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):   October 21, 2008

_____________________________

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 October 21, 2008, Newfield Exploration Company (“Newfield”) issued a press release announcing its third quarter 2008 financial and operating results, fourth quarter 2008 earnings guidance and 2009 capital budget.  A copy of the press release is furnished herewith as Exhibit 99.1.

Item 7.01  Regulation FD Disclosure

On October 21, 2008, Newfield issued its @NFX publication, which includes third quarter 2008 highlights, an operational update by region, fourth quarter 2008 earnings guidance, 2009 capital budget and production guidance, and tables detailing complete hedging positions as of October 20, 2008.  A copy of the publication is furnished herewith as Exhibit 99.2.

Item 9.01  Financial Statements and Exhibits

(d)	Exhibits
	99.1	Press Release issued by Newfield on October 21, 2008
	99.2	@NFX publication issued by Newfield on October 21, 2008

SIGNATURES

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

	NEWFIELD EXPLORATION COMPANY
Date:   October 22, 2008	By:	/s/ Brian L. Rickmers
		Brian L. Rickmers
		Controller

Exhibit Index

Exhibit No.	Description
99.1	Press Release Issued by Newfield on October 21, 2008
99.2	@NFX publication issued by Newfield on October 21, 2008

EX-99.1

Exhibit 99.1

Newfield Reports Third Quarter 2008 Financial Results

2009 Capital Spending Plans Aligned with Estimated Cash Flow

FOR IMMEDIATE RELEASE

Houston – October 21, 2008 – Newfield Exploration Company (NYSE: NFX) today reported third quarter 2008 financial and operating results. Newfield will be hosting a conference call at 3:30 p.m. CDT, Wednesday, October 22. To participate in the call, dial 719-325-2179 or listen through the website at http://www.newfield.com.

Third Quarter 2008

Newfield’s production in the third quarter of 2008 was 61.4 Bcfe. Production during the third quarter reflects the impact of the deferral of more than 2 Bcfe of production as a result of recent storms in the Gulf of Mexico. Based on the pace of storm recovery, Newfield was today able to slightly increase its full-year 2008 expected range of production to 235-238 Bcfe, an increase of approximately 25% over 2007 pro forma production (adjusted for asset sales and acquisitions). Previous guidance was 234-238 Bcfe.

For the third quarter of 2008, Newfield reported net income of $724 million, or $5.48 per diluted share (all per share amounts are on a diluted basis). Income for the third quarter of 2008 includes a net unrealized gain on commodity derivatives of $846 million ($589 million after-tax), or $4.46 per share.

 Without the effect of this item, net income was $135 million, or $1.02 per share.

Revenues in the third quarter of 2008 were $680 million. Net cash provided by operating activities before changes in operating assets and liabilities was $396 million. See “Explanation and Reconciliation of Non-GAAP Financial Measures” found after the financial statements in this release.

Capital Investments, Financial Update

“Both operationally and financially, Newfield is performing very well in 2008,” said David Trice, Chairman, President and CEO. “Unfortunately, the realities of today’s broader markets have shifted investor focus away from most traditional valuation metrics. Over the last 20 years, we have weathered many cycles and each time have relied on our strong balance sheet, hedging, ample access to liquidity and the proven track record of our management team. We are focused on what matters in 2009. We will fund the best projects. Our reduction in 2009 planned capital expenditures, $450 million less than our initial planned capital expenditures, will help ensure that we balance current growth expectations with our consistent goal of building long-term value for our shareholders. We have a diverse portfolio of assets which provide us with multiple options in today’s environment.”

Capital expenditures in the third quarter of 2008 were $514 million. Newfield reiterated that it expects 2008 capital investments to total approximately $2.2 billion, which includes a $226 million acquisition in the first half of the year.

Newfield today disclosed a significant reduction in its planned spending levels in 2009. For 2009, Newfield plans to invest $1.65 billion --- matching its capital budget with cash flow expectations. The 2009 budget includes approximately $100 million for capitalized interest and overhead. This reduced budget compares to preliminary guidance of approximately $2.1 billion (including capitalized interest and overhead), announced on September 9, 2008. Newfield expects 8-13% production growth in 2009, or a range of 255-267 Bcfe. A detailed budget overview will be presented during Newfield’s conference call with analysts and investors at 3:30 p.m. CDT, October 22, 2008.

For 2009, Newfield has hedged nearly 60% of its expected natural gas production and about 90% of expected domestic oil production. These hedge positions, which help ensure cash flow in 2009, are detailed in the Company’s @NFX publication on the Company’s website.

Newfield has a $1.25 billion credit revolver funded through 18 financial institutions. The largest commitment by a member of the syndicate of financial institutions is 8% of the facility. At the end of the third quarter, Newfield had $285 million of outstanding borrowings under the facility.

