NEWFIELD EXPLORATION CO /DE/ - FORM 8-K - EX-99.3 - EXHIBIT 99.3

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8-K - FORM 8-K - NEWFIELD EXPLORATION CO /DE/	nfx8k022112.htm
EX-99.2 - EXHIBIT 99.2 - NEWFIELD EXPLORATION CO /DE/	exhibit992.htm
EX-99.1 - EXHIBIT 99.1 - NEWFIELD EXPLORATION CO /DE/	exhibit991.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 21, 2012

Newfield today released financial and operational results for the fourth quarter and full year 2011, including its year-end 2011 proved and probable reserves. In addition, the Company provided guidance on its 2012 capital spending plans, expected production for oil and gas and certain costs and expenses. The earnings and operational release can be found on our website.

This edition of @NFX includes:

·	2011 Highlights

·	Proved and Probable Reserves By Area

·	2012 Capital Investment Plans and Estimated Production By Area

·	Updated tables detailing complete hedge positions. Items highlighted reflect new and/or changed data since our last publication on October 19, 2011

2011 HIGHLIGHTS

·	Recorded a nearly 30% increase in year-end 2011 proved oil reserves. Oil and liquids at year-end 2011 comprised 40% of total proved reserves.

·	Through several transactions, added more than 75,000 net acres north of Monument Butte in the Uinta Basin and expanded our dominant position in the region to approximately 230,000 net acres. The testing of multiple vertical and horizontal targets is planned for 2012.

·	Signed 7 and 10-year agreements for 38,000 BOPD in refining capacity for our Uinta Basin oil growth.

·	Added more than 125,000 net acres in the Cana Woodford, extending this active oil and “liquids-rich” gas play to the southeast. We will operate up to seven rigs in the play in 2012.

·	Recently commenced production from three new offshore developments – two in Malaysia and one in the Gulf of Mexico – adding more than 16,000 BOEPD net of new production.

·	Sold $728 million in non-strategic assets in 2011 and early 2012, improving organizational focus and providing proceeds to enhance oil growth.

2011 RESERVES

·	The following pie charts show our year-end 2011 proved and probable reserves by area:

Newfield, for the third consecutive year, has reported both proved and probable reserves. At year-end 2011, our proved and probable reserves totaled 6.5 Tcfe, a 4% increase over 2010. More than 90% of the Company’s 2.6 Tcfe in probable reserves are located in two focus areas – the Mid-Continent and the Rocky Mountains. Of probable reserves, 42% meet the technical definition of proved reserves but lie outside of the 5-year development window and are technically classified as “probable reserves” per SEC guidelines.

·	We have increased the oil and liquids component of our reserves to 40% of total proved reserves. Our 2011 proved oil reserves increased nearly 30% over 2010. Our natural gas reserves declined 6% due to reduced activity levels in natural gas plays.

·	Proved reserves at year-end 2011 were 3.9 Tcfe, up about 5% from the prior year. Approximately 55% of our proved reserves are “proved developed.” With our continuing increase in oil reserves, the present value discounted at 10% of our proved reserves grew more than 20% to $6 billion after-tax.

NFX OIL GROWTH (2008 – 2010)

·	The above chart depicts a more than 20% CAGR in oil production since 2008 (through year-end 2011). Our transition to an oil company has been underway since 2009 when a disproportionate amount of our annual capital investments were shifted to oil opportunities within our diverse portfolio.

·	The disparity in oil and gas prices has been the driving force behind our shift to oil. As a result, our realized commodity price, stated on a million cubic feet equivalent, is expected to double in 2012 when compared to 2009 (estimated for 2012 realized prices).

·	Our 2012 capital investments are directed to oil and liquids-rich gas opportunities. Our most significant investment regions will be the Uinta and Williston basins, the Anadarko Basin and offshore Malaysia.

