NEWFIELD EXPLORATION CO /DE/ - 10-Q Quarterly Report

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


(Mark One)
þ		QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the Quarterly Period Ended March 31, 2004

or

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: 1-12534

Newfield Exploration Company

(Exact name of Registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		72-1133047 (I.R.S. Employer Identification Number)

363 North Sam Houston Parkway East

Suite 2020

Houston, Texas 77060

(Address and Zip Code of principal executive offices)

(281) 847-6000

(Registrant’s telephone number, including area code)

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 twelve months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes þ No o

As of April 27, 2004, there were 56,384,783 shares of the Registrant’s Common Stock, par value $0.01 per share, outstanding.

TABLE OF CONTENTS


PART I
Item 1. Unaudited Financial Statements:
CONSOLIDATED BALANCE SHEET
CONSOLIDATED STATEMENT OF INCOME
CONSOLIDATED STATEMENT OF CASH FLOWS
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
PART II
Item 6. Exhibits and Reports on Form 8-K
Credit Agreement
Newfield Exploration Company Stock Plan
Certification of CEO pursuant to Section 302
Certification of CFO pursuant to Section 302
Certification of CEO pursuant to Section 906
Certification of CFO pursuant to Section 906

TABLE OF CONTENTS

Page

PART I

Item 1.

Unaudited Financial Statements:

Consolidated Balance Sheet as of March 31, 2004 and December 31, 2003

Consolidated Statement of Income for the three months ended March 31, 2004 and 2003

Consolidated Statement of Cash Flows for the three months ended March 31, 2004 and 2003

Consolidated Statement of Stockholders’ Equity for the three months ended March 31, 2004

Notes to Consolidated Financial Statements

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Item 4.

Controls and Procedures

PART II

Item 6.

Exhibits and Reports on Form 8-K

PART I


Item 1.	*Unaudited Financial Statements:*

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEET


			March 31,			December 31,
			2004			2003


			(In thousands, except
			share data)
			(Unaudited)
ASSETS
Current assets:
	Cash and cash equivalents		$	16,933		$	15,347
	Accounts receivable — oil and gas			168,733			134,774
	Inventories			784			553
	Derivative assets			5,889			13,786
	Deferred taxes			28,749			12,893
	Other current assets			33,858			61,563

		Total current assets		254,946			238,916

Oil and gas properties (full cost method, of which $369,703 at March 31, 2004 and $331,114 at December 31, 2003 were excluded from amortization)				4,230,462			4,078,115
Less — accumulated depreciation, depletion and amortization				(1,762,782	)		(1,659,615	)

				2,467,680			2,418,500

Floating production system and pipelines				35,000			35,000
Furniture, fixtures and equipment, net				5,489			5,875
Derivative assets				4,154			2,223
Other assets				17,948			16,197
Goodwill				16,378			16,378

		Total assets	$	2,801,595		$	2,733,089

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Accounts payable		$	26,101		$	30,556
	Accrued liabilities			221,895			204,054
	Advances from joint owners			16,884			5,922
	Secured notes payable			—			2,895
	Asset retirement obligation			11,484			12,095
	Derivative liabilities			81,559			44,696

		Total current liabilities		357,923			300,218

Derivative liabilities				13,582			13,244
Long-term debt				575,988			643,459
Asset retirement obligation				153,839			151,548
Deferred taxes				258,580			242,839
Other liabilities				13,154			13,203

		Total long-term liabilities		1,015,143			1,064,293

Commitments and contingencies				—			—
Stockholders’ equity:
	Preferred stock ($0.01 par value; 5,000,000 shares authorized; no shares issued)			—			—
	Common stock ($0.01 par value; 100,000,000 shares authorized; 57,278,787 and 57,141,807 shares issued and outstanding at March 31, 2004 and December 31, 2003, respectively)			573			571
Additional paid-in capital				800,598			796,256
Treasury stock (at cost; 893,972 and 886,247 shares at March 31, 2004 and December 31, 2003, respectively)				(27,050	)		(26,679	)
Unearned compensation				(10,506	)		(10,912	)
Accumulated other comprehensive income (loss):
	Foreign currency translation adjustment			1,116			851
	Commodity derivatives			(49,029	)		(26,428	)
	Minimum pension liability			(833	)		(833	)
Retained earnings				713,660			635,752

		Total stockholders’ equity		1,428,529			1,368,578

		Total liabilities and stockholders’ equity	$	2,801,595		$	2,733,089

The accompanying notes to consolidated financial statements are an integral part of this statement.

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF INCOME



			Three Months Ended
			March 31,

			2004			2003


			(In thousands, except
			share and
			per share data)
			(Unaudited)
Oil and gas revenues			$	305,355		$	267,891

Operating expenses:
	Lease operating			29,865			27,807
	Production and other taxes			8,359			10,207
	Transportation			1,440			1,563
	Depreciation, depletion and amortization			105,905			93,318
	General and administrative (includes non-cash stock compensation of $991 and $679 for the three months ended March 31, 2004 and 2003, respectively)			18,560			17,006
	Gas sales obligation settlement			—			9,998

		Total operating expenses		164,129			159,899

Income from operations				141,226			107,992
Other income (expenses):
	Interest expense			(12,532	)		(16,686	)
	Capitalized interest			3,935			3,819
	Dividends on convertible preferred securities of Newfield Financial Trust I			—			(2,336	)
	Commodity derivative expense			(12,241	)		(1,217	)
	Other			660			520

				(20,178	)		(15,900	)

Income from continuing operations before income taxes				121,048			92,092
Income tax provision:
	Current			30,581			22,856
	Deferred			12,559			9,890

				43,140			32,746

Income from continuing operations				77,908			59,346
Loss from discontinued operations, net of tax				—			(780	)

Income before cumulative effect of change in accounting principle				77,908			58,566
Cumulative effect of change in accounting principle, net of tax:
	Adoption of SFAS No. 143			—			5,575

		Net income	$	77,908		$	64,141

Earnings per share:
Basic —
	Income from continuing operations		$	1.39		$	1.14
	Loss from discontinued operations			—			(0.01	)
	Cumulative effect of change in accounting principle, net of tax			—			0.11

		Net income	$	1.39		$	1.24

Diluted —
	Income from continuing operations		$	1.38		$	1.08
	Loss from discontinued operations			—			(0.01	)
	Cumulative effect of change in accounting principle, net of tax			—			0.10

		Net income	$	1.38		$	1.17

Weighted average number of shares outstanding for basic earnings per share				55,921			51,886

Weighted average number of shares outstanding for diluted earnings per share				56,633			56,208

The accompanying notes to consolidated financial statements are an integral part of this statement.

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS



					Three Months Ended
					March 31,

					2004			2003


					(In thousands)
					(Unaudited)
Cash flows from operating activities:
	Net income				$	77,908		$	64,141
Adjustments to reconcile net income to net cash provided by continuing operating activities:
	Loss from discontinued operations, net of tax					—			780
	Depreciation, depletion and amortization					105,905			93,318
	Gas sales obligation settlement					—			9,998
	Stock compensation					991			679
	Commodity derivative expense					10,762			1,217
	Deferred taxes					12,559			9,890
	Cumulative effect of change in accounting principle					—			(5,575	)
	Changes in operating assets and liabilities:
		Increase in accounts receivable — oil and gas				(33,956	)		(75,248	)
		Increase in inventories				(230	)		(14	)
		(Increase) decrease in other current assets				27,505			(7,466	)
		Increase in other assets				(1,750	)		(1,566	)
		Increase (decrease) in accounts payable and accrued liabilities				8,132			(15,859	)
		Increase (decrease) in advances from joint owners				10,961			(1,529	)
		Decrease in other liabilities				(59	)		(11,683	)

			Net cash provided by continuing activities			218,728			61,083
			Net cash provided by discontinued activities			—			4,572

				Net cash provided by operating activities		218,728			65,655

Cash flows from investing activities:
	Additions to oil and gas properties					(147,058	)		(122,662	)
	Additions to furniture, fixtures and equipment					(702	)		(1,779	)

			Net cash used in continuing activities			(147,760	)		(124,441	)
			Net cash used in discontinued activities			—			(1,442	)

				Net cash used in investing activities		(147,760	)		(125,883	)

Cash flows from financing activities:
	Proceeds from borrowings under credit arrangements					132,500			744,000
	Repayments of borrowings under credit arrangements					(202,500	)		(575,000	)
	Proceeds from issuance of common stock					3,627			726
	Purchases of treasury stock					(371	)		(339	)
	Repurchases of secured notes					(2,895	)		(33,869	)
	Repayments of secured notes					—			(11,215	)
	Deliveries under the gas sales obligation					—			(8,442	)
	Gas sales obligation settlement					—			(62,017	)

			Net cash provided by (used in) continuing activities			(69,639	)		53,844
			Net cash provided by (used in) discontinued activities			—			—

				Net cash provided by (used in) financing activities		(69,639	)		53,844

Effect of exchange rate changes on cash and cash equivalents						257			72

Increase (decrease) in cash and cash equivalents						1,586			(6,312	)
Cash and cash equivalents from continuing operations, beginning of period						15,347			33,798
Cash and cash equivalents from discontinued operations, beginning of period						—			15,100

Cash and cash equivalents, end of period					$	16,933		$	42,586

The accompanying notes to consolidated financial statements are an integral part of this statement.