For an operational update on Newfield’s focus areas, please see the @NFX publication on the Company’s website.

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.newfield.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 of growing reserves through an active drilling program and select acquisitions. Newfield's domestic areas of operation include the Anadarko and Arkoma Basins of the Mid-Continent, the Rocky Mountains, onshore Texas and the Gulf of Mexico. The Company has international operations in Malaysia and China.

**This release contains forward-looking information. All information other than historical facts included in this release, such as information regarding estimated or anticipated fourth quarter 2008 results, estimated full-year 2008 production, estimated 2009 capital expenditures, cash flow and production growth, drilling and development plans and the timing of activities, is forward-looking information. Although Newfield believes that these expectations are reasonable, this information is based upon assumptions and anticipated results that are subject to numerous uncertainties and risks. 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 refining capacity for the crude oil Newfield produces from its Monument Butte field in Utah, the availability of capital resources, labor conditions and severe weather conditions (such as hurricanes). In addition, the drilling of oil and gas wells and the production of hydrocarbons are subject to governmental regulations and operating risks.

For information, contact:

Investor Relations: Steve Campbell (281) 847-6081

Media Relations: Keith Schmidt (281) 674-2650

Email: info@newfield.com

3Q08 Actual Results

	3Q08 Actual
	Domestic		Int’l		Total
Production/Liftings*
Natural gas – Bcf		44.9		–		44.9
Oil and condensate – MMBbl		1.6		1.1		2.7
Total Bcfe		54.7		6.7		61.4
Average Realized Prices Note 1
Natural gas – $/Mcf	$	7.25	$	–	$	7.25
Oil and condensate – $/Bbl	$	70.57	$	106.87	$	85.44
Mcf equivalent – $/Mcfe	$	8.05	$	17.81	$	9.12
Operating Expenses:
Lease operating
Recurring ($MM)	$	44.8	$	13.1	$	57.9
per/Mcfe	$	0.82	$	1.94	$	0.94
Major ($MM)	$	9.5	$	–	$	9.5
per/Mcfe	$	0.17	$	–	$	0.16
Production and other taxes ($MM)	$	20.5	$	30.1	$	50.6
per/Mcfe	$	0.38	$	4.46	$	0.82
General and administrative (G&A), net ($MM)	$	34.6	$	1.5	$	36.1
per/Mcfe	$	0.63	$	0.23	$	0.59
Capitalized G&A ($MM)					$	(17.9	)
per/Mcfe					$	(0.29	)
Interest expense ($MM)					$	36.2
per/Mcfe					$	0.59
Capitalized interest ($MM)					$	(16.8	)
per/Mcfe					$	(0.27	)
*Reflects approximately 2 Bcfe of deferred domestic gas production related to GOM storms. Note 1: Actual average realized prices include the effects of hedging contracts. If the effects of these contracts were excluded, the average realized price for total gas would have been $8.67 per Mcf and the total oil and condensate average realized price would have been $106.04 per barrel.

4Q08 Estimates

	4Q08 Estimates
	Domestic		Int’l		Total
Production/Liftings*
Natural gas – Bcf		42.0 – 44.2		–		42.0 – 44.2
Oil and condensate – MMBbl		1.8 – 1.9		1.4 – 1.5		3.2 – 3.4
Total Bcfe		52.8 – 54.6		8.3 – 8.7		61.1 – 63.3
Average Realized Prices
Natural gas – $/Mcf	Note 1
Oil and condensate – $/Bbl	Note 2		Note 3
Mcf equivalent – $/Mcfe
Operating Expenses:
Lease operating
Recurring ($MM)	$	39.4 - $43.6	$	13.3 - $14.7	$	52.7 - $58.3
per/Mcfe	$	0.75 - $0.80	$	1.60 - $1.69	$	0.86 - $0.92
Major (workover, repairs, etc.) ($MM)	$	8.3 - $9.1	$	0.7 - $0.8	$	9.0 - $9.9
per/Mcfe	$	0.16 - $0.17	$	0.08 - $0.09	$	0.14 - $0.16
Production and other taxes ($MM)Note 4	$	19.7 - $21.8	$	15.8 - $17.5	$	35.5 - $39.3
per/Mcfe	$	0.37 - $0.40	$	1.90 - $2.00	$	0.58 - $0.62
General and administrative (G&A), net ($MM)	$	35.4 - $39.1	$	1.5 - $1.7	$	36.9 - $40.8
per/Mcfe	$	0.67 - $0.72	$	0.18 - $0.20	$	0.60 - $0.64
Capitalized G&A ($MM)					$	(17.2 - $19.1	)
per/Mcfe					$	(0.28 - $0.30	)
Interest expense ($MM)					$	32.0 - $36.0
per/Mcfe					$	0.52 - $0.57
Capitalized interest ($MM)					$	(15.0 - $17.0	)
per/Mcfe					$	(0.25 - $0.27	)
Tax rate (%)Note 5						37 - 40	%
Income taxes (%)
Current						15 - 20	%
Deferred						80 - 85	%
*Reflects approximately 3 Bcfe of deferred domestic gas production related to GOM storms. Note 1: Gas prices in the Mid-Continent, after basis differentials, transportation and handling charges, typically average 75 – 85% of the Henry Hub Index. Gas prices in the Gulf Coast, after basis differentials, transportation and handling charges, are expected to average $0.40 – $0.60 per MMBtu less than the Henry Hub Index. Note 2: Oil prices in the Gulf Coast typically equal the NYMEX WTI price. Rockies oil prices average about $15 per barrel below WTI. Oil production from the Mid-Continent typically averages 96 – 98% of WTI. Note 3: Oil in Malaysia typically sells at a slight discount to Tapis, or about 90% of WTI. Oil production from China typically sells at $10 - $15 per barrel below WTI. Note 4: Guidance for production taxes determined using $70/Bbl oil and $7/MMBtu gas. Note 5:  Tax rate applied to earnings excluding unrealized gains or losses on commodity derivatives.