2012 CAPITAL EXPENDITURES AND ESTIMATED PRODUCTION

Our 2012 capital budget is $1.5 -- $1.7 billion, approximately $400 million less than our actual investment levels in 2011 (budget excludes approximately $210 million in capitalized internal costs). Substantially the entire budget is allocated to oil and “liquids-rich” gas plays. 2012 Budget highlights include:

·	An expected 20% increase in oil and liquids volumes, when compared to 2011 production.

o	Without investments, natural gas volumes expected to decline as much as 15%.

o	Approximately $500 million, or one third of total budget, allocated to Uinta Basin oil plays. Oil growth from this region expected to be more than 20% over 2011 levels.

o	One-third of total budget, more than $500 million, allocated to Mid-Continent region where up to seven operated rigs will assess the Company’s new 125,000 net acre position in the Cana Woodford play.

o	Activities in the Williston Basin are ramping up, with our oil production from the region expected to grow 35% in 2012 over 2011 levels. We will invest approximately $200 million and run 2-4 rigs in the basin.

o	Acceleration of development drilling in Malaysia to yield about 25% growth in area oil production. Approximately $100 million of the total international budget to be allocated to the development of the Pearl oil field in China.

o	Approximately 62% of the Company’s expected 2012 domestic gas production and 95% of the Company’s expected 2012 domestic oil production is hedged.

·	Our 2012 production is expected to range from 290 – 300 Bcfe, or flat to slightly higher than our 2011 pro forma production adjusted for asset sales.

OPERATIONAL UPDATE

Uinta Basin

·	The Uinta Basin represents the largest portion of our 2012 capital budget. We expect our oil production from the region to grow about 20% in 2012.

The map above provides recent highlights from our drilling operations in the Uinta Basin. In 2012, we plan to assess new play types including the Uteland Butte, Wasatch and the Black Shale. In addition, development of our Green River oil sands in the Monument Butte field will continue. Current Uinta Basin oil production is 22,000 BOEPD.

·	In the Central Basin, we are drilling our first pressured well in the Uteland Butte. To date, we have drilled nine horizontal wells in the Uteland Butte, all of which have been in our normally-pressured areas of the play. To date, we have drilled 17 vertical wells in the Wasatch.

We expect to run 7-8 rigs in the Uinta Basin in 2012, with 4-5 allocated to new plays in the Central Basin. Including all play types, we expect to drill about 60 wells in the Central Basin, including more than 20 horizontal wells targeting multiple formations throughout the basin. Our first horizontal well in the Wasatch is expected to spud before the end of the first quarter in 2012.

·	In late 2011 and early 2012, the Company announced two separate, long-term agreements (seven and 10 years beginning in 2013 and 2014, respectively) with area refiners adding approximately 38,000 BOPD of refining capacity.

Williston Basin

Following a brief slowdown in our Williston Basin activities in late 2011, we are planning to run 2-4 operated rigs in the region throughout 2012. In 2012, we plan to invest about $200 million in the Williston Basin to drill about 25 new wells. We are focused on developing identified locations in the middle Bakken and the Sanish/Three Forks across our acreage.

In late 2011, we deferred the completion of about 17 wells into 2012. Since then, we sold a package of assets which included 8 of the uncompleted wells. Our crews have completed and brought on-line three wells since January 1 with average 24-hour gross initial production rates of 2,900 BOEPD. We expect to have the remaining six wells completed by mid-year 2012.

Our current net production in the Williston Basin is approximately 7,500 BOEPD. Production is expected to increase approximately 35% over 2011 levels. We have about 60,000 net acres in core development regions on and west of the Nesson and an additional 40,000 acre position in Elm Coulee. We have more than 250 identified development drilling locations in the Williston Basin.

Mid-Continent

Our net daily production in the Mid-Continent is approximately 350 MMcfe/d. This region has historically been our “go to” basin for natural gas growth due to our deep inventory of held-by-production gas assets in the Arkoma Woodford Shale and the Granite Wash. With our expectation for continued weakness in natural gas prices, we are shifting our capital and drilling plans to a new 125,000 acre area in the Cana Woodford play of the Anadarko Basin. This new oil and “liquids-rich” gas play has the potential to add significant new production and reserves and provide another “Foundational Asset” for our future development.

