  Total Trading Derivative Assets                                        6,829
                                                                      =========

Current Trading Liabilities                                              5,461
Non-Current Trading Liabilities                                          1,440
                                                                      ---------
  Total Trading Derivative Liabilities                                   6,901
                                                                      =========

                                                                      ---------
  Total Net Trading Derivative Contracts                                   (72)
                                                                      =========

Trading  revenues  generated by our energy  marketing  group  include gains and
losses  on  derivative  instruments  and  non-derivative  instruments  such  as
physical inventory. During the three months ended March 31, 2009, the following
trading revenues were recognized in marketing and other income:

                                                                  Three Months
                                                                Ended March 31
                                                                          2009
--------------------------------------------------------------------------------
Commodity                                                                  348
Foreign Exchange                                                           (81)
                                                                         -----
  Marketing Revenue                                                        267
                                                                         =====


                                      11
<PAGE>

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

                                                                 Three Months
                                                               Ended March 31
                                                                         2009
-------------------------------------------------------------------------------
Natural Gas                                              bcf/d           28.6
Crude Oil                                             mmbbls/d            3.8
Power                                                    GWh/d          212.3
Foreign Exchange                                  USD millions            378
Foreign Exchange                                 Euro millions            153
                                                        ---------------------

(b)  TOTAL  CARRYING  VALUE OF  DERIVATIVE  CONTRACTS  RELATED  TO  NON-TRADING
     ACTIVITIES


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

                                                      March 31    December 31
                                                          2009           2008
-------------------------------------------------------------------------------
Accounts Receivable (Note 3)                               224              6
Deferred Charges and Other Assets (Note 6) (1)               -            234
                                                        ---------------------
  Total Non-Trading Derivative Assets                      224            240
                                                        =====================

Accounts Payable and Accrued Liabilities (Note 9)           27             21
Deferred Credits and Other Liabilities (Note 13) (1)        21             26
                                                        ---------------------
  Total Non-Trading Derivative Liabilities                  48             47
                                                        =====================

  Total Net Non-Trading Derivative Assets (2)              176            193
                                                        =====================

(1)  These  derivative  contracts  settle  beyond 12 months and are  considered
     non-current.

(2)  The net fair value of these  derivatives  is equal to the gross fair value
     before  consideration  of netting  arrangements  and collateral  posted or
     received with counterparties.

CRUDE OIL PUT OPTIONS

In 2008,  we purchased put options on  approximately  70,000 bbls/d of our 2009
crude oil production for $14 million. These options establish an annual average
Dated Brent floor price of  US$60/bbl  on these  volumes.  In  September  2008,
Lehman  Brothers filed for bankruptcy  protection.  This impacts  approximately
25,000  bbls/d  of our 2009 put  options  and the  carrying  value of these put
options has been  reduced to nil. The crude oil put options are carried at fair
value and are classified as long-term or short-term based on their  anticipated
settlement  date. Fair value of the put options is supported by multiple quotes
obtained from third party brokers,  which were validated with observable market
data to the extent  possible.  The  decrease in fair value of the crude oil put
options of $16 million is included in marketing  and other income for the three
months ended March 31, 2009.

<TABLE>
<CAPTION>
                                           Notional               Average    Fair    Change in
                                            Volumes    Term   Floor Price   Value   Fair Value
----------------------------------------------------------------------------------------------
                                           (bbls/d)             (US$/bbl)
<S>                                          <C>       <C>            <C>     <C>         <C>
Dated Brent Crude Oil Put Options            45,000    2009           60      224         (16)
Dated Brent Crude Oil Put Options            25,000    2009           60        -           -
                                                                          --------------------
                                                                              224         (16)
                                                                          ====================
</TABLE>


                                      12
<PAGE>

FIXED-PRICE NATURAL GAS CONTRACTS AND NATURAL GAS SWAPS

We have  fixed-price  natural gas sales  contracts and  offsetting  natural gas
swaps that are not part of our trading  activities.  These sales  contracts and
swaps are carried at fair value and are  classified  as long-term or short-term
based on their  anticipated  settlement date. The decrease in fair value of the
fixed  price  natural  gas  contracts  and  natural  gas swaps of $8 million is
included in  marketing  and other  income for the three  months ended March 31,
2009.

<TABLE>
<CAPTION>
                                           Notional               Average    Fair    Change in
                                            Volumes    Term         Price   Value   Fair Value
----------------------------------------------------------------------------------------------
                                             (Gj/d)                ($/Gj)
<S>                                         <C>        <C>           <C>     <C>          <C>
Fixed-Price Natural Gas Contracts            15,514    2009          2.28    (11)          10
                                             15,514    2010          2.28    (15)          11
Natural Gas Swaps                            15,514    2009          7.60    (16)         (22)
                                             15,514    2010          7.60     (6)          (7)
                                                                            ------------------
                                                                             (48)          (8)
                                                                            ==================
</TABLE>

(c)      FAIR VALUE OF DERIVATIVES

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

Net Derivatives             Level 1       Level 2       Level 3        Total
-------------------------------------------------------------------------------
  Trading Derivatives          (198)          167           (41)         (72)
  Non-Trading Derivatives         -           176             -          176
                           -----------------------------------------------------
  Total                        (198)          343           (41)         104
                           =====================================================

A reconciliation of changes in the fair value of our derivatives  classified as
Level 3 for the three months ended March 31, 2009 is provided below:

                                                                       Level 3
------------------------------------------------------------------------------
Beginning of Period                                                        (82)
  Realized and Unrealized Gains (Losses)                                    27
  Purchases, Issuances and Settlements                                      13
  Transfers In and/or Out of Level 3                                         1
                                                                  -------------
End of Period                                                              (41)
                                                                  =============

 Unsettled gains (losses) relating to
 instruments still held as of March 31, 2009                                28
                                                                  =============

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

8.       RISK MANAGEMENT

(a)      MARKET RISK

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

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

COMMODITY PRICE RISK

We are exposed to commodity  price  movements as part of our normal oil and gas
operations,  particularly  in relation to the prices received for our crude oil


                                      13
<PAGE>

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

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

Our  energy  marketing  business  is  focused  on  providing  services  for our
customers and  suppliers to meet their energy  commodity  needs.  We market and
trade physical energy commodities including crude oil, natural gas, electricity
and other  commodities in selected  regions of the world. We accomplish this by
buying and selling  physical  commodities,  by acquiring and holding  rights to
physical  transportation  and  storage  assets  for these  commodities,  and by
building strong relationships with our customers and suppliers.

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

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

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

                                            Three Months             Year Ended
                                          Ended March 31            December 31
Value-at-Risk                                       2009                   2008
-------------------------------------------------------------------------------
Period End                                            19                     25
High                                                  24                     40
Low                                                   18                     19
Average                                               20                     30
                                      -----------------------------------------

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


FOREIGN CURRENCY RISK

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

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

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


                                      14
<PAGE>

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

                                                      March 31      December 31
(US$ millions)                                            2009             2008
-------------------------------------------------------------------------------
Net Investment in Self-Sustaining Foreign Operations     4,592            4,662
Designated US-Dollar Debt                                4,592            4,545
                                                     --------------------------

At March 31, 2009, the ineffective portion of the foreign exchange gains and
losses was $16 million ($14 million net of income tax expense) and is included
in marketing and other income.

At March 31,  2009,  we had  US$6,240  million of  long-term  debt issued in US
dollars and a one cent change in the US dollar to Canadian dollar exchange rate
would  increase or  decrease  our  accumulated  other  comprehensive  income by
approximately $53 million, before income tax.

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

(b)      CREDIT RISK

Credit risk affects both our trading and non-trading activities and is the risk
of loss if counterparties do not fulfill their contractual obligations. Most of
our credit exposure is with  counterparties  in the energy industry,  including
integrated  oil companies,  refiners and  utilities,  and are subject to normal
industry  credit  risk.  Approximately  85% of our exposure is with these large
energy  companies.  This  concentration  of risk within the energy  industry is
reduced because of our broad base of domestic and international counterparties.
Our  processes  to  manage  this  risk are  consistent  with  those in place at
December 31, 2008.

At March 31, 2009, only one counterparty  individually made up more than 10% of
our credit exposure. This counterparty is a major integrated oil company with a
strong  investment grade credit rating.  No other  counterparties  made up more
than 5% of our credit exposure. The following table illustrates the composition
of credit exposure by credit rating.

                                                  March 31          December 31
CREDIT RATING                                         2009                 2008
-------------------------------------------------------------------------------
A or higher                                            70%                  65%
BBB                                                    28%                  29%
Non-Investment Grade                                    2%                   6%
                                        ---------------------------------------
TOTAL                                                 100%                 100%
                                        =======================================

Our maximum  counterparty  credit  exposure at the balance  sheet date consists
primarily of the carrying  amounts on  non-derivative  financial assets such as
cash and cash equivalents,  accounts  receivable,  as well as the fair value of
derivative financial assets. We provided an allowance of $68 million for credit
risk with our  counterparties.  In  addition,  we  incorporate  the credit risk
associated with counterparty  default, as well as Nexen's own credit risk, into
our estimates of fair value.

Collateral  received  from  customers at March 31, 2009 includes $91 million of
cash and $129 million of letters of credit. The cash received reflects customer
deposits that are included in accounts payable and accrued liabilities.

(c)      LIQUIDITY RISK

Liquidity  risk is the  risk  that we will  not be able to meet  our  financial
obligations as they fall due. We require liquidity specifically to fund capital
requirements,  satisfy financial obligations as they become due, and to operate
in our energy marketing business.  We generally rely on operating cash flows to
provide  liquidity and we also maintain  significant  undrawn  committed credit
facilities.  At March 31, 2009, we had  approximately  $3.3 billion of cash and
available  committed  lines of credit.  This  includes $2.1 billion of cash and
cash equivalents on hand. In addition,  we have undrawn term credit  facilities
of $1.6  billion,  of which $438  million was  supporting  letters of credit at
March 31, 2009.  These  facilities are available  until 2012. We also have $584
million of undrawn,  uncommitted  credit  facilities,  of which $81 million was
supporting letters of credit at March 31, 2009.


                                      15
<PAGE>

The following table details the contractual  maturities for our  non-derivative
financial liabilities,  including both the principal and interest cash flows at
March 31, 2009:

<TABLE>
<CAPTION>
                                        Less than                            More Than
                                 Total     1 Year  1-3 Years    4-5 Years      5 Years
--------------------------------------------------------------------------------------
<S>                              <C>          <C>        <C>        <C>          <C>
Long-Term Debt                   7,864          -        240        2,961        4,663
Interest on Long-Term Debt (1)   7,829        340        680          675        6,134
                                ------------------------------------------------------
Total                           15,693        340        920        3,636       10,797
                                ======================================================
</TABLE>

(1)  Excludes  interest on term credit  facilities  of $3.9 billion and Canexus
     term  credit  facilities  of $430  million  as the  amounts  drawn  on the
     facilities  fluctuate.  Based  on  amounts  drawn at  March  31,  2009 and
     existing  variable interest rates, we would be required to pay $30 million
     per year until the outstanding  amounts on the term credit  facilities are
     repaid.

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

<TABLE>
<CAPTION>

                                        Less than                            More Than
                                 Total     1 Year  1-3 Years    4-5 Years      5 Years
--------------------------------------------------------------------------------------
<S>                              <C>          <C>        <C>        <C>          <C>
Trading Derivatives (Note 7)     1,057        787        224           44            2
Non-Trading Derivatives
    (Note 7)                        48         27         21            -            -
                                 -----------------------------------------------------
Total                            1,105        814        245           44            2
                                 =====================================================
</TABLE>
The commercial  agreements our energy  marketing group enter into often include
financial  assurance  provisions  that  allow  us  and  our  counterparties  to
effectively  manage credit risk. The agreements  normally require collateral to
be posted if an adverse  credit-related  event occurs, such as a drop in credit
rating.  Based on contracts in place and commodity prices at March 31, 2009, we
could  be  required  to  post  collateral  of up to  $1.2  billion  if we  were
downgraded to  non-investment  grade.  This  represents  the maximum  amount of
collateral  that we would be  required  to post  assuming  a severe  event that
causes all rating agencies to simultaneously downgrade us. This amount includes
trade  payables of $851 million and  derivative  contracts with a fair value of
$377  million.  All of these  obligations  are  included  on our March 31, 2009
balance  sheet.  In the event of a ratings  downgrade,  we could  monetize  our
trading  inventories and receivables and draw on our existing credit facilities
to meet our collateral obligations.

At March 31, 2009,  collateral posted with counterparties  includes $24 million
of  cash  and  $313  million  of  letters  of  credit  related  to our  trading
activities.  Cash  posted  is  included  with  our  accounts  receivable.  Cash
collateral is not normally applied to contract settlement.  Once a contract has
been settled,  the collateral amounts are refunded.  If there is a default, the
cash is retained.

