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, 2010

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

                          COMMISSION FILE NUMBER 1-6702

                                [GRAPHIC OMITTED]
                                   NEXEN INC.

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

                              801 - 7th Avenue S.W.
                        Calgary, Alberta, Canada T2P 3P7
                            Telephone (403) 699-4000
                           Web site - WWW.NEXENINC.COM

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

                  Yes      X                No
                     ---------------          ----------------

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

                  Yes                       No
                     ---------------          ----------------

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

   Large accelerated filer  X   Accelerated filer     Non-Accelerated filer
                          ----                   ---                       ---

                  Smaller reporting company
                                            ---

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

                  Yes                       No       X
                     ---------------          ----------------

On March 31, 2010, there were 524,046,867 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
             Conditionand Results of Operations (MD&A) .......................29
    Item 3.  Quantitative and Qualitative Disclosures about Market Risk ......50
    Item 4.  Controls and Procedures .........................................51
PART II      OTHER INFORMATION
    Item 1.  Legal Proceedings ...............................................52
    Item 6.  Exhibits ........................................................52

This report  should be read in  conjunction  with our 2009 Annual Report on Form
10-K (2009 Form 10-K) and with our  current  reports on Forms 10-Q and 8-K filed
or furnished during the year.

SPECIAL NOTE TO CANADIAN INVESTORS

Nexen is a US Securities  and Exchange  Commission  (SEC)  registrant and a Form
10-K and related forms filer.  Therefore,  our reserves estimates and securities
regulatory  disclosures  generally  follow SEC  requirements.  In 2004,  certain
Canadian  regulatory  authorities adopted NATIONAL INSTRUMENT 51-101 - STANDARDS
OF  DISCLOSURE  FOR OIL AND GAS  ACTIVITIES  (NI 51-101)  which  prescribe  that
Canadian  companies follow certain  standards for the preparation and disclosure
of reserves and related  information.  We have been granted  certain  exemptions
from NI 51-101.  Please refer to the SPECIAL NOTE TO CANADIAN  INVESTORS on page
97 of our 2009 Form 10-K.

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

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

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

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

Electronic  copies  of our  filings  with  the SEC and  the  Ontario  Securities
Commission  (OSC) (from November 8, 2002 onward) are available,  free of charge,
on our web site  (WWW.NEXENINC.COM).  Filings  prior  to  November  8,  2002 are
available free of charge,  upon request,  by contacting  our investor  relations
department at (403) 699-5931. As soon as reasonably practicable, our filings are
made available on our website once they are electronically filed with the SEC or

the OSC. Alternatively, the SEC and the OSC each maintain a website (WWW.SEC.GOV
and WWW.SEDAR.COM) that contains our reports,  proxy and information  statements
and other published  information  that have been filed or furnished with the SEC
and the OSC.

On March 31, 2010,  the noon-day  exchange rate was  US$0.9846 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, 2010 and 2009............................4

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

Unaudited Consolidated Statement of Cash Flows
for the Three Months Ended March 31, 2010 and 2009............................6

Unaudited Consolidated Statement of Equity
for the Three Months Ended March 31, 2010 and 2009............................7

Unaudited Consolidated Statement of Comprehensive Income
for the Three Months Ended March 31, 2010 and 2009............................8

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














                                       3

<PAGE>

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

(Cdn$ millions, except per share amounts)                  2010         2009
----------------------------------------------------  ------------- -----------
REVENUES AND OTHER INCOME
   Net Sales                                                1,501        1,048
   Marketing and Other (Note 14)                              151          257
                                                      ------------- -----------
                                                            1,652        1,305
                                                      ------------- -----------
EXPENSES
   Operating                                                  422          305
   Depreciation, Depletion,
      Amortization and Impairment                             388          409
   Transportation and Other                                   202          201
   General and Administrative                                 118          100
   Exploration                                                 93           53
   Interest (Note 9)                                           80           68
                                                      ------------- -----------
                                                            1,303        1,136
                                                      ------------- -----------

INCOME BEFORE PROVISION FOR INCOME TAXES                      349          169
                                                     ------------- -----------

PROVISION FOR (RECOVERY OF) INCOME TAXES
   Current                                                     259          118
   Future                                                     (100)         (87)
                                                      ------------- -----------
                                                               159           31
                                                      ------------- -----------

NET INCOME                                                    190          138
   Less: Net Income Attributable
      to Canexus Non-Controlling Interests                      5            3
                                                     ------------- -------------

NET INCOME ATTRIBUTABLE TO NEXEN INC.                         185          135
                                                     ============= =============

EARNINGS PER COMMON SHARE ($/share) (Note 15)
   Basic                                                     0.35          0.26
                                                     ============= =============
   Diluted                                                   0.35          0.26
                                                     ============= =============

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)                  2010         2009
------------------------------------------------- ------------- ----------------
ASSETS
   CURRENT ASSETS
      Cash and Cash Equivalents                          1,997            1,700
      Restricted Cash                                      178              198
      Accounts Receivable (Note 2)                       2,635            2,788
      Inventories and Supplies (Note 3)                    574              680
      Other                                                102              185
                                                  ------------- ----------------
         Total Current Assets                            5,486            5,551
                                                  ------------- ----------------

   PROPERTY, PLANT AND EQUIPMENT
      Net of Accumulated Depreciation,
        Depletion, Amortization and Impairment
        of $10,931 (December 31, 2009 - $10,807)        15,381           15,492
   GOODWILL                                                330              339
   FUTURE INCOME TAX ASSETS                              1,238            1,148
   DEFERRED CHARGES AND OTHER ASSETS (Note 5)              328              370
                                                  ------------- ----------------
TOTAL ASSETS                                            22,763           22,900
                                                  ============= ================

LIABILITIES
   CURRENT LIABILITIES
      Accounts Payable and Accrued
          Liabilities (Note 8)                           3,084            3,038
      Accrued Interest Payable                              77               89
      Dividends Payable                                     26               26
                                                  ------------- ----------------
         Total Current Liabilities                       3,187            3,153
                                                  ------------- ----------------

   LONG-TERM DEBT (Note 9)                               7,054            7,251
   FUTURE INCOME TAX LIABILITIES                         2,804            2,811
   ASSET RETIREMENT OBLIGATIONS (Note 11)                  932            1,018
   DEFERRED CREDITS AND OTHER LIABILITIES
     (Note 12)                                             959            1,021

EQUITY
   Nexen Inc. Shareholders' Equity
      Common Shares, no par value
         Authorized:  Unlimited
         Outstanding: 2010 - 524,046,867 shares
                      2009 - 522,915,843 shares          1,076            1,049
      Contributed Surplus                                    -                1
      Retained Earnings                                  6,881            6,722
      Accumulated Other Comprehensive Loss                (201)            (190)
                                                  ------------- ----------------
   Total Nexen Inc. Shareholders' Equity                 7,756            7,582
      Canexus Non-Controlling Interests                     71               64
                                                  ------------- ----------------
   TOTAL EQUITY                                          7,827            7,646
   COMMITMENTS, CONTINGENCIES AND
      GUARANTEES (Note 16)
                                                  ------------- ----------------
TOTAL LIABILITIES AND EQUITY                            22,763           22,900
                                                  ============= ================

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)                                             2010            2009
-------------------------------------------------- ------------- ---------------
OPERATING ACTIVITIES
   Net Income                                               190             138
   Charges and Credits to Income not
      Involving Cash (Note 17)                              265             319
   Exploration Expense                                       93              53
   Changes in Non-Cash Working Capital (Note 17)            256             420
   Other                                                     (6)           (141)
                                                   ------------- ---------------
                                                            798             789

FINANCING ACTIVITIES
   Proceeds from (Repayment of) Term Credit
      Facilities, Net                                         -           1,011
   Proceeds from (Repayment of) Canexus Term
      Credit Facilities, Net                                 22              10
   Dividends Paid on Common Shares                          (26)            (26)
   Distributions Paid to Canexus
      Non-Controlling Interests                              (4)             (4)
   Issue of Common Shares and Exercise of
      Tandem Options for Shares                              25              23
                                                   ------------- ---------------
                                                             17           1,014

INVESTING ACTIVITIES
   Capital Expenditures
       Exploration and Development                         (492)           (702)
       Proved Property Acquisitions                           -            (757)
       Energy Marketing, Chemicals, Corporate
          and Other                                         (64)            (45)
   Proceeds on Disposition of Assets                         15              14
   Changes in Non-Cash Working Capital (Note 17)             88              19
   Changes in Restricted Cash                                15            (314)
   Other                                                     (3)             (2)
                                                   ------------- ---------------
                                                           (441)         (1,787)

EFFECT OF EXCHANGE RATE CHANGES ON CASH AND
   CASH EQUIVALENTS                                         (77)             35
                                                   ------------- ---------------

INCREASE IN CASH AND CASH EQUIVALENTS                       297              51

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

CASH AND CASH EQUIVALENTS - END OF PERIOD (1)             1,997           2,054
                                                   ============= ===============

(1)  Cash and cash equivalents at March 31, 2010 consist of cash of $257 million
     and short-term investments of $1,740 million (March 31, 2009 - cash of $182
     million and short-term investments of $1,872 million).

SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.

                                       6

<PAGE>

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

(Cdn$ millions)                                            2010           2009
------------------------------------------------- ------------- ----------------
COMMON SHARES, Beginning of Period                       1,049              981
      Issue of Common Shares                                24               23
      Exercise of Tandem Options for Shares                  1                -
      Accrued Liability Relating to Tandem
         Options Exercised for Common Shares                 2                -
                                                  ------------- ----------------
   Balance at End of Period                              1,076            1,004
                                                  ============= ================

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

RETAINED EARNINGS, Beginning of Period                   6,722           6,290
      Net Income Attributable to Nexen Inc.                185             135
      Dividends Paid on Common Shares (Note 13)            (26)            (26)
                                                  ------------- ----------------
   Balance at End of Period                              6,881           6,399
                                                  ============= ================

ACCUMULATED OTHER COMPREHENSIVE LOSS,
   Beginning of Period                                    (190)            (134)
      Other Comprehensive Income (Loss)
         Attributable to Nexen Inc.                        (11)               6
                                                  ------------- ----------------
   Balance at End of Period (1)                           (201)            (128)
                                                  ============= ================

(1)  Comprised of unrealized foreign currency translation adjustment.

CANEXUS NON-CONTROLLING INTERESTS, Beginning
   of Period                                                64               52
      Net Income Attributable to
         Non-Controlling Interests                           6                3
      Distributions Paid to Non-Controlling Interests       (4)              (4)
      Issue of Partnership Units to
         Non-Controlling Interests                           5                1
                                                  ------------- ----------------
   Balance at End of Period                                 71               52
                                                  ============= ================

SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.

                                       7

<PAGE>

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

(Cdn$ millions)                                              2010         2009
------------------------------------------------------- ---------- -------------
NET INCOME ATTRIBUTABLE TO NEXEN INC.                         185          135
   Other Comprehensive Income (Loss), Net of
      Income Taxes:
      Foreign Currency Translation Adjustment
         Net Gains (Losses) on Investment in
            Self-Sustaining Foreign Operations               (147)         174
         Net Gains (Losses) on Foreign-Denominated
            Debt Hedges of Self-Sustaining
            Foreign Operations (1)                            136         (168)
                                                        ---------- -------------
      Other Comprehensive Income (Loss)
         Attributable to Nexen Inc.                           (11)           6
                                                        ---------- -------------
COMPREHENSIVE INCOME ATTRIBUTABLE TO NEXEN INC.               174          141
                                                        ========== =============

(1)  Net of income tax expense for the three  months ended March 31, 2010 of $20
     million (2009 - $24 million recovery).

SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.

                                        8

<PAGE>

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

1.   ACCOUNTING POLICIES

Our Unaudited  Consolidated Financial Statements are prepared in accordance with
Canadian  Generally  Accepted  Accounting   Principles  (GAAP).  The  impact  of
significant differences between Canadian and United States GAAP on the Unaudited
Consolidated  Financial  Statements  is  disclosed in Note 20. In the opinion of
management,   the  Unaudited   Consolidated  Financial  Statements  contain  all
adjustments of a normal and recurring  nature  necessary to present fairly Nexen
Inc.'s (Nexen, we or our) financial  position at March 31, 2010 and December 31,
2009 and the results of our  operations  and our cash flows for the three months
ended March 31, 2010 and 2009.

We make estimates and assumptions that affect the reported amounts of assets and
liabilities  and disclosure of contingent  assets and liabilities at the date of
the  Unaudited  Consolidated  Financial  Statements,  and  revenues and expenses
during the  reporting  period.  Our  management  reviews  these  estimates on an
ongoing basis,  including those related to accruals,  litigation,  environmental
and asset retirement  obligations,  recoverability of assets, income taxes, fair
values of derivative assets and liabilities,  capital adequacy and determination
of proved  reserves.  Changes in facts and  circumstances  may result in revised
estimates  and actual  results may differ from these  estimates.  The results of
operations  and cash flows for the three  months  ended  March 31,  2010 are not
necessarily indicative of the results of operations or cash flows to be expected
for the year  ending  December  31,  2010.  As at April 26,  2010,  there are no
material  subsequent events requiring  additional  disclosure in or amendment to
these financial statements.

These Unaudited  Consolidated Financial Statements should be read in conjunction
with our Audited  Consolidated  Financial  Statements  included in our 2009 Form
10-K. The  accounting  policies we follow are described in Note 1 of the Audited
Consolidated Financial Statements included in our 2009 Form 10-K.

CHANGES IN ACCOUNTING POLICIES

Oil and Gas Reserve Estimates
On January 6, 2010, the Financial Accounting Standards Board issued guidance for
OIL AND GAS RESERVE  ESTIMATION  AND  DISCLOSURE,  which is effective  for years
ended  December 31, 2009.  The guidance  expands the  definition  of oil and gas
producing  activities to: i) include  unconventional  sources such as oil sands;
ii) change the price used in reserve  estimation  from the year-end price to the
simple average of the  first-day-of-the-month  price for the previous 12 months,
and iii) require  disclosures for geographic areas that represent 15% or more of
proved reserves.

We  follow  the  successful  efforts  method of  accounting  for our oil and gas
activities,  which use the estimated  proved reserves we believe are recoverable
from our oil and gas properties.  Specifically,  reserves  estimates are used to
calculate our unit-of-production  depletion rates and to assess, when necessary,
our oil and gas assets for impairment.  Adoption of these amendments changed our
estimate of reserves  used to calculate  depletion  in 2010.  As a result of the
amendments,  depletion  expense  for the  three  months  ended  March  31,  2010
increased by $14 million,  net income decreased by $9 million,  and earnings per
common share decreased by $0.02/share.

2.   ACCOUNTS RECEIVABLE

                                                         March 31   December 31
                                                             2010          2009
--------------------------------------------------- -------------- -------------
Trade
   Energy Marketing                                         1,385         1,410
   Energy Marketing Derivative Contracts (Note 6)             267           466
   Oil and Gas                                                867           823
   Chemicals and Other                                         46            44
                                                    -------------- -------------
                                                            2,565         2,743
Non-Trade                                                     123            99
                                                    -------------- -------------
                                                            2,688         2,842
Allowance for Doubtful Receivables                            (53)          (54)
                                                    -------------- -------------
Total                                                       2,635         2,788
                                                    ============== =============

                                       9

<PAGE>

3.   INVENTORIES AND SUPPLIES

                                                        March 31     December 31
                                                          2010           2009
--------------------------------------------------    -----------    -----------
Finished Products
   Energy Marketing                                          442            548
   Oil and Gas                                                25             25
   Chemicals and Other                                        12             12
                                                      -----------    -----------

                                                             479            585
Work in Process                                               10              7
Field Supplies                                                85             88
                                                      -----------    -----------
 Total                                                       574            680
                                                      ===========    ===========

4.   SUSPENDED EXPLORATION WELL COSTS

The  following  table shows the changes in  capitalized  exploratory  well costs
during the three  months  ended March 31, 2010 and the year ended  December  31,
2009,  and  does  not  include  amounts  that  were  initially  capitalized  and
subsequently  expensed in the same period.  Suspended exploration well costs are
included in property, plant and equipment.

