Nexen (NXY) 10-Q 2008 Q1 Quarterly report

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, 2008

o	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

 

NEXEN INC.

Incorporated under the Laws of Canada

98-6000202

(I.R.S. Employer Identification No.)

801 – 7^th 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  o

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

   Large accelerated filer   x          Non-Accelerated filer    o          Accelerated filer   o          Smaller reporting company   o

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

Yes   o No x

On March 31, 2008, there were 529,439,432 common shares issued and outstanding.

NEXEN INC.

INDEX

PART I		FINANCIAL INFORMATION	Page
	Item 1.	Unaudited Consolidated Financial Statements				3
	Item 2.	Management’s Discussion and Analysis of Financial Condition
		and Results of Operations			27
	Item 3.	Quantitative and Qualitative Disclosures about Market Risk			47
	Item 4.	Controls and Procedures			47
PART II		OTHER INFORMATION
	Item 4.	Submission of Matters to a Vote of Security Holders			48
	Item 6.	Exhibits		48

This report should be read in conjunction with our 2007 Annual Report on Form 10-K 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 76 of our 2007 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.

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

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 31, 2008, the noon-day exchange rate was US$0.9729 for Cdn$1.00, as reported by the Bank of Canada.

2

PART I

Item 1.   Unaudited Consolidated Financial Statements

TABLE OF CONTENTS

Page     

Unaudited Consolidated Statement of Income

for the Three Months Ended March 31, 2008 and 2007 4

Unaudited Consolidated Balance Sheet

as at March 31, 2008 and December 31, 2007 5

Unaudited Consolidated Statement of Cash Flows

for the Three Months Ended March 31, 2008 and 2007 6

Unaudited Consolidated Statement of Shareholders’ Equity

for the Three Months Ended March 31, 2008 and 2007 7

Unaudited Consolidated Statement of Comprehensive Income

for the Three Months Ended March 31, 2008 and 2007 7

Notes to Unaudited Consolidated Financial Statements 8

3

Nexen Inc.

Unaudited Consolidated Statement of Income

For the Three Months Ended March 31

(Cdn$ millions, except per share amounts)	2008	2007
Revenues and Other Income
Net Sales	1,870	1,140
Marketing and Other (Note 15)	222	248
	2,092	1,388
Expenses
Operating	309	290
Depreciation, Depletion, Amortization and Impairment	364	334
Transportation and Other	205	246
General and Administrative	55	202
Exploration	32	49
Interest (Note 6)	27	48
	992	1,169
Income before Income Taxes	1,100	219
Provision for Income Taxes
Current	392	60
Future	77	35
	469	95
Net Income before Non-Controlling Interests	631	124
Less: Net Income Attributable to Non-Controlling Interests	(1)	(3)
Net Income	630	121
Earnings Per Common Share ($/share)
Basic (Note 13)	1.19	0.23
Diluted (Note 13)	1.17	0.22

See accompanying notes to the Unaudited Consolidated Financial Statements.

4

Nexen Inc.

Unaudited Consolidated Balance Sheet

		March 31	December 31
(Cdn$ millions, except share amounts)		2008	2007
Assets
Current Assets
Cash and Cash Equivalents		524	206
Restricted Cash		75	203
Accounts Receivable (Note 2)		4,041	3,502
Inventories and Supplies (Note 3)		755	659
Future Income Tax Assets		25	18
Other		84	71
Total Current Assets		5,504	4,659
Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion, Amortization and
Impairment of $7,703 (December 31, 2007 – $7,195)		13,139	12,498
Future Income Tax Assets		263	268
Deferred Charges and Other Assets (Note 4)		418	324
Goodwill		337	326
Total Assets		19,661	18,075
Liabilities and Shareholders’ Equity
Current Liabilities
Current Portion of Long-Term Debt (Note 6)		125	-
Accounts Payable and Accrued Liabilities		4,894	4,180
Accrued Interest Payable		67	54
Dividends Payable		13	13
Total Current Liabilities		5,099	4,247
Long-Term Debt (Note 6)		4,458	4,610
Future Income Tax Liabilities		2,415	2,290
Asset Retirement Obligations (Note 8)		814	792
Deferred Credits and Other Liabilities (Note 9)		525	459
Non-Controlling Interests		64	67
Shareholders’ Equity (Note 12)
Common Shares, no par value
Authorized:	Unlimited
Outstanding:	2008 – 529,439,432 shares
	2007 – 528,304,813 shares	949	917
Contributed Surplus		3	3
Retained Earnings		5,600	4,983
Accumulated Other Comprehensive Loss		(266)	(293)
Total Shareholders’ Equity		6,286	5,610
Commitments, Contingencies and Guarantees (Note 16)
Total Liabilities and Shareholders’ Equity		19,661	18,075

See accompanying notes to the Unaudited Consolidated Financial Statements.

5

Nexen Inc.

Unaudited Consolidated Statement of Cash Flows

For the Three Months Ended March 31

(Cdn$ millions)	2008	2007
Operating Activities
Net Income	630	121
Charges and Credits to Income not Involving Cash (Note 14)	383	435
Exploration Expense	32	49
Changes in Non-Cash Working Capital (Note 14)	140	32
Other	(17)	(189)
	1,168	448
Financing Activities
(Repayment of) Proceeds from Term Credit Facilities, Net	(228)	366
Proceeds from Term Credit Facilities of Canexus	8	18
Repayment of Short-Term Borrowings, Net	-	(48)
Dividends on Common Shares	(13)	(13)
Issue of Common Shares and Exercise of Stock Options	26	29
Other	(4)	(7)
	(211)	345
Investing Activities
Capital Expenditures
Exploration and Development	(769)	(790)
Proved Property Acquisitions	-	(1)
Chemicals, Corporate and Other	(17)	(20)
Changes in Restricted Cash	121	16
Changes in Non-Cash Working Capital (Note 14)	22	28
Other	(27)	(4)
	(670)	(771)
Effect of Exchange Rate Changes on Cash
and Cash Equivalents	31	(13)
Increase in Cash and Cash Equivalents	318	9
Cash and Cash Equivalents – Beginning of Period	206	101
Cash and Cash Equivalents – End of Period	524	110

See accompanying notes to the Unaudited Consolidated Financial Statements.

6

Nexen Inc.

Unaudited Consolidated Statement of Shareholders’ Equity

For the Three Months Ended March 31

(Cdn$ millions)	2008	2007
Common Shares
Balance at Beginning of Period	917	821
Issue of Common Shares	20	21
Proceeds from Tandem Options Exercised for Shares	6	8
Accrued Liability Relating to Tandem Options Exercised for Shares	6	16
Balance at End of Period	949	866
Contributed Surplus
Balance at Beginning and End of Period	3	4
Retained Earnings
Balance at Beginning of Period	4,983	3,972
Net Income	630	121
Dividends on Common Shares (Note 12)	(13)	(13)
Balance at End of Period	5,600	4,080
Accumulated Other Comprehensive Loss
Balance at Beginning of Period	(293)	(161)
Opening Derivatives Designated as Cash Flow Hedges	-	61
Other Comprehensive Income (Loss)	27	(67)
Balance at End of Period	(266)	(167)
Nexen Inc. Unaudited Consolidated Statement of Comprehensive Income For the Three months Ended March 31
(Cdn$ millions)	2008	2007
Net Income	630	121
Other Comprehensive Income (Loss), Net of Income Taxes:
Foreign Currency Translation Adjustment:
Net Gains (Losses) on Investment in Self-Sustaining Foreign Operations	186	(58)
Net Gains (Losses) on Hedges of Self-Sustaining Foreign Operations 1	(159)	50
Realized Translation Adjustments Recognized in Net Income 2	-	2
Cash Flow Hedges:
Realized Mark-to-Market Gains Recognized in Net Income	-	(61)
Other Comprehensive Income (Loss), Net of Income Taxes	27	(67)
Comprehensive Income	657	54

 

¹ Net of income tax expense for the three months ended March 31, 2008 of $23 million (2007 – $9 million recovery).

² Net of income tax expense for the three months ended March 31, 2008 of $nil (2007 – $1 million expense).

 

See accompanying notes to the Unaudited Consolidated Financial Statements.

7

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 18. 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, 2008 and December 31, 2007 and the results of our operations and our cash flows for the three months ended March 31, 2008 and 2007.

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, 2008 are not necessarily indicative of the results of operations or cash flows to be expected for the year ending December 31, 2008.

These Unaudited Consolidated Financial Statements should be read in conjunction with our Audited Consolidated Financial Statements included in our 2007 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 2007 Annual Report on Form 10-K.

Change in Accounting Policies

Inventories

In 2007, we adopted CICA Section 3031 Inventories issued by the Canadian Accounting Standards Board (AcSB). Effective October 1, 2007, we began carrying the commodity inventories held for trading by our energy marketing group at fair value, less any costs to sell. This standard was adopted prospectively and our results for the first three months of 2007 have not been restated for this change in accounting policy.

Capital Disclosures

On January 1, 2008, we prospectively adopted CICA Section 1535 Capital Disclosures issued by the AcSB. This Section establishes standards for disclosing information about an entity’s objectives, policies and processes for managing its capital structure. The disclosures have been included in Note 7.

Financial Instruments Disclosures and Presentation

On January 1, 2008, we prospectively adopted the following new standards issued by the AcSB: Financial Instruments – Disclosure (Section 3862) and Financial Instruments – Presentation (Section 3863). These accounting standards replaced Financial Instruments – Disclosure and Presentation (Section 3861). The disclosures required by Section 3862 provide additional information on the risks associated with our financial instruments and how we manage those risks. The additional disclosures required by these standards are provided in Notes 10 and 11.

New Accounting Pronouncements

In February 2008, the AcSB issued Section 3064, Goodwill and Intangible Assets and amended Section 1000, Financial Statement Concepts clarifying the criteria for the recognition of assets, intangible assets and internally developed intangible assets. Items that no longer meet the definition of an asset are no longer recognized with assets. The standard is effective for fiscal years beginning on or after October 1, 2008 and early adoption is permitted. We are currently evaluating the impact these sections will have on our results of operations and financial position.

In January 2006, the AcSB adopted a strategic plan for the direction of accounting standards in Canada. Accounting standards for public companies in Canada will converge with the International Financial Reporting Standards (IFRS) by 2011 and we will be required to report according to IFRS standards for the year ended December 31, 2011. We are currently assessing the impact of the convergence of Canadian GAAP with IFRS on our results of operations, financial position and disclosures.

8

2. ACCOUNTS RECEIVABLE

	March 31	December 31
	2008	2007
Trade
Marketing	2,907	2,501
Oil and Gas	931	819
Chemicals and Other	64	60
	3,902	3,380
Non-Trade	149	132
	4,051	3,512
Allowance for Doubtful Receivables	(10)	(10)
Total	4,041	3,502

3. INVENTORIES AND SUPPLIES

	March 31	December 31
	2008	2007
Finished Products
Marketing	659	577
Oil and Gas	20	14
Chemicals and Other	16	13
	695	604
Work in Process	4	3
Field Supplies	56	52
Total	755	659

4. DEFERRED CHARGES AND OTHER ASSETS

	March 31	December 31
	2008	2007
Long-Term Marketing Derivative Contracts (Note 10)	294	248
Long-Term Capital Prepayments	38	9
Crude Oil Put Options and Natural Gas Swaps (Note 10)	18	-
Asset Retirement Remediation Fund	13	13
Other	55	54
Total	418	324

9

5. SUSPENDED WELL COSTS

The following table shows the changes in capitalized exploratory well costs during the three months ended March 31, 2008 and the year ended December 31, 2007, and does not include amounts that were initially capitalized and subsequently expensed in the same period. Capitalized exploratory well costs are included in property, plant & equipment.

