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

                                 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, 2007

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

                         COMMISSION FILE NUMBER 1-6702

                              [GRAPHIC OMITTED]
                              [LOGO - NEXEN INC.]


                                   NEXEN INC.


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

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


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

                   Yes  [X]                 No   [_]

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

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

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

                   Yes  [_]                 No   [X]

On March 31, 2007, there were 263,188,018 common shares issued and outstanding.

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

                                   NEXEN INC.
                                     INDEX

PART I        FINANCIAL INFORMATION                                         PAGE

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

    Item 2.   Management's Discussion and Analysis of Financial Condition
              and Results of Operation........................................24

    Item 3.   Quantitative and Qualitative Disclosures about Market Risk......42

    Item 4.   Controls and Procedures.........................................42

PART II       OTHER INFORMATION

    Item 4.   Submission of Matters to a Vote of Security Holders.............43

    Item 6.   Exhibits........................................................43

This report should be read in  conjunction  with our 2006 Annual Report on Form
10-K,  our amended  2006 Form  10-K/A and with our current  reports on Form 8-K
filed or furnished during the year.


SPECIAL NOTE TO CANADIAN INVESTORS

Nexen is a US Securities and Exchange  Commission  (SEC)  registrant and a Form
10-K and related forms filer. Therefore,  our reserves estimates and securities
regulatory  disclosures  generally follow SEC  requirements.  In 2004,  certain
Canadian regulatory  authorities adopted NATIONAL INSTRUMENT 51-101 - STANDARDS
OF  DISCLOSURE  FOR OIL AND GAS  ACTIVITIES  (NI 51-101) which  prescribe  that
Canadian  companies follow certain standards for the preparation and disclosure
of reserves and related  information.  We have been granted certain  exemptions
from NI 51-101.  Please refer to the SPECIAL NOTE TO CANADIAN INVESTORS on page
81 of our 2006 Annual Report on Form 10-K.

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

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

<TABLE>
<CAPTION>
<S>                                                   <C>
/d     =   per day                                    mmboe  =   million barrels of oil equivalent
bbl    =   barrel                                     mcf    =   thousand cubic feet
mbbls  =   thousand barrels                           mmcf   =   million cubic feet
mmbbls =   million barrels                            bcf    =   billion cubic feet
mmbtu  =   million British thermal units              NGL    =   natural gas liquid
boe    =   barrels of oil equivalent                  WTI    =   West Texas Intermediate
mboe   =   thousand barrels of oil equivalent         MW     =   megawatt
</TABLE>

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

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

On March 30, 2007,  the noon-day  exchange rate was US$0.8674 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 (Loss)
for the Three Months Ended March 31, 2007 and 2006...........................4

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

Unaudited Consolidated Statement of Cash Flows
for the Three Months Ended March 31, 2007 and 2006...........................6

Unaudited Consolidated Statement of Shareholders' Equity
for the Three Months Ended March 31, 2007 and 2006...........................7

Unaudited Consolidated Statement of Comprehensive Income
for the Three Months Ended March 31, 2007 and 2006...........................7

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


                                       3
<PAGE>

NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF INCOME (LOSS)
FOR THE THREE MONTHS ENDED MARCH 31
Cdn$ millions, except per share amounts

                                                                2007      2006
-------------------------------------------------------------------------------
REVENUES AND OTHER INCOME
    Net Sales                                                  1,140       980
    Marketing and Other (Note 13)                                248       426
                                                             ------------------
                                                               1,388     1,406
                                                             ------------------
EXPENSES
    Operating                                                    290       250
    Depreciation, Depletion, Amortization
        and Impairment                                           334       266
    Transportation and Other                                     246       260
    General and Administrative                                   202       220
    Exploration                                                   49       103
    Interest (Note 6)                                             48         9
                                                             ------------------
                                                               1,169     1,108
                                                             ------------------

INCOME BEFORE INCOME TAXES                                       219       298
                                                             ------------------

PROVISION FOR INCOME TAXES
    Current                                                       60       109
    Future                                                        35       269
                                                             ------------------
                                                                  95       378
                                                             ------------------

NET INCOME (LOSS) BEFORE NON-CONTROLLING INTERESTS               124       (80)
    Net Income Attributable to Non-Controlling Interests          (3)       (3)
                                                             ------------------

NET INCOME (LOSS)                                                121       (83)
                                                             ==================

EARNINGS (LOSS) PER COMMON SHARE ($/share)
    Basic (Note 11)                                             0.46     (0.32)
                                                             ==================

    Diluted (Note 11)                                           0.45     (0.32)
                                                             ==================


SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.


                                      4
<PAGE>

NEXEN INC.
UNAUDITED CONSOLIDATED BALANCE SHEET
Cdn$ millions, except share amounts

                                                          March 31  December 31
                                                              2007         2006
-------------------------------------------------------------------------------
ASSETS
    CURRENT ASSETS
      Cash and Cash Equivalents                                110          101
      Restricted Cash and Margin Deposits                      181          197
      Accounts Receivable (Note 2)                           2,853        2,951
      Inventories and Supplies (Note 3)                        665          786
      Future Income Tax Assets                                 426          479
      Other                                                     71           67
                                                         ----------------------
         Total Current Assets                                4,306        4,581
                                                         ----------------------

    PROPERTY, PLANT AND EQUIPMENT
      Net of Accumulated Depreciation, Depletion,
         Amortization and Impairment of $6,530
        (December 31, 2006 - $6,399)                        12,183       11,739
    GOODWILL                                                   374          377
    FUTURE INCOME TAX ASSETS                                   138          141
    DEFERRED CHARGES AND OTHER ASSETS (Note 4)                 312          318
                                                         ----------------------
TOTAL ASSETS                                                17,313       17,156
                                                         ======================

LIABILITIES AND SHAREHOLDERS' EQUITY
    CURRENT LIABILITIES
      Short-Term Borrowings (Note 6)                           107          158
      Accounts Payable and Accrued Liabilities               3,814        3,879
      Accrued Interest Payable                                  36           55
      Dividends Payable                                         13           13
                                                         ----------------------
         Total Current Liabilities                           3,970        4,105
                                                         ----------------------

    LONG-TERM DEBT (Note 6)                                  4,942        4,673
    FUTURE INCOME TAX LIABILITIES                            2,431        2,468
    ASSET RETIREMENT OBLIGATIONS (Note 7)                      691          683
    DEFERRED CREDITS AND OTHER LIABILITIES (Note 8)            423          516
    NON-CONTROLLING INTERESTS                                   73           75

    SHAREHOLDERS' EQUITY (Note 10)
      Common Shares, no par value
        Authorized:           Unlimited
        Outstanding:          2007 - 263,188,018 shares
                              2006 - 262,513,206 shares        866          821
      Contributed Surplus                                        4            4
      Retained Earnings                                      4,080        3,972
      Accumulated Other Comprehensive Income (Note 1)         (167)        (161)
                                                         ----------------------
         Total Shareholders' Equity                          4,783        4,636
                                                         ----------------------
    COMMITMENTS, CONTINGENCIES AND GUARANTEES (Note 14)

                                                         ----------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                  17,313       17,156
                                                         ======================


SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.


                                      5
<PAGE>

<TABLE>
<CAPTION>
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE THREE MONTHS ENDED MARCH 31
Cdn$ millions

                                                                         2007           2006
----------------------------------------------------------------------------------------------
<S>                                                                      <C>            <C>
 OPERATING ACTIVITIES
    Net Income (Loss)                                                     121            (83)
    Charges and Credits to Income not Involving Cash (Note 12)            435            672
    Exploration Expense                                                    49            103
    Changes in Non-Cash Working Capital (Note 12)                          32             73
    Other                                                                (189)           (31)
                                                                       -----------------------
                                                                          448            734

FINANCING ACTIVITIES
    Proceeds from (Repayment of) Term Credit Facilities, Net              366             (4)
    Proceeds from (Repayment of) Short-Term Borrowings, Net               (48)            35
    Proceeds from Term Credit Facilities of Canexus                        18              -
    Dividends on Common Shares                                            (13)           (13)
    Issue of Common Shares                                                 29             13
    Other                                                                  (7)            (7)
                                                                       -----------------------
                                                                          345             24

INVESTING ACTIVITIES
    Capital Expenditures
      Exploration and Development                                        (790)          (719)
      Proved Property Acquisitions                                         (1)            (3)
      Chemicals, Corporate and Other                                      (20)           (10)
    Business Acquisitions, Net of Cash Acquired                             -            (21)
    Changes in Restricted Cash                                             16            (54)
    Changes in Non-Cash Working Capital (Note 12)                          28             23
    Other                                                                  (4)             7
                                                                       -----------------------
                                                                         (771)          (777)

EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS              (13)             1
                                                                       -----------------------

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                            9            (18)

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

CASH AND CASH EQUIVALENTS - END OF PERIOD                                 110             30
                                                                       =======================
</TABLE>

SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.


                                       6
<PAGE>

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

<TABLE>
<CAPTION>
                                                                                            2007        2006
---------------------------------------------------------------------------------------------------------------
<S>                                                                                        <C>          <C>
COMMON SHARES
    Balance at Beginning of Period                                                           821         732
      Issue of Common Shares                                                                  21           5
      Proceeds from Options Exercised for Shares                                               8           8
      Accrued Liability Relating to Options Exercised for Shares                              16          18
                                                                                 ------------------------------
    Balance at End of Period                                                                 866         763
                                                                                 ==============================

CONTRIBUTED SURPLUS
    Balance at Beginning of Period                                                             4           2
      Stock-Based Compensation Expense                                                         -           -
                                                                                 ------------------------------
    Balance at End of Period                                                                   4           2
                                                                                 ==============================

RETAINED EARNINGS
    Balance at Beginning of Period                                                         3,972       3,435
      Net Income (Loss)                                                                      121         (83)
      Dividends on Common Shares                                                             (13)        (13)
                                                                                 ------------------------------
    Balance at End of Period                                                               4,080       3,339
                                                                                 ==============================

ACCUMULATED OTHER COMPREHENSIVE INCOME
    Balance at Beginning of Period                                                          (161)          -
      Opening Cumulative Foreign Currency Translation Adjustment (Note 1)                      -        (161)
      Opening Derivatives Designated as Cash Flow Hedges (Note 1)                             61           -
      Other Comprehensive Income                                                             (67)         (6)
                                                                                 ------------------------------
    Balance at End of Period                                                                (167)       (167)
                                                                                 ==============================

<CAPTION>
NEXEN INC.
UNAUDITED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
FOR THE THREE MONTHS ENDED MARCH 31
Cdn$ millions
                                                                                            2007        2006
---------------------------------------------------------------------------------------------------------------
<S>                                                                                         <C>         <C>
    Net Income (Loss)                                                                        121         (83)
    Other Comprehensive Income, Net of Income Taxes:
      Foreign Currency Translation Adjustment:
        Net Gains (Losses) on Investment in Self-Sustaining Foreign Operations               (58)          2
        Net Gains (Losses) on Hedges of Self-Sustaining Foreign Operations (1)                50          (7)
        Realized Translation Adjustments Recognized in Net Income (2)                          2          (1)
      Cash Flow Hedges:
        Realized Mark to Market Gains Recognized in Net Income                               (61)          -
                                                                                           --------------------
      Other Comprehensive Income                                                             (67)         (6)
                                                                                           --------------------
    Comprehensive Income                                                                      54         (89)
                                                                                           ====================
</TABLE>

Notes:
(1)   Net of income taxes of $9 million (2006 - $1 million)
(2)   Net of income taxes of $1 million (2006 - nil)


SEE ACCOMPANYING NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS.


                                       7
<PAGE>

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

1.     ACCOUNTING POLICIES

Our Unaudited Consolidated Financial Statements are prepared in accordance with
Canadian  Generally  Accepted  Accounting  Principles  (GAAP).  The  impact  of
significant  differences  between  Canadian and United  States (US) GAAP on the
Unaudited  Consolidated  Financial  Statements  is disclosed in Note 16. In the
opinion of management,  the Unaudited Consolidated Financial Statements contain
all  adjustments of a normal and recurring  nature  necessary to present fairly
Nexen Inc.'s (Nexen,  we or our)  financial  position at March 31, 2007 and the
results of our  operations  and our cash flows for the three months ended March
31, 2007 and 2006.

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

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

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

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

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

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

HEDGES
Section 3865 prescribes new standards for hedge accounting.

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

For fair value hedges, both the financial instrument designated as a fair value
hedge  and  the   underlying   commitment   are  recognized  on  the  Unaudited
Consolidated Balance Sheet at fair value. Changes in the fair value of both are
reflected in the Unaudited Consolidated Statement of Income.


