NEWFIELD EXPLORATION CO /DE/ - FORM 8-K - EX-99.2 - EXHIBIT 99.2

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8-K - FORM 8-K - NEWFIELD EXPLORATION CO /DE/	nfx8k-101911.htm
EX-99.1 - EXHIBIT 99.1 - NEWFIELD EXPLORATION CO /DE/	ex991.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 19, 2011

Newfield today released financial and operational results for the third quarter of 2011. The earnings and operational release can be found on our website.

This edition of @NFX includes:

·	Updated 2011 production guidance

·	An update on recent oil developments

·	Fourth quarter and full-year 2011 estimates

·	Updated tables detailing complete hedge positions. Items highlighted reflect new and/or changed data since our last publication on September 7, 2011

2011 PRODUCTION GUIDANCE

Newfield today adjusted its full year 2011 production guidance to 300 – 304 Bcfe (previous guidance was 312 – 316 Bcfe). Reconciliation to previous guidance is shown in the table below:

	BCFE
Previous Guidance	312-316
3Q Adjustments to Guidance
Williston Basin deferred completions / other	(6)
Reduced capital expenditures	(3)
Non-strategic asset sales	(2)
Gulf of Mexico weather	(1)
Current Guidance	300-304*

*Includes approximately 4 Bcfe of production associated with new offshore developments in Malaysia and the Gulf of Mexico.

AN UPDATE ON RECENT OIL DEVELOPMENTS

UINTA BASIN

Our gross production in the Uinta Basin recently reached a high of 24,500 BOPD. Today, we are high-grading our rig fleet by adding increased horsepower rigs to drill deeper targets in the Central Basin. These rigs also will be capable of drilling horizontal wells in the geopressured Wasatch (planned for 2012). We expect to operate at least 8 rigs in the Uinta Basin in 2012.

We have more than 250,000 acres in the Uinta Basin and we believe that our assets have net undeveloped resource potential of more than 700 MMBOE in the proven horizons of the Green River, Wasatch and Uteland Butte.

The Wasatch formation is being developed throughout the Central Basin and is prospective at depths of 9,000’ – 11,000’ total vertical depth (TVD). Over the last year, 14 vertical wells have been drilled on our acreage.

We recently completed several additional Wasatch wells in the Central Basin. Notable wells include the Lamb 1-19-3-1W, which had 24-hour gross initial production of 1,168 BOEPD and a 30-day gross average of 617 BOEPD, the Padilla 1-18-3-2W, which had 24-hour gross initial production of 1,102 BOEPD and the Miles 15-8-3-2, which had 24-hour gross initial production of 850 BOEPD. A recent “best in class” deep Wasatch well was drilled and cased in 13 days from spud to rig release. We plan to complete five additional wells in the fourth quarter of 2011.

The Uteland Butte horizontal oil play is prospective between 6,000’ – 9,000’ TVD on approximately 80% of our total acreage in the Uinta Basin. Portions of the play are geopressured and wells drilled in these areas are expected to have both higher production and estimated ultimate recovery (EUR).

To date, we have drilled seven horizontal wells in the Uteland Butte play and four additional wells are planned before year end. All of the wells to date have been drilled in the Monument Butte field. Multiple tests are planned in 2012 in the Central Basin. Initial gross 24-hour production from our first six wells averaged 500 BOEPD. The 14-14T well averaged more than 200 BOEPD over the first four months.

WILLISTON BASIN

We recently completed 10 wells in the Williston Basin. Substantially all of our recent completions were super extended laterals. Recent wells were drilled and completed for approximately $11 million. Notable well results are included in the table below.

WELL	LOCATION	LATERAL LENGTH	24-HOUR GROSS IP RATE (BOEPD)	30-DAY GROSS CUMULATIVE (BOE)
Wisness Federal	Westberg	5,320’	5,198	52,583
Lawlar	Watford	9,569’	3,880	42,355
Holm	Watford	9,434’	3,217	38,393
Hoffman	Watford	9,081’	3,345	37,853
Staal	Watford	9,490’	4,014	43,637

MALAYSIA

In the third quarter, net liftings from our oil assets in Southeast Asia were 1.6 MMBbls, or an average of about 17,400 BOPD. Net liftings in Malaysia during the period averaged approximately 15,700 BOPD.

