Newfield Exploration (NFX) 8-K Entry into a Material Definitive Agreement

Exhibit 99.2

NEWFIELD REPORTS FOURTH QUARTER AND FULL-YEAR RESULTS**
Company Raises 2005 Production Guidance

FOR IMMEDIATE RELEASE

     Houston –(February 9, 2005) — Newfield Exploration Company (NYSE:NFX)today announced financial and operating results for the fourth quarter and full-year 2004. A conference call to discuss the results is planned for 8:30 a.m. (CST), Thursday, February 10. To participate in the call, dial 719-457-2680. A listen-only broadcast will also be provided over the Internet. Simply go to the Investor Relations section athttp://www.newfld.com.

Highlights include:

•   Increased 2004 production volumes 10%. Company today raised 2005 production guidance to 262-272 Bcfe, an increase of 8-12% over 2004 production.

•   Added 725 Bcfe of proved reserves, nearly three times 2004 production. Reserves increased 35% to 1.78 Tcfe. Approximately 70% of proved reserves now located onshore.

•   Acquisitions continue diversification of assets, create balanced portfolio. Invested approximately $900 million in acquisitions in 2004. Largest transaction was the $575 million Inland Resources acquisition, adding 326 Bcfe of proved reserves and establishing a new focus area in Rocky Mountains.

•   Signed ventures to drill two ultra-deep exploration wells in our Treasure Project, located on the Gulf of Mexico shelf. First well – Blackbeard West – spud Feb. 9. Newfield has a 23% interest and substantially all of the costs are carried by partners.

•   Announced 2005 capital budget of $950 million. About $280 million earmarked for exploration across diverse drilling inventory. Total program includes about 500 wells.

Fourth Quarter 2004 Financial Results

     For the fourth quarter of 2004, Newfield reported net income of $90 million, or $1.43 per share (all per share amounts are on a diluted basis). Earnings in the quarter were negatively affected by the two items listed below. Without the effect of these items, earnings in the quarter would have been $123 million, or $1.96 per share.

•   As previously announced, Newfield fully wrote off the $35 million book value associated with the Enserch Garden Banks floating production facility (EGB) and related pipelines and processing facility. As a result, an after-tax net charge of $23 million, or $0.36 per diluted share, was recorded in the fourth quarter of 2004.

•   A ceiling test writedown of $10 million, or $0.16 per diluted share, was recorded for the remaining dry hole expenses in the fourth quarter associated with the Cumbria Prospect in the U.K. North Sea.

     Revenues in the fourth quarter of 2004 were $437 million. Net cash provided by operating activities before changes in operating assets and liabilities was $304 million in the fourth quarter of 2004. SeeExplanation and Reconciliation of Non-GAAP Financial Measures.

     Net income from continuing operations in the fourth quarter of 2003 was $40 million, or $0.71 per share. Revenues in the fourth quarter of 2003 were $245 million. Net cash provided by continuing operating activities before changes in operating assets and liabilities was $195 million in the fourth quarter of 2003.

     Newfield’s production in the fourth quarter of 2004 was 69.5 billion cubic feet equivalent (Bcfe), a 26% increase over production of 55.1 Bcfe in the fourth quarter of 2003. The following tables detail production and average realized prices for the fourth quarter of 2004 and 2003.

Quarterly Production

For the Three Months Ended December 31

	4Q04		4Q03		% Change
United States
Natural gas (Bcf)		53.8		46.1		17	%
Oil and condensate (MMBbls)		2.1		1.5		40	%
International(1)
Natural gas (Bcf)		0.1		—
Oil and condensate (MMBbls)		0.5		—
Total
Natural gas (Bcf)		53.9		46.1		17	%
Oil and condensate (MMBbls)		2.6		1.5		73	%
Total (Bcfe)		69.5		55.1		26	%

Average Realized Prices⁽²⁾
For the Three Months Ended December 31

	4Q04		4Q03		% Change
United States
Natural gas (per Mcf)	$	6.10	$	4.39		39	%
Oil and condensate (per Bbl)	$	40.81	$	27.47		49	%
International
Natural gas (per Mcf)	$	6.15		—
Oil and condensate liftings (per Bbl)	$	42.51		—
Total
Natural gas (per Mcf)	$	6.10	$	4.39		39	%
Oil and condensate (per Bbl)	$	41.12	$	27.47		50	%
Total (per Mcfe)	$	6.27	$	4.42		42	%

⁽¹⁾ Represents volumes sold regardless of when produced.

