NEWFIELD EXPLORATION CO /DE/ - FORM 8-K - EX-99.2 - @NFX PUBLICATION

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8-K - FORM 8-K - NEWFIELD EXPLORATION CO /DE/	nfx8k-10212009.htm
EX-99.1 - EARNINGS PRESS RELEASE - NEWFIELD EXPLORATION CO /DE/	nfx8k-10212009ex991.htm

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, 2009

This edition of @NFX includes:

·	2009 THIRD QUARTER DRILLING ACTIVITY BY AREA

·	RECENT HIGHLIGHTS

·	OPERATIONAL SUMMARIES BY FOCUS AREA

·	FOURTH QUARTER ESTIMATES

·	UPDATED TABLES DETAILING COMPLETE HEDGE POSITIONS

Third Quarter 2009 Drilling Activity*

	NFX Operated		Non-Operated		Gross Wells		Dry Holes
Mid-Continent		25		15		40		0
Rocky Mount.		47		4		51		0
Onshore GC		2		0		2		1
Gulf of Mexico		2		0		2		0
International		1		5		6		0
Total:		77		24		101		1

*Represents a 99% success rate

YTD Total gross wells: 317; YTD dry wells: 6

RECENT HIGHLIGHTS

-	Declining service costs, reduced water handling fees related to deferred completions and efficiency improvements throughout the Company have led to a significant decrease in lease operating expense (LOE) throughout the year. Domestic recurring LOE was $0.81 per Mcfe in the third quarter.

-	We have invested approximately $950 million year-to-date and paid down more than $100 million of debt on our revolver during the year. Significant new projects have been included throughout the year that will help build for the future, and were funded within our $1.45 billion 2009 capital budget.

Our production in the third quarter of 2009 was 65.5 Bcfe, an increase of 7% over the third quarter of 2008. The volumes exclude approximately 2.6 Bcfe of voluntary natural gas curtailments in the second quarter of 2009 in response to low natural gas prices. Full year 2009 production is expected to be in the upper half of original guidance – or greater than 255 Bcfe.

Oil liftings in the third quarter were 3.8 MMBbls, or more than 40,500 BOPD net. This represents a 40% increase over the same period in 2008. The increase is attributable to a 4% increase in our domestic crude volumes and a near-doubling of our international oil liftings. Throughout the second half of 2009, we have shifted capital investments to “oily” projects. Our diversified portfolio provides us with flexibility and multiple options.

-	Strong 2010 hedge position. We have hedged approximately 70% of estimated 2010 natural gas production and approximately 30% of estimated 2011 natural gas production. Approximately 40% of our estimated 2010 crude oil is hedged at more than $100 per barrel.

ENTERING THE MARCELLUS SHALE

On October 14, we entered the Marcellus Shale through a joint exploration agreement with Hess. The agreement covers up to 140,000 gross acres primarily in Susquehanna and Wayne Counties, Pennsylvania. We will operate with a 50 percent interest. Initial drilling is not expected to commence until 2010.

Our proven expertise from large scale developments like the Woodford Shale, Granite Wash and Monument Butte ranks us among a handful of companies that have developed large-scale unconventional plays. We have drilled approximately 300 horizontal wells in the Woodford and over a four-year time span held substantially all of 165,000 net-acre position by production. Our field production today is 317 MMcfe/d gross and we have firm transportation agreements in place to keep pace with our future growth. These activities have led to the development of “core competencies” within our company that will guide our success in the Marcellus.

The 2009 portion of our Marcellus Shale activities, estimated at approximately $20 million, will be funded within our existing $1.45 billion capital budget. We expect to grow our business in the Marcellus play, just as we have created businesses with scale in the Mid-Continent and Rocky Mountains.

MID-CONTINENT

Mid-Continent gross operated production recently reached a new high and is currently 460 MMcfe/d, or 323 MMcfe/d net during the third quarter. The significant increase is primarily attributable to curtailed wells that are being turned to sales, as well as initial production from deferred completions. Newfield has a remaining inventory of 30 wells (28 Woodford and 2 Granite Wash) that have been drilled but not completed. Completions are commencing and will continue through January 2010.

Woodford Shale

Gross operated production in the Woodford Shale set a recent new high, and today is 308 MMcfe/d, up nearly 30% from 240 MMcfe/d at the end of the second quarter. We have drilled approximately 300 horizontal wells and continue to make improvements in both drilling and completion operations. In 2008, we entered development mode in the Woodford and continued efficiency gains have been demonstrated through pad drilling, longer laterals and completion optimization.