CONSOLIDATED STATEMENT OF INCOME (Unaudited, in millions, except per share data)	For the Three Months Ended  September 30,						For the Nine Months Ended  September 30,
	2008			2007			2008			2007
Oil and gas revenues	$	680		$	419		$	1,887		$	1,384
Operating expenses:
Lease operating		67			64			184			268
Production and other taxes		51			25			154			63
Depreciation, depletion and amortization		181			162			504			539
General and administrative		36			37			105			107
Total operating expenses		335			288			947			977
Income from operations		345			131			940			407
Other income (expenses):
Interest expense		(36	)		(29	)		(83	)		(80	)
Capitalized interest		16			13			43			35
Commodity derivative income (expense)		726			38			(247	)		(43	)
Other		8			1			10			3
		714			23			(277	)		(85	)
Income from continuing operations before     income taxes		1,059			154			663			322
Income tax provision		335			62			247			125
Income from continuing operations		724			92			416			197
Loss from discontinued operations, net of tax		—			(9	)		—			(60	)
Net income	$	724		$	83		$	416		$	137
Earnings (loss) per share:
Basic --
Income from continuing operations	$	5.59		$	0.72		$	3.22		$	1.54
Loss from discontinued operations, net of tax		—			(0.07	)		—			(0.47	)
	$	5.59		$	0.65		$	3.22		$	1.07
Diluted --
Income from continuing operations	$	5.48		$	0.70		$	3.15		$	1.51
Loss from discontinued operations, net of tax		—			(0.06	)		—			(0.46	)
	$	5.48		$	0.64		$	3.15		$	1.05
Weighted average number of shares outstanding for basic earnings (loss) per share		129			128			129			127
Weighted average number of shares outstanding for diluted earnings (loss) per share		132			131			132			130

CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited, in millions)	September 30, 2008			December 31, 2007
ASSETS
Current assets:
Cash and cash equivalents	$	35		$	250
Short-term investments		—			120
Other current assets		765			557
Total current assets		800			927
Oil and gas properties, net (full cost method)		7,180			5,923
Other assets		452			136
Total assets	$	8,432		$	6,986
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	1,003		$	929
Other liabilities		206			322
Long-term debt		1,936			1,050
Deferred taxes		1,253			1,104
Total long-term liabilities		3,395			2,476
Commitments and contingencies		—			—
STOCKHOLDERS’ EQUITY
Common stock		1			1
Additional paid-in capital		1,322			1,278
Treasury stock		(32	)		(32	)
Accumulated other comprehensive loss		(10	)		(3	)
Retained earnings		2,753			2,337
Total stockholders’ equity		4,034			3,581
Total liabilities and stockholders’ equity	$	8,432		$	6,986