                                       8
<PAGE>

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

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

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

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

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

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

<CAPTION>
2.     ACCOUNTS RECEIVABLE
                                                                                                 March 31           December 31
                                                                                                     2007                  2006
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                              <C>                <C>
Trade
    Marketing                                                                                       2,092                 2,226
    Oil and Gas                                                                                       647                   600
    Chemicals and Other                                                                                58                    58
                                                                                                 -------------------------------
                                                                                                    2,797                 2,884
Non-Trade                                                                                              69                    80
                                                                                                 -------------------------------
                                                                                                    2,866                 2,964
Allowance for Doubtful Receivables                                                                    (13)                  (13)
                                                                                                 -------------------------------
Total                                                                                               2,853                 2,951
                                                                                                 ===============================
<CAPTION>
3.    INVENTORIES AND SUPPLIES
                                                                                                  March 31          December 31
                                                                                                      2007                 2006
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                               <C>               <C>
Finished Products
    Marketing                                                                                         535                   609
    Oil and Gas                                                                                         6                    21
    Chemicals and Other                                                                                 7                    14
                                                                                                 -------------------------------
                                                                                                      548                   644
Work in Process                                                                                         5                     5
Field Supplies                                                                                        112                   137
                                                                                                 -------------------------------
Total                                                                                                 665                   786
                                                                                                 ===============================
</TABLE>


                                       9
<PAGE>

<TABLE>
<CAPTION>
4.    DEFERRED CHARGES AND OTHER ASSETS
                                                                                                 March 31           December 31
                                                                                                     2007                  2006
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                             <C>                 <C>
Long-Term Marketing Derivative Contracts (Note 9)                                                     210                   153
Deferred Financing Costs (Note 1)                                                                       -                    59
Asset Retirement Remediation Fund                                                                      14                    13
Crude Oil Put Options (Note 9)                                                                          3                    19
Other                                                                                                  85                    74
                                                                                                -------------------------------
Total                                                                                                 312                   318
                                                                                                ===============================
</TABLE>

5.     SUSPENDED WELL COSTS

The following  table shows the changes in  capitalized  exploratory  well costs
during the three month period ended March 31, 2007 and the year ended  December
31, 2006,  and does not include  amounts that were  initially  capitalized  and
subsequently expensed in the same period.

<TABLE>
<CAPTION>
                                                                                             Three Months                  Year
                                                                                                    Ended                 Ended
                                                                                                 March 31           December 31
                                                                                                     2007                  2006
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                             <C>                 <C>
Balance at Beginning of Period                                                                        226                   252
    Additions to Capitalized Exploratory Well Costs Pending the
      Determination of Proved Reserves                                                                 26                   129
    Capitalized Exploratory Well Costs Charged to Expense                                               -                   (70)
    Transfers to Wells, Facilities and Equipment Based on
      Determination of Proved Reserves                                                                (13)                  (84)
    Effects of Foreign Exchange                                                                        (1)                   (1)
                                                                                             -----------------------------------
Balance at End of Period                                                                              238                   226
                                                                                             ===================================
</TABLE>

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

<TABLE>
<CAPTION>
                                                                                                 March 31           December 31
                                                                                                     2007                  2006
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                                                             <C>                 <C>
Capitalized for a Period of One Year or Less                                                          119                   179
Capitalized for a Period of Greater than One Year                                                     119                    47
                                                                                                 -------------------------------
Balance at End of Period                                                                              238                   226
                                                                                                 ===============================
Number of Projects that have Exploratory Well Costs Capitalized for a Period
    Greater than One Year                                                                               5                     4
                                                                                                 -------------------------------
</TABLE>

As at March 31, 2007, we have exploratory  costs that have been capitalized for
more than one year relating to our interest in an exploratory  block,  offshore
Nigeria  ($21  million),  our interest in an  exploratory  block in the Gulf of
Mexico ($56 million), our coalbed methane exploratory activities in Canada ($23
million),  an  exploratory  well on  Block  51 in Yemen  ($12  million)  and an
exploratory  block in the North Sea ($7  million).  We have  capitalized  costs
related to successful wells drilled in Nigeria,  the Gulf of Mexico,  the North
Sea, and at Block 51 in Yemen. In Canada, we have capitalized exploratory costs
relating to our coalbed methane  projects.  We are assessing all of these wells
and projects,  and are working with our partners to prepare  development plans,
drill additional appraisal wells or to assess commercial viability.


                                      10
<PAGE>

6.     LONG-TERM DEBT AND SHORT-TERM BORROWINGS

                                                     March 31       December 31
                                                         2007              2006
--------------------------------------------------------------------------------
Term Credit Facilities (US$1,235 million) (c)           1,424             1,078
Canexus LP Term Credit Facilities (US$164 million)        189               174
Medium-Term Notes, due 2007 (1)                           150               150
Medium-Term Notes, due 2008                               125               125
Notes, due 2013 (US$500 million)                          577               583
Notes, due 2015 (US$250 million)                          288               291
Notes, due 2028 (US$200 million)                          230               233
Notes, due 2032 (US$500 million)                          577               583
Notes, due 2035 (US$790 million)                          911               920
Subordinated Debentures, due 2043 (US$460 million)        530               536
                                                      --------------------------
                                                        5,001             4,673
Unamortized Debt Issue Costs (Note 1)                     (59)                -
                                                      --------------------------
Total Long-Term Debt                                    4,942             4,673
                                                      ==========================

Note:
(1)   Amounts  due July 2007 are not  included  in  current  liabilities  as we
      expect to refinance this amount with our term credit facilities.


(a)   INTEREST EXPENSE

                                                           Three Months
                                                          Ended March 31
                                                      2007             2006
-------------------------------------------------------------------------------
Long-Term Debt                                          81               62
Other                                                    5                4
                                                    ---------------------------
                                                        86               66
   Less: Capitalized                                   (38)             (57)
                                                    ---------------------------
Total                                                   48                9
                                                    ===========================

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

(b)    SHORT-TERM BORROWINGS

Nexen has  uncommitted,  unsecured  credit  facilities  of  approximately  $632
million,  of which $107  million  (US$93  million)  was drawn at March 31, 2007
(December 31, 2006 - $158 million). We have also utilized $181 million of these
facilities to support outstanding letters of credit at March 31, 2007 (December
31,  2006  -  $252  million).  Interest  is  payable  at  floating  rates.  The
weighted-average  interest rate on our  short-term  borrowings was 5.9% for the
three months ended March 31, 2007 (2006 - 4.8%).

(c)    TERM CREDIT FACILITIES

We have committed,  unsecured term credit facilities of $3.5 billion, which are
available to 2011. At March 31, 2007,  $1,424  million  (US$1,235  million) was
drawn on these facilities (December 31, 2006 - $1,078 million).  Borrowings are
available as Canadian bankers'  acceptances,  LIBOR-based loans, Canadian prime
loans,  US-dollar base rate loans or British pound call-rate loans. Interest is
payable monthly at floating rates.  The  weighted-average  interest rate on our
term credit facilities was 5.9% for the three months ended March 31, 2007 (2006
- 5.2%). At March 31, 2007,  $224 million of these  facilities were utilized to
support outstanding letters of credit (December 31, 2006 - $294 million).


                                      11
<PAGE>

7.     ASSET RETIREMENT OBLIGATIONS

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

                                                  Three Months           Year
                                                         Ended          Ended
                                                      March 31    December 31
                                                          2007           2006
-------------------------------------------------------------------------------
Balance at Beginning of Period                             704            611
    Obligations Assumed with Development Activities         11             75
    Obligations Discharged with Disposed Properties          -             (1)
    Expenditures Made on Asset Retirements                  (7)           (44)
    Accretion                                               11             37
    Revisions to Estimates                                  (3)           (10)
    Effects of Foreign Exchange                             (4)            36
                                                          ---------------------
Balance at End of Period (1,2)                             712            704
                                                          =====================

Notes:
(1)  Obligations  due within 12 months of $21 million  (December 31, 2006 - $21
     million) have been included in accounts payable and accrued liabilities.
(2)  Obligations  relating to our oil and gas activities amount to $666 million
     (December  31,  2006 -  $658  million)  and  obligations  relating  to our
     chemicals  business  amount  to  $46  million  (December  31,  2006  - $46
     million).


Our total estimated  undiscounted asset retirement obligations amount to $1,792
million  (December 31, 2006 - $1,770  million).  We have  discounted  the total
estimated   asset   retirement    obligations    using   a    weighted-average,
credit-adjusted  risk-free rate of 5.7%.  Approximately $91 million included in
our asset retirement  obligations will be settled over the next five years. The
remaining  obligations  settle  beyond  five years and will be funded by future
cash flows from our operations.

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

8.     DEFERRED CREDITS AND OTHER LIABILITIES

                                                     March 31      December 31
                                                         2007             2006
--------------------------------------------------------------------------------
Deferred Transportation Revenue                            90               89
Long-Term Marketing Derivative Contracts (Note 9)          87              199
Fixed-Price Natural Gas Contracts (Note 9)                 77               74
Capital Lease Obligations                                  51               48
Defined Benefit Pension Obligations                        48               48
Stock-Based Compensation Liability                         15                6
Other                                                      55               52
                                                     --------------------------
Total                                                     423              516
                                                     ==========================



                                      12
<PAGE>

9.     FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

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

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

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

<TABLE>
<CAPTION>
Cdn$ millions                                         MARCH 31, 2007                           DECEMBER 31, 2006
-------------------------------------------------------------------------------   ------------------------------------
                                           Carrying       Fair    Unrecognized    Carrying       Fair     Unrecognized
                                              Value      Value      Gain/(Loss)      Value      Value      Gain/(Loss)
                                           ------------------------------------   ------------------------------------
<S>                                          <C>        <C>               <C>       <C>        <C>                <C>
Derivatives
    Commodity Price Risk
      Non-Trading Activities
        Crude Oil Put Options                     3          3               -          19         19               -
        Fixed-Price Natural Gas Contracts      (109)      (109)              -         (96)       (96)              -
        Natural Gas Swaps                        11         11               -          (8)        (8)              -

      Trading Activities
        Crude Oil and Natural Gas                88         88               -         372        372               -
        Future Sale of Gas Inventory              -          -               -           -         25              25

    Foreign Currency Exchange Rate Risk
      Trading Activities                          -          -               -         (12)       (12)             -
                                            -----------------------------------   ------------------------------------
Total Derivatives                                (7)        (7)              -         275        300              25
                                            ===================================   ====================================

Other Financial Liabilities
      Long-Term Debt                         (4,942)    (5,058)           (116)     (4,673)    (4,728)            (55)
                                            ===================================   ====================================
</TABLE>

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

(b)      COMMODITY PRICE RISK MANAGEMENT

NON-TRADING ACTIVITIES

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

CRUDE OIL PUT OPTIONS

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

<TABLE>
<CAPTION>
                                     Notional                   Average               Fair
                                      Volumes       Term          Price              Value
-------------------------------------------------------------------------------------------
                                     (bbls/d)                 (US$/bbl)    (Cdn$ millions)
<S>                                   <C>           <C>              <C>                <C>
WTI Crude Oil Put Options             105,000       2007             50                  3
                                                                           ================
</TABLE>


                                      13
<PAGE>

FIXED-PRICE NATURAL GAS CONTRACTS AND NATURAL GAS SWAPS

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

<TABLE>
<CAPTION>
                                             Notional                        Average              Fair
                                              Volumes            Term          Price             Value
-------------------------------------------------------------------------------------------------------
                                               (Gj/d)                         ($/Gj)    (Cdn$ millions)
<S>                                            <C>        <C>            <C>                       <C>
Fixed-Price Natural Gas Contracts              15,514     2007 - 2008           2.46               (32)
                                               15,514     2008 - 2010    2.56 - 2.77               (77)
                                                                                       ----------------
                                                                                                  (109)
                                                                                       ================
</TABLE>

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

<TABLE>
<CAPTION>
                                             Notional                        Average              Fair
                                              Volumes            Term          Price             Value
-------------------------------------------------------------------------------------------------------
                                               (Gj/d)                         ($/Gj)    (Cdn$ millions)
<S>                                            <C>        <C>                   <C>                 <C>
Natural Gas Swaps                              15,514     2007 - 2008           7.60                  4
                                               15,514     2008 - 2010           7.60                  7
                                                                                       ----------------
                                                                                                     11
                                                                                       ================
</TABLE>

TRADING ACTIVITIES

CRUDE OIL AND NATURAL GAS
We enter  into  physical  purchase  and sales  contracts  as well as  financial
commodity  contracts to enhance our price realizations and lock in our margins.
The physical and  financial  commodity  contracts  (derivative  contracts)  are
stated at fair value. The $88 million fair value of the derivative contracts at
March 31, 2007 is included in the Unaudited  Consolidated Balance Sheet and any
change  is  included  in  marketing  and  other in the  Unaudited  Consolidated
Statement of Income.

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

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

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

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

At March 31, 2007, there were no cash flow hedges in place.

                                      14
<PAGE>

(c)    FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT

TRADING ACTIVITIES

Our sales and purchases of crude oil and natural gas are  generally  transacted
in or  referenced  to the US  dollar,  as are most of the  financial  commodity
contracts  used  by our  marketing  group.  However,  we pay  for  many  of our
purchases in Canadian  dollars.  We enter into US-dollar  forward contracts and
swaps to manage  this  exposure.  Gains and  losses  on our  US-dollar  forward
contracts and swaps are included in the Unaudited  Consolidated  Balance Sheet,
and any  change  in fair  value  is  included  in  marketing  and  other in the
Unaudited  Consolidated  Statement of Income. At March 31, 2007, the fair value
of our US-dollar forward contracts and swaps was immaterial.

