NEWFIELD EXPLORATION CO /DE/ - FORM 8-K - EX-99.3 - @NFX PUBLICATION

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8-K - FORM 8-K - NEWFIELD EXPLORATION CO /DE/	nfx8k-02162010.htm
EX-99.2 - EARNINGS PRESS RELEASE - NEWFIELD EXPLORATION CO /DE/	nfx8k-02162010ex992.htm
EX-99.1 - RESERVES PRESS RELEASE - NEWFIELD EXPLORATION CO /DE/	nfx8k-02162010ex991.htm

Exhibit 99.3

@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.

February 16, 2010

This edition of @NFX includes:

·	2009 HIGHLIGHTS & 2010 PLANS2009 FOURTH QUARTER DRILLING ACTIVITY BY AREA

·	OPERATIONAL SUMMARIES BY FOCUS AREA

·	UPDATED TABLES DETAILING COMPLETE HEDGE POSITIONS

Fourth Quarter 2009 Drilling Activity*

	NFX Operated		Non-Operated		Gross Wells		Dry Holes
Mid-Continent		30		5		35		0
Rocky Mount.		54		7		61		0
Onshore GC		2		1		3		0
Gulf of Mexico		1		1		2		1
International		3		1		4		0
Total:		90		15		105		1

*Represents a 99% success rate

2009 total gross wells: 422; dry wells: 7

2009 HIGHLIGHTS

·	Full year 2009 production was 257 Bcfe, an increase of 9% over 2008 production volumes. Production was in the top half of our original 2009 guidance (250-260 Bcfe), despite curtailment of 3 Bcfe in 3Q09 related to low natural gas prices.

Our proved reserves increased 23% in 2009 and at year-end were 3.6 Tcfe. The Company replaced approximately 250% of its 2009 production with the addition of new reserves (excluding the impact of the new SEC rules). Proved reserves in Newfield’s two largest divisions – the Mid-Continent and Rocky Mountains – increased 34% and represent more than 80% of the Company’s total proved reserves. Approximately 53% of the Company’s proved reserves were proved developed and 72% were natural gas. The Company’s proved reserve life index is approximately 14 years, reflecting continued growth in longer-lived resource plays. A detailed news release on our proved reserves for 2009 was released on February 16, 2010.

We allocated our capital more effectively in 2009. We lived within our cash flow from operations in 2009, while reducing our debt by approximately $200 million. Some 2009 projects were deferred into future periods and we added new projects to our original budget totaling approximately $100 million. Capital investments for 2009 totaled $1.4 billion.

In recent months, we added more than 500,000 net acres in long-lived, domestic resource plays. New ventures include: acquisition of Maverick Basin assets from TXCO Resources, Inc (>300,000 acres), Marcellus Shale entry through an exploration agreement with Hess Corp (approximately 35,000 acres), and a joint venture on Blackfeet Tribal acreage in northern Montana’s Southern Alberta Basin (approximately 156,000 acres).

2010 CAPITAL INVESTMENT PLANS AND PRODUCTION GUIDANCE

Newfield’s 2010 capital budget is $1.6 billion (including approximately $124 million in capitalized interest and overhead). This budget approximates the Company’s estimate of 2010 cash flow from operations and includes approximately $100 million for planned investments on the acreage recently acquired in the Maverick Basin of Texas. The budget excludes the recent $215 million purchase price for the acquisition of assets from TXCO Resources, Inc.

Our production for 2010 is expected to be 278 – 288 Bcfe, an increase of 8 – 12% over 2009. In 2010, we will invest approximately 70% of our budget, or approximately $1 billion, in domestic resource plays. More than one-third of the budget will be directed to oil plays. The following pie chart details our expected 2010 production by area.

Newfield has ample liquidity and, following our recent issuance of $700 million of 6 7/8% Senior Subordinated Notes, we have no outstanding borrowings under our $1.25 billion credit facility. Approximately 70% of our expected 2010 gas production is hedged at a weighted average minimum price of approximately $6.60 per MMbtu. Approximately 65% of our expected 2010 domestic oil production is hedged at a weighted average minimum price of approximately $108.00 per barrel. Complete hedging details are found at the end of this edition of @NFX.