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited, in millions)	For the Nine Months Ended September 30,
	2008			2007
Cash flows from operating activities:
Net income	$	416		$	137
Adjustments to reconcile net income to net cash provided by     operating activities:
Loss from discontinued operations, net of tax		—			60
Depreciation, depletion and amortization		504			539
Stock-based compensation		17			18
Commodity derivative expense		247			43
Cash (payments) receipts on derivative settlements		(783	)		174
Deferred taxes		213			47
		614			1,018
Changes in operating assets and liabilities		8			(75	)
Net cash provided by continuing activities		622			943
Net cash used in discontinued activities		—			(12	)
Net cash provided by operating activities		622			931
Cash flows from investing activities:
Additions to oil and gas properties and other		(1,551	)		(1,539	)
Acquisition of oil and gas properties		(231	)		(578	)
Proceeds from sale of oil and gas properties		2			1,281
Purchases of short-term investments		(22	)		(43	)
Redemption of short-term investments		70			24
Net cash used in continuing activities		(1,732	)		(855	)
Net cash used in discontinued activities		—			(41	)
Net cash used in investing activities		(1,732	)		(896	)
Cash flows from financing activities:
Net proceeds under credit arrangements		285			—
Net proceeds from issuance of senior subordinated notes		592			—
Payments to discontinued operations		—			(38	)
Proceeds from issuances of common stock		18			18
Stock-based compensation excess tax benefit		—			8
Purchases of treasury stock		—			(1	)
Net cash provided by (used in) continuing activities		895			(13	)
Net cash provided by discontinued activities		—			38
Net cash provided by financing activities		895			25
Effect of exchange rate changes on cash and cash equivalents		—			1
Increase (decrease) in cash and cash equivalents		(215	)		61
Cash and cash equivalents from continuing operations,     beginning of period		250			52
Cash and cash equivalents from discontinued operations,     beginning of period		—			28
Cash and cash equivalents, end of period	$	35		$	141

Explanation and Reconciliation of Non-GAAP Financial Measures

Earnings stated without the effects of certain items is a non-GAAP financial measure. Earnings without the effects of these items are presented because they affect the comparability of operating results from period to period. In addition, earnings without the effects of these items are more comparable to earnings estimates provided by securities analysts.

A reconciliation of earnings for the third quarter of 2008 stated without the effects of certain items to net income is shown below:

		3Q08
	(in millions)
Net income	$	724
Net unrealized gain on commodity derivatives (1)		(846	)
Income tax adjustment for above item		257
Earnings stated without the effect of the above items	$	135

(1) The determination of “Net unrealized gain on commodity derivatives” for the third quarter of 2008 is as follows:

		3Q08
	(in millions)
Commodity derivative income	$	726
Cash payments on derivative settlements		116
Option premiums associated with derivatives settled       during the period		4
Net unrealized gain on commodity derivatives	$	846

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 (used in) 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:

		3Q08
	(in millions)
Net cash provided by operating activities	$	451
Net change in operating assets and liabilities		(55	)
Net cash provided by operating activities before changes    in operating assets and liabilities	$	396

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.

October 21, 2008

This edition of @NFX includes:

·   Recent Highlights

·   Operational Updates

·   Fourth Quarter 2008 Estimates

·   Updated Tables Detailing Complete Hedging Positions

HIGHLIGHTS

-   We expect that our capital budget for 2009 will be $1.65 billion (including approximately $100 million of capitalized interest and overhead). This represents a $450 million decrease from our September 9, 2008, initial estimate of approximately $2.1 billion (including capitalized interest and overhead). Newfield expects to live within cash flow from operations in 2009.

-   Based on revised capital spending plans, Newfield expects production growth of 8 -13% in 2009 – or an expected range of 255 - 267 Bcfe.

-   Total company production guidance for 2008 was slightly increased to 235-238 Bcfe (previous range was 234-238 Bcfe). The increase relates to the pace of storm recoveries in the Gulf of Mexico. Production estimates for 2008 compare to 2007 actual production of approximately 190 Bcfe (adjusted for asset sales and acquisitions), representing an increase of approximately 25%.

-   NFX and partners today announced a significant deepwater discovery at the Dalmation Prospect. Please see details under the Gulf Coast section in this @NFX publication.

Third Quarter 2008 Drilling Activity

              &# 160;         NFX Operated       Non-Operated           Gross Wells            Dry Holes

Mid-Continent	28	24	52	0
Rocky Mount.	57	3	60	0
Onshore GC	19	1	26	6
Gulf of Mexico	0	1	1	0
International	3	2	5	0
Total:	107	31	144	6

Year-to-Date 2008 Drilling Activity

                     NFX Operated            Non-Operated           Gross Wells            Dry Holes

Mid-Continent	95	80	176	1
Rocky Mount.	177	11	190	2
Onshore GC	48	8	68	12
Gulf of Mexico	3	0	4	1
International	8	9	18	1
Total:	331	108	456	17

MID-CONTINENT

THE WOODFORD SHALE

Our gross operated production from the Woodford Shale reached more than 220 MMcfe/d in September, up from 165 MMcfe/d at year end 2007. Gross production is expected to exit 2008 at approximately 250 MMcfe/d and production volumes in 2009 are expected to increase nearly 40% over 2008 levels.

The Woodford remains the most active play in Oklahoma and its development represents our largest capital expenditure. There are 736 industry horizontal wells drilled to date. We have operated more than 225 of these wells and have 165,000 net acres, of which approximately 80% is “held-by-production.”

The Woodford will remain our largest area of capital investment in 2009. We plan to run 12 operated rigs through the end of 2008 with this number increasing to 15 operated rigs in 2009.  We have the option to add, or reduce, our rig count as service costs and/or commodity prices warrant.