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

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

                                                       March 31     December 31
(Cdn$ millions)                                            2007            2006
--------------------------------------------------------------------------------
Accounts Receivable                                         339             731
Deferred Charges and Other Assets (1)                       210             153
                                                    ----------------------------
    Total Derivative Contract Assets                        549             884
                                                    ============================

Accounts Payable and Accrued Liabilities                    374             325
Deferred Credits and Other Liabilities (1)                   87             199
                                                    ----------------------------
    Total Derivative Contract Liabilities                   461             524
                                                    ============================

    Total Derivative Contract Net Assets (2)                 88             360
                                                    ============================

Notes:
(1)  These  derivative  contracts  settle  beyond 12 months and are  considered
     non-current.
(2)  Comprised  of $88  million  (2006 - $372  million)  related  to  commodity
     contracts  and  losses of nil (2006 - losses of $12  million)  related  to
     US-dollar forward contracts and swaps.

As a physical energy  marketer,  we match the contract months of our derivative
instruments with the contract months of our physical sales and purchases.  As a
result, our disclosure with respect to derivative  instruments includes amounts
with no ongoing  commodity price or foreign exchange risk as at March 31, 2007.
Excluding such amounts, derivative contracts included in accounts receivable at
March 31, 2007 amounted to $284 million  (December 31, 2006 - $460 million) and
derivative  contracts  included  in accounts  payable  and accrued  liabilities
amounted to $350 million (December 31, 2006 -$312 million).

Our  exchange-traded   derivative  contracts  are  subject  to  margin  deposit
requirements.  We are  required to advance cash to  counterparties  in order to
satisfy their  requirements.  We have margin deposits of $181 million (December
31,  2006 - $197  million),  which have been  included in  restricted  cash and
margin deposits on our Unaudited Consolidated Balance Sheet at March 31, 2007.

                                      15
<PAGE>

10.  SHAREHOLDERS' EQUITY

DIVIDENDS
Dividends per common share for the three months ended March 31, 2007 were $0.05
(2006 - $0.05). Dividends paid to holders of common shares have been designated
as "eligible dividends" for Canadian tax purposes.


11.  EARNINGS PER COMMON SHARE

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

<TABLE>
<CAPTION>
                                                                         Three Months
                                                                        Ended March 31
(millions of shares)                                                    2007       2006
----------------------------------------------------------------------------------------
<S>                                                                    <C>        <C>
Weighted-average number of common shares outstanding                   263.0      261.6
Shares issuable pursuant to tandem options                              14.2          -
Shares to be purchased from proceeds of tandem options                  (7.9)         -
                                                                    --------------------
Weighted-average number of diluted common shares outstanding           269.3      261.6
                                                                    ====================
</TABLE>

In calculating the weighted-average number of diluted common shares outstanding
for the three months ended March 31, 2007,  all options were  included  because
their  exercise  price was less than the quarterly  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,  2006,  all
options were excluded because they have an anti-dilutive impact on the loss per
share amounts. During the periods presented, outstanding stock options were the
only potential dilutive instruments.


12.  CASH FLOWS

(a)    CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH

<TABLE>
<CAPTION>
                                                                        Three Months
                                                                       Ended March 31
                                                                      2007         2006
----------------------------------------------------------------------------------------
<S>                                                                    <C>          <C>
Depreciation, Depletion, Amortization and Impairment                   334          266
Stock-Based Compensation                                                44          108
Future Income Taxes                                                     35          269
Change in Fair Value of Crude Oil Put Options                           16            4
Net Income Attributable to Non-Controlling Interests                     3            3
Other                                                                    3           22
                                                                    --------------------
Total                                                                  435          672
                                                                    ====================
</TABLE>

(b)    CHANGES IN NON-CASH WORKING CAPITAL

<TABLE>
<CAPTION>
                                                                        Three Months
                                                                       Ended March 31
                                                                      2007        2006
----------------------------------------------------------------------------------------
<S>                                                                     <C>         <C>
   Accounts Receivable                                                  75          829
   Inventories and Supplies                                             65         (150)
   Other Current Assets                                                 (4)           5
   Accounts Payable and Accrued Liabilities                            (58)        (571)
   Accrued Interest Payable                                            (18)         (17)
                                                                    --------------------
Total                                                                   60           96
                                                                    ====================

Relating to:
   Operating Activities                                                 32           73
   Investing Activities                                                 28           23
                                                                    --------------------
Total                                                                   60           96
                                                                    ====================
</TABLE>

                                      16
<PAGE>

(c)    OTHER CASH FLOW INFORMATION

<TABLE>
<CAPTION>
                                                                         Three Months
                                                                        Ended March 31
                                                                      2007         2006
----------------------------------------------------------------------------------------
<S>                                                                    <C>           <C>
Interest Paid                                                          101           80
Income Taxes Paid                                                       57           70
                                                                    --------------------
</TABLE>

13.  MARKETING AND OTHER

<TABLE>
<CAPTION>
                                                                         Three Months
                                                                       Ended March 31
                                                                      2007         2006
----------------------------------------------------------------------------------------
<S>                                                                    <C>          <C>
Marketing Revenue, Net                                                 247          437
Decrease in Fair Value of Crude Oil Put Options                        (16)          (4)
Interest                                                                 9            9
Foreign Exchange Losses                                                 (5)         (21)
Other                                                                   13            5
                                                                    --------------------
Total                                                                  248          426
                                                                    ====================
</TABLE>


14.  COMMITMENTS, CONTINGENCIES AND GUARANTEES

As  described  in  Note 15 to the  Audited  Consolidated  Financial  Statements
included in our 2006 Annual Report on Form 10-K, there are a number of lawsuits
and claims pending, the ultimate results of which cannot be ascertained at this
time. We record costs as they are incurred or become  determinable.  We believe
the resolution of these matters would not have a material adverse effect on our
liquidity, consolidated financial position or results of operations.


                                      17
<PAGE>

15.  OPERATING SEGMENTS AND RELATED INFORMATION

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

<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31, 2007

                                                                                                                   Corporate
                                                                                    Energy                           and
(Cdn$ millions)                                    Oil and Gas                    Marketing   Syncrude  Chemicals    Other   Total
-----------------------------------------------------------------------------------------------------------------------------------
                                                  United    United       Other
                                 Yemen    Canada  States    Kingdom  Countries(1)
                                -------------------------------------------------
<S>                              <C>      <C>     <C>       <C>      <C>          <C>         <C>       <C>        <C>       <C>
Net Sales                          243      115      168       344         29        16         119        106        -      1,140
Marketing and Other                  3        1        -         4          -       247           -          5      (12)(2)    248
                                ---------------------------------------------------------------------------------------------------
Total Revenues                     246      116      168       348         29       263         119        111      (12)     1,388
Less: Expenses
 Operating                          42       39       28        53          2        13          47         66        -        290
 Depreciation, Depletion,
   Amortization and
    Impairment                      58       41       84       114          3         4          13         11        6        334
 Transportation and Other            3        7        -         -          -       220           5         11        -        246
 General and Administrative (3)      1       32       19         5         24        30           -          9       82        202
 Exploration                         3        5       13        20          8(4)      -           -          -        -         49
 Interest                            -        -        -         -          -         -           -          3       45         48
                                ---------------------------------------------------------------------------------------------------
Income (Loss) from
   Continuing Operations
    before Income Taxes            139       (8)      24       156         (8)       (4)         54         11     (145)       219
                                ============================================================================================
Less: Provision for Income
 Taxes (5)                                                                                                                      95
Less: Non-Controlling
 Interests                                                                                                                       3
                                                                                                                            -------
Net Income                                                                                                                     121
                                                                                                                            =======

Identifiable Assets                521    4,279    1,668     5,356        248     3,372(6)    1,196        467       206    17,313
                                ===================================================================================================

Capital Expenditures
 Development and Other              32      356      139       140          8         -           7         12        8        702
 Exploration                         5       33       14        46         10         -           -          -        -        108
 Proved Property Acquisitions        -        -        -         1          -         -           -          -        -          1
                                ---------------------------------------------------------------------------------------------------
                                    37      389      153       187         18         -           7         12        8        811
                                ===================================================================================================

Property, Plant and Equipment
 Cost                            2,414    5,601    2,982     4,834        256       230       1,305        797      294     18,713
 Less: Accumulated DD&A          2,121    1,485    1,491       528         81        49         185        436      154      6,530
                                ---------------------------------------------------------------------------------------------------
Net Book Value                     293    4,116    1,491     4,306        175       181       1,120        361      140     12,183
                                ===================================================================================================

Notes:
(1)  Includes results of operations from producing activities in Colombia.
(2)  Includes  interest  income of $9 million,  foreign  exchange  losses of $5 million and decrease in the fair value of crude oil
     put options of $16 million.
(3)  Includes stock-based compensation expense of $116 million.
(4)  Includes exploration activities primarily in Nigeria, Norway and Colombia.
(5)  Includes Yemen cash taxes of $44 million.
(6)  Approximately 78% of Marketing's identifiable assets are accounts receivable and inventories.
</TABLE>

                                      18
<PAGE>

<TABLE>
<CAPTION>
THREE MONTHS ENDED MARCH 31, 2006

                                                                                                                   Corporate
                                                                                    Energy                           and
(Cdn$ millions)                                    Oil and Gas                    Marketing   Syncrude  Chemicals    Other   Total
-----------------------------------------------------------------------------------------------------------------------------------
                                                  United    United       Other
                                 Yemen    Canada  States    Kingdom  Countries(1)
                                -------------------------------------------------
<S>                             <C>       <C>     <C>       <C>      <C>          <C>         <C>       <C>        <C>       <C>
Net Sales                          328      111      181       134         28         7          84        107        -        980
Marketing and Other                  3        1        -         2          -       437           -          -       (17)(2)   426
                                ---------------------------------------------------------------------------------------------------
Total Revenues                     331      112      181       136         28       444          84        107       (17)    1,406
Less: Expenses
 Operating                          36       34       30        22          2         7          53         66        -        250
 Depreciation, Depletion,
   Amortization and
    Impairment                      77       37       55        71          2         3           5         10        6        266
 Transportation and Other            2       10        -         -          -       232           6         10        -        260
 General and Administrative (3)     14       42       35         4         16        36           -          7       66        220
 Exploration                         -        6       62        20         15(4)      -           -          -        -        103
 Interest                            -        -        -         -          -         -           -          2        7          9
                                ---------------------------------------------------------------------------------------------------
Income (Loss) from
   Continuing Operations
    before Income Taxes            202      (17)      (1)       19         (7)      166          20         12      (96)       298
                                ============================================================================================
Less: Provision for Income
 Taxes (5), (6)                                                                                                                378
Less: Non-Controlling
 Interests                                                                                                                       3
                                                                                                                            -------
Net Loss                                                                                                                       (83)
                                                                                                                            =======

Identifiable Assets                630    2,789    1,414     4,966        188     2,743(7)    1,146        470       152    14,498
                                ===================================================================================================

Capital Expenditures
 Development and Other              47      325       64       120          9         1          37          2        7        612
 Exploration                         5       46       40        19          7         -           -          -        -        117
 Proved Property Acquisitions        -        2        -         1          -         -           -          -        -          3
                                ---------------------------------------------------------------------------------------------------
                                    52      373      104       140         16         1          37          2        7        732
                                ===================================================================================================

Property, Plant and Equipment
 Cost                            2,299    3,991    2,491     4,139        256       185       1,275        829      251     15,716
 Less: Accumulated DD&A          1,921    1,334    1,213       275        120        74         173        466      129      5,705
                                ---------------------------------------------------------------------------------------------------
Net Book Value                     378    2,657    1,278     3,864        136       111       1,102        363      122     10,011
                                ===================================================================================================

Notes:
(1)  Includes results of operations from producing activities in Colombia.
(2)  Includes interest income of $8 million, foreign exchange losses of $21 million and decrease in the fair value of crude oil
     put options of $4 million.
(3)  Includes stock-based compensation expense of $145 million.
(4)  Includes exploration activities primarily in Nigeria and Colombia.
(5)  Includes Yemen cash taxes of $67 million.
(6)  Includes future income tax expense of $277 million related to an increase in the supplemental tax rate on oil and gas
     activities in the United Kingdom.
(7)  Approximately 77% of Marketing's identifiable assets are accounts receivable and inventories.
</TABLE>

                                      19
<PAGE>

16.  DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING
     PRINCIPLES

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

<TABLE>
<CAPTION>
(a)    UNAUDITED CONSOLIDATED STATEMENT OF INCOME - US GAAP
       FOR THE THREE MONTHS ENDED MARCH 31

(Cdn$ millions, except per share amounts)                                2007         2006
-------------------------------------------------------------------------------------------
<S>                                                                     <C>         <C>
REVENUES AND OTHER INCOME
    Net Sales                                                           1,140         980
    Marketing and Other (i)                                               246         436
                                                                  -------------------------
                                                                        1,386       1,416
                                                                  -------------------------
EXPENSES
    Operating (ii)                                                        296         252
    Depreciation, Depletion, Amortization and Impairment                  334         266
    Transportation and Other                                              246         260
    General and Administrative (iv)                                       199         221
    Exploration                                                            49         103
    Interest                                                               48           9
                                                                  -------------------------
                                                                        1,172       1,111
                                                                  -------------------------

INCOME BEFORE INCOME TAXES                                                214         305
                                                                  -------------------------

PROVISION FOR INCOME TAXES
    Current                                                                60         109
    Deferred (i) - (iv)                                                    33          (6)
                                                                  -------------------------
                                                                           93         103
                                                                  -------------------------