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY


																				Accumulated
																				Other
			Common Stock				Treasury Stock						Additional							Comprehensive			Total
													Paid-In		Unearned			Retained		Income			Stockholders’
			Shares		Amount		Shares			Amount			Capital		Compensation			Earnings		(Loss)			Equity


			(In thousands, except share data)
			(Unaudited)
Balance, December 31, 2003				57,141,807	$	571		(886,247	)	$	(26,679	)	$	796,256	$	(10,912	)	$	635,752	$	(26,410	)	$	1,368,578
Issuance of common stock				124,980		2								3,626										3,628
Issuance of restricted stock, less amortization of $26 and cancellations				12,000										585		(559	)							26
Treasury stock, at cost								(7,725	)		(371	)												(371	)
Amortization of stock compensation																965								965
Tax benefit from exercise of stock options														131										131
Comprehensive income:
	Net income																		77,908					77,908
	Foreign currency translation adjustment, net of tax of ($143)																				265			265
	Reclassification adjustments for settled hedging positions, net of tax of $4,395																				(8,163	)		(8,163	)
	Changes in fair value of outstanding hedging positions, net of tax of $7,774																				(14,438	)		(14,438	)

		Total comprehensive income																						55,572

Balance, March 31, 2004				57,278,787	$	573		(893,972	)	$	(27,050	)	$	800,598	$	(10,506	)	$	713,660	$	(48,746	)	$	1,428,529

The accompanying notes to consolidated financial statements are an integral part of this statement.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	Organization and Summary of Significant Accounting Policies:


	*Organization and Principles of Consolidation*

We are an independent oil and gas company engaged in the exploration, development and acquisition of crude oil and natural gas properties. Our company was founded in 1989. Our initial focus area was the Gulf of Mexico. In the mid-1990s, we began to expand our operations to other select areas. Our areas of operation now include the Gulf of Mexico, the U.S. onshore Gulf Coast, the Anadarko and Arkoma Basins, China’s Bohai Bay and the North Sea.

Our financial statements include the accounts of Newfield Exploration Company, a Delaware corporation, and its subsidiaries. All significant intercompany balances and transactions have been eliminated. Unless otherwise specified or the context otherwise requires, all references in these notes to “Newfield,” “we,” “us” or “our” are to Newfield Exploration Company and its subsidiaries.

These unaudited consolidated financial statements reflect, in the opinion of our management, all adjustments, consisting only of normal and recurring adjustments, necessary to present fairly our financial position as of, and results of operations for, the periods presented. These financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with accounting principles generally accepted in the United States of America. Interim period results are not necessarily indicative of results of operations or cash flows for a full year.

These financial statements and notes should be read in conjunction with our audited consolidated financial statements and the notes thereto for the year ended December 31, 2003 included in our Annual Report on Form 10-K.

On September 5, 2003, we sold Newfield Exploration Australia Ltd., the holding company for all of our Australian assets. As a result of the sale, the historical results of our Australian operations are reflected in our consolidated financial statements as “discontinued operations.” See Note 2, “Discontinued Operations.” Except where noted and for pro forma earnings per share, discussions in these notes relate to our continuing activities only.


	*Dependence on Oil and Gas Prices*

As an independent oil and gas producer, our revenue, profitability and future rate of growth are substantially dependent on prevailing prices for natural gas and oil, which are dependent upon numerous factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. The energy markets have historically been very volatile, and there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil or gas prices could have a material adverse effect on our financial position, results of operations, cash flows and access to capital and on the quantities of oil and gas reserves that we may economically produce.


	*Use of Estimates*

The preparation of financial statements in accordance with accounting principles generally accepted in the United States requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, the reported amounts of revenues and expenses during the reporting period and the reported amounts of proved oil and gas reserves. Actual results could differ from these estimates. Our most significant financial estimates are based on remaining proved oil and gas reserves.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Reclassifications*

Certain reclassifications have been made to prior year’s reported amounts in order to conform with the current period presentation. These reclassifications, including those related to our discontinued operations (see Note 2, “Discontinued Operations”), did not impact our net income or stockholders’ equity.


	*Accounting for Asset Retirement Obligations*

We adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” as of January 1, 2003. This statement changes the method of accounting for expected future costs associated with our obligation to perform site reclamation, dismantle facilities and plug and abandon wells. Prior to January 1, 2003, we recognized the undiscounted estimated cost to abandon our oil and gas properties over their estimated productive lives on a unit-of-production basis as a component of depreciation, depletion and amortization expense and no liability or capitalized costs associated with such abandonment were recorded on our consolidated balance sheet. If a reasonable estimate of the fair value of an abandonment obligation can be made, SFAS No. 143 requires us to record a liability (an “asset retirement obligation” or “ARO”) on our consolidated balance sheet and to capitalize the asset retirement cost in oil and gas properties in the period in which the retirement obligation is incurred.

In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for our company. After recording these amounts, the ARO will be accreted to its future estimated value using the same assumed cost of funds and the additional capitalized costs will be depreciated on a unit-of-production basis over the productive life of the related properties. Both the accretion and the depreciation are included in depreciation, depletion and amortization on our consolidated statement of income.

At adoption of SFAS No. 143, a cumulative effect of change in accounting principle was required in order to recognize:

• an initial ARO as a liability on our consolidated balance sheet;

• an increase in oil and gas properties for the cost to abandon our oil and gas properties;

• cumulative accretion of the ARO from the period incurred up to the January 1, 2003 adoption date; and

• cumulative depreciation on the additional capitalized costs included in oil and gas properties up to the January 1, 2003 adoption date.

As a result of our adoption of SFAS No. 143, we recorded a $134.8 million increase in the net capitalized costs of our oil and gas properties and an initial ARO of $128.5 million. Additionally, we recognized an after-tax gain of $5.6 million (the after-tax amount by which additional capitalized costs, net of accumulated depreciation, exceeded the initial ARO, including in each case discontinued operations) as the cumulative effect of change in accounting principle.

The change in our ARO for the first quarter of 2004 is set forth below (in thousands):


Balance as of January 1, 2004	$	163,643
Accretion expense		2,214
Additions		77
Settlements		(611	)

Balance of ARO as of March 31, 2004	$	165,323

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Goodwill*

The $16.4 million recorded as goodwill on our consolidated balance sheet represents the excess of the purchase price over the estimated fair value of the assets acquired less the liabilities assumed in our acquisition of Primary Natural Resources in the third quarter of 2003. We allocated all of the goodwill associated with this acquisition to our Mid-Continent reporting unit.

Goodwill is tested for impairment on an annual basis, or more frequently if an event occurs or circumstances change that have an adverse effect on the fair value of the reporting unit such that the fair value could be less than the book value of such unit. The impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of that reporting unit. If the fair value of the reporting unit is less than the book value (including goodwill) then goodwill is reduced to its implied fair value and the amount of the writedown is charged to earnings.

We perform our goodwill impairment test annually on December 31, or more frequently if there is an indication of potential impairment. The fair value of the Mid-Continent reporting unit is based on our estimates of future net cash flows from proved reserves and from future exploration for and development of unproved reserves. Downward revisions of estimated reserves or production, increases in estimated future costs or decreases in oil and gas prices could lead to an impairment of all or a portion of this goodwill in future periods.


	*Stock-Based Compensation*

We account for our employee stock options using the intrinsic value method prescribed by APB Opinion No. 25.