	Three Months Ended March 31	Year Ended December 31
	2008	2007
Balance at Beginning of Period	326	226
Additions to Capitalized Exploratory Well Costs Pending the
Determination of Proved Reserves	49	215
Capitalized Exploratory Well Costs Charged to Expense	-	(10)
Transfers to Wells, Facilities and Equipment Based on
Determination of Proved Reserves	-	(74)
Effects of Foreign Exchange	7	(31)
Balance at End of Period	382	326

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

	March 31	December 31
	2008	2007
Capitalized for a Period of One Year or Less	195	202
Capitalized for a Period of Greater than One Year	187	124
Balance at End of Period	382	326
Number of Projects that have Exploratory Well Costs Capitalized for a
Period Greater than One Year	8	5

As at March 31, 2008, we have exploratory costs that have been capitalized for more than one year relating to our interest in four exploratory blocks in the North Sea ($55 million), an exploratory block in the Gulf of Mexico ($54 million), our coalbed methane exploratory activities in Canada ($41 million), exploratory activities on Block 51 in Yemen ($19 million) and our interest in an exploratory block, offshore Nigeria ($18 million). These costs relate to projects with successful exploration wells for which we have not been able to record proved reserves. We are assessing all of these wells and projects, and are working with our partners to prepare development plans, drill additional appraisal wells or to assess commercial viability.

6. LONG-TERM DEBT AND SHORT-TERM BORROWINGS

	March 31	December 31
	2008	2007
Term Credit Facilities (a)	-	211
Canexus Limited Partnership Term Credit Facilities (US$213 million)	218	202
Medium-Term Notes, due 2008 (b)	125	125
Notes, due 2013 (US$500 million)	514	494
Notes, due 2015 (US$250 million)	257	247
Notes, due 2017 (US$250 million)	257	247
Notes, due 2028 (US$200 million)	205	198
Notes, due 2032 (US$500 million)	514	494
Notes, due 2035 (US$790 million)	812	781
Notes, due 2037 (US$1,250 million)	1,285	1,235
Subordinated Debentures, due 2043 (US$460 million)	473	454
	4,660	4,688
Less: Unamortized Debt Issue Costs	(77)	(78)
	4,583	4,610
Less: Current Portion of Long-Term Debt (b)	(125)	-
	4,458	4,610

10

(a) Term credit facilities

We have unsecured term credit facilities of US$3 billion available to 2012, none of which were drawn at March 31, 2008 (December 31, 2007 – US$214 million). Borrowings are available as Canadian bankers’ acceptances, LIBOR-based loans, Canadian prime rate loans, US-dollar base rate loans or British pound call-rate loans. Interest is payable at floating rates. The weighted-average interest rate on our term credit facilities was 3.9% for the three months ended March 31, 2008 (2007 – 5.9%). At March 31, 2008, $296 million of these facilities were utilized to support outstanding letters of credit (December 31, 2007 – $283 million).

(b) Medium-Term Notes, due 2008

During October 1997, we issued $125 million of notes. Interest is payable semi-annually at a rate of 6.3% and the principal is to be repaid in June 2008. At December 31, 2007 this amount was not included in current liabilities as we expected to repay the principal using our term credit facilities. During the quarter, we reclassified this obligation to current liabilities as we now expect to repay this amount using our existing cash on hand.

(c) Interest expense

	Three Months Ended March 31
	2008	2007
Long-Term Debt	76	81
Other	4	5
	80	86
Less: Capitalized	(53)	(38)
Total	27	48

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

(d) Short-term borrowings

Nexen has uncommitted, unsecured credit facilities of approximately $666 million, none of which were drawn at March 31, 2008 (December 31, 2007 – nil). We have utilized $44 million of these facilities to support outstanding letters of credit at March 31, 2008 (December 31, 2007 – $196 million). Interest is payable at floating rates. The weighted-average interest rate on our short-term borrowings was 4.3% for the three months ended March 31, 2008 (2007 – 5.9%).

7. CAPITAL DISCLOSURES

Our objective for managing our capital structure is to ensure that we have the financial capacity, liquidity and flexibility to fund our investment in full-cycle exploration and development of conventional and unconventional resources and for our energy marketing activities. We generally rely on operating cash flows to fund capital investments. However, given the long cycle-time of some of our development projects, which require significant capital investment prior to cash flow generation, and volatile commodity prices, it is not unusual for capital expenditures to exceed our cash flow from operating activities in any given year. As such, our financing needs depend on where we are in a particular development cycle. This requires us to maintain financial flexibility and liquidity. Our capital management policies are aimed at:

• maintaining an appropriate balance between short-term debt, long-term debt and equity, such as using longer-term senior and subordinated debt securities to minimize near-term refinancing risks;

• maintaining sufficient undrawn committed credit capacity to provide liquidity;

• ensuring ample covenant room permitting us to draw on our credit lines as required;

• maintaining a level of leverage with sufficient room for increases when necessary; and

• ensuring we maintain a credit rating that is appropriate for our circumstances.

11

We have the ability to make adjustments to our capital structure by issuing additional equity or debt, controlling the amount we return to shareholders and making adjustments to our capital investment programs. Our capital consists of shareholders’ equity, short-term and long-term debt and cash and cash equivalents (excluding restricted cash) as follows:

	March 31	December 31
	2008	2007
Net Debt 1
Bank Debt	218	413
Public Senior Notes	3,907	3,758
Senior Debt	4,125	4,171
Subordinated Debt	458	439
Total Debt	4,583	4,610
Less: Cash and Cash Equivalents	(524)	(206)
Total Net Debt	4,059	4,404
Shareholders’ Equity	6,286	5,610

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

We monitor our capital structure by reviewing the ratio of net debt to cash flow from operating activities and interest coverage on a trailing 12 month basis that we feel are appropriate for Nexen.

We use the ratio of net debt to cash flow from operating activities as a key indicator of our leverage and to monitor the strength of our balance sheet. Net debt is a non-GAAP measure which is calculated using the GAAP measure of long-term debt and short-term borrowings less cash and cash equivalents (excluding restricted cash).

For the twelve months ending March 31, 2008 our net debt to cash flow from operating activities ratio was 1.1 times compared to 1.6 times at December 31, 2007. While we typically expect the target ratio to fluctuate between 1.0 and 2.0 times under normalized commodity prices, this can be higher when we identify strategic opportunities requiring additional investment. Whenever we exceed our target ratio, we devise a strategy to reduce our leverage and lower this ratio back to target levels. In the past, each time we exceeded our internal net debt to cash flow from operating activities target band, we successfully brought our leverage down through asset sales and capital management.

Our interest coverage ratio allows us to monitor our ability to meet the interest requirements of our capital and consequently the level, terms and condition of our debt profile. The higher the interest coverage, the better positioned we are to finance our longer-term investment projects. Our interest coverage strengthened in 2008 from 12.1 times at the end of 2007 to 14.4 times at March 31, as our earnings before interest, taxes, depreciation, depletion and amortization (EBITDA) increased from strong production and high commodity prices.

Interest coverage is calculated by dividing our twelve-month trailing EBITDA by interest expense before capitalized interest. EBITDA is a non-GAAP measure which is calculated using net income excluding interest expense, provision for income taxes, exploration expenses, DD&A and other non-cash expenses. The calculation of EBITDA is set out in the following table.

	Twelve Months Ended March 31 2008	Twelve Months Ended December 31 2007
Net Income	1,595	1,086
Add:
Interest Expense	147	168
Provision for Income Taxes	1,166	792
Depreciation, Depletion, Amortization and Impairment	1,797	1,767
Exploration Expense	309	326
Other Non-cash Expenses	(176)	(52)
EBITDA	4,838	4,087

12

8. ASSET RETIREMENT OBLIGATIONS  

Changes in carrying amounts of the asset retirement obligations associated with our property, plant and equipment are as follows:

	Three Months Ended March 31	Year Ended December 31
	2008	2007
Balance at Beginning of Period	832	704
Obligations Incurred with Development Activities	2	105
Expenditures Made on Asset Retirements	(13)	(23)
Accretion	13	44
Revisions to Estimates	(1)	79
Effects of Foreign Exchange	21	(77)
Balance at End of Period 1, 2	854	832

 

¹     Obligations due within 12 months of $40 million (December 31, 2007 – $40 million) have been included in accounts payable and accrued
      liabilities.

²     Obligations relating to our oil and gas activities amount to $807 million (December 31, 2007 – $786 million) and obligations relating to our
      chemicals business amount to $47 million (December 31, 2007 – $46 million).

Our total estimated undiscounted asset retirement obligations amount to $2,200 million (December 31, 2007 – $2,165 million). We have discounted the total estimated asset retirement obligations using a weighted-average, credit-adjusted risk-free rate of 5.9%. Approximately $139 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 obligation to remediate becomes determinable.

9. DEFERRED CREDITS AND OTHER LIABILITIES

	March 31 2008	December 31 2007
Long-Term Marketing Derivative Contracts (Note 10)	225	163
Deferred Transportation Revenue	73	82
Defined Benefit Pension Obligations	58	57
Capital Lease Obligations	53	52
Fixed-Price Natural Gas Contracts (Note 10)	49	48
Other	67	57
Total	525	459

13

10. FINANCIAL INSTRUMENTS  

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

In our energy marketing group, we enter into contracts to purchase and sell crude oil and natural gas and use derivative contracts, including futures, forwards, swaps and options, for hedging and trading purposes (collectively derivatives). Occasionally, we use derivatives such as put options to manage commodity price risk and foreign currency risk for non-trading purposes. We categorize our derivative instruments as trading or non-trading activities and carry the instruments at fair value on our balance sheet. Refer to the derivatives section below for details of our derivatives and fair values as at March 31, 2008. The fair value is included with accounts receivable or payable and they are classified as long-term or short-term based on their anticipated settlement date. Any change in fair value is included in marketing and other income.

We carry our long-term debt at amortized cost using the effective interest rate method. At March 31, 2008, the estimated fair value of our long-term debt was $4,578 million (December 31, 2007 – $4,692 million) as compared to the carrying value of $4,583 million (December 31, 2007 – $4,610 million). The fair value of long-term debt is estimated based on prices provided by quoted markets and third-party brokers.

Derivatives

a) Total carrying value of derivative contracts related to trading activities

The fair value and carrying amounts related to derivative instruments held by our energy marketing operations are as follows:

	March 31 2008	December 31 2007
Accounts Receivable	595	334
Deferred Charges and Other Assets 1	294	248
Total Derivative Assets	889	582
Accounts Payable and Accrued Liabilities	543	413
Deferred Credits and Other Liabilities 1	225	163
Total Derivative Liabilities	768	576
Total Net Derivatives related to Trading Activities	121	6

 

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

 

b) Total carrying value of derivative contracts related to non-trading activities

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

	March 31 2008	December 31 2007
Accounts Receivable	8	-
Deferred Charges and Other Assets 1	18	1
Total Derivative Assets	26	1
Accounts Payable and Accrued Liabilities	36	28
Deferred Credits and Other Liabilities 1	49	51
Total Derivative Liabilities	85	79
Total Net Derivatives related to Non-Trading Activities	(59)	(78)

 

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

 

Crude oil put options

In 2008, we purchased put options on approximately 70,000 bbls/d of our 2009 crude oil production. These options establish an annual average Dated Brent floor price of $60/bbl on these volumes. In 2007, we purchased put options on 36 million barrels or approximately 100,000 bbls/d of our 2008 crude oil production. These options establish an annual average Dated Brent floor price of US$50/bbl on these volumes.

14

The put options are carried at fair value within amounts receivable and are classified as long-term or short-term based on their anticipated settlement date. Any changes in fair value are included in marketing and other income.

	Notional Volumes	Term	Average Floor Price	Fair Value
	(bbls/d)		(US$/bbl)	(Cdn$ millions)
Dated Brent Crude Oil Put Options	100,000	2008	50		-
Dated Brent Crude Oil Put Options	70,000	2009	60		14
					14

Fixed-price natural gas contracts and natural gas swaps

We have fixed-price natural gas sales contracts and offsetting natural gas swaps that are not included in our trading activities. These sales contracts and swaps are carried at fair value and are included with amounts receivable or payable. They are classified as long-term or short-term based on their anticipated settlement date. Any change in fair value is included in marketing and other income.