Our   exchange-traded   derivative   contracts   are  also  subject  to  margin
requirements. We have margin deposits of $426 million (December 31, 2008 - $103
million), which have been included in restricted cash.

9.   ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

                                                  March 31          December 31
                                                      2009                 2008
------------------------------------------------------------------------------
Accrued Payables                                     1,767                2,033
Energy Marketing Derivative Contracts (Note 7)         787                  615
Trade Payables                                         403                  303
Stock-Based Compensation                                97                   97
Income Taxes Payable                                    75                   69
Other                                                  326                  209
                                                 ------------------------------
TOTAL                                                3,455                3,326
                                                 ==============================


                                       16
<PAGE>

10.   SHORT-TERM BORROWINGS AND LONG-TERM DEBT

                                                    March 31       December 31
                                                        2009              2008
-------------------------------------------------------------------------------
Canexus Term Credit Facilities,
 due 2011 (US$190 million drawn)(a)                      240               223
Term Credit Facilities, due 2012
 (US$1.8 billion drawn) (b)                            2,268             1,225
Canexus Notes, due 2013 (US$50 million)                   63                61
Notes, due 2013 (US$500 million)                         630               612
Notes, due 2015 (US$250 million)                         315               306
Notes, due 2017 (US$250 million)                         315               306
Notes, due 2028 (US$200 million)                         252               245
Notes, due 2032 (US$500 million)                         630               612
Notes, due 2035 (US$790 million)                         996               968
Notes, due 2037 (US$1,250 million)                     1,575             1,531
Subordinated Debentures, due 2043
                (US$460 million)                         580               563
                                                   ----------------------------
                                                       7,864             6,652
Unamortized Debt Issue Costs                             (73)              (74)
                                                   ----------------------------
TOTAL                                                  7,791             6,578
                                                   ============================

(a)      CANEXUS TERM CREDIT FACILITIES

Canexus has $430 million (US $341  million) of  committed,  secured term credit
facilities  available  until 2011.  At March 31,  2009,  $240  million  (US$190
million)  was  drawn on these  facilities  (December  31,  2008 - $223  million
(US$182 million)).  Borrowings are available as Canadian bankers'  acceptances,
LIBOR-based  loans,  Canadian  prime rate loans or  US-dollar  base rate loans.
Interest is payable monthly at floating rates.  The term credit  facilities are
secured by a floating charge debenture over all of Canexus' assets.  The credit
facility also contains  covenants with respect to certain  financial  ratios of
Canexus.  The  weighted-average  interest  rate  on  the  Canexus  term  credit
facilities  was 2.7% for the three  months  ended March 31, 2009 (Three  months
ended March 31, 2008 - 4.4%).

(b)      TERM CREDIT FACILITIES

We have  unsecured  term credit  facilities  of $3.9 billion  (US$3.1  billion)
available  until 2012.  At March 31, 2009,  $2.3 billion  (US$1.8  billion) was
drawn on these  facilities  (December 31, 2008 - $1.2 billion (US$1  billion)).
Borrowings are available as Canadian bankers'  acceptances,  LIBOR-based loans,
Canadian prime rate loans, US-dollar base rate loans or British pound call-rate
loans.  Interest is payable at floating rates.  The  weighted-average  interest
rate on our term credit  facilities  was 1.1% for the three  months ended March
31, 2009 (Three  months ended March 31, 2008 - 3.9%).  At March 31, 2009,  $438
million  (US$348   million)  of  these  facilities  were  utilized  to  support
outstanding  letters  of  credit  (December  31,  2008 - $381  million  (US$311
million)).

(c)      INTEREST EXPENSE

                                                                Three Months
                                                               Ended March 31
                                                            2009           2008
-------------------------------------------------------------------------------
Long-Term Debt                                               89             76
Other                                                         5              4
                                                  -----------------------------
Total                                                        94             80
   Less: Capitalized                                        (26)           (53)
                                                  -----------------------------
Total                                                        68             27
                                                  ============================

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

(d)   SHORT-TERM BORROWINGS

Nexen has  uncommitted,  unsecured  credit  facilities  of  approximately  $584
million (US$463 million),  none of which were drawn at March 31, 2009 (December
31, 2008 - nil). We utilized $81 million (US$64 million) of these facilities to
support  outstanding  letters of credit at March 31, 2009  (December 31, 2008 -
$29  million  (US$24  million)).  Interest is payable at  floating  rates.  The
weighted-average  interest rate on our  short-term  borrowings was 2.3% for the
three months ended March 31, 2009 (Three months ended March 31, 2008 - 4.3%).


                                      17
<PAGE>

11.   CAPITAL MANAGEMENT

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

                                                 March 31          December 31
                                                     2009                 2008
------------------------------------------------------------------------------
NET DEBT (1)
  Long-Term Debt                                    7,791                6,578
     Less: Cash and Cash Equivalents               (2,054)              (2,003)
                                                  -----------------------------
TOTAL                                               5,737                4,575
                                                  ============================
SHAREHOLDERS' EQUITY                                7,329                7,191
                                                  ============================

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


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

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

For the twelve  months  ended  March 31,  2009,  our net debt to cash flow from
operating  activities ratio was 1.4 times compared to 1.1 times at December 31,
2008. While we typically  expect the target ratio to fluctuate  between 1.0 and
2.0  times  under  normalized  commodity  prices,  this can be  higher  when we
identify strategic opportunities  requiring additional investment.  Whenever we
exceed our target ratio, we develop a strategy to reduce our leverage and lower
this ratio back to target levels over time.

Our  interest  coverage  ratio  monitors  our  ability  to  fund  the  interest
requirements  associated with our debt. Our interest coverage was 12.8 times at
March  31,  2009  (December  31,  2008  - 15.6  times).  Interest  coverage  is
calculated  by dividing our  twelve-month  trailing  adjusted  earnings  before
interest,  taxes, DD&A (Adjusted EBITDA) by interest expense before capitalized
interest.  Adjusted EBITDA is a non-GAAP  measure which is calculated using net
income  excluding  interest  expense,  provision for income taxes,  exploration
expenses,  DD&A,  impairment and other non-cash  expenses.  The  calculation of
Adjusted  EBITDA  is set  out in the  following  table  and is  unlikely  to be
comparable to similar measures presented by others.

                                                   Twelve Months     Year Ended
                                                  Ended March 31    December 31
                                                            2009           2008
-------------------------------------------------------------------------------
Net Income                                                 1,220         1,715
  Add:
     Interest Expense                                        135            94
     Provision for Income Taxes                            1,019         1,457
     Depreciation, Depletion, Amortization
       and Impairment                                      2,059         2,014
     Exploration Expense                                     423           402
     Recovery of Non-Cash Stock-Based
       Compensation                                         (213)         (272)
     Change in Fair Value of Crude Oil Put
       Options                                              (187)         (203)
     Other Non-Cash Expenses                                 (18)           (1)
                                                   ----------------------------
Adjusted EBITDA                                            4,438         5,206
                                                   ============================


                                      18
<PAGE>

12.      ASSET RETIREMENT OBLIGATIONS

Changes in carrying amounts of the asset retirement obligations associated with
our PP&E are as follows:

                                              Three Months Ended     Year Ended
                                                        March 31    December 31
                                                            2009           2008
------------------------------------------------------------------------------
Balance at Beginning of Period                             1,059           832
  Obligations Incurred with Development
    Activities                                                15            32
  Obligations Settled                                        (13)          (45)
  Accretion Expense                                           17            58
  Revisions to Estimates                                     (24)          159
  Effects of Changes in Foreign Exchange Rate                 14            23

                                                   ----------------------------
Balance at End of Period (1), (2)                          1,068         1,059
                                                   ============================

(1)  Obligations  due within 12 months of $35 million  (December 31, 2008 - $35
     million) have been included in accounts  payable and accrued  liabilities.
(2)  Obligations  relating  to our oil  and gas  activities  amount  to  $1,018
     million  (December 31, 2008 - $1,009 million) and obligations  relating to
     our  chemicals  business  amount to $50 million  (December  31, 2008 - $50
     million).

Our total estimated  undiscounted inflated asset retirement  obligations amount
to $2,424 million (December 31, 2008 - $2,393 million).  We have discounted the
total  estimated  asset  retirement   obligations  using  a   weighted-average,
credit-adjusted, risk-free rate of 5.9%. Approximately $421 million included in
our asset  retirement  obligations is expected to be settled over the next five
years. The remaining obligations settle beyond five years and will be funded by
future cash flows from our operations.

13.   DEFERRED CREDITS AND OTHER LIABILITIES
                                                        March 31    December 31
                                                            2009           2008
------------------------------------------------------------------------------
Deferred Tax Credit                                          698            709
Long-Term Energy Marketing Derivative
 Contracts (Note 7)                                          270            294
Deferred Transportation Revenue                               65             69
Fixed-Price Natural Gas Contracts
 and Swaps (Note 7)                                           21             26
Defined Benefit Pension Obligations                           68             67
Capital Lease Obligations                                     62             53
Other                                                        116            106
                                                   ----------------------------
Total                                                      1,300          1,324
                                                   ============================

14.   SHAREHOLDERS' EQUITY

DIVIDENDS

Dividends per common share for the three months ended March 31, 2009 were $0.05
per common share (2008 - $0.025).  Dividends  paid to holders of common  shares
have been designated as "eligible dividends" for Canadian tax purposes.

15.   MARKETING AND OTHER INCOME

                                                                Three Months
                                                               Ended March 31
                                                            2009           2008
-------------------------------------------------------------------------------
Marketing Revenue, Net (Note 7)                              267            211
Change in Fair Value of Crude Oil Put
  Options (Note 7)                                           (16)             -
Interest                                                       2             10
Foreign Exchange Gains                                        19              5
Other                                                        (15)            (4)
                                                   -----------------------------
Total                                                        257            222
                                                   =============================


                                      19
<PAGE>

16.   EARNINGS PER COMMON SHARE

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

                                                                Three Months
                                                               Ended March 31
(millions of shares)                                        2009           2008
-------------------------------------------------------------------------------
Weighted-average number of common
   shares outstanding                                      520.2          528.9
Shares issuable pursuant to tandem
   options                                                   7.6           22.5
Shares notionally purchased from proceeds
   of tandem options                                        (5.1)        (14.2)
                                                   -----------------------------
Weighted-average number of diluted common
  shares outstanding                                        522.7         537.2
                                                   =============================

In calculating the weighted-average number of diluted common shares outstanding
for the three  months  ended  March 31,  2009,  we excluded  17,243,309  tandem
options  because their exercise price was greater than the average common share
market  price in the period.  In  calculating  the  weighted-average  number of
diluted common shares outstanding for the three months ended March 31, 2008, we
excluded  4,103,560  tandem  options,  because their exercise price was greater
than the average  common share  market price in the period.  During the periods
presented,   outstanding  tandem  options  were  the  only  potential  dilutive
instruments.

17.   COMMITMENTS, CONTINGENCIES AND GUARANTEES

As  described  in  Note 16 to the  Audited  Consolidated  Financial  Statements
included  in our 2008 Form  10-K,  there are a number of  lawsuits  and  claims
pending,  the ultimate  results of which cannot be ascertained at this time. We
record  costs as they are  incurred  or become  determinable.  We  continue  to
believe  the  resolution  of these  matters  would not have a material  adverse
effect  on  our  liquidity,  consolidated  financial  position  or  results  of
operations. There have been no significant developments since year end.

18.   CASH FLOWS

(a)   CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH

                                                                Three Months
                                                               Ended March 31
                                                            2009           2008
-------------------------------------------------------------------------------
Depreciation, Depletion, Amortization
   and Impairment                                            409            364
Stock-Based Compensation                                       -            (59)
Provision for (Recovery of) Future
   Income Taxes                                              (87)            77
Change in Fair Value of Crude Oil Put
   Options                                                    16              -
Net Income Attributable to
   Non-Controlling Interests                                   3              1
Other                                                        (19)             -
                                                   -----------------------------
Total                                                        322            383
                                                   =============================


                                      20
<PAGE>

(b)   CHANGES IN NON-CASH WORKING CAPITAL

                                                                Three Months
                                                               Ended March 31
                                                            2009           2008
-------------------------------------------------------------------------------
   Accounts Receivable                                       298           (446)
   Inventories and Supplies                                  (49)           (78)
   Other Current Assets                                       (8)           (10)
   Accounts Payable and Accrued
      Liabilities                                            185            683
   Other                                                      13             13
                                                   -----------------------------
Total                                                        439            162
                                                   =============================
Relating to:
   Operating Activities                                      420            140
   Investing Activities                                       19             22
                                                   -----------------------------
Total                                                        439            162
                                                   =============================
(c)      OTHER CASH FLOW INFORMATION

                                                                Three Months
                                                               Ended March 31
                                                            2009           2008
-------------------------------------------------------------------------------
Interest Paid                                                 81             66
Income Taxes Paid                                             34             85
                                                   -----------------------------

Cash flow from other  operating  activities  includes cash outflows  related to
geological  and  geophysical  expenditures  of $12 million for the three months
ended March 31, 2009 (2008 - $10 million).


