8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________

FORM 8-K

______________

CURRENT REPORT

Pursuant to Section 13 OR 15(d) of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): July 26, 2005

______________

NEWFIELD EXPLORATION COMPANY

(Exact name of registrant as specified in its charter)

______________

Delaware	1-12534	72-1133047
(State or other jurisdiction	(Commission File Number)	(I.R.S. Employer
of incorporation)		Identification No.)

363 N. Sam Houston Parkway E., Suite 2020

Houston, Texas 77060

(Address of principal executive offices)

Registrant’s telephone number, including area code: (281) 847-6000

Not Applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 2.02 Results of Operations and Financial Condition

On July 26, 2005, Newfield issued a press release announcing its second quarter 2005 financial and operating results and third quarter 2005 earnings guidance. A copy of the press release is furnished herewith as Exhibit 99.1.

On July 26, 2005, Newfield issued its @NFX publication, which includes an update on significant development projects and recent drilling activities, guidance for the third quarter of 2005 and updated tables detailing complete hedging positions as of July 25, 2005. A copy of this publication is furnished herewith as Exhibit 99.2.

Item 7.01 Regulation FD Disclosure

On July 26, 2005, Newfield issued a press release providing a revised production forecast for 2005, production forecasts for 2006 and 2007 and a discussion of some of the significant reasons for the growth in production reflected in the forecasts. A copy of the press release is furnished herewith as Exhibit 99.3.

Item 9.01 Financial Statements and Exhibits

(c)	Exhibits
	99.1	Press release issued by Newfield Exploration Company on July 26, 2005.
	99.2	@NFX publication issued by Newfield Exploration Company on July 26, 2005.
	99.3	Press release issued by Newfield Exploration Company on July 26, 2005.

2

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Form 8-K to be signed on its behalf by the undersigned hereunto duly authorized.

	NEWFIELD EXPLORATION COMPANY
Date:July 28, 2005	By:	/s/ TERRY W. RATHERT
		Terry W. Rathert
		Senior Vice President and Chief FinancialOfficer

3

Exhibit Index

Exhibit No.	Description
99.1	Press release issued by Newfield Exploration Company on July 26, 2005.
99.2	@NFX publication issued by Newfield Exploration Company on July 26, 2005.
99.3	Press release issued by Newfield Exploration Company on July 26, 2005.

EX-99.1

Exhibit 99.1

NEWFIELD EXPLORATION REPORTS SECOND QUARTER RESULTS

FOR IMMEDIATE RELEASE

Houston -(July 26, 2005) - Newfield Exploration Company (NYSE:NFX) today announced financial and operating results for the second quarter of 2005. A conference call to discuss the results is planned for 8:30 a.m. (CDT), Wednesday, July 27. To participate in the call, dial 719-457-2633. A listen-only broadcast also will be provided over the Internet. Simply go to the Investor Relations section at http://www.newfld.com.

Second Quarter 2005

For the second quarter of 2005, Newfield reported net income of $104 million, or $0.82 per share (all per share amounts are on a diluted basis and reflect the two-for-one stock split in May 2005). Earnings for the quarter include the effect of a $45 million charge ($30 million after tax), or $0.23 per share, associated with changes in the fair market value of open three-way collar contracts, which do not qualify for hedge accounting, and hedge ineffectiveness. Without the effects of this item, net income for the quarter would have been $134 million, or $1.05 per share. Revenues in the second quarter of 2005 were $446 million. Net cash provided by operating activities before changes in operating assets and liabilities was $329 million. See Explanation and Reconciliation of Non-GAAP Financial Measures.

By comparison, Newfield’s net income for the second quarter of 2004 was $67 million, or $0.59 per share. Revenues in the same period were $283 million. Net cash provided by operating activities before changes in operating assets and liabilities was $185 million in the second quarter of 2004. See Explanation and Reconciliation of Non-GAAP Financial Measures.

Newfield’s production in the second quarter of 2005 was 67.3 Bcfe, a 20% increase over second quarter 2004 production of 56.0 Bcfe. The following tables detail production and average realized prices for the second quarters of 2005 and 2004.

Quarterly Production(1)	2Q05		2Q04		% Change
United States
Natural gas (Bcf)		53.3		47.3		13%
Oil and condensate (MMBbls)		2.0		1.4		43%
International
Natural gas (Bcf)		0.1		0.2		(50%)
Oil and condensate (MMBbls)		0.3		—		N/M
Total
Natural gas (Bcf)		53.4		47.5		12%
Oil and condensate (MMBbls)		2.3		1.4		64%
Total (Bcfe)		67.3		56.0		20%

Average Realized Prices(2)	2Q05		2Q04		% Change
United States
Natural gas (per Mcf)		$6.41		$4.92		30%
Oil and condensate (per Bbl)		$43.24		$34.64		25%
International
Natural gas (per Mcf)		$5.35		$3.87		38%
Oil and condensate (per Bbl)		$51.95		—		N/M
Total
Natural gas (per Mcf)		$6.41		$4.92		30%
Oil and condensate (per Bbl)		$44.28		$34.65		28%
Total (per Mcfe)		$6.61		$5.05		31%

⁽¹⁾ Represents volumes sold regardless of when produced.