If the fair value based method of accounting under SFAS No. 123, “Accounting for Stock-Based Compensation,” had been applied using a Black-Scholes option pricing model, our net income and earnings per common share for the three months ended March 31, 2004 and 2003 would have approximated the pro forma amounts below:



		Three Months Ended
		March 31,

		2004		2003


		(In thousands, except
		per share data)
Net income:
	As reported	$	77,908	$	64,141
	Pro forma		76,316		62,480
Basic earnings per common share —
	As reported	$	1.39	$	1.24
	Pro forma		1.36		1.20
Diluted earnings per common share —
	As reported	$	1.38	$	1.17
	Pro forma		1.35		1.14

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Recent Accounting Developments*

SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets,” were issued by the FASB in June 2001 and became effective for us on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141 requires that all business combinations initiated after June 30, 2001 be accounted for using the purchase method and that certain intangible assets be disaggregated and reported separately from goodwill. SFAS No. 142 established new guidelines for accounting for goodwill and other intangible assets. Under the statement, goodwill and certain other intangible assets are reviewed annually for impairment but are not amortized. To our knowledge, substantially all publicly traded oil and gas companies have continued to include oil and gas rights and interests held under leases, governmental licenses or other contractual arrangements (“leasehold interests”) as part of oil and gas properties after SFAS No. 141 and SFAS No. 142 became effective. This matter was referred to the Emerging Issues Task Force (EITF) in late 2003. Although the EITF has not issued formal guidance for oil and gas companies, at the March 2004 meeting, the Task Force reached a consensus that mineral rights for mining companies should be accounted for as tangible assets. However, the effective date of that consensus is pending until the resolution of a perceived inconsistency between the characterization of mineral rights as tangible assets in this consensus and the characterization of mineral rights as intangible assets in SFAS No. 141 and SFAS No. 142. In order to resolve this inconsistency, the Board directed the FASB staff to prepare a FASB Staff Position (FSP) that will amend SFAS No. 141 and SFAS No. 142. The consensus will be effective when the FSP is finalized.

If all leasehold interests were deemed to be intangible assets, for companies like us that use the full cost method of accounting for oil and gas activities:

• leasehold interests with proved reserves that were acquired after June 30, 2001 and leasehold interests with no proved reserves would be classified as intangible assets and would not be included in oil and gas properties on our consolidated balance sheet;

• our results of operations and cash flows would not be affected because leasehold costs would continue to be amortized in accordance with full cost accounting rules; and

• the disclosures required by SFAS Nos. 141 and 142 relative to intangibles would be included in the notes to our financial statements.

If SFAS Nos. 141 and 142 were applied as described above, as of March 31, 2004, we had undeveloped leasehold interests of approximately $117.6 million (without reduction for depreciation, depletion and amortization) that would be classified on our consolidated balance sheet as “intangible undeveloped leaseholds” and we had developed leasehold interests of approximately $637.5 million (without reduction for depreciation, depletion and amortization) that would be classified on our consolidated balance sheet as “intangible developed leaseholds.”

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


2.	Discontinued Operations:

On September 5, 2003, we sold our wholly owned subsidiary, Newfield Exploration Australia Ltd., the holding company for all of our Australian assets. The historical results of our Australian operations are reflected in our consolidated financial statements as “discontinued operations” and are summarized as follows:


	Three Months
	Ended
	March 31, 2003

	(In thousands)
Revenues	$	11,393
Operating expenses		(10,773	)

Income from operations		620
Other expense(1)		(1,751	)

Loss before income taxes		(1,131	)
Income tax benefit		351

Loss from discontinued operations	$	(780	)

(1) Other expense primarily consists of foreign currency exchange gains and losses.


3.	Earnings Per Share:

Basic earnings per share (EPS) is calculated by dividing net income (the numerator) by the weighted average number of shares of common stock outstanding during the period (the denominator). Diluted earnings per share incorporates the incremental shares issuable (if dilutive) upon the assumed exercise of stock options (using the treasury stock method) and upon the assumed conversion of our trust preferred securities as if exercise or conversion to common stock had occurred at the beginning of the accounting period. Net income also has been increased for distributions accrued during the period on our trust preferred securities. We redeemed all of our outstanding trust preferred securities in June 2003.

The following is the calculation of basic and diluted weighted average shares outstanding and EPS for the three months ended March 31, 2004 and 2003:



		Three Months Ended
		March 31,

		2004		2003


		(In thousands, except
		share and per
		share data)
Income (numerator):
	Income from continuing operations	$	77,908	$	59,346
	Loss from discontinued operations, net of tax		—		(780	)

	Income before cumulative effect of change in accounting principle		77,908		58,566
	Cumulative effect of change in accounting principle, net of tax		—		5,575

	Net income — basic		77,908		64,141
	After-tax dividends on convertible trust preferred securities		—		1,518

	Net income — diluted	$	77,908	$	65,659

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)



				Three Months Ended
				March 31,

				2004		2003


				(In thousands, except
				share and per
				share data)
Weighted average shares (denominator):
	Weighted average shares — basic				55,921		51,886
	Dilution effect of stock options outstanding at end of period				712		399
	Dilution effect of convertible trust preferred securities				—		3,923

	Weighted average shares — diluted				56,633		56,208

Earnings per share:
	Basic:
		Income from continuing operations		$	1.39	$	1.14
		Loss from discontinued operations			—		(0.01	)
		Cumulative effect of change in accounting principle, net of tax			—		0.11

			Net income	$	1.39	$	1.24

	Diluted:
		Income from continuing operations		$	1.38	$	1.08
		Loss from discontinued operations			—		(0.01	)
		Cumulative effect of change in accounting principle, net of tax			—		0.10

			Net income	$	1.38	$	1.17

The calculation of shares outstanding for diluted EPS for the three months ended March 31, 2004 and 2003 does not include the effect of outstanding stock options to purchase 448,500 and 1,582,850 shares, respectively, because to do so would have been antidilutive.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


4.	Oil and Gas Assets:


	*Oil and Gas Properties*

Oil and gas properties consisted of the following at the indicated dates:


				March 31,			December 31,
				2004			2003


				(In thousands)
Subject to amortization				$	3,860,759		$	3,747,001
Not subject to amortization:
	Exploration wells in progress				12,118			8,221
	Development wells in progress				61,477			31,105
	Capitalized interest				25,066			23,089
	Fee mineral interests				23,298			23,298
	Other capital costs:
		Incurred in 2004			10,043			—
		Incurred in 2003			59,794			61,918
		Incurred in 2002			103,014			105,830
		Incurred in 2001 and prior			74,893			77,653

			Total not subject to amortization		369,703			331,114

Gross oil and gas properties					4,230,462			4,078,115
Accumulated depreciation, depletion and amortization					(1,762,782	)		(1,659,615	)

Net oil and gas properties				$	2,467,680		$	2,418,500

We believe that substantially all of the costs not currently subject to amortization will be evaluated within four years.

A portion of incurred (if not previously included in the amortization base) and future development costs associated with qualifying major development projects may be temporarily excluded from amortization. To qualify, a project must require significant costs to ascertain the quantities of proved reserves attributable to the properties under development (e.g., the installation of an offshore production platform from which development wells are to be drilled). Incurred and future costs are allocated between completed and future work. Any temporarily excluded costs are included in the amortization base upon the earlier of when the associated reserves are determined to be proved or impairment is indicated.

As of March 31, 2004 and December 31, 2003, we excluded from the amortization base $25.7 million (which is included in costs not subject to amortization in the table above) associated with development costs for our deepwater Gulf of Mexico project known as “Glider,” located at Green Canyon 247/248.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


5.	Debt:

As of the indicated dates, our long-term debt consisted of the following:


				March 31,		December 31,
				2004		2003


				(In thousands)
Senior unsecured debt:
	Bank revolving credit facility:
		Prime rate based loans		$	—	$	—
		LIBOR based loans			25,000		90,000

			Total bank revolving credit facility		25,000		90,000
	Money market lines of credit(1)				—		5,000

			Total credit arrangements		25,000		95,000

	7.45% Senior Notes due 2007				124,831		124,821
	Fair value of interest rate swaps(2)				1,319		171
	7 5/8% Senior Notes due 2011				174,908		174,905
	Fair value of interest rate swaps(2)				1,779		449

			Total senior unsecured notes		302,837		300,346

			Total senior unsecured debt		327,837		395,346

8 3/8% Senior Subordinated Notes due 2012					248,151		248,113

			Total long-term debt	$	575,988	$	643,459

(1) Because capacity under our credit facility was available to repay borrowings under our money market lines of credit, this obligation was classified as long-term.