⁽²⁾ Prices shown are net of all applicable transportation expense. Domestic 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 collar contracts, our average realized price for total natural gas would have been $6.09 per Mcf and our average realized price for total oil and condensate would have been $38.44 per Bbl for the fourth quarter of 2004. No three-way contracts were settled in the fourth quarter of 2003.

     Stated on a unit of production basis, Newfield’s lease operating expense (LOE) in the fourth quarter of 2004 was $0.68 per Mcfe compared to LOE from continuing operations of $0.61 per Mcfe in the same period of 2003. Production and other taxes in the fourth quarter of 2004 increased to $0.17 per Mcfe compared to production and other taxes from continuing operations of $0.12 per Mcfe in the same period of 2003. DD&A expense in the fourth quarter of 2004 was $2.04 per Mcfe compared to DD&A expense from continuing operations of $1.84 per Mcfe in the same period of 2003. G&A expense in the fourth quarter of 2004 was $0.35 per Mcfe compared to G&A expense from continuing operations of $0.28 per Mcfe in the same period of 2003. G&A expense in the fourth quarter of 2004 is net of capitalized direct internal costs of $9 million. Capitalized direct internal costs were $6 million in the fourth quarter of 2003.

     Capital expenditures in the fourth quarter of 2004 were $238 million.

Full-Year 2004 Financial Results

     For 2004, Newfield posted net income of $312 million, or $5.26 per share. Revenues for 2004 were $1.35 billion. This compares to net income from continuing operations of $211 million, or $3.77 per share, on revenues of $1.02 billion. Net cash provided by continuing operating activities before changes in operating assets and liabilities was $965 million in 2004 compared to $734 million in the same period of 2003. SeeExplanation and Reconciliation of Non-GAAP Financial Measures.

     Production volumes for 2004 increased 10% over the same period last year. The Company produced 243.6 Bcfe in 2004 compared to production from continuing operations of 220.6 Bcfe in the prior year. The following tables detail production and average realized prices for 2004 and 2003:

Full-Year Production
For the Year Ended December 31

	2004		2003		%Change
United States
Natural gas (Bcf)		197.6		184.2		7	%
Oil and condensate (MMBbls)		6.7		6.1		10	%
International(1)
Natural gas (Bcf)		0.6		—
Oil and condensate (MMBbls)		0.9		—
Total
Natural gas (Bcf)		198.2		184.2		8	%
Oil and condensate (MMBbls)		7.6		6.1		25	%
Total (Bcfe)		243.6		220.6		10	%

Average Realized Prices⁽²⁾

For the Year Ended December 31

	2004		2003		% Change
United States
Natural gas (per Mcf)	$	5.37	$	4.58		17	%
Oil and condensate (per Bbl)	$	36.37	$	27.65		32	%
International
Natural gas (per Mcf)	$	4.38		—
Oil and condensate liftings (per Bbl)	$	44.26		—
Total
Natural gas (per Mcf)	$	5.37	$	4.58		17	%
Oil and condensate (per Bbl)	$	37.29	$	27.65		35	%
Total (per Mcfe)	$	5.53	$	4.58		21	%

⁽¹⁾ Represents volumes sold regardless of when produced.

⁽²⁾ Prices shown are net of all applicable transportation expense. Domestic average realized prices include the effects of hedging other than our three-way collar contracts, which do not qualify for hedge accounting under SFAS No. 133. Had we included the realized loss on our three-way contracts our average realized price for total natural gas would have been $5.33 per Mcf and our average realized price for total oil and condensate would have been $35.05 per Bbl for 2004. No three-way contracts were settled in 2003.

     In 2004, LOE, stated on a unit of production basis, averaged $0.60 per Mcfe compared to LOE from continuing operations of $0.54 per Mcfe in 2003. Production and other taxes in 2004 were $0.17 per Mcfe compared to production and other taxes from continuing operations of $0.14 per Mcfe in 2003. DD&A expense in 2004 was $1.94 per Mcfe compared to DD&A expense from continuing operations of $1.79 per Mcfe in 2003. G&A expense in 2004 was $0.34 per Mcfe compared to G&A expense from continuing operations of $0.28 per Mcfe in the prior year. G&A expense in 2004 is net of capitalized direct internal costs of $32 million. Capitalized direct internal costs were $27 million in 2003.

Proved Reserves and Capital Activity

     Newfield’s total reserves at year-end 2004 were 1.78 Tcfe, an increase of 35% over year-end 2003 reserves. Reserve additions from all sources were 725 Bcfe and included 458 Bcfe from acquisitions and 267 Bcfe from discoveries, extensions and other revisions/additions. Sales of reserves in 2004 totaled 14 Bcfe.