NET INCOME BEFORE NON-CONTROLLING INTERESTS                               121         202
    Net Income Attributable to Non-Controlling Interests                   (3)         (3)
                                                                  -------------------------

NET INCOME - US GAAP (1)                                                  118         199
                                                                  =========================

EARNINGS PER COMMON SHARE ($/share)
                                                                  -------------------------
    Basic (Note 11)                                                      0.45        0.76
                                                                  =========================

                                                                  -------------------------
    Diluted (Note 11)                                                    0.44        0.74
                                                                  =========================

Note:
(1)  RECONCILIATION OF CANADIAN AND US GAAP NET INCOME
                                                                            Three Months
                                                                           Ended March 31
     (Cdn$ millions)                                                     2007        2006
    ---------------------------------------------------------------------------------------
     Net Income - Canadian GAAP                                           121         (83)
     Impact of US Principles, Net of Income Taxes:
       Ineffective Portion of Cash Flow Hedges (i)                         (2)          6
       Pre-operating Costs (ii)                                            (3)         (1)
       Deferred Income Taxes (iii)                                          -         277
       Liability-based Stock Compensation Plans (iv)                        2           -
                                                                  -------------------------
     Net Income - US GAAP                                                 118         199
                                                                  =========================
</TABLE>

                                      20
<PAGE>

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

                                                                          March 31   December 31
(Cdn$ millions, except share amounts)                                         2007          2006
--------------------------------------------------------------------------------------------------
<S>                                                                          <C>           <C>
ASSETS
    CURRENT ASSETS
      Cash and Cash Equivalents                                                110           101
      Restricted Cash and Margin Deposits                                      181           197
      Accounts Receivable                                                    2,853         2,976
      Inventories and Supplies                                                 665           786
      Deferred Income Tax Asset                                                426           479
      Other                                                                     71            67
                                                                          ------------------------
        Total Current Assets                                                 4,306         4,606
                                                                          ------------------------

    PROPERTY, PLANT AND EQUIPMENT
      Net of Accumulated Depreciation, Depletion, Amortization and
         Impairment of $6,923 (December 31, 2006 - $6,792) (ii); (vi)       12,130        11,692
    GOODWILL                                                                   374           377
    DEFERRED INCOME TAX ASSETS                                                 138           141
    DEFERRED CHARGES AND OTHER ASSETS                                          312           263
                                                                          ------------------------
TOTAL ASSETS                                                                17,260        17,079
                                                                          ========================

LIABILITIES AND SHAREHOLDERS' EQUITY
    CURRENT LIABILITIES
      Short-Term Borrowings                                                    107           158
      Accounts Payable and Accrued Liabilities (iv)                          3,836         3,839
      Accrued Interest Payable                                                  36            55
      Dividends Payable                                                         13            13
                                                                          ------------------------
        Total Current Liabilities                                            3,992         4,065
                                                                          ------------------------

    LONG-TERM DEBT                                                           4,942         4,618
    DEFERRED INCOME TAX LIABILITIES (i) - (vi)                               2,389         2,427
    ASSET RETIREMENT OBLIGATIONS                                               691           683
    DEFERRED CREDITS AND LIABILITIES (v)                                       504           597
    NON-CONTROLLING INTERESTS                                                   73            75
    SHAREHOLDERS' EQUITY
      Common Shares, no par value
        Authorized:   Unlimited
        Outstanding:  2007 - 263,188,018 shares
                      2006 - 262,513,206 shares                                866           821
      Contributed Surplus                                                        4             4
      Retained Earnings (i) - (vi)                                           4,022         3,945
      Accumulated Other Comprehensive Income (i); (v)                         (223)         (156)
                                                                          ------------------------
          Total Shareholders' Equity                                         4,669         4,614
                                                                          ------------------------
     COMMITMENTS, CONTINGENCIES AND GUARANTEES

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                                  17,260        17,079
                                                                          ========================

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

(Cdn$ millions)                                                               2007          2006
--------------------------------------------------------------------------------------------------
Net Income - US GAAP                                                           118           199
Other Comprehensive Income, Net of Income Taxes:
    Foreign Currency Translation Adjustment                                     (6)           (2)
    Change in Mark to Market on Cash Flow Hedges (i)                           (61)           14
                                                                          ------------------------
Comprehensive Income                                                            51           211
                                                                          ========================
</TABLE>

                                      21
<PAGE>

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

                                                                         March 31    December 31
(Cdn$ millions)                                                              2007           2006
-------------------------------------------------------------------------------------------------
<S>                                                                          <C>           <C>
Foreign Currency Translation Adjustment                                      (167)         (161)
Mark to Market on Cash Flow Hedges (i)                                          -            61
Unamortized Defined Benefit Pension Costs (v)                                 (56)          (56)
                                                                          -----------------------
                                                                             (223)         (156)
                                                                          =======================
</TABLE>
NOTES:
i.    Under US GAAP, all derivative  instruments  are recognized on the balance
      sheet as either an asset or a liability  measured at fair value.  Changes
      in the fair  value of  derivatives  are  recognized  in  earnings  unless
      specific  hedge  criteria  are met.  On January 1, 2007,  we adopted  the
      equivalent Canadian standard for derivative instruments.

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

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

      In the first quarter of 2006, our US GAAP net income includes $10 million
      ($6 million,  net of income taxes) related to the ineffective  portion of
      cash flow hedges.

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

      At March 31, 2007, there were no cash flow hedges in place.

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

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

      o    operating expenses include pre-operating costs of $6 million for the
           three months ended March 31, 2007 ($3 million,  net of income taxes)
           (2006 - $2 million ($1 million, net of income taxes)); and

      o    property,  plant and equipment is lower under US GAAP by $34 million
           (December 31, 2006 - $28 million).

iii.  Under US GAAP,  enacted tax rates are used to calculate  deferred  income
      taxes, whereas under Canadian GAAP, substantively enacted rates are used.
      During the first quarter of 2006, the UK government substantively enacted
      increases to the  supplementary tax on oil and gas activities from 10% to
      20%, effective January 1, 2006. This created a $277 million future income
      tax expense during the first quarter of 2006 under Canadian GAAP.

iv.   Under Canadian  principles,  we record  obligations  for  liability-based
      stock compensation plans using the intrinsic-value  method of accounting.
      Under US principles,  obligations for liability-based  stock compensation
      plans are recorded using the fair-value method of accounting. We are also
      required  to  accelerate  the  recognition  of  stock-based  compensation
      expense  for  all  stock-based  awards  made  to our  retirement-eligible
      employees  under Canadian GAAP.  However,  under US GAAP, the accelerated
      recognition  for such employees is only required for  stock-based  awards
      granted on or after January 1, 2006. As a result:

      o    general  and  administrative  expense  is  lower by $3  million  ($2
           million,  net of income  taxes) for the three months ended March 31,
           2007 (2006 - higher by $1 million (nil, net of income taxes)); and

      o    accounts  payable and accrued  liabilities are higher by $22 million
           as at March 31, 2007 (December 31, 2006 - $25 million).

                                      22
<PAGE>

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

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


STOCK-BASED COMPENSATION EXPENSE FOR RETIRED AND RETIREMENT-ELIGIBLE EMPLOYEES
Under US GAAP, we recognize  stock-based  compensation  expense for our retired
and  retirement-eligible  employees  over  an  accelerated  vesting  period  in
accordance  with the  provisions  of Statement  123(R) for  stock-based  awards
granted  to  employees  on or after  January 1, 2006.  For  stock-based  awards
granted  prior to the adoption of Statement  123(R),  stock-based  compensation
expense for our retired and retirement-eligible  employees is recognized over a
graded vesting  period.  If we applied the  accelerated  vesting  provisions of
Statement   123(R)  to   stock-based   awards   granted  to  our   retired  and
retirement-eligible  employees prior to the adoption of Statement 123(R), there
would be no material  change to our  stock-based  compensation  expense for the
three months ended March 31, 2007 and 2006.

CHANGES IN ACCOUNTING POLICIES - US GAAP

INCOME TAXES
On  January  1,  2007,  we  adopted  FASB   Interpretation  48  ACCOUNTING  FOR
UNCERTAINTY  IN INCOME  TAXES (FIN 48) with respect to FAS 109  ACCOUNTING  FOR
INCOME TAXES  regarding  accounting and disclosure for uncertain tax positions.
On the  adoption  of FIN 48, we  recorded  a  cumulative  effect of a change in
accounting principle of $28 million.  This amount increased our deferred income
tax liabilities,  with a corresponding  decrease to our retained earnings as at
January 1, 2007 in our US GAAP - Unaudited  Consolidated  Balance Sheet.  As at
January 1 and March 31, 2007, the total amount of our unrecognized tax benefits
was approximately $210 million,  all of which, if recognized,  would affect our
effective  tax rate.  As at January 1 and March 31,  2007,  the total amount of
interest and  penalties in relation to uncertain  tax  positions  recognized in
deferred income tax liabilities in the US GAAP -Unaudited  Consolidated Balance
Sheet is  approximately  $9 million.  We had no interest or penalties in the US
GAAP -  Unaudited  Consolidated  Statement  of Income for the first  quarter of
2007. Our income tax filings are subject to audit by taxation  authorities  and
as at January 1 and March 31, 2007 the following tax years remained  subject to
examination;  (i) Canada - 1985 to date, (ii) United Kingdom - 2002 to date and
(iii) United States - 2003 to date. We do not anticipate  any material  changes
to the  unrecognized tax benefits  previously  disclosed within the next twelve
months.

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

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

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

                                      23
<PAGE>

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

THE FOLLOWING  SHOULD BE READ IN  CONJUNCTION  WITH THE UNAUDITED  CONSOLIDATED
FINANCIAL  STATEMENTS  INCLUDED  IN THIS  REPORT.  THE  UNAUDITED  CONSOLIDATED
FINANCIAL  STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE WITH GENERALLY  ACCEPTED
ACCOUNTING   PRINCIPLES  (GAAP)  IN  CANADA.  THE  IMPACT  OF  THE  SIGNIFICANT
DIFFERENCES  BETWEEN  CANADIAN AND UNITED STATES (US) ACCOUNTING  PRINCIPLES ON
THE FINANCIAL STATEMENTS IS DISCLOSED IN NOTE 16 TO THE UNAUDITED  CONSOLIDATED
FINANCIAL STATEMENTS. THE DATE OF THIS DISCUSSION IS APRIL 25, 2007.

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

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

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

EXECUTIVE SUMMARY OF FIRST QUARTER RESULTS
                                                                 Three Months
                                                                 Ended March 31
(Cdn$ millions)                                                  2007      2006
--------------------------------------------------------------------------------
Net Income (Loss)                                                 121       (83)
Earnings (Loss) per Common Share ($/share)                       0.46     (0.32)
Cash Flow from Operating Activities                               448       734

Production, before Royalties (mboe/d)                             238       222
Production, after Royalties (mboe/d)                              191       159
Nexen's Average Realized Oil and Gas Price (Cdn$/boe)           59.13     61.11

Capital Investment, including Acquisitions                        811       753
Net Debt (1)                                                    4,939     3,697
                                                            --------------------

Note:
(1) Net debt is defined as long-term debt and short-term borrowings less cash
    and cash equivalents.

Strong commodity  prices and commencement of production at Buzzard  contributed
to our financial results in the first quarter. These contributions were reduced
by lower  marketing  results.  Despite  an 8%  decrease  in WTI from the  first
quarter of 2006, our average realized oil and gas price only fell 3% mainly due
to narrower product  differentials.  Economically our marketing  division added
value for the quarter,  however,  for  accounting  purposes they broke even. We
were  unable  to  recognize  gains  on the  increased  value  of our  marketing
inventories and  transportation  assets.  These can only be recognized when the
inventories  are sold and the  transportation  assets  are  used.  We expect to
recognize the gains over the next 12 months. A year ago, marketing  contributed
$175 million to our earnings as they took  advantage of volatile gas markets in
late 2005.  Our results in the first  quarter of 2006  included $277 million of
future income tax expense related to an increase in the  supplemental  tax rate
applicable to our North Sea operations in the United Kingdom.

Our production  before royalties  increased 7% compared to the first quarter of
2006 and 15% from the fourth  quarter.  Buzzard came on stream in early January
and contributed 36,000 boe/d to our quarterly production volumes. Peak rates of
85,000 boe/d (net to us) are expected by mid year.  Production  also  increased
from an  additional  development  well at Aspen in the Gulf of Mexico.  Natural
declines in Yemen partially offset these increases.

In April, we began injecting steam at Long Lake to begin heating the reservoir.
Bitumen  production  is expected to be minimal  until the third quarter when we
convert  the  wells  to SAGD  operation.  After a  review  of all  trends,  the
projected cost of Long Lake has increased from $4.6 billion to approximately $5
billion  ($2.5 billion net to us). In addition,  a contingency  reserve of $300
million  ($150  million net to us) has been  created for cost and  productivity
pressures over and above current trends.

                                      24
<PAGE>

The  increase  in our net debt  compared  to last  year  largely  reflects  the
completion  of the Buzzard  project in late 2006 and our ongoing  investment at
Long Lake.