                                                Three Months Ended  Year Ended
                                                     March 31       December 31
                                                      2010             2009
------------------------------------------------ ---------------   -------------
Beginning of Period                                         794             518
   Exploratory Well Costs Capitalized Pending
       the Determination of Proved Reserves                 146             396
   Capitalized Exploratory Well Costs Charged
       to Expense                                            (2)            (56)
   Transfers to Wells, Facilities and Equipment
       Based on Determination of Proved Reserves               -            (21)
   Effects of Foreign Exchange Rate Changes                 (14)            (43)
                                                 ---------------   -------------
End of Period                                               924             794
                                                 ===============   =============

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.

                                                          March 31  December 31
                                                           2010         2009
----------------------------------------------------- ------------- ------------
Capitalized for a Period of One Year or Less                   425          383
Capitalized for a Period of Greater than One Year              499          411
                                                      ------------- ------------
Total                                                          924          794
                                                      ============= ============

Number of Projects that have Exploratory Well Costs
   Capitalized for a Period Greater than One Year               13           12
                                                      ------------- ------------


                                       10

<PAGE>
As at March 31, 2010, we have  exploratory  costs that have been capitalized for
more than one year relating to our interests in eight exploratory  blocks in the
North Sea ($174  million),  certain  coalbed  methane and shale gas  exploratory
activities  in Canada  ($194  million),  two  exploratory  blocks in the Gulf of
Mexico ($113 million), and our interest in an exploratory block offshore Nigeria
($18 million).  These costs relate to projects with successful exploration wells
for which we have not been able to recognize proved  reserves.  We are assessing
all of these wells and  projects,  and are working  with our partners to prepare
development  plans,  drill  additional   appraisal  wells  or  otherwise  assess
commercial viability.

Aging of Suspended
Exploration Wells Greater   United                United
than One Year              Kingdom     Canada     States    Nigeria     Total
------------------------- ---------- ---------- ---------- ---------- ----------
1-3 years                       119        194         42          -        355
4-5 years                        55          -         71          -        126
Greater than 5 years              -          -          -         18         18
                          ---------- ---------- ---------- ---------- ----------
Total                           174        194        113         18        499
                          ========== ========== ========== =========+ ==========

5.   DEFERRED CHARGES AND OTHER ASSETS

                                                       March 31     December 31
                                                        2010            2009
-------------------------------------------------- --------------- -------------
Long-Term Energy Marketing Derivative
   Contracts (Note 6)                                       200             225
Crude Oil Put Options and Natural Gas
   Swaps (Note 6)                                             -               4
Defined Benefit Pension Assets                               56              60
Long-Term Capital Prepayments                                23              27
Other                                                        49              54
                                                   --------------- -------------
Total                                                       328             370
                                                   =============== =============

6.   FINANCIAL INSTRUMENTS

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

In our energy  marketing  group,  we enter into  contracts  to purchase and sell
crude  oil,  natural  gas and  other  energy  commodities,  and  use  derivative
contracts,  including  futures,  forwards,  swaps and  options,  for hedging and
trading purposes (collectively  derivatives).  We also use derivatives to manage
commodity  price risk and foreign  currency risk for  non-trading  purposes.  We
categorize our derivative  instruments as trading or non-trading  activities and
carry the  instruments  at fair  value on our  balance  sheet.  The  derivatives
section below details our  derivatives and fair values as at March 31, 2010. The
fair values are included with accounts  receivable or payable and are classified
as long-term or short-term  based on anticipated  settlement date. Any change in
fair value is included in marketing and other income.  Related amounts posted as
margin for exchange traded positions are recorded in restricted cash.

We carry our long-term debt at amortized cost using the effective  interest rate
method.  At March 31, 2010,  the estimated  fair value of our long-term debt was
$7,337 million  (December 31, 2009 - $7,594 million) as compared to the carrying
value of $7,054 million (December 31, 2009 - $7,251 million).  The fair value of
long-term  debt is  estimated  based on prices  provided  by quoted  markets and
third-party brokers.

                                       11

<PAGE>

DERIVATIVES

(a)  DERIVATIVE CONTRACTS RELATED TO TRADING ACTIVITIES

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

                                                          March 31  December 31
                                                              2010         2009
------------------------------------------------------- ----------- ------------
  Commodity Contracts                                          267          463
  Foreign Exchange Contracts                                     -            3
                                                        ----------- ------------
   Accounts Receivable (Note 2)                                267          466
                                                        ----------- ------------

  Commodity Contracts                                          200          225
                                                        ----------- ------------
   Deferred Charges and Other Assets (Note 5)(1)               200          225
                                                        ----------- ------------

Total Trading Derivative Assets                                467          691
                                                        =========== ============

  Commodity Contracts                                          212          410
  Foreign Exchange Contracts                                    13           46
                                                        ----------- ------------
   Accounts Payable and Accrued Liabilities (Note 8)           225          456
                                                        ----------- ------------

  Commodity Contracts                                          198          212
  Foreign Exchange Contracts                                     1            -
                                                        ----------- ------------
   Deferred Credits and Other Liabilities (Note 12)            199          212
                                                        ----------- ------------

Total Trading Derivative Liabilities                           424          668
                                                        =========== ============

Total Net Trading Derivative Contracts                          43           23
                                                        =========== ============

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

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

                                                     March 31      December 31
                                                      2010             2009
--------------------------------------------- ---------------- ----------------
Current Trading Assets                                  2,116            2,625
Non-Current Trading Assets                                613              716
                                              ---------------- ----------------
  Total Trading Derivative Assets                       2,729            3,341
                                              ================ ================

Current Trading Liabilities                             2,074            2,615
Non-Current Trading Liabilities                           612              703
                                              ---------------- ----------------
  Total Trading Derivative Liabilities                  2,686            3,318
                                              ================ ================

                                              ---------------- ----------------
Total Net Trading Derivative Contracts                     43               23
                                              ================ ================

                                       12
<PAGE>

Trading  revenues  generated by our energy  marketing  group  include  gains and
losses on derivative instruments and non-derivative instruments such as physical
inventory.  During the three months ended March 31, 2010 and 2009, the following
trading revenues were recognized in marketing and other income:

                                                   Three Months Ended March 31
                                                      2010            2009
----------------------------------------------- ---------------- ---------------
Commodity                                                    91             270
Foreign Exchange                                             (5)             (3)
                                                ---------------- ---------------
  Marketing Revenue                                          86             267
                                                ================ ===============

As an energy marketer,  we may undertake several transactions during a period to
execute a single sale of physical  product.  Each transaction may be represented
by one or more derivative  instruments  including a physical buy, physical sell,
and in many cases,  numerous  financial  instruments  for  economic  hedging and
trading purposes.  The absolute notional volumes  associated with our derivative
instrument  transactions for the three months ended March 31, 2010 and 2009, are
as follows:

                                                     Three Months Ended March 31
                                                            2010           2009
------------------------------------------------- --------------- --------------
Natural Gas                            bcf/d                15.2           28.6
Crude Oil                           mmbbls/d                 3.3            3.8
Power                                  GWh/d               280.8          212.3
Foreign Exchange                US$ millions                 787            378
Foreign Exchange               Euro millions                  53            153
                                                  --------------- --------------

(b)  DERIVATIVE CONTRACTS RELATED TO NON-TRADING ACTIVITIES

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

                                                          March 31  December 31
                                                              2010        2009
----------------------------------------------------- ------------- -----------
Accounts Receivable                                              1          13
Deferred Charges and Other Assets (Note 5) (1)                   -           4
                                                      ------------- -----------
  Total Non-Trading Derivative Assets                            1          17
                                                      ============= ===========

Accounts Payable and Accrued Liabilities (Note 8)               20          26
                                                      ------------- -----------
  Total Non-Trading Derivative Liabilities                      20          26
                                                      ============= ===========
  Total Net Non-Trading Derivative Assets (2)                  (19)         (9)
                                                      ============= ===========

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

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

CRUDE OIL PUT OPTIONS
In 2009,  we  purchased  put  options  on 90,000  bbls/d  of our 2010  crude oil
production  for $39  million.  These  options  establish  a WTI  floor  price of
US$50/bbl on these volumes and provide a base level of price protection  without
limiting our upside to higher prices.  Options on 60,000 bbls/d settle  monthly,
while the remaining options settle annually.  These options are recorded at fair
value  throughout  their term. As a result,  changes in forward crude oil prices
create  gains or losses on these  options at each period end. At March 31, 2010,
higher crude oil prices  reduced the fair value of the options to  approximately
$1  million,  and we recorded a fair value loss during the period of $16 million
in marketing and other income.

<TABLE>
<CAPTION>
                                                                                Three Months Ended March 31, 2010
                                                                                --------------------------------
                                          Notional                   Average          Fair          Change in
                                           Volumes        Term     Floor Price        Value         Fair Value
------------------------------------- -------------- ---------- --------------- -------------- -----------------
                                          (bbls/d)      (US$/bbl)
<S>                                         <C>           <C>               <C>           <C>              <C>
WTI Crude Oil Put Options (monthly)         60,000        2010              50            1                (12)
WTI Crude Oil Put Options (annual)          30,000        2010              50            -                 (4)
                                                                                -------------- -----------------
                                                                                          1                (16)
                                                                                ============== =================
</TABLE>

                                       13
<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 current based on their  anticipated
settlement  date.  Any change in fair value is included in  marketing  and other
income.

<TABLE>
<CAPTION>
                                                                               Three Months Ended March 31, 2010
                                                                               ----------------------------------
                                          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       2010            2.28               (4)               (7)
Natural Gas Swaps                           15,514       2010            7.60              (16)                7
                                                                               ---------------- -----------------
                                                                                           (20)                -
                                                                               ================ =================
</TABLE>

(c)  FAIR VALUE OF DERIVATIVES

Our processes for  estimating and  classifying  the fair value of our derivative
contracts are consistent with those in place at December 31, 2009. The following
table  includes  our  derivatives  carried  at fair  value for our  trading  and
non-trading  activities as at March 31, 2010.  Financial  assets and liabilities
are classified in the fair value hierarchy in their entirety based on the lowest
level of input that is significant to the fair value measurement.  Assessment of
the  significance of a particular input to the fair value  measurement  requires
judgment and may affect placement within the fair value hierarchy levels.

Net Derivatives at March 31, 2010       Level 1   Level 2   Level 3      Total
-------------------------------------- --------- --------- --------- ----------
  Commodity Contracts                      (156)      175        38         57
  Foreign Exchange Contracts                  -       (14)        -        (14)
                                       --------- --------- --------- ----------
Trading Derivatives                        (156)      161        38         43
Non-Trading Derivatives                       -       (19)        -        (19)
                                       --------- --------- --------- ----------
Total                                      (156)      142        38         24
                                       ========= ========= ========= ==========

A reconciliation  of changes in the fair value of our derivatives  classified as
Level 3 for the three months ended March 31, 2010 is provided below:

                                                                        Level 3
---------------------------------------------------------------- ---------------
Beginning of Period                                                          42
  Realized and Unrealized Gains (Losses)                                      7
  Purchases                                                                   -
  Settlements                                                               (11)
  Transfers Into Level 3                                                      -
  Transfers Out of Level 3                                                    -
                                                                 ---------------
End of Period                                                                38
                                                                 ===============

Unsettled gains relating to instruments still
  held as of March 31, 2010                                                   7
                                                                 ===============

Items classified in Level 3 are generally economically hedged such that gains or
losses on positions classified in Level 3 are often offset by gains or losses on
positions classified in Level 1 or 2. Transfers into or out of Level 3 represent
existing assets and  liabilities  that were either  previously  categorized as a
higher level for which the inputs became  unobservable or assets and liabilities
that were  previously  classified  as Level 3 for which the  lowest  significant
input became observable during the period. Fair values of instruments in Level 3
are determined using broker quotes,  pricing  services and  internally-developed
inputs. We performed a sensitivity analysis of inputs used to calculate the fair
value of Level 3 instruments. Using reasonably possible alternative assumptions,
the fair value of Level 3 instruments  would change by $13 million (December 31,
2009 - $12 million).

                                       14
<PAGE>

7.   RISK MANAGEMENT

(a)  MARKET RISK

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

The following  market risk  discussion  focuses on the commodity  price risk and
foreign  currency risk related to our financial  instruments  as our exposure to
interest rate risk is  immaterial,  given that the majority of our debt is fixed
rate.

COMMODITY PRICE RISK

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

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

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

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

We also seek to profit from our views on the future movement of energy commodity
pricing  relationships,  primarily between different locations,  time periods or
product  qualities.  We do this by holding  open  positions,  where the terms of
physical  or  financial  contracts  are not  completely  matched  to  offsetting
positions.

Our risk management  activities include prescribed capital limits and the use of
tools  such as  Value-at-Risk  (VaR)  and  stress  testing  consistent  with the
methodology used at December 31, 2009. Our period end, high, low and average VaR
amounts for the three  months  ended March 31, 2010 and the year ended  December
31, 2009, are as follows:
                                          Three Months Ended    Year Ended
                                               March 31        December 31
Value-at-Risk                                   2010               2009
--------------------------------------- -------------------- ------------------
Period End                                               13                 11
High                                                     15                 24
Low                                                       9                  9
Average                                                  12                 15
                                        -------------------- ------------------

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

                                       15
<PAGE>

FOREIGN CURRENCY RISK

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

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

In our oil and gas operations,  we manage our exposure to  fluctuations  between
the US and  Canadian  dollar  by  matching  our  expected  net  cash  flows  and
borrowings  in  the  same  currency.  Cash  inflows  generated  by  our  foreign
operations and borrowings on our US-dollar debt facilities are generally used to
fund US-dollar capital  expenditures and debt repayments.  We maintain revolving
Canadian and US-dollar borrowing facilities that can be used or repaid depending
on expected net cash flows.

We designate  most of our US-dollar  borrowings as a hedge against our US-dollar
net investment in self-sustaining foreign operations. The foreign exchange gains
or losses related to the effective portion of our designated  US-dollar debt are
included in accumulated other comprehensive income in shareholders'  equity. Our
net  investment  in  self-sustaining   foreign  operations  and  our  designated
US-dollar debt at March 31, 2010 and December 31, 2009 are as follows:

                                                        March 31     December 31
(US$ millions)                                            2010            2009
---------------------------------------------------- ------------- -------------
Net Investment in Self-Sustaining Foreign Operations      4,523           4,492
Designated US-Dollar Debt                                 4,523           4,492
                                                     ------------- -------------

For the three month period ended March 31, 2010, the ineffective  portion of our
US-dollar  debt  resulted in a net  foreign  exchange  gain of $21 million  ($19
million,  net of income tax  expense)  and is  included in  marketing  and other
income.  A one cent change in the US dollar to  Canadian  dollar  exchange  rate
would  increase  or  decrease  our  accumulated  other  comprehensive  income by
approximately $45 million, net of income tax, and would increase or decrease our
net income by approximately $6 million, net of income tax.

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

(b)  CREDIT RISK

Credit risk affects our oil, gas and chemicals  operations,  and our trading and
non-trading derivative activities,  and is the risk of loss if counterparties do
not fulfill their contractual  obligations.  Most of our credit exposure is with
counterparties  in the energy  industry,  including  integrated  oil  companies,
refiners  and  utilities,  and are  subject  to  normal  industry  credit  risk.
Approximately  70% of our  exposure is with these large energy  companies.  This
concentration of risk within the energy industry is reduced because of our broad
base of domestic and international counterparties.  Our processes to manage this
risk are consistent with those in place at December 31, 2009.

