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

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


[X]		QUARTERLY REPORT UNDER SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended June 30, 2004


[ ]		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 [X] No [ ]

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).

Yes [X] No [ ]

As of July 28, 2004, there were 56,673,606 shares of the Registrant’s Common Stock, par value $0.01 per share, outstanding.

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEET

(In thousands, except share data)

(Unaudited)


	June 30,			December 31,
	2004			2003
ASSETS
Current assets:
Cash and cash equivalents	$	27,853		$	15,347
Accounts receivable—oil and gas		184,359			134,774
Inventories		3,664			553
Derivative assets		12,031			13,786
Deferred taxes		25,431			12,893
Other current assets		43,371			61,563

Total current assets		296,709			238,916

Oil and gas properties (full cost method, of which $388,501 at June 30, 2004 and $331,114 at December 31, 2003 were excluded from amortization)		4,466,684			4,078,115
Less—accumulated depreciation, depletion and amortization		(1,864,889	)		(1,659,615	)

		2,601,795			2,418,500

Floating production system and pipelines		35,000			35,000
Furniture, fixtures and equipment, net		5,369			5,875
Derivative assets		3,228			2,223
Other assets		17,644			16,197
Goodwill		16,378			16,378

Total assets	$	2,976,123		$	2,733,089

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	19,799		$	30,556
Accrued liabilities		298,428			204,054
Advances from joint owners		20,677			5,922
Secured notes payable		—			2,895
Asset retirement obligation		10,380			12,095
Derivative liabilities		81,693			44,696

Total current liabilities		430,977			300,218

Derivative liabilities		13,190			13,244
Long-term debt		579,559			643,459
Asset retirement obligation		158,283			151,548
Deferred taxes		267,994			242,839
Other liabilities		13,040			13,203

Total long-term liabilities		1,032,066			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; 200,000,000 and 100,000,000 shares authorized at June 30, 2004 and December 31, 2003, respectively; 57,568,244 and 57,141,807 shares issued and outstanding at June 30, 2004 and December 31, 2003, respectively)		576			571
Additional paid-in capital		811,422			796,256
Treasury stock (at cost; 894,585 and 886,247 shares at June 30, 2004 and December 31, 2003, respectively)		(27,081	)		(26,679	)
Unearned compensation		(9,664	)		(10,912	)
Accumulated other comprehensive income (loss):
Foreign currency translation adjustment		1,124			851
Commodity derivatives		(43,538	)		(26,428	)
Minimum pension liability		(833	)		(833	)
Retained earnings		781,074			635,752

Total stockholders’ equity		1,513,080			1,368,578

Total liabilities and stockholders’ equity	$	2,976,123		$	2,733,089

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

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF INCOME

(In thousands, except per share data)

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2004			2003			2004			2003
Oil and gas revenues	$	282,737		$	255,552		$	588,092		$	523,443

Operating expenses:
Lease operating		28,965			26,917			58,830			54,724
Production and other taxes		9,094			7,463			17,453			17,670
Transportation		1,942			1,859			3,382			3,422
Depreciation, depletion and amortization		105,172			99,191			211,077			192,509
General and administrative (includes non-cash stock compensation of $969 and $807 for the three months ended June 30, 2004 and 2003, respectively, and $1,960 and $1,486 for the six months ended June 30, 2004 and 2003, respectively)		19,061			15,190			37,621			32,196
Gas sales obligation settlement and redemption of securities		—			10,477			—			20,475

Total operating expenses		164,234			161,097			328,363			320,996

Income from operations		118,503			94,455			259,729			202,447
Other income (expenses):
Interest expense		(11,935	)		(14,982	)		(24,467	)		(31,668	)
Capitalized interest		4,388			3,899			8,323			7,718
Dividends on convertible preferred securities of Newfield Financial Trust I		—			(2,245	)		—			(4,581	)
Commodity derivative expense		(5,594	)		(1,629	)		(17,835	)		(2,846	)
Other		340			(9	)		1,000			511

		(12,801	)		(14,966	)		(32,979	)		(30,866	)

Income from continuing operations before income taxes		105,702			79,489			226,750			171,581
Income tax provision:
Current		25,507			12,724			56,088			35,580
Deferred		12,781			13,710			25,340			23,600

		38,288			26,434			81,428			59,180

Income from continuing operations		67,414			53,055			145,322			112,401
Loss from discontinued operations, net of tax		—			(7,240	)		—			(8,020	)

Income before cumulative effect of change in accounting principle		67,414			45,815			145,322			104,381
Cumulative effect of change in accounting principle, net of tax:
Adoption of SFAS No. 143		—			—			—			5,575

Net income	$	67,414		$	45,815		$	145,322		$	109,956

Earnings per share:
Basic —
Income from continuing operations	$	1.20		$	1.00		$	2.59		$	2.13
Loss from discontinued operations		—			(0.14	)		—			(0.15	)
Cumulative effect of change in accounting principle, net of tax		—			—			—			0.11

Net income	$	1.20		$	0.86		$	2.59		$	2.09

Diluted —
Income from continuing operations	$	1.18		$	0.95		$	2.55		$	2.02
Loss from discontinued operations		—			(0.13	)		—			(0.14	)
Cumulative effect of change in accounting principle, net of tax		—			—			—			0.10

Net income	$	1.18		$	0.82		$	2.55		$	1.98

Weighted average number of shares outstanding for basic earnings per share		56,114			53,468			56,019			52,679

Weighted average number of shares outstanding for diluted earnings per share		57,029			57,701			56,884			56,956

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

NEWFIELD EXPLORATION COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)

(Unaudited)


	Six Months Ended
	June 30,
	2004			2003
Cash flows from operating activities:
Net income	$	145,322		$	109,956
Adjustments to reconcile net income to net cash provided by continuing operating activities:
Loss from discontinued operations, net of tax		—			8,020
Depreciation, depletion and amortization		211,077			192,509
Gas sales obligation settlement and redemption of securities		—			20,475
Stock compensation		1,960			1,486
Commodity derivative expense		9,511			2,846
Deferred taxes		25,340			23,600
Cumulative effect of change in accounting principle		—			(5,575	)
Changes in operating assets and liabilities:
Increase in accounts receivable — oil and gas		(49,587	)		(49,526	)
(Increase) decrease in inventories		(2,834	)		114
(Increase) decrease in other current assets		16,746			(4,264	)
(Increase) decrease in other assets		(1,446	)		2,546
Increase (decrease) in accounts payable and accrued liabilities		43,551			(27,106	)
Increase in advances from joint owners		14,754			823
Increase (decrease) in other liabilities		(133	)		945