(2) See “— Interest Rate Swaps” below.

At March 31, 2004 and December 31, 2003, the interest rate was 2.38% and 2.50%, respectively, for LIBOR based loans under our credit facility. At December 31, 2003, the interest rate was 3.00% for the loans outstanding under our money market lines of credit.


	*New Credit Facility*

On March 16, 2004, we entered into a new reserve-based revolving credit facility with JPMorgan Chase Bank, as agent. The banks participating in the new facility have committed to lend us up to $600 million. The amount available under the facility is subject to a calculated borrowing base determined by banks holding 75% of the aggregate commitments, which is reduced by the principal amount of any outstanding senior notes ($300 million at March 31, 2004) and 30% of the principal amount of any outstanding senior subordinated notes (a reduction of $75 million at March 31, 2004). The borrowing base is redetermined at least semi-annually and, after all required adjustments, was $500 million at March 31, 2004. The facility contains restrictions on the payment of dividends and the incurrence of debt as well as other customary covenants and restrictions. The facility matures on March 14, 2008. At March 31, 2004, we had $475 million available under our credit facility and had outstanding borrowings of $25 million.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Interest Rate Swaps*

During September 2003, we entered into interest rate swap agreements to take advantage of low interest rates and to obtain what we view as a more desirable proportion of variable and fixed rate debt. We hedged $50 million principal amount of our 7.45% Senior Notes due 2007 and $50 million principal amount of our 7 5/8% Senior Notes due 2011. These swap agreements provide for us to pay variable and receive fixed interest payments and are designated as fair value hedges of a portion of our outstanding senior notes.

Pursuant to SFAS No. 133, changes in the fair value of derivatives designated as fair value hedges are recognized as offsets to the changes in fair value of the exposure being hedged. As a result, the fair value of our interest rate swap agreements is reflected within our derivative assets on our consolidated balance sheet and changes in their fair value are recorded as an adjustment to the carrying value of the associated long-term debt. Receipts and payments related to our interest rate swaps are reflected in interest expense.


	*Gas Sales Obligation Settlement*

We acquired EEX Corporation in November 2002. Pursuant to a gas forward sales contract entered into in 1999, EEX committed to deliver approximately 50 Bcf of production to Bob West Treasure L.L.C. (BWT) in exchange for proceeds of $105 million. As of the date of our acquisition of EEX, we recorded a liability of approximately $62 million, which represented the then current market value of approximately 16 Bcf of reserves remaining subject to the gas sales contract. We accounted for this obligation as debt on our consolidated balance sheet.

On March 31, 2003, pursuant to a settlement agreement with BWT and the other parties to related transactions, the gas sales contract, the swaps entered into by BWT in connection with the gas sales contract and all other agreements related to the gas sales contract, including the guarantee and all liens and other security interests on EEX’s properties, were terminated in exchange for a payment by us of approximately $73 million. This payment represented:

• the remaining unamortized obligation under the gas sales contract;

• the fair market value of swaps entered into by BWT in conjunction with the gas sales contract;

• various transaction fees related to the termination; and

• an agreed upon value for BWT’s membership interest in an EEX subsidiary.

In connection with the settlement, we recognized a loss of $10.0 million under the caption “Gas sales obligation settlement” on our consolidated statement of income.


6.	Contingencies:

We have been named as a defendant in a number of lawsuits arising in the ordinary course of our business. While the outcome of these lawsuits cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, cash flows or results of operations.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


7.	Geographic Information:


			United States		International		Total


			(In thousands)
Three Months Ended March 31, 2004:
Oil and gas revenues			$	304,425	$	930	$	305,355
Operating expenses:
	Lease operating			29,608		257		29,865
	Production and other taxes			8,359		—		8,359
	Transportation			1,440		—		1,440
	Depreciation, depletion and amortization			105,553		352		105,905
	Allocated income taxes			55,813		128

		Net income from oil and gas properties	$	103,652	$	193

	General and administrative (inclusive of stock compensation)(1)							18,560

		Total operating expenses						164,129

Income from operations								141,226
	Interest expense, net of interest income, capitalized interest and other							(7,937	)
	Commodity derivative expense							(12,241	)

Income from continuing operations before income taxes							$	121,048

Total long-lived assets			$	2,411,407	$	56,273	$	2,467,680

Additions to long-lived assets			$	149,101	$	3,246	$	152,347

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


			United States		International		Total


			(In thousands)
Three Months Ended March 31, 2003:
Oil and gas revenues			$	267,891	$	—	$	267,891
Operating expenses:
	Lease operating			27,807		—		27,807
	Production and other taxes			10,207		—		10,207
	Transportation			1,563		—		1,563
	Depreciation, depletion and amortization			93,318		—		93,318
	Allocated income taxes			47,153		—

		Net income from oil and gas properties	$	87,843	$	—

	Gas sales obligation settlement							9,998
	General and administrative (inclusive of stock compensation)(1)							17,006

		Total operating expenses						159,899

Income from operations								107,992
	Interest expense and dividends, net of interest income, capitalized interest and other							(14,683	)
	Commodity derivative expense							(1,217	)

Income from continuing operations before income taxes							$	92,092

Total long-lived assets			$	2,127,080	$	38,726	$	2,165,806

Additions to long-lived assets(2)			$	229,793	$	2,382	$	232,175

(1) General and administrative expense includes stock compensation charges of $991 and $679 for the three months ended March 31, 2004 and 2003, respectively.

(2) Includes $113.1 million (domestic) for capitalized asset retirement obligations associated with our adoption of SFAS No. 143.


8.	Commodity Derivative Instruments and Hedging Activities:

We utilize swap, floor, collar and three-way collar derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of our future oil and gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also may limit future revenues from favorable price movements.

With respect to a swap contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price for such contract, and we are required to make payment to the counterparty if the settlement price for any settlement period is greater than the swap price for such contract. For a floor contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price for such contract. We are not required to make any payment in connection with the settlement of a floor contract. For a collar contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price for such contract, we are required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling price for such contract and neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

less than the ceiling price for such contract. A three-way collar contract consists of a standard collar contract plus a put sold by us with a price below the floor price of the collar. This additional put requires us to make a payment to the counterparty if the settlement price for any settlement period is below the put price. Combining the collar contract with the additional put results in us being entitled to a net payment equal to the difference between the floor price of the standard collar and the additional put price if the settlement price is equal to or less than the additional put price. If the settlement price is greater than the additional put price, the result is the same as it would have been with a standard collar contract only. This strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a traditional no cost collar while defraying the associated cost with the sale of the additional put.

Substantially all of our oil and gas derivative contracts are settled based upon reported prices on the NYMEX. The estimated fair value of these contracts is based upon various factors, including closing exchange prices on the NYMEX, over-the-counter quotations, volatility and, in the case of collars and floors, the time value of options. The calculation of the fair value of collars and floors requires the use of an option-pricing model.

On the date we enter into a derivative contract, we determine whether the derivative contract should be designated as a hedge of the variability in cash flows associated with the forecasted sale of our future oil and gas production. After-tax changes in the fair value of a derivative that is highly effective and is designated and qualifies as a cash flow hedge, to the extent that the hedge is effective, are recorded under the caption “Accumulated other comprehensive income (loss) — Commodity derivatives” on our consolidated balance sheet until the sale of the hedged oil and gas production. Upon the sale of the hedged production, the net after-tax change in the fair value of the associated derivative recorded under the caption “Accumulated other comprehensive income (loss) — Commodity derivatives” is reversed and the gain or loss on the hedge, to the extent that it is effective, is reported in “Oil and gas revenues” on our consolidated statement of income. At March 31, 2004, we had a net $49.0 million after-tax loss recorded under the caption “Accumulated other comprehensive income (loss) — Commodity derivatives.” We expect hedged production associated with commodity derivatives accounting for a net loss of approximately $44.5 million to be sold within the next 12 months and hedged production associated with the remaining net loss of approximately $4.5 million to be sold thereafter. The actual gain or loss on these commodity derivatives could vary significantly as a result of changes in market conditions and other factors.