We are operating 10 rigs under term contract, with three of the remaining rigs rolling off of term in November and December 2009. Spot market rates on these rigs are significantly lower than term rates.

Over the last several years, we have increased our lateral lengths significantly. We expect that our average completed lateral length will be more than 5,000’ in 2009. The following chart shows the significant increase in lateral length by year:

Shown another way in the chart below, the increasing lateral lengths are leading to marked improvements in finding and development costs. Over the last 12 months, our completed wells costs are down more than 25%.

We are referring to our wells with laterals exceeding 8,000’ as “super extended laterals” or SXLs. Regulatory rules in Oklahoma allow for drilling on stand-up 640 acre units… or units that are ½-mile wide by 2-miles long. This configuration accommodates a 10,000’ lateral. We have drilled two 10,000’ laterals to date and expect to have eight SXLs drilled by year-end ‘09. These wells have planned lateral lengths between 8,000’ and 9,000’. Initial production data from the first SXLs are expected in late 2009.

We also are fracture stimulating our wells with greater efficiency in 2009. The average number of fracs per day has increased to more than five on recent pad completions, compared to just three fracs per day in 2008. This eliminates approximately six days off a standard completion; saving money and allowing us to turn wells to production more quickly.

One of the largest contributors to our Woodford cost reductions has been pad drilling -- a common development technique in resource plays. Now that approximately 95% of our acreage is held-by-production, our development drilling is dominated by multi-well pads. Approximately 85% of our wells in 2009 will be drilled from common pad locations.

Two recent notable Woodford wells that typify increased cost efficiencies include:

·	The Cunningham 3H-22, located in Coal County, was drilled and cased in 26 days for $3.3 million gross. The well was the first on a three-well pad and had a 5,100’ lateral length. The completion was deferred until late 2009.

·	The Tollett 7H-22, located in Hughes County, was drilled and cased in 17 days for $2.7 million. The well had a 5,100’ lateral length. The completion was deferred until late 2009.

The new Mid-Continent Express Pipeline (MEP) links our Woodford production to Perryville, La. For 2009, we have 310 MMcf/d of firm transportation on MEP and an additional 50 MMcf/d on CEGT. We have staged additional firm transportation on Boardwalk to coincide with our future growth needs. In total, we have approximately 650 MMcf/d of firm transportation, helping to ensure we obtain the best possible pricing for our Woodford gas.

The Granite Wash

Based on the success of our initial drilling program in the Granite Wash play, we added a fourth operated rig in our Stiles Ranch field, located in Wheeler County, Texas. In July, we announced that the first seven horizontal wells in our Stiles Ranch field had an average initial production rate of 22 MMcfe/d. Recent well completions have been deferred and the Company expects to have production results from 6 – 8 additional completions in early 2010.

We have increased lateral lengths on recent wells to approximately 4,000’, compared to about 3,500’ on average for our initial seven wells.

(For additional information on Granite Wash, please see @NFX July 22, 2009 and the Granite Wash feature in Oil and Gas Investor magazine, October 2009.)

ROCKY MOUNTAINS

Monument Butte Field

Despite dropping two operated rigs in Monument Butte in early 2009, production from our Rocky Mountain division is expected to be up about 9% in 2009. Due to higher oil prices and improved differentials, we recently added a fourth rig at Monument Butte and expect to add a fifth rig in early 2010. Monument Butte production is approximately 16,000 BOPD gross and a five-rig program is expected to grow annual volumes by more than 10%.

Monument Butte Well Costs

Differentials for Black Wax crude have narrowed in 2009. The chart below shows our position in the overall Black Wax market and in that area refining capacity has been increasing. Monument Butte is a giant resource with more than 2 billion barrels in place. Through the drilling of several thousand additional wells, we expect to recover 18-20% of the original oil in place. We have more than a decade-long inventory of drilling locations and significant growth through this large oil asset.

Williston Basin

We expect to add up to two additional operated rigs in our Williston Basin development areas. We have been running a one-rig program since early 2009. We have approximately 200,000 net acres in prospective development areas, located primarily on the Nesson Anticline and west of the Nesson. An additional 200,000 net acres are located in northern Montana where several exploration plays are underway. We have drilled 12 successful oil wells in the North Dakota portion of the Williston, focusing to date primarily on the Bakken Shale and Three Forks/Sanish formations.

Two wells were drilled since the last quarter’s update: Trigger is our first well in Big Valley, an area covering more than 50,000 net acres in northern North Dakota. The well was recently fracture stimulated and continues to clean-up. Early results warrant additional drilling to asses this large area. Sergeant Major was drilled in the Catwalk area, which covers 25,300 net acres. Completion operations on the well are expected to commence next week.