     Total oil and gas capital costs in 2004 were $1.85 billion, which includes a non-cash $144 million step-up in the booked fair value of the assets acquired in the Inland transaction and $49 million associated with asset retirement cost.

Oil and Gas Reserves*

	MMBbls			Bcf			Bcfe
December 31, 2003		37.8			1,090			1,317
Purchases of properties		54.4			131			458
Extensions, discoveries and other additions		5.2			231			262
Revisions		1.2			(2	)		5
Reserve additions		60.8			360			725
Sales of properties		(0.6	)		(11	)		(14	)
Production		(7.5	)		(198	)		(244	)
December 31, 2004		90.5			1,241			1,784

* As a requirement of our revolving credit facility, independent reserve engineers prepare separate reserve reports with respect to properties holding at least 80% of our proved reserves. For December 31, 2004, the independent reserve engineers’ reports covered properties representing 86% of our proved reserves and for such properties, the reserves were within 1% of the reserves we reported for such properties.

Capital Expenditures

(In millions)	2004
Property acquisitions(1):
Unproved	$	439
Proved		603
Exploration(2)		158
Development		570
Asset retirement cost		49
Capitalized interest		26
Total costs incurred	$	1,845
Less:
Step-up in booked fair value of Inland assets		(144	)
Asset retirement cost		(49	)
	$	1,652

⁽¹⁾ Includes $37 million of unproved leasehold and $7million of proved leasehold expenditures.

⁽²⁾ Includes $37 million of seismic expenditures.

Explanation and Reconciliation of Non-GAAP Financial Measures

     Net cash provided by operating activities before changes in operating assets and liabilities is presented because of its acceptance as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt. This measure should not be considered as an alternative to net cash provided by operating activities as defined by generally accepted accounting principles. A reconciliation of net cash provided by operating activities from continuing operations before changes in operating assets and liabilities to net cash provided by operating activities from continuing operations is shown below:

(In millions)	4Q04			4Q03
Net cash provided by operating activities from continuing operations	$	353		$	201
Net change in operating assets and liabilities		(49	)		(6	)
Net cash provided by operating activities from continuing operations before changes in operating assets and liabilities	$	304		$	195

(In millions)	2004			2003
Net cash provided by operating activities from continuing operations	$	998		$	659
Net change in operating assets and liabilities		(33	)		75
Net cash provided by operating activities from continuing operations before changes in operating assets and liabilities	$	965		$	734

First Quarter 2005 Estimates

     Natural Gas Production and PricingThe Company’s natural gas production in the first quarter of 2005 is expected to be 49 – 54 Bcf (538 – 593 MMcf/d). The price the Company realizes for natural gas production from the Gulf of Mexico and onshore Gulf Coast, after basis differentials, transportation and handling charges, typically averages $0.15 — $0.20 less per MMBtu than the Henry Hub Index. Realized gas prices for our Mid-Continent properties, after basis differentials, transportation and handing charges, typically average $0.70 — $0.80 less per MMBtu than the Henry Hub Index. Hedging gains or losses will affect price realizations.

     Crude Oil Production and PricingThe Company’s oil production, including international liftings, in the first quarter of 2005 is expected to be 2.1 – 2.3 million barrels (23,000 – 25,000 BOPD). Newfield expects to produce approximately 4,200 BOPD from its Malaysian operations. The timing of liftings in Malaysia may affect our total reported production. The price the Company receives for Gulf Coast production typically averages about $2 per barrel below the NYMEX West Texas Intermediate (WTI) price. The price the Company receives for its production in the Rocky Mountains averages about $3 per barrel below WTI price. Oil production from the Mid-Continent typically sells at a $1.00 – $1.50 per barrel discount to WTI. Oil production from Malaysia typically sells at Tapis, or about even with WTI. Hedging gains or losses will affect price realizations.

     Lease Operating and Other ExpensesLOE is expected to be $43 – $48 million ($0.68 – $0.75 per Mcfe) in the first quarter of 2005. Production taxes in the first quarter of 2005 are expected to be $12 – $13 million ($0.19 – $0.21 per Mcfe). These expenses vary and are subject to impact from, among other things, production volumes and commodity pricing, tax rates, service costs, the costs of goods and materials and workover activities.

     General and Administrative ExpenseG&A expense for the first quarter of 2005 is expected to be $23 – $25 million ($0.36 – $0.40 per Mcfe), net of capitalized direct internal costs. Capitalized direct internal costs are expected to be $9 – $11 million. G&A expense includes stock and incentive compensation expense. Incentive compensation expense depends largely on net income.