⁽²⁾ 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 effect of these contracts, our average realized price for total gas would have been unchanged for the second quarter of 2005 and $4.84 per Mcf for the second quarter of 2004. Our total oil and condensate average realized price would have been $43.86 per Bbl and $32.42 per Bbl for the second quarter of 2005 and 2004, respectively.

Stated on a unit of production basis, Newfield’s lease operating expense (LOE) in the second quarter of 2005 was $0.71 per Mcfe, compared to LOE of $0.52 per Mcfe in the second quarter of 2004. LOE in the second quarter of 2005 was impacted by $0.11 per Mcfe of well workover expense. Production and other taxes in the second quarter of 2005 increased to $0.18 per Mcfe compared to production and other taxes of $0.16 per Mcfe in the same period of 2004. DD&A expense in the second quarter of 2005 was $2.09 per Mcfe compared to DD&A expense of $1.88 per Mcfe in the same period of 2004. G&A expense in the second quarter of 2005 was $0.41 per Mcfe compared to G&A expense of $0.34 per Mcfe in the same period of 2004. G&A expense in the second quarter of 2005 is net of capitalized direct internal costs of $12 million. Capitalized direct internal costs were $9 million in the second quarter of 2004.

Capital expenditures in the second quarter of 2005 were $263 million.

Year-to-Date 2005

For the first six months of 2005, Newfield posted net income of $164 million, or $1.29 per share, on revenues of $859 million. Earnings for the first half of 2005 were impacted by two items:

Ø   A $152 million charge ($99 million after tax), or $0.78 per share, associated with changes in the fair market value of open three-way collar contracts, which do not qualify for hedge accounting, and hedge ineffectiveness; and

Ø   An $8 million benefit, or $0.06 per share, related to a reduction of the valuation allowance on Newfield’s U.K. net operating loss carryforwards because of a substantial increase in estimated future taxable income as a result of Newfield’s Grove discovery in the U.K. North Sea.

Without the effects of these items, net income for the first six months of 2005 would have been $255 million, or $2.01 per share.

By comparison, in the first half of 2004, net income was $145 million, or $1.28 per share, on revenues of $588 million. Without the effect of unrealized commodity expense of $10 million ($7 million after tax), net income for the first half of 2004 would have been $152 million, or $1.33 per share. Net cash provided by operating activities before changes in operating assets and liabilities was $639 million in the first half of 2005 compared to $393 million in the same period of 2004. See Explanation and Reconciliation of Non-GAAP Financial Measures.

Production volumes for the first half of 2005 increased 17% above the same period of 2004. The Company produced 132.2 Bcfe in the first six months of 2005 compared to 113.3 Bcfe in the first six months of 2004. The following tables detail production and average realized prices for the first half of 2005 and 2004:

Production(1)	1HQ05		1HQ04		% Change
United States
Natural gas (Bcf)		104.5		95.2		10%
Oil and condensate (MMBbls)		4.1		3.0		37%
International
Natural gas (Bcf)		0.1		0.3		(67%)
Oil and condensate (MMBbls)		0.5		—		N/M
Total
Natural gas (Bcf)		104.6		95.5		10%
Oil and condensate (MMBbls)		4.6		3.0		53%
Total (Bcfe)		132.2		113.3		17%

Average Realized Prices(2)	1HQ05		1HQ04		% Change
United States
Natural gas (per Mcf)		$6.32		$5.13		23%
Oil and condensate (per Bbl)		$42.07		$33.26		26%
International
Natural gas (per Mcf)		$5.15		$3.95		30%
Oil and condensate (per Bbl)		$48.27		$36.50		32%
Total
Natural gas (per Mcf)		$6.32		$5.12		23%
Oil and condensate (per Bbl)		$42.76		$33.26		29%
Total (per Mcfe)		$6.49		$5.19		25%

⁽¹⁾ Represents volumes sold regardless of when produced.

⁽²⁾ 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 effect of these contracts, our average realized price for total gas would have been unchanged for the six months ended June 30, 2005 and $5.08 per Mcf for the six months ended June 30, 2004. Our total oil and condensate average realized price would have been $42.05 per Bbl and $31.69 per Bbl for the six months ended June 30, 2005 and 2004, respectively.

In the first half of 2005, LOE, stated on a unit of production basis, averaged $0.69 per Mcfe, compared to LOE of $0.52 per Mcfe in the same period of 2004. Production taxes in the first half of 2005 were $0.18 per Mcfe compared to production taxes of $0.15 per Mcfe in the same period of 2004. DD&A expense in the first half of 2005 was $2.09 per Mcfe compared to DD&A expense of $1.86 per Mcfe in the same period of 2004. G&A expense in the first half of 2005 was $0.38 per Mcfe compared to G&A expense of $0.33 per Mcfe in the prior year.G&A expense in the first half of 2005 is net of capitalized direct internal costs of $22 million compared to $15 million in the first half of 2004.