Any hedge ineffectiveness (which represents the amount by which the change in the fair value of the derivative differs from the change in the cash flows of the forecasted sale of production) is reported currently each period under the caption “Commodity derivative income (expense)” on our consolidated statement of income.

We formally document all relationships between derivative instruments designated as cash flow hedges and hedged production, as well as our risk management objective and strategy for particular derivative contracts. This process includes linking the derivatives to the specific forecasted sale of oil or gas at its physical location. We also formally assess (both at the derivative’s inception and on an ongoing basis) whether the derivatives being utilized have been highly effective at offsetting changes in the cash flows of hedged production and whether those derivatives may be expected to remain highly effective in future periods. If it is determined that a derivative has ceased to be highly effective as a hedge, we will discontinue hedge accounting prospectively. If hedge accounting is discontinued and the derivative remains outstanding, we will carry the derivative at its fair value on our consolidated balance sheet and recognize all subsequent changes in its fair value on our consolidated statement of income for the period in which the change occurs. Hedge accounting was not discontinued during the periods presented for any hedging instruments.

Although our three-way collar contracts are effective as economic hedges of our commodity price exposure, they do not qualify for hedge accounting under SFAS No. 133. These contracts are carried at their fair value on our consolidated balance sheet under the captions “Derivative assets” and “Derivative liabilities.”

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Both realized gains and losses upon settlement of three-way collar contracts and unrealized gains and losses due to changes in fair value of open three-way collar contracts are recognized in our consolidated statement of income under the caption “Commodity derivative income (expense).” We recorded an unrealized loss of $9.9 million and a realized loss of $1.5 million on our three-way collar contracts for the three months ended March 31, 2004.


	*Natural Gas*

As of March 31, 2004, we had entered into derivative contracts that qualify as cash flow hedges with respect to our future natural gas production as follows:



				NYMEX Contract Price Per MMBtu


						Collars


						Floors				Ceilings				Floor Contracts				Estimated
				Swaps														Fair Value
		Volume in		(Weighted				Weighted				Weighted				Weighted		Asset (Liability)
Period and Type of Contract		MMMBtus		Average)		Range		Average		Range		Average		Range		Average		(In millions)

April 2004-June 2004
	Price swap contracts		17,565	$	4.76		—		—		—		—		—		—	$	(17.5	)
	Collar contracts		11,595		—	$	3.00-$5.25	$	4.68	$	4.16-$6.67	$	5.96		—		—		(2.7	)
	Floor contracts		2,250		—		—		—		—		—	$	4.20-$4.21	$	4.21		—
July 2004-September 2004
	Price swap contracts		17,275		4.75		—		—		—		—		—		—		(21.8	)
	Collar contracts		11,595		—		3.00-5.25		4.68		4.16-6.67		5.96		—		—		(5.4	)
	Floor contracts		2,250		—		—		—		—		—		4.20-4.21		4.21		—
October 2004-December 2004
	Price swap contracts		7,645		4.78		—		—		—		—		—		—		(9.8	)
	Collar contracts		4,195		—		3.00-5.25		4.57		4.16-6.67		5.86		—		—		(2.7	)
	Floor contracts		750		—		—		—		—		—		4.20-4.21		4.21		—
January 2005-December 2005
	Price swap contracts		5,440		4.43		—		—		—		—		—		—		(7.1	)
	Collar contracts		1,380		—		3.50		3.50		4.16		4.16		—		—		(2.2	)

																		$	(69.2	)

As of March 31, 2004, we also had entered into three-way collar contracts with respect to our future natural gas production as set forth in the table below. These contracts do not qualify for hedge accounting.



				NYMEX Contract Price Per MMBtu


								Collars


				Additional Put				Floors				Ceilings				Estimated
																Fair Value
		Volume in				Weighted				Weighted				Weighted		Asset (Liability)
Period and Type of Contract		MMMBtus		Range		Average		Range		Average		Range		Average		(In millions)

April 2004-June 2004
	3-Way collar contracts		6,750	$	3.50-$3.76	$	3.62	$	4.50-$4.76	$	4.62	$	5.20-$6.10	$	5.50	$	(2.8	)
July 2004-September 2004
	3-Way collar contracts		6,750		3.50-3.76		3.62		4.50-4.76		4.62		5.20-6.10		5.50		(5.0	)
October 2004-December 2004
	3-Way collar contracts		2,250		3.50-3.76		3.62		4.50-4.76		4.62		5.20-6.10		5.50		(1.8	)

																$	(9.6	)

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Oil*

As of March 31, 2004, we had entered into derivative contracts that qualify as cash flow hedges with respect to our future oil production as follows:



				NYMEX Contract Price Per Bbl


						Collars


						Floors				Ceilings				Estimated
				Swaps										Fair Value
		Volume in		(Weighted				Weighted				Weighted		Asset (Liability)
Period and Type of Contract		Bbls		Average)		Range		Average		Range		Average		(In millions)

April 2004-June 2004
	Price swap contracts		24,000	$	23.23		—		—		—		—	$	(0.3	)
	Collar contracts		300,000		—	$	22.00-$24.00	$	22.80	$	26.04-$28.85	$	27.16		(2.4	)
July 2004-September 2004
	Price swap contracts		204,000		29.85		—		—		—		—		(0.7	)
	Collar contracts		390,000		—		22.00-27.50		26.35		26.35-34.50		31.56		(1.2	)
October 2004-December 2004
	Price swap contracts		204,000		29.85		—		—		—		—		(0.5	)
	Collar contracts		330,000		—		27.00-27.50		27.14		30.65-34.50		32.51		(0.7	)
January 2005-December 2005
	Price swap contracts		294,000		24.90		—		—		—		—		(1.8	)
	Collar contracts		390,000		—		27.00		27.00		30.65-32.30		31.64		(0.7	)

														$	(8.3	)

As of March 31, 2004, we also had entered into three-way collar contracts with respect to our future oil production as set forth in the table below. These contracts do not qualify for hedge accounting.



				NYMEX Contract Price Per Bbl


						Collars


						Floors				Ceilings				Estimated
														Fair Value
		Volume in		Additional				Weighted				Weighted		Asset (Liability)
Period and Type of Contract		Bbls		Put		Range		Average		Range		Average		(In millions)

April 2004-June 2004
	3-Way collar contracts		377,000	$	21.00	$	25.00-$26.00	$	25.76	$	29.70-$30.05	$	29.91	$	(1.9	)
July 2004-September 2004
	3-Way collar contracts		379,000		21.00		25.00-26.00		25.76		29.70-30.05		29.91		(1.6	)
October 2004-December 2004
	3-Way collar contracts		379,000		21.00		25.00-26.00		25.76		29.70-30.05		29.91		(1.4	)
January 2005-December 2005
	3-Way collar contracts		90,000		21.00		25.00		25.00		29.70		29.70		(0.3	)

														$	(5.2	)


Item 2.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*

Overview

We are an independent oil and gas company engaged in the exploration, development and acquisition of crude oil and natural gas properties. Our areas of operation include the Gulf of Mexico, the U.S. onshore Gulf Coast, the Anadarko and Arkoma Basins, China’s Bohai Bay and the North Sea.

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and gas and on our ability to find, develop and acquire oil and gas reserves that are economically recoverable. The preparation of our financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and gas reserves. We use the full cost method of accounting for our oil and gas activities.

Oil and Gas Prices. Prices for oil and gas fluctuate widely. Oil and gas prices affect:

• the amount of cash flow available for capital expenditures;

• our ability to borrow and raise additional capital;

• the amount of oil and gas that we can economically produce; and

• the accounting for our oil and gas activities.

We generally hedge a substantial, but varying, portion of our anticipated future oil and gas production to, among other things, reduce our exposure to commodity price fluctuations.

Reserve Replacement. Generally, our producing properties in the Gulf of Mexico and the onshore Gulf Coast have high initial production rates, followed by steep declines. As a result, we must locate and develop or acquire new oil and gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire oil and gas reserves.

Significant Estimates. We believe the most difficult, subjective or complex judgments and estimates we must make in connection with the preparation of our financial statements are:

• remaining proved oil and gas reserves;

• timing of our future drilling, development and abandonment activities;

• future costs to develop and abandon our oil and gas properties;

• allocating the purchase price associated with business combinations; and

• the valuation of our derivative positions.