We are currently completing our first dual lateral well (each lateral is 4,800’ in length) in the Woodford. The well was successfully drilled and completions are going as planned with first production in early November. Success with this concept could significantly lower development costs for the play. In November, we will spud our first “super extended” lateral of 8,000’ to 10,000’.

More than half of our operated rigs today are drilling from common pads. To date, we have completed and placed on production 59 wells drilled from pads. Cost improvements from the first well on a pad to the fourth well have ranged from 25% to as much as 75%. Pad drilling significantly decreases completed well costs through the elimination of roads, and by minimizing rig mobilization days between spuds, optimizing completion logistics as well as through reduced drilling days. In addition, pads allow for the use of common fracture stimulation sites that further reduce completion costs.

Woodford Firm Transportation Helps Maximize Future Price

In an effort to ensure that we minimize basis differentials, we have signed firm transportation for a substantial portion of our expected growth in the Woodford Shale. We have firm transportation on Midcontinent Express Pipeline (MEP) and sales to Laclede Energy Resources for a total of 360,000 dth/d of firm capacity in 2009.  This will increase with Gulf Crossing Pipeline Company LLC beginning in March 2010 initially adding 100,000 dth/d.  Firm transportation will incrementally expand to a maximum total of 600,000 dth/d in 2012.

MOUNTAIN FRONT WASH/STILES RANCH FIELD

Our working interest is predominately 100%, and we have approximately 50,000 net acres in the play, located in the Texas Panhandle and western Oklahoma. Drilling activity in Mountain Front Wash continues with 3 operated rigs running. Stiles Ranch hit a mid-year 2008 high of more than 110 MMcfe/d.

Horizontal drilling technology has dramatically changed the landscape of onshore drilling through more efficient reserve recovery and lower finding and development costs.  The Stiles Ranch field, one of Newfield’s largest producing assets, has been developed to date with vertical wells. Our knowledge base from the Woodford Shale is now being applied to the future development of Stiles.

We recently performed a study on the feasibility of horizontal drilling in the Stiles Ranch field. Horizontal development has the potential to improve estimated recovery and lower F&D costs.  We plan to test lateral lengths between 2,500’ and 4,000’. We are drilling our first horizontal well with a planned lateral length of 3,800’. We have an extensive inventory of drilling locations in Stiles Ranch – including up to 110 horizontal locations. We plan to dedicate at least 1 of 3 rigs next year to drilling horizontal wells.

ROCKY MOUNTAINS

MONUMENT BUTTE

Our largest producing oil asset in the Rocky Mountains is Monument Butte, located in the Uinta Basin of Utah. Current gross production is approximately 15,700 BOPD and is expected to increase to about 16,500 BOPD in November. In 2009, we will continue with a 5-rig operated program. Demand for black wax remains strong with 100% of 2008 and 2009 volumes sold under term contracts with area refiners.

Success continues with our 20-acre spaced development program. To date, we have drilled 115 successful wells on 20-acre spacing. Results continue to indicate the potential to drill as many as 2,500 wells on 20-acre spacing. These locations are in addition to the more than 1,000 locations remaining to drill the field down to 40-acre spacing. Our total acreage in the Monument Butte field area includes about 162,000 gross acres, which includes 62,000 acres with Ute Energy and the Ute Tribe.

Newfield is drilling its 40th well on Tribal acreage today – 38 of the 39 wells drilled to date have been successful. Recent wells on the Ute acreage have performed above expectations and are consistent with main field producing intervals to the south. One rig will be dedicated to drilling wells on this acreage throughout 2009.   

We are assessing the deep gas potential beneath Monument Butte. Prospective targets include the Wasatch, Mesa Verde, Blackhawk, Mancos and Dakota. The play concept covers 82,000 acres and is held by production through our shallow Green River oil production at Monument Butte.

We have drilled the first two of several deep Mancos Shale tests beneath Monument Butte under a Deep Gas Exploration Agreement that is underway with Red Technology Alliance (RTA). The initial well is being completed and the second well is drilling to 18,500’.

Approximately 10,700 net acres in the immediate vicinity of recent deep gas tests were excluded from the agreement. Completion of our first operated deep gas test (NFX working interest 75%) is underway and a second well (NFX working interest 100%) is drilling.

GREATER WILLISTON BASIN 

Our current net production from the area is approximately 2,500 BOEPD, and our activity level in the greater Williston Basin is expected to increase in 2009. We plan to operate three rigs throughout 2009. Plans include continued development and expansion along the Nesson Anticline and our exploration areas west of the Nesson and in Montana. 