Capital expenditures in the first half of 2005 totaled $517 million. For the full-year 2005, Newfield has increased its capital budget to be about $1.2 billion, up from its original $950 million budget. The increase in spending primarily relates to the development of recent discoveries and higher oilfield service costs.

Explanation and Reconciliation of Non-GAAP Financial Measures

Earnings stated without the effects of certain items, a non-GAAP financial measure, affect the comparability of operating results. Earnings without the effects of these items are presented because the timing and amount of these items cannot be reasonably estimated and because earnings without the effects of these items are more comparable to earnings estimates provided by securities analysts.

Our consolidated statement of income includes the effects of these items as follows:

-   Commodity derivative expense includes $45 million of unrealized commodity derivative expense for the second quarter of 2005, resulting from changes in the fair market value of open three-way collar contracts, which do not qualify for hedge accounting, and hedge ineffectiveness, and $1 million of realized expenses related to the monthly settlement of certain of those contracts in the second quarter of 2005.

A reconciliation of earnings without the effect of unrealized commodity derivative expense to net income is shown below:

	2Q05
	(in millions)
Net income	$	104
Plus: Unrealized commodity derivative expense		45
Less: Income tax benefit adjustment for above item		(15	)
Earnings stated without the effects of the above items	$	134

In the first half of 2005 our consolidated statement of income includes the effects of these items as follows:

-   Commodity derivative expense for the first half of 2005 and 2004 includes $152 million and $10 million, respectively, of unrealized commodity derivative expense resulting from changes in the fair market value of open three-way collar contracts, which do not qualify for hedge accounting, and hedge ineffectiveness, and $3 million and $8 million of realized expenses related to the monthly settlement of certain of those contracts in the first half of 2005 and 2004, respectively.

-   Income tax provision for 2005 includes an $8 million benefit related to a reduction of the valuation allowance on Newfield’s U.K. net operating loss carryforwards because of a substantial increase in estimated future taxable income as a result of Newfield’s Grove discovery in the U.K. North Sea.

A reconciliation of earnings without the effects of unrealized commodity derivative expense and the tax benefit related to reducing the U.K. tax asset valuation allowance to net income is shown below:

	1H05			1H04
	(in millions)
Net income	$	164		$	145
Plus: Unrealized commodity derivative expense		152			10
Less: Income tax benefit adjustment for above item		(53	)		(3	)
Less: Tax benefit related to U.K. net operating loss valuation allowance		(8	)		—
Earnings stated without the effects of the above items	$	255		$	152

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 before changes in operating assets and liabilities to net cash provided by operating activities is shown below:

	2Q05			2Q04
	(in millions)
Net cash provided by operating activities	$	356		$	196
Net change in operating assets and liabilities		(27	)		(11	)
Net cash provided by operating activities before changes in operating assets and liabilities	$	329		$	185

	1H05		1H04
	(in millions)
Net cash provided by operating activities	$	617	$	414
Net change in operating assets and liabilities		22		(21	)
Net cash provided by operating activities before changes in operating assets and liabilities	$	639	$	393

Third Quarter 2005 Estimates

Natural Gas Production and Pricing The Company’s natural gas production in the third quarter of 2005 is expected to be 49 - 54 Bcf (533 - 587 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 the Company’s 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 Pricing The Company’s oil production, including international liftings, in the third quarter of 2005 is expected to be 2.2 - 2.4 million barrels (24,000 - 26,000 BOPD). Newfield expects to produce approximately 4,200 BOPD from its Malaysian operations. The timing of liftings in Malaysia may affect 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. 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 Expense and Production Taxes LOE is expected to be $46 - $51 million ($0.71 - $0.80 per Mcfe) in the third quarter of 2005. LOE guidance for the third quarter of 2005 includes $0.16 per Mcfe of well workover expense. Production taxes in the third quarter of 2005 are expected to be $17 - $19 million ($0.27 - $0.29 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 Expense G&A expense for the third quarter of 2005 is expected to be $24 - $26 million ($0.36 - $0.40 per Mcfe), net of capitalized direct internal costs. Capitalized direct internal costs are expected to be $11 - $13 million. G&A expense includes stock and incentive compensation expense. Incentive compensation expense depends largely on adjusted net income (as defined in the Company’s incentive compensation plan), which excludes unrealized gains and losses on commodity derivatives.

Interest Expense The non-capitalized portion of the Company’s interest expense for the third quarter of 2005 is expected to be $6 - $7 million ($0.08 - $0.10 per Mcfe). As of July 25, 2005, Newfield had no outstanding borrowings under its credit arrangements. 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 third quarter of 2005 is expected to be about $11 - $12 million.

Income Taxes Including both current and deferred taxes, the Company expects its consolidated income tax rate in the third quarter of 2005 to be about 35 - 39%. About 75% 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 at http://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 and the Uinta Basin of the Rocky Mountains. The Company has development projects underway offshore Malaysia, in the U.K. North Sea and in Bohai Bay, China.