	Notional Volumes	Term	Average Price	Fair Value
	(Gj/d)		($/Gj)	(Cdn$ millions)
Fixed-Price Natural Gas Contracts	15,514	2008	2.46		(36)
	15,514	2009 – 2010	2.56 – 2.77		(49)
Natural Gas Swaps	15,514	2008	7.60		8
	15,514	2009 – 2010	7.60		4
					(73)

c) Fair Value of Derivatives

Wherever possible, the estimated fair value of our derivative instruments is based on quoted market prices and, if not available, on estimates from third-party brokers. We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk. As a basis for establishing fair value, we utilize a mid-market pricing convention between bid and ask and then adjust our pricing to the ask price when we have a net open sell and the bid price when we have a net open buy. We incorporate the credit risk associated with counterparty default into our estimates of fair value. Inputs to fair valuations may be readily observable, market-corroborated, or generally unobservable. We utilize valuation techniques that maximize the use of observable inputs wherever possible and minimize the use of unobservable inputs. To value longer-term transactions and transactions in less active markets for which pricing information is not generally available, unobservable inputs may be used.

We classify our derivatives according to the following hierarchy based on the amount of observable inputs used to value the instruments.

• Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and we use information from markets such as the New York Mercantile Exchange and the International Petroleum Exchange.

• Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value, volatility factors, and broker quotations, which can be observed or corroborated in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter physical forwards and options. We obtain information from sources such as the Natural Gas Exchange, independent price publications and over-the-counter broker quotes.

• Level 3 – Valuations in this level are based on inputs which are less observable, unavailable or where the observable data does not support the majority of the instrument’s fair value. Level 3 instruments include longer-term transactions, transactions in less active markets or transactions at locations for which pricing information is not available. In these instances, internally developed methodologies are used to determine fair value which primarily include extrapolation of observable future prices to similar locations, similar instruments or later time periods.

15

The following table includes our derivatives that are carried at fair value on a recurring basis for our trading and non-trading activities as at March 31, 2008. Financial assets and liabilities are classified in the fair value hierarchy in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect placement within the fair value hierarchy levels.

	Level 1	Level 2	Level 3	Total
Net Derivatives
Trading Derivatives	148	7	(34)	121
Non-Trading Derivatives	–	(59)	–	(59)
Total Net Derivatives	148	(52)	(34)	62

A reconciliation of changes in the fair value of our derivatives classified as Level 3 for the three months ended March 31, 2008 is provided below:

	Level 3
Fair Value at January 1, 2008	(7)
Realized and unrealized gains (losses)	(5)
Purchases, issuances and settlements	(2)
Transfers in and/or out of Level 3	(20)
Fair Value at March 31, 2008	(34)
Unsettled gains (losses) relating to instruments still held as of March 31, 2008	(23)

Transfers in and/or out represent existing assets and liabilities that were either previously categorized as a higher level for which the inputs became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period.

11. RISK MANAGEMENT

(a) Market Risk

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

The following market risk discussion relates primarily to commodity price risk and foreign exchange risk related to our financial instruments. Our exposure to interest rate risk is immaterial.

Commodity price risk

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

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

Our energy marketing group markets and trades crude oil, natural gas, NGLs, ethanol and power through physical purchase and sales contracts, as well as financial commodity contracts. These activities expose us to commodity price risk, as well as foreign currency risk and volatility within these markets. Our energy marketing group actively manages this risk by utilizing energy and currency derivatives. We typically take advantage of location, time and quality spreads using physical and financial contracts. The marketing group also tries to take advantage of volatility within commodity markets and can establish net open commodity positions to take advantage of existing market conditions.

Volatility within our various markets can vary and change over time. While this volatility gives us opportunities, it can also cause our results to vary significantly between periods. We attempt to manage associated risk and take on positions based on solid market intelligence; however, it is possible that we could incur financial loss.

16

Open positions exist when not all contracted purchases and sales terms have been matched. These net open positions allow us to generate income, but also expose us to risk of loss due to fluctuating market prices (market risk sensitivities in our portfolio).

We manage the level of market risk through daily monitoring of our energy-trading activities relative to:

• prescribed limits for Value-at-Risk (VaR);

• nominal size of commodity positions;

• stop loss limits; and

• stress testing.

VaR is a statistical estimate assuming normal market conditions exist. Our VaR calculation estimates the maximum probable loss, given a 95% confidence level that we would incur if we were to unwind our outstanding positions over a two-day period. We estimate VaR primarily by using the Variance-Covariance method based on historical commodity price volatility, correlation inputs where available and by historical simulation in other situations. Our estimate is based upon the following key assumptions:

• changes in commodity prices follow a statistical pattern of distribution;

• price volatility remains stable; and

• price correlation relationships remain stable.

If a severe market shock occurred, the key assumptions underlying our VaR estimate could be exceeded and the potential loss could be greater than our estimate. We also use stress testing using extreme market movements which complements our VaR estimates. It is used to quantify potential unexpected losses from low probability market movements. Our VaR analysis incorporates our derivative positions, non-derivative transportation and storage contracts and assets, as well as commodity trading inventories.

Our quarter end, high, low, and average VaR amounts for the three months ended March 31 are as follows:

	Three Months Ended March 31
	2008	2007
Value-at-Risk
Quarter End	35	33
High	40	35
Low	21	24
Average	30	28

Foreign currency risk

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

• sales of crude oil, natural gas and certain chemicals products;

• capital spending and expenses for our oil and gas, Syncrude and chemicals operations;

• commodity derivative contracts used primarily by our energy marketing group; and

• short-term and long-term borrowings.

In our oil and gas operations, we manage our exposure to fluctuations between the US and Canadian dollar by matching our expected net cash flows and borrowings in the same currency. Net revenue from our foreign operations and our US-dollar borrowings are generally used to fund US-dollar capital expenditures and debt repayments. We maintain revolving Canadian and US-dollar borrowing facilities that can be used or repaid depending on expected net cash flows. We designate our US-dollar borrowings as a hedge against our US-dollar net investment in self-sustaining foreign operations. At March 31, 2008, we had US$4,413 million of long-term debt issued in US dollars and a one cent change in the US dollar to Canadian dollar exchange rate would increase or decrease our accumulated other comprehensive income by approximately $45 million, before income tax.

In our energy marketing group, the majority of the financial commodity contracts are denominated in US dollars. We enter into US-dollar forward contracts and swaps to manage this exposure.

We also have immaterial exposures to currencies other than the US dollar. A portion of our United Kingdom operating expenses, capital spending and future asset retirement obligations are denominated in British pounds and Euros. We do not have any material exposure to highly inflationary foreign currencies.

17

(b) Credit Risk

Credit risk affects both our trading and non-trading activities and is the risk of loss if counterparties do not fulfill their contractual obligations. The majority of our accounts receivable are with counterparties in the energy industry and are subject to normal industry credit risk. This concentration of risk within the energy industry is reduced because of our broad base of domestic and international counterparties. We assess the financial strength of our counterparties, including those involved in marketing and other commodity arrangements, and we limit the total exposure to individual counterparties. As well, a number of our contracts contain provisions that allow us to demand the posting of collateral in the event of a downgrade to a non-investment grade credit rating occurs. Credit risk, including credit concentrations, is routinely reported to our management, including the Risk Management Committee. We also use standard agreements that allow for the netting of exposures associated with a single counterparty. We believe this minimizes our overall credit risk. However, there can be no assurance that these processes will protect us against all losses from non-performance.

At March 31, 2008:

• over 97% of our credit exposures were investment grade; and

• only one counterparty individually made up more than 10% of our credit exposure. This counterparty was investment grade.

Our maximum counterparty credit exposure at the balance sheet date consists primarily of the carrying amounts of non-derivative financial assets such as accounts receivable, as well as the fair value of derivative financial assets. There are no significant amounts past due or impaired at the balance sheet date. Collateral received from customers at March 31, 2008 includes $17 million of cash and $581 million of letters of credit related to our trading activities and the cash received is included in our accounts payable and accrued liabilities.

(c) Liquidity Risk

Liquidity risk is the risk that we will not be able to meet our financial obligations as they fall due. We require liquidity specifically to fund capital requirements, satisfy financial obligations as they become due, and to engage in our energy marketing business. We generally rely on operating cash flows to provide liquidity and we also maintain significant undrawn committed credit facilities. At March 31, 2008, we had unsecured term credit facilities of US$3 billion available until 2012. At March 31, 2008, no amounts were drawn on these facilities, however, $296 million of the facilities were used to support outstanding letters of credit. We also had $666 million of undrawn, uncommitted, unsecured credit facilities, of which $44 million was supporting letters of credit at March 31, 2008.

The following table details the contractual maturities for our non-derivative financial liabilities, including both the principal and interest cash flows at March 31, 2008:

	Total	< 1 Year	1-3 Years	4-5 Years	> 5 Years
Long-Term Debt	4,660	125	218	–	4,317
Interest on Long-Term Debt 1	6,593	219	548	548	5,278
Total	11,253	344	766	548	9,595

¹ Excludes interest on term credit facilities of US$3 billion and Canexus LP term credit facilities of $350 million as the amounts drawn on the facilities fluctuate. As a result, we are unable to provide a reasonable estimate of the interest.

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

	Total	< 1 Year	1–3 Years	4–5 Years	> 5 Years
Trading Derivatives	768	543	206	19	–
Non-Trading Derivatives	89	38	51	–	–
Total	857	581	257	19	–

The commercial agreements our energy marketing group enters into often include financial assurance provisions that allow us and our counterparties to effectively manage credit risk. The agreements normally require collateral to be posted if an adverse credit-related event, such as a drop in credit ratings, occurs. Based on contracts in place and commodity prices at March 31, 2008, we could be required to post collateral of up to $1.7 billion if we were downgraded to non-investment grade. These obligations are reflected on our balance sheet. The posting of collateral merely secures the payment of such amounts.

At March 31, 2008, collateral posted to our counterparties includes $36 million of cash and $200 million of letters of credit related to our trading activities. Cash posted is included with our accounts receivable. Letters of credit issued cannot be drawn on unless there has been default, which would have to be proven to the bank in order for them to release the funds. Cash collateral is not normally applied to contract settlement. Once a contract has been settled, the collateral amounts are refunded. If there is a default, the cash is retained.

18

Our exchange-traded derivative contracts are also subject to margin requirements. We have margin deposits of $75 million (December 31, 2007 – $203 million), which have been included in restricted cash.

12. SHAREHOLDERS’ EQUITY

Dividends

Dividends per common share for the three months ended March 31, 2008 were $0.025 (2007 – $0.025). Dividends paid to holders of common shares have been designated as “eligible dividends” for Canadian tax purposes.

13.  EARNINGS PER COMMON SHARE

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

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

	Three Months                Ended March 31
(millions of shares)	2008	2007
Weighted-average number of common shares outstanding	528.9	526.0
Shares issuable pursuant to tandem options	22.5	28.4
Shares notionally purchased from proceeds of tandem options	(14.2)	(15.8)
Weighted-average number of diluted common shares outstanding	537.2	538.6

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

14. CASH FLOWS

(a) Charges and credits to income not involving cash

	Three Months              Ended March 31
	2008	2007
Depreciation, Depletion, Amortization and Impairment	364	334
Stock-Based Compensation	(59)	44
Future Income Taxes	77	35
Change in Fair Value of Crude Oil Put Options	-	16
Net Income Attributable to Non-Controlling Interests	1	3
Other	-	3
Total	383	435

19

(b) Changes in non-cash working capital

	Three Months             Ended March 31
	2008	2007
Accounts Receivable	(446)	75
Inventories and Supplies	(78)	65
Other Current Assets	(10)	(4)
Accounts Payable and Accrued Liabilities	683	(58)
Accrued Interest Payable	13	(18)
Total	162	60
Relating to:
Operating Activities	140	32
Investing Activities	22	28
Total	162	60

(c)
Other cash flow information

	Three Months           Ended March 31
	2008	2007
Interest Paid	66	101
Income Taxes Paid	85	57

Cash flow from other operating activities includes cash outflows related to geological and geophysical expenditures of $10 million for the three months ended March 31, 2008 (2007 – $10 million).