Net cash provided by continuing activities		414,261			276,849
Net cash provided by discontinued activities		—			661

Net cash provided by operating activities		414,261			277,510

Cash flows from investing activities:
Additions to oil and gas properties		(347,409	)		(228,519	)
Additions to furniture, fixtures and equipment		(1,659	)		(2,302	)

Net cash used in continuing activities		(349,068	)		(230,821	)
Net cash used in discontinued activities		—			(3,155	)

Net cash used in investing activities		(349,068	)		(233,976	)

Cash flows from financing activities:
Proceeds from borrowings under credit arrangements		385,500			1,019,000
Repayments of borrowings under credit arrangements		(446,500	)		(915,000	)
Proceeds from issuances of common stock		11,321			137,683
Purchases of treasury stock		(402	)		(362	)
Repurchases of secured notes		(2,895	)		(59,595	)
Repayments of secured notes		—			(11,215	)
Deliveries under the gas sales obligation		—			(8,442	)
Gas sales obligation settlement		—			(62,017	)
Redemption of trust preferred securities		—			(148,448	)

Net cash used in continuing activities		(52,976	)		(48,396	)
Net cash provided by (used in) discontinued activities		—			—

Net cash used in financing activities		(52,976	)		(48,396	)

Effect of exchange rate changes on cash and cash equivalents		289			387

Increase (decrease) in cash and cash equivalents		12,506			(4,475	)
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	$	27,853		$	44,423

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 also include the U.S. onshore Gulf Coast, the Anadarko and Arkoma Basins, China’s Bohai Bay, the North Sea and Malaysia.

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.

In May 2004, we entered into production sharing contracts (PSCs) with Petroliam Nasional Berhad (“Petronas”), Malaysia’s state-owned oil company, in partnership with Petronas Carigali Sdn. Bhd. (“Petronas Carigali”), the exploration and production subsidiary of Petronas. See Note 12, “Acquisition.”

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.

Inventories

Inventories include international oil produced but not sold. Crude oil from our operations located offshore Malaysia is produced into a floating production, storage and off-loading vessel and sold periodically as a barge quantity is accumulated. The product inventory at June 30, 2004 consisted of approximately 248,000 barrels of crude oil valued at $2.7 million and is carried at the lower of average cost or market. Also included in inventories are materials and supplies, which also are stated at the lower of average cost or market.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Foreign Currency

The functional currency for our operations located in the United Kingdom is the British pound and the functional currency for our operations in Malaysia is the Malaysian ringgit. The functional currency for all other foreign operations is the U.S. dollar. Translation adjustments resulting from translating our United Kingdom subsidiaries’ British pound financial statements and our Malaysian subsidiaries’ Malaysian ringgit financial statements into U.S. dollars are included as other comprehensive income in our consolidated statement of stockholders’ equity. Gains and losses incurred on currency transactions in other than a country’s functional currency are included in the consolidated statement of income.

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 Statement of Financial Accounting Standards (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 six months ended June 30, 2004 is set forth below (in thousands):


Balance as of January 1, 2004	$	163,643
Accretion expense		4,478
Additions		2,257
Settlements		(1,715	)

Balance of ARO as of June 30, 2004	$	168,663

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 and six months ended June 30, 2004 and 2003 would have approximated the pro forma amounts below:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2004		2003		2004		2003
	(In thousands, except per share data)
Net income:
As reported	$	67,414	$	45,815	$	145,322	$	109,956
Pro forma		65,531		44,050		141,848		106,530
Basic earnings per common share —
As reported	$	1.20	$	0.86	$	2.59	$	2.09
Pro forma		1.17		0.82		2.53		2.03
Diluted earnings per common share —
As reported	$	1.18	$	0.82	$	2.55	$	1.98
Pro forma		1.15		0.79		2.49		1.92

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 and not as intangible assets after SFAS Nos. 141 and 142 became effective. In July 2004, the FASB proposed FSP FAS 142-b, “Application of FAS 142 to Oil and Gas Producing Entities.” The proposed FSP clarifies that the exception in paragraph 8(b) of SFAS No. 142, “Goodwill and Other Intangible Assets,” includes the balance sheet classification and disclosures for drilling and mineral rights of oil and gas producing entities. Accordingly, the FASB staff believes that the scope exception extends to the disclosure provisions of SFAS No. 142 for drilling and mineral rights of oil and gas producing entities. The consensus will be effective when the FSP is finalized.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

If SFAS Nos. 141 and 142 were applied as described above, as of June 30, 2004, we had undeveloped leasehold interests of approximately $143.5 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 $678.2 million (without reduction for depreciation, depletion and amortization) that would be classified on our consolidated balance sheet as “intangible developed leaseholds.”

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			Six Months
	Ended			Ended
	June 30, 2003			June 30, 2003
	(In thousands)
Revenues	$	—		$	11,393
Operating expenses⁽¹⁾		(6,988	)		(17,761	)

Income from operations		(6,988	)		(6,368	)
Other expense⁽²⁾		(3,081	)		(4,832	)

Loss before income taxes		(10,069	)		(11,200	)
Income tax benefit		2,829			3,180

Loss from discontinued operations	$	(7,240	)	$	(8,020	)

(1)		Operating expenses include a ceiling test writedown of $7.3 million recorded in June 2003 and a production tax credit recorded in the second quarter of 2003 due to a change in the estimate of Australian resource rent taxes for the period from July 2002 to June 2003.