**The statements set forth in this release regarding estimated or anticipated third quarter results and production volumes 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 on Form 10-K for the year ended December 31, 2004. 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	Steve Campbell
Houston, TX 77060	(281) 847-6081
www.newfld.com	info@newfld.com

###

CONSOLIDATED STATEMENT OF INCOME (Unaudited, in millions, except per share data)	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2005			2004			2005			2004
Oil and gas revenues	$	445.8		$	282.7		$	858.9		$	588.1
Operating expenses:
Lease operating		47.7			28.9			90.9			58.8
Production and other taxes		12.2			9.1			23.3			17.5
Transportation		1.9			2.0			4.2			3.4
Depreciation, depletion and amortization		140.5			105.2			276.3			211.1
General and administrative		27.7			19.0			50.5			37.6
Total operating expenses		230.0			164.2			445.2			328.4
Income from operations		215.8			118.5			413.7			259.7
Other income (expenses):
Interest expense		(18.6	)		(12.0	)		(36.6	)		(24.5	)
Capitalized interest		11.4			4.4			22.7			8.3
Commodity derivative expense		(46.3	)		(5.6	)		(155.2	)		(17.8	)
Other		1.1			0.4			1.3			1.0
		(52.4	)		(12.8	)		(167.8	)		(33.0	)
Income before income taxes		163.4			105.7			245.9			226.7
Income tax provision		59.2			38.3			81.7			81.4
Net income	$	104.2		$	67.4		$	164.2		$	145.3
Earnings per share:
Basic	$	0.83		$	0.60		$	1.32		$	1.30
Diluted	$	0.82		$	0.59		$	1.29		$	1.28
Weighted average number of shares outstanding for basic earnings per share		125.2			112.2			124.8			112.0
Weighted average number of shares outstanding for diluted earnings per share		127.6			114.1			127.1			113.8

CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited, in millions)	June 30, 2005			December 31, 2004
ASSETS
Current assets:
Cash and cash equivalents	$	58.6		$	58.3
Accounts receivable		238.1			247.7
Inventories		18.6			7.8
Derivative assets		9.9			54.5
Deferred taxes		40.0			1.0
Other current assets		39.2			22.3
Total current assets		404.4			391.6
Oil and gas properties, net (full cost method)		4,011.5			3,775.3
Furniture, fixtures and equipment, net		18.1			18.3
Derivative assets		18.7			55.6
Other assets		20.4			21.4
Deferred taxes		8.8			—
Goodwill		65.3			65.3
Total assets	$	4,547.2		$	4,327.5
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	401.4		$	427.0
Derivative liabilities		99.2			47.0
Total current liabilities		500.6			474.0
Other liabilities		26.6			15.8
Derivative liabilities		193.0			83.1
Long-term debt		872.1			992.4
Asset retirement obligation		203.2			194.2
Deferred taxes		607.5			551.1
Total long-term liabilities		1,902.4			1,836.6
Commitments and contingencies		—			—
STOCKHOLDERS’ EQUITY
Common stock		1.3			1.3
Additional paid-in capital		1,151.3			1,101.8
Treasury stock		(27.8	)		(27.3	)
Unearned compensation		(25.6	)		(9.5	)
Accumulated other comprehensive income (loss):
Foreign currency translation adjustment		(1.4	)		2.6
Commodity derivatives		(65.7	)		0.1
Retained earnings		1,112.1			947.9
Total stockholders’ equity		2,144.2			2,016.9
Total liabilities and stockholders’ equity	$	4,547.2		$	4,327.5

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited, in millions)	For the Six Months Ended June 30,
	2005			2004
Cash flows from operating activities:
Net income	$	164.2		$	145.3
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		276.3			211.1
Deferred taxes		43.3			25.3
Stock compensation		3.7			2.0
Commodity derivative expense		151.9			9.5
		639.4			393.2
Changes in operating assets and liabilities		(22.5	)		21.1
Net cash provided by operating activities		616.9			414.3
Cash flows from investing activities:
Additions to oil and gas properties		(522.2	)		(347.4	)
Proceeds from sale of oil and gas properties		10.7			—
Additions to furniture, fixtures and equipment		(2.2	)		(1.7	)
Net cash used in investing activities		(513.7	)		(349.1	)
Cash flows from financing activities:
Proceeds from borrowings under
credit arrangements		473.0			385.5
Repayments of borrowings under
credit arrangements		(593.0	)		(446.5	)
Repurchases of secured notes		—			(2.9	)
Proceeds from issuances of common stock		20.2			11.3
Purchases of treasury stock		(0.5	)		(0.4	)
Net cash used in financing activities		(100.3	)		(53.0	)
Effect of exchange rate changes on cash and cash equivalents		(2.6	)		0.3
Increase in cash and cash equivalents		0.3			12.5
Cash and cash equivalents, beginning of period		58.3			15.3
Cash and cash equivalents, end of period	$	58.6		$	27.8

EX-99.2

Exhibit 99.2

@NFX is periodically published to keep shareholders aware of current operating activities at Newfield. It may include estimates of expected production volumes, costs and expenses, recent changes to hedging positions and commodity pricing.