                                      21

<PAGE>

19.   OPERATING SEGMENTS AND RELATED INFORMATION

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

<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31, 2009
                                                                                                              Corporate
                                                                                 Energy                             and
                                               Oil and Gas                    Marketing  Syncrude  Chemicals       Other     Total
------------------------------------------------------------------------------------------------------------------------------------
                                                 United   United        Other
                                Yemen   Canada   States  Kingdom  Countries(1)
                              -----------------------------------------------
<S>                              <C>        <C>      <C>     <C>           <C>       <C>       <C>       <C>                 <C>
Net Sales                        162        91       63      478           19        13        98        124           -     1,048
Marketing and Other                3         7        -        4            -       267         -        (14)        (10)(2)   257
                              ------------------------------------------------------------------------------------------------------
Total Revenues                   165        98       63      482           19       280        98        110         (10)    1,305

Less: Expenses
  Operating                       47        41       23       51            2         8        66         67           -       305
  Depreciation, Depletion,
   Amortization and
     Impairment                   41        63       68      193            5         4        11         12          12       409
  Transportation and Other         3         3       13       (3)           -       162         7         10           6       201
  General and Administrative       4        14       14        2            8        23         -          9          26       100
  Exploration                      -        21       10        8          14 (3)      -         -          -           -        53
  Interest                         -         -        -        -            -         -         -          2          66        68
                              ------------------------------------------------------------------------------------------------------
Income (Loss)
  before Income Taxes             70       (44)     (65)     231          (10)       83        14         10        (120)      169
Less: Provisions for
(Recovery                         24       (11)     (23)      86           (6)       35         4          2         (80)       31
  of) Income Taxes
Less: Non-Controlling
  Interests                        -         -        -        -            -         -         -          3          -          3
                              ------------------------------------------------------------------------------------------------------
Net Income (Loss)                 46       (33)     (42)     145           (4)       48        10          5         (40)      135
                              ======================================================================================================

Identifiable Assets              400     7,678(4) 2,100    6,403          807     3,035(5)  1,212        594       1,390    23,619
                              ======================================================================================================
Capital Expenditures
  Development and Other           29       244       42      149           58         8        17         36           1       584
  Exploration                      -        94       26       28           15         -         -          -           -       163
  Proved Property
    Acquisitions                   -       757        -        -            -         -         -          -           -       757
                              ------------------------------------------------------------------------------------------------------
                                  29     1,095       68      177           73         8        17         36           1     1,504
                              ======================================================================================================
Property, Plant and
Equipment
  Cost                         2,920     9,225    4,591    6,869          636       256     1,386        983         332    27,198
  Less: Accumulated DD&A       2,729     1,843    2,850    2,419          121        80       244        523         212    11,021
                              ------------------------------------------------------------------------------------------------------
Net Book Value                   191     7,382(4) 1,741    4,450          515       176     1,142        460         120    16,177
                              ======================================================================================================
</TABLE>
(1)  Includes results of operations from producing activities in Colombia.
(2)  Includes  interest  income of $2 million,  foreign  exchange  gains of $19
     million,  decrease  in the  fair  value of crude  oil put  options  of $16
     million and other losses of $15 million.
(3)  Includes exploration activities primarily in Norway and Colombia.
(4)  Includes  costs of $5,658  million  related to our insitu oil sands  (Long
     Lake and future phases).
(5)  Approximately  77%  of  Marketing's   identifiable   assets  are  accounts
     receivable and inventories.


                                      22

<PAGE>

<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31, 2008
                                                                                                              Corporate
                                                                                 Energy                             and
                                               Oil and Gas                    Marketing  Syncrude  Chemicals       Other     Total
------------------------------------------------------------------------------------------------------------------------------------
                                                 United   United        Other
                                Yemen   Canada   States  Kingdom  Countries(1)
                              -----------------------------------------------
<S>                              <C>        <C>      <C>     <C>           <C>       <C>       <C>       <C>                 <C>
Net Sales                        276      147       181       939          46         14       158        109          -      1,870
Marketing and Other                4        -         1         1           -        211         -         (7)         12 (2)   222
                              ------------------------------------------------------------------------------------------------------
Total Revenues                   280      147       182       940          46        225       158        102         12      2,092

Less: Expenses
  Operating                       45        42       24        57           3          9        62         67          -        309
  Depreciation, Depletion,
   Amortization and
     Impairment                   34        47       74       170           4          3        12         10         10        364
  Transportation and Other         2         5        1         -           -        173         5         19 (3)      -        205
  General and                     (2)        1        6        (1)          1         26         1          7         16         55
    Administrative (4)
  Exploration                      -         4        6         7          15 (5)      -         -          -          -         32
  Interest                         -         -        -         -           -          -         -          3         24         27
                              ------------------------------------------------------------------------------------------------------
Income (Loss)
  before Income Taxes            201        48       71       707          23         14        78         (4)       (38)     1,100
Less: Provisions for
(Recovery                         70        14       25       359           3          1        22          -        (25)       469
  of) Income Taxes
Less: Non-Controlling
  Interests                        -         -        -         -           -          -         -          1          -          1
                              ------------------------------------------------------------------------------------------------------
Net Income (Loss)                131        34       46       348          20         13        56         (5)       (13)       630
                              ======================================================================================================
Identifiable Assets              341     5,837(6) 1,766     4,970         393      4,271(7)  1,216        476        391     19,661
                              ======================================================================================================
Capital Expenditures
  Development and Other           18       351       79       100          28          -         9         13          4        602
  Exploration                      5        86       67        16          10          -         -          -          -        184
                              ------------------------------------------------------------------------------------------------------
                                  23       437      146       116          38          -         9         13          4        786
                              ======================================================================================================

Property, Plant and
Equipment
  Cost                         2,288     7,171    3,330     4,999         302        252     1,339        848        313     20,842
  Less: Accumulated DD&A       2,068     1,637    1,898     1,085          84         65       214        474        178      7,703
                              ------------------------------------------------------------------------------------------------------
Net Book Value                   220     5,534(6) 1,432     3,914         218        187     1,125        374        135     13,139
                              ======================================================================================================
</TABLE>
(1)  Includes results of operations from producing activities in Colombia.
(2)  Includes  interest  income of $10 million,  foreign  exchange  gains of $5
     million and other losses of $3 million.
(3)  Includes  severance  accrual  of  $7  million  in  connection  with  North
     Vancouver technology conversion project.
(4)  Includes recovery of stock-based compensation expense of $41 million.
(5) Includes exploration activities primarily in Nigeria, Norway and Colombia.
(6)  Includes  costs of $4,003  million  related to our insitu oil sands  (Long
     Lake and future phases).
(7)  Approximately  83%  of  Marketing's   identifiable   assets  are  accounts
     receivable and inventories.


                                      23

<PAGE>

20.   DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING
      PRINCIPLES

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

UNAUDITED CONSOLIDATED STATEMENT OF INCOME - US GAAP
FOR THE THREE MONTHS ENDED MARCH 31

(Cdn$ millions, except per share amounts)                   2009           2008
-------------------------------------------------------------------------------
REVENUES AND OTHER INCOME
     Net Sales                                             1,048          1,870
     Marketing and Other (v); (vi)                           292            206
                                                    ---------------------------
                                                           1,340          2,076
                                                    ---------------------------
EXPENSES
     Operating (i)                                           305            310
     Depreciation, Depletion, Amortization
       and Impairment                                        409            364
     Transportation and Other (v)                            194            205
     General and Administrative (iv)                         108             62
     Exploration                                              53             32
     Interest                                                 68             27
                                                    ---------------------------
                                                           1,137          1,000
                                                    ---------------------------

INCOME BEFORE PROVISION FOR INCOME TAXES                     203          1,076
                                                    ---------------------------

PROVISION FOR (RECOVERY OF) INCOME TAXES
     Current                                                 118            392
     Deferred (iv); (vi)                                     (74)            66
                                                    ---------------------------
                                                              44            458
                                                    ---------------------------

NET INCOME BEFORE NON-CONTROLLING INTERESTS                  159            618
     Less: Net Income Attributable to
           Non-Controlling Interests                          (3)            (1)
                                                    ---------------------------

NET INCOME ATTRIBUTABLE TO NEXEN INC. - US GAAP (1)          156            617
                                                    ===========================

EARNINGS PER COMMON SHARE ($/share) (Note 16)
     Basic                                                  0.30           1.17
                                                    ===========================

     Diluted                                                0.30           1.15
                                                    ===========================

(1) RECONCILIATION OF CANADIAN AND US GAAP NET INCOME

                                                                Three Months
                                                               Ended March 31
(Cdn$ millions)                                             2009           2008
-------------------------------------------------------------------------------
Net Income - Canadian GAAP                                   135           630
Impact of US Principles, Net of Income Taxes:
     Pre-operating Costs (i)                                   -            (1)
     Stock-based Compensation (iv)                            (6)           (5)
     Inventory Valuation (vi)                                 27            (7)
                                                    --------------------------
Net Income - US GAAP                                         156           617
                                                    ==========================


                                      24

<PAGE>

UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP
                                                        March 31    December 31
(Cdn$ millions, except share amounts)                       2009           2008
-------------------------------------------------------------------------------
ASSETS
   CURRENT ASSETS
      Cash and Cash Equivalents                            2,054          2,003
      Restricted Cash                                        426            103
      Accounts Receivable                                  2,821          3,163
      Inventories and Supplies (vi)                          530            426
      Other                                                  405            169
                                                    ---------------------------
         Total Current Assets                              6,236          5,864
                                                    ---------------------------

   PROPERTY, PLANT AND EQUIPMENT
      Net of Accumulated Depreciation,
         Depletion, Amortization and
         Impairment of $11,414
         (December 31, 2008 - $10,786)(i); (iii)          16,128         14,873
   GOODWILL                                                  400            390
   DEFERRED INCOME TAX ASSETS                                359            351
   DEFERRED CHARGES AND OTHER ASSETS                         431            570
                                                    ---------------------------
TOTAL ASSETS                                              23,554        22,048
                                                    ===========================

LIABILITIES AND SHAREHOLDERS' EQUITY
   CURRENT LIABILITIES
      Accounts Payable and Accrued
        Liabilities (iv)                                   3,521          3,384
      Accrued Interest Payable                                80             67
      Dividends Payable                                       26             26
                                                    ---------------------------
         Total Current Liabilities                         3,627          3,477
                                                    ---------------------------

   LONG-TERM DEBT                                          7,791          6,578
   DEFERRED INCOME TAX LIABILITIES
      (i); (ii); (iv); (vi); (vii)                         2,542          2,543
   ASSET RETIREMENT OBLIGATIONS                            1,033          1,024
   DEFERRED CREDITS AND OTHER
      LIABILITIES (ii)                                     1,404          1,428

SHAREHOLDERS' EQUITY
   Nexen Inc. Shareholders' Equity
      Common Shares, no par value
         Authorized:   Unlimited
         Outstanding:  2009 - 520,813,961 shares
                       2008 - 519,448,590 shares           1,004            981
      Contributed Surplus                                      2              2
      Retained Earnings (i) - (vii)                        6,302          6,172
      Accumulated Other Comprehensive Loss (ii)             (203)          (209)
                                                    ---------------------------
   Total Nexen Inc. Shareholders' Equity                   7,105          6,946
      Non-Controlling Interests                               52             52
                                                    ---------------------------
   TOTAL SHAREHOLDERS EQUITY                               7,157          6,998
                                                    ---------------------------
   COMMITMENTS, CONTINGENCIES AND GUARANTEES
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                23,554         22,048
                                                    ===========================


UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - US GAAP
FOR THE THREE MONTHS ENDED MARCH 31

(Cdn$ millions)                                             2009           2008
--------------------------------------------------------------------------------
Net Income - US GAAP                                         156            617
Other Comprehensive Income (Loss),
      Net of Income Taxes:
      Foreign Currency Translation Adjustment                  6            (27)
                                                    ---------------------------
Comprehensive Income                                         162            590
                                                    ===========================


                                      25

<PAGE>

UNAUDITED CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE LOSS -
US GAAP

                                                        March 31    December 31
(Cdn$ millions)                                             2009           2008
-------------------------------------------------------------------------------
Foreign Currency Translation Adjustment                     (128)          (134)
Unamortized Defined Benefit Pension
     Plan Costs (ii)                                         (75)           (75)
                                                    ---------------------------
Accumulated Other Comprehensive Loss (AOCI)                 (203)          (209)
                                                    ===========================

NOTES TO THE UNAUDITED CONSOLIDATED US GAAP FINANCIAL STATEMENTS:

i.   Under Canadian GAAP, we defer certain  development costs to PP&E. Under US
     principles,  these costs have been  included in operating  expenses.  As a
     result property, plant and equipment is lower under US GAAP by $30 million
     (December 31, 2008 - $30 million).

ii.  US GAAP requires the recognition of the over-funded and under-funded status
     of a defined benefit plan on the balance sheet as an asset or liability. At
     March 31, 2009, the unfunded  amount of our defined  benefit  pension plans
     that was not included in the Pension Liability under Canadian GAAP was $104
     million.  This  amount has been  included  in  deferred  credits  and other
     liabilities  and $75 million,  net of income  taxes,  has been  included in
     AOCI.