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

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 dilutive impact of outstanding stock options (using the treasury stock method), unvested restricted stock awards to officers and employees and 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 any accrued distributions with respect to our trust preferred securities during any of the periods presented. 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 and six month periods ended June 30, 2004 and 2003:


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2004		2003			2004		2003
	(In thousands, except per share data)
Income (numerator):
Income from continuing operations	$	67,414	$	53,055		$	145,322	$	112,401
Loss from discontinued operations, net of tax		—		(7,240	)		—		(8,020	)

Income before cumulative effect of change in accounting principle		67,414		45,815			145,322		104,381
Cumulative effect of change in accounting principle, net of tax		—		—			—		5,575

Net income—basic		67,414		45,815			145,322		109,956
After-tax dividends on convertible trust preferred securities		—		1,459			—		2,978

Net income — diluted	$	67,414	$	47,274		$	145,322	$	112,934

Weighted average shares (denominator):
Weighted average shares — basic		56,114		53,468			56,019		52,679
Dilution effect of stock options and unvested restricted stock outstanding at end of period		915		467			865		432
Dilution effect of convertible trust preferred securities		—		3,766			—		3,845

Weighted average shares — diluted		57,029		57,701			56,884		56,956

Earnings per share:
Basic:
Income from continuing operations	$	1.20	$	1.00		$	2.59	$	2.13
Loss from discontinued operations		—		(0.14	)		—		(0.15	)
Cumulative effect of change in accounting principle, net of tax		—		—			—		0.11

Net income	$	1.20	$	0.86		$	2.59	$	2.09

Diluted:
Income from continuing operations	$	1.18	$	0.95		$	2.55	$	2.02
Loss from discontinued operations		—		(0.13	)		—		(0.14	)
Cumulative effect of change in accounting principle, net of tax		—		—			—		0.10

Net income	$	1.18	$	0.82		$	2.55	$	1.98

The calculation of shares outstanding for diluted EPS does not include the effect of outstanding stock options to purchase 89,400 and 853,450 shares for the three months ended June 30, 2004 and 2003, respectively, and 127,900 and 1,002,050 shares for the six months ended June 30, 2004 and 2003, respectively, because to do so would have been antidilutive.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

4. Oil and Gas Properties:

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


	June 30,			December 31,
	2004			2003
	(In thousands)
Subject to amortization	$	4,078,183		$	3,747,001
Not subject to amortization:
Exploration wells in progress		18,052			8,221
Development wells in progress		52,350			31,105
Capitalized interest		27,123			23,089
Fee mineral interests		23,333			23,298
Other capital costs:
Incurred in 2004		44,814			—
Incurred in 2003		60,370			71,063
Incurred in 2002		101,060			104,164
Incurred in 2001 and prior		61,399			70,174

Total not subject to amortization		388,501			331,114

Gross oil and gas properties		4,466,684			4,078,115
Accumulated depreciation, depletion and amortization		(1,864,889	)		(1,659,615	)

Net oil and gas properties	$	2,601,795		$	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 June 30, 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 historical and future 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:


	June 30,			December 31,
	2004			2003
	(In thousands)
Senior unsecured debt:
Bank revolving credit facility:
Prime rate based loans	$	—		$	—
LIBOR based loans		34,000			90,000

Total bank revolving credit facility		34,000			90,000
Money market lines of credit⁽¹⁾		—			5,000

Total credit arrangements		34,000			95,000

7.45% Senior Notes due 2007		124,842			124,821
Fair value of interest rate swaps⁽²⁾		(777	)		171
7 5/8% Senior Notes due 2011		174,910			174,905
Fair value of interest rate swaps⁽²⁾		(1,604	)		449

Total senior unsecured notes		297,371			300,346

Total senior unsecured debt		331,371			395,346

8 3/8% Senior Subordinated Notes due 2012		248,188			248,113

Total long-term debt	$	579,559		$	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 June 30, 2004 and December 31, 2003, the interest rate was 2.38% and 2.50%, respectively, for the 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 June 30, 2004) and 30% of the principal amount of any outstanding senior subordinated notes (a reduction of $75 million at June 30, 2004). The borrowing base is redetermined at least semi-annually and, after all required adjustments, was $500 million at June 30, 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 June 30, 2004, we had $466 million available under our credit facility and had outstanding borrowings of $34 million.

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.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 and redemption of securities” on our consolidated statement of income.

6. Redemption of Trust Preferred Securities:

We redeemed all of the outstanding 6 1/2% Cumulative Quarterly Income Convertible Preferred Securities of Newfield Financial Trust I on June 27, 2003 for an aggregate redemption price of approximately $148.4 million, or $38.31 on a per share of underlying common stock basis (excluding in each case accrued but unpaid distributions). The holders of only a small number of the securities elected to convert their securities into shares of our common stock prior to the redemption date (a total of 48,076 shares of common stock were issued). Included in the aggregate redemption price is $6.5 million of optional redemption premium. Upon redemption, this premium and $4.0 million of unamortized offering costs (which were being amortized over the 30-year life of the securities) were expensed under the caption “Gas sales obligation settlement and redemption of securities” on our consolidated statement of income.

We financed the redemption with the net proceeds from the issuance and sale of 3.5 million shares of our common stock on May 27, 2003 (approximately $131.2 million, or $37.49 per share) and borrowings under our revolving credit facility.

7. 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)

8. Geographic Information:


	United		United				Other
	States		Kingdom		Malaysia		International		Total
	(In thousands)
Three Months Ended June 30, 2004:
Oil and gas revenues	$	282,126	$	611	$	—	$	—	$	282,737
Operating expenses:
Lease operating		28,715		250		—		—		28,965
Production and other taxes		9,094		—		—		—		9,094
Transportation		1,942		—		—		—		1,942
Depreciation, depletion and amortization		104,872		300		—		—		105,172
Allocated income taxes		48,128		25		—		—

Net income from oil and gas properties	$	89,375	$	36	$	—	$	—

General and administrative (inclusive of stock compensation) ⁽¹⁾										19,061

Total operating expenses										164,234

Income from operations										118,503
Interest expense, net of interest income, capitalized interest and other										(7,207	)
Commodity derivative expense										(5,594	)

Income from continuing operations before income taxes									$	105,702

Total long-lived assets	$	2,490,208	$	12,472	$	51,971	$	47,144	$	2,601,795

Additions to long-lived assets	$	180,409	$	993	$	52,247	$	2,573	$	236,222

Three Months Ended June 30, 2003:
Oil and gas revenues	$	255,552	$	—	$	—	$	—	$	255,552
Operating expenses:
Lease operating		26,917		—		—		—		26,917
Production and other taxes		7,463		—		—		—		7,463
Transportation		1,859		—		—		—		1,859
Depreciation, depletion and amortization		99,191		—		—		—		99,191
Allocated income taxes		42,160		—		—		—

Net income from oil and gas properties	$	77,962	$	—	$	—	$	—

Gas sales obligation settlement and redemption of securities										10,477
General and administrative (inclusive of stock compensation) ⁽¹⁾										15,190

Total operating expenses										161,097

Income from operations										94,455
Interest expense and dividends, net of interest income, capitalized interest and other										(13,337	)
Commodity derivative expense										(1,629	)

Income from continuing operations before income taxes									$	79,489

Total long-lived assets	$	2,129,083	$	3,535	$	—	$	38,787	$	2,171,405

Additions to long-lived assets	$	109,315	$	880	$	—	$	2,716	$	112,911

(1)