If you have problems viewing this e-mail please go to www.newfld.com

July 26, 2005

This edition of @NFX includes:

·   Update on significant development projects

·   Update on recent drilling activities

·   Guidance for the third quarter of 2005; and

·   Updated tables detailing complete hedging positions

On July 26, we issued an expected range for our production for 2005-07. The increase in volumes is driven by large development projects underway today. The following table details the significant projects that are under development and the expected timing of first production. The second table shows historical production, as well as expected ranges for 2005-07.

An Update on Significant Development Projects

Monument Butte - Since closing our Inland acquisition in August of last year, we have grown gross oil production from the field by over 20% to a current rate of 9,500 BOPD. Gross production should exit this year at 10,500 BOPD and grow to more than 14,500 BOPD in 2007. Newfield operates the field with an average working interest of more than 80%.

West Cameron 77 - This was a 2004 deep shelf discovery. Production commenced in mid-July at about 15 MMcfe/d (gross). A second deep prospect is planned in the field and is expected to spud later this year. Newfield has a 34% working interest at WC 77.

Rigel - A late 2003 deepwater discovery, Rigel is on track for first production in October 2006 at more than 50 MMcfe/d (gross). We have a 33% interest in this outside-operated development.

Wrigley - This February ’05 deepwater discovery is expected to be on-line in July ’06, less than 18 months from discovery to first production. Wrigley, located at Mississippi Canyon 506, is expected to produce at least 50 MMcfe/d. Newfield operates the development with a 50% interest.

Bohai Bay, China - The CFD 12-1 and 12-1 South Fields in Bohai Bay, China are now under development and we expect first production in late 2006. We will have a 12% interest in the unit, after CNOOC back-in.

Grove - Our Grove development in the North Sea is expected to come on-line in the fourth quarter of ‘06. With three wells planned in the central fault block, we estimate that Grove will produce 60 MMcf/d and 600 BCPD. The Company recently reached an agreement to purchase a used facility (pictured below). This is the first time that a refurbished facility has been used to develop a new discovery in the North Sea. Newfield is the operator with a 100% interest in the development.

Abu Cluster - Located on the shallow water PM 318 block offshore Malaysia, we expect to have the Abu Field on line in early 2007 at about 12,000 BOPD gross. We will have a 50% interest in the field. When combined with current production at Penara and North Lukut fields, we are expected to have more than 20,000 BOPD of gross production from Malaysia in early 2007.

Focus Area Updates

ONSHORE GULF COAST

During the second quarter, we drilled 11 successful wells out of 16 attempts and have two wells remaining to be tested in our onshore Gulf Coast division. We have eight operated rigs running along the Gulf Coast and are participating in two outside operated wells. We expect to drill 40-60 development wells in the area during 2005.

Monte Christo

In South Texas, we continue to have good success with our drilling program in the Monte Christo Field area, located in Hidalgo County, Texas. Since the beginning of 2005, we’ve drilled two successful wells out of three attempts in the Monte Christo Field. Located in a separate field in the same area, we have drilled four successful development wells out of as many attempts in the McCook Field. Our recent Johnson #75 well came on-line at 15.3 MMcf/d and total field production is about 30 MMcfe/d and limited by facilities. We expect the field to increase to nearly 40 MMcfe/d later this year. The Johnson #76 well was a recent success and is now being completed. We are drilling the Johnson #77. We have a 100% working interest in these wells.

Val Verde Basin

We remain active in the Val Verde Basin of southwest Texas where we hold more than 100,000 lease acres. Our production from the area is about 45 MMcfe/d gross and growing.

We recently completed a bite-size acquisition of the Snakebite Field. This acquisition adds 12,000 acres north of our Venom Field, a February ‘05 discovery. We see the potential to drill as many as 35 locations in the Snakebite Field. A pipeline is under construction to connect Venom with gathering assets acquired in the Snakebite transaction. The pipeline will provide for 30 MMcf/d of gross capacity from Venom. We have an 80-100% working interest in Venom and Snakebite and control more than 26,000 net acres in the area.

Poulter Field

We continue to develop the Poulter Field, also located in the Val Verde Basin. Current production is 12 MMcf/d from four wells and is expected to increase with further development drilling. The Packenham 2601 was a recent success that is being completed. We expect to bring two wells on-line during the next month and field production is expected to grow to over 20 MMcf/d. We operate Poulter and our working interest ranges from 60-100%. We control nearly 5,000 gross acres around this development.

Bravo Prospect

We are now completing a recent discovery at our Bravo Prospect, located in Zapata County, Texas. We expect to have this well on-line in the third quarter and are planning offset locations at this time. We have an 88% interest in Bravo. We have two additional exploration prospects drilling in Zapata County.

GULF OF MEXICO

During the first half of 2005, we participated in 14 wells in the Gulf of Mexico, eight of which were successful.

We have seven development projects underway that will add net production of about 30 MMcfe/d in the second half of 2005.

West Cameron 77 - This was a 2004 deep shelf discovery that came on-line in July at 15 MMcfe/d (gross). We are the operator with a 33% working interest. Another well is planned in the field in late 2005.

High Island 520 - We recently installed a used facility and first production of 10 MMcfe/d (gross) is expected in August 2005. We have a 75% interest in the field.

South Marsh Island 139 - A new platform was recently installed and first production of 500 BOPD (gross) is expected in September 2005. We have a 23% interest in the field.