Please see “Other Factors Affecting Our Business and Financial Results” in Item 7 of our annual report for the year ended December 31, 2003 for a more detailed discussion of a number of other factors that affect our business, financial condition and results of operations. This report should be read together with those discussions.

Results of Operations

On September 5, 2003, we sold our wholly owned subsidiary, Newfield Exploration Australia Ltd., which held all of our Australian assets. As a result of the sale, the historical results of our Australian operations are reflected on our consolidated financial statements as “discontinued operations.” Please see Note 2, “Discontinued Operations,” to our consolidated financial statements appearing earlier in this report. Except where noted, discussions in this report relate to our continuing activities.

Revenues. All of our revenues are derived from the sale of our oil and gas production and the settlement of hedging contracts associated with our production. Our revenues may vary significantly from period to period as a result of changes in commodity prices or production volumes. Revenues for the first quarter of 2004 were

about 14% higher than the comparable period of 2003 because of higher commodity prices and higher production.



		Three Months Ended
		March 31,				Percentage
						Increase
		2004		2003		(Decrease)

Production:
	Natural gas (Bcf)		48.1		44.0		9	%
	Oil and condensate (MBbls)		1,546.6		1,516.4		2	%
	Total (Bcfe)(1)		57.4		53.1		8	%
Average Realized Prices(2):
	Natural gas (per Mcf)	$	5.30	$	5.05		5	%
	Oil and condensate (per Bbl)		31.66		29.04		9	%
	Natural gas equivalent (per Mcfe)		5.30		5.02		6	%

(1) Three months ended March 31, 2004 includes 0.2 Bcfe related to our North Sea operations.

(2) For purposes of this table, average realized prices for natural gas and oil and condensate are presented net of all applicable transportation expenses, which reduced the realized price of natural gas by $0.02 per Mcf and the realized price of oil and condensate by $0.33 per Bbl in both quarters. Average realized prices include the effects of hedging other than our three-way collar contracts, which do not qualify for hedge accounting under SFAS No. 133. Had we included the realized loss on our three-way oil contracts, our average realized price for oil and condensate would have been $30.70 per Bbl for the first quarter of 2004. The settlement of our three-way gas contracts had no impact on our realized price for natural gas for the first quarter of 2004. We did not enter into any three-way collar contracts prior to August 2003.

Production. Our total oil and gas production (stated on a natural gas equivalent basis) increased in the first quarter of 2004 when compared to the same period in 2003 primarily because of successful drilling efforts in 2003 and our Primary Natural Resources acquisition in September 2003.

Effect of Hedging on Realized Prices. The following table presents information about the effect of our hedging program on realized prices (other than our three-way collar contracts, which do not qualify for hedge accounting under SFAS No. 133).



		Average
		Realized Prices				Ratio of
						Hedged to
		With		Without		Non-Hedged
		Hedge		Hedge		Price(1)

Natural Gas:
	Three months ended March 31, 2004	$	5.30	$	5.43		98	%
	Three months ended March 31, 2003		5.05		6.30		80	%
Crude Oil and Condensate:
	Three months ended March 31, 2004	$	31.66	$	34.09		93	%
	Three months ended March 31, 2003		29.04		32.47		89	%

(1) The ratio is determined by dividing the realized price (which includes the effects of hedging) by the price that otherwise would have been realized without hedging activities.

Operating Expenses. We are a growth-oriented company. As such, our proved reserves and production have grown steadily since our founding. Naturally, our operating expenses have increased with our growth. As a result, we believe the most informative way to analyze changes in our operating expenses from one period to another is on a unit-of-production, or Mcfe, basis. The following table presents information about our operating expenses for the first quarter of 2004 and 2003.



		Unit-of-Production							Amount
		(Per Mcfe)							(In thousands)


		Three Months							Three Months Ended
		Ended March 31,				Percentage			March 31,				Percentage
						Increase							Increase
		2004		2003		(Decrease)			2004		2003		(Decrease)

Lease operating		$	0.52	$	0.52		—		$	29,865	$	27,807		7	%
Production and other taxes			0.15		0.19		(21	)%		8,359		10,207		(18	)%
Transportation			0.03		0.03		—			1,440		1,563		(8	)%
Depreciation, depletion and amortization			1.85		1.76		5	%		105,905		93,318		13	%
General and administrative (exclusive of stock compensation)(1)			0.31		0.31		—			17,569		16,327		8	%
	Total operating(1)		2.86		2.81		2	%		163,138		149,222		9	%

(1) Stock compensation charges were $991, or $0.01 per Mcfe, and $679, or $0.01 per Mcfe, for the three months ended March 31, 2004 and 2003, respectively. Total operating expense, inclusive of these charges but excluding the gas sales obligation settlement in March 2003, was $164,129, or $2.86 per Mcfe, and $149,901, or $2.82 per Mcfe, for the three months ended March 31, 2004 and 2003, respectively.

Our total operating expense (excluding stock compensation) for the first quarter of 2004, stated on a unit-of-production basis, increased 2% over the same period in 2003. The increase was primarily related to an increase in per unit depreciation, depletion and amortization (excluding furniture, fixtures and equipment), which for the first quarter of 2004 was $1.79 per Mcfe versus $1.70 per Mcfe for the comparable period of 2003. This increase primarily resulted from the increased cost of reserve additions during 2003. The increase in total operating expense was partially offset by a decrease in production and other taxes. The decrease in production and other taxes is primarily related to production tax exemptions related to certain of our onshore high cost gas wells.

General and administrative expense in the first quarter of 2004 is net of capitalized direct internal costs of $6.9 million compared to $6.8 million in the first quarter of 2003.

Gas Sales Obligation Settlement. We acquired EEX Corporation in November 2002. Pursuant to a gas forward sales contract entered into in 1999, EEX committed to deliver approximately 50 Bcf of production to Bob West Treasure L.L.C. (BWT) in exchange for proceeds of $105 million. As of the date of our acquisition of EEX, we recorded a liability of approximately $62 million, which represented the then current market value of approximately 16 Bcf of reserves remaining under the gas sales contact. We accounted for the obligation under the gas sales contract as debt on our consolidated balance sheet.

• the remaining unamortized obligation under the gas sales obligation;

• the fair market value of swaps entered into by BWT in conjunction with the gas sales contract;

• various transactions fees related to the termination; and

• an agreed upon value for BWT’s membership interest in an EEX subsidiary.

In connection with the settlement, we recognized a loss of $10 million under the caption “Gas sales obligation settlement” on our consolidated statement of income.

Interest Expense. The following table presents information about our interest expense for the first quarter of 2004 compared to the same period last year.



		Three Months
		Ended March 31,

		2004			2003


		(In millions)
Gross interest expense		$	12.5		$	16.7
Capitalized interest			(3.9	)		(3.8	)

Net interest expense			8.6			12.9
Distributions on preferred securities			—			2.3

	Total interest expense and distributions	$	8.6		$	15.2

Our total interest expense and distributions decreased 43% in the first quarter of 2004 compared to the same period in 2003 due to the repayment of debt with excess cash flow from operations and the redemption of our trust preferred securities during 2003 primarily with the net proceeds from an offering of our common stock.

Commodity Derivative Expense. The commodity derivative expense of $12.2 million for the first quarter of 2004 represents the fair value adjustment ($9.9 million) and the realized loss ($1.5 million) for our three-way collar contracts that do not qualify for hedge accounting and the hedge ineffectiveness associated with our derivatives that qualify as cash flow hedges ($0.8 million). The commodity derivative expense of $1.2 million for the first quarter of 2003 represents the hedge ineffectiveness associated with our hedging program.

Taxes. The effective tax rate for the first quarter of 2004 and the first quarter of 2003 was 35.6%. Estimates of future taxable income can be significantly affected by changes in oil and natural gas prices, estimates of the timing and amount of future production and estimates of future operating and capital costs.

Cumulative Effect of Change in Accounting Principle — Adoption of SFAS No. 143. We adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” as of January 1, 2003. This statement changed the method of accounting for expected future costs associated with our obligation to perform site reclamation, dismantle facilities and plug and abandon wells. As a result of our adoption of SFAS No. 143, we recorded a $134.8 million increase in the net capitalized costs of our oil and gas properties and an initial ARO of $128.5 million. Additionally, we recognized an after-tax gain of $5.6 million (the after-tax amount by which additional capitalized costs, net of accumulated depreciation, exceeded the initial ARO, including in each case discontinued operations) as the cumulative effect of change in accounting principle. See Note 1, “Organization and Summary of Significant Accounting Policies — Accounting for Asset Retirement Obligations” to our consolidated financial statements appearing earlier in this report.