CAPITAL INVESTMENT

Our  capital  investment  strategy  continues  to  focus  on  developing  major
projects,  exploring our growth basins,  maximizing the remaining  value of our
core assets and  investing in new  technology.  In 2007, we are investing in: o
our Long Lake development project; o targeting up to 19 exploration  prospects,
primarily in the Gulf of Mexico and the North Sea; and o creating  value in our
existing asset base.

<TABLE>
<CAPTION>
Details of our first quarter capital programs are set out below.

                                                            Major      Early Stage       New Growth       Core Asset
(Cdn$ millions)                                       Development      Development      Exploration      Development      Total
--------------------------------------------------------------------------------------------------------------------------------
<S>                                                           <C>               <C>             <C>              <C>        <C>
Oil and Gas
      Synthetic (mainly Long Lake)                            255               50                -                -        305
     United Kingdom                                           123                -               46               18        187
     Yemen                                                      -                -                5               32         37
     United States                                             14                -               14              125        153
     Canada                                                    22                4               33               25         84
     Other Countries                                            -                5               10                3         18
Syncrude                                                        -                -                -                7          7
                                                   -----------------------------------------------------------------------------
                                                              414               59              108              210        791
Chemicals, Marketing, Corporate and Other                       -                -                -               20         20
                                                   -----------------------------------------------------------------------------
Total Capital                                                 414               59              108              230        811
                                                   =============================================================================
As a % of Total Capital                                       51%               7%              13%              29%       100%
                                                   -----------------------------------------------------------------------------
</TABLE>

MAJOR AND EARLY STAGE DEVELOPMENT PROJECTS

SYNTHETIC
Our Long Lake project  achieved a major  milestone as we began  injecting steam
into two of our 10 well pads in  April.  Over the next  several  months we will
continue to circulate  steam into the injection and producing  wells to heat up
the  reservoir and establish  communication  between the wells.  Our plan is to
commission a new pad (3 to 12 well pairs per pad) at a rate of one pad per week
until all wells are  circulating  steam.  We expect  all 81 SAGD well pairs (10
pads) to be circulating steam by the end of the second quarter.

Bitumen  production  is expected to be minimal  until the third quarter when we
convert  the wells to SAGD  operation.  During the initial  ramp up period,  we
expect steam-to-oil ratios will be high from initial steam circulation and will
decline with time as bitumen  production ramps up to peak rates over a 12 to 24
month  period.  Over the  project  life,  we expect our  steam-to-oil  ratio to
average  approximately  3.0.  Depending on production  ramp up and new facility
uptime, we expect bitumen  production to reach between 35,000 and 45,000 bbls/d
(between 17,500 and 22,500 bbls/d net to us) by the end of 2007.

Upgrader  module  fabrication  is now  complete,  all  modules  are on site and
construction  of the upgrader is  approximately  85%  complete.  Peak output of
premium  synthetic  crude oil is expected within 18 months of upgrader start up
and we expect to exit 2007 producing  between 28,000 and 36,000 bbls/d (between
14,000 and 18,000 bbls/d net to us) of synthetic crude. Production capacity for
the first phase of Long Lake is approximately  60,000 bbls/d (30,000 bbls/d net
to us) of  premium  synthetic  crude  which we  expect to reach by late 2008 or
early 2009.

The current  commodity price  environment is fueling the high rate of oil sands
activity.  This is resulting in unprecedented  demand for supplies and services
in the Athabasca region,  causing inflationary  pressure on costs. In addition,
skilled  labour  shortages  are  affecting  productivity.  These  pressures are
impacting our Long Lake project.  It has taken additional hours to complete the
SAGD central  processing  facility and system  turnover to operations has taken
longer than  anticipated.  On the upgrader,  progress and productivity has been
less than expected on the sulphur and air separation  plants,  putting pressure
on both cost and schedule.  After a review of all trends, the projected cost of
Long Lake has  increased  from $4.6 billion to  approximately  $5 billion ($2.5
billion net to us). In addition,  a  contingency  reserve of $300 million ($150
million net to us) has been created for cost and  productivity  pressures  over
and above current trends.

We are planning to increase  synthetic  crude oil  production to 240,000 bbls/d
(120,000  bbls/d  net to us)  over  the next  decade.  We plan to  sequentially
develop our oil sands leases with  additional  60,000 bbls/d (30,000 bbls/d net
to us) phases using the same  technology and design as Long Lake.  This process

                                      25
<PAGE>

significantly  reduces our need to purchase  natural  gas, a key cost driver in
competing technologies and results in a significant cost advantage for us.

UNITED KINGDOM - ETTRICK
Development of the Ettrick field in the North Sea where we have an 80% operated
working interest is progressing  well. The project consists of three production
wells and one water injector tied back to a leased floating production, storage
and offloading (FPSO) vessel which is almost 60% complete. The FPSO is designed
to handle 30,000 bbls/d of oil, 35 mmcf/d of gas and to re-inject 55,000 bbls/d
of water.  During the quarter,  we began drilling the first  development  well.
Production  from the field is  expected  in mid 2008  with our share  averaging
approximately 9,000 boe/d for the year.

CANADA - COALBED METHANE (CBM)
In  Canada,  we  continue  to  develop  CBM  from  Mannville  coals in the Fort
Assiniboine  area. Well  performance  continues to meet  expectations,  however
capital spending has been less than planned due to partner constraints.  We are
taking action as permitted by our agreements to mitigate these  constraints and
move ahead with the capital program.  Our production from this area averaged 21
mmcf/d for the  quarter.  We expect this to double by year-end  and continue to
grow as we develop  additional  sections  of land in the  Corbett,  Thunder and
Doris fields using multiple leg-horizontal wells.

OFFSHORE WEST AFRICA
The Usan field  development,  located in Nigeria  on  offshore  Block  OPL-222,
continues  to progress  toward  project  sanction.  The  project  will have the
ability to process an  average of 180,000  bbls/day  of oil during the  initial
production  plateau  period  through a new  floating  production,  storage  and
offloading vessel with a two million barrel storage  capacity.  Recommendations
have been prepared for award of the major  deep-water  facilities  and drilling
contracts,  subject to final government and partner approval to proceed.  These
contracts  provide  for  fabrication  and  integration  of a  portion  of these
facilities  within Nigeria,  reflecting the project's  support of local content
initiatives  established  by  the  Nigerian  government.  We  expect  the  Usan
development to be formally sanctioned this year, with first production as early
as 2010. We have a 20% interest in exploration and development on this block.


NEW GROWTH EXPLORATION
In 2006, we had discoveries at Alaminos Canyon Block 856 (Great White West) and
Ringo on Mississippi Canyon Block 546. We are currently evaluating  development
options at Great White West. At Ringo we have an appraisal well planned for the
fourth quarter. We recently pooled our acreage at Ringo with adjacent Block 502
as we  believe  the  structure  is  situated  on  both  blocks.  We  have a 25%
non-operated  interest in Ringo and Block 502.  The  operator  has renamed this
discovery Longhorn.

At Knotty  Head,  we are moving  forward to secure a rig to drill an  appraisal
well.  One of our partners  has access to a deep-water  drilling rig which they
are  prepared  to make  available  late this year or early  next  year.  We are
currently   verifying  the  rig's   capabilities   and  reviewing   contractual
arrangements. We have a 25% operated interest in the field.

During the  quarter,  we had  successes in the UK North Sea at Golden Eagle and
Kildare. Golden Eagle is located on Block 20/1N. The discovery well was drilled
to a  depth  of  approximately  7,500  feet  and  encountered  hydrocarbons.  A
successful  sidetrack well was drilled to appraise the  accumulation and we are
currently  evaluating  development  options. We have a 34% operated interest in
Golden  Eagle.  Kildare is  located on Block  15/26b.  The  discovery  well was
drilled to a depth of approximately  14,100 feet and encountered  hydrocarbons.
We  are  currently  analyzing  the  results  from  the  well.  We  have  a  50%
non-operated interest in Kildare.

We are currently drilling two exploration wells. For the remainder of the year,
we expect to drill an additional 12 to 15  exploration  wells with the majority
in the Gulf of Mexico and the UK North  Sea.  We have rigs lined up for all but
one of these wells.

                                      26
<PAGE>

FINANCIAL RESULTS

<TABLE>
<CAPTION>
CHANGE IN NET INCOME

                                                                                  2007 VS. 2006
(Cdn$ millions)
-----------------------------------------------------------------------------------------------
<S>                                                                                   <C>
NET LOSS AT MARCH 31, 2006                                                            (83)
                                                                                ===============
    Favourable (unfavourable) variances:

       Production Volumes, After Royalties
         Crude Oil                                                                    233
         Natural Gas                                                                  (18)
         Change in Crude Oil Inventory                                                 (6)
                                                                                ---------------
           Total Volume Variance                                                      209

       Realized Commodity Prices
         Crude Oil                                                                    (39)
         Natural Gas                                                                  (18)
                                                                                ---------------
           Total Price Variance                                                       (57)

       Oil and Gas Operating Expense
         Conventional                                                                 (40)
         Syncrude                                                                       6
                                                                                ---------------
           Total Operating Expense Variance                                           (34)

       Depreciation, Depletion, Amortization and Impairment
         Oil & Gas and Syncrude                                                       (66)
         Other                                                                         (2)
                                                                                ---------------
           Total Depreciation, Depletion, Amortization and Impairment Variance        (68)

       Exploration Expense                                                             54

       Energy Marketing Contribution                                                 (175)

       Chemicals Contribution                                                           3

       General and Administrative Expense                                              18

       Interest Expense                                                               (39)

       Current Income Taxes                                                            49
       Future Income Taxes                                                            234

       Other
         Decrease in Fair Value of Crude Oil Put Options                              (12)
         Other                                                                         22
                                                                                ---------------

NET INCOME AT MARCH 31, 2007                                                          121
                                                                                ===============
</TABLE>

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

                                      27
<PAGE>

OIL & GAS AND SYNCRUDE

<TABLE>
<CAPTION>
PRODUCTION

                                                               Three Months Ended March 31
                                                       2007                          2006
-----------------------------------------------------------------------------------------------------
                                              Before           After          Before           After
                                           Royalties (1)   Royalties       Royalties (1)   Royalties
                                           ----------------------------------------------------------
<S>                                              <C>            <C>             <C>             <C>
Crude Oil and NGLs (mbbls/d)
    Yemen                                       77.1            45.0           102.4            53.7
    Canada                                      17.8            14.2            22.2            17.8
    United States                               21.6            19.3            19.3            17.0
    United Kingdom                              55.6            55.6            15.7            15.7
    Other Countries                              5.8             5.4             5.8             5.3
Syncrude (mbbls/d) (2)                          21.4            18.9            14.8            13.4
                                           ----------------------------------------------------------
                                               199.3           158.4           180.2           122.9
                                           ----------------------------------------------------------
Natural Gas (mmcf/d)
    Canada                                       118              95             106              89
    United States                                101              86             120             102
    United Kingdom                                14              14              23              23
                                           ----------------------------------------------------------
                                                 233             195             249             214
                                           ----------------------------------------------------------

Total Production (mboe/d)                        238             191             222             159
                                           ==========================================================
</TABLE>

Notes:
(1) We have presented production volumes before royalties as we measure our
    performance on this basis consistent with other Canadian oil and gas
    companies.
(2) Considered a mining operation for US reporting purposes.

HIGHER PRODUCTION INCREASED NET INCOME FOR THE QUARTER BY $209 MILLION
Production after royalties increased 20% from the first quarter in 2006 and 19%
from the fourth quarter of last year with the addition of royalty-free  Buzzard
production in the UK North Sea.  Production before royalties  increased 7% from
the first  quarter in 2006 and 15% from the  fourth  quarter.  Production  also
increased as we brought on stream an  additional  development  well at Aspen in
the Gulf of Mexico.

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

<TABLE>
<CAPTION>
                                                                                  Before       After
(mboe/d)                                                                       Royalties   Royalties
-----------------------------------------------------------------------------------------------------
<S>                                                                                  <C>         <C>
Production, fourth quarter 2006                                                      207         161
    Production changes:
      United Kingdom                                                                  34          34
      United States                                                                    5           4
      Yemen                                                                           (7)         (6)
      Other                                                                           (1)         (2)
                                                                             ------------------------
Production, first quarter 2007                                                       238         191
                                                                             ========================
</TABLE>

We expect our  production  will  continue  to increase in 2007 as we ramp up to
full production rates at Buzzard by mid year. Further production  increases are
expected to come from a sidetrack  development  well at Aspen  currently  being
completed in the Gulf of Mexico and from bitumen  production at Long Lake later
this year.  Long Lake  synthetic  crude oil  production  is  expected  to begin
towards the end of 2007. Production volumes discussed in this section represent
before-royalties volumes, net to our working interest.

YEMEN
Production  from the Masila field  decreased 7% from the fourth quarter and 18%
from the first  quarter of 2006.  Production  declines  at Masila  reflect  the
maturity  of the field and the impact of a reduced  2007  development  drilling
program.  In 2007, we have 14 development wells and one sidetrack planned as we
continue our field development  program.  During the first quarter,  we drilled
six  development  wells.  Production  declines  are  expected to continue as we
maximize recovery of the remaining reserves on the block.

                                      28
<PAGE>

Block 51  production  decreased  43% from the  first  quarter  of 2006  when we
commissioned the permanent central  processing  facilities on the block, due to
relatively  high natural  decline rates.  Our 2007 capital  investment  program
includes  further  development  of the BAK A and BAK B  fields  including  nine
development wells,  de-bottlenecking  of the BAK production  facility to handle
additional water, continued well optimizations and completion of water handling
and power plant expansions.