GULF OF MEXICO

We have seven deepwater developments underway in the Gulf of Mexico which are expected to provide significant future growth. Our most recent development is Fastball, located at Viosca Knoll 1003. Fastball commenced production on October 19. Gross production is expected to ramp up to 40 MMcf/d and 3,200 BOPD. We operate Fastball with a 66% interest.

Pyrenees -- In the second quarter of 2009, we announced a significant operated discovery on its Pyrenees Prospect, located at Garden Banks 293 in approximately 2,100 feet of water. A recent sidetrack delineated the downdip limits in the three proven pay sands seen in the discovery well and provided encouragement for the exploration potential of both the shallow and deep sand sections on the feature. Additional drilling is planned for 2010. We operate the development with a 40% working interest.

Over the last several years, we have assembled a substantial inventory of exploration prospects in the deepwater Gulf of Mexico. We own interests in 88 deepwater blocks (approximately 500,000 gross acres). We plan to drill 3-5 deepwater Gulf of Mexico wells each year for the next several years.

INTERNATIONAL

International oil liftings in the third quarter of 2009 increased more than 90% over the same period in 2008. We lifted 2.1 MMBbls in the third quarter, or an average of 23,380 BOPD net. The increased liftings reflects production recent developments offshore Malaysia as well as timing of liftings in the quarter.

Malaysia

During the third quarter, liftings from Malaysia average 21,270 BOPD net. Production increases are attributable to higher rates from the East Belumut and Chermingat oil fields. We recently accelerated the timing of our planned East Belumut “Phase II” program, with plans to drill six development wells in late 2009 and an additional six wells in 2010. We expect to invest approximately $18 million in 2009 and $18 million in early 2010 associated with Phase II. Our developments are located on two shallow water blocks – PM 318 and PM 323. We have a 50% interest in PM 318 and a 60% operated interest in PM 323.

China

For the third quarter of 2009, our offshore China liftings averaged 2,108 BOPD net. We recently announced a significant operated oil discovery on our Pearl prospect, located in the Pearl River Mouth Basin. The Pearl development is underway with first production expected in 2012. The LF 7-1 well encountered more than 250’ of high-quality oil pay in multiple sands and tested a single zone at 6,000 BOPD, which was the maximum limit of the test equipment on location. The well was an exploration offset to a downthrown anticline and was an offset to our 2008 oil discovery – the LF 7-2. The two successes confirmed a commercial oil development with first production expected in late 2012. There is significant additional reserve potential in deeper objectives at Pearl, as well as with prospects along a structural ridge located to the northeast. We call these our Jade prospects.

Prior to year-end 2009, we expect to spud an exploration well on our first Jade prospect. We have a 100% working interest in the Pearl development; CNOOC has a 51% back-in election to any commercial development.

FOURTH QUARTER ESTIMATES

	4Q09 Estimates
	Domestic		Int’l		Total
Production/Liftings
Natural gas – Bcf		44.7 – 45.5		–		44.7 – 45.5
Oil and condensate – MMBbls		1.7 – 1.8		1.4 – 1.5		3.1 – 3.3
Total Bcfe		54.9 – 56.3		8.4 – 9.0		63.3 – 65.3

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)	$	34.2 - $37.8	$	18.4 - $20.3	$	52.6 - $58.1
per/Mcfe	$	0.62 - $0.67	$	2.19 - $2.25	$	0.83 - $0.89
Major (workover, repairs, etc.) ($MM) Note 4	$	13.1 - $14.5		--	$	13.1 - $14.5
per/Mcfe	$	0.24 - $0.26		--	$	0.21 - $0.22

Production and other taxes ($MM)Note 5	$	14.0 - $15.4	$	13.3 - $14.7	$	27.3 - $30.1
per/Mcfe	$	0.26 - $0.27	$	1.58 - $1.63	$	0.43 - $0.46

General and administrative (G&A), net ($MM)	$	29.8 - $33.0	$	1.4 - $1.5	$	31.2 - $34.5
per/Mcfe	$	0.54 - $0.59	$	0.16 - $0.17	$	0.49 - $0.53

Capitalized internal costs ($MM)					$	(18.5 - $20.4	)
per/Mcfe					$	(0.29 - $0.31	)

Interest expense ($MM)					$	29.0 - $32.0
per/Mcfe					$	0.46 - $0.49

Capitalized interest ($MM)					$	(11.0 - $12.1	)
per/Mcfe					$	(0.17 - $0.19	)