RECENT ACTIVITTY BY AREA AND 2010 PLANS

ONSHORE TEXAS

For 2010, the primary focus of our activity will be on the acreage that we recently acquired in the Maverick Basin from TXCO Resources. This transaction closed on February 11, 2010. In 2010, we expect to invest approximately $100 million in the asset, with drilling programs beginning in the second quarter.

This transaction marked our entry into the Maverick Basin of Texas. We now have 300,000 net acres located primarily in Maverick and Dimmit Counties, Texas. Current production from the assets totals about 1,300 BOEPD. There are multiple geologic horizons on the acreage, with prospects ranging from dry gas to oil. The following cross section details the prospective formations throughout our acreage.

Our 2010 plans are aggressive. We will begin work immediately and expect to be running at least three operated rigs here by summer. Our efforts will be primarily focused on three plays – the Eagle Ford, Pearsall Shales and the Georgetown formation.

MID-CONTINENT

Our net production from the Mid-Continent grew 18% in 2009. The growth is being driven by the Granite Wash and Woodford Shale plays. Gross production from the Mid-Continent is currently more than 500 MMcfe/d, or approximately 320 MMcfe/d net. Approximately 40% of our 2010 budget will be allocated to our activities in the Mid-Continent.

The Granite Wash

In today’s fourth quarter and full year 2009 earnings and operating release, we announced results from six additional completions in our horizontal Granite Wash play. In total, we have results from 13 Granite Wash horizontal completions. Average initial production rates for our first 12 wells was 20 MMcfe/d. Our 13th well, the Britt 8-6H, commenced production this week and the rate continues to rise following fracture stimulation. We have six additional horizontal Granite Wash wells that are in various stages of completion at this time. The following chart shows our results to date.

Since 2002, we have drilled approximately 150 vertical wells in our Granite Wash play (primarily Stiles/Britt Ranch fields, Wheeler County, Texas). We know from this drilling that there are multiple productive horizons within the four primary geologic targets – Marmaton, Red Fork, Cherokee and Atoka. In the table above, the wells with high condensate yields were located in the Marmaton, the shallowest of the four targets. Of our recent wells (6) were completed in the Atoka, a known dry-gas producer. We plan to drill horizontal wells in 4-6 additional horizons in 2010.

We continue to optimize our drilling and completion practices in the Granite Wash. Lateral lengths in our most recent wells are 4,300’ - 4,700’ and our “best in class” drill and complete costs to date is approximately $7.3 million. Our drill and case cost per lateral foot is down approximately 20% when comparing our first seven wells with our most recent wells.

We are running a four rig program today and expect that this level of activity will allow us to drill about 20 horizontal wells in 2010. Although extensive work is underway to determine our overall development plan, we estimate that there are about 250 remaining horizontal locations in our Granite Wash play. We have more than 40,000 net acres in this play.

The Woodford Shale

Our production in the Woodford continues to grow. Gross operated production is approximately 329 MMcfe/d, or approximately 191 MMcfe/d net. Our 2009 volumes in the Woodford grew 25% and we expect that our production will increase more than 25% during 2010. Today, we have 166,500 net acres in the play and substantially all of the acreage is held by production.

In 2010, we expect to run 6-8 operated rigs in our Woodford Shale area. Although this is fewer operated rigs than we have run in previous years, our efficiency gains are allowing us to drill and complete more lateral feet per year, per rig. The following chart depicts these efficiency gains.

We expect to drill approximately 50 horizontal wells in our Woodford play in 2010. Our average lateral length is expected to be approximately 6,000’. We define wells with lateral lengths in excess of 5,000’ as “Super Extended Laterals,” or SXLs. About one-third of our 2010 wells in the Woodford are expected to be SXLs. Our efficiencies have been improved through lengthened laterals and operational gains. Our average lateral length in 2009 was approximately 5,000’, compared to an average of approximately 4,000’ in 2008 and less than 2,500’ in 2006-07.

To date, the Company has drilled 11 SXLs with an average lateral length of nearly 9,000’. As previously reported, the first five SXL wells had average initial production rates of approximately 10 MMcfe/d gross. The remainder of the SXLs (6) are in various stages of completion.

Today, we have more than 300 horizontal wells producing in the Woodford Shale. Since October 2009, we have completed and turned a total of 34 Woodford wells to sales (SXLs, standard completions and multi-well pads). The average initial gross production rate for all wells is 6 MMcfe/d.