We expect Yemen production to average between 60,000 and 75,000 boe/d in 2007.

CANADA
Production in Canada was consistent with the previous quarter but 6% lower than
the first quarter of 2006.  Natural  declines at our heavy oil properties  were
partially offset by our heavy oil winter drilling program. Natural gas declines
in our  Medicine  Hat region have been offset by capital  investment  in infill
drilling and well optimization activities. CBM production continues to increase
as the wells in our Fort  Assiniboine  area  de-water  and we bring  additional
development wells and facilities on stream.

Production  volumes are  expected to  increase  in the  remainder  of 2007 from
additional CBM natural gas volumes and new bitumen production at Long Lake.

UNITED STATES
Gulf of Mexico production  increased 16% from the previous quarter primarily as
a result of bringing an additional  development well at Aspen on-stream in late
December 2006, coupled with less downtime at the existing Aspen wells. With the
additional  development well on stream,  our production from the field averaged
approximately  16,500  boe/d for the first  quarter of 2007  compared to 10,400
boe/d a year ago. We have identified  other  opportunities  in the field and we
are  currently  sidetracking  Aspen 1 to exploit a number of deeper  sands.  We
expect this well to come on stream mid year.  Our 2007 annual  production  from
the Aspen field is expected to average between 15,000 and 20,000 boe/d. We have
a 100% operated working interest in Aspen.

The increase from Aspen was  partially  offset by reduced  production  rates at
Gunnison.  Shelf production  declined from last year due to lower  performance,
program delays and unsuccessful  projects. In May, we anticipate producing from
Wrigley  on  Mississippi  Canyon  Block  506  where we have a 50%  non-operated
interest.  The well flow  tested  at 62 mmcf/d  (31  mmcf/d  net to us)  during
completion operations.


UNITED KINGDOM
Buzzard  came on stream in early  January and is ramping up to peak  production
rates as expected.  During the quarter,  production  averaged  36,000 boe/d and
reached  over 65,000 boe/d in late April.  Five of the planned six  development
wells are on stream.  We expect to reach peak rates of 85,000 boe/d by mid year
as we bring  additional  wells on stream and optimize the wells and  production
facility.

Production  from the  Scott and  Telford  fields  increased  19% from the first
quarter of 2006, when  maintenance and turnaround  activity in 2006 temporarily
reduced production  volumes.  Early in the second quarter of 2007, we increased
our interests in the Scott and Telford fields by 0.9% and 17.4%,  respectively.
The non-operated  Farragon field produced  approximately 3,100 boe/d during the
quarter.


OTHER COUNTRIES
Production  from our Guando field in Colombia  averaged 5,800 bbls/d during the
quarter.  We began a 35 well infill drilling program early in the year and five
wells were on stream by the end of March. We expect production from Colombia to
average between 6,000 and 7,000 bbls/d in 2007.

SYNCRUDE
Syncrude  production  increased  45%  from  the  same  period  last  year.  New
production from the Stage 3 expansion  accounted for  approximately  75% of the
increase. The balance of the production increase in 2007 reflects the impact of
reduced  capacity in 2006 as a result of maintenance and turnaround work. Since
mid-December,  circulation  difficulties have restricted Coker 8-3 to less than
70% of design capacity. A turnaround on Coker 8-3 is expected to occur in May.

                                      29
<PAGE>

<TABLE>
<CAPTION>
COMMODITY PRICES

                                                                     Three Months
                                                                     Ended March 31
                                                                   2007         2006
-------------------------------------------------------------------------------------
<S>                                                               <C>          <C>
CRUDE OIL AND NGLS
    West Texas Intermediate (WTI) (US$/bbl)                       58.16        63.48
                                                           --------------------------

    Differentials (1) (US$/bbl)
      Heavy Oil                                                   16.57        28.89
      Mars                                                         5.09         7.90
      Masila                                                       2.01         3.76
      Dated Brent                                                  0.41         1.73

    Producing Assets (Cdn$/bbl)
      Yemen                                                       63.02        68.32
      Canada                                                      41.71        30.00
      United States                                               58.49        63.73
      United Kingdom                                              64.33        69.02
      Other Countries                                             59.81        58.81
      Syncrude                                                    70.03        69.95

    Corporate Average (Cdn$/bbl)                                  61.69        63.11
                                                           --------------------------

NATURAL GAS
    New York Mercantile Exchange (NYMEX) (US$/mmbtu)               7.18         7.87
    AECO (Cdn$/GJ)                                                 7.07         8.79
                                                           --------------------------

    Producing Assets (Cdn$/mcf)
      Canada                                                       7.16         7.65
      United States                                                8.58         9.06
      United Kingdom                                               3.87        11.82

    Corporate Average (Cdn$/mcf)                                   7.58         8.71
                                                           --------------------------

NEXEN'S AVERAGE REALIZED OIL AND GAS PRICE (Cdn$/boe)             59.13        61.11
                                                           --------------------------

AVERAGE FOREIGN EXCHANGE RATE
    Canadian to US Dollar (US$)                                  0.8573       0.8660
                                                           --------------------------
</TABLE>
Note:
(1)  These differentials are a discount to WTI.

LOWER REALIZED COMMODITY PRICES DECREASED QUARTERLY NET INCOME BY $57 MILLION
WTI weakened early in the quarter,  averaging 8% lower as compared to the first
quarter of 2006.  Benchmark  commodity  prices  remained  high and helped us to
realize  strong  prices of  $61.69/bbl  for our crude oil in the  quarter.  Our
realized gas price  decreased  13% from a year ago to average  $7.58/mcf in the
first three months of the year. NYMEX decreased 9% in the same period averaging
US$7.18/mmbtu.

CRUDE OIL REFERENCE PRICES
WTI dipped under the US$50/bbl mark during the quarter for the first time since
May 2005 before rebounding to finish the quarter at US$65.87/bbl. WTI traded at
an  average  of  US$58.16/bbl  for the  quarter  with a trading  range  between
US$49.90/bbl and US$68.09/bbl.  The fluctuation in crude prices has been driven
by mild  weather  in  January,  large  sell offs by  various  institutions  and
geopolitical risk in the Middle East.

At the  beginning of the year,  crude prices  declined from the prior year as a
result of warmer than expected winter weather and  institutional-led  sell offs
in the crude oil commodity  markets.  The warming effect of El Nino contributed
to a warm January in North America.  In addition,  as crude prices continued to
slide,  institutions  increased  their selling of crude oil futures in order to
manage their exposure to hedging and price  protection  programs of oil and gas
producers.

Crude prices  started to recover  towards the end of January as winter  weather
finally  arrived in North America.  The cold weather boosted demand for heating
oil and crude. In addition, the market started to tighten in response to OPEC's
agreement to reduce  production  by 1.2 million  barrels a day from November 1,
2006 and by a further 500,000 barrels a day from February 1, 2007.

                                      30
<PAGE>

Geopolitical  risk in Iran, the world's  fourth  largest oil exporter,  was the
dominant  factor  applying  upward pressure on crude prices near the end of the
quarter.  Crude prices  surged over  US$68/bbl in late March  following  Iran's
detention of 15 British military personnel.  This exacerbated on-going tensions
involving Iran and its uranium enrichment program. Aside from Iran, violence in
Nigeria,  the world's  eighth  largest oil exporter,  continues to cause supply
outages.   In  the  current  tight  supply  environment  any  potential  supply
disruptions have a significant impact on global oil balances as there is little
spare capacity.

CRUDE OIL DIFFERENTIALS
In Canada, heavy crude oil differentials averaged US$16.57/bbl (28% of WTI) for
the quarter,  as compared to  US$28.89/bbl  (46% of WTI) in 2006.  The expanded
market for Canadian heavy crude as a result of increased pipeline capacity from
a line  reversal  last year of the Spearhead  pipeline has  contributed  to the
strengthening  of this  differential.  Greater  demand for Canadian heavy crude
also reflects  security of supply  concerns  with respect to  Venezuelan  heavy
crude.  In  addition,  heavy crude  differentials  are tighter  than usual this
winter since OPEC cuts tend to be heavy barrels,  increasing the value of heavy
barrels relative to lighter barrels.

The US Gulf Coast Mars  differential  narrowed  to an historic  low,  averaging
US$5.09/bbl  throughout the first quarter as compared to US$7.90/bbl last year.
Mars  differentials  narrowed in response to weakening  WTI prices early in the
quarter and OPEC production  quota cuts which have caused a shortage of foreign
sour crude.

The Yemen Masila  differential  also narrowed  relative to WTI during the first
quarter,  averaging  US$2.01/bbl compared to US$3.76/bbl in 2006. Strong demand
growth in China has been the  primary  driver for the  strengthening  of Masila
crude.  In addition,  stronger Brent pricing has provided  upside support since
Masila crude is priced off Brent.

The Brent/WTI  differential  strengthened during the quarter with Brent trading
at  a  discount  averaging  US$0.41/bbl  compared  to  US$1.73/bbl  last  year,
resulting in solid pricing for our North Sea barrels.  Brent closed the quarter
at a record US$2/bbl premium over WTI. Historically, Brent trades at a discount
of US$1.50 to US$2.00 per barrel but the spread broke away last year because of
the  Israel-Lebanon  conflict  and again this year when Iran  detained  British
sailors. North Sea crude is typically more volatile than the North American WTI
benchmark.  We expect that Brent will  continue to trade at a premium  over WTI
given the April Nigerian Presidential election, the North Sea turnaround season
scheduled  to commence in June which will shut-in  production,  and the current
pipeline  constraints  at  Cushing,  Oklahoma  which is causing WTI to trade at
lower prices than other crude grades.  Increased  shipments of Canadian volumes
due to increased oil sands production also put downward pressure on WTI.

NATURAL GAS REFERENCE PRICES
Natural gas prices averaged  US$7.18/mmbtu  for the quarter.  The trading range
for NYMEX was  between  US$6.03/mmbtu  and  US$8.04/mmbtu.  Softer  natural gas
prices reflect the impact of warm weather and high storage  levels.  Gas prices
were lower in January than in February and March.  This was attributable to the
mild January weather in North America and the colder  temperatures that arrived
thereafter.  As the year  progresses,  natural  gas prices  will  depend on the
summer heat and autumn's hurricane season.

<TABLE>
<CAPTION>
 OPERATING COSTS

                                                                Three Months Ended March 31
(Cdn$/boe)                                                2007                              2006
----------------------------------------------------------------------------------------------------------
                                                 Before            After           Before           After
                                              Royalties (1)    Royalties        Royalties (1)   Royalties
                                          ----------------------------------------------------------------
<S>                                               <C>              <C>              <C>             <C>
Conventional Oil and Gas                           8.24            10.49             6.56            9.50
Synthetic Crude Oil
    Syncrude                                      24.40            27.66            40.12           44.36
Total Oil and Gas                                  9.67            12.18             8.78           12.46
                                          ----------------------------------------------------------------
</TABLE>
Note:
(1)  Operating  costs per boe are our total oil and gas operating costs divided
     by our working interest  production  before  royalties.  We use production
     before royalties to monitor our performance consistent with other Canadian
     oil and gas companies.

HIGHER OIL AND GAS OPERATING  COSTS DECREASED NET INCOME FOR THE QUARTER BY $34
MILLION
Our  corporate  average  unit  operating  cost was  impacted  by changes in our
production mix during the quarter. New production from Buzzard in the North Sea
and  increased  Syncrude  production  are  higher  contributors  to  our  total
production.  Buzzard  operating  costs  reduced  our  average by  $0.47/boe  as
operating costs on the Buzzard  platform are lower than our corporate  average,
while  higher-cost  Syncrude barrels  increased our total oil and gas operating
cost by $1.51/boe.

                                      31
<PAGE>

Lower production at Masila and Block 51 in Yemen,  together with higher service
rig activity,  increased unit operating  costs.  Overall,  Yemen  increased our
corporate  unit average cost by $0.48/boe.  Although  industry  cost  pressures
caused by the strong  commodity price  environment have increased our operating
costs  in the  Gulf of  Mexico,  this  increase  had a  minimal  impact  on our
corporate  average  compared  to last  year.  Our Gulf of Mexico  costs in 2006
included turnaround and maintenance activity on the Shelf at Eugene Island 18.

In Canada,  operating costs increased our corporate  average by $0.38/boe.  Our
heavy oil properties  have higher  operating costs per boe as many of our costs
are fixed in nature.  Unit  operating  costs at CBM are higher  initially as we
de-water the wells to stimulate gas production. Costs have also increased as we
ramp  up  our  CBM  operations  with  more  wells  coming  on  stream  at  Fort
Assiniboine.  Initial  production  from the new CBM wells is low as we  produce
water to  depressurize  the coals.  We expect  operating costs to decrease over
time as the wells de-water and gas production increases.

North Sea quarterly  operating costs on the Scott and Telford fields  increased
as a result of additional  maintenance  costs and water  injection  improvement
work on Scott. These increases increased our corporate average by $0.53/boe.

US-dollar  denominated  operating costs were higher when translated to Canadian
dollars as a result of the stronger US dollar.  This  increased  our  corporate
average by $0.05/boe for the quarter.