At March 31, 2010, only two counterparties individually made up more than 10% of
our credit  exposure.  These  counterparties  are major integrated oil companies
with a strong  investment grade credit rating. 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                                           2010          2009
------------------------------------------------- --------------- -------------
A or higher                                                  67%             67%
BBB                                                          25%             26%
Non-Investment Grade                                          8%              7%
                                                  --------------- -------------
TOTAL                                                       100%            100%
                                                  =============== =============

                                       16

<PAGE>

Our maximum  counterparty  credit  exposure at the balance  sheet date  consists
primarily of the carrying  amounts on  non-derivative  financial  assets such as
cash and cash equivalents,  restricted cash, accounts receivable, as well as the
fair value of  derivative  financial  assets.  We provided an  allowance  of $53
million for credit risk with our counterparties. In addition, we incorporate the
credit risk associated with counterparty  default, as well as Nexen's own credit
risk, into our estimates of fair value.

Collateral received from customers at March 31, 2010 includes $1 million of cash
and $319 million of letters of credit. The cash received is included in accounts
payable and accrued liabilities.

(c)  LIQUIDITY RISK

Liquidity  risk  is the  risk  that we will  not be able to meet  our  financial
obligations as they fall due. We require liquidity  specifically to fund capital
requirements, satisfy financial obligations as they come due, and to operate our
energy marketing business.  We generally rely on operating cash flows to provide
liquidity and we also maintain  significant undrawn committed credit facilities.
At March 31,  2010,  we had  approximately  $3.6  billion of cash and  available
committed lines of credit. This includes $2 billion of cash and cash equivalents
on hand and  undrawn  term  credit  facilities  of $1.6  billion,  of which $391
million was supporting letters of credit at March 31, 2010. These facilities are
available  until  2012  unless  extended.  We also have  about  $466  million of
undrawn,  uncommitted  credit  facilities,  of which $116 million was supporting
letters of credit at March 31, 2010.

The following  table details the contractual  maturities for our  non-derivative
financial  liabilities,  including both the principal and interest cash flows at
March 31, 2010:

                                          Less than                    More than
                                   Total   1 Year   1-3 Years 4-5 Years  5 Years
------------------------------ ---------- -------- ---------- --------- --------
Long-Term Debt                     7,144        -      1,771       854    4,519
Interest on Long-Term Debt (1)     7,724      350        700       658    6,016
                               ---------- -------- ---------- --------- --------
Total                             14,868      350      2,471     1,512   10,535
                               ========== ======== ========== ========= ========

(1)  Excludes  interest  on  term  credit  facilities  of $1.5  billion  (US$1.5
     billion)  and  Canexus  term  credit  facilities  of $247  million  (US$244
     million) as the amounts drawn on the facilities fluctuate. Based on amounts
     drawn at March 31, 2010 and existing  variable  interest rates, we would be
     required to pay $18 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.

                                       Less than                      More than
                                 Total   1 Year  1-3 Years  4-5 Years  5 Years
-------------------------------- ----- --------- ---------- --------- ----------
Trading Derivatives (Note 6)      424       225        173        26          -
Non-Trading Derivatives (Note 6)   20        20         -         -           -
                                 ----- --------- ---------- --------- ----------
Total                             444       245        173        26          -
                                 ===== ========= ========== ========= ==========

The commercial  agreements our energy  marketing  group enter into often include
financial  assurance   provisions  that  allow  us  and  our  counterparties  to
effectively manage credit risk. The agreements normally require collateral to be
posted  if an  adverse  credit-related  event  occurs,  such as a drop in credit
ratings to  non-investment  grade.  Based on  contracts  in place and  commodity
prices at March 31,  2010,  we could be  required  to post  collateral  of up to
$1,016 million if we were downgraded to non-investment  grade. These obligations
are  reflected  on our  balance  sheet.  The posting of  collateral  secures the
payment of such amounts.  In the event of a ratings  downgrade,  we have trading
inventories  and  receivables  that can be quickly  monetized as well as undrawn
credit facilities.

At March 31, 2010, collateral posted with counterparties  includes $5 million of
cash and $299  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 $178 million (December 31, 2009 - $198
million), which have been included in restricted cash.

                                       17
<PAGE>

8.   ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

                                                      March 31     December 31
                                                       2010           2009
-------------------------------------------------- ------------- ---------------
Energy Marketing Payables                                 1,422           1,366
Energy Marketing Derivative Contracts (Note 6)              225             456
Accrued Payables                                            615             619
Trade Payables                                              245             210
Income Taxes Payable                                        233             179
Stock-Based Compensation                                     68              72
Other                                                       276             136
                                                   ------------- ---------------
Total                                                     3,084           3,038
                                                   ============= ===============

9.   SHORT-TERM BORROWINGS AND LONG-TERM DEBT

                                                        March 31    December 31
                                                          2010          2009
----------------------------------------------------- ------------- ------------
Canexus Term Credit Facilities, due 2012
   (US$244 million drawn) (a)                                  247          233
Term Credit Facilities, due 2012
   (US$1.5 billion drawn) (b)                                1,523        1,570
Canexus Notes, due 2013 (US$50 million)                         51           52
Notes, due 2013 (US$500 million)                               508          523
Canexus Convertible Debentures, due 2014                        41           46
Notes, due 2015 (US$250 million)                               254          262
Notes, due 2017 (US$250 million)                               254          262
Notes, due 2019 (US$300 million)                               305          314
Notes, due 2028 (US$200 million)                               203          209
Notes, due 2032 (US$500 million)                               508          523
Notes, due 2035 (US$790 million)                               802          827
Notes, due 2037 (US$1,250 million)                           1,270        1,308
Notes, due 2039 (US$700 million)                               711          733
Subordinated Debentures, due 2043
   (US$460 million)                                            467          481
                                                      ------------- ------------
                                                             7,144        7,343
Unamortized Debt Issue Costs                                   (90)         (92)
                                                      ------------- ------------
Total                                                        7,054        7,251
                                                      ============= ============

(a)  CANEXUS TERM CREDIT FACILITIES

Canexus has $450  million  (US$444  million) of  committed,  secured term credit
facilities  available  until  2012.  At March 31,  2010,  $247  million  (US$244
million) was drawn on these facilities (December 31, 2009 - $233 million (US$223
million)).   Borrowings   are  available  as  Canadian   bankers'   acceptances,
LIBOR-based  loans,  Canadian  prime rate loans or  US-dollar  base rate  loans.
Interest is payable  monthly at floating rates.  The term credit  facilities are
secured by a floating charge debenture over all of Canexus'  assets.  The credit
facility also contains  covenants  with respect to certain  financial  ratios of
Canexus.  The  weighted-average   interest  rate  on  the  Canexus  term  credit
facilities  was 1.5% for the three  months  ended March 31,  2010 (three  months
ended March 31, 2009 - 2.7%).

(b)  TERM CREDIT FACILITIES

We have  unsecured  term credit  facilities  of $3.1  billion  (US$3.1  billion)
available until 2012. At March 31, 2010, $1.5 billion (US$1.5 billion) was drawn
on  these  facilities  (December  31,  2009 - $1.6  billion  (US$1.5  billion)).
Borrowings are available as Canadian bankers'  acceptances,  LIBOR-based  loans,
Canadian prime rate loans,  US-dollar base rate loans or British pound call-rate
loans. Interest is payable at floating rates. The weighted-average interest rate
on our term credit facilities was 0.9% for the three months ended March 31, 2010
(three  months  ended March 31, 2009 - 1.1%).  At March 31,  2010,  $391 million
(US$385  million)  of these  facilities  were  utilized  to support  outstanding
letters of credit (December 31, 2009 - $407 million (US$389 million)).

                                       18

<PAGE>

(c)  INTEREST EXPENSE

                                                    Three Months Ended March 31
                                                    ---------------------------
                                                         2010       2009
-------------------------------------------------   ------------- -------------
Long-Term Debt                                                94            89
Other                                                          4             5
                                                    ------------- -------------
Total                                                         98            94
   Less: Capitalized                                         (18)          (26)
                                                    ------------- -------------
Total                                                         80            68
                                                    ============= =============

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

(d)  SHORT-TERM BORROWINGS

Nexen has uncommitted, unsecured credit facilities of approximately $466 million
(US$459 million),  none of which were drawn at March 31, 2010 (December 31, 2009
- nil). We utilized $116 million (US$114 million) of these facilities to support
outstanding letters of credit at March 31, 2010 (December 31, 2009 - $86 million
(US$82 million)). Interest is payable at floating rates.

10.  CAPITAL MANAGEMENT

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

                                                      March 31     December 31
                                                        2010           2009
------------------------------------------------- --------------- --------------
NET DEBT (1)
  Long-Term Debt                                           7,054          7,251
     Less: Cash and Cash Equivalents                      (1,997)        (1,700)
                                                  --------------- --------------
Total                                                      5,057          5,551
                                                  =============== ==============

EQUITY (2)                                                 7,827          7,646
                                                  =============== ==============

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

We monitor the leverage in our capital  structure by reviewing  the ratio of net
debt to adjusted cash flow (cash flow from operating  activities  before changes
in non-cash  working capital and other) and interest  coverage ratios at various
commodity prices. Net debt and adjusted cash flow are non-GAAP measures that are
unlikely to be comparable to similar measures  presented by others. We calculate
net debt using the GAAP  measures of long-term  debt and  short-term  borrowings
less cash and cash equivalents (excluding restricted cash).

We use the ratio of net debt to  adjusted  cash flow as a key  indicator  of our
leverage and to monitor the strength of our balance sheet. For the twelve months
ended March 31, 2010,  the net debt to adjusted cash flow was 2.2 times compared
to 2.5 times at December 31, 2009. While we typically expect the target ratio to
fluctuate between 1.0 and 2.0 times under normalized  commodity prices, this can
be higher or lower depending on commodity price  volatility,  when we are in the
investment  cycle,  or  when  we  identify  strategic   opportunities  requiring
additional investment. Whenever we exceed our target ratio, we assess whether we
need to 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 increased from 8.5
times at the end of 2009 to 8.9 times at March 31,  2010.  Interest  coverage is
calculated  by  dividing  our  adjusted   EBITDA  by  interest   expense  before
capitalized  interest.  Adjusted EBITDA is a non-GAAP measure that is calculated
using net  income  excluding  interest  expense,  provision  for  income  taxes,
exploration  expenses,   DD&A,  impairment  and  other  non-cash  expenses.  The
calculation of adjusted EBITDA is set out in the following table and is unlikely
to be comparable to similar measures presented by others.

                                       19

<PAGE>

                                                   Twelve Months   Year Ended
                                                   Ended March 31  December 31
                                                       2010           2009
-------------------------------------------------- ------------- ------------
Net Income Attributable to Nexen Inc.                       586          536
  Add:
     Interest Expense                                       324          312
     Provision for Income Taxes                             388          260
     Depreciation, Depletion, Amortization
       and Impairment                                     1,781        1,802
     Exploration Expense                                    342          302
     Recovery of Non-Cash Stock-Based Compensation          (11)         (10)
     Change in Fair Value of Crude Oil Put Options          251          251
     Other Non-Cash Expenses                               (153)        (136)
                                                   ------------- ------------
Adjusted EBITDA                                           3,508        3,317
                                                   ============= ============

11.  ASSET RETIREMENT OBLIGATIONS

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

                                                     Three Months    Year Ended
                                                    Ended March 31   December 31
                                                         2010           2009
--------------------------------------------------- -------------- -------------
Balance at Beginning of Period                              1,053         1,059
  Obligations Incurred with Development Activities              7            27
  Obligations Settled                                         (11)          (42)
  Accretion Expense                                            17            70
  Revisions to Estimates                                      (32)           13
  Effects of Changes in Foreign Exchange Rate                 (38)          (74)
                                                    -------------- -------------
Balance at End of Period (1), (2)                             996         1,053
                                                    ============== =============

(1)  Obligations  due within 12 months of $64 million  (December  31, 2009 - $35
     million) have been included in accounts payable and accrued liabilities.

(2)  Obligations  relating to our oil and gas activities  amount to $962 million
     (December  31,  2009 - $1,002  million)  and  obligations  relating  to our
     chemicals business amount to $34 million (December 31, 2009 - $51 million).

Our total estimated undiscounted inflated asset retirement obligations amount to
$2,261  million  (December 31, 2009 - $2,341  million).  We discounted the total
estimated  asset  retirement  obligations  using  a  weighted-average,   credit-
adjusted,  risk-free rate of 5.9%.  Approximately  $298 million  included in our
asset retirement obligations is expected to be settled over the next five years.
The remaining obligations settle beyond five years and are expected to be funded
by future cash flows from our operations.

12.  DEFERRED CREDITS AND OTHER LIABILITIES

                                                          March 31  December 31
                                                              2010         2009
------------------------------------------------------- ----------- ------------
Deferred Tax Credit                                            460          503
Long-Term Energy Marketing Derivative Contracts (Note 6)       199          212
Defined Benefit Pension Obligations                             75           76
Capital Lease Obligations                                       60           61
Deferred Transportation Revenue                                 52           55
Other                                                          113          114
                                                        ----------- ------------
Total                                                          959        1,021
                                                        =========== ============

                                       20
<PAGE>

13.  SHAREHOLDERS' EQUITY

DIVIDENDS

Dividends  per common share for the three months ended March 31, 2010 were $0.05
per common share (2009 - $0.05). Dividends paid to holders of common shares have
been designated as "eligible dividends" for Canadian tax purposes.

14.  MARKETING AND OTHER INCOME
                                                     Three Months Ended March 31
                                                     ---------------------------
                                                         2010          2009
---------------------------------------------------- ------------ -------------
Marketing Revenue, Net                                        86           267
Long Lake Purchased Bitumen Sales                             28             -
Change in Fair Value of Crude Oil Put Options                (16)          (16)
Interest                                                       4             2
Foreign Exchange Gains                                        34            19
Other                                                         15           (15)
                                                     ------------ -------------
Total                                                        151           257
                                                     ============ =============

15.  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)                                         2010         2009
---------------------------------------------------- ------------- -------------
Weighted-average number of common shares outstanding        523.6         520.2
Shares issuable pursuant to tandem options                    6.3           7.6
Shares notionally purchased from proceeds of
   tandem options                                            (4.8)         (5.1)
                                                     ------------- -------------
Weighted-average number of diluted common shares
   outstanding                                               525.1        522.7
                                                     ============= =============

In calculating the weighted-average  number of diluted common shares outstanding
for the three  months  ended  March 31,  2010,  we  excluded  16,476,455  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, 2009, 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.

16.  COMMITMENTS, CONTINGENCIES AND GUARANTEES

As  described  in  Note  15 to the  Audited  Consolidated  Financial  Statements
included  in our 2009  Form  10-K,  there are a number of  lawsuits  and  claims
pending,  the ultimate  results of which cannot be  ascertained at this time. We
record costs as they are incurred or become determinable. We continue to believe
the resolution of these matters would not have a material  adverse effect on our
liquidity, consolidated financial position or results of operations.

During the quarter,  we sold our European gas and power marketing  business.  We
agreed to maintain our parental guarantees to the existing  counterparties until
the purchaser is able to replace them. The  guarantees  expire at the earlier of
the purchaser  replacing the  guarantees  and July 25, 2010. We are obligated to
perform under the guarantees only if the purchaser does not meet its obligations
to the  counterparties.  Our  total  exposure  is $275  million  for  which  the
purchaser has provided us with an indemnity and a letter of credit from a highly
rated financial institution.