Results of Discontinued Operations

As a result of the sale of our Australian operations in September 2003, the historical financial position, results of operations and cash flow of our Australian operations are reflected in our consolidated financial statements as “discontinued operations.” The results of our Australian operations for the three months ended March 31, 2003 are summarized as follows:


	Three Months
	Ended
	March 31, 2003

	(In thousands)
Revenues	$	11,393
Operating expenses		(10,773	)

Income from operations		620
Other expense		(1,751	)

Loss before income taxes		(1,131	)
Income tax benefit		351

Loss from discontinued operations	$	(780	)

Liquidity and Capital Resources

Our capital budget is established at the beginning of each year. Because of the nature of the properties we own, only a small portion of our capital budget is nondiscretionary. The size of our budget is driven by expected cash flow from operations. Based on current commodity prices and the high percentage of our anticipated 2004 production that has been hedged, we currently anticipate that cash flow will exceed our capital budget (which excludes acquisitions) by more than $50 million for the remainder of 2004. We anticipate that we will continue to pay down debt outstanding under our credit arrangements during the remainder of the year, unless we increase our capital budget.

Credit Arrangements. On March 16, 2004, we entered into a new reserve-based revolving credit facility with JPMorgan Chase Bank, as agent. The banks participating in the new facility have committed to lend us up to $600 million. The amount available under the facility is subject to a calculated borrowing base determined by banks holding 75% of the aggregate commitments, which is reduced by the principal amount of any outstanding senior notes ($300 million at April 28, 2004) and 30% of the principal amount of any outstanding senior subordinated notes (a reduction of $75 million at April 28, 2004). The borrowing base is redetermined at least semi-annually and, after all required adjustments, was $500 million at April 28, 2004. The facility contains restrictions on the payment of dividends and the incurrence of debt as well as other customary covenants and restrictions. The facility matures on March 14, 2008. At April 28, 2004, we had $488 million available under our credit facility and had outstanding borrowings of $12 million.

We also have money market lines of credit with various banks in an amount limited by our credit facility to $50 million. At April 28, 2004, we had $7 million outstanding under our money market lines of credit. Consequently, at April 28, 2004, we had approximately $531 million of available capacity under our credit arrangements.

Working Capital. Our working capital balance fluctuates as a result of the timing and amount of borrowings or repayments under our credit arrangements. Generally, we use excess cash to pay down borrowings under our credit arrangements. As a result, we often have a working capital deficit or a relatively small amount of positive working capital. We had a working capital deficit of $103.0 million as of March 31, 2004. This compares to a working capital deficit of $61.3 million as of December 31, 2003.

Cash Flows from Continuing Operations. Our net cash flows from continuing operations for the first quarter of 2004 increased 258% compared to the first quarter of 2003. The increase was primarily due to timing and the increased requirements of working capital during the first quarter of 2003.

Capital Expenditures. Our capital spending during the first quarter of 2004 was $152 million, a 28% increase over the same period last year. During the first quarter of 2004, we invested $112 million in domestic development, $29 million in domestic exploration, $8 million in other domestic leasehold activity and $3 million internationally.

Our current budget for capital spending in 2004 is $650 million, excluding acquisitions. We expect that 40% of this budget will be invested in the Gulf of Mexico (including deepwater), 50% in the onshore U.S. and the remainder internationally. We anticipate that our current capital expenditure budget for 2004 will be fully funded from cash flow from operations. To the extent that cash receipts during the year are slower than capital needs, we will make up the shortfall with borrowings under our credit arrangements. Actual levels of capital expenditures may vary significantly due to many factors, including the extent to which proved properties are acquired, drilling results, oil and gas prices, industry conditions and the prices and availability of goods and services. We continue to pursue attractive acquisition opportunities; however, the timing, size and purchase price of acquisitions are unpredictable. Historically, we have completed several acquisitions of varying sizes each year. Depending on the timing of an acquisition, we may spend additional capital during the year of the acquisition for drilling and development activities on the acquired properties.

Cash Flows from Financing Activities. Net cash flows used in financing activities for the first quarter of 2004 were $69.6 million compared to cash flows provided by financing activities of $53.8 million for the same period of 2003. During the first quarter of 2004, we repaid a net $70 million under our revolving credit arrangements. During the first quarter of 2003, we borrowed a net $169 million under our revolving credit arrangements, repaid or repurchased $45.1 million principal amount of our secured notes and settled our gas sales contract obligation for $62.0 million.

Oil and Gas Hedging

We generally hedge a substantial, but varying, portion of our anticipated oil and gas production for the next 18-24 months as part of our risk management program. We use hedging to reduce price volatility, help ensure that we have adequate cash flow to fund our capital programs and manage price risks and returns on some of our acquisitions and drilling programs. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions.

While the use of these hedging arrangements limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. In addition, the use of hedging transactions may involve basis risk. Substantially all of our hedging transactions are settled based upon reported settlement prices on the NYMEX. We believe there is no material basis risk with respect to our natural gas price hedging contracts because substantially all of our hedged natural gas production is sold at market prices that historically have highly correlated to the settlement price. Because substantially all of our oil production is sold at current market prices that historically have highly correlated to the NYMEX West Texas Intermediate (WTI) price, we believe that we have no material basis risk with respect to these transactions. The actual cash price we receive, however, is about $2.00 per barrel less than the NYMEX WTI price when adjusted for location and quality differences for our Gulf Coast production. Our Mid-Continent production has typically sold at a $1.00-$1.50 per barrel discount to WTI because of location and quality differences.

In 2003, we entered into three-way collar derivative contracts. Although our three-way collar contracts are effective as economic hedges of our commodity price exposure, they do not qualify for hedge accounting under SFAS No. 133.

Please see the discussion and tables in Note 8, “Commodity Derivative Instruments and Hedging Activities,” to our consolidated financial statements appearing earlier in this report for a description of the accounting applicable to our hedging program and a listing of open contracts as of March 31, 2004 and the fair value of those contracts as of that date.

Between March 31, 2004 and April 26, 2004, we entered into the additional natural gas price hedging contracts set forth in the table below.



				NYMEX Contract Price Per MMBtu


				Collars


				Floors				Ceilings

Period and		Volume in				Weighted				Weighted
Type of Contract		MMMBtus		Range		Average		Range		Average

October 2004-December 2004
	Collar contracts		800	$	5.00	$	5.00	$	10.00	$	10.00
January 2005-March 2005
	Collar contracts		1,200		5.00		5.00		10.00		10.00

Floating Production System and Pipelines

As a result of our acquisition of EEX Corporation in November 2002, we own a 60% interest in a floating production system (FPS), some offshore pipelines and a processing facility located at the end of the pipelines in shallow water. The FPS is a combination deepwater drilling rig and processing facility capable of simultaneous drilling and production operations. These infrastructure assets are not currently in service and we do not have a specific use for them in our offshore operations. At the time of acquisition, we estimated their fair market value to be $35 million and these assets are periodically evaluated for possible impairment.

We have engaged brokers who survey the world market for potential application of the assets “as is” or “to-be-modified” for a particular application. We also have direct discussions with other operators about the potential application of the assets to their developments around the world. Because there is no established market for these unique assets, it is difficult to accurately estimate their fair market value. An immediate sale or a sale under distressed circumstances might realize less than the current carrying value of the assets. No assurance can be given that we will be successful in selling these assets or that any sale will recover the carrying value of these assets.

General Information

General information about us can be found at www.newfld.com. In conjunction with our web page, we also maintain an electronic publication entitled @NFX. @NFX is periodically published to provide updates on our operating activities and our latest publicly announced estimates of expected production volumes, costs and expenses for the then current quarter. Recent editions of @NFX are available on our web page. To receive @NFX directly by email, please forward your email address to [email protected] or visit our web page and sign up. Unless specifically incorporated, the information about us at www.newfld.com and in any edition of @NFX is not part of this report.

Our Annual Report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after we file or furnish them to the SEC.

Forward-Looking Information

This report contains information that is forward-looking or relates to anticipated future events or results such as planned capital expenditures, the availability of capital resources to fund capital expenditures and anticipated cash flows. Although we believe that the expectations reflected in this information are reasonable, this information is based upon assumptions and anticipated results that are subject to numerous uncertainties. Actual results may vary significantly from those anticipated due to many factors, including drilling results, oil and gas prices, industry conditions, the prices of goods and services, the availability of drilling rigs and other support services and the availability of capital resources.