On PM 329, the East Piatu development is expected to commence production later this week at about 10,000 BOPD (gross). NFX has a 70% interest in East Piatu.

MAVERICK BASIN

We continue to explore and assess our 335,000 net acre position in the Maverick Basin of south Texas. Our recent drilling activity in the Eagle Ford Shale has focused on the “southern” portion of our acreage along existing infrastructure.

A recent development area is the West Asherton field, a 20,000 acre-area located in Dimmitt County, Texas. A spacing pilot is underway with recent wells being drilled from pad locations. Year-to-date, we have completed 16 wells in West Asherton with average 24-hour gross initial production of 650 BOEPD. The wells have been drilled in as few as seven days and gross completed well costs have averaged approximately $6.6 million.

Year-to-date, we have completed 24 wells in the Eagle Ford Shale, six wells in the Georgetown formation and two wells in the Pearsall Shale. Current gross production from the Maverick Basin is approximately 7,000 BOEPD with an average working interest in the region of approximately 80%.

FOURTH QUARTER AND FULL YEAR 2011 ESTIMATES

		4Q11 & FY11 Estimates
		Domestic		Int’l		Total
Production/Liftings		4QE	FY11	4QE	FY11	4QE	FY11
Natural gas – Bcf		46 – 48	183 – 186	0.2 – 0.2	0.2 – 0.2	46 – 48	183 – 186
Oil, condensate and NGLs – MMBbls		3.4 – 3.7	12.8 – 13.1	2.1 – 2.3	6.4 – 6.7	5.6 – 5.9	19.4 – 19.7
Total Bcfe		66 – 70	260 – 264	13 – 14	39 – 41	79 – 84	300 – 304

Average Realized Prices
Natural gas – $/Mcf		Note 1	Note 1
Oil, condensate and NGLs – $/Bbl		Note 2	Note 2	Note 3	Note 3
Mcf equivalent – $/Mcfe

Operating Expenses (per Mcfe):
Lease Operating
Recurring		$0.78 - $0.94	$0.83 - $0.88	$1.54 - $1.93	$1.73 - $1.86	$0.91 - $1.11	$0.95 - $1.01
Major (workovers, etc.)		$0.17 - $0.23	$0.15 - $0.16	$0.34 - $0.44	$0.72 - $0.76	$0.19 - $0.27	$0.22 - $0.24
Transportation		$0.33 - $0.44	$0.34 - $0.37	-	-	$0.28 - $0.37	$0.30 - $0.32

Production/Taxes Note 4		$0.26 - $0.34	$0.28 - $0.30	$4.85 - $6.28	$6.39 - $6.87	$1.01 - $1.31	$1.08 - $1.17

G&A, net		$0.63 - $0.76	$0.65 - $0.69	$0.12 - $0.16	$0.14 - $0.15	$0.55 - $0.65	$0.59 - $0.61

Capitalized internal costs						($0.33 - $0.40)	($0.34 - $0.38)

Interest Expense						$0.60 - $0.64	$0.56 - $0.59

Capitalized Interest						($0.23 - $0.29)	($0.25 - $0.29)

Tax rate (%)Note 5						36% - 38%	36% - 38%

Income taxes (%)
Current						18% - 22%	18% - 22%
Deferred						78% - 82%	78% - 82%

Note 1:	The price that the Company receives 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 90-95% of the Henry Hub Index.
Note 2:	The price the Company receives for its Gulf Coast oil production, excluding NGLs, typically averages about 105-110% of the NYMEX West Texas Intermediate (WTI) price. The price the Company receives for its oil production in the Rocky Mountains, excluding NGLs, is currently averaging $15-17 per barrel below the WTI price. Oil production from the Company’s Mid-Continent properties, excluding NGLs, typically averages 90-95% of the WTI price.
Note 3:	Oil from the Company’s operations in Malaysia typically sells at a slight discount to Tapis, or about 125-130% of the WTI price. Oil from the Company’s operations in China typically sells $23-28 per barrel higher than the WTI price.
Note 4:	Guidance for production taxes determined using the average of the strip at 09/22/11 ($80.62/bbl, $3.84/mcf).
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 2011 and beyond are as of October 18, 2011:

Fourth Quarter 2011
	Weighted Average		Range
Volume	Fixed	Collars	Floor	Ceiling
12,030 MMMBtus	$6.03	—	—	—
17,440 MMMBtus*	—	$5.86 — $7.37	$5.50 — $6.00	$6.60 — $8.03