We have 473,000 gross acres (160,000 net) in the Williston Basin.Our acreage position has prospective targets that include the Bakken Shale, as well as the Madison, Red River and Three Forks/Sanish. We completed additional horizontal wells in the Bakken formation and early production results are summarized below:

Ø   Larsen 1-16H: 710 BOEPD (Disclosed September 2)

Ø   Jorgenson 1-10H: 911 BOEPD (Disclosed September 2)

Ø   Jorgenson 1-4H: 622 BOEPD

Ø   Rolfsrud 1-32H: 590 BOEPD

The Jorgenson 1-15H, our first Sanish/Three Forks horizontal well, is an apparent success and the well awaits completion at this time. Flow rates are expected in early November. We expect to drill four additional operated wells near this well in 2008.

Continued development drilling in our Westberg prospect area is planned, where we have drilled three successful wells to date and identified 22 development locations from earlier successes and additional infill drilling locations. We also plan continued development drilling in our Lost Bear prospect area where we have drilled three successful wells to date and identified 5-10 development locations.

In 2009, we will assess our acreage position west of the Nesson and in Montana.  Two wells are planned in our Big Valley area and four wells are planned in our large acreage positions in the Southern Alberta Basin and northeastern Williston Basin.

GULF COAST REGION

Newfield and partners recently announced a significant deepwater Gulf of Mexico discovery at the Dalmatian prospect, located at Desoto Canyon Block 48. The well found more than 120' measured depth of net high quality dry gas pay. The discovery is located in about 5,900’ of water.

The discovery will be developed via a subsea tie to existing infrastructure. Newfield has a 37.5% working interest. Partners include: Murphy Oil Corporation (operator) with a 50% working interest, and Mariner Energy with a 12.5% working interest.

In addition to Dalmation, we own working interests between 23% and 50% in nine contiguous blocks offsetting this discovery. We have five additional amplitude prospects in the area that we are evaluating for future exploration and development potential.

In addition to Dalmation, we have four additional deepwater developments:

Gladden: The MC 800#1updip sidetrack tested approximately 5,600 BOEPD.  We expect first production in late 2009 or early 2010. We operate and have a 47.5% working interest.

Anduin West: Located at Mississippi Canyon 754, the well tested 18 MMcf/d and 2,400 BCPD. We expect first production in late 2009.

Fastball: Located at VK 1003, this single well development will be a sub-sea tieback to existing infrastructure with first production expected in late 2009 or early 2010. We operate Fastball with a 66% working interest.

Glider: Operator Shell plans to spud the Glider #5 development well in Green Canyon Block 248 during the second quarter of 2009. This well will be drilled in proximity to the original Glider discovery well drilled in 1996. Plans call for production in late 2009. We have a 25% working interest in Glider.

SOUTH TEXAS

Newfield has an interest in nearly 500,000 acres in Texas.

Newfield is active under two separate joint ventures with ExxonMobil in South Texas that cover nearly 140,000 (gross) acres. Newfield’s interest in these ventures is approximately 50%. Production from the Sarita field area is approximately 67 MMcfe/d (gross). At Sarita, we have established pay in a new fault block with our SKE B-96 well, which logged nearly 200' of net pay.

We made a potential discovery with J. G. Kenedy #1 in Kenedy County, Texas. The well was drilled to 18,142' with casing and completion operations already begun. We are currently drilling below 17,000' on the Kenedy #2, which is being drilled on a separate structure on this 35,000 acre block, which lies just east of our prolific Sarita Field. We have a 50% working interest. The potential gross size of this prospect is 80 - 100 BCFE.

INTERNATIONAL

MALAYSIA

Current gross production in Malaysia is more than 35,000 BOPD. Although exploration expenditure will be curtailed in 2009, development of our oil fields will continue. In shallow water Malaysia, we have a 50% interest in PM 318 and a 60% operated interest in PM 323. We expect to spud the Paus-1 exploration well in the first quarter of 2009 in Deepwater Block 2C. We are the operator with a 40% working interest. Other partners include Petronas Carigali (40%) and Mitsubishi (20%).

CHINA

Current production from two fields on Blocks 04/36 and 05/36 is 18,000 BOPD gross or approximately 2,000 BOPD net to NFX. Newfield holds a 12% interest in the unit. The operator, Anadarko, is planning to drill 25-30 additional development wells in the complex and production is expected to further increase in 2009.