General and administrative expense includes stock compensation charges of $969 and $807 for the three months ended June 30, 2004 and 2003, respectively.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


	United		United				Other
	States		Kingdom		Malaysia		International		Total
	(In thousands)
Six Months Ended June 30, 2004:
Oil and gas revenues	$	586,551	$	1,541	$	—	$	—	$	588,092
Operating expenses:
Lease operating		58,323		507		—		—		58,830
Production and other taxes		17,453		—		—		—		17,453
Transportation		3,382		—		—		—		3,382
Depreciation, depletion and amortization		210,425		652		—		—		211,077
Allocated income taxes		103,941		153		—		—

Net income from oil and gas properties	$	193,027	$	229	$	—	$	—

General and administrative (inclusive of stock compensation) ⁽¹⁾										37,621

Total operating expenses										328,363

Income from operations										259,729
Interest expense, net of interest income, capitalized interest and other										(15,144	)
Commodity derivative expense										(17,835	)

Income from continuing operations before income taxes									$	226,750

Total long-lived assets	$	2,490,208	$	12,472	$	51,971	$	47,144	$	2,601,795

Additions to long-lived assets	$	329,510	$	1,487	$	52,247	$	5,325	$	388,569

Six Months Ended June 30, 2003:
Oil and gas revenues	$	523,443	$	—	$	—	$	—	$	523,443
Operating expenses:
Lease operating		54,724		—		—		—		54,724
Production and other taxes		17,670		—		—		—		17,670
Transportation		3,422		—		—		—		3,422
Depreciation, depletion and amortization		192,509		—		—		—		192,509
Allocated income taxes		89,409		—		—		—

Net income from oil and gas properties	$	165,709	$	—	$	—	$	—

Gas sales obligation settlement and redemption of securities										20,475
General and administrative (inclusive of stock compensation) ⁽¹⁾										32,196

Total operating expenses										320,996

Income from operations										202,447
Interest expense and dividends, net of interest income, capitalized interest and other										(28,020	)
Commodity derivative expense										(2,846	)

Income from continuing operations before income taxes									$	171,581

Total long-lived assets	$	2,129,083	$	3,535	$	—	$	38,787	$	2,171,405

Additions to long-lived assets ⁽²⁾	$	330,801	$	2,147	$	—	$	3,831	$	336,779

(1)		General and administrative expense includes stock compensation charges of $1,960 and $1,486 for the six months ended June 30, 2004 and 2003, respectively.

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

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

9. 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 may also 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 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, for accounting purposes, 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 June 30, 2004, we had a net $43.5 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 $39.0 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.

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.” 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 gain of $0.9 million and a realized loss of $6.9 million on our three-way collar contracts for the three months ended June 30, 2004. We recorded an unrealized loss of $9.0 million and a realized loss of $8.3 million on our three-way collar contracts for the six months ended June 30, 2004.

Natural Gas

As of June 30, 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
			Swaps		Floors				Ceilings				Floor Contracts				Estimated 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)
July 2004 – September 2004
Price swap contracts		17,275	$	4.75		—		—		—		—		—		—	$	(25.3	)
Collar contracts		11,595		—	$3.00 – $5.25		$	4.68	$4.16 – $6.67		$	5.96		—		—		(5.9	)
Floor contracts		2,250		—		—		—		—		—	$4.20 – $4.21		$	4.21		—
October 2004 – December 2004
Price swap contracts		7,645		4.78		—		—		—		—		—		—		(11.6	)
Collar contracts		9,795		—	3.00 – 5.25			4.90	4.16 – 10.25			8.24		—		—		(3.2	)
Floor contracts		8,850		—		—		—		—		—	4.20 – 5.50			5.39		1.4
January 2005 – December 2005
Price swap contracts		5,440		4.43		—		—		—		—		—		—		(9.8	)
Collar contracts		16,530		—	3.50 – 5.77			5.20	4.16 – 10.25			9.53		—		—		(3.7	)
Floor contracts		5,400		—		—		—		—		—	5.47 – 5.50			5.49		1.5

																	$	(56.6	)

As of June 30, 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

Asset (Liability)

Period and Type of Contract

MMMBtus

Range

Average

Range

Average

Range

Average

(In millions)

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

(5.5

)

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

(2.2

)

(7.7

)

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Oil

As of June 30, 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
			Swaps		Floors				Ceilings				Estimated Fair Value
	Volume in		(Weighted				Weighted				Weighted		Asset (Liability)
Period and Type of Contract	Bbls		Average)		Range		Average		Range		Average		(In millions)
July 2004 – September 2004
Price swap contracts		264,000	$	32.18		—		—		—		—	$	(1.3	)
Collar contracts		390,000		—	$22.00 – $27.50		$	26.35	$26.35 – $34.50		$	31.56		(2.3	)
October 2004 – December 2004
Price swap contracts		204,000		29.85		—		—		—		—		(1.4	)
Collar contracts		330,000		—	27.00 – 27.50			27.14	30.65 – 34.50			32.51		(1.8	)
January 2005 – December 2005
Price swap contracts		294,000		24.90		—		—		—		—		(3.0	)
Collar contracts		390,000		—		27.00		27.00	30.65 – 32.30			31.64		(2.4	)

													$	(12.2	)

As of June 30, 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)
July 2004 – September 2004
3-Way collar contracts		379,000	$	21.00	$25.00 – $26.00		$	25.76	$29.70 – $30.05		$	29.91	$	(2.8	)
October 2004 – December 2004
3-Way collar contracts		379,000		21.00	25.00 – 26.00			25.76	29.70 – 30.05			29.91		(2.8	)
January 2005 – December 2005
3-Way collar contracts		90,000		21.00		25.00		25.00		29.70		29.70		(0.7	)

													$	(6.3	)

10. Accrued Liabilities:

As of the indicated dates, our accrued liabilities consisted of the following:


	June 30,		December 31,
	2004		2003
	(In thousands)
Revenue payable	$	89,941	$	59,737
Accrued capital costs		93,907		70,464
Accrued lease operating expenses		17,590		20,402
Employee incentive payable		27,020		24,292
Accrued interest on notes		14,203		14,332
Accrued federal income taxes		19,004		—
Accrued ad valorem taxes		3,194		3,462
Deferred acquisition payment		10,500		—
Other		23,069		11,365

Total accrued liabilities	$	298,428	$	204,054

NEWFIELD EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

11. Increase in Authorized Shares of Common Stock:

In May 2004, we amended our Second Restated Certificate of Incorporation to increase the authorized number of shares of our common stock that we have authority to issue from 100,000,000 to 200,000,000. The increase in authorized shares will not, by itself, have any effect on the rights of holders of presently issued and outstanding shares of our common stock. However, the issuance of additional shares of our common stock may, among other things, have a dilutive effect on earnings per share and on equity and voting rights of the present holders of our common stock.