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

iv.  Under Canadian principles, we record obligations for liability-based stock
     compensation plans using the intrinsic-value  method of accounting.  Under
     US principles,  obligations for  liability-based  stock compensation plans
     are recorded using the fair-value method of accounting. In addition, under
     Canadian principles,  we retroactively  adopted EIC-162 which requires the
     accelerated  recognition  of  stock-based  compensation  expense  for  all
     stock-based awards made to our retired and retirement-eligible  employees.
     However,  US GAAP  requires the  accelerated  recognition  of  stock-based
     compensation  expense for such  employees  for awards  granted on or after
     January 1, 2006. As a result:

     o    general  and  administrative  expense  is  higher by $8  million  ($6
          million,  net of income  taxes) for the three  months ended March 31,
          2009,  (2008 -  higher  by $7  million  ($5  million,  net of  income
          taxes)); and

     o    accounts payable and accrued liabilities are higher by $66 million as
          at March 31, 2009 (December 31, 2008 - $58 million).

v.   Under US GAAP,  asset  disposition  gains and  losses  are  included  with
     transportation and other expense. Gains of $7 million for the three months
     ended March 31, 2009 were  reclassified from marketing and other income to
     transportation and other expense (no gains were reclassified for the three
     months ended March 31, 2008).

vi.  Under Canadian  GAAP, we began  carrying our commodity  inventory held for
     trading purposes at fair value, less any costs to sell,  effective October
     31, 2007.  Under US GAAP,  we are required to carry this  inventory at the
     lower of cost or net realizable value. As a result:

     o    marketing and other income is higher by $42 million ($27 million, net
          of  income  taxes)  for  the  three  months  ended  March  31,  2009,
          respectively (2008 - lower by $16 million ($7 million,  net of income
          taxes)); and

     o    inventories  are lower by $16 million as at March 31, 2009  (December
          31, 2008 - lower by $58 million).

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

     As at March 31, 2009, the total amount of our unrecognized tax benefit was
     approximately $235 million, all of which, if recognized,  would affect our
     effective tax rate.  To the extent  interest and penalties may be assessed
     by taxing authorities on any underpayment of income tax, such amounts have
     been  accrued and are  classified  as a component  of income  taxes in the
     Unaudited  Consolidated  Statement of Income.  As at March 31,  2009,  the
     total amount of interest and penalties  related to uncertain tax positions
     recognized in deferred  income tax  liabilities in the US GAAP - Unaudited
     Consolidated  Balance  Sheet  was  approximately  $8  million.  We  had no
     interest or penalties included in the US GAAP - Consolidated  Statement of
     Income for the three months ended March 31, 2009.


                                      26

<PAGE>

     Our income tax filings are subject to audit by taxation authorities and as
     at March 31, 2009 the following tax years remained subject to examination,
     (i)  Canada - 1985 to date  (ii)  United  Kingdom - 2007 to date and (iii)
     United States - 2005 to date. We do not anticipate any material changes to
     the  unrecognized  tax benefits  previously  disclosed  within the next 12
     months.


CHANGES IN ACCOUNTING POLICIES - US GAAP
BUSINESS COMBINATIONS

On January 1, 2009, we prospectively  adopted  Financial  Accounting  Standards
Board (FASB)  Statement 141  (revised),  BUSINESS  COMBINATIONS.  Statement 141
establishes  principles and requirements of the acquisition method for business
combinations  and related  disclosures.  The adoption of this statement did not
impact our results of operations or financial position.

NON-CONTROLLING INTERESTS

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

DERIVATIVE AND HEDGING DISCLOSURES

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

NEW ACCOUNTING PRONOUNCEMENTS - US GAAP

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

In April 2009, FASB issued three final staff positions to improve  guidance and
disclosures on fair value  measurement and impairments.  The positions  clarify
fair value accounting specifically  regarding:  inactive markets and distressed
transactions;   other-than-temporary   impairments;  and  expanded  fair  value
disclosures for financial  instruments in interim periods.  These positions are
effective for interim and annual periods ending after June 15, 2009, with early
adoption  permitted  for periods  ending after March 15, 2009. We do not expect
the  adoption of these  positions  to have a material  impact on our results of
operation or financial position.


                                      27
<PAGE>

ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (MD&A)

THE FOLLOWING  SHOULD BE READ IN  CONJUNCTION  WITH THE  UNAUDITED  CONSOLIDATED
FINANCIAL  STATEMENTS  INCLUDED  IN  THIS  REPORT.  THE  UNAUDITED  CONSOLIDATED
FINANCIAL  STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE  WITH GENERALLY  ACCEPTED
ACCOUNTING   PRINCIPLES  (GAAP)  IN  CANADA.   THE  IMPACT  OF  THE  SIGNIFICANT
DIFFERENCES BETWEEN CANADIAN AND UNITED STATES (US) ACCOUNTING PRINCIPLES ON THE
FINANCIAL  STATEMENTS  IS  DISCLOSED  IN NOTE 20 TO THE  UNAUDITED  CONSOLIDATED
FINANCIAL STATEMENTS. THE DATE OF THIS DISCUSSION IS APRIL 27, 2009.

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

NOTE:  CANADIAN  INVESTORS SHOULD READ THE SPECIAL NOTE TO CANADIAN INVESTORS ON
PAGE 79 OF OUR 2008 FORM 10-K WHICH HIGHLIGHTS  DIFFERENCES BETWEEN OUR RESERVES
ESTIMATES  AND  RELATED  DISCLOSURES  THAT ARE  OTHERWISE  REQUIRED  BY CANADIAN
REGULATORY AUTHORITIES.

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

EXECUTIVE SUMMARY OF FIRST QUARTER RESULTS

                                                                  Three Months
                                                                 Ended March 31
(Cdn$ millions, unless otherwise noted)                       2009         2008
--------------------------------------------------------------------------------
Production before Royalties (mboe/d)                           252          267
Production after Royalties (mboe/d)                            225          222
Nexen's Average Realized Oil and Gas Price (Cdn$/boe)        47.56        85.90

Cash Flow from Operating Activities                            789        1,168
Net Income                                                     135          630
Earnings per Common Share, Basic ($/share)                    0.26         1.19

Capital Investment                                             747          786
Acquisition of Additional Interest in Long Lake                757            -
Net Debt (1)                                                 5,737        4,059
                                                             -------------------

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

Production  before royalties  averaged 252,000 boe/d in the quarter,  up 9% from
the previous  quarter.  Buzzard delivered strong production with rates of 92,700
boe/d net to us, during the quarter. Gulf of Mexico production continues to ramp
up following  the  hurricane  interruptions  from last year and averaged  18,800
boe/d in the quarter, while Long Lake SAGD bitumen production increased to 8,100
bbls/d.

Weaker  commodity  prices  reduced our net income and cash flow from  operations
while our after-royalty production increased. Our realized oil and gas price for
the quarter was $47.56/boe compared to $85.90/boe last year. Despite the drop in
commodity prices, our netbacks remain strong.

We incurred  approximately 25% of our 2009 planned capital  expenditures  during
the first quarter focusing on increasing production at Long Lake, conducting our
shale gas  winter  drilling  program  in  Canada,  advancing  work on the fourth
platform at Buzzard and bringing our Ettrick and Longhorn developments on stream
later this year.  We continue to review  opportunities  to reduce  operating and
capital costs.

At Long Lake, we acquired an  additional  15% interest in the project and became
the sole  operator of the resource and upgrader.  We are now  upgrading  bitumen
from our SAGD production and third-party  bitumen  purchases,  and are currently
producing  approximately 15,000 bbls/d of premium synthetic crude (PSCTM) (9,750
bbls/d net to us).

During the quarter, we drilled a successful  exploration well and two sidetracks
at Hobby in the UK North Sea, with a further  sidetrack planned to determine the
extent of the discovery.  Hobby is part of a rapidly growing area of exploration
interest, which includes other discoveries at Golden Eagle and Pink.


                                       28
<PAGE>

We  believe  our  financial  position  remains  strong.  We  have  liquidity  of
approximately  $3.3  billion  available  comprised  of cash on hand and  undrawn
committed  credit.  We have no significant  debt  maturities  until 2012 and the
average  term-to-maturity  of our long-term debt is  approximately  17 years. We
believe our significant  liquidity,  combined with strong netbacks,  provides us
with the financial flexibility to carry out our investment programs.

CAPITAL INVESTMENT

Our strategy and capital programs are focused on growing long-term value for our
shareholders  responsibly.  We are advancing our strategy as described below. In
2009, we are investing  primarily in:

     o    completing  the Ettrick  development  and advancing work on the fourth
          platform at Buzzard in the North Sea;
     o    bringing Longhorn in the Gulf of Mexico on stream during the year, and
          developing our Usan project offshore Nigeria;
     o    targeting a number of  exploration  prospects,  primarily in the North
          Sea and Gulf of Mexico; and
     o    advancing  our  Horn  River  shale  gas play in  northeastern  British
          Columbia.

Details of our capital programs are set out below:

<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31, 2009

                                                 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)                   168 (1)          40               1               -             209
    Long Lake Acquisition                          757               -               -               -             757
    United Kingdom                                  81               6              28              62             177
    Canada                                           -               2              93              34             129
    United States                                   37               -              26               5              68
    Nigeria                                         58               -               2               -              60
    Yemen                                            -               -               -              29              29
    Other Countries                                  -               -              13               -              13
Syncrude                                             -               -               -              17              17
                                         -----------------------------------------------------------------------------
                                                 1,101              48             163             147           1,459
Chemicals                                            -               -               -              36              36
Energy Marketing, Corporate and Other                -               -               -               9               9
                                         -----------------------------------------------------------------------------
Total Capital                                    1,101              48             163             192           1,504
                                         =============================================================================
As a % of Total Capital                            73%              3%             11%             13%            100%
                                         -----------------------------------------------------------------------------
</TABLE>
(1)  Includes $91 million of capitalized start-up costs.

SYNTHETIC
During the  quarter,  we reached a  significant  milestone  at Long Lake when we
produced and sold first PSCTM from the  upgrader.  The main process units in the
upgrader have been successfully  commissioned and are operating. The gasifier is
creating syngas that is being used in SAGD  operations for steam  generation and
creating  hydrogen  that is being  used for  upgrading.  This has  significantly
reduced the need for  purchased  natural gas.  During the  upgrader  ramp up, we
expect  that  there will be periods of  downtime  as we work  through  the early
stages of production and upgrading.

The reservoir continues to perform well and bitumen production is reflecting the
amount of steam that has been injected into the reservoir.  Our steam generation
has been  restricted  by our  ability to treat  water  during our ramp up phase.
Approximately  90-95% of the water we inject into the  reservoir is recycled and
treated.  In addition,  we add cold source water to gradually  increase  overall
steam volumes. Temperature limitations in the water treating system have limited
our ability to ramp up steam volumes.  We have  implemented a number of low cost
changes to the water treating system which include adding  supplementary heat to
the hot lime  softeners and improving our filtration  system.  These changes are
nearing completion and we expect that they will allow us to accelerate our steam
injection  capability.  The modifications made so far have already resulted in a
substantial increase to our steam generation volumes. For the first quarter, our
steam  volumes  averaged  66,000  bbls/d and we are now starting to see rates in
excess of 85,000 bbls/d. When the remaining modifications are completed shortly,
we expect to see another step change in our steam  volumes  which we  anticipate
will accelerate our bitumen production ramp up. Given the steaming  constraints,
we have rationed our steam to 39 of the 81 well pairs.  As we increase our steam
capacity, the remaining wells will be brought on. The average steam to oil ratio
for the wells on production is between four and five and we expect this ratio to
fall to around three as production ramps up.

Currently, we are producing approximately 18,000 bbls/d (gross) of bitumen which
is almost a 35% improvement over our first quarter average  production of 13,400
bbls/d (gross). When we combine our bitumen production with third-party volumes,
we are producing approximately 15,000 bbls/d (gross) of upgraded


                                       29
<PAGE>

on-spec  PSCTM.  Yields in the second  quarter should improve as we start up the
thermal cracker and solvent  de-asphalter.  We expect to reach full design rates
of 72,000 bbls/d of gross bitumen production,  upgraded to approximately  60,000
bbls/d (39,000 bbls/d net to us) of PSCTM in 2010.