West Delta 133 - We fabricated a new facility and first production of 3 MMcf/d and 2,000 BOPD is expected in October 2005. We have a 75% working interest.

North Padre Island 9- We recently installed a used facility and first production of 7.5 MMcfe/d (gross) is expected from this 1-2 well development in October 2005. We have a 51% working interest.

South Timbalier 299 - We are fabricating a platform and expect first production of 15 MMcf/d and 200 BOPD in November 2005. We have a 75% working interest.

South Marsh Island 155 - We recently acquired a used facility and first production of 3.5 MMcfe/d is expected in December 2005. We have a 100% working interest in the field.

In the second half of 2005, we expect to drill about 10 additional shelf wells and 5-7 deep shelf exploration wells. We expect to run 6-7 operated rigs in the Gulf of Mexico during the second half of 2005.

Mid-Continent

In 2005, we have drilled 43 company-operated wells and are currently operating 8 drilling rigs. In 2005, 42 operated wells have been completed or are in various stages of completion (excluding Cherokee Basin CBM wells).

WACCAWH - Our WACCAWH play is located in Coal, Pittsburgh and Hughes Counties, Oklahoma. We have been active in the play since 2002 and have drilled 77wells to date. Gross operated production from the area is 25 MMcfe/d. We expect to drill 35-40 WACCAWH wells in 2005. We have two rigs operating in the play today. Our recent Blevins 3H-9 well, located in Pittsburg County, was our first operated horizontal Woodford test. The well has a 1,500’ lateral section and has averaged 800 Mcfe/d during its first 30 days of production. Another Woodford test - the Cometti well - was drilled in our southern WACCAWH area and found the thickest pay section we have seen to date in the three primary target horizons - Wapanucka, Cromwell and Woodford shale. The Woodford had initial production of 1.8 MMcfe/d and averaged 850 Mcfe/d during its first 3 weeks of production. We are planning an offset and control more than 20,000 net acres around this well. We maintain an interest in more than 100,000 net acres in the WACCAWH play.

Wash Plays - During the second quarter, we averaged six operated rigs in the Wash Plays - located in the Texas Panhandle and Western Oklahoma. We are continuing to lease acreage and captured another 20,000 acres net during the quarter. We now own interests in more than 50,000 net acres in the Wash Play. Our gross operated daily production is about 35 MMcfe/d.

Texas Wash Play - We are currently operating three drilling rigs in the Stiles Ranch field, located in Wheeler County. Completion operations are underway on four wells. The Britt Ranch B 45-6 is now producing to sales at 3.5 MMcf/d (gross). Our gross daily production in the Texas Wash Play is 28 MMcfe/d from 77 wells. For 2005, we plan to drill 20-25 wells in the Texas Wash Play. We have over 100 remaining locations at Stiles Ranch, where we have a 100% working interest in most of the area.

Oklahoma Wash Play - We are operating two rigs in the Cheyenne Area of Roger Mills County in western Oklahoma. Targets are the Marmaton, Cherokee, Red Fork and Atoka Washes. A third rig is anticipated to move into the area in October. Recent completions are producing 2-4 MMcfe/d gross and our working interest ranges from 60-100%. In August, we plan to begin the assessment drilling of our Sweetwater Area (west of Cheyenne), which has been the focus of our leasing activity during the first half of the year. For 2005, we plan to drill a total of 15-20 wells.

Cherokee Basin CBM Area - In 2005, we have drilled 88 wells in the northeast corner of Oklahoma - our Cherokee Basin coal bed methane play. We have one rig running in the area. Gross production has grown to about 16 MMcfe/d, up from about 11 MMcfe/d at this time last year.

ROCKY MOUNTAINS

Our gross production from the Monument Butte field has increased from 8,775 BOPD in January to a current rate of nearly 9,500 BOPD. We have been operating three rigs in the field, however a fourth rig has been secured and will be drilling by the end of July.

We recently entered into a joint exploration venture with Bill Barrett Group and will have a 40% interest in the Red River “B” play on 17,000 acres in the Williston Basin.

Third Quarter 2005 Estimates

Natural Gas Production and Pricing The Company’s natural gas production in the third quarter of 2005 is expected to be 49 - 54 Bcf (533 - 587 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 the Company’s 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 Pricing The Company’s oil production, including international liftings, in the third quarter of 2005 is expected to be 2.2 - 2.4 million barrels (24,000 - 26,000 BOPD). Newfield expects to produce approximately 4,200 BOPD from its Malaysian operations. The timing of liftings in Malaysia may affect 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. 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 Expense and Production Taxes LOE is expected to be $46 - $51 million ($0.71 - $0.80 per Mcfe) in the third quarter of 2005. LOE guidance for the third quarter of 2005 includes $0.16 per Mcfe of well workover expense. Production taxes in the third quarter of 2005 are expected to be $17 - $19 million ($0.27 - $0.29 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 Expense G&A expense for the third quarter of 2005 is expected to be $24 - $26 million ($0.36 - $0.40 per Mcfe), net of capitalized direct internal costs. Capitalized direct internal costs are expected to be $11 - $13 million. G&A expense includes stock and incentive compensation expense. Incentive compensation expense depends largely on adjusted net income (as defined in the Company’s incentive compensation plan), which excludes unrealized gains and losses on commodity derivatives.