     Interest ExpenseThe non-capitalized portion of the Company’s interest expense for the first quarter of 2005 is expected to be $7 – $8 million ($0.10 – $0.11 per Mcfe). As of February 9, 2005, borrowings under the Company’s credit arrangements were $78 million. The remainder of long-term debt consists of four separate issuances of notes that in the aggregate total $875 million in principal amount. Capitalized interest for the first quarter of 2005 is expected to be about $11 – $12 million.

     Income TaxesIncluding both current and deferred taxes, the Company expects its consolidated income tax rate in the first quarter of 2005 to be about 35 – 39%. About 70% of the tax provision is expected to be deferred.

     The Company provides information regarding its outstanding hedging positions in its annual and quarterly reports filed with the SEC and in its electronic publication — @NFX. This publication can be found on Newfield’s web page athttp://www.newfld.com. Through the web page, you may elect to receive @NFX through e-mail distribution.

     Newfield Exploration Company is an independent crude oil and natural gas exploration and production company. The Company relies on a proven growth strategy that includes balancing acquisitions with drill bit opportunities. Newfield’s areas of operation include the Gulf of Mexico, the U.S. onshore Gulf Coast, the Anadarko and Arkoma Basins of the Mid-Continent, the Uinta Basin of the Rocky Mountains and select international ventures.

     **The statements set forth in this release regarding estimated or anticipated full-year 2005 production volumes and capital expenditures and first quarter 2005 results are forward looking and are 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, the availability of capital resources, labor conditions and other factors set forth in the Company’s Annual Report onForm 10-K for the year ended December 31, 2003. In addition, the drilling of oil and gas wells and the production of hydrocarbons are subject to governmental regulations and operating risks.

Newfield Exploration Company	For information, contact:
363 N. Sam Houston Parkway East, Ste. 2020 Houston, TX 77060 www.newfld.com	Steve Campbell (281)847-6081 info@newfld.com

###

CONSOLIDATED STATEMENT OF INCOME
(Unaudited, in millions, except per share data)

	For the						For the
	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2004			2003			2004			2003
Oil and gas revenues	$	436.9		$	244.9		$	1,352.7		$	1,017.0
Operating expenses:
Lease operating		47.0			33.5			145.7			119.3
Production and other taxes		12.1			6.6			42.3			31.7
Transportation		1.2			1.3			6.3			6.4
Depreciation, depletion and amortization		141.9			101.3			471.4			394.7
Ceiling test writedown		10.3			—			17.0			—
General and administrative		24.6			15.6			84.0			61.6
Writedown of EGB, gas sales obligation settlement and redemption of securities		35.0			—			35.0			20.5
Total operating expenses		272.1			158.3			801.7			634.2
Income from operations		164.8			86.6			551.0			382.8
Other income (expenses):
Interest expense		(18.4	)		(12.8	)		(57.7	)		(57.8	)
Capitalized interest		11.2			4.2			25.8			15.9
Dividends on preferred securities of Newfield Financial Trust I		—			—			—			(4.6	)
Commodity derivative expense		(7.3	)		(6.8	)		(23.8	)		(6.1	)
Other		1.2			0.4			3.6			1.4
		(13.3	)		(15.0	)		(52.1	)		(51.2	)
Income from continuing operations before income taxes		151.5			71.6			498.9			331.6
Income tax provision		61.3			31.4			186.8			120.7
Income from continuing operations		90.2			40.2			312.1			210.9
Loss from discontinued operations, net of tax		—			—			—			(17.0	)
Income before cumulative effect of change in accounting principle		90.2			40.2			312.1			193.9
Cumulative effect of change in accounting principle, net of tax*		—			—			—			5.6
Net income	$	90.2		$	40.2		$	312.1		$	199.5
Earnings per share:
Basic
Income from continuing operations	$	1.46		$	0.72		$	5.35		$	3.88
Loss from discontinued operations		—			—			—			(0.31	)
Cumulative effect of change in accounting principle, net of tax*		—			—			—			0.10
Net income	$	1.46		$	0.72		$	5.35		$	3.67
Diluted
Income from continuing operations	$	1.43		$	0.71		$	5.26		$	3.77
Loss from discontinued operations		—			—			—			(0.30	)
Cumulative effect of change in accounting principle, net of tax*		—			—			—			0.10
Net income	$	1.43		$	0.71		$	5.26		$	3.57
Weighted average number of shares outstanding for basic earnings per share		61.9			56.1			58.3			54.3
Weighted average number of shares outstanding for diluted earnings per share		63.0			56.6			59.3			56.7

* Associated with the adoption of SFAS No. 143.