15. MARKETING AND OTHER INCOME

	Three Months            Ended March 31
	2008	2007
Marketing Revenue, Net	211	247
Change in Fair Value of Crude Oil Put Options	-	(16)
Interest	10	9
Foreign Exchange Gains (Losses)	5	(5)
Other	(4)	13
Total	222	248

16. COMMITMENTS, CONTINGENCIES AND GUARANTEES

As described in Note 15 to the Audited Consolidated Financial Statements included in our 2007 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.

20

17.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 2007 Annual Report on Form 10-K.

Three Months Ended March 31, 2008

						Energy		Corporate and
(Cdn$ millions)	Oil and Gas					Marketing	Syncrude	Chemicals	Other	Total
	Yemen	Canada	United States	United Kingdom	Other    Countries1
Net Sales	276	147	181	939	46	14	158	109	-	1,870
Marketing and Other	4	-	1	1	-	211	-	(7)	122	222
Total Revenues	280	147	182	940	46	225	158	102	12	2,092
Less: Expenses
Operating	45	42	24	57	3	9	62	67	-	309
Depreciation, Depletion, Amortization
and Impairment	34	47	74	170	4	3	12	10	10	364
Transportation and Other	2	5	1	-	-	173	5	19 3	-	205
General and Administrative 4	(2)	1	6	(1)	1	26	1	7	16	55
Exploration	-	4	6	7	155	-	-	-	-	32
Interest	-	-	-	-	-	-	-	3	24	27
Income (Loss)
before Income Taxes	201	48	71	707	23	14	78	(4)	(38)	1,100
Less: Provision for (Recovery
of) Income Taxes	70	14	25	359	3	1	22	-	(25)	469
Less: Non-Controlling
Interests	-	-	-	-	-	-	-	1	-	1
Net Income (Loss)	131	34	46	348	20	13	56	(5)	(13)	630
Identifiable Assets	341	5,8376	1,766	4,970	393	4,2717	1,216	476	391	19,661
Capital Expenditures
Development and Other	18	351	79	100	28	-	9	13	4	602
Exploration	5	86	67	16	10	-	-	-	-	184
	23	437	146	116	38	-	9	13	4	786
Property, Plant and Equipment
Cost	2,288	7,171	3,330	4,999	302	252	1,339	848	313	20,842
Less: Accumulated DD&A	2,068	1,637	1,898	1,085	84	65	214	474	178	7,703
Net Book Value	220	5,5346	1,432	3,914	218	187	1,125	374	135	13,139

¹     Includes results of operations from producing activities in Colombia.

²     Includes interest income of $10 million, foreign exchange gains of $5 million and other losses of $3 million.

³     Includes a severance accrual of $7 million in connection with North Vancouver technology conversion project.

⁴     Includes recovery of stock-based compensation expense of $41 million.

⁵     Includes exploration activities primarily in Nigeria, Norway and Colombia.

⁶     Includes costs of $4,003 million related to our Long Lake Project (Phase 1 and future phases).

⁷     Approximately 83% of Marketing’s identifiable assets are accounts receivable and inventories.

21

Three Months Ended March 31, 2007

						Energy			Corporate and
(Cdn$ millions)	Oil and Gas					Marketing	Syncrude	Chemicals	Other	Total
	Yemen	Canada	United States	United Kingdom	Other Countries 1
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)
before Income Taxes	139	(8)	24	156	(8)	(4)	54	11	(145)	219
Less: Provision for (Recovery
of) Income Taxes	48	(2)	8	75	(1)	(1)	17	3	(52)	95
Less: Non-Controlling
Interests	-	-	-	-	-	-	-	3	-	3
Net Income (Loss)	91	(6)	16	81	(7)	(3)	37	5	(93)	121
Identifiable Assets	521	4,279 5	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 5	1,491	4,306	175	181	1,120	361	140	12,183

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 costs of $2,847 million related to our Long Lake Project (Phase 1 and future phases).

⁶ Approximately 78% of Marketing’s identifiable assets are accounts receivable and inventories.

22

18.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:

(a)
Unaudited Consolidated Statement of Income – US GAAP

For the Three Months Ended March 31

(Cdn$ millions, except per share amounts)	2008	2007
Revenues and Other Income
Net Sales	1,870	1,140
Marketing and Other (i); (vii)	206	246
	2,076	1,386
Expenses
Operating (ii)	310	296
Depreciation, Depletion, Amortization and Impairment	364	334
Transportation and Other	205	246
General and Administrative (iii)	62	199
Exploration	32	49
Interest	27	48
	1,000	1,172
Income before Income Taxes	1,076	214
Provision for Income Taxes
Current	392	60
Deferred (i) – (vii)	66	33
	458	93
Net Income before Non-Controlling Interests	618	121
Net Income Attributable to Non-Controlling Interests	(1)	(3)
Net Income – US GAAP 1	617	118
Earnings Per Common Share ($/share)
Basic (Note 13)	1.17	0.23
Diluted (Note 13)	1.15	0.22

Note:

1	Reconciliation of Canadian and US GAAP Net Income
		Three Months       Ended March 31
	(Cdn$ millions)	2008	2007
	Net Income – Canadian GAAP	630	121
	Impact of US Principles, Net of Income Taxes:
	Ineffective Portion of Cash Flow Hedges (i)	-	(2)
	Pre-operating Costs (ii)	(1)	(3)
	Inventory Valuation (vii)	(7)	-
	Stock-based Compensation (iii)	(5)	2
	Net Income – US GAAP	617	118

23

(b) Unaudited Consolidated Balance Sheet – US GAAP  

	March 31	December 31
(Cdn$ millions, except share amounts)	2008	2007
Assets
Current Assets
Cash and Cash Equivalents	524	206
Restricted Cash	75	203
Accounts Receivable	4,041	3,502
Inventories and Supplies (vii)	695	615
Deferred Income Tax Asset	25	18
Other	84	71
Total Current Assets	5,444	4,615
Property, Plant and Equipment
Net of Accumulated Depreciation, Depletion, Amortization and
Impairment of $8,096 (December 31, 2007 – $7,588) (ii); (v)	13,089	12,449
Goodwill	337	326
Deferred Income Tax Assets	263	268
Deferred Charges and Other Assets	418	324
Total Assets	19,551	17,982
Liabilities and Shareholders’ Equity
Current Liabilities
Short-Term Borrowings	125	-
Accounts Payable and Accrued Liabilities (iii)	4,954	4,233
Accrued Interest Payable	67	54
Dividends Payable	13	13
Total Current Liabilities	5,159	4,300
Long-Term Debt	4,458	4,610
Deferred Income Tax Liabilities (i) – (vii)	2,344	2,230
Asset Retirement Obligations	814	792
Deferred Credits and Liabilities (iv)	600	534
Non-Controlling Interests	64	67
Shareholders’ Equity
Common Shares, no par value
Authorized:   Unlimited
Outstanding:   2008 – 529,439,432 shares
2007 – 528,304,813 shares	949	917
Contributed Surplus	3	3
Retained Earnings (i) – (vii)	5,480	4,876
Accumulated Other Comprehensive Loss (i); (iv)	(320)	(347)
Total Shareholders’ Equity	6,112	5,449
Commitments, Contingencies and Guarantees
Total Liabilities and Shareholders’ Equity	19,551	17,982

(c) Unaudited Consolidated Statement of Comprehensive Income – US GAAP

For the Three Months Ended March 31

(Cdn$ millions)	2008	2007
Net Income – US GAAP	617	118
Other Comprehensive Income, Net of Income Taxes:
Foreign Currency Translation Adjustment	(27)	(6)
Change in Mark to Market on Cash Flow Hedges (i)	-	(61)
Comprehensive Income	590	51

24

(d) Unaudited Consolidated Statement of Accumulated Other Comprehensive Income – US GAAP

	March 31	December 31
(Cdn$ millions)	2008	2007
Foreign Currency Translation Adjustment	(266)	(293)
Unamortized Defined Benefit Pension Costs (iv)	(54)	(54)
	(320)	(347)

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.

Future sale of gas inventory: At December 31, 2006, we included $25 million of gains on cash flow hedges in accounts receivable. Accumulated Other Comprehensive Income (AOCI) includes the effective portion of $23 million ($16 million, net of taxes) and $2 million ($2 million, net of taxes) of the ineffective portion in our US GAAP net income. Under Canadian GAAP, these gains were recognized in the first quarter of 2007.

At March 31, 2008, there were no cash flow 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:

• operating expenses include pre-operating costs of $1 million for the three months ended March 31, 2008 ($1 million, net of income taxes) (2007 – $6 million ($3 million, net of income taxes)); and

• property, plant and equipment is lower under US GAAP by $31 million (December 31, 2007 – $30 million).

iii. 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:

• general and administrative expense is higher by $7 million ($5 million, net of income taxes) for the three months ended March 31, 2008 (2007 – lower by $3 million ($2 million, net of income taxes)); and

• accounts payable and accrued liabilities are higher by $60 million as at March 31, 2008 (December 31, 2007 – $53 million).

iv. On December 31, 2006, we adopted FASB Statement 158 Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans (FAS 158). At March 31, 2008, the unfunded amount of our defined benefit pension plans was $75 million. This amount has been included in deferred credits and other liabilities and $54 million, net of income taxes has been included in AOCI.

v. 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.

vi. 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 March 31, 2008, the total amount of our unrecognized tax benefits was approximately $223 million, all of which, if recognized, would affect our effective tax rate. As at March 31, 2008, the total amount of interest and penalties in relation to uncertain tax positions recognized in deferred income tax liabilities in the US GAAP –Unaudited Consolidated Balance Sheet is approximately $10 million. We had no interest or penalties in the US GAAP – Unaudited Consolidated Statement of Income for the first quarter of 2008. Our income tax filings are subject to audit by taxation authorities and as at March 31, 2008 the following tax years remained subject to examination; (i) Canada – 1985 to date, (ii) United Kingdom – 2002 to date and (iii) United States – 2004 to date. We do not anticipate any material changes to the unrecognized tax benefits previously disclosed within the next twelve months.

25

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

• marketing and other income is lower by $16 million ($7 million, net of income taxes) for the three months ended March 31, 2008; and

• inventories are lower by $60 million as at March 31, 2008 (December 31, 2007 – $44 million).

Changes in Accounting Policies–US GAAP

During the quarter, we adopted FASB Statement 157 Fair Value Measurements which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The adoption of this statement did not have a material impact on our results of operations or financial position. The additional disclosures required by the statement are included in Note 10.

New Accounting Pronouncements–US GAAP

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 will have a material impact on our results of operations or financial position.

In December 2007, FASB issued Statement 141 (revised), Business Combinations. Statement 141 (revised) establishes principles and requirements of the acquisition method for business combinations and related disclosures. This statement is effective for fiscal years beginning on or after December 15, 2008. We do not expect the adoption of this statement will have a material impact on our results of operations or financial position.

In December 2007, FASB issued Statement 160, Non-controlling Interests In Consolidated Financial Statements, an amendment of ARB. No. 51. This statement clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This statement is effective for fiscal years beginning on or after December 15, 2008. We do not expect the adoption of this statement to have a material impact on our results of operations or financial position.

In March 2008, FASB issued Statement 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement 133. The statement requires qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of gains and losses on derivative contracts and details of credit-risk-related contingent features in their hedged positions. The statement also requires the disclosure of the location and amounts of derivative instruments in the financial statements. This statement is effective for fiscal years and interim periods beginning on or after November 15, 2008. We do not expect the adoption of this statement to have a material impact on our results of operations or financial position.

26

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 18 to the Unaudited Consolidated Financial Statements. The date of this discussion is April 28, 2008.