Since the beginning of 2009, our drill and complete costs in the Woodford have decreased about 20%.

ROCKY MOUNTAINS

Our net production from the Rocky Mountains grew 10% in 2009 and is expected to grow by a comparable amount in 2010. Nearly 25% of our 2010 budget will be allocated to our activities in the Rocky Mountains. Our primary areas of focus will be the Uinta, Williston and Southern Alberta Basins.

Monument Butte

Our largest oil asset is Monument Butte, located in the Uinta Basin of northeast Utah. The Monument Butte field covers approximately 180,000 net acres (includes 63,000 Ute Tribal acres). Our production from this field is currently 17,000 BOPD (gross). In 2010, we expect to run a 5-rig program and to drill about 275 wells. Our Monument Butte production is expected to increase 15% in 2010.

Recent drilling results on our Ute Tribal acreage have exceeded our expectations. To date, we have drilled 75 wells on this acreage, located north and adjacent to Monument Butte. We have two rigs active on this acreage today. Recent wells have “stepped out” as far as 10 miles from core development drilling areas and initial production rates have ranged from 100 – 1,500 BOPD. Our interest on the Ute Tribal acreage is approximately 70%. The following map shows our acreage in the Monument Butte area.

There are more than 1,300 producing wells in the Monument Butte field, of which approximately 900 have been drilled since we acquired the field in 2004. The average initial gross production rate for a typical Monument Butte well has ranged from 65 – 80 BOPD.

Williston / Southern Alberta Basins

Over the last several years, we have assembled a large acreage position in the Williston and Southern Alberta Basins. Newfield has approximately 150,000 net acres in prospective development areas, located primarily on the Nesson Anticline and west of the Nesson. In addition, Newfield owns interest in approximately 54,000 net acres in the Elm Coulee field. In addition, we have 221,000 net acres in the Southern Alberta Basin of northern Montana. Our activity levels in these regions are increasing and we expect that our Williston production will grow by about 40% in 2010. We have more than 80 development locations, located primarily along the Nesson Anticline. Our current net production is approximately 3,000 BOEPD.

Due to strong oil prices, we recently increased our operated rig count in the Williston to three rigs. Two of the rigs will be dedicated to our development areas, located along the Nesson Anticline. The third rig will be used to continue to assess our acreage west of the Nesson. We have drilled 14 successful oil wells in the North Dakota portion of the Williston Basin since entering the region in late 2007. The following chart details our results to date:

In late 2009, we signed an agreement with the Blackfeet Nation, adding 156,000 net acres in the Southern Alberta Basin. This was additive to our existing acreage and we now own interests in 221,000 net acres in Glacier County, Montana. The area is geologically similar to the Williston Basin. Our prospective oil targets include: the Bakken, Three Forks and Lodgepole. We expect to begin assessment drilling in the region in April 2010 and, depending on success, plan to drill as many as 10 operated wells during 2010.

MARCELLUS SHALE / APPALACHIAN BASIN

In late 2009, we entered the Marcellus Shale through a joint exploration agreement with Hess. To date, we have leased interests in approximately 35,000 net acres, primarily in Susquehanna and Wayne Counties, Pennsylvania. We operate the venture with a 50 percent working interest.

We recently filed permits to drill up to 10 vertical assessment wells in Wayne County in 2010. Our first well is expected to spud this summer.

GULF OF MEXICO

Approximately 15% of our 2010 budget will be allocated to our activities in the deepwater Gulf of Mexico. Our GOM production is expected to increase more than 60% in 2010. We have five active deepwater developments that we expect to add significant production growth in 2010 -12. In addition to these developments, we anticipate participating in 2-3 deepwater exploration wells in 2010.

GOM Deepwater Developments

·	Fastball: Fastball (Viosca Knoll 1003) commenced production in late 2009. This field is currently producing 41 MMcf/d and 3,000 BOPD gross. We operate with a 66% working interest.

·	Sargent: We are currently developing Sargent (Garden Banks 339), which was a 2008 discovery with a single well tie back to existing infrastructure. We have a 25% interest in this non-operated development and expect first production in April 2010.