Syncrude  operating  costs per barrel were 39% lower than the first  quarter of
2006 as a result of reduced  maintenance  and higher  production.  In the first
quarter of 2006,  costs related to maintenance  and coker  turnaround  activity
were spread over fewer  barrels,  increasing  the  average  operating  cost per
barrel to $40.12.  The impact of the lower  Syncrude  unit  costs  reduced  our
corporate average by $1.63/boe during the quarter.

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

                                                               Three Months Ended March 31
(Cdn$/boe)                                                2007                              2006
----------------------------------------------------------------------------------------------------------
                                                 Before            After           Before           After
                                              Royalties (1)    Royalties        Royalties (1)   Royalties
                                           ---------------------------------------------------------------
<S>                                               <C>              <C>              <C>             <C>
Conventional Oil and Gas                          15.20            19.35            12.83           18.58
Synthetic Crude Oil
    Syncrude                                       6.65             7.54             3.78            4.18
Average Oil and Gas                               14.45            18.19            12.23           17.36
                                           ---------------------------------------------------------------
</TABLE>
Note:
(1)  DD&A per boe is our DD&A for oil and gas operations divided by our working
     interest  production before royalties.  We use production before royalties
     to monitor our  performance  consistent  with other  Canadian  oil and gas
     companies.

HIGHER OIL AND GAS DD&A REDUCED NET INCOME FOR THE QUARTER BY $66 MILLION
Our  production  mix has  changed  with new  production  added from the Buzzard
development  in the North Sea.  Costs  relating  to Buzzard are higher than our
corporate  average  as they  include  our  acquisition  cost  and the  costs to
complete the project.  Buzzard  increased  our average unit DD&A by  $0.82/boe.
This was offset by declines in Block 51 production, which reduced our corporate
average by  $0.89/boe.  Buzzard  unit  depletion is expected to decrease in the
next  few  years as we  anticipate  booking  additional  proved  reserves  from
production experience and development drilling.

In Yemen,  a lower reserve base and  additional  development  costs to maximize
recovery of the remaining  reserves increased our corporate unit depletion rate
by $0.30/boe as compared to the first quarter of 2006.

Canadian land acquisitions in 2006, together with capital spending on new wells
and  facilities  for CBM  projects,  increased  our Canada DD&A rate during the
quarter.  Our  average  DD&A rate  increased  by  $0.44/boe  as a  result.  Our
depletion rate in the Gulf of Mexico  increased as compared to 2006 from higher
costs  related to the  additional  development  well at Aspen and from  reserve
reductions  at the end of 2006.  The Gulf of  Mexico  increased  our  corporate
average rate by $1.70/boe.

DD&A on our existing  assets in the Scott and Telford fields  decreased in 2007
as a  result  of a higher  reserves  base.  In 2006,  DD&A  also  included  the
write-off of $15 million of purchase  price  allocated  to unproved  properties
following unsuccessful exploration activities.  Our 2007 corporate average unit
rate decreased $0.70/boe as a result.

The weakening of the Canadian dollar increased our DD&A expense relative to the
first  quarter of 2006 as the depletion of our  international  and US assets is
denominated in US dollars. This increased our corporate average by $0.11/boe.

Syncrude  DD&A  includes  costs to develop the Stage 3  expansion  that came on
stream in mid 2006. The depletion of the expansion  costs increased our average
by $0.44/boe.

                                      32
<PAGE>

<TABLE>
<CAPTION>
EXPLORATION EXPENSE

                                                                        Three Months
                                                                       Ended March 31
(Cdn$ millions)                                                      2007          2006
----------------------------------------------------------------------------------------
<S>                                                                  <C>           <C>
Seismic                                                               10            22
Unsuccessful Exploration Drilling                                     21            65
Other                                                                 18            16
                                                                  ----------------------
Total Exploration Expense                                             49           103
                                                                  ======================

New Growth Exploration                                               108           117
Geological and Geophysical Costs                                      10            22
                                                                  ----------------------
Total Exploration Expenditures                                       118           139
                                                                  ======================

Exploration Expense as a % of Exploration Expenditures               42%           74%
                                                                  ----------------------
</TABLE>

LOWER EXPLORATION EXPENSE INCREASED NET INCOME FOR THE QUARTER BY $54 MILLION
Exploration activity during the first quarter was primarily focused on drilling
exploratory wells in the North Sea. During the quarter,  we completed  drilling
operations  at our  successful  Golden  Eagle  prospect  in the North Sea.  The
discovery  well  was  drilled  to a  depth  of  approximately  7,500  feet  and
encountered  hydrocarbons.  A  sidetrack  well  was  drilled  to  appraise  the
accumulation and we are currently evaluating  development options. We were also
successful  on our 50%  non-operated  Kildare  target  in the  North  Sea.  The
discovery  well was  drilled  to  approximately  14,100  feet  and  encountered
hydrocarbons.  Additional  appraisal work is being  evaluated to further define
the discovery.

Our  exploration  expense in the first  quarter  includes  $15 million of costs
relating to the  unsuccessful  Guinea  well in the North Sea.  Drilling on this
well was completed in early March and reached 7,410 feet.  We  encountered  the
target reservoir but abandoned the well as the reservoir was water bearing.  In
Yemen, we expensed $2 million of costs related to an  unsuccessful  exploratory
well on Block 51. Our 2006 exploration expense includes $44 million of dry hole
costs associated with our unsuccessful Pathfinder well in the Gulf of Mexico.

Seismic  data  acquisition  was lower  during  the  quarter  as we  focused  on
analyzing  the  data  acquired  last  year to  identify  potential  exploration
targets.  We are currently drilling two exploration wells. For the remainder of
the year, we expect to drill an additional 12 to 15 exploration wells, with the
majority in the Gulf of Mexico and the UK North Sea.

                                      33
<PAGE>

<TABLE>
<CAPTION>
ENERGY MARKETING

                                                                            Three Months
                                                                           Ended March 31
(Cdn$ millions)                                                            2007      2006
--------------------------------------------------------------------------------------------
<S>                                                                     <C>       <C>
    Physical Sales (1)                                                   10,898    10,458
    Physical Purchases (1)                                              (10,624)  (10,126)
    Net Financial Transactions (1)                                          (27)      105
                                                                      ----------------------
Net Revenue                                                                 247       437
    Transportation Expense                                                 (220)     (232)
    Other                                                                     3         -
                                                                      ----------------------
NET MARKETING REVENUE                                                        30       205
                                                                      ======================

CONTRIBUTION TO NET MARKETING REVENUE BY PRODUCT TYPE:
    North American Natural Gas                                               25       188
    Global Crude Oil                                                        (12)       11
    North American Power                                                      7         3
    Other                                                                    10         3
                                                                      ----------------------
NET MARKETING REVENUE                                                        30       205
    General and Administrative                                              (30)      (36)
                                                                      ----------------------
NET MARKETING REVENUE AFTER GENERAL AND ADMINISTRATIVE                        -       169
    Depreciation, Depletion, Amortization and Impairment                     (4)       (3)
                                                                      ----------------------
MARKETING CONTRIBUTION TO INCOME BEFORE INCOME TAXES                         (4)      166
                                                                      ======================

PHYSICAL SALES VOLUMES (2)
    North American Natural Gas (bcf/d)                                      5.4       5.4
    Global Crude Oil (mbbls/d)                                              851       587
    North American Power (MW/d)                                           4,548     4,297

VALUE-AT-RISK
    Quarter-end                                                              33        19
    High                                                                     35        26
    Low                                                                      24        17
    Average                                                                  28        20
                                                                      ----------------------
</TABLE>
NOTES:
(1)  Marketing's   physical  sales,   physical   purchases  and  net  financial
     transactions are reported net on the unaudited  consolidated  statement of
     income as marketing and other.
(2)  Excludes intra-segment transactions.

LOWER CONTRIBUTION FROM MARKETING DECREASED NET INCOME BY $175 MILLION
Marketing's contribution to our first quarter results was lower than a year ago
when our Marketing  group was able to take advantage of volatile gas markets in
late 2005. In 2007,  late first quarter  liquidations in the gas markets caused
our North American natural gas group to report unrealized losses on their basis
positions.  The group is still  holding  these  positions  as they look to take
advantage of a favourable move in location spreads in the months ahead.

Losses  on   financial   contracts   hedging   Marketing's   gas   storage  and
transportation  assets also  contributed  to the lower  results in the quarter.
While the value of these storage and  transportation  assets has increased,  we
are unable to recognize these value gains in our reported results until the gas
in storage is sold and the  transportation  assets are used.  We are,  however,
required to include the losses on the  financial  contracts in our results.  We
expect to recognize the gains on our gas storage positions over the next twelve
months.

Our crude oil marketing  group was also affected by the volatility in crude oil
prices.  We  increased  our crude oil in storage  from last year.  We generated
unrealized  gains on our crude oil storage during the quarter but we are unable
to include the increase in value in our reported results until the oil is sold.
At the  same  time,  we  incurred  losses  on  financial  contracts  we hold to
economically  hedge this oil.  These  losses are included in our results as the
financial  contracts are carried at fair value. The global crude oil group also
realized  losses on their  crude oil trading  positions  as they were short oil
when prices started to rise. These positions have been closed out.

                                      34
<PAGE>

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.

<TABLE>
<CAPTION>
COMPOSITION OF NET MARKETING REVENUE
                                                                                                    Three Months
                                                                                                   Ended March 31
(Cdn$ millions)                                                                                 2007         2006
-------------------------------------------------------------------------------------------------------------------
<S>                                                                                               <C>         <C>
Trading Activities                                                                                24          202
Non-Trading Activities                                                                             6            3
                                                                                         --------------------------
                                                                                                  30          205
                                                                                         ==========================
</TABLE>

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

We value derivative trading contracts daily using:

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

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


FAIR VALUE OF DERIVATIVE CONTRACTS
At March 31, 2007, the fair value of our derivative contracts not designated as
accounting hedges totalled $88 million. Below is a breakdown of this fair value
by valuation method and contract maturity.

<TABLE>
<CAPTION>
(Cdn$ millions)                                                                       MATURITY
--------------------------------------------------------------------------------------------------------------------
                                                      less than                                more than
                                                         1 year    1-3 years     4-5 years      5 years       Total
                                                      --------------------------------------------------------------
<S>                                                   <C>          <C>           <C>           <C>            <C>
Prices
    Actively Quoted Markets                                 (36)          25           (11)           -         (22)
    From Other External Sources                               1           90            21           (2)        110
    Based on Models and Other Valuation Methods               -            -             -            -           -
                                                      --------------------------------------------------------------
Total                                                       (35)         115            10           (2)         88
                                                      ==============================================================
</TABLE>

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

(Cdn$ millions)                                                                                            Total
-------------------------------------------------------------------------------------------------------------------
<S>                                                                                                        <C>
Fair Value at December 31, 2006                                                                              360
    Change in Fair Value of Contracts                                                                         11
    Net Losses (Gains) on Contracts Closed                                                                  (283)
    Changes in Valuation Techniques and Assumptions (1)                                                        -
                                                                                                       ------------
Fair Value at March 31, 2007                                                                                  88
                                                                                                       ============
</TABLE>

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

As a physical energy  marketer,  we match the contract months of our derivative
contracts with the contract  months of our physical  sales and purchases.  As a
result,  the fair  value of our  derivative  contracts  as at  March  31,  2007
includes amounts with no ongoing  commodity price or foreign currency  exchange
risk.  Excluding these amounts,  the fair value of our derivative  contracts at
March 31, 2007 was $57 million.

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.  While forward prices
vary,  the  value  of  the  contracts  only  varies  to  the  extent  they  are
economically  exposed or  unprotected.  As most of our unrealized  value is not
economically exposed, we expect to realize the majority of this fair value.

                                      35
<PAGE>

Contract  maturities  vary  from a single  day up to 11 years.  Those  maturing
beyond one year primarily relate to North American  natural gas positions.  The
relatively short maturity of our contracts,  the high quality of our valuations
from quoted  markets and  external  sources and the limited  economic  exposure
combine to lower our portfolio risk.

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


NON-TRADING ACTIVITIES
We enter into fee for service contracts  related to transportation  and storage
of  third-party  oil and gas.  In  addition,  we earn  income  from  our  power
generation facilities at Balzac and Soderglen.  We earned $6 million from these
activities in the first quarter (2006 - $3 million).


CHEMICALS

HIGHER CHEMICALS CONTRIBUTION INCREASED NET INCOME BY $3 MILLION
North American  chlor-alkali  and sodium chlorate sales volumes remained strong
during the quarter  despite pulp mill outages and delays  caused by rail worker
labour  disturbances.  Our  operations  in Brazil  remain strong as a result of
continued demand from Aracruz Cellulose, our primary customer in Brazil.

Chemicals net income during the quarter  includes  foreign exchange gains of $2
million on Canexus US-dollar denominated debt.

<TABLE>
<CAPTION>
CORPORATE EXPENSES

GENERAL AND ADMINISTRATIVE (G&A)

                                                                            Three Months
                                                                           Ended March 31
(Cdn$ millions)                                                           2007        2006
--------------------------------------------------------------------------------------------
<S>                                                                        <C>         <C>
General and Administrative Expense before Stock-Based Compensation          86          75
Stock-Based Compensation (1)                                               116         145
                                                                        --------------------
Total General and Administrative Expense                                   202         220
                                                                        ====================
</TABLE>
Note:
(1)  Includes the tandem option plan, stock options for our US-based  employees
     and stock appreciation rights.