12. Acquisition:

In May 2004, we entered into PSCs with Petronas, Malaysia’s state-owned oil company, in partnership with Petronas Carigali, the exploration and production subsidiary of Petronas. The PSCs relate to two blocks – PM 318 and deepwater Block 2C. The consideration for our interests under the PSCs is comprised of a one-time reimbursement by us of sunk costs of $38.5 million and a deferred payment of $10.5 million.

Petronas Carigali will operate the PSC for PM 318, which consists of approximately 400,000 acres, located offshore Peninsular Malaysia. Within the boundaries of PM 318, we also are participating in the development of two recently productive shallow water fields. We have a 50% interest in PM 318. The deepwater Block 2C covers more than 1.1 million acres offshore Sarawak and is operated by us with a 60% interest. Together with our partner, we will acquire and evaluate 3-D seismic data in the next 12 months and are targeting initial drilling in 2005.

13. Subsequent Events:

On July 8, 2004, we acquired oil and gas producing assets located in northeast Oklahoma from a private company for total consideration of approximately $42 million. The acquisition was financed through cash on hand and borrowings under our credit arrangements.

On July 20, 2004, we acquired all of the outstanding stock of Denbury Offshore, Inc., the subsidiary of Denbury Resources Inc. that holds all of its Gulf of Mexico assets. After purchase price adjustments, total consideration is expected to be approximately $187 million, inclusive of the purchase of approximately $5 million in working capital. The transaction adds approximately 50 MMcfe per day of net gas production, of which 97 percent is natural gas. The acquisition was financed through cash on hand and borrowings under our credit arrangements.

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, the North Sea and Malaysia.

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 our 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 among the assets of acquired companies; 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 second quarter of 2004 were about 11% higher than the comparable period of 2003 because of higher commodity prices and higher gas production. Revenues for the first six months of 2004 were 12% higher than the same period of the prior year due to higher commodity prices and higher gas production.


	Three Months Ended							Six Months Ended
	June 30,				Percentage Increase			June 30,				Percentage Increase
	2004		2003		(Decrease)			2004		2003		(Decrease)
Production⁽¹⁾:
Natural gas (Bcf)		47.5		46.8		1	%		95.5		90.8		5	%
Oil and condensate (MBbls)		1,422.2		1,579.4		(10	%)		2,968.8		3,095.7		(4	%)
Total (Bcfe) ⁽²⁾		56.0		56.2		—			113.3		109.3		4	%
Average Realized Prices⁽³⁾:
Natural gas (per Mcf)	$	4.89	$	4.50		9	%	$	5.10	$	4.77		7	%
Oil and condensate (per Bbl)		34.18		27.54		24	%		32.87		28.27		16	%
Natural gas equivalent (per Mcfe)		5.02		4.51		11	%		5.16		4.76		8	%

(1)		Represents volumes sold or lifted regardless of when produced.

(2)		The three and six month periods ended June 30, 2004 include 0.2 Bcfe and 0.4 Bcfe, respectively, related to our North Sea operations. There had been no liftings as of June 30, 2004 with respect to our Malaysian operations.

(3)		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 $0.03 and $0.02 per Mcf for the three months ended June 30, 2004 and 2003, respectively, and by $0.02 per Mcf for the six months ended June 30, 2004 and 2003. The realized price of oil and condensate was reduced by $0.46 and $0.45 per Bbl for the three months ended June 30, 2004 and 2003, respectively, and by $0.39 per Bbl for the six months ended June 30, 2004 and 2003. Average realized prices also 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 contracts, our average realized price for natural gas would have been $4.82 per Mcf and our average realized price for oil and condensate would have been $31.95 per Bbl for the second quarter of 2004 and $5.06 per Mcf and $31.30 per Bbl for the six months ended June 30, 2004.

Production. Our total oil and gas production (stated on a natural gas equivalent basis) remained flat for the second quarter of 2004 and increased 4% for the six months ended June 30, 2004 when compared to the same periods in 2003.

Natural Gas. Our second quarter and first six months of 2004 natural gas production increased primarily because of our successful drilling efforts during the second half of 2003 and our acquisition of Primary Natural Resources in September 2003. This increase was offset by natural field declines in our Gulf of Mexico properties.

Crude Oil and Condensate. Our domestic oil production for the second quarter and the first half of 2004 as compared to the same periods of the prior year decreased primarily due to natural field declines in our Gulf of Mexico properties.

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 June 30, 2004	$	4.89	$	5.46		90	%
Three months ended June 30, 2003		4.50		5.23		86	%
Six months ended June 30, 2004		5.10		5.45		94	%
Six months ended June 30, 2003		4.77		5.75		83	%
Crude Oil and Condensate:
Three months ended June 30, 2004	$	34.18	$	36.80		93	%
Three months ended June 30, 2003		27.54		28.30		97	%
Six months ended June 30, 2004		32.87		35.39		93	%
Six months ended June 30, 2003		28.27		30.34		93	%

(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 recurring operating expenses have increased with our growth. As a result, we believe the most informative way to analyze changes in our recurring 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 second quarter of 2004 and 2003.


	Unit-of-Production							Amount
	(Per Mcfe)							(In thousands)
	Three Months Ended							Three Months Ended
	June 30,				Percentage Increase			June 30,				Percentage Increase
	2004		2003		(Decrease)			2004		2003		(Decrease)
Lease operating	$	0.52	$	0.48		8	%	$	28,965	$	26,917		8	%
Production and other taxes		0.16		0.13		23	%		9,094		7,463		22	%
Transportation		0.03		0.03		—			1,942		1,859		4	%
Depreciation, depletion and amortization		1.88		1.76		7	%		105,172		99,191		6	%
General and administrative ⁽¹⁾		0.34		0.27		26	%		19,061		15,190		25	%
Gas sales obligation settlement and redemption of securities		—		0.19		(100	%)		—		10,477		(100	%)
Total operating expenses		2.93		2.86		2	%		164,234		161,097		2	%
Total operating expenses excluding non-recurring items ⁽²⁾		2.93		2.68		9	%		164,234		150,620		9	%

(1)		Includes stock compensation charges of $969, or $0.02 per Mcfe, and $807, or $0.01 per Mcfe, for the three months ended June 30, 2004 and 2003, respectively.