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 76 of our 2007 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)	2008	2007
Net Income	630	121
Earnings per Common Share, Basic ($/share)	1.19	0.23
Cash Flow from Operating Activities	1,168	448
Production, before Royalties (mboe/d)	267	238
Production, after Royalties (mboe/d)	222	191
Nexen’s Average Realized Oil and Gas Price (Cdn$/boe)	85.90	59.13
Capital Investment, including Acquisitions	786	811
Net Debt 1	4,059	4,939

Note:

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

 

Higher production, combined with strong commodity prices, contributed to record quarterly net income and cash flow from operating activities in excess of a billion dollars. We met or exceeded our production targets during the quarter in all areas with the exception of Syncrude and volumes were 2% higher from the prior quarter and 12% higher from the same period last year. Buzzard averaged 91,500 boe/d and facility performance consistently exceeds our original design expectations. Base declines in mature assets in Yemen and the Gulf of Mexico partially offset volume increases from Buzzard.

WTI averaged US$97.90 for the quarter, 68% higher than the first quarter of 2007. Strong reference crude oil prices allowed us to realize an average crude oil price for the quarter of $93.00/boe, 51% higher from the same period last year. Our cash netback per boe increased 67% from the first quarter of 2007 and reflects the high-margin production from Buzzard. Since the majority of our oil and gas sales are denominated in or referenced to the US dollar, the strengthening Canadian dollar mitigated the increase in benchmark commodity prices. Overall, the higher Canadian dollar reduced our quarterly cash flow from operating activities and net income by approximately $250 million and $135 million, respectively.

During the quarter, we reached two major milestones at Long Lake as bitumen production began to increase and we completed construction of the upgrader. We have 29 of 81 well-pairs converted to SAGD production and total bitumen production is averaging 6,200 bbls/d (3,100 bbls/d net to us). In the UK North Sea, our Ettrick development is progressing with production expected later this year.

These strong results generated cash flow in excess of our capital investment requirements and net debt decreased $345 million from the end of 2007. We recently doubled our quarterly dividend payable to shareholders to $0.05 per share.

27

CAPITAL INVESTMENT

Our strategy and capital programs are focused on growing long-term value for our shareholders responsibly. We are advancing our strategy as described below. In 2008, we are investing in:

• bringing Phase 1 of our Long Lake project on stream and advancing other phases;

• completing our Ettrick development in the UK North Sea;

• targeting a number of exploration prospects, primarily in the Gulf of Mexico and the North Sea; and

• creating value in our existing asset base.

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
Oil and Gas
Synthetic (mainly Long Lake)	242	66	2	-	310
United Kingdom	57	-	16	43	116
Yemen	-	-	5	18	23
United States	2	-	67	77	146
Canada	12	6	84	25	127
Other Countries	23	-	10	5	38
Syncrude	-	-	-	9	9
	336	72	184	177	769
Chemicals, Marketing, Corporate and Other	-	-	-	17	17
Total Capital	336	72	184	194	786
As a % of Total Capital	43%	9%	23%	25%	100%

MAJOR AND EARLY STAGE DEVELOPMENT PROJECTS

Synthetic

During the quarter, we reached two major milestones at Long Lake as bitumen production began to ramp up and we completed construction of the upgrader. Total costs and project timing remain on schedule.

We are injecting steam into the reservoir through all well pads and we started converting wells to SAGD production in late February. Currently 29 of 81 well pairs have been converted to SAGD. While early production rates are variable, total bitumen production is averaging 6,200 bbls/d with peak rates to date in excess of 7,500 bbls/d (3,750 bbls/d net to us). During the first quarter, we started up the first cogeneration unit which has reliably produced power in excess of 80 megawatts. Surplus power was sold into the Alberta power grid. We recently started up the second cogeneration unit and we expect it to be fully operational shortly. We expect to convert the remaining well pairs to SAGD by mid summer. This will allow bitumen production to grow to full rates over the next 6 to 12 months. The bitumen production capacity of the SAGD facilities is approximately 72,000 bbls/d (36,000 bbls/d net to us).

With construction of the upgrader complete, we have turned over all units and systems to operations. We estimate that commissioning is over 50% complete and we plan to start introducing hydrocarbons into key processing units in May. Last week, while introducing oxygen into a liquid oxygen tank, the tank roof was damaged. We are presently investigating the cause of the damage and implementing solutions to keep the upgrader start up process on track. Our start up schedule forecasts production of synthetic crude to ramp up to full rates over a 12 to 18 month period following initial upgrader start up. The upgrader is designed to produce approximately 60,000 bbls/d (30,000 bbls/d net to us) of premium synthetic crude.

This project only develops about 10% of our oil sands leases. We plan to increase synthetic crude oil production as we sequentially develop our lands in 60,000 bbls/d (30,000 bbls/d net to us) phases using technologies developed at Long Lake.

Work continues on Phase 2 and our goal is to sanction this phase by year end. However, ultimate timing depends on accumulating sufficient operating history from Phase 1 and receiving clarity on proposed regulatory changes such as climate change. Proposed federal climate change regulations indicate a move towards carbon capture and sequestration. With the addition of shift reactors to future phases, our unique process allows for the pre-combustion capture of greenhouse gas emissions for future sequestration.

United Kingdom – Ettrick

Our Ettrick development in the North Sea is progressing towards first oil in the second half of 2008. The development will utilize a leased floating production, storage and offloading vessel (FPSO) designed to handle 30,000 bbls/d of oil and 35 mmcf/d of gas. Construction of the FPSO is nearly complete and sea trials are expected to commence mid year.

28

We have also identified a number of exploration opportunities in the immediate area that could be future tie-backs to Ettrick. We recently spud one of these opportunities, Blackbird, and have plans to drill another one later this year. We operate both Ettrick and Blackbird with an 80% working interest in each. We plan to drill six exploration wells in total in the UK North Sea before year end.

Canada – Coalbed Methane (CBM)

In Canada, we continue to develop CBM from Mannville coals in the Fort Assiniboine area and well performance continues to meet expectations. The Government of Alberta recently provided clarification of the length adjustment to be used for calculation of the proposed royalties and we are reviewing our investment program in light of this announcement. Our production from this area averaged 34 mmcf/d for the quarter and we expect to exit the year around 46 mmcf/d as our existing wells dewater and production increases.

Offshore West Africa

During the quarter, we commenced development of the Usan field, offshore Nigeria. The field development plan includes a floating production, storage and offloading vessel with a storage capacity of two million barrels of oil. All major contracts for deep-water facilities have been awarded and contractors are mobilizing for detailed engineering and project execution. Our capital investment is expected to be within the range of US$1.6 to US$2.0 billion over the development period, with an estimated 2008 capital commitment of approximately US$300 million. The Usan field is expected to come on stream in early 2012 and will ramp up to a peak production rate of 180,000 barrels of oil per day (36,000 boe/d net to us).

The Usan field development is located in OML 138 and is covered by the original production sharing contract for OPL 222 issued in 1993, with the Nigerian National Petroleum Corporation as concessionaire. The contract conveys the right to develop and produce crude oil and continue with exploration activity. We are currently processing three-dimensional seismic here in anticipation of further exploratory drilling in the area. The Usan field was discovered in 2002 and is located approximately 100 kilometres offshore in water depths ranging from 750 to 850 meters. Nexen has a 20% interest in exploration and development along with Elf Petroleum Nigeria Limited (20% and Operator), Chevron Petroleum Nigeria Limited (30%) and Esso Exploration and Production Nigeria (Offshore East) Limited (30%).

United States – Gulf of Mexico

In the Gulf of Mexico, we sanctioned development of our Longhorn discovery during the quarter. Development will consist of three subsea wells tied-back approximately 20 miles to the non-operated Crystal facility. First production is expected in 2009 with a peak production rate of approximately 200 mmcf/d gross. We have a 25% non-operated working interest and Eni is the operator.

To date, we have not been able to find a rig with the capability of drilling a delineation well at Knotty Head. As a result, we plan to drill an appraisal well in mid 2009 when our first new deep-water drilling rig arrives. We have a 25% operated interest in the field.

NEW GROWTH EXPLORATION

Canada – Shale Gas

Over the past 18 months, we have accumulated a substantial land position of approximately 123,000 net acres in an emerging Devonian shale gas play in the Horn River Basin in northeast British Columbia which has the potential to become one of the most significant shale gas plays in North America. We have a 100% working interest in these lands. Our capital program over the past two winters has primarily focused on the Dilly Creek area in the Horn River Basin where we have approximately 85,000 net acres. This shale gas play has been compared to the Barnett Shale in Texas by other operators in the area as it displays similar rock properties and play characteristics. The average gross shale thickness on our Dilly Creek lands is approximately 175 meters which is almost 50% thicker than the Barnett.

During the 2006/2007 winter drilling season, we drilled two vertical wells on our acreage at Dilly Creek, recovered core data and conducted extensive wire-line logging which was analyzed last summer. This information confirmed the significant potential of this play. In our 2007/2008 winter program, we drilled one vertical and two horizontal wells at Dilly Creek. We fraced our three vertical wells to obtain data across the entire gross shale interval and we tested a variety of techniques to frac and complete one of the horizontal wells. We plan to frac and complete the second horizontal well next winter.

We fraced approximately 300 meters of the horizontal well and the well tested over 2 mmcf/d from its two frac segments. These test rates are consistent with rates reported by competitor wells in the area which average approximately 1 mmcf/d per frac segment. We expect typical future development wells on our acreage to consist of 6 to 12 frac segments over longer horizontal lengths. We have placed this horizontal well and one vertical well on long-term production tests and they are currently producing approximately 2.5 mmcf/d.

29

To further assess the potential of our lands, we are gearing up to conduct a summer drilling program consisting of two horizontal wells which will be fraced, completed and tied-in. We recently participated in the construction of an all-season road, providing us access to these well locations and approximately half of our Dilly Creek lands year round.

United States

In the Eastern Gulf of Mexico, where we have interests in discoveries at Vicksburg and Shiloh, we increased our acreage position on an unpromoted basis by acquiring working interests of 25% in 33 blocks recently awarded to Shell from the lease sale in late 2007. A number of additional exploration opportunities have been identified in the region and plans are in place to spud one of these opportunities, Fredricksburg, in the next few months. We have a 20% interest in Shiloh, a 25% interest in Vicksburg and a 20% interest in Fredricksburg, with Shell operating all three.

CORE ASSET DEVELOPMENT

During the quarter, we drilled a development well at Green Canyon 6 in the deep-water US Gulf of Mexico. The sidetrack was drilled to a depth of 8,400 feet where it encountered hydrocarbons. Completion operations commenced in March and we expect production from this well in the second quarter of 2008.

In the UK North Sea, work continues on our Buzzard enhancement project where engineering design and material procurement progressed on the fourth platform. The additional platform has production sweetening facilities which will be able to handle higher levels of hydrogen sulphide previously identified in the reservoir. We expect that existing equipment and processes on the Buzzard platform can maintain current deliverability until the additional equipment is commissioned in 2010.

30

FINANCIAL RESULTS

Change in Net Income

(Cdn$ millions)	2008 vs. 2007
Net Income at March 31, 2007	121
Favourable (unfavourable) variances:
Production Volumes, After Royalties
Crude Oil	173
Natural Gas	19
Change in Crude Oil Inventory	15
Total Volume Variance	207
Realized Commodity Prices
Crude Oil	509
Natural Gas	13
Total Price Variance	522
Oil and Gas Operating Expense
Conventional	(7)
Syncrude	(15)
Total Operating Expense Variance	(22)
Depreciation, Depletion, Amortization and Impairment
Conventional	(29)
Syncrude	1
Other	(2)
Total Depreciation, Depletion, Amortization and Impairment Variance	(30)
Exploration Expense	17
Energy Marketing Contribution	13
Chemicals Contribution	(18)
General and Administrative Expense	147
Interest Expense	21
Current Income Taxes	(332)
Future Income Taxes	(42)
Other
Decrease in Fair Value of Crude Oil Put Options	16
Other	10
Net Income at March 31, 2008	630

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

31

OIL & GAS AND SYNCRUDE

Production

	Three Months Ended March 31
	2008		2007
	Before	After	Before	After
	Royalties 1	Royalties	Royalties 1	Royalties
Crude Oil and NGLs (mbbls/d)
Yemen	62.2	31.8	77.1	45.0
Canada	16.9	12.9	17.8	14.2
United States	13.7	12.0	21.6	19.3
United Kingdom	106.0	106.0	55.6	55.6
Other Countries	6.0	5.5	5.8	5.4
Syncrude (mbbls/d) 2	19.3	17.0	21.4	18.9
	224.1	185.2	199.3	158.4
Natural Gas (mmcf/d)
Canada	127	107	118	95
United States	112	95	101	86
United Kingdom	21	21	14	14
	260	223	233	195
Total Production (mboe/d)	267	222	238	191

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 $207 million

Production after royalties increased 16% from the first quarter of 2007 and 4% from the prior quarter. The increase over last year was primarily the result of higher rates at Buzzard in the North Sea. The higher volumes were partially offset by natural declines in Yemen and the Gulf of Mexico and temporary production shortfalls at Syncrude. Production before royalties was 2% higher than the prior quarter and 12% higher than the first quarter of 2007.