LOWER COSTS INCREASED QUARTERLY NET INCOME BY $18 MILLION
Our stock-based compensation expense decreased as compared to the first quarter
2006. In 2007,  our share price  increased 10% as compared to the first quarter
of 2006, when our common share price increased 16%. Cash expense related to our
stock-based compensation programs was $72 million during the first quarter.

We are continuing to expand our marketing  operations into new European markets
which has  increased  our G&A  expenses  relative to last year.  Labour  market
conditions  in the oil and gas  industry  also  remain  tight which is creating
upward pressure on employee costs.

                                      36
<PAGE>

INTEREST AND FINANCING COSTS

                                                                Three Months
                                                               Ended March 31
(Cdn$ millions)                                                2007       2006
--------------------------------------------------------------------------------
Interest                                                         86         66
    Less: Capitalized Interest                                  (38)       (57)
                                                             -------------------
Net Interest Expense                                             48          9
                                                             ===================

HIGHER INTEREST EXPENSE DECREASED QUARTERLY NET INCOME BY $39 MILLION
Our financing  costs increased $20 million from the first quarter of 2006 as we
used our term  credit  facilities  to finance  some of our  capital  investment
activities.  The  amount  of  interest  capitalized  on our  major  development
projects  decreased during the quarter as we completed the Buzzard and Syncrude
Stage 3 development projects in 2006. In 2007, we are capitalizing  interest on
our Long Lake development in the Athabasca oil sands and on our Ettrick project
in the North Sea.


INCOME TAXES

                                                                 Three Months
                                                                Ended March 31
(Cdn$ millions)                                                2007       2006
--------------------------------------------------------------------------------
Current                                                          60        109
Future                                                           35        269
                                                             -------------------
Total Provision for Income Taxes                                 95        378
                                                             ===================

Effective Tax Rate (%)                                          43%       127%
                                                             -------------------

EFFECTIVE TAX RATE DECREASES TO 43%
Current  income taxes  include  cash taxes in Yemen of $44 million  (2006 - $67
million). Our income tax provision also includes current taxes in Colombia, the
United States and the United Kingdom.

Our provision  for future  income taxes in 2006 included a one-time  expense of
$277  million  related  to tax rate  changes in the UK. In early  2006,  the UK
government  substantively  enacted increases to the supplementary charge on our
North Sea oil and gas activities  from 10% to 20%,  effective  January 1, 2006.
Excluding  the charge,  our effective tax rate in the first quarter of 2006 was
34%. Our  effective  tax rate in 2007  increased to 43% as more income is being
generated from our North Sea operations.


OTHER

                                                                  Three Months
                                                                 Ended March 31
(Cdn$ millions)                                                 2007       2006
--------------------------------------------------------------------------------
Decrease in Fair Value of Crude Oil Put Options                  (16)        (4)
                                                              ------------------

During the second  quarter of 2006, we purchased  put options on  approximately
105,000 bbls/d of our 2007 crude oil production.  These options establish a WTI
floor price of US$50/bbl on these volumes,  are settled  annually and provide a
base level of price  protection  without  limiting our upside to higher prices.
The put options were  purchased  for $26 million and are carried at fair value.
At December 31, 2006,  the options had a fair value of $19 million.  During the
first  quarter we recorded a loss of $16 million for the decrease in fair value
as a result of the rise in WTI.  In the first  quarter of 2006,  we  recorded a
loss of $4 million on crude oil put options purchased in late 2004 that expired
unused.

                                      37
<PAGE>

<TABLE>
<CAPTION>
LIQUIDITY

CAPITAL STRUCTURE

                                                                   March 31      December 31
(Cdn$ millions)                                                        2007             2006
---------------------------------------------------------------------------------------------
<S>                                                                   <C>              <C>
NET DEBT (1)
   Bank Debt                                                          1,720            1,410
   Public Senior Notes                                                2,815            2,885
                                                                   --------------------------
     Senior Debt                                                      4,535            4,295
   Subordinated Debt                                                    514              536
                                                                   --------------------------
     Total Debt                                                       5,049            4,831
   Less: Cash and Cash Equivalents                                     (110)            (101)
                                                                   --------------------------
TOTAL NET DEBT                                                        4,939            4,730
                                                                   ==========================

SHAREHOLDERS' EQUITY (2)                                              4,783            4,636
                                                                   ==========================
</TABLE>
Notes:
(1)  Includes  all  of our  debt  and  is  calculated  as  long-term  debt  and
     short-term borrowings less cash and cash equivalents.

(2)  At March 31, 2007, there were 263,188,018 common shares and US$460 million
     of  unsecured  subordinated  securities  outstanding.  These  subordinated
     securities  may be redeemed by issuing  common  shares at our option after
     November  8,  2008.  The number of shares  issuable  depends on the common
     share price on the redemption date.

NET DEBT

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

<TABLE>
<CAPTION>
(Cdn$ millions)
--------------------------------------------------------------------------------------------
<S>                                                                                    <C>
Capital Investment                                                                      811
Cash Flow from Operating Activities                                                    (448)
                                                                                ------------
   Excess of Capital Investment over Cash Flow                                          363

Dividends on Common Shares                                                               13
Issue of Common Shares                                                                  (29)
Foreign Exchange Translation of US-dollar Debt and Cash                                 (50)
Other                                                                                   (88)
                                                                                ------------
Increase in Net Debt                                                                    209
                                                                                ============
</TABLE>
<TABLE>
<CAPTION>
CHANGE IN WORKING CAPITAL

                                                         March 31     December 31   Increase/
(Cdn$ millions)                                              2007            2006   (Decrease)
----------------------------------------------------------------------------------------------
<S>                                                        <C>             <C>          <C>
Cash and Cash Equivalents                                     110             101        9
Restricted Cash                                               181             197      (16)
Accounts Receivable                                         2,853           2,951      (98)
Inventories and Supplies                                      665             786     (121)
Future Income Tax Assets                                      426             479      (53)
Accounts Payable and Accrued Liabilities                   (3,814)         (3,879)      65
Other                                                          22              (1)      23
                                                      ----------------------------------------
Net Working Capital                                           443             634     (191)
                                                      ========================================
</TABLE>

Accounts  receivable  were  lower  than  year  end as  gains  on our  marketing
derivative  contracts  previously  included  in our  accounts  receivable  were
realized during the quarter.  Natural gas inventory held by our marketing group
was lower than year end as we capitalized on the winter heating season and sold
natural gas from storage.  This was partially offset as our crude oil marketing
group acquired additional inventory during the quarter. Our accrued liabilities
decreased  during the quarter as we settled the Block 51 arbitration.  This was
partially offset by accruals for our stock-based  compensation  obligations and
higher activity by our international crude oil marketing group.

                                      38
<PAGE>

OUTLOOK FOR REMAINDER OF 2007
We continue to expect our 2007 full year  production to average between 275,000
and 305,000 boe/d before royalties. We expect to generate $3 to $3.3 billion in
cash flow (before  remediation and geological and geophysical  expenditures) in
2007, assuming the following for the remainder of the year:


-------------------------------------------------------------------------------
WTI (US$/bbl)                                                            50.00
NYMEX natural gas (US$/mmbtu)                                             6.00
Oil & Gas and Syncrude Operating Costs (Cdn$/boe)                         8.00
US to Canadian dollar exchange rate                                       0.88
                                                                   ------------

To date,  we have  incurred  almost 28% of our planned 2007 capital  investment
program.  Our 2007  estimated  capital  investment  program has  increased as a
result of higher estimates to complete the Long Lake  development.  Our capital
investment  for the  remainder of the year is focused on bringing  Long Lake on
stream,  advancing the Ettrick  development in the North Sea towards completion
in 2008 and investing in exploration opportunities in our growth areas.

Our future  liquidity is primarily  dependent on cash flows  generated from our
operations, existing committed credit facilities and our ability to access debt
and equity  markets.  In July 2007,  we are  required to repay $150  million of
medium term notes that become due; however,  we plan to fund this with our term
credit  facilities.  At March 31, 2007,  we had undrawn  committed  term credit
facilities  of over $2 billion  that are  available  until 2011,  of which $224
million  was  utilized  to support  letters  of  credit.  We also had over $500
million of undrawn  uncommitted  credit  facilities,  of which $181 million was
utilized to support letters of credit.

In the first quarter, we declared common share dividends of $0.05 per share.

CONTRACTUAL OBLIGATIONS, COMMITMENTS AND GUARANTEES
We have assumed various  contractual  obligations and commitments in the normal
course of our  operations  and financing  activities.  We have  included  these
obligations and commitments in our MD&A in our 2006 Annual Report on Form 10-K.
In 2007, we entered into work commitments  related to a drilling rig, which has
been contracted to work for us in the North Sea,  totaling $93 million over the
next two years.  There have been no other significant  developments  since year
end.


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


NEW ACCOUNTING PRONOUNCEMENTS

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

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

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

                                      39
<PAGE>

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

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


EQUITY SECURITY REPURCHASES

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


<TABLE>
<CAPTION>
SUMMARY OF QUARTERLY RESULTS

                                                                                       Three Months Ended
                                                              2005                            2006                          2007
                                                 -------------------------------|---------------------------------------|---------
(Cdn$ millions)                                     Jun       Sept       Dec    |    Mar       Jun        Sep     Dec   |    Mar
--------------------------------------------------------------------------------|---------------------------------------|---------
<S>                                                 <C>      <C>       <C>           <C>     <C>          <C>     <C>      <C>
Net Sales                                           909      1,094     1,073         980     1,039        997     920      1,140

Net Income (Loss) from Continuing Operations        167        205       303         (83)      408        199      77        121
Net Income from Discontinued Operations              30        404         -           -         -          -       -          -
                                                 ---------------------------------------------------------------------------------
Net Income (Loss)                                   197        609       303         (83)      408        199      77        121
                                                 =================================================================================

Earnings per Common Share from
     Continuing Operations ($/share)
   Basic                                           0.64       0.79      1.16       (0.32)     1.56       0.76    0.29       0.46
   Diluted                                         0.63       0.77      1.13       (0.32)     1.53       0.74    0.29       0.45

Earnings per Common Share ($/share)
   Basic                                           0.76       2.34      1.16       (0.32)     1.56       0.76    0.29       0.46
   Diluted                                         0.75       2.28      1.13       (0.32)     1.53       0.74    0.29       0.45
                                                 ---------------------------------------------------------------------------------
</TABLE>

                                      40
<PAGE>

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain  statements  in this  report,  including  those  appearing  in ITEM 7 -
MANAGEMENT'S  DISCUSSION  AND  ANALYSIS OF FINANCIAL  CONDITION  AND RESULTS OF
OPERATIONS, are forward-looking  statements.(1)  Forward-looking statements are
generally  identifiable  by terms such as ANTICIPATE,  BELIEVE,  INTEND,  PLAN,
EXPECT,  ESTIMATE,   BUDGET,  OUTLOOK  or  other  similar  words,  and  include
statements  relating to expected  full year  production,  cash flow and capital
expenditures as well as future production  associated with our coalbed methane,
Long Lake,  Syncrude,  North Sea,  Gulf of Mexico and West Africa  projects and
other projects.

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

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

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

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

o   foreign-currency exchange rates;

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

o   governmental actions that increase taxes or royalties, change environmental
    and other laws and regulations;

o   renegotiations of contracts;

o   results of litigation, arbitration or regulatory proceedings; and

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

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

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

o   future crude oil, natural gas or chemicals prices;

o   future production levels;

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

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

o   future asset dispositions;

o   future sources of funding for our capital program;

o   possible commerciality, development plans or capacity expansions;

o   future ability to execute dispositions of assets or businesses;

o   future debt levels;

o   future cash flows and their uses;

o   future drilling of new wells;

o   ultimate recoverability of reserves;

o   expected finding and development costs;

o   expected operating costs;

o   future demand for chemicals products;

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

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

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


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

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<PAGE>

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4.    CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

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

CHANGES IN INTERNAL CONTROLS

We have  continually  had in place  systems  relating to internal  control over
financial  reporting.  During the first  quarter of 2007, we had two changes in
our control  environment.  Firstly in  February  2007,  our Board of  Directors
approved a revised Ethics Policy for the Company. The Ethics Policy is now in a
new format and  presented  in plainer  language,  but there are no  substantive
changes  from  the  previous  Ethics  Policy.  Secondly,  in  March  2007,  our
Controller,  Michael  Harris,  assumed the position of Vice President  Investor
Relations and Corporate  Communications,  and in April 2007, Brendon Muller was
appointed as our new Controller. There has not been any change in the Company's
internal control over financial reporting during the first quarter of 2007 that
has materially  affected,  or is reasonably  likely to materially  affect,  the
Company's  internal control over financial  reporting.  As well, based on these
evaluations,  there were no  material  weaknesses  in these  internal  controls
requiring  corrective  action.  As a result,  no such  corrective  actions were
taken.


                                       42
<PAGE>


                                    PART II

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

None.

ITEM 6.    EXHIBITS

10.48  Amended and Restated Change of Control Agreement with Roger Thomas dated
       during December 2001.

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 27, 2007.

                                         NEXEN INC.


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



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


                                      43