(2)		Excludes the expenses associated with the redemption of our trust preferred securities in June 2003. See “-Redemption of Trust Preferred Securities” below.

Our total operating expenses (excluding the redemption of securities) for the second quarter of 2004, stated on an Mcfe basis, increased 9% over the same period in 2003. The increase was primarily related to the following items:

• Lease operating expense (LOE) on an Mcfe basis in the second quarter of 2004 was more than LOE in the same period of the prior year as a result of natural field declines in our Gulf of Mexico properties.

• Production taxes on an Mcfe basis increased in the second quarter of 2004 due to higher commodity prices when compared to the same period of last year.

• Depreciation, depletion and amortization (DD&A) (excluding furniture, fixtures and equipment) for the second quarter of 2004 was $1.86 per Mcfe versus $1.74 for the comparable period of 2003. The increase primarily resulted from the increased cost of reserve additions during the last half of 2003 and the first half of 2004. Included in the DD&A rate per unit-of-production is the accretion expense related to SFAS No. 143 of $0.04 per Mcfe for the second quarter of 2004 and $0.03 per Mcfe for the same period of 2003.

• General and administrative (G&A) expense increased primarily due to an increase in incentive compensation expense as a result of the increase in 2004 earnings over the same period of 2003, an increase in consultant fees related to compliance with Sarbanes-Oxley Section 404 and some non-recurring expenses associated with upgrades to our business systems. During the second quarter of 2004, we capitalized $9.2 million of direct internal costs compared to $7.4 million in the second quarter of 2003.

The following table presents information about our operating expenses for the first six months of 2004 and 2003.


	Unit-of-Production							Amount
	(Per Mcfe)							(In thousands)
	Six Months Ended							Six Months Ended
	June 30,				Percentage Increase			June 30,				Percentage Increase
	2004		2003		(Decrease)			2004		2003		(Decrease)
Lease operating	$	0.52	$	0.50		4	%	$	58,830	$	54,724		8	%
Production and other taxes		0.15		0.16		(6	%)		17,453		17,670		(1	%)
Transportation		0.03		0.03		—			3,382		3,422		(1	%)
Depreciation, depletion and amortization		1.86		1.76		6	%		211,077		192,509		10	%
General and administrative ⁽¹⁾		0.33		0.29		14	%		37,621		32,196		17	%
Gas sales obligation settlement and redemption of securities		—		0.19		(100	%)		—		20,475		(100	%)
Total operating expenses		2.90		2.94		(1	%)		328,363		320,996		2	%
Total operating expenses excluding non-recurring items ⁽²⁾		2.90		2.75		5	%		328,363		300,521		9	%

(1)		Includes stock compensation charges of $1,960, or $0.02 per Mcfe, and $1,486, or $0.01 per Mcfe, for the six months ended June 30, 2004 and 2003, respectively.

(2)		Excludes the expenses associated with the gas sales obligation settlement and the redemption of our trust preferred securities during the first six months of 2003. See “-Gas Sales Obligation Settlement” and “-Redemption of Trust Preferred Securities” below.

Our total operating expenses (excluding the gas sales obligation settlement and redemption of securities) for the first six months of 2004, stated on an Mcfe basis, increased 5% over the same period in 2003. The increase was primarily related to the following items:

• LOE on an Mcfe basis for the first six months of 2004 increased over the same period of the prior year primarily because of natural field declines in our Gulf of Mexico properties.

• Production taxes on an Mcfe basis were lower in the first six months of 2004 as a result of production tax exemptions related to certain of our onshore high cost gas wells partially offset by higher realized oil prices.

• DD&A (excluding furniture, fixtures and equipment) for the first six months of 2004 was $1.84 per Mcfe versus $1.74 for the comparable period of 2003. The increase primarily resulted from the increased cost of reserve additions during the last half of 2003 and the first half of 2004. Included in the DD&A rate per unit-of-production is the accretion expense related to SFAS No. 143 of $0.04 per Mcfe for the first six months of 2004 and $0.03 per Mcfe for the same period of 2003.

• G&A expense increased primarily due to an increase in incentive compensation expense as a result of the increase in 2004 earnings over the same period of 2003, an increase in consultant fees related to compliance with Sarbanes-Oxley Section 404 and some non-recurring expenses associated with upgrades to our business systems. During the first half of 2004, we capitalized $16.0 million of direct internal costs, as compared to $14.2 million in the first half 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.

Redemption of Trust Preferred Securities. We redeemed all of the outstanding 6 1/2% Cumulative Quarterly Income Convertible Preferred Securities of Newfield Financial Trust I on June 27, 2003 for an aggregate redemption price of approximately $148.4 million, or $38.31 on a per share of underlying common stock basis (excluding in each case accrued but unpaid distributions). The holders of only a small number of the securities elected to convert their securities into shares of our common stock prior to the redemption date (a total of 48,076 shares of common stock were issued). Included in the aggregate redemption price is $6.5 million of optional redemption premium. Upon redemption, this premium and $4.0 million of unamortized offering costs (which were being amortized over the 30-year life of the securities) were expensed under the caption “Gas sales obligation settlement and redemption of securities” on our consolidated statement of income.

Interest Expense. The following table presents information about our interest expense for the second quarter of 2004 and the first six months of 2004 compared to the same periods of the prior year.


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2004			2003			2004			2003
				(In millions)
Gross interest expense	$	11.9		$	15.0		$	24.5		$	31.7
Capitalized interest		(4.4	)		(3.9	)		(8.3	)		(7.7	)

Net interest expense		7.5			11.1			16.2			24.0
Distributions on preferred securities		—			2.2			—			4.6

Total interest expense and distributions	$	7.5		$	13.3		$	16.2		$	28.6

Our total interest expense and distributions decreased about 44% in the second quarter and the first six months of 2004 compared to the same periods in 2003 due to the repayment of debt with excess cash flow from operations, the redemption of our trust preferred securities in June 2003 primarily with the net proceeds from an offering of our common stock and the favorable impact from our interest rate swaps.

Commodity Derivative Expense. The following table presents information about the components of commodity derivative expense for the second quarter of 2004 and the first six months of 2004 compared to the same periods of the prior year.