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

	Before	After
(mboe/d)	Royalties	Royalties
Production, fourth quarter 2007	262	214
Production changes:
United Kingdom	13	13
Yemen	(4)	(2)
Syncrude	(3)	(2)
Other	(1)	(1)
Production, first quarter 2008	267	222

We expect our 2008 production to range between 260,000 and 280,000 boe/d before royalties (220,000 and 240,000 boe/d after royalties). Production is expected to increase later this year with new volumes from the Ettrick development in the UK North Sea and as bitumen production continues to ramp up at Long Lake. Production of premium synthetic crude oil from the Long Lake upgrader is expected upon start up of the facilities this summer. Production volumes discussed in this section represent before-royalties volumes, net to our working interest.

UNITED KINGDOM

Buzzard production for the quarter averaged 91,500 boe/d, an increase of 150% from the first quarter of 2007 when operations first came on stream. With Buzzard production regularly exceeding our original design expectations, we continue to pursue debottlenecking opportunities to increase processing capacity. We expect Buzzard volumes in the second and third quarters to be lower due to reduced platform uptime as a result of scheduled maintenance activities. We have commenced work on a fourth platform at Buzzard which will contain production sweetening facilities designed to handle higher levels of hydrogen sulphide previously identified in the reservoir. The projected cost of the new platform is between US$350 million and US$400 million, net to us.

Natural declines and unplanned maintenance at Scott/Telford contributed to a 12% and 25% decrease in production as compared to the previous quarter and the first quarter of 2007, respectively. In addition, we are performing flow trials on one

32

of our Telford wells which required us to temporarily shut in a producing well. Our non-operated fields at Duart and Farragon contributed 4,300 boe/d to our first quarter volumes.

YEMEN

Production from the Masila field decreased 6% from the fourth quarter and 18% from the first quarter of 2007, consistent with expectations. Production declines at Masila reflect the maturity of the field and the impact of drilling fewer development wells. We are focusing our capital spending on maximizing reserve recoveries and economic returns from existing wells. In the first quarter of 2008, we drilled three development wells and one sidetrack well. We expect to drill a further six development wells this year. Production declines are expected to continue as we maximize recovery of the remaining reserves on the block.

Block 51 production decreased 24% from the first quarter of 2007 and 8% from the prior quarter, due to relatively high natural decline rates and fewer development wells. Our 2008 capital investment program includes further development of the BAK A field including five development wells and one exploration well.

We expect Yemen production will average between 50,000 and 55,000 boe/d in 2008.

CANADA

Production in Canada was flat when compared with both the previous quarter and the first quarter of 2007. Long Lake SAGD production is ramping up as we convert wells to SAGD production from steam circulation. 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. The increase in natural gas production has been largely offset by a decrease in heavy oil volumes. Investment in our heavy oil winter drilling program partially offset natural declines in the field.

Production volumes are expected to increase in the remainder of 2008 from additional CBM natural gas and bitumen production growth at Long Lake.

UNITED STATES

Gulf of Mexico production decreased 16% from the same period in 2007, while remaining flat relative to the prior quarter. Production from the Aspen wells decreased in 2007 reflecting natural declines. In 2008, additional water handling facilities were installed on the host platform during the quarter, increasing Aspen production by 2,600 boe/d over the previous quarter to average 6,900 boe/d this quarter. Natural declines and ongoing maintenance at Gunnison decreased production by 3,300 boe/d relative to the same period last year.

These production decreases were partially offset by increases at Wrigley and from three properties in the Garden Banks and Green Canyon areas. Wrigley came on stream in the second quarter of 2007 and contributed 2,900 boe/d to our volumes this quarter. The three properties in the Garden Banks and Green Canyon areas were acquired mid 2007 and produced 2,000 boe/d during the quarter.

On the shelf, we completed several successful workovers and recompletions which enhanced well performance. This activity offset natural declines elsewhere. We are minimizing the amount of capital invested in our mature assets on the shelf.

OTHER COUNTRIES

Production from the Guando field in Colombia averaged 6,000 boe/d during the quarter. We began an infill drilling program in 2007 and virtually all wells were on stream by early 2008. We expect production from Colombia to average between 6,000 and 7,000 boe/d in 2008. Under the terms of our license with the Colombian government, our interest in the Guando field will decrease by half to 10% once the field has produced 60 million barrels, likely in 2009.

SYNCRUDE

Syncrude production decreased 15% from the prior quarter and 10% from the same period last year. A combination of downtime due to maintenance on one of the cokers and extreme winter conditions at the end of January contributed to lower production rates. Additionally, our upgrader production was reduced due to a shortage of high-quality ore and low bitumen inventories. Planned coker turnarounds at Syncrude will keep production volumes at similar rates for the next two quarters.

33

Commodity Prices

	Three Months Ended March 31
	2008	2007
Crude Oil and NGLs
West Texas Intermediate (WTI) (US$/bbl)	97.90	58.16
Differentials 1 (US$/bbl)
Heavy Oil	21.85	16.57
Mars	6.93	5.09
Masila	2.32	2.01
Dated Brent	1.00	0.41
Producing Assets (Cdn$/bbl)
Yemen	96.57	63.02
Canada	65.94	41.71
United States	94.07	58.49
United Kingdom	93.38	64.33
Other Countries	91.85	59.81
Syncrude	101.70	70.03
Corporate Average (Cdn$/bbl)	93.00	61.69
Natural Gas
New York Mercantile Exchange (NYMEX) (US$/mmbtu)	8.75	7.18
AECO (Cdn$/GJ)	6.76	7.07
Producing Assets (Cdn$/mcf)
Canada	7.57	7.16
United States	9.03	8.58
United Kingdom	6.82	3.87
Corporate Average (Cdn$/mcf)	7.97	7.58
Nexen’s Average Realized Oil and Gas Price (Cdn$/boe)	85.90	59.13
Average Foreign Exchange Rate
Canadian to US Dollar (US$)	0.9959	0.8573

Note:

¹ These differentials are a discount to WTI.

Higher realized commodity prices increased quarterly net income by $522 million

Commodity prices increased significantly throughout 2007 and continued to strengthen during the first few months of 2008. WTI averaged US$97.90/bbl in the quarter, an 8% increase over the prior quarter and 68% higher than the first quarter of last year. These strong benchmark commodity prices allowed us to realize a record price of $93.00/bbl for our crude oil sales in the quarter, 51% higher than the same period last year. However, the increase in WTI and other benchmark crude prices was reduced as the stronger Canadian dollar relative to the US dollar partially offset the full effect of the increase.

Our quarterly realized gas price increased 5% from a year ago to average $7.97/mcf. NYMEX increased 22% in the same period averaging US$8.75/mmbtu. AECO natural gas prices fell 4% from last year, which impacted our realized gas price as approximately half of our gas production comes from western Canada.

CRUDE OIL REFERENCE PRICES

Crude oil prices were volatile during the first quarter with WTI ranging from a low of US$86.11/bbl to a record high in March of US$111.80/bbl, before settling to US$101.58/bbl at quarter end. The high prices were driven more by the weakening US dollar and global political tensions than by traditional supply and demand fundamentals.

The US dollar continued to weaken during the quarter and fell to an all-time low against the Euro as the financial markets reacted to the threat of a US recession and the global credit liquidity crisis. Investors re-directed their investments into the commodity markets to hedge against the weak dollar and inflation, which contributed to the volatility in oil prices.

Geopolitical risk continued to place upward pressure on crude oil prices. Supply outages in Nigeria, Africa’s largest oil producer, reduced production. In the Middle East, escalating conflict between Turkey and Kurdish rebels in Northern Iraq,

34

added to geopolitical instability. In Southern Iraq, military action led to the bombing of a major export pipeline in Basra. The market reacted strongly to the disrupted supply although the pipeline was quickly repaired.

CRUDE OIL DIFFERENTIALS

In Canada, heavy oil differentials averaged US$21.85/bbl (22% of WTI) for the quarter, compared to US$16.57/bbl (28% of WTI) for the first quarter of 2007. The differentials were wider in the first two months of the quarter as outages at BP’s Whiting refinery reduced the demand for Canadian crude. The refinery came back on line in March and the differential narrowed significantly from US$24.06/bbl in February to US$16.75/bbl in March. Production disruption at Cold Lake, which decreased heavy supply by 25%, and the approach of the summer asphalt season also contributed to the narrower differentials in March.

The Brent/WTI differential widened with Brent trading at a discount to WTI of US$1.00/bbl compared to US$0.41/bbl for the first quarter of 2007. Historically, Brent traded at a discount to WTI because of the transportation cost to supply Brent crude to the US market. In 2007, Brent traded at a premium to WTI for part of the year as inventories were high, thereby putting downward pressure on WTI. Crude oil inventories at Cushing remain low as backwardation of the WTI forward curve has not encouraged inventory building.

In the US Gulf Coast, the Mars differential widened during the quarter, averaging US$6.93/bbl (7% of WTI) compared to US$5.09/bbl (9% of WTI) in the first quarter of 2007. Higher production offshore in the Gulf increased supply to the US, widening the differential. Financial investment in WTI contracts also created support for WTI relative to other crude qualities, including Mars. Overall, the differential is returning to more normal historic levels.

The Yemen Masila differential widened slightly relative to WTI, with Masila trading at a discount of US$2.32/bbl compared to US$2.01/bbl in the first quarter of 2007. The Masila price remains high reflecting strong demand from China, India and Thailand. Masila sales are typically priced based on Brent pricing and the wider differential to WTI reflects the WTI/Brent differential.

NATURAL GAS REFERENCE PRICES

NYMEX natural gas prices averaged US$8.75/mmbtu for the quarter, compared to US$7.18/mmbtu for the first quarter of 2007. The higher prices were driven by lower storage levels, cooler than normal temperatures in US consuming regions and reduced supply from LNG imports and western Canada. Storage levels at the end of the quarter were at their lowest level in the last three years. Strong demand for LNG in Europe and Asia resulted in reduced supply to the North American market.

Operating Costs

	Three Months Ended March 31
(Cdn$/boe)	2008		2007
	Before	After	Before	After
	Royalties 1	Royalties	Royalties 1	Royalties
Conventional Oil and Gas	7.49	9.06	8.24	10.49
Synthetic Crude Oil
Syncrude	35.16	39.79	24.40	27.66
Average Oil and Gas	9.46	11.39	9.67	12.18

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 $22 million

Changes in our production mix during the quarter, primarily as a result of increases at Buzzard, reduced our corporate average unit cost by $0.36/boe. The strengthening Canadian dollar also had an impact on our average cost per barrel. US-dollar denominated operating costs were lower when translated to Canadian dollars, reducing our corporate quarterly average by $0.83/boe.

In the UK North Sea, Buzzard operating costs reduced our corporate average by $0.90/boe compared to the same period last year. A combination of higher production rates and fixed operating costs on the Buzzard platform reduced our average unit operating cost. Elsewhere in the UK North Sea, quarterly operating costs on the Scott and Telford fields were consistent with the first quarter of 2007, however lower production increased our corporate average by $0.23/boe.