CONDENSED CONSOLIDATED
BALANCE SHEET
(Unaudited, in millions)

	December 31,			December 31,
	2004			2003
ASSETS
Current assets:
Cash and cash equivalents	$	58.3		$	15.3
Accounts receivable, oil and gas		247.7			134.8
Inventories		7.8			0.5
Derivative assets		54.5			13.8
Deferred taxes		1.0			12.9
Other current assets		22.3			61.6
Total current assets		391.6			238.9
Oil and gas properties, net (full cost method)		3,775.3			2,418.5
Floating production system and pipelines		—			35.0
Furniture, fixtures and equipment, net		18.3			5.9
Derivative assets		55.6			2.2
Other assets		21.4			16.2
Goodwill		65.3			16.4
Total assets	$	4,327.5		$	2,733.1
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	427.0		$	255.5
Derivative liabilities		47.0			44.7
Total current liabilities		474.0			300.2
Other liabilities		15.8			13.2
Derivative liabilities		83.1			13.2
Long-term debt		992.4			643.5
Asset retirement obligation		194.2			151.6
Deferred taxes		551.1			242.8
Total long-term liabilities		1,836.6			1,064.3
Commitments and contingencies		—			—
STOCKHOLDERS’ EQUITY
Common stock		0.6			0.5
Additional paid-in capital		1,102.5			796.2
Treasury stock		(27.3	)		(26.7	)
Unearned compensation		(9.5	)		(10.9	)
Accumulated other comprehensive income (loss):
Foreign currency translation adjustment		2.6			0.9
Commodity derivatives		0.1			(26.4	)
Minimum pension liability		—			(0.8	)
Retained earnings		947.9			635.8
Total stockholders’ equity		2,016.9			1,368.6
Total liabilities and stockholders’ equity	$	4,327.5		$	2,733.1

CONDENSED CONSOLIDATED
STATEMENT OF CASH FLOWS
(Unaudited, in millions)

	For the
	Twelve Months Ended
	December 31,
	2004			2003
Cash flows from operating activities:
Net income	$	312.1		$	199.5
Loss from discontinued operations, net of tax		—			17.0
Depreciation, depletion and amortization		471.4			394.7
Deferred taxes		125.7			99.1
Stock compensation		4.1			3.0
Commodity derivative income (expense)		(0.4	)		6.1
Writedown of EGB, gas sales obligation settlement and redemption of securities		35.0			20.5
Ceiling test writedown		17.0			—
Cumulative effect of change in accounting principle *		—			(5.6	)
		964.9			734.3
Changes in operating assets and liabilities		32.6			(75.1	)
Net cash provided by continuing activities		997.5			659.2
Net cash provided by discontinued activities		—			10.3
Net cash provided by operating activities		997.5			669.5
Cash flows from investing activities:
Purchases of businesses, net of cash acquired		(755.7	)		(90.2	)
Proceeds from sale of business		—			9.7
Additions to oil and gas properties		(853.0	)		(530.9	)
Proceeds from sale of oil and gas properties		16.7			—
Additions to furniture, fixtures and equipment		(6.8	)		(3.3	)
Net cash used in continuing activities		(1,598.8	)		(614.7	)
Net cash used in discontinued activities		—			(3.1	)
Net cash used in investing activities		(1,598.8	)		(617.8	)
Cash flows from financing activities:
Proceeds from borrowings under credit arrangements		1,254.0			1,569.0
Repayments of borrowings under credit arrangements		(1,229.0	)		(1,510.0	)
Proceeds from issuance of senior subordinated notes		325.0			—
Repurchases of secured notes		(2.9	)		(63.1	)
Deliveries under the gas sales obligation		—			(8.4	)
Proceeds from issuances of common stock		297.3			149.3
Repayments of secured notes		—			(11.2	)
Gas sales obligation settlement		—			(62.0	)
Purchases of treasury stock		(0.6	)		(0.5	)
Redemption of trust preferred securities		—			(148.5	)
Net cash provided by (used in) continuing activities		643.8			(85.4	)
Net cash used in discontinued activities		—			—
Net cash provided by (used in) financing activities		643.8			(85.4	)
Effect of exchange rate changes on cash and cash equivalents		0.5			0.1
Increase (decrease) in cash and cash equivalents		43.0			(33.6	)
Cash and cash equivalents from continuing operations, beginning of period		15.3			33.8
Cash and cash equivalents from discontinued operations, beginning of period		—			15.1
Cash and cash equivalents, end of period	$	58.3		$	15.3

* Associated with the adoption of SFAS No. 143.