We have a 65% interest in the Long Lake project and joint venture lands.  We are
the  sole  operator  of the  resource  and  upgrader  and we  have  successfully
integrated the upgrader  personnel that came with the recent  acquisition of the
additional 15% of the project from Opti Canada Inc.


UNITED KINGDOM - NORTH SEA
During the quarter, we have had significant success at Hobby in the Golden Eagle
area. We have completed  drilling the Hobby  discovery well and two  sidetracks.
All three wells encountered  significant high quality oil pay. These results are
encouraging.  We plan to continue with appraisal  activity and expect to spud an
appraisal well shortly.  In addition,  we plan to drill a third  sidetrack.  The
Golden Eagle area includes exciting discoveries at Golden Eagle, Hobby and Pink.
We have a 34%  operated  interest  in both  Hobby  and  Golden  Eagle  and a 46%
operated working interest in Pink. We have additional prospects in the area that
we plan to drill later this year.

Our Ettrick development in the North Sea is progressing towards first oil in the
coming months and is expected to add  approximately  6,000 to 8,000 boe/d to our
annual 2009 production  volumes.  The development  consists of a leased floating
production,  storage and  offloading  vessel  (FPSO)  designed to handle  30,000
bbls/d of oil and 35 mmcf/d of gas. We also have a discovery at Blackbird  which
could be a future  tie-back to Ettrick.  We operate both Ettrick and  Blackbird,
with an 80% working interest in each.


UNITED STATES - GULF OF MEXICO
At our Cote de Mer  prospect,  located  on the  Louisiana  coast,  we  completed
drilling  to target  depth of 22,300 feet where we have  encountered  commercial
quantities of  hydrocarbons.  We are currently  completing  this well and expect
first  production in the fourth quarter.  We have a 35% working interest in this
project.

In the Eastern Gulf of Mexico,  we plan to spud the Antietam  prospect  shortly,
which is located three miles west of our Shiloh discovery. We expect drilling to
be  completed  early in the third  quarter.  This is the fourth well in the area
where we have already had success at Shiloh and Vicksburg.  In addition, we plan
to drill one more exploration well and an appraisal well at Vicksburg. We have a
25% interest in Vicksburg and a 20% interest in both  Antietam and Shiloh,  with
Shell operating all three.

Development of the Longhorn discovery continues and first production is expected
mid year. Peak production of approximately  200 mmcf/d gross (50 mmcf/d,  net to
us) is expected by year end. We have recently  completed  drilling a deeper well
here which has extended our reserve  base.  We have a 25%  non-operated  working
interest and ENI is the operator.


At Knotty Head,  we plan to start  drilling an  appraisal  well in 2009 when the
first of our two new  deep-water  drilling rigs arrives.  The rig is expected to
enter the Gulf in the third  quarter.  We have a 25%  operated  interest  in the
field.

CANADA

During the quarter,  we completed  and tied-in two wells  drilled last summer in
our Horn River shale gas play. We have commenced testing on these wells. We also
drilled  three wells  earlier  this year and plan to complete  and tie-in  these
wells  before  year end. We expect to have six wells on  production  as the year
unfolds.

This  shale gas play has the  potential  to become  one of the most  significant
shale gas plays in North  America.  It has been compared to the Barnett Shale in
Texas by other operators in the area as it displays  similar rock properties and
play characteristics. We have approximately 88,000 acres in the Dilly Creek area
of the Horn River basin with a 100% working interest. Further appraisal activity
is required before commerciality is established.


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

On OPL 223,  we have  commenced  exploration  drilling  on the block.  Following
drilling  of the  exploration  well,  the rig will  return  to OML 138 and begin
development  drilling at Usan. We have a 20% funding interest and 18% beneficial
interest on block OPL 223. Our  partners are Total E&P Nigeria  Limited (18% and
Operator), ChevronTexaco Nigeria Deepwater F Limited (27%), Esso Exploration and
Production  (Upstream) Limited (27%) and Nigerian Petroleum  Development Company
Limited (10% carried interest).


                                       30
<PAGE>

FINANCIAL RESULTS

CHANGE IN NET INCOME

   (Cdn$ millions)                                                2009 VS 2008
   -----------------------------------------------------------------------------
   NET INCOME AT MARCH 31, 2008                                            630
                                                                 ===============
      Favorable (unfavorable) variances(1):

        Production Volumes, After Royalties
          Crude Oil                                                         15
          Natural Gas                                                      (32)
          Increase in Crude Oil Inventory                                  (49)
                                                                 ---------------
             Total Volume Variance                                         (66)

        Realized Commodity Prices
          Crude Oil                                                       (724)
          Natural Gas                                                      (46)
                                                                 ---------------
             Total Price Variance                                         (770)

        Operating Expense
          Conventional Oil & Gas                                             7
          Syncrude                                                          (4)
                                                                 ---------------
             Total Operating Expense Variance                                3

        Depreciation, Depletion, Amortization and Impairment
          Oil & Gas and Syncrude                                           (40)
          Other                                                             (5)
                                                                 ---------------
             Total DD&A                                                    (45)

        Exploration Expense                                                (21)

        Net Energy Marketing Revenue                                        67

        Chemicals Contribution                                              17

        General and Administrative Expense                                 (45)

        Interest Expense                                                   (41)

        Current Income Taxes                                               274
        Future Income Taxes                                                164

        Other
          Decrease in Fair Value of Crude Oil Put Options                  (16)
          Other                                                            (16)
                                                                 ---------------

   NET INCOME AT MARCH 31, 2009                                            135
                                                                 ===============
(1)  All amounts are presented before provision for income taxes.


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


                                       31
<PAGE>

<TABLE>
<CAPTION>
OIL & GAS AND SYNCRUDE

PRODUCTION

                                                                    Three Months Ended March 31
                                                                    2009                     2008
-----------------------------------------------------------------------------------------------------------
                                                           Before         After          Before       After
                                                     Royalties (1)    Royalties     Royalties(1)  Royalties
                                                     -------------    ---------     ------------  ---------
<S>                                                  <C>              <C>           <C>           <C>
Crude Oil and Liquids (mbbls/d)
    United Kingdom                                          103.8          103.8        106.0         106.0
    Yemen                                                    54.5           35.7         62.2          31.8
    Canada                                                   15.5           12.3         16.2          12.3
    United States                                            10.4            9.5         13.7          12.0
    Long Lake Bitumen(2)                                      8.1            8.1          0.7           0.6
    Other Countries                                           5.5            5.1          6.0           5.5
Syncrude (mbbls/d) (3)                                       19.8           19.6         19.3          17.0
                                                     -------------- ------------ ------------- ------------
                                                            217.6          194.1        224.1         185.2
                                                     -------------- ------------ ------------- ------------
Natural Gas (mmcf/d)
    United Kingdom                                             18            18           21            21
    Canada                                                    137           122          127           107
    United States                                              50            45          112            95
                                                     -------------- ------------ ------------- ------------
                                                              205           185          260           223
                                                     -------------- ------------ ------------- ------------

Total (mboe/d)                                                252           225          267           222
                                                     ============== ============ ============= ============
</TABLE>

(1) We have  presented  production  volumes  before  royalties as we measure our
    performance  on  this  basis  consistent  with  other  Canadian  oil and gas
    companies.
(2) Pre-operating  revenues  and costs  associated  with Long Lake  bitumen  are
    capitalized as development costs until we reach commercial operations.
(3) Considered a mining operation for US reporting purposes.


LOWER SALES VOLUMES DECREASED NET INCOME FOR THE QUARTER BY $66 MILLION
Production before royalties increased 9% from the prior quarter but was 6% lower
than the first quarter of 2008.  The increase  from the prior  quarter  resulted
from higher  uptime at Buzzard in the North Sea and restored  production  in the
Gulf of Mexico following last year's hurricane interruptions.  The decrease from
the first quarter of 2008 largely reflects  production that is still shut-in the
Gulf of Mexico,  partially offset by increasing bitumen production at Long Lake.
Production  after royalties  increased 14% and 1% from the prior quarter and the
first quarter of 2008, respectively.

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

                                                         Before          After
(mboe/d)                                              Royalties      Royalties
----------------------------------------------------------------- --------------
Production, fourth quarter 2008                             230            198
   Production changes:
       United Kingdom                                        12             12
       United States                                         10              9
       Yemen                                                  2              4
       Canada                                                (1)             1
       Long Lake Bitumen                                      2              2
       Syncrude                                              (3)            (1)
                                                   -------------- --------------
Production, first quarter 2009                              252            225
                                                   ============== ==============

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

UNITED KINGDOM
The Buzzard field continues to perform well,  achieving  volumes of 92,700 boe/d
during the quarter (214,500 boe/d gross). Production volumes were 9% higher than
the previous  quarter due to better uptime of the  platform.  This was partially
offset by maintenance on the water injection system.  Construction of the fourth
platform at Buzzard is on time and on budget.

At  Scott/Telford,  production  volumes  increased  39% from the prior  quarter.
Maintenance  on the Scott  platform to resolve  power supply issues and downtime
for subsea repairs resulted in lower production in the prior quarter. Production
volumes  decreased  25% from the first  quarter  of 2008 as a result of  natural
declines and unplanned  maintenance.  Production from our non-operated fields at
Duart and Farragon increased to average 3,700 boe/d for the quarter.


                                       32
<PAGE>

YEMEN
Yemen production  increased 4% from the prior quarter and decreased 12% from the
first quarter of 2008.

Masila  production was consistent  with the prior quarter and decreased 16% from
the first quarter of 2008. This decline is consistent  with our  expectations as
the field  matures.  Our  drilling  program  is focused  on  maximizing  reserve
recoveries and economic returns.  In the first quarter of 2009, we drilled seven
development  wells and plan to drill a further  eight wells in the year.  Strong
rates  from  wells  drilled  late in 2008  and  early  2009  contributed  to the
additional production in the first quarter.  Production declines are expected to
continue as we maximize recovery of the remaining reserves on the block.

Block 51  production  was 12% and 3% higher than the prior quarter and the first
quarter of 2008,  respectively.  The increase relates to better performance from
secondary  zones in our  existing  fields.  During  the  quarter,  we  drilled a
development well at BAK A.

CANADA
Production  in Canada was 2% lower than the previous  quarter and 3% higher than
the same period last year. Conventional production from our heavy oil properties
was  slightly  lower due to natural  field  declines.  CBM  production  remained
consistent  with the prior quarter  averaging 49 mmcf/d and was 14 mmcf/d higher
than the first quarter of 2008 as additional  wells and facilities  were brought
on stream.

LONG LAKE
Bitumen production averaged 8,100 boe/d (net to us) during the quarter.  The 23%
increase  from the prior quarter  reflects the  additional  working  interest we
acquired  in the Long Lake  Project  combined  with a modest  increase  in total
volumes. We currently have 39 of 81 well pairs converted to SAGD production.

In January,  we increased  our interest in the Long Lake Project from 50% to 65%
and the upgrader began  producing  premium  synthetic  crude oil. The project is
upgrading  bitumen  from  our  SAGD  production  and  from  third-party  bitumen
purchases,  and is  currently  producing  approximately  15,000 boe/d of premium
synthetic crude (9,750 net to us).

UNITED STATES

Gulf of Mexico production  volumes were 111% higher than the prior quarter as we
continue to bring our  hurricane-affected  properties  back  on-stream.  We were
producing  approximately 30,000 boe/d prior to Hurricanes' Gustav and Ike in the
third  quarter of 2008.  Our  properties  at  Gunnison,  West Cameron and Eugene
Island  came  back on  stream  towards  the end of 2008 and we  exited  the year
producing  approximately 12,000 boe/d. At Aspen,  production resumed in January.
Additional water handling facilities on the third-party  platform were installed
allowing Aspen  production  rates to increase.  Production  volumes on the shelf
were 42%  lower  than the same  period  last year as  production  shut in by the
hurricane  interruptions was offset by higher rates as a result of workovers and
recompletions.  At the end of the first  quarter,  our production in the Gulf of
Mexico was approximately  21,000 boe/d. Our Wrigley field came back on stream in
late April and we anticipate that  production will be restored to  pre-hurricane
rates.

OTHER COUNTRIES
Production  from the Guando  field in Colombia  averaged  5,500 boe/d during the
quarter,  slightly lower than the prior quarter and first quarter of 2008. Under
the terms of our license, our interest in the Guando field will decrease by half
to 10% during the second quarter as we reached 60 million  barrels of cumulative
production during the first quarter.

SYNCRUDE
Syncrude  production  was 11% lower than the previous  quarter mainly due to low
bitumen inventories and the scheduled turnaround of Coker 8-3 that began late in
the quarter.  The  turnaround  is expected to be  completed  early in the second
quarter.  Production  volumes  were 3% higher than the first  quarter of 2008 as
rates were lower last year as a result of downtime  caused by  maintenance  on a
coker and extreme winter conditions in January 2008.