Gladden: In December 2009, we gained an additional 10% interest in our Gladden development through a trade for our remaining interest in the Anduin West development (Mississippi Canyon 754). Gladden (Mississippi Canyon 800) is expected to commence production in late 2010. We operate with a 57.5% working interest.

·	Dalmatian: The Dalmatian development (DeSoto Canyon 48) is underway with first production expected in 2011. Newfield has a 37.5% non-operated interest in this development. Additional exploration opportunities exist around Dalmatian.

Pyrenees: In mid-2009, we announced a significant operated discovery at Pyrenees (Garden Banks 293). Development of the field is underway with first production expected in late 2011. Additional drilling prospects remain on an 11-block area around Pyrenees. We operate the development with a 40% working interest.

2010 GOM Deepwater Exploration

Our 2010 planned exploration wells in the deepwater GOM are shown below:

Saluki prospect: Our operated Saluki prospect (Garden Banks 425) will spud in late February 2010. We have recently taken additional partners in the well and will have a 50% working interest (35% cost interest). The prospect is located in close proximity to our Pyrenees development.

Axe: Located in close proximity to our outside-operated Dalmatian development, Axe (DeSoto Canyon 4) is expected to spud in March 2010. We will have a 23% non-operated interest in Axe.

We expect to drill 1-2 additional deepwater prospects in 2010, including Lyell (Green Canyon 551) where we have a 25% substantially-carried interest.

INTERNATIONAL

Our international activities in 2010 will comprise about 15% of our planned capital budget. Our activities are focused solely on our offshore Malaysia and China assets (Bohai Bay and Pearl River Mouth Basin). Our production from our international division was up 40% in 2009. It is expected to decline in 2010, but will grow significantly in 2011 and 2012 due to new field developments.

Malaysia

Total liftings from Malaysia in 2009 totaled 5.3 MMBbls, or 14,500 BOPD (net). Our production benefitted from new developments East Belumut and Chermingat, located on PM 323.

East Belumut and Chermingat – In late 2009, we accelerated planned development drilling in our East Belumut field, offshore Malaysia. We are now drilling our sixth of seven planned development wells from an existing platform. The program is expected to add approximately 1 MMBbls of incremental oil production in 2010 due to its accelerated timing. Our interest in PM 323, which we operate, is approximately 60%.

Phase II drilling operations on Newfield’s East Belumut platform

Horizontal drilling is not only applied in U.S. resource plays… in fact, we have been increasing our lateral lengths overseas, as well. Our development wells in the East Belumut field are all horizontal wells and recent completions are nearly 6,000’.

China

Our Bohai Bay production is approximately 2,500 BOPD net. We have a 12% non-operated interest in a unit where more than 20 planned development wells are expected to be drilled during 2010.

In the Pearl River Mouth Basin, our recent Jade exploration test was unsuccessful. The dry hole was drilled to test a fault separated structure approximately 10 miles northeast of our Pearl discovery. The well was drilled for approximately $10 million and material exploration opportunities remain in the area.

Our operated Pearl development is underway with first production expected in late 2012. We recently completed the first phase of the regulatory approval process, which we anticipate be concluded by the end of 2010.

We have two additional exploration wells planned offshore China in 2010.

FIRST QUARTER 2010 ESTIMATES

	1Q10 Estimates
	Domestic		Int’l		Total
Production/Liftings
Natural gas – Bcf		45.6 – 50.4		–		45.6 – 50.4
Oil and condensate – MMBbls		1.6 – 1.7		1.3 – 1.4		2.9 – 3.1
Total Bcfe		54.9 – 60.7		7.7 – 8.5		62.6 – 69.2

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)	$	54.9 - $60.7	$	14.2 - $15.7	$	69.1 - $76.4
per/Mcfe	$	1.01 - $1.03	$	1.82 - $1.86	$	1.11 - $1.13
Major (workover, repairs, etc.) ($MM)	$	9.1 - $10.1	$	0.4 - $0.5	$	9.5 - $10.5
per/Mcfe	$	0.16 - $0.17	$	0.04 - $0.05	$	0.15 - $0.16

Production and other taxes ($MM)Note 4	$	17.1 - $18.9	$	11.7 - $12.9	$	28.8 - $31.8
per/Mcfe	$	0.31 - $0.32	$	1.50 - $1.53	$	0.46 - $0.47