                                       21
<PAGE>

17.  CASH FLOWS

(a)  CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH

                                                     Three Months Ended March 31
                                                     ---------------------------
                                                           2010        2009
---------------------------------------------------- -------------- ------------
Depreciation, Depletion, Amortization and Impairment           388          409
Stock-Based Compensation                                        (1)           -
Loss (Gains) on Disposition of Assets                            3           (7)
Recovery of Future Income Taxes                               (100)         (87)
Change in Fair Value of Crude Oil Put Options                   16           16
Foreign Exchange                                               (41)         (13)
Other                                                            -            1
                                                     -------------- ------------
Total                                                          265          319
                                                     ============== ============

(b)  CHANGES IN NON-CASH WORKING CAPITAL

                                                     Three Months Ended March 31
                                                          2010          2009
---------------------------------------------------- -------------- ------------
   Accounts Receivable                                        (218)         298
   Inventories and Supplies                                    113          (49)
   Other Current Assets                                         73           (8)
   Accounts Payable and Accrued Liabilities                    385          185
   Other Current Liabilities                                    (9)          13
                                                     -------------- ------------
Total                                                          344          439
                                                     ============== ============

Relating to:
   Operating Activities                                        256          420
   Investing Activities                                         88           19
                                                     -------------- ------------
Total                                                          344          439
                                                     ============== ============
(c)      OTHER CASH FLOW INFORMATION

                                                     Three Months Ended March 31
                                                          2010          2009
--------------------------------------------------- -------------- -------------
Interest Paid                                                 103            81
Income Taxes Paid                                             207            34
                                                    -------------- -------------

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, 2010 (2009 - $12 million).

18.  SUBSEQUENT EVENTS

In April 2010, we substantially completed negotiations for the sale of our North
American natural gas marketing business subject to finalizing  documentation and
customary  closing  conditions.  We expect to sign the  agreement  in the second
quarter and close the sale in the third quarter. The sale is expected to be cash
neutral and we expect to  recognize a non-cash  loss on the sale of between $250
and $290  million.  This loss  primarily  relates to the  transfer of  long-term
natural gas physical  transportation  commitments  that are less  valuable  with
increased  gas supplies that reduce the need for  transport  services.  Although
volatile on a quarterly  basis, we have had success with our marketing  business
over the last 10 years generating about $800 million of cash.


                                       22
<PAGE>

19.  OPERATING SEGMENTS AND RELATED INFORMATION

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

THREE MONTHS ENDED MARCH 31, 2010

<TABLE>
<CAPTION>

                                                                                            Energy             Corporate
                                                       Oil and Gas                        Marketing  Chemicals  and Other    Total
----------------------------- ----------------------------------------------------------- ---------- ---------- ----------- --------
                           United                        United              Other
                            Kingdom   Canada   Syncrude  States    Yemen    Countries(1)
                          ---------- --------- -------- --------- --------- -----------
<S>                      <C>        <C>        <C>      <C>       <C>       <C>         <C>          <C>       <C>          <C>
Net Sales                      755      180        134       113       182         15           9         113          -      1,501
Marketing and Other              5       28          1         -         5          -          83           7          22(2)    151
                         ---------- ---------  -------- --------- --------- ----------  ----------  ---------- -----------  --------
Total Revenues                 760       208       135       113       187         15          92         120          22     1,652

Less: Expenses
  Operating                     77       134        67        22        41          1          10         70            -       422
  Depreciation, Depletion,
   Amortization and
     Impairment                168        80        13        64        35          2           5          11          10       388
  Transportation and Other      (1)       56         7         2         3          -         123          12           -       202
  General and
  Administrative (3)            13        16         -        11         1          8          21           8          40       118
  Exploration                   24         7         -        16         -         46(4)        -           -           -        93
  Interest                       -         -         -         -         -          -           -           1          79        80
                         ---------- ---------  -------- --------- --------- ----------  ----------  ---------- -----------  --------
Income (Loss)
  before Income Taxes          479       (85)       48        (2)      107        (42)        (67)         18        (107)      349
Less: Provision for
(Recovery                      240       (21)       12        (1)       37        (38)        (23)          4         (51)      159
  of) Income Taxes
Less: Non-Controlling
  Interests                      -         -         -         -         -          -           -           5           -         5
                         ---------- ---------  -------- --------- --------- ----------  ----------  ---------- -----------  --------
NET INCOME (LOSS)              239       (64)       36        (1)       70         (4)        (44)          9         (56)      185
                         ========== =========  ======== ========= ========= ==========  ==========  ========== ===========  ========

IDENTIFIABLE ASSETS          4,696     7,848(5)  1,292     1,717       257      1,141       2,588(6)       701       2,523    22,763
                         ========== =========  ======== ========= ========= ==========  ==========   ========== =========== ========

Capital Expenditures
  Development and Other         88        70        19        15        10         91           9          49           6       357
  Exploration                   41        68         -        49         -         41           -           -           -       199
                         ---------- ---------  -------- --------- --------- ----------  ----------   ---------- ----------- --------
TOTAL                          129       138        19        64        10        132           9          49           6       556
                         ========== =========  ======== ========= ========= ==========  ==========  ========== ===========  ========

Property, Plant and
Equipment
  Cost                       6,027     9,781    1,482     3,828     2,397        991        265      1,164          377     26,312
  Less: Accumulated DD&A     2,745     2,108      281     2,504     2,286         97         88        570          252     10,931
                         ---------- ---------  -------- --------- --------- ---------- ----------  ---------- -----------  --------
NET BOOK VALUE               3,282     7,673(5)   1,201     1,324       111        894       177         594          125     15,381
                         ========== =========  ======== ========= ========= ========== ==========  ========== ===========  ========
</TABLE>

(1)  Includes results of operations from producing activities in Colombia.

(2)  Includes  interest  income of $4  million,  foreign  exchange  gains of $34
     million  and a decrease  in the fair value of crude oil put  options of $16
     million.

(3)  Includes  stock-based  compensation  expense of $2  million.

(4)  Includes exploration activities primarily in Nigeria, Norway and Colombia.

(5)  Includes costs of $6,088 million related to our insitu oil sands (Long Lake
     and future phases).

(6)  Approximately   79%  of  Marketing's   identifiable   assets  are  accounts
     receivable and inventories.

                                       23
<PAGE>

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

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

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

IDENTIFIABLE ASSETS          6,403     7,678(4)  1,212     2,100       400        807       3,035(5)      594       1,390    23,619
                        =========== =========  ======== ========= ========= ==========  ==========  ========== =========== =========

Capital Expenditures
  Development and Other        149       244        17        42        29         58           8          36           1       584
  Exploration                   28        94         -        26         -         15           -           -           -       163
  Proved Property
  Acquisitions                   -       757         -         -         -          -           -           -           -       757
                         ---------- ---------  -------- --------- --------- ----------  ----------  ---------- -----------  --------
TOTAL                          177     1,095        17        68        29         73           8          36           1     1,504
                        =========== =========  ======== ========= ========= ==========  ==========  ========== =========== =========

Property, Plant and
Equipment
  Cost                       6,869     9,225     1,386     4,591     2,920        636         256         983         332    27,198
  Less: Accumulated DD&A     2,419     1,843       244     2,850     2,729        121          80         523         212    11,021
                         ---------- ---------  -------- --------- --------- ----------  ----------  ---------- -----------  --------
NET BOOK VALUE               4,450     7,382(4)  1,142     1,741       191        515         176         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.

                                       24

<PAGE>

20.  DIFFERENCES   BETWEEN  CANADIAN  AND  US  GENERALLY   ACCEPTED   ACCOUNTING
     PRINCIPLES

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

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

(Cdn$ millions, except per share amounts)                      2010        2009
------------------------------------------------------ ------------- -----------
REVENUES AND OTHER INCOME
   Net Sales                                                  1,501       1,048
   Marketing and Other (v); (vi)                                205         292
                                                       ------------- -----------
                                                              1,706       1,340
                                                       ------------- -----------
EXPENSES
   Operating                                                    422         305
   Depreciation, Depletion, Amortization
      and Impairment                                            388         409
   Transportation and Other (v)                                 205         194
   General and Administrative (iv)                              126         108
   Exploration                                                   93          53
   Interest                                                      80          68
                                                       ------------- -----------
                                                              1,314       1,137
                                                       ------------- -----------

INCOME BEFORE PROVISION FOR INCOME TAXES                        392         203
                                                       ------------- -----------

PROVISION FOR (RECOVERY OF) INCOME TAXES
   Current                                                      259         118
   Deferred (iv); (vi); (vii)                                   (86)        (74)
                                                       ------------- -----------
                                                                173          44
                                                       ------------- -----------

NET INCOME - US GAAP                                            219         159
   Less: Net Income Attributable to
      Non-Controlling Interests                                   5           3
                                                       ------------- -----------

NET INCOME ATTRIBUTABLE TO NEXEN INC. - US GAAP (1)             214         156
                                                       ============= ===========

EARNINGS PER COMMON SHARE ($/share) (Note 15)
   Basic                                                      0.41         0.30
                                                       ============= ===========

   Diluted                                                    0.41         0.30
                                                       ============= ===========
(1)  RECONCILIATION OF CANADIAN AND US GAAP NET INCOME

                                                         Three Month March 31
                                                       -------------------------
                                                               2010        2009
------------------------------------------------------ ------------- -----------
Net Income Attributable to Nexen Inc - Canadian GAAP            185         135
Impact of US Principles, Net of Income Taxes:
   Stock-based Compensation (iv)                                 (6)          -
   Inventory Valuation (vi)                                      35          (6)
   Deferred Taxes (vii)                                           -          27
                                                       ------------- -----------
Net Income Attributable to Nexen Inc - US GAAP                  214         156
                                                       ============= ===========

                                       25
<PAGE>

UNAUDITED CONSOLIDATED BALANCE SHEET - US GAAP
                                                         March 31    December 31
(Cdn$ millions, except share amounts)                       2010          2009
------------------------------------------------------ ------------ ------------
ASSETS
   CURRENT ASSETS
      Cash and Cash Equivalents                              1,997        1,700
      Restricted Cash                                          178          198
      Accounts Receivable                                    2,635        2,788
      Inventories and Supplies (vi)                            555          610
      Other                                                    102          185
                                                       ------------ ------------
         Total Current Assets                                5,467        5,481
                                                       ------------ ------------
   PROPERTY, PLANT AND EQUIPMENT
      Net of Accumulated Depreciation, Depletion,
         Amortization and Impairment of $11,324
         (December 31, 2009 - $11,200) (i); (iii)           15,332       15,443
   GOODWILL                                                    330          339
   DEFERRED INCOME TAX ASSETS                                1,238        1,148
   DEFERRED CHARGES AND OTHER ASSETS                           328          370
                                                       ------------ ------------
TOTAL ASSETS                                                22,695       22,781
                                                       ============ ============
LIABILITIES
   CURRENT LIABILITIES
      Accounts Payable and Accrued Liabilities (iv)          3,185        3,131
      Accrued Interest Payable                                  77           89
      Dividends Payable                                         26           26
                                                       ------------ ------------
         Total Current Liabilities                           3,288        3,246
                                                       ------------ ------------
   LONG-TERM DEBT                                            7,054        7,251
   DEFERRED INCOME TAX LIABILITIES (i);
      (ii); (iv); (vi); (vii)                                2,727        2,720
   ASSET RETIREMENT OBLIGATIONS                                932        1,018
   DEFERRED CREDITS AND OTHER LIABILITIES (ii)               1,064        1,126

EQUITY
   Nexen Inc. Shareholders' Equity
      Common Shares, no par value
         Authorized:   Unlimited
         Outstanding:  2010 - 524,046,867 shares
                       2009 - 522,915,843 shares             1,076        1,049
      Contributed Surplus                                        -            1
      Retained Earnings (i); (ii); (iv); (vi); (vii)         6,763        6,575
      Accumulated Other Comprehensive Loss (ii)               (280)        (269)
                                                       ------------ ------------
   Total Nexen Inc. Shareholders' Equity                     7,559        7,356
      Canexus Non-Controlling Interests                         71           64
                                                       ------------ ------------
   TOTAL EQUITY                                              7,630        7,420
                                                       ------------ ------------
   COMMITMENTS, CONTINGENCIES AND GUARANTEES (Note 16)
TOTAL LIABILITIES AND EQUITY                                22,695       22,781
                                                       ============ ============

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

                                                    Three Months Ended March 31
                                                    ---------------------------
                                                        2010            2009
--------------------------------------------------- -------------- -------------
Net Income Attributable to Nexen Inc. - US GAAP               214           156
Other Comprehensive Income (Loss), Net of Income Taxes:
   Foreign Currency Translation Adjustment                    (11)            6
                                                    -------------- -------------
Comprehensive Income Attributable to
   Nexen Inc. - US GAAP                                       203           162
                                                    ============== =============

                                       26
<PAGE>

UNAUDITED  CONSOLIDATED  STATEMENT OF ACCUMULATED OTHER  COMPREHENSIVE LOSS - US
GAAP

                                                        March 31    December 31
                                                          2010         2009
--------------------------------------------------- -------------- -------------
Foreign Currency Translation Adjustment                      (201)         (190)
Unamortized Defined Benefit Pension Plan Costs (ii)           (79)          (79)
                                                    -------------- -------------
Accumulated Other Comprehensive Loss                         (280)         (269)
                                                    ============== =============

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 in prior
     years.  As a result,  PP&E is lower under US GAAP by $30 million  (December
     31, 2009 - $30 million) and deferred  income tax  liabilities  are lower by
     $11 million (December 31, 2009 - $11 million).

ii.  US GAAP requires the recognition of the over-funded and under-funded status
     of a defined benefit plan on the balance sheet as an asset or liability. At
     March 31, 2010 and December 31,  2009,  the unfunded  amount of our defined
     benefit pension plans that was not included in the pension  liability under
     Canadian GAAP was $105  million.  This amount has been included in deferred
     credits and other  liabilities  and $79 million,  net of income taxes,  has
     been included in Accumulated Other Comprehensive Income (AOCI).

iii. On January 1, 2003, we adopted ACCOUNTING FOR ASSET RETIREMENT  OBLIGATIONS
     for US GAAP reporting purposes. We adopted the equivalent Canadian standard
     for asset  retirement  obligations on January 1, 2004.  These standards are
     consistent  except for the adoption date which results in our PP&E under US
     GAAP being lower by $19 million.

iv.  Under Canadian principles,  we record obligations for liability-based stock
     compensation plans using the intrinsic-value method of accounting. Under US
     principles,  obligations for  liability-based  stock compensation plans are
     recorded using the  fair-value  method of  accounting.  In addition,  under
     Canadian  principles,  we retroactively  adopted EIC-162 which 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 under US GAAP:

     o    general and administrative  (G&A) expense is higher by $8 million, ($6
          million,  net of income  taxes),  for the three months ended March 31,
          2010, (2009 - higher by $8 million ($6 million, net of income taxes));
          and

     o    accounts payable and accrued liabilities are higher by $101 million as
          at March 31, 2010 (December 31, 2009 - $93 million).

v.   Under US GAAP,  asset  disposition  gains  and  losses  are  included  with
     transportation and other expense. Losses of $3 million for the three months
     ended March 31, 2010, were  reclassified from marketing and other income to
     transportation and other expense (gains of $7 million were reclassified for
     the three months ended March 31, 2009).

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

     o    marketing and other income is higher by $51 million ($35 million,  net
          of income  taxes) for the three  months  ended  March 31, 2010 (2009 -
          higher by $42 million ($27 million, net of income taxes)); and

     o    inventories  are lower by $19 million as at March 31,  2010  (December
          31, 2009 - lower by $70 million) and deferred  income tax  liabilities
          are $7 million lower (December 31, 2009 - lower by $23 million).

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

     As at March 31, 2010, the total amount of our  unrecognized tax benefit was
     approximately $279 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, 2010, the total
     amount of  interest  and  penalties  related  to  uncertain  tax  positions
     recognized in deferred  income tax


                                       27
<PAGE>

     liabilities  in the US GAAP -  Unaudited  Consolidated  Balance  Sheet  was
     approximately $8 million.  We had no interest or penalties  included in the
     US GAAP - Unaudited  Consolidated  Statement of Income for the three months
     ended March 31, 2010.