                                       33
<PAGE>

<TABLE>
<CAPTION>
COMMODITY PRICES
                                                                             Three Months
                                                                            Ended March 31
                                                                         2009           2008
---------------------------------------------------------------------------------------------
<S>                                                                     <C>            <C>
CRUDE OIL
     West Texas Intermediate (WTI) (US$/bbl)                            43.08          97.90
                                                                    -------------------------

     Benchmark Differentials (1) (US$/bbl)
        Heavy Oil                                                        9.17          21.85
        Dated Brent                                                     (1.32)          1.00
        Mars                                                            (0.66)          6.93
        Masila                                                           0.05           2.32

     Realized Prices from Producing Assets (Cdn$/bbl)
        United Kingdom                                                  51.60          93.38
        Yemen                                                           52.30          96.57
        Canada                                                          35.35          65.94
        United States                                                   46.27          94.07
        Other Countries                                                 41.68          91.85
        Syncrude                                                        55.48         101.70

     Corporate Average (Cdn$/bbl)                                       50.41          93.00
                                                                    -------------------------

NATURAL GAS
     New York Mercantile Exchange (US$/mmbtu)                            4.48           8.75
     AECO (Cdn$/mcf)                                                     5.34           6.76
                                                                    -------------------------

     Realized Prices from Producing Assets (Cdn$/mcf)
        United Kingdom                                                   5.50           6.82
        Canada                                                           4.75           7.57
        United States                                                    5.93           9.03

     Corporate Average (Cdn$/mcf)                                        5.11           7.97
                                                                    -------------------------

NEXEN'S AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe)                   47.56          85.90
                                                                    -------------------------

AVERAGE FOREIGN EXCHANGE RATE - Canadian to US Dollar                  0.8028         0.9959
                                                                    -------------------------
</TABLE>
(1) These differentials are a discount/(premium) to WTI.

LOWER REALIZED COMMODITY PRICES DECREASED QUARTERLY NET INCOME BY $770 MILLION
WTI  averaged  US$43.08/bbl  for the  quarter,  down 27% and 56% from the  prior
quarter  and the first  quarter of 2008,  respectively,  while  Brent  crude oil
prices  fell 19% and 54% over the same  periods.  The effect of lower  commodity
prices was  mitigated  somewhat by the  strengthening  US dollar.  Our  realized
prices for our crude oil sales were 16% lower than the previous  quarter and 46%
lower than the first quarter of 2008.

NYMEX averaged  $4.48/mmbtu  for the quarter,  30% lower than the prior quarter,
while our realized  gas price  averaged  $5.11/mcf,  down only 19% over the same
period.  When compared to the first quarter of 2008, our realized gas price fell
36% while NYMEX prices  decreased 49%. AECO natural gas prices  meanwhile,  only
decreased 21% and 17% from the prior year and the previous quarter respectively.
The combination of a portion of our gas being priced at AECO and the stronger US
dollar  compared to the Canadian dollar in the first quarter,  partially  offset
the effect the NYMEX decline had on our realized gas prices.

The strengthening US dollar increased our net sales by approximately $53 million
and $177 million  compared to the prior  quarter and the first  quarter of 2008,
respectively.  Over the same  periods,  our realized  crude oil price  increased
$2.94/bbl  and  $9.77/bbl  as a result  of the  stronger  US  dollar,  while our
realized natural gas price increased $0.30/mcf and $0.99/mcf, respectively.


                                       34
<PAGE>

CRUDE OIL REFERENCE PRICES
Crude oil  prices  were  pressured  during the  quarter  by the global  economic
recession and contracting oil demand.  WTI ranged from a high of $54.34/bbl to a
low of  $33.98/bbl,  with price  strengthening  late in the quarter.  During the
first quarter  continued  global  economic  weakness and oil demand  destruction
resulted  in building  inventory  levels.  Rising  crude  inventories  depressed
current  prices,  resulting in a steep  contango  curve  structure  that further
provided  incentives to store crude. Oil demand in the U.S. continues to decline
as a result of the global recession.  Reduced industrial production and shipping
lowered demand for distillate and petrochemical feedstocks.  Nigerian attacks in
the Delta and  rumors  that  Russia may join OPEC in  cutting  crude  supply had
minimal price impact.  These geopolitical events that were once bullish to price
continued to have minimal impact due to the weak supply and demand  fundamentals
and additional OPEC spare capacity.

CRUDE OIL DIFFERENTIALS
High crude oil inventory levels, particularly at Cushing, influenced many of the
WTI differentials during the quarter.  These high inventories and reduced demand
depressed  pricing for WTI crude oil relative to other benchmark  crudes such as
Brent.

In Canada,  heavy oil differentials  averaged US$9.17/bbl (21.3% of WTI) for the
quarter,  compared to US$21.85/bbl (22.3% of WTI) for the first quarter of 2008.
Factors  contributing  to the narrower  differential  include  reduced supply of
medium crude oil from OPEC,  strong fuel oil pricing,  and  declining  heavy oil
production in Mexico.

Brent/WTI  differentials  averaged  US$1.32/bbl  for  the  quarter,  with  Brent
commanding a premium to WTI for much of the quarter.  The differential  remained
volatile  with  Brent  trading  both at a discount  and  premium to WTI at times
during the quarter.

The Mars differential averaged US$0.66/bbl for the quarter, with Mars trading at
a premium to WTI. MARS is a medium sour crude that normally trades at a discount
to WTI. The differential  widened towards  traditional  levels at the end of the
quarter due to stronger WTI prices.

The Yemen Masila differential  narrowed relative to WTI during the quarter, with
Masila  trading at a discount of $0.05/bbl  for the quarter.  This  reflects the
weaker WTI relative to other crude oil grades.

NATURAL GAS REFERENCE PRICES
NYMEX  natural gas prices  averaged  US$4.48/mmbtu  for the quarter  compared to
US$8.75/mmbtu last year. A combination of shrinking industrial and power demand,
new supply from unconventional  plays and lower oil prices resulted in a bearish
inventory outlook. This outlook reduced natural gas prices in the quarter. North
American  natural gas inventory levels at the end of the winter season are above
average putting further pressure on prices. Globally, additional LNG volumes are
expected to come on stream in 2009 and could be imported into the North American
market  due to larger  storage  capacity  than  elsewhere  in the  world.  These
additional LNG volumes and strong supply  additions from shale gas and tight gas
plays in North America could further reduce natural gas prices.

<TABLE>
<CAPTION>
OPERATING EXPENSES

                                                                 Three Months Ended March 31
(Cdn$/boe)                                                   2009                         2008
--------------------------------------------------------------------------------------------------------
                                                   Before            After       Before           After
                                                Royalties (1)    Royalties    Royalties (1)   Royalties
                                            ------------------------------------------------------------
<S>                                             <C>              <C>          <C>             <C>
Conventional Oil and Gas                             8.27             9.47         7.49            9.06
Synthetic Crude Oil
    Syncrude                                        36.95            37.31        35.16           39.79
Average Oil and Gas                                 10.62            12.03         9.46           11.39
                                            ------------------------------------------------------------
</TABLE>

(1)  Operating  expenses  per boe  are our  total  oil and gas  operating  costs
     divided  by  our  working  interest  production  before  royalties.  We use
     production  before  royalties to monitor our  performance  consistent  with
     other Canadian oil and gas companies.

LOWER OPERATING EXPENSES INCREASED NET INCOME FOR THE QUARTER BY $3 MILLION
Operating  costs are  consistent  with the same  period  last year  despite  the
stronger  US dollar  increasing  our  corporate  average  by  $1.06/boe  for the
quarter.  Fewer  maintenance  expenses  in the  UK  North  Sea  were  offset  by
additional  costs at Syncrude for unplanned  equipment  repairs and maintenance.
Excluding  the effect of the change in exchange  rates,  our  corporate  average
increased $0.10/boe.

In the UK North Sea,  costs  decreased  $6 million or 11% from last year.  Lower
tariffs at Buzzard reduced our corporate average by $0.33/boe. At Scott/Telford,
fewer  repairs  and  maintenance  expenses  reduced  operating  costs;  however,
production declines increased our per unit corporate average by $0.07/boe.


                                       35
<PAGE>

In Yemen,  we continue to incur  costs to  maintain  existing  wells to maximize
reserve  recoveries and slow the natural decline of the field. At Masila,  these
costs, combined with declining production,  increased average operating costs by
$0.18/boe.  At Block 51, production was consistent with the prior year; however,
lower maintenance costs helped to reduce our corporate average by $0.24/boe.

In the US Gulf of Mexico,  lower lease  operating  costs,  surface  facility and
downhole maintenance and other expenses reduced our costs relative to last year.
Production   volumes  have  not  been  fully  restored   following  last  year's
hurricanes, which increased our corporate average by $0.23/boe.

In Canada, fewer surface maintenance costs and additional CBM production reduced
our corporate  average by $0.13/boe.  At Syncrude,  operating costs increased $4
million  over last year as a result of higher costs for  unplanned  maintenance,
repairs to mining  equipment and costs for the Coker 8-3 turnaround  late in the
quarter. These additional expenses increased our corporate average by $0.15/boe.

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

                                                         Three Months Ended March 31
(Cdn$/boe)                                              2009                        2008
----------------------------------------------------------------------------------------------------
                                                Before          After       Before           After
                                             Royalties (1)  Royalties    Royalties (1)   Royalties
                                         -----------------------------------------------------------
<S>                                          <C>            <C>          <C>             <C>
Conventional Oil and Gas                         18.58          21.27        14.40           17.42
Synthetic Crude Oil
    Syncrude                                      6.46           6.53         6.87            7.77
Average Oil and Gas                              17.59          19.91        13.86           16.69
                                         -----------------------------------------------------------
</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 $40 MILLION
Our oil and gas DD&A  expense  increased  12% from the  first  quarter  of 2008.
Production  mix between areas  continues to change with lower  production in the
Gulf of Mexico and natural  declines  in Yemen  offset by strong  production  at
Buzzard.  This change in  production  mix  decreased  our  corporate  average by
$0.64/boe,  compared to the same period last year.  The weaker  Canadian  dollar
relative  to the same  period  last year  increased  our  corporate  average  by
$2.62/boe,  as depletion of our international and US assets is denominated in US
dollars.

At Buzzard,  successful  development  drilling  increased our year-end reserves,
slightly  lowering the depletion  rate.  This decrease in the Buzzard  depletion
rate has  lowered  our  corporate  average by  $0.06/boe.  Elsewhere  in the UK,
downward economic reserve revisions at our mature Scott/Telford fields increased
our corporate average by $0.40/boe.

In the Gulf of  Mexico,  higher  estimates  for  future  abandonment  costs  and
downward  economic  reserve  revisions  at the end of 2008  resulted  in  higher
depletion rates,  increasing our corporate  average rate by $0.62/boe.  Our DD&A
expense in the United States was lower  compared to the first quarter of 2008 as
some production remains shut-in following last year's hurricanes.

In Canada,  DD&A  expense  increased  $16  million  or 34% from the prior  year,
increasing  our  corporate  average  by  $0.70/boe.  This was  caused  by higher
depletion  rates at our heavy oil  properties  where  lower  year-end  commodity
prices  reduced  our proved  reserves.  The impact of these  downward  revisions
however,  was partially offset by lower depletion rates on our CBM properties as
additional reserves were recognized through improved recovery rates.


                                       36

<PAGE>

<TABLE>
<CAPTION>
EXPLORATION EXPENSE

                                                                          Three Months
                                                                         Ended March 31
(Cdn$ millions)                                                       2009          2008
-----------------------------------------------------------------------------------------
<S>                                                                   <C>           <C>
Seismic                                                                 12            10
Unsuccessful Drilling                                                   11             -
Other                                                                   30            22
                                                                -------------------------
Total Exploration Expense                                               53            32
                                                                =========================

New Growth Exploration                                                 163           184
Geological and Geophysical Costs                                        12            10
                                                                -------------------------
Total Exploration Expenditures                                         175           194
                                                                =========================

Exploration Expense as a % of Exploration Expenditures                  30%           16%
                                                                -------------------------
</TABLE>

HIGHER EXPLORATION EXPENSE DECREASED NET INCOME FOR THE QUARTER BY $21 MILLION
Our total  exploration  expenditures were $19 million lower than the same period
last year as reduced investment in the US Gulf of Mexico was partially offset by
additional spending in Canada and the UK North Sea.