Commonly Used Oil and Gas Terms

Below are explanations of some commonly used terms in the oil and gas business.

Basis risk. The risk associated with the sales point price for oil or gas production varying from the reference (or settlement) price for a particular hedging transaction.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or condensate.

Bcf. Billion cubic feet.

Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil or condensate.

Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil or condensate.

MMBbls. One million barrels of crude oil or other liquid hydrocarbons.

MMBtu. One million Btus.

MMMBtu. One billion Btus.

MMcf. One million cubic feet.

MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil or condensate.

NYMEX. The New York Mercantile Exchange.


Item 3.	*Quantitative and Qualitative Disclosures About Market Risk*

We are exposed to market risk from changes in oil and gas prices, interest rates and foreign currency exchange rates as discussed below.

Oil and Gas Prices

Please see the discussion and tables in Note 8, “Commodity Derivative Instruments and Hedging Activities,” to our consolidated financial statements appearing earlier in this report and the discussion under the caption “Oil and Gas Hedging” in Item 2 of this report for a description of our hedging program and a listing of open hedging contracts as of March 31, 2004 and the fair value of those contracts as of that date.

Interest Rates

Inclusive of interest rate swaps, at March 31, 2004, we had $450 million in long-term fixed rate debt and $125 million of variable rate debt. Please see the discussion in Note 5, “Debt,” to our consolidated financial statements appearing earlier in this report for a description of our long-term debt and interest rate swaps. Because a large percentage of our debt is at fixed rates, we believe that we do not have any material market risk from changes in interest rates.

Foreign Currency Exchange Rates

Our cash flow from certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. We consider our current risk exposure to exchange rate movements, based on net cash flows, to be immaterial. We did not have any open derivative contracts relating to foreign currencies at March 31, 2004.


Item 4.	*Controls and Procedures*

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2004 in ensuring that material information was accumulated and communicated to management, and made known to our Chief Executive Officer and Chief Financial Officer, on a timely basis to allow disclosure as required in this report. During the three months ended March 31, 2004, there were no changes in our internal controls over financial reporting or in other factors that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

PART II


Item 6.	*Exhibits and Reports on Form 8-K*

(a) Exhibits:


Exhibit
Number			Description

	10	.1	Credit Agreement, dated as of March 16, 2004, among Newfield Exploration Company, a Delaware corporation, the Lenders party thereto, and JPMorgan Chase Bank, as Administrative Agent and as Issuing Bank (the “Credit Agreement”)
	†10	.2	Newfield Exploration Company 2004 Omnibus Stock Plan
	31	.1	Certification of Chief Executive Officer of Newfield pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	31	.2	Certification of Chief Financial Officer of Newfield pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	32	.1	Certification of Chief Executive Officer of Newfield 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 Chief Financial Officer of Newfield pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

† Identifies management contracts and compensatory plans or arrangements.

(b) Reports on Form 8-K:

On March 16, 2004, we filed a current report on Form 8-K providing the information required by Regulation BTR with respect to our 401(k) plan.

On February 13, 2004, we filed a current report on Form 8-K announcing our fourth quarter and full-year 2003 financial results and first quarter 2004 earnings guidance regarding production and significant operating and financial data. Additionally, we announced the issuance of our @NFX publication, which included an update on drilling activities during the fourth quarter and full-year 2003, guidance for the first quarter of 2004 and updated tables detailing complete hedging positions as of February 10, 2004.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

NEWFIELD EXPLORATION COMPANY

By: /s/ TERRY W. RATHERT

Terry W. Rathert

Vice President and Chief Financial Officer

(Authorized Officer and

Principal Financial Officer)

Date: April 29, 2004

EXHIBIT INDEX


Exhibit
Number			Description

	10	.1	Credit Agreement, dated as of March 16, 2004, among Newfield Exploration Company, a Delaware corporation, the Lenders party thereto, and JPMorgan Chase Bank, as Administrative Agent and as Issuing Bank (the “Credit Agreement”)
	†10	.2	Newfield Exploration Company 2004 Omnibus Stock Plan
	31	.1	Certification of Chief Executive Officer of Newfield pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	31	.2	Certification of Chief Financial Officer of Newfield pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	32	.1	Certification of Chief Executive Officer of Newfield 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 Chief Financial Officer of Newfield pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

† Identifies management contracts and compensatory plans or arrangements.

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	•	an initial ARO as a liability on our consolidated balance sheet;

	•	an increase in oil and gas properties for the cost to abandon our oil and gas properties;

	•	cumulative accretion of the ARO from the period incurred up to the January 1, 2003 adoption date; and

	•	cumulative depreciation on the additional capitalized costs included in oil and gas properties up to the January 1, 2003 adoption date.


	•	leasehold interests with proved reserves that were acquired after June 30, 2001 and leasehold interests with no proved reserves would be classified as intangible assets and would not be included in oil and gas properties on our consolidated balance sheet;

	•	our results of operations and cash flows would not be affected because leasehold costs would continue to be amortized in accordance with full cost accounting rules; and

	•	the disclosures required by SFAS Nos. 141 and 142 relative to intangibles would be included in the notes to our financial statements.


(1)	Other expense primarily consists of foreign currency exchange gains and losses.


(1)	Because capacity under our credit facility was available to repay borrowings under our money market lines of credit, this obligation was classified as long-term.

(2)	See “— Interest Rate Swaps” below.


	•	the remaining unamortized obligation under the gas sales contract;

	•	the fair market value of swaps entered into by BWT in conjunction with the gas sales contract;

	•	various transaction fees related to the termination; and

	•	an agreed upon value for BWT’s membership interest in an EEX subsidiary.


(1)	General and administrative expense includes stock compensation charges of $991 and $679 for the three months ended March 31, 2004 and 2003, respectively.

(2)	Includes $113.1 million (domestic) for capitalized asset retirement obligations associated with our adoption of SFAS No. 143.


	•	the amount of cash flow available for capital expenditures;

	•	our ability to borrow and raise additional capital;

	•	the amount of oil and gas that we can economically produce; and

	•	the accounting for our oil and gas activities.


	•	remaining proved oil and gas reserves;

	•	timing of our future drilling, development and abandonment activities;

	•	future costs to develop and abandon our oil and gas properties;

	•	allocating the purchase price associated with business combinations; and

	•	the valuation of our derivative positions.


(1)	Three months ended March 31, 2004 includes 0.2 Bcfe related to our North Sea operations.

(2)	For purposes of this table, average realized prices for natural gas and oil and condensate are presented net of all applicable transportation expenses, which reduced the realized price of natural gas by $0.02 per Mcf and the realized price of oil and condensate by $0.33 per Bbl in both quarters. Average realized prices include the effects of hedging other than our three-way collar contracts, which do not qualify for hedge accounting under SFAS No. 133. Had we included the realized loss on our three-way oil contracts, our average realized price for oil and condensate would have been $30.70 per Bbl for the first quarter of 2004. The settlement of our three-way gas contracts had no impact on our realized price for natural gas for the first quarter of 2004. We did not enter into any three-way collar contracts prior to August 2003.


(1)	The ratio is determined by dividing the realized price (which includes the effects of hedging) by the price that otherwise would have been realized without hedging activities.


	•	the remaining unamortized obligation under the gas sales obligation;

	•	the fair market value of swaps entered into by BWT in conjunction with the gas sales contract;

	•	various transactions fees related to the termination; and

	•	an agreed upon value for BWT’s membership interest in an EEX subsidiary.


†	Identifies management contracts and compensatory plans or arrangements.


	On March 16, 2004, we filed a current report on Form 8-K providing the information required by Regulation BTR with respect to our 401(k) plan.

	On February 13, 2004, we filed a current report on Form 8-K announcing our fourth quarter and full-year 2003 financial results and first quarter 2004 earnings guidance regarding production and significant operating and financial data. Additionally, we announced the issuance of our @NFX publication, which included an update on drilling activities during the fourth quarter and full-year 2003, guidance for the first quarter of 2004 and updated tables detailing complete hedging positions as of February 10, 2004.



	Terry W. Rathert
	Vice President and Chief Financial Officer
	(Authorized Officer and
	Principal Financial Officer)