     Our income tax filings are subject to audit by taxation  authorities and as
     at March 31, 2010 the following tax years remained  subject to examination,
     (i)  Canada - 1985 to date  (ii)  United  Kingdom  - 2008 to date and (iii)
     United States - 2005 to date. We do not anticipate any material  changes to
     the  unrecognized  tax  benefits  previously  disclosed  within the next 12
     months.

NEW ACCOUNTING PRONOUNCEMENTS - US GAAP

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

                                       28

<PAGE>

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

THE FOLLOWING  SHOULD BE READ IN  CONJUNCTION  WITH THE  UNAUDITED  CONSOLIDATED
FINANCIAL  STATEMENTS  INCLUDED  IN  THIS  REPORT.  THE  UNAUDITED  CONSOLIDATED
FINANCIAL  STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE  WITH GENERALLY  ACCEPTED
ACCOUNTING   PRINCIPLES  (GAAP)  IN  CANADA.   THE  IMPACT  OF  THE  SIGNIFICANT
DIFFERENCES BETWEEN CANADIAN AND UNITED STATES (US) ACCOUNTING PRINCIPLES ON THE
FINANCIAL  STATEMENTS  IS  DISCLOSED  IN NOTE 20 TO THE  UNAUDITED  CONSOLIDATED
FINANCIAL STATEMENTS. THE DATE OF THIS DISCUSSION IS APRIL 26, 2010.

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

NOTE:  CANADIAN  INVESTORS SHOULD READ THE SPECIAL NOTE TO CANADIAN INVESTORS ON
PAGE 97 OF OUR 2009 FORM 10-K WHICH HIGHLIGHTS  DIFFERENCES BETWEEN OUR RESERVES
ESTIMATES  AND  RELATED  DISCLOSURES  THAT ARE  OTHERWISE  REQUIRED  BY CANADIAN
REGULATORY AUTHORITIES.

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

EXECUTIVE SUMMARY OF FIRST QUARTER RESULTS

                                                     Three Months Ended March 31
                                                     ---------------------------

(Cdn$ millions, except as indicated)                         2010          2009
--------------------------------------------------- -------------- -------------
Production before Royalties (mboe/d)                          252           252
Production after Royalties (mboe/d)                           221           225
Nexen's Average Realized Oil and Gas
   Price (Cdn$/boe)                                         70.16         47.56

Cash Flow from Operating Activities                           798           789
Net Income Attributable to Nexen Inc.                         185           135
Earnings per Common Share, Basic ($/share)                   0.35          0.26

Capital Investment                                            556           747
Acquisition of Additional Interest in Long Lake                 -           757
Net Debt (1)                                                5,057         5,737
                                                    -------------- -------------

(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 for the quarter was consistent with last year.  Production  increases
at Long Lake,  the Gulf of Mexico and at Ettrick and Telford in the UK North Sea
were offset by natural declines at Yemen and maintenance downtime at Buzzard for
repairs to the separator  unit. Our realized  average oil and gas price averaged
$70.16/boe  for the  quarter,  48% higher than last year as a result of stronger
benchmark  commodity  prices.  The stronger  Canadian  dollar relative to the US
dollar reduced the benefit of the higher commodity  prices.  The combined impact
of higher prices and steady  production,  offset by lower energy  marketing cash
flow, resulted in a 37% increase in net income.

At our Long Lake oil sands project,  we are steadily growing bitumen  production
volumes  each month as we increase  steam  volumes.  Our first  quarter  results
include start-up losses of $57 million at Long Lake. We expect Long Lake to make
positive cash flow contributions later this year as our bitumen volumes grow.

We  incurred  approximately  20%  of  our  2010  capital  budget  to  date.  Our
expenditures  have  focused  on our  major  developments  at Long Lake and Usan,
offshore West Africa,  exploration  in the Gulf of Mexico and the North Sea, and
advancing our shale gas project in north-east British Columbia.

                                       29
<PAGE>

During the quarter, we made a significant oil discovery at Appomattox in Eastern
Gulf  of  Mexico  where  we  drilled  an  exploratory  well  and  two  appraisal
sidetracks.  Appomattox  is the third  discovery in the area  following  earlier
discoveries at Shiloh and Vicksburg.  Additional exploration and appraisal wells
for Appomattox are planned for later this year.

Our financial position remains strong with available  liquidity of approximately
$3.6  billion.  This  liquidity  includes cash on hand of $2 billion and undrawn
lines of credit of  approximately  $1.6  billion.  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  operating cash netbacks,  provides us with the financial  flexibility to
carry out our investment programs.

CAPITAL INVESTMENT

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

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

Details of our capital programs are set out below:

THREE MONTHS ENDED MARCH 31, 2010
<TABLE>
<CAPTION>

                                                                                     New Growth
                                                         Major        Early Stage    Exploration      Core Asset
                                                      Development    Development                       Development      Total
------------------------------------------------ ----------------- ---------------- --------------- ----------------- ------------
<S>                                              <C>               <C>              <C>             <C>               <C>
Oil and Gas
    United Kingdom                                             22                 -            41                 66        129
    Canada                                                      -                 -            68                  6         74
    Synthetic (mainly Long Lake)                                -                15             -                 49         64
    Syncrude                                                    -                 -             -                 19         19
    United States                                               -                 -            49                 15         64
    Yemen                                                       -                 -             -                 10         10
    Nigeria                                                    91                 -             1                  -         92
    Other Countries                                             -                 -            40                  -         40
                                                 ----------------- ---------------- --------------- ----------------- ------------
                                                              113                15           199                165        492
Chemicals                                                       -                 -             -                 49         49
Energy Marketing, Corporate and Other                           -                 -             -                 15         15
                                                 ----------------- ---------------- --------------- ----------------- ------------
Total Capital                                                 113                15           199                229        556
                                                 ================= ================ =============== ================= ============
As a % of Total Capital                                     20%                 3%           36%               41%          100%
                                                 ----------------- ---------------- --------------- ----------------- ------------
</TABLE>

UNITED KINGDOM - NORTH SEA
The Golden Eagle area has emerged as a significant  development  opportunity for
us. We are in the process of completing the  acquisition  of additional  land in
the area and plan to drill an exploration well here mid-year.  Golden Eagle area
development  supports  standalone  facilities  and is  economic  with oil prices
significantly  lower  than  they are  currently.  We are  assessing  development
options  for the area and will  select  an  appropriate  configuration  prior to
sanctioning  in 2011.  We have a 34% interest in both Golden Eagle and Hobby,  a
46% interest in Pink, and operate all three.

West of the Shetland  Islands,  we are finalizing  plans to drill the North Uist
prospect.  We have a 35% working  interest  here and expect to drill the well in
the second  half of 2010.  This  prospect  has a target  size much  larger  than
typical North Sea targets. BP is the operator with a 45% working interest.

                                       30

<PAGE>

CANADA - HORN RIVER SHALE GAS
We  have  finished  drilling  our  eight-well   program  and  continue  to  make
significant progress on lowering costs and gaining access to the shale reservoir
on our substantial Horn River shale gas position in north-east British Columbia.
We plan to complete these wells in the second half of the year with 18 fracs per
well.  First production from these wells is expected before year end, ramping up
to 50 mmcf/d.

Substantial cost savings and productivity  improvements  were realized with this
drilling  program and our average  drilling days per well were under 25 days. We
currently expect that with an 18 well program,  we could reduce our all-in costs
even further to under $0.6  million per frac.  Our  production  results to date,
together with those of our competitors, indicate that recovery factors should be
higher than our estimate of 20%.  Additional  production  history will determine
recovery factors.

SYNTHETIC
Since the  completion of the  turnaround  last fall,  bitumen  volumes have been
consistently growing. Long Lake's gross bitumen production has grown from 14,000
bbls/d in the fourth  quarter of 2009 to 19,000  bbls/d in the first  quarter of
2010.  In  March,  gross  bitumen  production  averaged  22,000  bbls/d.  We are
currently  producing  approximately  25,000  bbls/d  and are  seeing  production
increases from both new wells and from  optimization of mature  producers.  This
represents an 80% increase over average pre-turnaround rates.

Production  growth reflects  significant  improvement in steam reliability since
the turnaround and steam rates are at all-time highs of about 140,000 bbls/d and
increasing.  This  represents a 100% increase over  pre-turnaround  rates.  As a
result,  we are  injecting  more steam into more wells than ever  before with 64
well pairs now on production  and steam  circulating  in an additional 15 pairs.
These  circulating  wells  will be  converted  to  production  over the next few
months.

Our all-in  steam-to-oil  ratio (SOR) is between 5 and 6 but this includes steam
to wells that are still in the steam  circulation stage and wells early in their
growth cycle. As our circulating wells start producing bitumen, we expect to see
an increase in bitumen  production  rates with a corresponding  decrease in SOR.
The SOR of our  producing  wells is  approximately  5, and  includes  well pairs
recently  converted  to  production  that are in the early stages of ramp up. We
continue to expect a long term SOR of 3.0 over the life of the project.

The upgrader facility is also performing consistently. Since the turnaround, the
upgrader  has  experienced  90% uptime,  compared to 50% before and is producing
high quality  premium  synthetic  crude (PSCTM).  For the quarter,  our realized
price for Long Lake PSCTM  averaged over $81/bbl.  The  gasification  process is
working,  creating a low-cost  fuel  source  which  reduces our need to purchase
natural gas for operations and will generate a significant margin advantage over
our peers, even at current low gas prices.

UNITED STATES - GULF OF MEXICO
During the  quarter,  we made a  significant  discovery  in the Eastern  Gulf of
Mexico at Appomattox, located in Mississippi Canyon blocks 391 and 392. Drilling
activities  resulted  in an oil  discovery  with  excellent  reservoir  quality,
following an exploration well and two appraisal sidetracks.  The discovery well,
located  in 7,217  feet of water,  was  drilled  to a depth of 25,077  feet true
vertical depth. An appraisal sidetrack was drilled to approximately  25,950 feet
true vertical depth.  The second  sidetrack was undertaken to further  delineate
the discovery. Well results have exceeded our pre-drill expectations.

Appomattox is the third discovery in the area following  earlier  discoveries at
Shiloh and Vicksburg.  Additional appraisal wells for Appomattox are planned for
later in the year and we are  investigating  development  options for Appomattox
and Vicksburg, located six miles east. We have a 25% interest in Vicksburg and a
20% interest in Appomattox and Shiloh.  Shell  Offshore Inc.  operates all three
discoveries.

Elsewhere in the deep water,  we completed  drilling an appraisal well at Knotty
Head and are  currently  evaluating  results and possible  development  choices.
Drilling  operations  with our new  deep-water  rig  exceeded  expectations.  We
completed  the well in  approximately  15% less time than expected and 20% below
planned cost. We are  continuing  our efforts to unitize our lands with adjacent
acreage.  We are operator of Knotty Head with a 25% working  interest.  A second
deep-water  drilling  rig is expected to arrive later this year which will allow
us to start drilling our other identified prospects.

OFFSHORE WEST AFRICA
Development of the Usan field,  offshore West Africa,  is progressing  well with
first  production  expected  in  2012.  The  development   includes  a  floating
production and storage (FPSO) vessel with the ability to process  180,000

                                       31
<PAGE>

bbls/d (36,000 bbls/d net to us) and store up to two million  barrels of oil. We
have a 20% interest in exploration  and  development on this block and Total E&P
Nigeria Limited is the operator.

We  continue  to  explore  offshore  West  Africa  and  previously  announced  a
successful  exploration well at Owowo in the southern portion of Oil Prospecting
License  (OPL)  223.  Other  exploration  prospects  are  under  evaluation  for
drilling.

FINANCIAL RESULTS

CHANGE IN NET INCOME

                                                                 2010 VS 2009
------------------------------------------------------------- ------------------
NET INCOME AT MARCH 31, 2009                                                135
                                                              ------------------
     Favorable (unfavorable) variances(1):

         Realized Commodity Prices
              Crude Oil                                                     410
              Natural Gas                                                     1
                                                              ------------------
                  Total Price Variance                                      411

         Production Volumes, After Royalties
              Crude Oil                                                     (15)
              Natural Gas                                                    34
              Changes in Crude Oil Inventory For Sale                        38
                                                              ------------------
                  Total Volume Variance                                      57

         Oil and Gas Operating Expense                                     (112)

         Oil and Gas Depreciation, Depletion,
            Amortization and Impairment                                      19

         Exploration Expense                                                (40)

         Energy Marketing Revenue, Net                                     (151)

         Chemicals Contribution                                               4

         General and Administrative Expense (2)                             (18)

         Interest Expense                                                   (12)

         Current Income Taxes                                              (141)
         Future Income Taxes                                                 13

         Other                                                               20
                                                              ------------------

NET INCOME AT MARCH 31, 2010                                                185
                                                              ==================

(1)  All amounts are presented before provision for income taxes.

(2)  Includes stock-based compensation expense.

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

                                       32
<PAGE>

OIL & GAS

PRODUCTION

                                          Three Months Ended March 31
                             ---------------------------------------------------
                                        2010                       2009
                             ------------------------- -------------------------
                                Before        After       Before       After
                              Royalties(1)  Royalties  Royalties(1)  Royalties
---------------------------- ------------ ------------ ------------ ------------
Crude Oil and Liquids
(mbbls/d)
   United Kingdom                  105.6        105.6        103.8        103.8
   Canada                           14.2         11.0         15.5         12.3
   Long Lake Bitumen                12.1         11.3          8.1          8.1
   Syncrude                         19.5         17.8         19.8         19.6
   United States                     9.8          8.9         10.4          9.5
   Yemen                            42.8         23.1         54.5         35.7
   Other Countries                   2.3          2.1          5.5          5.1
                             ------------ ------------ ------------ ------------
                                   206.3        179.8        217.6        194.1
                             ------------ ------------ ------------ ------------
Natural Gas (mmcf/d)
   United Kingdom                     40           40           18           18
   Canada                            133          121          137          122
   United States                     101           88           50           45
                             ------------ ------------ ------------ ------------
                                     274          249          205          185
                             ------------ ------------ ------------ ------------

Total Production (mboe/d)            252          221          252          225
                             ============ ============ ============ ============

(1)  We have presented  production  volumes  before  royalties as we measure our
     performance  on this  basis  consistent  with  other  Canadian  oil and gas
     companies.

HIGHER SALES VOLUMES INCREASED NET INCOME FOR THE QUARTER BY $57 MILLION
Production  before royalties  remained  consistent with the same period in 2009.
Production  increases  included i) restoring Gulf of Mexico gas production which
was shut in due to Hurricane Ike and new production at Longhorn; ii) new volumes
from  Ettrick  and  Telford in the UK North Sea;  and iii)  ramping up Long Lake
bitumen production. These increases were offset by i) natural declines in Yemen;
ii) reduced working interest in Colombia;  iii) lower production in Canada;  and
iv)  temporary  downtime  at Buzzard.  Compared  to the fourth  quarter of 2009,
production before royalties  decreased 5% as a result of downtime at Buzzard and
Ettrick in the UK North Sea and an advanced  turnaround  at  Syncrude.  This was
partially  offset  by  increased  production  at Long  Lake  and the  ramp up of
Longhorn in the Gulf of Mexico.