In the UK North  Sea,  we have had  significant  success  at Hobby in the Golden
Eagle  area.  We have  completed  drilling  the  Hobby  discovery  well  and two
sidetracks.  All three wells encountered significant high quality oil pay. These
results are encouraging.  We plan to continue with appraisal activity and expect
to spud  an  appraisal  well  shortly.  In  addition,  we plan to  drill a third
sidetrack.  The Golden Eagle area includes exciting discoveries at Golden Eagle,
Hobby and Pink.  We have a 34% operated  interest in both Hobby and Golden Eagle
and a 46% operated working interest in Pink. We have additional prospects in the
area that we plan to drill later this year.

Exploration  expense was higher by $21 million  compared with the same period in
the prior year. In Canada,  we expensed $9 million for unsuccessful  exploration
drilling.  Our exploration expense also includes seismic acquisition costs of $9
million in the Dilly Creek shale gas area.

We are  focusing our  exploration  investment  for the  remainder of the year on
drilling  exploratory  and  appraisal  wells in the UK North  Sea and US Gulf of
Mexico.


                                       37

<PAGE>

<TABLE>
<CAPTION>
ENERGY MARKETING

                                                                             Three Months
                                                                            Ended March 31
(Cdn$ millions)                                                          2009           2008
---------------------------------------------------------------------------------------------
<S>                                                                  <C>           <C>
      Physical Sales (1)                                                9,945         14,227
      Physical Purchases (1)                                           (9,802)       (13,738)
      Net Financial Transactions (1)                                       48           (287)
      Change in Fair Market Value of Inventory                             76              9
                                                                   --------------------------
Marketing Revenue                                                         267            211
      Transportation Expense                                             (165)          (173)
      Other                                                                 5              5
                                                                   --------------------------
NET MARKETING REVENUE                                                     107             43
                                                                   ==========================

CONTRIBUTION TO NET MARKETING REVENUE BY REGION
      North America                                                       104             45
      Asia                                                                 12              4
      Europe                                                               (9)            (6)
                                                                   --------------------------
NET MARKETING REVENUE                                                     107             43
      Depreciation, Depletion, Amortization and Impairment                 (4)            (3)
      General and Administrative                                          (23)           (26)
      Allowance for Doubtful Receivables                                    3              -
                                                                   --------------------------
MARKETING CONTRIBUTION TO INCOME BEFORE INCOME TAXES                       83             14
                                                                   ==========================

NORTH AMERICA
      NATURAL GAS
      Physical Sales Volumes (2)  (bcf/d)                                 5.1            6.6
      Transportation Capacity (bcf/d)                                     1.6            1.9
      Storage Capacity (bcf)                                             33.5           42.6
      Financial Volumes (3) (bcf/d)                                      15.6           26.4

      CRUDE OIL
      Physical Sales Volumes 2 (mbbls/d)                                  806            649
      Storage Capacity (mbbls)                                          2,757          3,119
      Financial Volumes (3) (mbbls/d)                                     915          1,412

      POWER
      Physical Sales Volumes 2 (GWh/d)                                    4.9            5.2
      Generation Capacity (MW)                                             87             87

ASIA
      Physical Sales Volumes 2 (mbbls/d)                                  129            206
      Financial Volumes (3) (mbbls/d)                                     322            268

EUROPE
      NATURAL GAS
      Physical Sales Volumes (2)  (bcf/d)                                 1.4            1.5
      Storage Capacity (bcf)                                              3.7            2.7

      CRUDE OIL
      Financial Volumes (3) (mbbls/d)                                     507          2,106

      POWER
      Physical Sales Volumes 2 (GWh/d)                                   70.2           60.9

VALUE-AT-RISK
      Quarter-end                                                          19             35
      High                                                                 24             40
      Low                                                                  18             21
      Average                                                              20             30
                                                                   --------------------------
</TABLE>

(1)  Marketing's   physical   sales,   physical   purchases  and  net  financial
     transactions  are reported net on the Unaudited  Consolidated  Statement of
     Income as marketing and other.
(2)  Excludes  intra-segment  transactions.  Physical volumes  represent amounts
     delivered during the quarter.
(3)  Financial volumes represent amounts largely acquired to economically  hedge
     physical transactions during the quarter.


                                       38
<PAGE>

HIGHER CONTRIBUTION FROM ENERGY MARKETING INCREASED NET INCOME BY $67 MILLION
Energy  marketing  delivered  improved  results in the first quarter driven by a
renewed focus on optimizing our physical business. The crude oil team used their
physical storage  positions to take advantage of contango (rising prices) in the
crude  oil  market.   This   contango,   combined  with   narrowing   crude  oil
differentials,  enabled us to capture both realized and unrealized  gains on our
relatively low-risk physical trading strategies.

Gains were also generated by the  strengthening  condensate  market. We imported
condensate  to supply the  Canadian  market  and  generated  gains by  supplying
condensate  to support  the strong  demand for  Canadian  heavy oil and  bitumen
production.

These  gains were offset  somewhat  by losses  early in the quarter in our North
America  natural gas business.  These losses  related to exiting the last of our
basis trading  positions  from 2008.  Additionally,  we  recognized  losses from
selling  natural  gas  inventory  where   offsetting   gains  on  the  financial
instruments hedging the value of the inventory were recognized in prior periods.

We  have  substantially  completed  re-aligning  our  marketing  strategies  and
positions   to  focus  on  and   support  our  core   physical   business  as  a
producer/marketer.

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

COMPOSITION OF NET MARKETING REVENUE

                                                               Three Months
                                                              Ended March 31
(Cdn$ millions)                                             2009         2008
------------------------------------------------------------------------------
Trading Activities (Physical and Financial)                  101           37
Non-Trading Activities                                         6            6
                                                       -----------------------
Total Net Marketing Revenue                                  107           43
                                                       =======================

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

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


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

At March 31,  2009,  the fair value of our  derivative  contracts  in our energy
marketing  trading  activities was a net loss of $72 million.  These derivatives
are used to economically hedge our physical storage and transportation contracts
which cannot be carried at fair value until they are used.  Below is a breakdown
of the derivative fair value by valuation method and contract maturity.

<TABLE>
<CAPTION>
(Cdn$ millions)                                                                          MATURITY
---------------------------------------------------------------------------------------------------------------------------------
                                                                  Less than                               More than
                                                                     1 year      1-3 years    4-5 years     5 years       Total
                                                                -----------------------------------------------------------------
<S>                                                               <C>            <C>          <C>         <C>             <C>
   Level 1 - Actively Quoted Markets                                  (107)           (66)         (26)          1        (198)
   Level 2 - Based on Other Observable Pricing Inputs                   98             68            3          (2)        167
   Level 3 - Based on Unobservable Pricing Inputs                      (55)            10            4           -         (41)
                                                                -----------------------------------------------------------------
Total                                                                  (64)            12          (19)         (1)        (72)
                                                                =================================================================
</TABLE>


                                       39
<PAGE>

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

(Cdn$ millions)                                                                                       Total
-----------------------------------------------------------------------------------------------------------
<S>                                                                                              <C>
Fair Value at December 31, 2008                                                                          63
   Change in Fair Value of Contracts                                                                     25
   Net Losses (Gains) on Contracts Closed                                                              (160)
   Changes in Valuation Techniques and Assumptions (1)                                                    -
                                                                                                ------------
Fair Value at March 31, 2009                                                                            (72)
                                                                                                ============
</TABLE>

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

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


CHEMICALS

HIGHER CHEMICALS CONTRIBUTION INCREASED NET INCOME BY $17 MILLION
Chlor-alkali  prices  increased  40%,  primarily  as caustic  prices have almost
doubled  since the  first  quarter  of 2008.  The  positive  impact of the price
increases  have been  offset by a  decrease  in sales  volumes.  Demand  for our
chlorine  and caustic  products  fell as a  consequence  of the global  economic
downturn.

Transportation  and other costs are $9 million  lower than the first  quarter of
2008 when we accrued  severance costs of $7 million in connection with our North
Vancouver technology  conversion project.  Chemicals net income includes foreign
exchange losses of $6 million on the Canexus US-dollar denominated debt, as well
as an $8 million  decrease in the fair value of interest  rate swaps and foreign
exchange forward contracts.

<TABLE>
<CAPTION>
CORPORATE EXPENSES

GENERAL AND ADMINISTRATIVE (G&A)
                                                                                            Three Months
                                                                                           Ended March 31
(Cdn$ millions)                                                                          2009          2008
------------------------------------------------------------------------------------------------------------
<S>                                                                                      <C>           <C>
General and Administrative Expense before Stock-Based Compensation                        100            96
Stock-Based Compensation (1)                                                                -           (41)
                                                                                  --------------------------
Total General and Administrative Expense                                                  100            55
                                                                                  ==========================
</TABLE>

(1)  Includes cash and non-cash  expenses  related to our tandem option plan and
     stock appreciation rights plan.


HIGHER G&A COSTS DECREASED NET INCOME BY $45 MILLION
G&A costs increased during the quarter as our stock-based  compensation  expense
in  2008  included  a $41  million  recovery  of  expense.  We  account  for our
stock-based   compensation   programs  using  the  intrinsic-value   method  and
therefore, fluctuations in our share price creates volatility in our net income.
Our share price at March 31, 2009 was  consistent  with the 2008 year end price.
Cash payments  made in connection  with our  stock-based  compensation  programs
during the quarter were insignificant  compared to $18 million paid in the first
quarter of 2008.

<TABLE>
<CAPTION>
INTEREST
                                                                                            Three Months
                                                                                           Ended March 31
(Cdn$ millions)                                                                          2009          2008
------------------------------------------------------------------------------------------------------------
<S>                                                                                   <C>           <C>
Interest                                                                                   94            80
      Less: Capitalized                                                                   (26)          (53)
                                                                                   -------------------------
Net Interest Expense                                                                       68            27
                                                                                   =========================

                                                                                   -------------------------
Effective Interest Rate                                                                   4.9%          6.1%
                                                                                   =========================
</TABLE>

HIGHER INTEREST EXPENSE DECREASED NET INCOME BY $41 MILLION
Our financing  costs  increased  from the first quarter of 2008 primarily due to
the  strengthening  US dollar.  The  stronger US dollar  increased  our interest
expense  by $17  million.  This was  partially  offset by lower  expense  on our
medium-term notes that were repaid in mid 2008. Interest costs on our additional
term credit  facilities  borrowings  were offset by lower  interest rates on our
floating debt facilities.


                                       40
<PAGE>

Capitalized  interest on our Long Lake  Project  was $35 million  lower than the
previous  year as  construction  of the  facilities  is now  complete.  This was
partially  offset by  additional  capitalized  interest  related  to the  fourth
platform at Buzzard  and our  developments  at Ettrick in the North Sea,  and at
Usan, offshore West Africa.


INCOME TAXES
                                                                 Three Months
                                                                Ended March 31
(Cdn$ millions)                                               2009        2008
-------------------------------------------------------------------------------
Current                                                        118         392
Future                                                         (87)         77
                                                        -----------------------
Total Provision for Income Taxes                                31         469
                                                        =======================

Effective Tax Rate                                              18%         43%
                                                        -----------------------


LOWER TAXES INCREASED NET INCOME BY $438 MILLION AND THE YEAR-TO-DATE  EFFECTIVE
TAX RATE DECREASED TO 18%
Lower  commodity  prices resulted in reduced tax expense in the first quarter of
2009.  During the first  quarter,  we also  reduced  our  future tax  expense by
amortizing a portion of the deferred tax benefit  arising from the 2008 internal
reorganization and financing of our North Sea assets. Reductions in Canadian tax
rates resulted in an additional $22 million  recovery of future taxes during the
quarter.

Our income tax provision  includes current taxes in the UK, Yemen,  Colombia and
the United States.


OTHER
                                                                Three Months
                                                               Ended March 31
(Cdn$ millions)                                               2009        2008
-------------------------------------------------------------------------------
Decrease in Fair Value of Crude Oil Put Options                (16)          -
                                                        -----------------------

During the first  quarter of 2008,  we  purchased  put options on  approximately
70,000 bbls/d of our 2009 crude oil production.  These options establish a Dated
Brent floor price of  US$60/bbl  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 $14 million and are carried at fair
value. During the third quarter of 2008, Lehman Brothers,  one of the put option
counterparties,  filed for bankruptcy  protection impacting 25,000 bbls/d of our
2009 put options.  The  carrying  value of these put options has been reduced to
nil. At March 31, 2009, the remaining  options had a fair value of $224 million,
$16 million lower than the end of 2008 due to the increase in Dated Brent.