Interest Expense The non-capitalized portion of the Company’s interest expense for the third quarter of 2005 is expected to be $6 - $7 million ($0.08 - $0.10 per Mcfe). As of July 25, 2005, Newfield had no outstanding borrowings under its credit arrangements. 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 third quarter of 2005 is expected to be about $11 - $12 million.

Income Taxes Including both current and deferred taxes, the Company expects its consolidated income tax rate in the third quarter of 2005 to be about 35 - 39%. About 75% of the tax provision is expected to be deferred.

Please see the tables below for our complete hedging positions.

Natural Gas Hedge Positions

The following hedge positions for the third quarter of 2005 and beyond are as of July 25, 2005:

Third Quarter 2005

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
11,806 MMMBtus	$6.40	—	—	—	—
18,495 MMMBtus	—	—	$5.74 — $7.87	$3.50 — $6.24	$4.16 — $9.00
10,800 MMMBtus	—	$5.84	—	$5.50 — $6.50	—
6,150 MMMBtus*	—	—	$5.86 — $7.50	$5.50 — $6.15	$7.45 — $7.60

Fourth Quarter 2005

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
9,625 MMMBtus	$6.77	—	—	—	—
7,995 MMMBtus	—	—	$5.69 — $8.19	$3.50 — $6.24	$4.16 — $10.00
6,800 MMMBtus	—	$6.62	—	$5.50 — $7.50	—
6,350 MMMBtus*	—	—	$6.48 — $10.64	$5.50 — $7.50	$7.45 — $14.50

First Quarter 2006

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
5,100 MMMBtus	$8.95	—	—	—	—
2,400 MMMBtus	—	—	$5.80 — $10.00	$5.80	$10.00
5,100 MMMBtus	—	$7.55	—	$7.50 — $7.65	—
8,850 MMMBtus*	—	—	$7.06 — $12.12	$6.00 — $8.00	$10.00 — $14.50

*These 3-way collar contracts are standard natural gas collar contracts with respect to the periods, volumes and prices stated above. The contracts have floor and ceiling prices per MMMBtu as per the table above until the price drops below a weighted average price of $5.47 per MMMBtu. Below $5.47 per MMMBtu, these contracts effectively result in realized prices that are on average $1.07 per MMMBtu higher than the cash price that otherwise would have been realized.

Crude Oil Hedge Positions

The following hedge positions for the third quarter of 2005 and beyond are as of July 25, 2005:

Third Quarter 2005

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
635,000 Bbls	$33.25	—	—	—	—
681,000 Bbls	—	—	$40.20 — $57.45	$35.60 — $45.00	$48.00 — $64.00
304,000 Bbls**	—	—	$39.60 — $50.08	$35.00 — $46.00	$49.00 — $51.25

Fourth Quarter 2005

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
635,000 Bbls	$33.25	—	—	—	—
681,000 Bbls	—	—	$40.20 — $57.45	$35.60 — $45.00	$48.00 — $64.00
304,000 Bbls**	—	—	$39.60 — $50.08	$35.00 — $46.00	$49.00 — $51.25

First Quarter 2006

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
561,000 Bbls	$41.52	—	—	—	—
75,000 Bbls	—	—	$50.00 — $73.96	$50.00	$73.90 — $74.00
414,000 Bbls**	—	—	$45.96 — $63.91	$35.00 — $60.00	$50.50 — $80.00

Second Quarter 2006

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
565,000 Bbls	$41.58	—	—	—	—
75,000 Bbls	—	—	$50.00 — $73.96	$50.00	$73.90 — $74.00
417,000 Bbls**	—	—	$45.95 — $63.27	$35.00 — $60.00	$50.50 — $80.00

Third Quarter 2006

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
569,000 Bbls	$41.64	—	—	—	—
75,000 Bbls	—	—	$50.00 — $73.96	$50.00	$73.90 — $74.00
480,000 Bbls**	—	—	$44.69 — $62.21	$35.00 — $60.00	$50.50 — $80.00

Fourth Quarter 2006

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
569,000 Bbls	$41.64	—	—	—	—
75,000 Bbls	—	—	$50.00 — $73.96	$50.00	$73.90 — $74.00
480,000 Bbls**	—	—	$44.69 — $62.21	$35.00 — $60.00	$50.50 — $80.00

First Quarter 2007

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
120,000 Bbls	$27.00	—	—	—	—
810,000 Bbls**	—	—	$35.44 — $53.67	$32.00 — $55.00	$44.70 — $82.00

Second Quarter 2007

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
120,000 Bbls	$27.00	—	—	—	—
819,000 Bbls**	—	—	$35.44 — $53.67	$32.00 — $55.00	$44.70 — $82.00

Third Quarter 2007

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
828,000 Bbls**	—	—	$35.44 — $53.67	$32.00 — $55.00	$44.70 — $82.00