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

                                                            Before        After
(mboe/d)                                                 Royalties    Royalties
--------------------------------------------------- --------------- ------------
Production, fourth quarter 2009                                265          235
   Production changes:
       Long Lake Bitumen                                         3            2
       United States                                             3            2
       Canada                                                   (1)           -
       Yemen                                                    (2)          (3)
       Syncrude                                                 (4)          (3)
       United Kingdom                                          (12)         (12)
                                                    --------------- ------------
Production, first quarter 2010                                 252          221
                                                    =============== ============

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

                                       33
<PAGE>

UNITED KINGDOM
Production volumes in the UK North Sea averaged 112,300 boe/d in the quarter, 5%
higher than the first  quarter of 2009 but 10% lower than the previous  quarter.
The  decrease  from the previous  quarter was  primarily a result of downtime at
Buzzard  for  repairs  to the  separator  unit and  drilling  rig  movement  and
commissioning activities at Ettrick which required a shut in of the FPSO vessel.

Buzzard  production  averaged  84,600  boe/d  during the  quarter,  2% below the
previous  quarter  and 9% lower  than  the  first  quarter  last  year.  Routine
monitoring of equipment on the Buzzard  platform  during the quarter  identified
repairs that were required to the separator unit. The repair work lasted a week,
during  which time Buzzard  produced at reduced  rates of  approximately  50,000
boe/d (gross).  Production was subsequently  restored to full capacity.  Further
activities are scheduled to permanently  repair the separator unit. This work is
timed to coincide  with our planned two week shutdown to install the topsides of
the fourth platform in the second quarter.

Production  at  Scott/Telford  decreased  15% from the prior  quarter to average
20,400  boe/d as a result  of well  intervention  work at  Scott  and  scheduled
maintenance  at Telford.  Production  has almost  doubled  compared to the first
quarter  of  2009 as a  result  of a  successful  step-out  development  well at
Telford.  This well was  completed in the third quarter of 2009 and is tied back
to our Scott  platform.  Production  from our  non-operated  fields at Duart and
Farragon averaged 2,300 boe/d for the quarter.

Production  from our Ettrick  field  averaged  5,000 boe/d for the quarter as we
continue to ramp up the facilities and safely commission all systems. Production
was 55% lower than the previous quarter as a result of commissioning  activities
and a two week shut-in for rig  movements  relating to drilling  and  completion
activities  in the  area.  Production  was shut in for two  weeks  as a  result.
Ettrick  production  has been restored,  is currently  producing at rates around
20,000 boe/d gross (16,000 boe/d net to us) and continues to ramp up.

CANADA
Production  in Canada  decreased 5% from the first  quarter of 2009 and remained
comparable with the fourth quarter.  Heavy oil production has remained strong as
we successfully  implemented strategies to maximize recoveries from our existing
wells while minimizing capital investment. CBM production was consistent quarter
over quarter and averaged 48 mmcf/d.

We  continue  to invest in our shale gas  project in the Dilly Creek area of the
Horn River basin in north-east British Columbia.  We currently have six wells on
production  and they are meeting  expectations  with respect to  production  and
decline profiles. During the quarter, we finished drilling an eight-well program
to further test the play. We plan to complete  these wells in the second half of
the year. First production is from these wells expected before year end, ramping
up to 50 mmcf/d.

LONG LAKE
Since the  completion of the  turnaround  last fall,  bitumen  volumes have been
consistently growing. Long Lake's gross bitumen production has grown from 14,000
bbls/d in the fourth  quarter of 2009 to 19,000  bbls/d in the first  quarter of
2010.  In  March,  gross  bitumen  production  averaged  22,000  bbls/d.  We are
currently  producing  approximately  25,000  bbls/d  and are  seeing  production
increases from both new wells and from  optimization of mature  producers.  This
represents an 80% increase over average  pre-turnaround  rates.  The table below
shows gross  bitumen  production  volumes  since the  turnaround.  We have a 65%
interest in Long Lake.

                                                                 Gross Bitumen
Month                                                         Volumes (bbls/d)
--------------------------------------------------------- ----------------------
October 2009                                                              8,600
November 2009                                                            15,200
December 2009                                                            16,200
January 2010                                                             16,300
February 2010                                                            17,700
March 2010                                                               21,900
April 2010 - Month to date                                               24,500
--------------------------------------------------------- ----------------------

Production  growth reflects  significant  improvement in steam reliability since
the turnaround and steam rates are at all-time highs of about 140,000 bbls/d and
increasing.  This  represents a 100% increase over  pre-turnaround  rates.  As a
result,  we are  injecting  more steam into more wells than ever  before with 64
well pairs now on production  and steam  circulating  in an additional 15 pairs.
These  circulating  wells  will be  converted  to  production  over the next few
months.

                                       34
<PAGE>

SYNCRUDE
Syncrude  production  averaged  19,500 boe/d for the quarter,  down 18% from the
previous quarter and marginally lower than the first quarter of 2009. Production
volumes were reduced as a turnaround of the LC finer originally  planned for the
second  quarter was advanced to January.  The  turnaround  was  completed in mid
March and is now back to full rates.  A coker  turnaround  is  scheduled  in the
third quarter.

UNITED STATES
Production in the Gulf of Mexico averaged 26,600 boe/d, 42% higher than the same
period  last  year.   The  increase  in  production   primarily  came  from  our
non-operated Longhorn  development,  which averaged 8,900 boe/d for the quarter.
Production  during  the first  quarter of 2009 was  reduced  as  several  fields
remained  shut in as a result  of  Hurricane  Ike.  These  fields  resumed  full
production in the second  quarter of 2009.  These  increases have been offset by
natural declines primarily at Gunnison.

Production  in the US  increased  11% from the  prior  quarter.  The  impact  of
increases from ramping up production at Longhorn were partially  offset by lower
production at Mississippi Canyon 72 and Wrigley.

YEMEN
Yemen  production  decreased 5% from the previous quarter and 21% from the first
quarter of 2009. The decline is consistent  with our  expectations  as the field
matures and from reduced development drilling.  During the quarter at Masila, we
drilled four  development  wells and plan to drill up to seven more  development
wells  later this year.  At Block 51, we  recently  obtained  approval to drill,
complete and tie-in five additional  development wells in the remainder of 2010.
Production  declines in Yemen are expected to continue as we focus on maximizing
recovery of the remaining reserves.

We are working with the Yemen government and our partners to potentially  extend
our  production-sharing  agreement  beyond the  current  expiry date of December
2011. There is no assurance that this extension will be received.

OTHER COUNTRIES
Our share of production  from the Guando field in Colombia  averaged 2,300 boe/d
for the quarter. While this was consistent with the previous quarter, it was 58%
lower  than the first  quarter  of 2009 as lower  volumes  reflect  the  reduced
working interest of the Guando field, effective the second quarter of 2009, once
we achieved pre-set production levels.

                                       35
<PAGE>

COMMODITY PRICES
                                                     Three Months Ended March 31
                                                     ---------------------------
                                                          2010          2009
---------------------------------------------------- -------------- ------------
CRUDE OIL
   West Texas Intermediate (WTI) (US$/bbl)                   78.71        43.08
   Dated Brent (Brent) (US$/bbl)                             76.23        44.40
                                                     -------------- ------------

   Benchmark Differentials (1) (US$/bbl)
         Heavy Oil                                           9.25         9.17
         Mars                                                2.97        (0.66)
         Masila                                              1.62         0.05

   Realized Prices from Producing Assets (Cdn$/bbl)
         United Kingdom                                      77.25        51.60
         Canada                                              65.26        35.35
         Long Lake Synthetic                                 81.04            -
         Syncrude                                            83.55        55.48
         United States                                       79.12        46.27
         Yemen                                               80.39        52.30
         Other Countries                                     78.88        41.68

   Corporate Average (Cdn$/bbl)                              78.00        50.41
                                                     -------------- ------------

NATURAL GAS
   New York Mercantile Exchange (US$/mmbtu)                   5.04         4.48
   AECO (Cdn$/mcf)                                            5.08         5.34
                                                     -------------- ------------

   Realized Prices from Producing Assets (Cdn$/mcf)
         United Kingdom                                       4.81         5.50
         Canada                                               5.02         4.75
         United States                                        6.00         5.93

   Corporate Average (Cdn$/mcf)                               5.37         5.11
                                                     -------------- ------------

NEXEN'S AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe)        70.16        47.56
                                                     -------------- ------------

AVERAGE FOREIGN EXCHANGE RATE - Canadian to US Dollar       0.9615       0.8028
                                                     -------------- ------------

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

HIGHER COMMODITY PRICES INCREASED QUARTERLY NET INCOME BY $411 MILLION
Crude oil prices  continued to strengthen  during the quarter with WTI averaging
US$78.71/bbl,  an  increase  of 83% over the same period last year and 3% higher
than the prior  quarter.  Dated Brent  increased 72% and 2% when compared to the
same  periods,  averaging  US$76.23/bbl  for the  quarter.  The impact of higher
commodity  prices was  reduced  somewhat  as the  Canadian  dollar  strengthened
compared to the US dollar over the same period last year. Our realized oil price
averaged  $78.00/bbl,  55% higher  than the first  quarter of 2009 and 2% higher
than the previous quarter.

Natural gas prices were higher as NYMEX averaged US$5.04/mmbtu,  13% higher than
the first quarter of 2009 and 3% higher than the previous quarter. AECO averaged
Cdn$5.08/mcf during the first quarter, 27% above the prior quarter.  Compared to
the same  period  last  year,  AECO  decreased  5% as the  Canadian  dollar  has
strengthened.  Our realized gas price  averaged  $5.37/mcf,  25% higher than the
prior quarter and 5% higher than the first quarter of 2009.

The Canadian dollar strengthened considerably against the US dollar, compared to
the same period last year.  This  reduced  our net sales by  approximately  $260
million,  as our realized crude oil and gas prices were $15.42/bbl and $1.06/mcf
lower,   respectively.   However,  our  US-dollar  denominated  long-term  debt,
operating  expenses  and  capital  expenditures  are lower  when  translated  to
Canadian dollar as a result of the weaker US dollar.

                                       36
<PAGE>

CRUDE OIL REFERENCE PRICES
Crude oil prices were 83% higher than the first quarter  2009.  WTI traded above
US$80/bbl for most of March,  supported by positive  economic news, strong Asian
demand and cold weather.

Demand/supply  fundamentals  for crude oil  improved  from  better-than-expected
world economic growth.  OPEC continues to have spare production capacity but oil
demand is  forecasted  to reach  record  levels by year  end.  Demand  growth is
exceeding  non-OPEC  supply  growth  resulting in  reduction to spare  capacity.
Continued  strong demand growth from emerging  markets has  redirected  supplies
away from the  Atlantic  basin  and  reduced  floating  inventory  levels.  More
recently,  demand for WTI increased as Canadian  synthetic  crude oil production
has been constrained due to outages.

World-wide  economic  indicators appear relatively strong but there are concerns
over sovereign credit risks,  global fiscal imbalances and the timing and impact
of the withdrawal of government fiscal and monetary stimuli. Most OECD countries
have  experienced GDP growth but it has been  unbalanced with relatively  strong
growth in the US  compared  to minimal  growth in Europe.  China has seen strong
growth but the government has taken actions to moderate this because of concerns
about  inflation and an overheating  economy.  Global  economic growth remains a
downside risk. A risk to commodity  prices continues to be the lack of demand in
developed markets.

Crude oil prices were  supported  late last year by the weakening US dollar.  To
date in 2010, the US dollar strengthened  against the Euro and British Pound but
this did not appear to impact  crude oil  prices.  The US dollar is  expected to
weaken during 2010 which should continue to support higher crude oil prices.

The  recent  strength  in crude oil  prices  has been  partially  attributed  to
geopolitical events such as concerns over Iran's nuclear enrichment program, the
ongoing   wars  in  Iraq  and   Afghanistan   and  threats  of  attacks  to  oil
infrastructure in Nigeria. A much tighter supply/demand environment, and reduced
spare capacity should increase price sensitivity to geopolitical events.

CRUDE OIL DIFFERENTIALS
The heavy oil differential  continued to be narrower than historic levels due to
declining heavy oil production and excess heavy refinery  capacity.  There was a
slight widening of  differentials in March primarily due to lower heavy fuel oil
prices.

The  Brent/WTI  differential  widened due to stronger  WTI demand as a result of
Canadian  synthetic  production  outages  and  strong  gasoline  demand.  Rising
transatlantic freight rates also contributed to the wider differential.

The Masila price strengthened  relative to Brent,  reflecting strong demand from
China and other Asian countries that are the primary buyers of Masila crude.

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

NATURAL GAS REFERENCE PRICES
NYMEX  natural gas prices  declined  throughout  the quarter as an early  spring
reduced heating demand and increased storage levels.  Shale gas supply continues
to grow despite lower prices.  This new supply and the warmer spring weather are
driving market concerns over higher storage levels despite the expected addition
of new storage  capacity in 2010.  Some  near-term  support for demand  includes
industrial demand growth from a stronger economy,  strong power demand due to an
expected  warmer  summer  than 2009,  low US hydro power  generation  and higher
coal-fired  power  costs.  However,  continuing  weak gas prices are forecast as
strong  supply  additions  are  expected  from shale gas,  tight gas and new LNG
volumes imported from Russia and the Middle East.

                                       37
<PAGE>

OPERATING EXPENSES

                                          Three Months Ended March 31
                             ---------------------------------------------------
(Cdn$/boe)                              2010                       2009
---------------------------- ------------------------- -------------------------
                                Before        After      Before         After
                             Royalties(1)   Royalties  Royalties(1)   Royalties
                             ------------ ------------ ------------ ------------
   Conventional Oil and Gas        13.18        15.20          8.27        9.47
   Syncrude                        38.43        42.01         36.95       37.31
   Average Oil and Gas             15.14        17.38         10.62       12.03
                             ------------ ------------ ------------ ------------

(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.

HIGHER OPERATING EXPENSES REDUCED QUARTERLY NET INCOME BY $112 MILLION
Operating  costs  increased  $112  million  from the same period last year.  The
majority of the increase relates to costs associated with our Long Lake project.
As of January 1, 2010, we ceased  capitalizing  our Long Lake  operations as the
facility was reliably operating as designed following the successful  turnaround
late last year. These costs are now included in operating expenses. The addition
of these costs  increased  our per-unit  average cost as bitumen  production  is
still  ramping  up while  costs at Long  Lake are  mostly  fixed and do not vary
significantly  with production  rates. We expect our average per-unit  operating
costs to decrease as bitumen production rates increase.

During the quarter,  the  strengthening  Canadian dollar decreased our US dollar
denominated  operating costs,  reducing our corporate  average operating cost by
$1.07/boe.  Additionally,  changes in  production  mix with natural  declines in
Canada and Yemen  offset by  increases  in the North Sea and the Gulf of Mexico,
decreased our corporate average by $0.11/boe.

In the UK North  Sea,  Buzzard  operating  costs were  higher due to  additional
maintenance  expense and higher  transportation  tariffs.  These  higher  costs,
combined with lower volumes due to temporary  downtime,  increased our corporate
average  operating cost by $0.61/boe.  Elsewhere in the UK North Sea,  operating
costs increased our corporate average by $0.22/boe. At Ettrick,  operating costs
per barrel are higher than our corporate average because of the costs associated
with the leased  FPSO and from not being at full  production  rates  yet.  These
higher  average  operating  costs have been  partially  offset by lower  average
per-unit costs at Scott/Telford as a result of higher volumes.

In Yemen, we continue to incur costs to maintain  existing well  productivity to
maximize  reserve  recoveries and slow the natural  decline of the field.  These
costs,  combined with  production  declines,  increased  our  corporate  average
operating cost by $0.38/boe.  In the US Gulf of Mexico,  the effect of increased
operating costs due to higher repair and maintenance  expenditures was partially
offset by higher  volumes,  increasing our corporate  average  operating cost by
$0.04/boe.

Natural declines in Canada reduced production volumes,  increasing our corporate
average by $0.12/boe. At Syncrude, higher maintenance costs and lower production
volumes  associated  with the turnaround of the LC finer increased our corporate
average by $0.11/boe.