                                       41
<PAGE>

<TABLE>
<CAPTION>
LIQUIDITY AND CAPITAL RESOURCES

CAPITAL STRUCTURE
                                                                             March 31       December 31
(Cdn$ millions)                                                                  2009              2008
--------------------------------------------------------------------------------------------------------
<S>                                                                          <C>            <C>
NET DEBT (1)
     Bank Debt                                                                  2,508             1,448
     Public Senior Notes                                                        4,718             4,582
                                                                         -------------------------------
     Total Senior Debt                                                          7,226             6,030
     Subordinated Debt                                                            565               548
                                                                         -------------------------------
     Total Debt                                                                 7,791             6,578
     Less: Cash and Cash Equivalents                                           (2,054)           (2,003)
                                                                         -------------------------------
TOTAL NET DEBT                                                                  5,737             4,575
                                                                         ===============================

SHAREHOLDERS' EQUITY                                                            7,329             7,191
                                                                         ===============================
</TABLE>

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


NET DEBT

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

<TABLE>
<CAPTION>
(Cdn$ millions)
--------------------------------------------------------------------------------------------------------
<S>                                                                                        <C>
Capital Investment                                                                                  747
Acquisition of Additional Working Interest at Long Lake                                             757
Cash Flow from Operating Activities, Net of Changes in Restricted Cash                             (475)
                                                                                           -------------
     Deficiency                                                                                   1,029

Dividends on Common Shares                                                                           26
Issue of Common Shares                                                                              (23)
Foreign Exchange Translation of US-dollar Debt and Cash                                             138
Other                                                                                                (8)
                                                                                           -------------
INCREASE IN NET DEBT                                                                              1,162
                                                                                           =============
</TABLE>

Our net debt increased  during the first quarter  primarily as a result of using
term credit facilities to finance the $757 million acquisition of the additional
working  interest  in Long  Lake and as a  stronger  US dollar  relative  to the
Canadian dollar increased our US-dollar  denominated  debt by $138 million.  Our
available  liquidity  at the end of the quarter was  approximately  $3.3 billion
comprised of cash on hand and undrawn committed credit facilities.

<TABLE>
<CAPTION>
CHANGE IN WORKING CAPITAL
                                                         March 31         December 31         Increase/
(Cdn$ millions)                                              2009                2008        (Decrease)
---------------------------------------------------------------------------------------------------------
<S>                                                      <C>              <C>                <C>
Cash and Cash Equivalents                                   2,054               2,003                51
Restricted Cash                                               426                 103               323
Accounts Receivable                                         2,821               3,163              (342)
Inventories and Supplies                                      546                 484                62
Accounts Payable and Accrued Liabilities                   (3,455)             (3,326)             (129)
Other                                                         299                  76               223
                                                     ----------------------------------------------------
Net Working Capital                                         2,691               2,503               188
                                                     =================================
</TABLE>

Our cash and cash equivalents are slightly higher than year end while restricted
cash increased $323 million.  Our cash balances  remained  steady as we used our
term credit  facilities and cash flow from  operating  activities to finance our
capital  investment  during the quarter.  At March 31, 2009, our restricted cash
consists  of  margin  deposits  of  $426  million  related  to   exchange-traded
derivative financial contracts used by our energy marketing group to hedge other
derivative  contracts such as physical  purchase and sale  commodity  contracts.
Certain exchanges require that we maintain margin for open derivative  financial
contracts.  The  margin  requirements  change  daily to  reflect  the  number of
outstanding  contracts and the change in net mark-to-market  gains and losses on
those  contracts.  During  the  quarter,  a portion  of the gains  were  settled
resulting  in  an  increase  in  margin  requirements  to  cover  unsettled  but
previously recognized losses. Additional margin was required to cover net losses


                                       42
<PAGE>

recognized  during the quarter on  derivative  financial  contracts  which hedge
mark-to-market gains on our physical positions.

Since the  beginning  of the year,  our  energy  marketing  accounts  receivable
decreased $281 million while accounts payable increased $218 million. Our energy
marketing  net  working  capital  position  fluctuates  depending  on  timing of
settlement of  outstanding  positions and the movement in commodity  prices.  At
March 31, 2009,  the majority of the  positions  settled were in net  receivable
positions.  Our  commodity  trading  inventory  is carried at fair value and was
higher than year end as  increased  crude oil volumes  and prices  offset  lower
natural  gas  volumes and prices.  The  increase  in other  assets is  primarily
represented by the Dated Brent crude oil put options fair value of $224 million.
The annual  options  mature at the end of 2009 and were reclassed from long-term
to current assets during the first quarter.


OUTLOOK FOR REMAINDER OF 2009

We expect our 2009  production to range between 255,000 and 270,000 boe/d before
royalties,  although  this is largely  dependent on the ramp-up of Long Lake and
the  startup of our  Ettrick and  Longhorn  developments.  We expect to generate
between $2.3 and $2.9 billion in cash flow (before  remediation  and  geological
and geophysical  expenditures) in 2009,  assuming WTI averages between US$50 and
US$65.

Our future liquidity and ability to fund capital requirements  generally depends
upon operating cash flows, our existing  working  capital,  our unused committed
credit facilities,  and our ability to access debt and equity markets. Given the
long cycle  time of some of our  development  projects  and  volatile  commodity
prices,  it is not  unusual in any year for capital  expenditures  to exceed our
cash flow. Changes in commodity prices,  particularly crude oil as it represents
over  80% of our  production,  can  impact  our  operating  cash  flows.  We use
short-term  contracts  to sell  the  majority  of our  oil  and gas  production,
exposing us to short-term  price  movements.  A US$1/bbl change in WTI above and
below  US$60/bbl  is  projected  to increase or decrease our 2009 cash flow from
operating  activities,  after cash taxes, by  approximately  $54 million and $45
million  respectively  ($43  million  and  $36  million,  respectively,  for the
remainder of 2009).  Our exposure to a $0.01 change in the US to Canadian dollar
exchange  rate is  projected  to  increase  or  decrease  our 2009  cash flow by
approximately  $30  million  ($25  million  for the  remainder  of 2009).  While
commodity prices can fluctuate  significantly in the short term, we believe that
over the longer term,  commodity  prices will  increase as a result of growth in
world  demand and delays or  shortages  in supply  growth.  We believe  that our
existing  liquidity and balance sheet  capacity  provides us with the ability to
fund our obligations  during periods of lower commodity prices. We have incurred
approximately 25% of our 2009 planned capital  expenditures to date and acquired
the  additional  15% working  interest  in Long Lake.  During the  quarter,  our
capital has been concentrated on completing the Buzzard  enhancement project and
progressing  the Ettrick  development  in the UK North Sea, and on our shale gas
winter drilling program in Canada.  We expect to invest capital of approximately
$2 billion during the remainder of the year on a variety of projects  including:
i)  bringing  Ettrick on stream and  advancing  work on the fourth  platform  at
Buzzard;  ii) progressing our Usan development project,  offshore Nigeria;  iii)
bringing  Longhorn  in the Gulf of  Mexico on  stream;  and iv)  furthering  our
exploration  and appraisal  opportunities  in key areas such as UK North Sea, US
Gulf of Mexico and our Horn River shale gas play in Canada.

During the first three months of 2009, our capital investment  exceeded our cash
flow from operating  activities.  Capital expenditures  included $757 million to
acquire an additional 15% in the Long Lake Project.  Excluding this acquisition,
our cash flow from operating  activities exceeded our capital  expenditures.  We
currently  have over $2  billion of cash and cash  equivalents  on hand and also
have significant  undrawn  committed credit facilities  available.  At March 31,
2009, we had unsecured  term credit  facilities of US$3.1  billion in place that
are available  until 2012, of which US$1.8  billion was drawn and US$348 million
was used to support  outstanding  letters of credit. We also have  approximately
$584 million of undrawn, uncommitted,  unsecured credit facilities, of which $81
million  was  used  to  support  outstanding  letters  of  credit.  The  average
length-to-maturity of our public debt is approximately 17 years.


CONTRACTUAL OBLIGATIONS, COMMITMENTS AND GUARANTEES

We have assumed  various  contractual  obligations and commitments in the normal
course of our  operations  and  financing  activities.  We have  included  these
obligations and  commitments in our MD&A in our 2008 Form 10-K.  There have been
no significant developments since year end.

CREDIT RATINGS

During the quarter,  Moody's Investor Service,  Inc.  downgraded our senior debt
credit  rating  from Baa2 to Baa3.  There  were no other  changes  in our credit
rating  during the  period.  We  believe  our strong  financial  results,  ample
liquidity and financial flexibility continue to support our credit ratings.


                                       43
<PAGE>

CONTINGENCIES

There are a number of lawsuits and claims pending,  the ultimate result of which
cannot be  ascertained  at this time.  We record  costs as they are  incurred or
become determinable. We believe the resolution of these matters would not have a
material  adverse effect on our liquidity,  consolidated  financial  position or
results of operations.  These matters are described in LEGAL PROCEEDINGS in Item
3 contained in our 2008 Form 10-K.  There have been no significant  developments
since year end.

NEW ACCOUNTING PRONOUNCEMENTS

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

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

In April 2009, FASB issued three final staff  positions to improve  guidance and
disclosures on fair value  measurement and  impairments.  The positions  clarify
fair value  accounting  specifically  regarding  inactive markets and distressed
transactions,   other-than-temporary   impairments   and  expanded   fair  value
disclosures for financial  instruments in interim  periods.  These positions are
effective for interim and annual periods ending after June 15, 2009,  with early
adoption permitted for periods ending after March 15, 2009. We do not expect the
adoption  of  these  positions  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
                                                  -------------------------------------------------------------------------------
                                                              2007             |                 2008                  |    2009
(Cdn$ millions)                                      Jun      Sept       Dec   |  Mar       Jun       Sep        Dec   |    Mar
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                <C>       <C>       <C>      <C>       <C>       <C>        <C>        <C>
Net Sales                                          1,399     1,446     1,598    1,870     2,071     2,213      1,270      1,048

Net Income (Loss)                                    368       403       194      630       380       886       (181)       135

Earnings (Loss) Per Common Share ($/share)
     Basic                                          0.70      0.77      0.37     1.19      0.72      1.68      (0.35)      0.26
     Diluted                                        0.68      0.75      0.36     1.17      0.70      1.66      (0.35)      0.26
                                                  -------------------------------------------------------------------------------
</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,
constitute "forward-looking statements" (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)  or   "forward-looking
information" (within the meaning of applicable Canadian securities legislation).
Such  statements or  information  (together  "forward-looking  statements")  are
generally   identifiable  by  the  forward-looking   terminology  used  such  as
"ANTICIPATE",  "BELIEVE",  "INTEND",  "PLAN",  "EXPECT",  "ESTIMATE",  "BUDGET",
"OUTLOOK", "FORECAST" or other similar words, and include statements relating to
or  associated  with  individual  wells,  regions or  projects.  Any  statements
regarding the following are forward-looking statements:

o    future crude oil, natural gas or chemicals prices;
o    future production levels;
o    future cost recovery oil revenues from our Yemen operations;
o    future  capital  expenditures  and  their  allocation  to  exploration  and
     development activities;
o    future earnings;
o    future asset acquisitions or dispositions;
o    future sources of funding for our capital program;
o    future debt levels;
o    availability of committed credit facilities;
o    possible commerciality;
o    development plans or capacity expansions;
o    future ability to execute dispositions of assets or businesses;
o    future sources of liquidity, cash flows and their uses;
o    future drilling of new wells;
o    ultimate recoverability of current and long-term assets;
o    ultimate recoverability of reserves or resources;
o    expected finding and development costs;
o    expected operations costs;
o    future demand for chemical products;
o    estimates on a per share basis;
o    future foreign currency exchange rates;
o    future   expenditures  and  future  allowances  relating  to  environmental
     matters;
o    dates by which certain areas will be developed or will come on-stream; and
o    changes in any of the foregoing.

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

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

o    market prices for oil and gas and chemical products;
o    our  ability to  explore,  develop,  produce  and  transport  crude oil and
     natural gas to markets;
o    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
     environment 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.

These  risks,  uncertainties  and other  factors and their  possible  impact are
discussed  more  fully  in the  sections  titled  RISK  FACTORS  in  Item 1A and
QUANTITATIVE  AND  QUALITATIVE  DISCLOSURES  ABOUT MARKET RISK in Item 7A of our
2008  Form  10-K.  The  impact  of any one  risk,  uncertainty  or  factor  on a
particular forward-looking statement is not determinable with certainty as these


                                       45
<PAGE>

factors are  interdependent,  and  management's  future  course of action  would
depend on an assessment of all information at that time.

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


ITEM 3.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

At March 31, 2009:

o    over 98% of our credit exposures were investment grade;
o    approximately  85%  of  our  credit  exposures  were  with  integrated  oil
     companies, crude oil refiners and marketers and large utilities; and
o    only one  counterparty  individually  made up more  than 10% of our  credit
     exposure. This counterparty is a major integrated oil company with a strong
     investment grade credit rating.

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


ITEM 4.   CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

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

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

CHANGES IN INTERNAL CONTROLS

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


                                       46
<PAGE>

                                     PART II


ITEM 1.   LEGAL PROCEEDINGS

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


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

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 April 29, 2009.

                                         NEXEN INC.


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



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



                                       47