FOURTH QUARTER 2008 ESTIMATES

	Domestic		Int’l		Total
Production/Liftings*
Natural gas – Bcf		42.0 – 44.2		–		42.0 – 44.2
Oil and condensate – MMBbl		1.8 – 1.9		1.4 – 1.5		3.2 – 3.4
Total Bcfe		52.8 – 54.6		8.3 – 8.7		61.1 – 63.3
Average Realized Prices
Natural gas – $/Mcf	Note 1
Oil and condensate – $/Bbl	Note 2		Note 3
Mcf equivalent – $/Mcfe
Operating Expenses:
Lease operating
Recurring ($MM)	$	39.4 - $43.6	$	13.3 - $14.7	$	52.7 - $58.3
per/Mcfe	$	0.75 - $0.80	$	1.60 - $1.69	$	0.86 - $0.92
Major (workover, repairs, etc.) ($MM)	$	8.3 - $9.1	$	0.7 - $0.8	$	9.0 - $9.9
per/Mcfe	$	0.16 - $0.17	$	0.08 - $0.09	$	0.14 - $0.16
Production and other taxes ($MM)Note 4	$	19.7 - $21.8	$	15.8 - $17.5	$	35.5 - $39.3
per/Mcfe	$	0.37 - $0.40	$	1.90 - $2.00	$	0.58 - $0.62
General and administrative (G&A), net ($MM)	$	35.4 - $39.1	$	1.5 - $1.7	$	36.9 - $40.8
per/Mcfe	$	0.67 - $0.72	$	0.18 - $0.20	$	0.60 - $0.64
Capitalized G&A ($MM)					$	(17.2 - $19.1	)
per/Mcfe					$	(0.28 - $0.30	)
Interest expense ($MM)					$	32.0 - $36.0
per/Mcfe					$	0.52 - $0.57
Capitalized interest ($MM)					$	(15.0 - $17.0	)
per/Mcfe					$	(0.25 - $0.27	)
Tax rate (%)Note 5						37 - 40	%
Income taxes (%)
Current						15 - 20	%
Deferred						80 - 85	%
*Reflects approximately 3 Bcfe of deferred domestic gas production related to GOM storms. Note 1: Gas prices in the Mid-Continent, after basis differentials, transportation and handling charges, typically average 75 – 85% of the Henry Hub Index. Gas prices in the Gulf Coast, after basis differentials, transportation and handling charges, are expected to average $0.40 – $0.60 per MMBtu less than the Henry Hub Index. Note 2: Oil prices in the Gulf Coast typically equal the NYMEX WTI price. Rockies oil prices average about $15 per barrel below WTI. Oil production from the Mid-Continent typically averages 96 – 98% of WTI. Note 3: Oil in Malaysia typically sells at a slight discount to Tapis, or about 90% of WTI. Oil production from China typically sells at $10 - $15 per barrel below WTI. Note 4: Guidance for production taxes determined using $70/Bbl oil and $7/MMBtu gas. Note 5:  Tax rate applied to earnings excluding unrealized gains or losses on commodity derivatives.

NATURAL GAS HEDGE POSITIONS

Please see the tables below for our complete hedging positions.

The following hedge positions for the fourth quarter of 2008 and beyond are as of October 20, 2008:

Fourth Quarter 2008

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
9,445 MMMBtus	$	8.04		—		—		—		—
15,965 MMMBtus		—		—	$	8.03 — $10.70	$	7.00 — $9.00	$	9.00 — $17.60
6,100 MMMBtus*		—		—	$	8.70 — $13.92	$	8.00 — $9.00	$	11.72 — $20.10
1,860 MMMBtus		—	$	8.64		—	$	8.58 — $8.70		—

First Quarter 2009

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
900 MMMBtus	$	9.00		—		—		—		—
21,150 MMMBtus		—		—	$	8.09 — $10.88	$	8.00 — $9.00	$	9.67 — $17.60
9,000 MMMBtus*		—		—	$	8.70 — $13.92	$	8.00 — $9.00	$	11.72 — $20.10

Second Quarter 2009

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
16,505 MMMBtus	$	8.33		—		—		—		—
13,485 MMMBtus		—		—	$	8.00 — $11.83	$	8.00	$	8.97 — $14.37

Third Quarter 2009

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
16,660 MMMBtus	$	8.33		—		—		—		—
13,620 MMMBtus		—		—	$	8.00 — $11.83	$	8.00	$	8.97 — $14.37

Fourth Quarter 2009

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
9,265 MMMBtus	$	8.42		—		—		—		—
8,435 MMMBtus		—		—	$	8.23 — $11.20	$	8.00 — $8.50	$	8.97 — $14.37

First Quarter 2010

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
5,400 MMMBtus	$	8.55		—		—		—		—
5,700 MMMBtus		—		—	$	8.50 — $10.44	$	8.50	$	10.00 — $11.00

Second Quarter 2010

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
1,820 MMMBtus	$	8.01		—		—		—		—

Third Quarter 2010

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
1,840 MMMBtus	$	8.01		—		—		—		—

Fourth Quarter 2010

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
620 MMMBtus	$	8.01		—		—		—		—

*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 MMBtu as per the table above until the price drops below a weighted average price of $7.20 per MMBtu. Below $7.20 per MMBtu, these contracts effectively result in realized prices that are on average $1.50 per MMBtu higher than the cash price that otherwise would have been realized.

The following table details the expected impact to pre-tax income from the settlement of our derivative contracts, outlined above, at various NYMEX gas prices, net of premiums paid for these contracts (in millions).