·	Our expected production declines in the Arkoma Woodford and Granite Wash plays should be partially offset by increasing oil and liquids growth from our Cana Woodford play. For 2012, we expect that our production in the Mid-Continent will decline approximately 5-10% in 2012.

We are allocating approximately $300 million to rapidly assess our new Cana Woodford position. Our acreage position was leased in late 2010 and throughout 2011 and is a southeast extension of the well-know Cana Woodford play. We plan to run up to seven rigs in the play. We have been encouraged with our early results, as well as information gained from interests in wells operated by others in and around our leased position. We will provide an update on our drilling once we have a larger sample of wells, likely around mid-year 2012.

Our current net production in the Granite Wash is a record 150 MMcfe/d. In late 2011, eight completions were deferred into 2012 as the Company slowed activities in several areas to meet its capital budget. All of the deferred completions are now on-line. With the planned increase in activities in the Cana Woodford, we are slowing investments in our Granite Wash play. In 2012, 13 total well completions are planned and net production for the year is expected to average about 90 MMcfe/d, or a decrease of nearly 15% over 2011 levels.

Our current net production in the Arkoma Woodford is approximately 160 MMcfe/d, down from our 2011 average of approximately 180 MMcfe/d. With current low gas prices, the Company has ceased drilling activity in the Arkoma Woodford and expects that 2012 production will decline about 10% when compared to 2011 production.

Onshore Gulf Coast / Maverick Basin

In our Onshore Gulf Coast region, we plan to invest about $100 million in 2012. Our current net production in the Onshore Gulf Coast region is approximately 85 MMcfe/d. Our primary area of focus continues to be the Maverick Basin of Texas where we are testing multiple geologic horizons across our acreage.

Our active Maverick Basin program today encompasses more than 250,000 net acres and we plan to run a single-rig program in 2012. Highlights of this program include the testing of four super extended laterals (SXLs are approximately 7,500’ laterals) in the Eagle Ford Shale. Two of the four SXL wells have been drilled and completions are planned in the first quarter of 2012.

·	In addition, we will be testing prospective targets in the Austin Chalk and drilling oil wells in our Georgetown play in northern Maverick County.

International

Our international efforts are focused in Southeast Asia – specifically, offshore Malaysia and China. These areas provide the profitable development of offshore oil fields. In 2012, we plan to allocate about $235 million to these activities. Malaysia represents about $135 million of the total and the remainder is being allocated to the development of our Pearl Field in China where first production is expected in late 2013 or early 2014.

·	In Malaysia, our production is at a record 67,000 BOPD. We are the fourth largest oil producer in the country and are developing fields that are material to Newfield and to our partner, Petronas.

Our net production today in Malaysia is a record 29,000 BOPD, influenced by recent first oil from two new fields – East Piatu and Puteri. We are accelerating development of our Malaysian producing fields and planning to test new oil and gas exploration prospects. Production from Malaysia in 2012 is expected to increase approximately 25% over 2011 levels.

Our East Piatu field came on line in in November 2011 and is today producing about 12,500 BOPD gross. We have a 70% interest in the field and serve as operator. We will accelerate a “Phase 2” development drilling campaign, which will allow us to keep production at maximum rates. The Puteri field commenced production in October and is today producing about 8,000 BOPD gross.

2012 ESTIMATES

The following table provides production and certain cost guidance for the full year 2012. For the first quarter of 2012, we expect that our production will be approximately 72 Bcfe (comprised of 39 Bcfe of natural gas, 3.2 MMBbls of domestic oil and 2.3 MMBbls of international oil). Early in the first quarter of 2012, we deferred production of approximately 2 Bcfe associated with well shut-ins and deferred completions in the Mid-Continent. Costs for the first quarter of 2012 are expected to be within 5% of the annual ranges listed below.