General and administrative (G&A), net ($MM)	$	34.2 - $37.8	$	1.1 - $1.2	$	35.3 - $39.0
per/Mcfe	$	0.63 - $0.64	$	0.14 - $0.15	$	0.57 - $0.58

Capitalized internal costs ($MM)					$	(19.4 - $21.5	)
per/Mcfe					$	(0.31 - $0.32	)

Interest expense ($MM)					$	39.0 - $43.1
per/Mcfe					$	0.62 - $0.64

Capitalized interest ($MM)					$	(11.5 - $12.7	)
per/Mcfe					$	(0.18 - $0.19	)

Tax rate (%)Note 5						35% - 37	%

Income taxes (%)
Current						14% - 16	%
Deferred						84% - 86	%

Note 1: The price that we receive for natural gas production from the Gulf of Mexico and onshore Gulf Coast, after basis differentials, transportation and handling charges, typically averages $0.25 - $0.50 per MMBtu less than the Henry Hub Index. Realized natural gas prices for our Mid-Continent properties, after basis differentials, transportation and handling charges, typically average 85-90% of the Henry Hub Index. Note 2: The price we receive for our Gulf Coast oil production typically averages about 90-95% of the NYMEX West Texas Intermediate (WTI) price. The price we receive for our oil production in the Rocky Mountains is currently averaging about $12-$14 per barrel below the WTI price. Oil production from our Mid-Continent properties typically averages 80-85% of the WTI price. Note 3: Oil sales from our operations in Malaysia typically sell at a slight discount to Tapis, or about 90-95% of WTI. Oil sales from our operations in China typically sell at $4-$6 per barrel less than the WTI price. Note 4: Guidance for production taxes determined using $70/Bbl oil and $5.50/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 first quarter of 2010 and beyond are as of February 15, 2010:

First Quarter 2010

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
31,800 MMMBtus	$	6.79		—		—		—		—
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
34,850 MMMBtus	$	6.41		—		—		—		—

Third Quarter 2010

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
35,200 MMMBtus	$	6.41		—		—		—		—

Fourth Quarter 2010

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
28,320 MMMBtus	$	6.49		—		—		—		—

First Quarter 2011

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
18,900 MMMBtus	$	6.55		—		—		—		—
9,900 MMMBtus*		—		—	$	6.00 — $7.91	$	6.00	$	7.75 — $8.03

Second Quarter 2011

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
19,110 MMMBtus	$	6.55		—		—		—		—
10,010 MMMBtus*		—		—	$	6.00 — $7.91	$	6.00	$	7.75 — $8.03

Third Quarter 2011

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
19,320 MMMBtus	$	6.55		—		—		—		—
10,120 MMMBtus*		—		—	$	6.00 — $7.91	$	6.00	$	7.75 — $8.03

Fourth Quarter 2011

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
6,510 MMMBtus	$	6.55		—		—		—		—
8,290 MMMBtus*		—		—	$	6.00 — $7.94	$	6.00	$	7.75 — $8.03

*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 $4.50 per MMMBtu. Below $4.50 per MMMBtu, these contracts effectively result in realized prices that are on average $1.50 per MMMBtu 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.

	Gas Prices
	$	4.00	$	5.00	$	6.00	$	7.00		$	8.00		$	9.00
2010
1st Quarter	$	114	$	77	$	40	$	2		$	(35	)	$	(70	)
2nd Quarter	$	84	$	49	$	14	$	(21	)	$	(56	)	$	(91	)
3rd Quarter	$	85	$	49	$	14	$	(21	)	$	(56	)	$	(91	)
4th Quarter	$	70	$	43	$	14	$	(14	)	$	(43	)	$	(71	)
Total 2010	$	353	$	218	$	82	$	(54	)	$	(190	)	$	(323	)

2011
1st Quarter	$	63	$	39	$	10	$	(8	)	$	(28	)	$	(57	)
2nd Quarter	$	64	$	40	$	10	$	(9	)	$	(29	)	$	(58	)
3rd Quarter	$	64	$	40	$	11	$	(9	)	$	(29	)	$	(58	)
4th Quarter	$	29	$	18	$	4	$	(3	)	$	(10	)	$	(25	)
Total 2011	$	220	$	137	$	35	$	(29	)	$	(96	)	$	(198	)

In the Rocky Mountains, we hedged basis associated with approximately 15 Bcf of our natural gas production from January 2010 through December 2012 to lock in the differential at a weighted average of $0.95 per MMBtu less than the Henry Hub Index. In total, this hedge and the 8,000 MMBtu per day we have sold on a fixed physical basis for the same period results in an average basis hedge of $0.95 per MMBtu.