Tax rate (%)Note 6						36 - 38	%

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

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 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. Note 2: Oil prices in the Gulf Coast typically average 90–95% of NYMEX WTI price. Rockies oil prices are currently averaging about $12–$14 per barrel below WTI. Oil production from the Mid-Continent typically averages 85–90% of WTI. Note 3: Oil in Malaysia typically sells at a slight discount to Tapis, or about 90–95% of WTI. Oil production from China typically sells at $6–$8 per barrel less than WTI. Note 4: Domestic major expense includes approximately $6 million for well workover expense and other projects initiated in response to higher commodity prices and lower service costs. Note 5: Guidance for production taxes determined using $75/Bbl oil and $4.50/MMBtu gas. Note 6: 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 2009 and beyond are as of October 20, 2009:

Fourth Quarter 2009

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
26,120 MMMBtus	$	7.34		—		—		—		—
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
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		—		—		—		—

Second Quarter 2011

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
19,110 MMMBtus	$	6.55		—		—		—		—

Third Quarter 2011

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
19,320 MMMBtus	$	6.55		—		—		—		—

Fourth Quarter 2011

	Weighted Average						Range
Volume	Fixed		Floors		Collars		Floor		Ceiling
6,510 MMMBtus	$	6.55		—		—		—		—

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
	$	4.00	$	5.00	$	6.00	$	7.00		$	8.00		$	9.00
2009
4th Quarter	$	123	$	88	$	54	$	19		$	(15	)	$	(43	)
Total 2009	$	123	$	88	$	54	$	19		$	(15	)	$	(43	)

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	$	48	$	29	$	10	$	(8	)	$	(27	)	$	(46	)
2nd Quarter	$	49	$	30	$	10	$	(9	)	$	(28	)	$	(47	)
3rd Quarter	$	49	$	30	$	11	$	(9	)	$	(28	)	$	(47	)
4th Quarter	$	17	$	10	$	4	$	(3	)	$	(9	)	$	(16	)
Total 2011	$	163	$	99	$	35	$	(29	)	$	(92	)	$	(156	)

In the Rocky Mountains, we hedged basis associated with approximately 17 Bcf of our natural gas production from October 2009 through full-year 2012. This is in addition to the 8,000 mmbtu/d sold on a fixed physical basis for the same term for a total basis hedged for the period at an average of $(0.94) per Mmbtu.

In the Mid-Continent, we hedged basis associated with approximately 14 Bcf of our anticipated Stiles/Britt Ranch production from October 2009 through August 2011. This is in addition to the 30,000 mmbtu/d sold on a fixed physical basis for the same term for a total basis hedged for the period at an average of $(0.52) per Mmbtu. In addition, we 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 10% of our natural gas production correlates to Houston Ship Channel, 13% to Columbia Gulf, 13% to Texas Gas Zone 1, 5% to Southern Natural Gas, 10% to Tenn 100, 6% to CenterPoint/East, 24% to Panhandle Eastern Pipeline, 6% to Waha, 7% to Colorado Interstate, 6% to others.

CRUDE OIL HEDGE POSITIONS

The following hedge positions for the fourth quarter of 2009 and beyond are as of October 20, 2009:

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
180,000 Bbls*		—		—	$	60.00— $112.05	$	60	$	112.00—$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
182,000 Bbls*		—		—	$	60.00— $112.05	$	60	$	112.00—$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
184,000 Bbls*		—		—	$	60.00— $112.05	$	60	$	112.00—$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
184,000 Bbls*		—		—	$	60.00— $112.05	$	60	$	112.00—$112.10

*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 Bbls as per the table above until the price drops below a weighted average price of $50 per Bbls. Below $50 per Bbls, these contracts effectively result in realized prices that are on average $10 per Bbls 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
2009
4th Quarter	$	129	$	115	$	99	$	84	$	70	$	54	$	39
Total 2009	$	129	$	115	$	99	$	84	$	70	$	54	$	39

2010
1st Quarter	$	70	$	61	$	50	$	42	$	33	$	23	$	14
2nd Quarter	$	71	$	62	$	51	$	42	$	33	$	24	$	15
3rd Quarter	$	72	$	63	$	52	$	42	$	33	$	24	$	15
4th Quarter	$	72	$	62	$	52	$	42	$	33	$	24	$	15
Total 2010	$	285	$	248	$	205	$	168	$	132	$	95	$	59

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 distributions.

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 release, such as information regarding estimated or anticipated fourth quarter 2009 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.

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