In Yemen, a combination of lower production and higher service rig activity increased per unit operating costs. Our corporate unit average cost increased by $0.34/boe and $0.36/boe for Masila and Block 51, respectively. On the shelf in the Gulf of Mexico, reduced downtime and fewer expenses for maintenance activity lowered our corporate average by

35

$0.15/boe. In the deep water of the Gulf, lower production and higher operating costs due to workovers and other maintenance increased our corporate average by $0.13/boe.

In Canada, operating costs increased our corporate average by $0.14/boe. Our heavy oil properties have higher per unit operating costs as many of our costs are fixed in nature and production is declining. Additional surface maintenance costs have been partially offset by lower downhole maintenance. CBM operating costs also increased as we brought additional wells on stream with high initial operating costs. We expect operating costs will decrease over time as the wells de-water and gas production increases.

Syncrude operating costs were $15 million higher than the first quarter of 2007. This increase was the result of purchasing bitumen for upgrading and unscheduled maintenance costs. The higher operating costs and lower production rates, increased our corporate average by $0.77/boe during the quarter.

Depreciation, Depletion, Amortization and Impairment (DD&A)

	Three Months Ended March 31
(Cdn$/boe)	2008		2007
	Before	After	Before	After
	Royalties 1	Royalties	Royalties 1	Royalties
Conventional Oil and Gas	14.40	17.42	15.20	19.35
Synthetic Crude Oil
Syncrude	6.87	7.77	6.65	7.54
Average Oil and Gas	13.86	16.69	14.45	18.19

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 conventional and Syncrude DD&A reduced net income for the quarter by $28 million

The impact of Buzzard production at full rates in the North Sea has changed our production mix. Depletion costs relating to the Buzzard field are higher than our corporate average as they include our acquisition cost and the costs to complete the project. This change in production mix increased our average unit DD&A by $0.81/boe. In 2007, we increased our estimates of proved reserves at Buzzard, thereby reducing the depletion rate. This reduced our corporate average unit DD&A by $0.75/boe. Buzzard unit depletion is expected to decrease further in the next few years as we anticipate booking additional proved reserves reflecting production experience and further development drilling. DD&A on our other North Sea assets increased our corporate average by $0.45/boe.

In Yemen, production declines, combined with lower capital expenditures from drilling fewer wells, decreased our corporate unit depletion rate by $0.26/boe as compared to the first quarter of 2007. Despite higher realized oil prices, lower production volumes resulted in a slower recovery of capital costs paid on behalf of the government.

Depletion of our Canadian assets increased our corporate average by $0.21/boe. This reflects capital spending on new wells and facilities, and the timing of reserve bookings for our CBM projects in central Alberta. We expect our depletion rate for our CBM projects will decline as wells de-water and we are able to recognize additional proved reserves. Our depletion rate in the Gulf of Mexico increased our corporate average rate by $0.69/boe as compared to 2007 from lower reserve estimates at the end of 2007.

The strengthening Canadian dollar reduced our DD&A expense relative to the first quarter of 2007 as depletion of our international and US assets is denominated in US dollars. This decreased our corporate average by $1.81/boe.

36

Exploration Expense

	Three Months           Ended March 31
(Cdn$ millions)	2008	2007
Seismic	10	10
Unsuccessful Exploration Drilling	-	21
Other	22	18
Total Exploration Expense	32	49
New Growth Exploration	184	108
Geological and Geophysical Costs	10	10
Total Exploration Expenditures	194	118
Exploration Expense as a % of Exploration Expenditures	16%	42%

Lower exploration expense increased net income for the quarter by $17 million

Exploration activity during the first quarter was primarily focused on acquiring additional acreage and seismic data in the Gulf of Mexico, Norway and Canada. We are continuing to assess our opportunities in new growth areas and develop opportunities for our exploration drilling program.

Early in the quarter, we drilled two successful exploration wells in the Gulf of Mexico at Green Canyon 448 and Mississippi Canyon 72 and we are currently reviewing development options for these assets. We also continued to appraise the results from our emerging shale gas play in northeast British Columbia during the quarter.

Late in the quarter, we began drilling two exploration wells in the Gulf of Mexico and Yemen. In the Gulf of Mexico, we re-entered our Cote De Mer exploration well and resumed drilling operations at approximately 13,000 feet. This well is expected to reach a depth of approximately 21,000 feet with preliminary results expected in the third quarter. In Yemen, we are currently drilling an exploration well on Block 51.

37

ENERGY MARKETING

	Three Months Ended March 31
(Cdn$ millions, except as indicated)	2008	2007
Physical Sales 1	14,227	10,898
Physical Purchases 1	(13,738)	(10,624)
Net Financial Transactions 1	(287)	(27)
Increase in Fair Market Value of Inventory	9	–
Net Revenue	211	247
Transportation Expense	(173)	(220)
Other	5	3
Net Marketing Revenue	43	30
Contribution to Net Marketing Revenue by Region:
North America	45	21
Asia	4	–
Europe	(6)	9
Net Marketing Revenue	43	30
Depreciation, Depletion, Amortization and Impairment	(3)	(4)
General and Administrative	(26)	(30)
Marketing Contribution to Income before Income Taxes	14	(4)
North America Natural Gas
Physical Sales Volumes 2 (bcf/d)	6.6	5.4
Transportation Capacity (bcf/d)	1.9	4.0
Storage Capacity (bcf)	42.6	48.0
Financial Volumes 3 (bcf/d)	26.4	24.9
Crude Oil
Physical Sales Volumes 2 (mbbls/d)	649	672
Storage Capacity (mbbls)	3,119	1,784
Financial Volumes 3 (mbbls/d)	1,412	2,340
Power
Physical Sales Volumes 2 (MW/d)	5,157	4,548
Generation Capacity (MW/hr)	132	87
Asia
Physical Sales Volumes 2 (mbbls/d)	206	179
Financial Volumes 3 (mbbls/d)	268	266
Europe
Financial Volumes 3 (mbbls/d)	2,106	285
Value-at-Risk
Quarter-end	35	33
High	40	35
Low	21	24
Average	30	28

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. Physical volumes represent amounts delivered during the quarter.
3	Financial volumes represent amounts traded during the quarter.

Higher contribution from Energy Marketing increased net income by $13 million

Energy Marketing’s quarterly contribution was higher than a year ago with a stronger contribution from North America, offset in part by losses in Europe. Through optimizing storage positions and by taking advantage of volatility in commodity price differentials, North America crude oil delivered record quarterly results of $45 million. With the volatility in differentials we were able to move product between markets, blend different crude qualities as well as buy and sell at

38

opportune times to generate profits. We also increased our crude oil physical storage position compared to last year to take advantage of location and quality differentials.

The gains recognized by crude oil were offset in part by financial losses on basis positions in North America natural gas. As part of our gas marketing strategy, we hold physical transportation and storage 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). We use derivatives, which are carried at fair value, to hedge these physical transportation positions. While the value of our North America transportation assets increased, we are unable to recognize these value gains in our reported results until the transportation assets are used. However, the change in fair value of the derivatives hedging these physical positions is included in our net income for the quarter.

Our European team incurred losses during the first quarter compared to gains in the first quarter of 2007. Losses were recognized primarily on our UK gas and spark spread strategies.

At December 31, 2007, we adopted a new inventory standard under Canadian GAAP which requires us to carry our commodity trading inventories at fair value. As a result, increases in commodity prices enabled us to recognize $9 million in fair value gains during the quarter.

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

Composition of Net Marketing Revenue

	Three Months Ended March 31
(Cdn$ millions)	2008	2007
Trading Activities	37	24
Other Activities	6	6
Net Marketing Revenue	43	30

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 fair value accounting and record the change in fair value in marketing and other income. The fair value of these instruments is included with amounts receivable or payable and they are classified as long-term or short-term based on their anticipated settlement date.

Fair Value of Derivative Contracts

Wherever possible, the estimated fair value of our derivative instruments is based on quoted market prices and, if not available, on estimates from third-party brokers. We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk. Where we have offsetting positions, we utilize a mid-market pricing convention as a basis for establishing fair value and adjust our pricing to the highest price when we have a net open sell and the lowest price when we have a net open buy. We incorporate the credit risk associated with counterparty default into our estimates of fair value. Inputs to fair valuations may be readily observable, market-corroborated, or generally unobservable. We utilize valuation techniques that maximize the use of observable inputs wherever possible and minimize the use of unobservable inputs. To value longer-term transactions and transactions in less active markets for which pricing information is not generally available, unobservable inputs may be used.

We classify our derivatives according to the following hierarchy based on the amount of observable inputs used to value the instruments.

• Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and we use information from markets such as the New York Mercantile Exchange and the International Petroleum Exchange.

• Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value, volatility factors, and broker quotations, which can be observed or corroborated in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter

39

physical forwards and options. We obtain information from sources such as the Natural Gas Exchange, independent price publications and over-the-counter broker quotes.

• Level 3 – Valuations in this level are based on inputs which are less observable, unavailable or where the observable data does not support the majority of the instrument’s fair value. Level 3 instruments include longer-term transactions, transactions in less active markets or transactions at locations for which pricing information is not available. In these instances, internally developed methodologies are used to determine fair value which primarily includes extrapolation of observable future prices to similar locations, similar instruments or later time periods.

At March 31, 2008, the fair value of our derivative contracts in our energy marketing trading activities totalled $121 million. Below is a breakdown of this fair value by valuation method and contract maturity.

(Cdn$ millions)	Maturity
	< 1 year	1-3 years	4-5 years	> 5 years	Total
Level 1 – Actively Quoted Markets	93	73	(18)	–	148
Level 2 – Based on Other Observable Pricing Inputs	(35)	32	10	–	7
Level 3 – Based on Unobservable Pricing Inputs	(7)	(27)	–	–	(34)
Total	51	78	(8)	–	121

Changes in Fair Value of Derivative Contracts

(Cdn$ millions)	Total
Fair Value at December 31, 2007	6
Change in Fair Value of Contracts	31
Net Losses (Gains) on Contracts Closed	96
Changes in Valuation Techniques and Assumptions 1	(12)
Fair Value at March 31, 2008	121

Note:

¹ Our valuation methodology has been applied consistently in each period, with the exception of two portfolio level reserves that were included this period to account for a) credit risk associated with counterparty default and b) liquidity risk in our portfolio.

 

The fair values of our derivative contracts will be realized over time as the related contracts settle. Until then, the value of certain contracts will vary with forward commodity prices and price differentials. The average term of our derivative contracts is approximately 1.4 years. Those maturing beyond one year primarily relate to North American natural gas positions.

Other Activities

We enter into fee for service contracts related to transportation and storage of third-party oil and gas. In addition, we earn income from our power generation facilities at Balzac and Soderglen. We earned $6 million from these activities in the first quarter (2007 – $6 million).

CHEMICALS

Lower Chemicals contribution decreased net income by $18 million

North American sodium chlorate sales volumes increased 5% from a year ago, while chlor-alkali sales volumes were consistent. The increase in sales volumes was partially offset by lower chlor-alkali prices compared to the first quarter of 2007. Our operations in Brazil remain strong as a result of continued demand from Aracruz Cellulose, our primary customer in Brazil. Higher chlor-alkali sales volumes and prices; however, were offset by a decrease in chlorate prices in Brazil.

During the quarter, we successfully completed the expansion of our plant at Brandon, increasing capacity by 12%. Chemicals net income includes foreign exchange losses of $6 million on Canexus US-dollar denominated debt. Canexus also accrued severance costs of $7 million during the quarter relating to a new technology conversion project currently underway in the North Vancouver plant, which will result in staff reductions following completion in 2010.

40

CORPORATE EXPENSES

General and Administrative (G&A)

	Three Months Ended March 31
(Cdn$ millions)	2008	2007
General and Administrative Expense before Stock-Based Compensation	96	86
Stock-Based Compensation 1	(41)	116
Total General and Administrative Expense	55	202

Note:

¹ Includes the tandem option plan, stock options for our US-based employees and stock appreciation rights.