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2004			2003			2004			2003
	(In millions)
Cash Flow Hedges:
Hedge ineffectiveness	$	0.4		$	(1.6	)	$	(0.5	)	$	(2.8	)
Other Commodity Contracts:
Unrealized gain (loss) due to changes in fair market value		0.9			—			(9.0	)		—
Realized loss on settlement		(6.9	)		—			(8.3	)		—

	$	(5.6	)	$	(1.6	)	$	(17.8	)	$	(2.8	)

The unrealized income (expense) related to our cash flow hedges represents the hedge ineffectiveness associated with our hedging contracts that qualify for hedge accounting under SFAS No. 133. All of the changes in the items related to our other commodity contracts are associated with our three-way collar contracts that do not qualify for hedge accounting. The unrealized gain (loss) represents changes in the fair market value of our open three-way collar contracts and the realized loss on the settlement of the contracts during the periods presented.

Taxes. The effective tax rate for the second quarter of 2004 and 2003 was 36.2% and 33.3%, respectively. The effective tax rate for the first six months of 2004 and 2003 was 35.9% and 34.5%, respectively. 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 and six months ended June 30, 2003 are summarized in Note 2, “Discontinued Operations,” to our consolidated financial statements appearing earlier in this report.

Liquidity and Capital Resources

Substantial capital is required to replace and grow reserves. Without the addition of new reserves, our production and revenues will decline rapidly. We establish a capital budget at the beginning of each calendar year based on expected cash flow from operations for that year. In the past, we often have revised our capital budget upward several times during the year as the result of acquisitions or successful drilling. 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 flows from operations.

During the first six months of 2004 our cash flow from operations exceeded our capital expenditures (including the acquisition of our Malaysian PSCs). We used the excess cash flow to pay down a portion of our outstanding debt under our credit arrangements (see “-Credit Arrangements” and “-Cash Flows from Continuing Operations” below and Note 5, “Debt,” to our consolidated financial statements appearing earlier in this report).

Cash Flows from Continuing Operations. Our net cash flows from continuing operations for the first six months of 2004 increased 50% compared to the first six months of 2003. The increase was primarily due to increased operating income and the timing of working capital requirements during the first six months of 2004.

Capital Expenditures. Our capital spending during the first six months of 2004 was $389 million, a 74% increase over the same period last year. During the first six months of 2004, we invested $244 million in domestic development, $59 million in domestic exploration, $27 million in other domestic leasehold activity and $59 million internationally. The international capital spending included $49 million related to the acquisition of our Malaysian PSCs. In July 2004, we acquired Denbury Offshore, Inc. for total consideration of $187 million. The acquisition was financed through cash on hand and borrowings under our credit arrangements.

Our current budget for capital spending in 2004 is $1.0 billion, including the acquisition of our Malaysian PSCs, the property acquisition in Oklahoma and the acquisition of Denbury Offshore, Inc. 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. Based on current commodity prices and the high percentage of our anticipated remaining 2004 production that has been hedged, we anticipate that our capital expenditure budget for the second half of 2004 (excluding the acquisition of Denbury Offshore, Inc.) will be funded by cash flows from operations.

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.

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 July 27, 2004) and 30% of the principal amount of any outstanding senior subordinated notes (a reduction of $75 million at July 27, 2004). The borrowing base is redetermined at least semi-annually and, after all required adjustments, was $500 million at July 27, 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 July 27, 2004, we had $241 million available under our credit facility and had outstanding borrowings of $259 million.

We also have money market lines of credit with various banks in an amount limited by our credit facility to $50 million. At July 27, 2004, we had $6.0 million outstanding under our money market lines of credit. Consequently, at July 27, 2004, we had approximately $285 million of available capacity under our credit arrangements.

At June 30, 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.

Working Capital. Our working capital balance fluctuates as a result of the timing and amount of borrowings or repayments under our credit arrangements and the fair market value changes associated with our open derivative contracts. 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 $134.3 million as of June 30, 2004. This compares to a working capital deficit of $61.3 million as of December 31, 2003.

Cash Flows from Financing Activities. Net cash flows used in financing activities for the first half of 2004 were $53.0 million compared to cash flows used in financing activities of $48.4 million for the same period of 2003. During the first half of 2004, we repaid a net $61.0 million under our credit arrangements. During the first half of 2003, we borrowed a net $104 million under our revolving credit arrangements, repaid or repurchased $70.8 million principal amount of our secured notes and settled our gas sales contract obligation for $62.0 million. In addition, we redeemed all of our outstanding trust preferred securities in June 2003 for an aggregate redemption price of approximately $148.4 million. We financed the redemption with the net proceeds from the issuance and sale of 3.5 million shares of our common stock (approximately $131.2 million) and borrowings under our credit arrangements. For a further discussion of these transactions, please see “—Results of Operations—Redemption of Trust Preferred Securities.”

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.

Please see the discussion and tables in Note 9, “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 June 30, 2004 and the fair value of those contracts as of that date.

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.

Issuer Purchases of Equity Securities

The following table sets forth certain information with respect to repurchases of our equity securities during the six months ended June 30, 2004.

Maximum Number

Total Number

(or Approximate)

of Shares Purchased

Dollar Value) of

as Part of Publicly

Shares that May Yet

Total Number

Average Price

Announced Plans

Be Purchased Under

Period

of Shares Purchased

Paid per Share

or Programs

the Plans or Programs

January 1 – June 30, 2004

8,338

48.18

—

*All of the indicated shares were surrendered by employees to pay tax withholding upon the vesting of restricted stock.

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 or 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 Securities and Exchange Commission.

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 industry.

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 other liquid hydrocarbons.

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 other liquid hydrocarbons.

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 9, “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 June 30, 2004 and the fair value of those contracts as of that date.

Interest Rates

Inclusive of interest rate swaps, at June 30, 2004, we had $446 million in long-term fixed rate debt and $134 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 such 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 June 30, 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 June 30, 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 six months ended June 30, 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 4. Submission of Matters to a Vote of Security Holders

At the May 6, 2004 Annual Meeting of Stockholders, our stockholders voted on four matters. As of the March 19, 2004 record date, 56,338,835 shares of common stock were outstanding and entitled to vote at the meeting.