Fourth Quarter 2007

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
828,000 Bbls**	—	—	$35.44 — $53.67	$32.00 — $55.00	$44.70 — $82.00

First Quarter 2008

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
819,000 Bbls**	—	—	$33.00 — $50.29	$32.00 — $35.00	$49.50 — $52.90

Second Quarter 2008

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
819,000 Bbls**	—	—	$33.00 — $50.29	$32.00 — $35.00	$49.50 — $52.90

Third Quarter 2008

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
828,000 Bbls**	—	—	$33.00 — $50.29	$32.00 — $35.00	$49.50 — $52.90

Fourth Quarter 2008

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
828,000 Bbls**	—	—	$33.00 — $50.29	$32.00 — $35.00	$49.50 — $52.90

First Quarter 2009

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
810,000 Bbls**	—	—	$33.33 — $50.62	$32.00 — $36.00	$50.00 — $54.55

Second Quarter 2009

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
819,000 Bbls**	—	—	$33.33 — $50.62	$32.00 — $36.00	$50.00 — $54.55

Third Quarter 2009

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
828,000 Bbls**	—	—	$33.33 — $50.62	$32.00 — $36.00	$50.00 — $54.55

Fourth Quarter 2009

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
828,000 Bbls**	—	—	$33.33 — $50.62	$32.00 — $36.00	$50.00 — $54.55

First Quarter 2010

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
900,000 Bbls**	—	—	$34.90 — $51.52	$32.00 — $38.00	$50.00 — $53.50

Second Quarter 2010

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
909,000 Bbls**	—	—	$34.90 — $51.52	$32.00 — $38.00	$50.00 — $53.50

Third Quarter 2010

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
918,000 Bbls**	—	—	$34.91 — $51.52	$32.00 — $38.00	$50.00 — $53.50

Fourth Quarter 2010

	Weighted Average			Range
Volume	Fixed	Floors	Collars	Floor	Ceiling
918,000 Bbls**	—	—	$34.91 — $51.52	$32.00 — $38.00	$50.00 — $53.50

**These 3-way collar contracts are standard crude oil collar contracts with respect to the periods, volumes and prices stated above. The contracts have floor and ceiling prices per barrel as per the table above until the price drops below a weighted average price of $45.88 per barrel. Below $45.88 per barrel, these contracts effectively result in realized prices that are on average $9.29 per barrel higher than the cash price that otherwise would have been realized.

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 at http://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 and the Uinta Basin of the Rocky Mountains. The Company has development projects underway offshore Malaysia, in the U.K. North Sea and Bohai Bay, China.

**The statements set forth in this publication regarding estimated or anticipated third quarter results and production volumes 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 on Form 10-K for the year ended December 31, 2004. In addition, the drilling of oil and gas wells and the production of hydrocarbons are subject to governmental regulations and operating risks.

EX-99.3

Exhibit 99.3

NEWFIELD EXPLORATION ISSUES 2005-07 PRODUCTION GUIDANCE

Development Projects Provide Double-Digit Growth in 2007

FOR IMMEDIATE RELEASE

Houston - (July 26, 2005) - Newfield Exploration Company (NYSE:NFX) today issued an expected range for its annual production for 2005-07. The production growth is coming from 10 significant development projects that the Company has underway in both domestic and international focus areas.

Newfield expects to meet its 2005 production target of 262-272 billion cubic feet equivalent (Bcfe). Including the impact of deferred production from three separate storms in the Gulf of Mexico year-to-date, Newfield expects to produce about 265 Bcfe, an increase of 9% over 2004 production of 244 Bcfe.

For 2006, production is expected to be 273-286 Bcfe, an increase of 3-8% over 2005. Production growth in 2006 will be driven primarily by continued development of the Monument Butte Field in the Uinta Basin, gas mining plays in the Mid-Continent, the Wrigley deepwater development in the Gulf of Mexico, the Grove development in the North Sea and first production from fields in China’s Bohai Bay.

The Company’s production in 2007 is expected to increase 8-15% over 2006 -- or to a range of 300-325 Bcfe. Production in 2007 is expected to benefit from a full year of production from Grove, Wrigley and Bohai Bay Fields, as well as first oil from the Abu Field in Malaysia and continued increases from the Rocky Mountains and the Mid-Continent.

“We are in a better position today at Newfield than we have ever been,” said Newfield Chairman, President and CEO David A. Trice. “Our work to diversify the Company over the last several years has helped to assemble a broad portfolio of development projects - projects that will add significant production and reserve growth for our stockholders. We have visible growth projects for 2006, 2007 and beyond. This growth is from development projects we have in hand today and does not assume acquisitions or significant exploration success.”

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 and the Uinta Basin of the Rocky Mountains. The Company has development projects underway offshore Malaysia, in the U.K. North Sea and in Bohai Bay, China.

**The statements set forth in this release regarding estimated production volumes and timing 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, delays in the construction of infrastructure, delays in obtaining governmental approvals, the availability of capital resources, labor conditions and other factors set forth in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004. 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	Steve Campbell
Houston, TX 77060	(281) 847-6081
www.newfld.com	info@newfld.com

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