In the Mid-Continent, we hedged basis associated with approximately 12 Bcf of our anticipated Stiles/Britt Ranch natural gas production from January 2010 through August 2011. In total, this hedge and the 30,000 MMBtu per day we have sold on a fixed physical basis for the same period results in an average basis hedge of $0.52 per MMBtu. We have also hedged basis associated with approximately 23 Bcf of our natural gas production from this area for the period September 2011 through December 2012 at an average of $0.55 per MMBtu.

Approximately 12% of our natural gas production correlates to Houston Ship Channel, 13% to Columbia Gulf, 13% to Texas Gas Zone 1, 9% to Southern Natural Gas, 9% to Tenn 100, 5% to CenterPoint/East, 22% to Panhandle Eastern Pipeline, 6% to Waha, 6% to Colorado Interstate, and 5% to others.

CRUDE OIL HEDGE POSITIONS

The following hedge positions for the first quarter of 2010 and beyond are as of February 15, 2010:

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
360,000 Bbls*		—		—	$	67.50 — $106.28	$	60.00 — $75.00	$	100.00 —$112.10

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
364,000 Bbls*		—		—	$	67.50 — $106.28	$	60.00 — $75.00	$	100.00 —$112.10

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
368,000 Bbls*		—		—	$	67.50 — $106.28	$	60.00 — $75.00	$	100.00 —$112.10

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
368,000 Bbls*		—		—	$	67.50 — $106.28	$	60.00 — $75.00	$	100.00 —$112.10

First Quarter 2011

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
360,000 Bbls*		—		—	$	77.50 — $119.94	$	75.00 — $80.00	$	118.50—$121.50

Second Quarter 2011

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
364,000 Bbls*		—		—	$	77.50 — $119.94	$	75.00 — $80.00	$	118.50—$121.50

Third Quarter 2011

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
368,000 Bbls*		—		—	$	77.50 — $119.94	$	75.00 — $80.00	$	118.50—$121.50

Fourth Quarter 2011

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
368,000 Bbls*		—		—	$	77.50 — $119.94	$	75.00 — $80.00	$	118.50—$121.50

*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 Bbl as per the table above until the price drops below a weighted average price of $58.75 per Bbl. Below $58.75 per Bbl, these contracts effectively result in realized prices that are on average $13.75 per Bbl 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
	$	40.00	$	50.00	$	60.00	$	70.00	$	80.00	$	90.00	$	100.00
2010
1st Quarter	$	73	$	64	$	53	$	43	$	33	$	23	$	14
2nd Quarter	$	74	$	65	$	54	$	43	$	33	$	24	$	15
3rd Quarter	$	74	$	65	$	54	$	43	$	33	$	24	$	15
4th Quarter	$	75	$	65	$	54	$	43	$	33	$	24	$	15
Total 2010	$	296	$	259	$	215	$	172	$	132	$	95	$	59



2011
1st Quarter	$	5	$	5	$	5	$	2	$	-	$	-	$	-
2nd Quarter	$	5	$	5	$	5	$	3	$	-	$	-	$	-
3rd Quarter	$	6	$	6	$	6	$	3	$	-	$	-	$	-
4th Quarter	$	6	$	6	$	6	$	3	$	-	$	-	$	-
Total 2011	$	22	$	22	$	22	$	11	$	-	$	-	$	-

We provide information regarding our outstanding hedging positions in our annual and quarterly reports filed with the SEC and in our 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 the drilling of a balanced risk/reward portfolio and select acquisitions. Newfield's domestic areas of operation include the U.S. onshore Gulf Coast, the Anadarko and Arkoma Basins of the Mid-Continent, the Rocky Mountains 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 first quarter 2010 results, estimated capital expenditures, cash flow, production and cost reductions, 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 and cost 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.

Attached files

NEWFIELD EXPLORATION CO /DE/ Reports

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