First Quarter 2012
	Weighted Average		Range
Volume	Fixed	Collars	Floor	Ceiling
5,460 MMMBtus	$5.42	—	—	—
22,750 MMMBtus*	—	$5.59 — $6.55	$5.00 — $6.00	$5.20 — $7.10

Second Quarter 2012
	Weighted Average		Range
Volume	Fixed	Collars	Floor	Ceiling
5,460 MMMBtus	$5.42	—	—	—
22,750 MMMBtus*	—	$5.44 — $6.26	$5.00 — $5.75	$5.20 — $7.00

Third Quarter 2012
	Weighted Average		Range
Volume	Fixed	Collars	Floor	Ceiling
5,520 MMMBtus	$5.42	—	—	—
23,000 MMMBtus*	—	$5.44 — $6.26	$5.00 — $5.75	$5.20 — $7.00

Fourth Quarter 2012
	Weighted Average		Range
Volume	Fixed	Collars	Floor	Ceiling
1,860 MMMBtus	$5.42	—	—	—
15,070 MMMBtus*	—	$5.51 — $6.41	$5.00 — $6.00	$5.20 — $7.55

First Quarter 2013
	Weighted Average		Range
Volume	Fixed	Collars	Floor	Ceiling
4,500 MMMBtus	$5.33	—	—	—
10,800 MMMBtus*	—	$5.58 — $6.89	$5.00 — $6.00	$6.00 — $7.55

Second Quarter 2013
	Weighted Average		Range
Volume	Fixed	Collars	Floor	Ceiling
4,550 MMMBtus	$5.33	—	—	—
10,920 MMMBtus*	—	$5.44 — $6.36	$5.00 — $5.75	$6.00 — $6.65

Third Quarter 2013
	Weighted Average		Range
Volume	Fixed	Collars	Floor	Ceiling
4,600 MMMBtus	$5.33	—	—	—
11,040 MMMBtus*	—	$5.44 — $6.36	$5.00 — $5.75	$6.00 — $6.65


Fourth Quarter 2013
	Weighted Average		Range
Volume	Fixed	Collars	Floor	Ceiling
4,600 MMMBtus	$5.33	—	—	—
6,770 MMMBtus*	—	$5.24 — $6.20	$5.00 — $5.75	$6.00 — $6.65

*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 $4.24 per MMMBtu. Below $4.24 per MMMBtu, these contracts effectively result in realized prices that are on average $1.28 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	$5	$6	$7	$8	$9
2011 (in millions)
4th Quarter	$48	$27	$ -	($14)	($35)	($64)
Total 2011	$48	$27	$ -	($14)	($35)	($64)

2012 (in millions)
1st Quarter	$35	$16	($7)	($19)	($47)	($75)
2nd Quarter	$31	$12	($7)	($26)	($54)	($82)
3rd Quarter	$32	$12	($7)	($26)	($54)	($83)
4th Quarter	$20	$9	($4)	($14)	($29)	($46)
Total 2012	$118	$49	($25)	($85)	($184)	($286)

2013 (in millions)
1st Quarter	$20	$8	($3)	($12)	($24)	($39)
2nd Quarter	$19	$6	($3)	($14)	($30)	($46)
3rd Quarter	$19	$6	($3)	($15)	($30)	($46)
4th Quarter	$13	$3	($3)	($13)	($25)	($36)
Total 2013	$71	$23	($12)	($54)	($109)	($167)

In the Rocky Mountains, we hedged basis associated with approximately 6 Bcf of our natural gas production from October 2011 through December 2012 to lock in the differential at a weighted average of $0.92 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 $0.91 per MMBtu less than the Henry Hub Index.

In the Mid-Continent, we hedged basis associated with approximately 22 Bcf of our anticipated natural gas production from the Stiles/Britt Ranch area for the period October 2011 through December 2012 at an average of $0.55 per MMBtu less than the Henry Hub Index.

Approximately 14% of our natural gas production correlates to Houston Ship Channel, 16% to Columbia Gulf, 16% to Texas Gas Zone 1, 3% to Southern Natural Gas, 4% to Tetco ELA, 1% to Tenn 100, 6% to CenterPoint/East, 20% to Panhandle Eastern Pipeline, 2% to Waha, 6% to Colorado Interstate, and 12% to others.