	Gas Prices
	$	5.00	$	6.00	$	7.00	$	8.00	$	9.00
2008
Total 2008	$	92	$	65	$	37	$	6	$	(10	)
2009
1st Quarter	$	83	$	60	$	38	$	9		—
2nd Quarter	$	92	$	63	$	34	$	5	$	(12	)
3rd Quarter	$	92	$	63	$	33	$	4	$	(12	)
4th Quarter	$	34	$	23	$	13	$	2	$	(5	)
Total 2009	$	301	$	209	$	118	$	20	$	(29	)
2010
Total 2010	$	52	$	37	$	21	$	6	$	(7	)

In conjunction with our recent acquisition of properties in the Rocky Mountains, we hedged basis associated with 50% of the proved producing fields from August 2007 through full-year 2012. The weighted average hedged differential during this period was $(1.18) per Mcf.

Approximately 31% of our natural gas production correlates to Houston Ship Channel, 25% to CenterPoint/East, 19% to Panhandle Eastern Pipeline, 10% to Waha, 7% to Colorado Interstate, 8% to others.

CRUDE OIL HEDGE POSITIONS

The following hedge positions for the fourth quarter of 2008 and beyond are as of October 20, 2008:

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	$	128.93		—		—		—		—
810,000 Bbls		—	$	107.11		—	$	104.50 — $109.75		—

Second Quarter 2009

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
819,000 Bbls	$	128.93		—		—		—		—
819,000 Bbls		—	$	107.11		—	$	104.50 — $109.75		—

Third Quarter 2009

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
828,000 Bbls	$	128.93		—		—		—		—
828,000 Bbls		—	$	107.11		—	$	104.50 — $109.75		—

Fourth Quarter 2009

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
828,000 Bbls	$	128.93		—		—		—		—
828,000 Bbls		—	$	107.11		—	$	104.50 — $109.75		—

First Quarter 2010

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
90,000 Bbls	$	93.40		—		—		—		—
810,000 Bbls		—		—	$	127.97— $170.00	$	125.50 — $130.50	$	170.00

Second Quarter 2010

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
90,000 Bbls	$	93.40		—		—		—		—
819,000 Bbls		—		—	$	127.97— $170.00	$	125.50 — $130.50	$	170.00

Third Quarter 2010

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
90,000 Bbls	$	93.40		—		—		—		—
828,000 Bbls		—		—	$	127.97— $170.00	$	125.50 — $130.50	$	170.00

Fourth Quarter 2010

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
90,000 Bbls	$	93.40		—		—		—		—
828,000 Bbls		—		—	$	127.97— $170.00	$	125.50 — $130.50	$	170.00

**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 $26.56 per barrel. Below $26.56 per barrel, these contracts effectively result in realized prices that are on average $6.44 per barrel higher than the cash price that otherwise would have been realized.

The following table details the expected impact to pre-tax income from the settlement of our derivative contracts, outlined above, at various NYMEX oil prices, net of premiums paid for these contracts (in millions).

Oil Prices
	$	50.00	$	60.00		$	70.00		$	80.00		$	90.00
2008
Total 2008	$	0	$	(8	)	$	(17	)	$	(25	)	$	(33	)
2009
1st Quarter	$	104	$	88		$	72		$	55			39
2nd Quarter	$	105	$	89		$	72		$	56		$	40
3rd Quarter	$	106	$	90		$	73		$	57		$	40
4th Quarter	$	140	$	129		$	118		$	107		$	90
Total 2009	$	455	$	396		$	335		$	275		$	209
2010
Total 2010	$	241	$	205		$	168		$	132		$	95

Newfield Exploration Company is an independent crude oil and natural gas exploration and production company. The Company relies on a proven growth strategy of growing reserves through an active drilling program and select acquisitions. Newfield's domestic areas of operation include the Anadarko and Arkoma Basins of the Mid-Continent, the Rocky Mountains, onshore Texas and the Gulf of Mexico. The Company has international operations in Malaysia and China.

**This publication contains forward-looking information. All information other than historical facts included in this publication, such as information regarding estimated or anticipated fourth quarter 2008 results, estimated full-year 2008 and 2009 production, drilling and development plans, estimated 2009 capital expenditures, cash flow and production growth, the timing of activities, the timing of initial production and future rates of production from wells, fields and regions, expected cost reductions and the expected ultimate recovery of reserves from wells, is forward-looking information. Although Newfield believes that these expectations are reasonable, this information is based upon assumptions and anticipated results that are subject to numerous uncertainties and risks. 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 refining capacity for the crude oil Newfield produces from its Monument Butte field in Utah, the availability of capital resources, labor conditions and severe weather conditions (such as hurricanes). In addition, the drilling of oil and gas wells and the production of hydrocarbons are subject to governmental regulations and operating risks.