	2012 Estimates
	Domestic		Int’l		Total
Production/Liftings Note 1
Natural gas – Bcf		155		–		155
Oil and condensate – MMBbls		14.9		8.4		23.3
Total Bcfe		244		51		295

Operating Expenses
Lease operating (per Mcfe)
Recurring	$	0.95	$	1.80	$	1.10
Major (workovers, etc.) Note 2	$	0.25	$	0.30	$	0.25
Transportation	$	0.45	$	–	$	0.40


Production and other taxes (per Mcfe) Note 3	$	0.35	$	6.45	$	1.40

DD&A expense (per Mcfe) Note 4	$	2.80	$	4.25	$	3.10

General and administrative (G&A), net (per Mcfe)					$	0.70

Capitalized internal costs (per Mcfe)					$	(0.45	)

Interest expense (per Mcfe)					$	0.45

Capitalized interest (per Mcfe)					$	(0.30	)

Note 1: Production/liftings is subject to timing and can vary by quarter.

Note 2: The timing of “major expense” items varies and includes well workovers and repairs and related expenses.

Note 3: Production and other taxes are dependent on commodity prices as well as the terms of our international PSC’s. Guidance for production taxes was determined using $100 Bbl WTI NYMEX and $3.25/MMBtu NYMEX gas prices.

Note 4: The DD&A rate per Mcfe is reflective of the composition of the investments and reserves associated with our existing asset base and the assumed cost to add new reserves during the year. The timing and impact of our activities on this rate will vary by quarter.

NATURAL GAS HEDGE POSITIONS

Please see the tables below for our complete hedging positions.

The following hedge positions for the first quarter of 2012 and beyond are as of February 20, 2012:

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 $4.20 per MMMBtu. Below $4.20 per MMMBtu, these contracts effectively result in realized prices that are on average $1.27 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
	$	2	$	3	$	4	$	5	$	6
2012 (in millions)
1st Quarter	$	48	$	43	$	35	$	16	$	(7	)
2nd Quarter	$	45	$	39	$	31	$	12	$	(7	)
3rd Quarter	$	45	$	40	$	32	$	12	$	(7	)
4th Quarter	$	26	$	24	$	20	$	9	$	(4	)
Total 2012	$	164	$	146	$	118	$	49	$	(25	)


2013 (in millions)
1st Quarter	$	31	$	27	$	20	$	8	$	(3	)
2nd Quarter	$	30	$	25	$	19	$	6	$	(3	)
3rd Quarter	$	30	$	26	$	19	$	6	$	(3	)
4th Quarter	$	25	$	20	$	13	$	3	$	(3	)
Total 2013	$	116	$	98	$	71	$	23	$	(12	)

In the Rocky Mountains, we hedged basis associated with approximately 5 Bcf of our natural gas production from January 2012 through December 2012 to lock in the differential at a weighted average of $0.91 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 have also hedged basis associated with approximately 17 Bcf of our anticipated natural gas production from the Stiles/Britt Ranch area for the period January 2012 through December 2012 at an average of $0.55 per MMBtu less than the Henry Hub Index.

Approximately 15% of our natural gas production correlates to Houston Ship Channel, 15% to Columbia Gulf, 15% to Texas Gas Zone 1, 3% to Tetco ELA, 7% to CenterPoint/East, 26% to Panhandle Eastern Pipeline, 3% to Waha, 7% to Colorado Interstate, and 9% to others.

CRUDE OIL HEDGE POSITIONS

The following hedge positions for the first quarter of 2012 and beyond are as of February 20, 2012:

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 $66.16 per Bbl. Below $66.16 per Bbl, these contracts effectively result in realized prices that are on average $16.00 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

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 in the Uinta Basin, 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 energy company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids. Our domestic areas of operation include the Mid-Continent, the Rocky Mountains and onshore Texas. Internationally, we focus on offshore oil developments in Malaysia and China.

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