CRUDE OIL HEDGE POSITIONS

The following hedge positions for the fourth quarter of 2011 and beyond are as of October 18, 2011:

Fourth Quarter 2011
	Weighted Average		Range
Volume	Fixed	Collars	Floor	Ceiling
920,000 Bbls	$81.51	—	—	—
1,932,000 Bbls*	—	$ 81.67 — $111.68	$75.00 — $100.00	$102.25 — $129.75

First Quarter 2012
	Weighted Average		Range
Volume	Fixed	Collars	Floor	Ceiling
3,185,000 Bbls*	—	$ 82.96 — $111.14	$75.00 — $100.00	$88.20 — $137.80

Second Quarter 2012
	Weighted Average		Range
Volume	Fixed	Collars	Floor	Ceiling
3,185,000 Bbls*	—	$ 82.96 — $111.14	$75.00 — $100.00	$88.20 — $137.80

Third Quarter 2012
	Weighted Average		Range
Volume	Fixed	Collars	Floor	Ceiling
3,220,000 Bbls*	—	$ 82.96 — $111.14	$75.00 — $100.00	$88.20 — $137.80

Fourth Quarter 2012
	Weighted Average		Range
Volume	Fixed	Collars	Floor	Ceiling
3,220,000 Bbls*	—	$ 82.96 — $111.14	$75.00 — $100.00	$88.20 — $137.80

First Quarter 2013
	Weighted Average		Range
Volume	Fixed	Collars	Floor	Ceiling
1,170,000 Bbls*	—	$ 80.00 — $110.54	$80.00	$109.50 — $111.40

Second Quarter 2013
	Weighted Average		Range
Volume	Fixed	Collars	Floor	Ceiling
1,183,000 Bbls*	—	$ 80.00 — $110.54	$80.00	$109.50 — $111.40

Third Quarter 2013
	Weighted Average		Range
Volume	Fixed	Collars	Floor	Ceiling
1,196,000 Bbls*	—	$ 80.00 — $110.54	$80.00	$109.50 — $111.40

Fourth Quarter 2013
	Weighted Average		Range
Volume	Fixed	Collars	Floor	Ceiling
1,196,000 Bbls*	—	$ 80.00 — $110.54	$80.00	$109.50 — $111.40

*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 $66.23 per Bbl. Below $66.23 per Bbl, these contracts effectively result in realized prices that are on average $15.88 per Bbl higher than the cash price that otherwise would have been realized.

In August 2011 we entered into a series of transactions that had the effect of unwinding all of our then outstanding crude oil swaps for 2012, effectively eliminating the variability in cash flows associated with the future settlement of those contracts.

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.

	Oil Prices
	$50	$60	$70	$80	$90	$100	$110

2011 (in millions)
4th Quarter	$57	$48	$26	$7	($4)	($17)	($33)
Total 2011	$57	$48	$26	$7	($4)	($17)	($33)

2012 (in millions)
1st Quarter	$51	$48	$30	$8	$5	($5)	($13)
2nd Quarter	$51	$48	$30	$8	$5	($5)	($14)
3rd Quarter	$52	$48	$31	$8	$5	($6)	($14)
4th Quarter	$52	$49	$31	$8	$5	($6)	($14)
Total 2012	$206	$193	$122	$32	$20	($22)	($55)

2013 (in millions)
1st Quarter	$29	$23	$12	$ -	$ -	$ -	$ -
2nd Quarter	$30	$24	$12	$ -	$ -	$ -	$ -
3rd Quarter	$30	$24	$12	$ -	$ -	$ -	$ -
4th Quarter	$30	$24	$12	$ -	$ -	$ -	$ -
Total 2013	$119	$95	$48	$ -	$ -	$ -	$ -

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.

This publication contains forward-looking information. All information other than historical facts included in this publication, such as information regarding estimated or anticipated drilling plans and planned capital expenditures, 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, new regulations or changes in tax legislation, 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 numerous governmental regulations and operating risks. Other factors that could impact forward-looking statements are described in "Risk Factors" in Newfield's 2010 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, and other subsequent public filings with the Securities and Exchange Commission, which can be found at www.sec.gov. Unpredictable or unknown factors not discussed in this publication could also have material adverse effects on forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. Unless legally required, Newfield undertakes no obligation to publicly update or revise any forward-looking statements.

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.

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