(1) Election of Eleven Directors:

Our stockholders elected the eleven nominees for director by the following vote:


Nominee Elected	For		Withheld
Joe B. Foster		54,039,992		533,918
David A. Trice		54,090,602		483,308
David F. Schaible		54,090,604		483,306
Charles W. Duncan, Jr.		54,090,262		483,648
Howard H. Newman		53,433,141		1,140,769
Thomas G. Ricks		53,915,126		658,784
Dennis R. Hendrix		54,250,761		323,149
C. E. (Chuck) Shultz		54,136,804		437,106
Philip J. Burguieres		51,512,580		3,061,330
Claire S. Farley		54,062,185		511,725
John Randolph Kemp III		54,249,950		323,960

(2) Approval of the Newfield Exploration Company 2004 Omnibus Stock Plan:

Our stockholders approved the Newfield Exploration Company 2004 Omnibus Stock Plan by the following vote:


		Abstentions and
For	Against	Broker Non-Votes
42,989,998	5,984,434	5,599,478

(3) Amendment to Second Restated Certificate of Incorporation to Increase Authorized Shares:

Our stockholders approved an amendment to our certificate of incorporation to increase the number of shares of our common stock that we are authorized to issue to 200,000,000 from 100,000,000 by the following vote:


		Abstentions and
For	Against	Broker Non-Votes
50,079,916	4,464,075	29,919

(4) Appointment of Independent Public Accountants:

Our stockholders ratified the appointment of PricewaterhouseCoopers LLP as our independent accountants for 2004 by the following vote:


		Abstentions and
For	Against	Broker Non-Votes
53,224,459	1,329,823	19,628

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits:


Exhibit Number		Description
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

(b) Reports on Form 8-K:

On June 15, 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 June 10, 2004, we filed a Current Report on Form 8-K to furnish our press release of that date announcing the issuance of our @NFX publication, which included updated tables summarizing our hedging positions as of June 8, 2004.

On April 29, 2004, we filed a Current Report on Form 8-K to furnish our press release dated April 28, 2004 announcing our first quarter 2004 financial results and second quarter 2004 earnings guidance.

On April 22, 2004, we filed a Current Report on Form 8-K to furnish our press release of that date announcing that we had signed letters of intent to drill a Treasure Island wildcat well.



																		Accumulated
	Common Stock				Treasury Stock						Additional Paid-in		Unearned			Retained		Other Comprehensive			Total Stockholders’
	Shares		Amount		Shares			Amount			Capital		Compensation			Earnings		Income (Loss)			Equity
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		412,869		5								11,316										11,321
Issuance of restricted stock, less amortization of $82 and cancellations		13,568										712		(630	)							82
Treasury stock, at cost						(8,338	)		(402	)												(402	)
Amortization of stock compensation														1,878								1,878
Tax benefit from exercise of stock options												3,138										3,138
Comprehensive income:
Net income																	145,322					145,322
Foreign currency translation adjustment, net of tax of ($147)																			273			273
Reclassification adjustments for settled hedging positions, net of tax of $11,953																			(22,199	)		(22,199	)
Changes in fair value of outstanding hedging positions, net of tax of ($2,740)																			5,089			5,089

Total comprehensive income																						128,485

Balance, June 30, 2004		57,568,244	$	576		(894,585	)	$	(27,081	)	$	811,422	$	(9,664	)	$	781,074	$	(43,247	)	$	1,513,080


	NEWFIELD EXPLORATION COMPANY
Date: July 30, 2004	By:	/s/ TERRY W. RATHERT
		Terry W. Rathert
		Vice President and Chief Financial Officer (Authorized Officer and Principal Financial Officer)

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	Page
PART I
Item 1. Unaudited Financial Statements:
Consolidated Balance Sheet as of June 30, 2004 and December 31, 2003		1
Consolidated Statement of Income for the three and six months ended June 30, 2004 and 2003		2
Consolidated Statement of Cash Flows for the six months ended June 30, 2004 and 2003		3
Consolidated Statement of Stockholders’ Equity for the six months ended June 30, 2004		4
Notes to Consolidated Financial Statements		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		19
Item 3. Quantitative and Qualitative Disclosures About Market Risk		27
Item 4. Controls and Procedures		27
PART II
Item 4. Submission of Matters to a Vote of Security Holders		28
Item 6. Exhibits and Reports on Form 8-K		29
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

•		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.

•		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.

•		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 among the assets of acquired companies; and

•		the valuation of our derivative positions.

•		Lease operating expense (LOE) on an Mcfe basis in the second quarter of 2004 was more than LOE in the same period of the prior year as a result of natural field declines in our Gulf of Mexico properties.

•		Production taxes on an Mcfe basis increased in the second quarter of 2004 due to higher commodity prices when compared to the same period of last year.

•		Depreciation, depletion and amortization (DD&A) (excluding furniture, fixtures and equipment) for the second quarter of 2004 was $1.86 per Mcfe versus $1.74 for the comparable period of 2003. The increase primarily resulted from the increased cost of reserve additions during the last half of 2003 and the first half of 2004. Included in the DD&A rate per unit-of-production is the accretion expense related to SFAS No. 143 of $0.04 per Mcfe for the second quarter of 2004 and $0.03 per Mcfe for the same period of 2003.

•		General and administrative (G&A) expense increased primarily due to an increase in incentive compensation expense as a result of the increase in 2004 earnings over the same period of 2003, an increase in consultant fees related to compliance with Sarbanes-Oxley Section 404 and some non-recurring expenses associated with upgrades to our business systems. During the second quarter of 2004, we capitalized $9.2 million of direct internal costs compared to $7.4 million in the second quarter of 2003.

•		LOE on an Mcfe basis for the first six months of 2004 increased over the same period of the prior year primarily because of natural field declines in our Gulf of Mexico properties.

•		Production taxes on an Mcfe basis were lower in the first six months of 2004 as a result of production tax exemptions related to certain of our onshore high cost gas wells partially offset by higher realized oil prices.

•		DD&A (excluding furniture, fixtures and equipment) for the first six months of 2004 was $1.84 per Mcfe versus $1.74 for the comparable period of 2003. The increase primarily resulted from the increased cost of reserve additions during the last half of 2003 and the first half of 2004. Included in the DD&A rate per unit-of-production is the accretion expense related to SFAS No. 143 of $0.04 per Mcfe for the first six months of 2004 and $0.03 per Mcfe for the same period of 2003.

•		G&A expense increased primarily due to an increase in incentive compensation expense as a result of the increase in 2004 earnings over the same period of 2003, an increase in consultant fees related to compliance with Sarbanes-Oxley Section 404 and some non-recurring expenses associated with upgrades to our business systems. During the first half of 2004, we capitalized $16.0 million of direct internal costs, as compared to $14.2 million in the first half of 2003.