                                       38
<PAGE>

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

                                             Three Months Ended March 31
                             ---------------------------------------------------
(Cdn$/boe)                              2010                       2009
---------------------------- ------------------------- -------------------------
                                Before        After      Before         After
                             Royalties(1)   Royalties  Royalties(1)   Royalties
                             ------------ ------------ ------------ ------------
Conventional Oil and Gas           16.79        19.35        18.58        21.27
   Syncrude                         7.03         7.68         6.46         6.53
   Average Oil and Gas             16.03        18.40        17.59        19.91
                             ------------ ------------ ------------ ------------

(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.

LOWER OIL AND GAS DD&A INCREASED NET INCOME FOR THE QUARTER BY $19 MILLION
Our average  per-unit DD&A cost  decreased  $1.56/boe  from the same period last
year. The stronger Canadian dollar reduced our corporate average by $2.08/boe as
depletion of our international and US assets is denominated in US dollars.  This
was  partially  offset by  changes in our  production  mix which  increased  our
average  DD&A rate by  $1.59/boe.  The change in  production  mix was  partially
driven by lower production at Buzzard, offset by new volumes at Ettrick and Long
Lake.  Buzzard  DD&A rates are lower than our  corporate  average  while DD&A at
Ettrick and Long Lake is higher.

During the  quarter,  we began  depleting  our Long Lake  assets.  The Long Lake
depletion  rate  is  higher  than  our  corporate   average  and  increased  our
consolidated average depletion cost by $0.76/boe.

In the UK North Sea,  our Buzzard  depletion  rate  decreased  from last year as
successful  development  drilling  increased our proved reserve estimates at the
end of 2009.  This  lower  depletion  rate  reduced  our  corporate  average  by
$0.60/boe.  Elsewhere  in the UK,  successful  development  drilling  at Telford
increased  proved  reserve  estimates  at the end of 2009,  which  significantly
reduced the  Scott/Telford  depletion  rate.  This was  partially  offset by new
volumes from the Ettrick field, decreasing our corporate average by $0.86/boe.

Depletion  rates in Yemen  increased our  corporate  average  $0.33/boe.  As the
fields mature and production  declines,  our capital is focused on accessing the
remaining  reserves,  thereby  increasing  our depletion  rates.  In the Gulf of
Mexico,  positive reserve  revisions and lower estimates for future  abandonment
costs reduced our corporate average depletion rate of $1.04/boe.

Higher Canadian  depletion  costs increased our corporate  average by $0.27/boe.
Our 2010  depletion  rates are higher at our CBM and natural gas  properties  as
reserve  estimates  at the end of 2009 were  reduced  by lower gas  prices.  The
higher  depletion rates on our natural gas properties  were partially  offset by
lower rates on our heavy oil  properties,  where we had  positive  price-related
proved reserves revisions at the end of 2009.

                                       39
<PAGE>

EXPLORATION EXPENSE

                                                     Three Months Ended March 31
                                                     ---------------------------
                                                          2010         2009
---------------------------------------------------- ------------- -------------
Seismic                                                        12            12
Unsuccessful Drilling                                          41            11
Other                                                          40            30
                                                     ------------- -------------
Total Exploration Expense                                      93            53
                                                     ============= =============

New Growth Exploration                                        199           163
Geological and Geophysical Costs                               12            12
                                                     ------------- -------------
Total Exploration Expenditures                                211           175
                                                     ============= =============

Exploration Expense as a % of Exploration
   Expenditures                                                44%           30%
                                                     ------------- -------------

HIGHER EXPLORATION EXPENSE DECREASED NET INCOME FOR THE QUARTER BY $40 MILLION
Exploration  expenditures increased $36 million or 22% from the same period last
year as we  continue  to invest in our core  basins in the Gulf of  Mexico,  the
North Sea and Canada.

In  the  Eastern  Gulf  of  Mexico,  we  made a  significant  oil  discovery  at
Appomattox,  where we drilled an exploratory well and two appraisal  sidetracks.
Appomattox  is the third  discovery in the area  following  previous  successful
drilling at Shiloh and Vicksburg.  Additional appraisal wells for Appomattox are
planned for later in the year and we are investigating  development  options for
Appomattox  and  Vicksburg,  located six miles east.  We have a 25%  interest in
Vicksburg and a 20% interest in Appomattox and Shiloh,  with Shell Offshore Inc.
operating all three.

In the UK, we are  assessing  development  options for our Golden  Eagle area to
determine the appropriate configuration. We are in the process of completing the
acquisition of additional land in the area and plan to drill an exploration well
here  mid-year.  The Golden Eagle area  includes  our 34%  operated  interest in
Golden Eagle and Hobby and our 46% operated  interest in Pink.  We plan to drill
up to five additional exploration and appraisal wells in 2010.

In Canada,  we are investing in our shale gas project in the Dilly Creek area of
the Horn River basin in north-east British Columbia. We currently have six wells
on production and they are meeting  expectations  with respect to production and
decline profiles.  During the quarter, we successfully drilled an eight well pad
to further  test the play.  These wells are  expected to be on stream later this
year following completion  operations.  In north-east British Columbia,  we have
approximately 90,000 acres in the Dilly Creek area and a further 38,000 acres in
the Cordova area, with a 100% working interest in each.

Exploration  expense increased $40 million or 75% from the same period last year
as higher  unsuccessful  drilling costs were  partially  offset by a decrease in
exploration G&A. During the quarter,  we drilled two  unsuccessful  wells in the
North Sea.  The Brand  well in Norway  and the  Deacon  well in the UK failed to
encounter  hydrocarbons  and we expensed  drilling  costs of $25 million and $14
million, respectively.

                                       40

<PAGE>

ENERGY MARKETING
                                                     Three Months Ended March 31
                                                     ---------------------------
                                                             2010          2009
---------------------------------------------------- ------------- -------------
   Physical Sales (1)                                      10,114         9,945
   Physical Purchases (1)                                  (9,896)       (9,802)
   Net Financial Transactions (2)                             (64)           48
   Change in Fair Market Value of Inventory                   (68)           76
                                                     ------------- -------------
Marketing Revenue                                              86           267
   Transportation Expense                                    (122)         (165)
   Other                                                       (1)            5
                                                     ------------- -------------
NET MARKETING REVENUE                                         (37)          107
                                                     ============= =============
CONTRIBUTION TO NET MARKETING REVENUE BY REGION
   North America                                              (35)          104
   Asia                                                         1            12
   Europe                                                      (3)           (9)
                                                     ------------- -------------
NET MARKETING REVENUE                                         (37)          107
   DD&A                                                        (5)           (4)
   General and Administrative                                 (21)          (23)
   Other                                                       (4)            3
                                                     ------------- -------------
MARKETING CONTRIBUTION TO INCOME BEFORE
   INCOME TAXES                                               (67)           83
                                                     ============= =============
NORTH AMERICA
   NATURAL GAS
   Physical Sales Volumes (3) (bcf/d)                         4.8           5.1
   Transportation Capacity (bcf/d)                            1.5           1.6
   Storage Capacity (bcf)                                    31.9          33.5
   Financial Volumes (4) (bcf/d)                              6.0          15.6
   CRUDE OIL
   Physical Sales Volumes (3) (mbbls/d)                       754           806
   Storage Capacity (mbbls)                                 2,968         2,757
   Financial Volumes (4) (mbbls/d)                            755           915
   POWER
   Physical Sales Volumes (3) (GWh/d)                          10             5
   Generation Capacity (MW)                                    87            87
ASIA
   Physical Sales Volumes (3) (mbbls/d)                        91           129
   Financial Volumes (4) (mbbls/d)                            290           322
EUROPE
   Financial Volumes (4) (mbbls/d)                            603           507
VALUE-AT-RISK
   Quarter-end                                                 13            19
   High                                                        15            24
   Low                                                          9            18
   Average                                                     12            20
                                                     ------------- -------------

(1)  Marketing's   physical   sales,   physical   purchases  and  net  financial
     transactions are reported within marketing revenue as detailed in the notes
     to the unaudited consolidated financial statements.

(2)  Net  financial  transactions  include  all  gains and  losses on  financial
     derivatives  and the  unrealized  portion of gains and  losses on  physical
     purchase and sale contracts.

(3)  Excludes  inter-segment  transactions.  Physical volumes  represent amounts
     delivered  during the quarter.

(4)  Financial volumes represent amounts largely acquired to economically  hedge
     physical transactions during the quarter.

                                       41
<PAGE>

LOWER CONTRIBUTION FROM ENERGY MARKETING DECREASED NET INCOME BY $151 MILLION
During  the  quarter,  we  continued  our  strategic  review  resulting  in  the
successful  sale of the European gas and power  business,  which  generated  $15
million of cash proceeds. We have substantially  completed  negotiations for the
sale  of  our  North  American   natural  gas  business  subject  to  finalizing
documentation and customary closing conditions.  We expect to sign the agreement
in the  second  quarter  and close the sale in the  third  quarter.  The sale is
expected  to be cash  neutral  and we expect to  recognize  a  non-cash  loss of
between $250 and $290 million.  This loss  primarily  relates to the transfer of
long-term natural gas physical transportation commitments that are less valuable
with  increased  gas  supplies  that  reduce  the need for  transport  services.
Although  volatile on a quarterly  basis, we have had success with our marketing
business over the last 10 years  generating  about $800 million of positive cash
flow.

Results from energy  marketing are lower than last year's results as a result of
strong  crude oil  results in the first  quarter of 2009 and strong  natural gas
income reported in the fourth quarter, together with lower results this quarter.

In 2010, the group's results were lower as global crude demand  increased prices
and flattened the forward contango curve. Early in the first quarter, gains were
generated from blending  physical  crudes and inventory  management  strategies.
These were  substantially  offset  late in the quarter by a  flattening  forward
contango curve,  widening heavy  differentials  and a weaker US dollar. In 2009,
record  results were  generated  from the steep crude oil forward price curve as
near-term  crude oil prices  were  negatively  impacted  by the global  economic
recession.

During  the first  quarter  of 2010,  our North  America  natural  gas  business
continued to face a challenging environment as declining natural gas spot prices
reduced the reported value of our gas  inventories  and  transportation  spreads
between producing and consuming regions remained narrow impacting our ability to
generate  profits as we moved gas to different  regions.  These losses partially
offset related gains reported in the previous quarter.

The first quarter natural gas losses in 2009 were due to exiting the last of our
2008 basis trading  positions as we eliminated this activity.  Our inventory and
time spread strategy  experienced  losses in both the first quarters of 2010 and
2009,  largely related to the declining value of inventory.  Typically,  natural
gas prices fall in the first part of the year as winter demand  declines and the
injection  season  begins.  Our inventory is valued at the spot market price and
losses  were  reported  in the first  quarter  as natural  gas prices  decreased
relative to year end. Losses on this strategy were consistent year over year. We
recognized gains in the fourth quarter as spot natural gas prices increased from
stronger winter demand.

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
                                                    ---------------------------
                                                          2010         2009
--------------------------------------------------- --------------- ------------
Trading Activities (Physical and related Financial)            (38)         101
Non-Trading Activities                                           1            6
                                                    --------------- ------------
Total Net Marketing Revenue                                    (37)         107
                                                    =============== ============

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

                                       42
<PAGE>

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


FAIR VALUE OF DERIVATIVE CONTRACTS
Our processes for  estimating and  classifying  the fair value of our derivative
contracts are consistent with those in place at December 31, 2009.

At March 31,  2010,  the fair value of our  derivative  contracts  in our energy
marketing  trading  activities was $43 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.

                                                       MATURITY
                                      -----------------------------------------
                                      Less than   1-3     4-5   More than
                                       1 year    years   years   5 years   Total
                                      --------- ------- ------- ---------- -----
  Level 1 - Actively Quoted Markets        (68)    (79)     (9)         -  (156)
  Level 2 - Based on Other Observable
            Pricing Inputs                  93      52      10          6   161
  Level 3 - Based on Unobservable
            Pricing Inputs                  17      21       -          -    38
                                      --------- ------- ------- ---------- -----
Total                                       42      (6)      1          6    43
                                      ========= ======= ======= ========== =====

CHANGES IN FAIR VALUE OF DERIVATIVE CONTRACTS

                                                                           Total
------------------------------------------------------------------- ------------
Fair Value at December 31, 2009                                               23
   Change in Fair Value of Contracts                                          19
   Net Losses (Gains) on Contracts Closed                                      1
   Changes in Valuation Techniques and Assumptions (1)                         -
                                                                    ------------
Fair Value at March 31, 2010                                                  43
                                                                    ============

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

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

CHEMICALS

HIGHER CHEMICALS CONTRIBUTION INCREASED NET INCOME BY $4 MILLION
Chlor-alkali  and chlorate sales revenues in North America were lower during the
quarter than the same period last year.  Chlorate revenue decreased 8% despite a
12% increase in volumes,  as the average price  received was 18% lower than last
year.  Chlor-alkali sale volumes remained consistent;  however,  price decreases
due to  competition  reduced our revenue by 12%. In Brazil,  our  revenues  were
consistent with the first quarter of 2009, as the impact of a slight increase in
volumes was offset by a small decrease in price.

The stronger  Canadian dollar at March 31, 2010 generated foreign exchange gains
of $7 million on the Canexus  US-dollar  denominated  debt. This was higher than
the first  quarter  of 2009 when our  chemicals  operations  recognized  foreign
exchange translation losses of $6 million.

                                       43

<PAGE>

CORPORATE EXPENSES

GENERAL AND ADMINISTRATIVE (G&A)

                                                    Three Months Ended March 31
                                                    ---------------------------
                                                          2010          2009
--------------------------------------------------- -------------- -------------
General and Administrative Expense before
   Stock-Based Compensation                                   116           100
Stock-Based Compensation (1)                                    2             -
                                                    -------------- -------------
Total General and Administrative Expense                      118           100
                                                    ============== =============

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

HIGHER G&A COSTS DECREASED NET INCOME BY $18 MILLION
G&A expenditures  before stock-based  compensation  increased 16% from the first
quarter of 2009 primarily as a result of higher employee costs.

Fluctuations  in our  share  price  create  volatility  in our net  income as we
account  for  stock-based   compensation  using  the   intrinsic-value   method.
Stock-based  compensation  increased  marginally during the quarter as our share
price  was  largely  unchanged  from  the end of  2009.  Cash  payments  made in
connection  with our  stock-based  compensation  programs during the three month
period ended March 31, 2010 were $3 million (2009 - nil).


INTEREST
                                                    Three Months Ended March 31
                                                    ---------------------------
                                                          2010          2009
--------------------------------------------------- -------------- -------------
Interest                                                       98            94
   Less: Capitalized                                          (18)          (26)
                                                    -------------- -------------
Net Interest Expense                                           80            68
                                                    ============== =============

Effective Interest Rate                                       5.2%          4.9%
                                                    -------------- -------------

HIGHER NET INTEREST EXPENSE REDUCED NET INCOME BY $12 MILLION
Our financing costs increased $4 million from the first quarter of 2009. In July
2009, we issued US$1 billion of long-term notes and additional  interest expense
in the quarter related to this debt was $17 million.  This was partially  offset
by the strengthening Canadian dollar which decreased our US-denominated interest
expense by $13 million.

Capitalized  interest  was $8  million  lower  than 2009 as we  completed  major
development  projects.   Construction  completion  of  our  Long  Lake  Phase  1
facilities  and our  Ettrick  project  in the UK North Sea  reduced  capitalized
interest  by $10  million and $8 million,  respectively.  These  decreases  were
partially offset by $6 million of additional  capitalized  interest on our major
development  project  at  Usan,  offshore  West  Africa.  We  also  continue  to
capitalize interest on the construction of the fourth platform at Buzzard and on
our Chemicals technical conversion project in North Vancouver.