Lower G&A costs increased quarterly net income by $147 million

Changes in our share price create volatility in our net income as we account for stock-based compensation using the intrinsic-value method. During the quarter, a 5% decrease in our share price since the end of 2007 created a recovery of stock-based compensation expense of $41 million. This decrease compared to a 10% increase in our share price in the first quarter of 2007. Cash expense related to our stock-based compensation programs was $18 million during the quarter as compared to $72 million in the first quarter of 2007. Other G&A expense increased as we incurred additional employee costs from expanding our oil and gas operations internationally.

Interest and Financing Costs

	Three Months Ended March 31
(Cdn$ millions)	2008	2007
Interest	80	86
Less: Capitalized Interest	(53)	(38)
Net Interest Expense	27	48

Lower interest expense increased net income by $21 million

Our financing costs decreased $6 million from the first quarter of 2007 as cash generated from operations was used to reduce borrowings on our debt facilities. Capitalized interest on our Long Lake development project increased $13 million from the same period in 2007 and we have capitalized interest on our Ettrick project in the North Sea. Both projects are expected to be completed later this year, at which time our net interest expense should increase.

Income Taxes

	Three Months Ended March 31
(Cdn$ millions)	2008	2007
Current	392	60
Future	77	35
Total Provision for Income Taxes	469	95
Effective Tax Rate (%)	43%	43%

Higher taxes decreased net income by $374 million, while the effective tax rate remained unchanged at 43%

While our effective tax rate remains unchanged from the first quarter of 2007, the total provision for income taxes has increased $374 million as a result of higher earnings. Strong Buzzard production, combined with high commodity prices, created a provision for taxes of $359 million in the UK as compared to $75 million for the same period last year. Our income tax provision also includes current taxes in Yemen, the United States and Colombia.

41

Other

	Three Months Ended March 31
(Cdn$ millions)	2008	2007
Decrease in Fair Value of Crude Oil Put Options	–	(16)

During the first quarter of 2008, we purchased put options on 70,000 bbls/d of our 2009 crude oil production. These options establish a Dated Brent floor price of US$60/bbl on these volumes, are settled annually and provide a base level of price protection without limiting our upside to higher prices. The put options were purchased for $14 million and are carried at fair value. At March 31, 2008, the options had a fair value of $14 million. In the first quarter of 2007, we recorded a loss of $16 million on crude oil put options purchased in the second quarter of 2006 for our 2007 production.

42

LIQUIDITY

Capital Structure

	March 31	December 31
(Cdn$ millions)	2008	2007
Net Debt 1
Bank Debt	218	413
Public Senior Notes	3,907	3,758
Senior Debt	4,125	4,171
Subordinated Debt	458	439
Total Debt	4,583	4,610
Less: Cash and Cash Equivalents	(524)	(206)
Total Net Debt	4,059	4,404
Shareholders’ Equity 2	6,286	5,610

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, 2008, there were 529,439,432 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:

(Cdn$ millions)
Capital Investment	786
Cash Flow from Operating Activities	(1,168)
Excess of Cash Flow over Capital Investment	(382)
Dividends on Common Shares	13
Issue of Common Shares	(26)
Foreign Exchange Translation of US-dollar Denominated Debt and Cash	160
Other	(110)
Decrease in Net Debt	(345)

Change in Working Capital

	March 31	December 31	Increase/
(Cdn$ millions)	2008	2007	(Decrease)
Cash and Cash Equivalents	524	206	318
Restricted Cash	75	203	(128)
Accounts Receivable	4,041	3,502	539
Inventories and Supplies	755	659	96
Future Income Tax Assets	25	18	7
Accounts Payable and Accrued Liabilities	(4,894)	(4,180)	(714)
Current Portion of Long-Term Debt	(125)	-	(125)
Other	4	4	-
Net Working Capital	405	412	(7)

Generally, our receivables and payables are higher as a result of record commodity prices. The higher commodity prices at the end of the first quarter resulted in a $500 million increase in our crude oil and marketing receivables. Natural gas inventory held by our marketing group was higher than year end despite a reduction in storage volumes, as natural gas prices increased significantly in the first quarter. Additionally, strong Buzzard production, combined with higher commodity prices resulted in a higher current tax provision at the end of the quarter. These increases were partially offset by reducing the accruals for our stock-based compensation obligations as a result of a lower share price and exercises throughout 2007.

During the quarter, the Canadian dollar weakened slightly relative to the end of 2007. This impacted our US-dollar denominated working capital by increasing our accounts receivable, inventory and accounts payable approximately $90 million, $10 million and $80 million, respectively.

43

Outlook for Remainder of 2008

We expect our 2008 full year production will average between 260,000 and 280,000 boe/d before royalties. We expect to generate over $3 billion in cash flow (before remediation and geological and geophysical expenditures) after cash taxes of approximately $1 billion in 2008, assuming the following for the remainder of the year:

WTI (US$/bbl)	70.00 1
NYMEX natural gas (US$/mmbtu)	6.75 2
Oil & Gas and Syncrude Operating Costs (Cdn$/boe)	10.00
US to Canadian dollar exchange rate	0.97

Notes:

1	The WTI forward commodity price for the remainder of 2008 at April 28, 2008 is US$116.39/bbl.
2	The NYMEX forward commodity price for the remainder of 2008 at April 28, 2008 is US$11.58/mmbtu.

The majority of our oil and gas production is sold under short-term contracts, exposing us to short-term price movements. A US$1/bbl change in WTI above US$50 increases or decreases our 2008 cash flow by approximately $42 million ($33 million for the remainder of the year). Our exposure to a $0.01 change in the US to Canadian dollar exchange rate increases or decreases our 2008 cash flow by approximately $45 million ($30 million for the remainder of the year).

To date, we have incurred almost a third of our planned 2008 capital investment program, which is consistent with our plans. Our 2008 capital investment program is focused on completing the commissioning of the Long Lake upgrader and advancing future phases of Long Lake, bringing our Ettrick development in the North Sea on stream and investing in exploration opportunities in our growth areas.

We generally rely on operating cash flow to fund capital requirements and provide liquidity. Given the long cycle-time of some of our development projects and volatile commodity prices, it is not unusual in any year for capital expenditures to exceed our cash flow. Accordingly, we maintain significant undrawn committed credit facilities. At March 31, 2008, we had undrawn, unsecured term credit facilities of US$3 billion in place that are available until 2012, of which $296 million was used to support outstanding letters of credit. We also had approximately $666 million of undrawn, uncommitted, unsecured credit facilities, of which $44 million was used to support outstanding letters of credit. In June 2008, we expect to repay $125 million of medium term notes that become due using our cash on hand.

In the first quarter, we declared common share dividends of $0.025 per share. In April 2008, we declared a common share dividend of $0.05 per share, payable July 1, 2008.

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 2007 Annual Report on Form 10-K. During the quarter, our international oil and gas operations entered into additional work commitments of $205 million related to a drilling rig and seismic purchases in the North Sea. In addition, the development of the Usan field, offshore Nigeria received all the necessary approvals to proceed during the quarter. As a result, we entered into additional work commitments related to the development of the Usan field totaling $800 million. 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 2007 Annual Report on Form 10-K. There have been no significant developments since year end.

NEW ACCOUNTING PRONOUNCEMENTS

Canadian Pronouncements

In January 2006, the Canadian Accounting Standards Board (AcSB) adopted a strategic plan for the direction of accounting standards in Canada. Accounting standards for public companies in Canada will converge with the International Financial Reporting Standards (IFRS) by 2011 and we will be required to report according to IFRS standards for the year ended December 31, 2011. We are currently assessing the impact of the convergence of Canadian GAAP with IFRS on our results of operations, financial position and disclosures.

In February 2008, the AcSB issued Section 3064, Goodwill and Intangible Assets and amended Section 1000, Financial Statement Concepts clarifying the criteria for the recognition of assets, intangible assets and internally developed intangible assets. Items that no longer meet the definition of an asset are no longer recognized with assets. The standard is effective for

44

fiscal years beginning on or after October 1, 2008 and early adoption is permitted. We are currently evaluating the impact these sections will have on our results of operations or financial position.

US Pronouncements

Effective December 31, 2006, we adopted the recognition and disclosure provisions of the Financial Accounting Standards Board (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 December 2007, FASB issued Statement 141 (revised), Business Combinations Statement 141 (revised) establishes principles and requirements of the acquisition method for business combinations and related disclosures. This statement is effective for fiscal years beginning on or after December 15, 2008. We do not expect the adoption of this statement to have a material impact on our results of operations or financial position.

In December 2007, FASB issued Statement 160, Non-controlling Interests In Consolidated Financial Statements, an amendment of ARB. No51. This statement clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This statement is effective for fiscal years beginning on or after December 15, 2008. We do not expect the adoption of this statement to have a material impact on our results of operations or financial position.

In March 2008, FASB issued Statement 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement 133. The statement requires qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of gains and losses on derivative contracts and details of credit-risk-related contingent features in their hedged positions. The statement also requires the disclosure of the location and amounts of derivative instruments in the financial statements. This statement is effective for fiscal years and interim periods beginning on or after November 15, 2008. We do not expect the adoption of this statement to have a material impact on our results of operations or financial position.

EQUITY SECURITY REPURCHASES

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

SUMMARY OF QUARTERLY RESULTS

	Three Months Ended
	2006			2007				2008
(Cdn$ millions)	Jun	Sept	Dec	Mar	Jun	Sep	Dec	Mar
Net Sales	1,039	997	920	1,140	1,399	1,446	1,598	1,870
Net Income	408	199	77	121	368	403	194	630
Earnings per Common Share ($/share)
Basic	0.78	0.38	0.15	0.23	0.70	0.77	0.37	1.19
Diluted	0.76	0.37	0.14	0.22	0.68	0.75	0.36	1.17

45

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements in this report, including those appearing in Management’s Discussion and Analysis of Financial Condition and Results of Operations, constitute “forward-looking statements” (within the meaning of the United States Private Securities Litigation Reform Act of 1995, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended) or “forward-looking information” (within the meaning of applicable Canadian securities legislation). Such statements or information (together “forward-looking statements”) are generally identifiable by the terminology used such as “anticipate”, “believe”, “intend”, “plan”, “expect”, “estimate”, “budget”, “outlook”, “forecast”  or other similar words, and include statements relating to or associated with individual wells, regions or projects. Any statements regarding the following are forward-looking statements:

• future crude oil, natural gas or chemicals prices;

• future production levels;

• future cost recovery oil revenues from our Yemen operations;

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

• future earnings;

• future asset dispositions;

• future sources of funding for our capital program;

• future debt levels;

• possible commerciality;

• development plans or capacity expansions;

• future ability to execute dispositions of assets or businesses;

• future cash flows and their uses;

• future drilling of new wells;

• ultimate recoverability of reserves or resources;

• expected finding and development costs;

• expected operating costs;

• future demand for chemicals products;

• estimates on a per share basis;

• sales;

• future expenditures and future allowances relating to environmental matters;

• dates by which certain areas will be developed or will come on-stream; and

• changes in any of the foregoing.

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

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

• market prices for oil and gas and chemicals products;

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

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

• volatility in energy trading markets;

• foreign-currency exchange rates;

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

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

• renegotiations of contracts;

• results of litigation, arbitration or regulatory proceedings; and

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

These 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 2007 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 factors are interdependent, and management’s future course of action would depend on our assessment of all information at that time.

Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels

46

of activity and achievements. Undue reliance should not be placed on the statements contained herein, which are made as of the date hereof and, except as required by law, we undertake no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to normal market risks inherent in the oil and gas 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 72 – 74 in our 2007 Annual Report on Form 10-K has not changed materially since December 31, 2007.

Item 4. Controls and Procedures

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

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

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

CHANGES IN INTERNAL CONTROLS

We have continually had in place systems relating to internal control over financial reporting. There has not been any change in the Company's internal control over financial reporting during the first quarter of 2008 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting.

47

PART II

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

None.

Item 6. Exhibits

31.1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

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

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on May 1, 2008.

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)

48