INCOME TAXES
                                                    Three Months Ended March 31
                                                    ---------------------------
                                                          2010          2009
--------------------------------------------------- -------------- -------------
Current                                                       259           118
Future                                                       (100)          (87)
                                                    -------------- -------------
Total Provision for Income Taxes                              159            31
                                                    ============== =============

HIGHER TAXES REDUCED NET INCOME BY $128 MILLION
Stronger  commodity prices in the first quarter compared to the same period last
resulted in an increase to our tax expense.  Our future tax expense in 2009 also
included  the  effect of a  reduction  in  Canadian  tax  rates.  Our income tax
provision includes current taxes in the United Kingdom,  Yemen, Norway, Colombia
and the United States.

                                       44
<PAGE>

OTHER
                                                    Three Months Ended March 31
                                                    ---------------------------
                                                          2010          2009
--------------------------------------------------- -------------- -------------
Decrease in Fair Value of Crude Oil Put Options               (16)          (16)
                                                    -------------- -------------

In the fourth  quarter of 2009, we purchased put options on 90,000 bbls/d of our
2010  crude  oil  production.  These  options  establish  a WTI  floor  price of
US$50/bbl  and provide a base level of price  protection  without  limiting  our
upside to higher  prices.  Options on 60,000  bbls/d settle  monthly,  while the
remaining  options  settle  annually.  These  options are recorded at fair value
throughout  their term. As a result,  changes in forward crude oil prices create
gains or losses on these  options  at each  period  end.  The put  options  were
purchased  for $39 million and are  carried at fair  value.  At March 31,  2010,
higher crude oil prices  reduced the fair value of the options to  approximately
$1 million,  $16 million lower than the end of 2009. In 2009, we recorded a fair
value loss of $16 million on our 2009 crude oil put option program.

LIQUIDITY AND CAPITAL RESOURCES

CAPITAL STRUCTURE
                                                        March 31    December 31
                                                          2010         2009
---------------------------------------------------- ------------- -------------
NET DEBT (1)
       Bank Debt                                            1,770         1,803
       Public Senior Notes                                  4,831         4,982
                                                     ------------- -------------
      Total Senior Debt                                     6,601         6,785
       Subordinated Debt                                      453           466
                                                     ------------- -------------
      Total Debt                                            7,054         7,251
       Less: Cash and Cash Equivalents                     (1,997)       (1,700)
                                                     ------------- -------------
TOTAL NET DEBT                                              5,057         5,551
                                                     ============= =============

EQUITY                                                      7,827         7,646
                                                     ============= =============

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

NET DEBT

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

--------------------------------------------------------------------------------
Capital Investment                                                         (556)
Cash Flow from Operating Activities (1)                                     798
                                                                     -----------
  Excess Cash Generated                                                     242

Dividends on Common Shares                                                  (26)
Issue of Common Shares                                                       25
Changes in Restricted Cash                                                   15
Foreign Exchange Translation of US-dollar Debt and Cash                     141
Other                                                                        97
                                                                     -----------
                                                                     -----------
Decrease in Net Debt                                                        494
                                                                     ===========

(1)  Includes changes in non-cash  working  capital.  For the three months ended
     March 31, 2010, $256 million was included as a source of cash flow.

Our net debt decreased  approximately $500 million from December 31, 2009 as our
cash  flow  from  operating   activities  exceeded  our  first  quarter  capital
investment by $242 million.  Additionally, the stronger Canadian dollar relative
to the US dollar,  decreased our US dollar  denominated debt and US dollar cash.
This reduced net debt by $141 million. Our available liquidity at March 31, 2010
was  approximately  $3.6 billion,  comprised of cash on hand and undrawn  credit
facilities.  Operating cash flows in the oil and gas industry can be volatile as
short-term   commodity   prices  are  driven  by  existing   supply  and  demand
fundamentals and market volatility.  We periodically  invest through the lows of
the  current  commodity  market  to  create  future  growth  and  value  for our
shareholders for the long-term. Changes in our non-cash working capital can vary
between quarters as our energy marketing net working capital position fluctuates
depending on timing of  settlement  of  outstanding  positions,  the movement in
commodity prices and inventory cycles.

                                       45
<PAGE>

CHANGE IN WORKING CAPITAL
                                           March 31   December 31   Increase/
                                            2010          2009      (Decrease)
---------------------------------------- ------------ ------------ ------------
Cash and Cash Equivalents                      1,997        1,700           297
Restricted Cash                                  178          198           (20)
Accounts Receivable                            2,635        2,788          (153)
Inventories and Supplies                         574          680          (106)
Accounts Payable and Accrued Liabilities      (3,084)      (3,038)          (46)
Other                                             (1)          70           (71)
                                         ------------ ------------ ------------
Net Working Capital                            2,299        2,398
                                         ============ ============

We generated cash from reducing  working capital  requirements  since the end of
2009.  Cash was  generated  by selling  commodity  inventory  held by our energy
marketing  group and  timing of crude oil sales in the UK. We sold  natural  gas
trading inventory during the winter heating season. In addition, we are reducing
our trading  activity to focus on  supporting  our core  physical  business as a
producer/marketer.  Working  capital was also reduced from the timing of current
tax payments to governments.

At March 31,  2010,  our  restricted  cash  consists of margin  deposits of $178
million (December 31, 2009 - $198 million) related to exchange-traded derivative
financial  contracts  used by our  energy  marketing  group  to  hedge  physical
commodities,  and storage,  transportation and customer sales contracts.  We are
required  to  maintain  margin  for net  out-of-the-money  derivative  financial
contracts.

OUTLOOK FOR REMAINDER OF 2010

We expect  our 2010  production  to range  between  230,000  and  280,000  boe/d
(200,000 and 250,000 boe/d after  royalties).  We expect to continue to fund our
2010 capital investment program using cash flow from operating activities.

Our future  liquidity and ability to fully fund capital  requirements  generally
depends upon operating cash flows,  existing working  capital,  unused committed
credit facilities,  and our ability to access debt and equity markets. Given the
long cycle  time of some of our  development  projects  and  volatile  commodity
prices,  it is not  unusual in any year for capital  expenditures  to exceed our
cash flow. Changes in commodity prices,  particularly crude oil as it represents
approximately  85% of our  current  production,  can impact our  operating  cash
flows.  We use  short-term  contracts  to sell the  majority  of our oil and gas
production,  exposing us to short-term price movements. A US$1/bbl change in WTI
above  US$50/bbl  is  projected  to  increase  or  decrease  our cash  flow from
operating  activities,  after cash taxes, by  approximately  $36 million for the
remainder of 2010.  Our exposure to a $0.01 change in the US to Canadian  dollar
exchange   rate  is   projected  to  increase  or  decrease  our  cash  flow  by
approximately  $27 million for the remainder of 2010. While commodity prices can
fluctuate significantly in the short term, we believe that over the longer term,
commodity  prices will  continue to remain strong as a result of growth in world
demand and delays or  shortages in supply  growth.  We believe that our existing
liquidity, balance sheet capacity and capital investment flexibility provides us
with the  ability to fund our  obligations  during  periods  of lower  commodity
prices.

During the first three months of 2010, we have incurred approximately 20% of our
2010 capital budget and generated cash flow from operating  activities in excess
of our capital  investment by $242 million.  We currently have  approximately $2
billion of cash and cash equivalents on hand and as well as significant  undrawn
committed credit facilities available.  At March 31, 2010, we had unsecured term
credit  facilities of US$3.1 billion in place that are available  until 2012, of
which  US$1.5  billion  was  drawn  and  US$385  million  was  used  to  support
outstanding  letters  of  credit.  We also have  approximately  $466  million of
undrawn,  uncommitted,  unsecured credit  facilities,  of which $116 million was
used to support outstanding letters of credit. The average length-to-maturity of
our public debt is approximately 17 years.

                                       46
<PAGE>

CONTRACTUAL OBLIGATIONS, COMMITMENTS AND GUARANTEES

We have assumed  various  contractual  obligations and commitments in the normal
course of our operations and financing activities. We included these obligations
and commitments in our MD&A in our 2009 Form 10-K.

During the quarter,  we sold our European gas and power marketing  business.  We
agreed to maintain our parental guarantees to the existing  counterparties until
the purchaser is able to replace them. The  guarantees  expire at the earlier of
the purchaser  replacing the  guarantees  and July 25, 2010. We are obligated to
perform under the guarantees only if the purchaser does not meet its obligations
to the  counterparties.  Our  total  exposure  is $275  million  for  which  the
purchaser  has  provided  us an  indemnity  and a letter of credit from a highly
rated financial institution.

There have been no other significant developments since year-end.

CONTINGENCIES

There are a number of lawsuits and claims pending,  the ultimate result of which
cannot be  ascertained  at this time.  We record  costs as they are  incurred or
become determinable. We believe the resolution of these matters would not have a
material  adverse effect on our liquidity,  consolidated  financial  position or
results of operations.  These matters are described in LEGAL PROCEEDINGS in Item
3 contained in our 2009 Form 10-K.  There have been no significant  developments
since year-end.

                                       47
<PAGE>

NEW ACCOUNTING PRONOUNCEMENTS


CANADIAN PRONOUNCEMENTS
INTERNATIONAL FINANCIAL REPORTING STANDARDS ADOPTION PLAN

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

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

The  following  chart is a summary of our progress  since our  previous  update.
Significant changes are highlighted below:

<TABLE>
<CAPTION>

------------------------------------------- ------------------------------------------ -----------------------------------------
KEY ACTIVITY                                KEY MILESTONE                              STATUS
------------------------------------------- ------------------------------------------ -----------------------------------------
Financial Information
------------------------------------------- ------------------------------------------ -----------------------------------------
<S>                                         <C>                                        <C>
o   Identify differences between Canadian   o   Comprehensive analysis of IFRS         o   Comprehensive analysis completed
    GAAP and IFRS                               differences identified in the              mid 2009
o   Revise  accounting  policies under IFRS     diagnostics  phase                     o   Received  senior management  approval
o   Identify  potential  adjustments  to    o   Senior  management approval of IFRS        of IFRS accounting policies
    initial IFRS financial statements           accounting policies                    o   Areas of potential adjustment to
o   Develop IFRS-compliant financial        o   Develop draft IFRS financial               opening balance sheet identified
    statements, including transition            statements and disclosures             o   ANALYSIS TO SUPPORT OPENING
    period disclosures                                                                     BALANCE SHEET ADJUSTMENTS IS
                                                                                           UNDERWAY
                                                                                       o   DRAFT IFRS FINANCIAL STATEMENTS AND
                                                                                           NOTE DISCLOSURES ARE SUBSTANTIALLY
                                                                                           COMPLETE
------------------------------------------- ------------------------------------------ -----------------------------------------
Training and Communication
------------------------------------------- ------------------------------------------ -----------------------------------------
o   Develop and deliver  targeted IFRS      o   Delivery of training in 2009           o   Targeted training completed in 2009
    training to employees and management        targeted to affected employees         o   Strategy for follow-up training in
o   Ensure internal and external            o   Ongoing communication with major           2010 developed
    stakeholders receive ongoing                internal and external stakeholders     o   Regular communication with Project
    appropriate communications                                                             Steering Committee, senior
o   Develop and deliver targeted IFRS                                                      management and Audit Committee
    training to senior management and                                                      throughout the year
    Board of Directors                                                                 o   Quarterly disclosure of project
                                                                                           status in MD&A
------------------------------------------- ------------------------------------------ -----------------------------------------
Information Technology
------------------------------------------- ------------------------------------------ -----------------------------------------
o   Ensure systems are able to adequately   o   Be IFRS data capture ready             o    System testing for IFRS data
    support  conversion to IFRS and             January 1, 2010                             capture complete
    ongoing  financial  reporting           o   Ensure dual GAAP  reporting            o    Dual GAAP reporting capability
                                                capability throughout 2010                  testing complete
                                                                                       o    IFRS DATA CAPTURE IN THE
                                                                                            FINANCIAL SYSTEM HAS COMMENCED
------------------------------------------- ------------------------------------------ -----------------------------------------
Business Process
------------------------------------------- ------------------------------------------ -----------------------------------------
o   Ensure business processes and control   o   Implement necessary business process   o    Necessary changes to business
    environment properly support                and key control changes to ensure           process have been designed
    conversion to IFRS and ongoing              adequate  internal control over        o    Key controls designed to ensure
    financial reporting                         financial reporting                         adequate internal control over
                                                                                            financial reporting on IFRS results
                                                                                            throughout 2010
------------------------------------------- ------------------------------------------ -----------------------------------------
</TABLE>

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

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

                                       48

<PAGE>

EQUITY SECURITY REPURCHASES

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

SUMMARY OF QUARTERLY RESULTS

<TABLE>
<CAPTION>

                                                             2008             |                2009                  |    2010
                                                  ----------------------------|--------------------------------------|---------
(Cdn$ millions, except per share amounts)            Jun       Sep       Dec  |     Mar       Jun       Sep      Dec |     Mar
------------------------------------------------- --------- --------- --------|--------- --------- --------- --------|---------
<S>                                                <C>      <C>       <C>      <C>       <C>       <C>       <C>      <C>
Net Sales                                            2,071    2,213     1,270 |   1,048    1,200     1,097     1,550 |   1,501
                                                                              |                                      |
Net Income (Loss)                                      380      886      (181)|      135       20       122       259|     185
                                                                              |                                      |
Earnings (Loss) Per Common Share ($/share)                                    |                                      |
     Basic                                            0.72     1.68     (0.35)|    0.26     0.04       0.23     0.50 |    0.35
     Diluted                                          0.70     1.66     (0.35)|    0.26     0.04       0.23     0.49 |    0.35
                                                  --------- --------- --------|--------- --------- --------- --------|---------
</TABLE>

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain  statements in this report,  including  those  appearing in MANAGEMENT'S
DISCUSSION  AND  ANALYSIS OF  FINANCIAL  CONDITION  AND  RESULTS OF  OPERATIONS,
constitute "forward-looking statements" (within the meaning of the United States
PRIVATE   SECURITIES   LITIGATION   REFORM   ACT  OF  1995,   as   amended)   or
"forward-looking   information"  (within  the  meaning  of  applicable  Canadian
securities    legislation).    Such   statements   or   information    (together
"forward-looking  statements") are generally identifiable by the forward-looking
terminology used such as "ANTICIPATE",  "BELIEVE",  "INTEND",  "PLAN", "expect",
"ESTIMATE",  "BUDGET", "OUTLOOK", "FORECAST" or other similar words, and include
statements relating to or associated with individual wells, regions or projects.
Any statements regarding the following are forward-looking statements:

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


                                       49
<PAGE>

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

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

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

These  risks,  uncertainties  and other  factors and their  possible  impact are
discussed  more  fully  in the  sections  titled  RISK  FACTORS  in  Item 1A and
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and in Item 7A of our
2009  Form  10-K.  The  impact  of any one  risk,  uncertainty  or  factor  on a
particular forward-looking statement is not determinable with certainty as these
factors are  interdependent,  and  management's  future  course of action  would
depend on an assessment of all information at that time.

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

ITEM 3.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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


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

At March 31, 2010:

o    over 96% of our credit exposures were investment grade;

o    approximately  70% of our  credit  exposures  were with a diverse  group of
     integrated  oil  companies,  crude oil  refiners and  marketers,  and large
     utilities; and

o    only two  counterparties  individually  made up more than 10% of our credit
     exposure.  These  counterparties  are major  integrated  oil companies with
     strong investment grade credit ratings.

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

                                       50

<PAGE>

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

                                       51
<PAGE>


                                     PART II


ITEM 1.   LEGAL PROCEEDINGS

Information  in  response  to this item is included in Part I, Item 1 in Note 16
"Commitments,  Contingencies  and  Guarantees"  and is incorporated by reference
into Part II of this Quarterly Report on Form 10-Q.


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 30, 2010.

                                          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)





                                       52