NEWFIELD EXPLORATION CO /DE/ - FORM 8-K - EX-99.1 - EXHIBIT 99.1

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8-K - FORM 8-K - NEWFIELD EXPLORATION CO /DE/	nfx8k022112.htm
EX-99.3 - EXHIBIT 99.3 - NEWFIELD EXPLORATION CO /DE/	exhibit993.htm
EX-99.2 - EXHIBIT 99.2 - NEWFIELD EXPLORATION CO /DE/	exhibit992.htm

Exhibit 99.1

Newfield Provides 2011 Fourth Quarter and Full-Year Financial and Operating Results

Fourth Quarter 2011 Oil/Liquids Production Up 15% over Prior Quarter and almost 28% Over Prior Year;

Year-end 2011 Proved and Probable Reserves Up 5% and 4%, Respectively, Over Prior Year;

Proved Oil Reserves Up Nearly 30%, YE’11 SEC PV-10 Value Up 20% Over YE’10

The Woodlands, Texas – February 21, 2012 – Newfield Exploration Company (NYSE: NFX) today reported its unaudited fourth quarter and full-year 2011 financial results. Newfield will host a conference call at 10 a.m. CST on February 22, 2012. To participate in the call, dial 719-325-2481 or listen through the investor relations section of our website at http://www.newfield.com.

Fourth Quarter 2011

For the fourth quarter of 2011, Newfield recorded net income of $68 million, or $0.51 per diluted share (all per share amounts are on a diluted basis). Net income for the fourth quarter includes a net unrealized loss on commodity derivatives of $93 million ($59 million after-tax), or $0.44 per share. Without the effect of this item, net income for the fourth quarter of 2011 would have been $127 million, or $0.95 per share.

Revenues in the fourth quarter of 2011 were $677 million. Net cash provided by operating activities before changes in operating assets and liabilities was $387 million. See “Explanation and Reconciliation of Non-GAAP Financial Measures” found after the financial statements in this release.

Newfield’s oil and liquids liftings in the fourth quarter of 2011 were 6 MMBbls, or an average of approximately 64,000 BOPD. This is about 9,000 BOPD higher than the third quarter of 2011 and 28% higher than the fourth quarter of 2010. Natural gas production in the fourth quarter of 2011 was 44 Bcf, an average of 478 MMcf/d. When combined, Newfield’s production in the fourth quarter of 2011 was 79 Bcfe, of which 44% was oil and liquids. Capital expenditures in the fourth quarter of 2011 were $479 million.

Full-Year 2011

For 2011, Newfield recorded net income of $539 million, or $3.99 per diluted share. Revenues for 2011 were $2.5 billion. Net cash provided by operating activities before changes in operating assets and liabilities was $1.5 billion. See “Explanation and Reconciliation of Non-GAAP Financial Measures” found after the financial statements in this release.

Newfield’s production for the full year of 2011 was 300 Bcfe, an increase of 4% over 2010 production volumes. Oil and liquids production grew more than 20% over 2010 levels and comprised approximately 40% of the Company’s total production. Production associated with approximately $400 million in non-strategic asset sales during the year would have contributed an additional 4 Bcfe. Capital expenditures for 2011 were approximately $2.2 billion, excluding acquisitions.

Year-End 2011 Reserves and Capital Expenditures

At year-end 2011, Newfield’s proved reserves were 3.9 Tcfe and probable reserves were 2.6 Tcfe. This reflects growth of 5% and 4%, respectively, over the prior year. The Company’s proved oil reserves increased nearly 30% during 2011 while proved natural gas reserves declined by 6% as compared to year-end 2010. Proved developed reserves at year-end 2011 were 54% of total proved reserves. Newfield’s present value of its proved reserves discounted 10% (PV-10) increased by more than 20% over the prior year to approximately $6 billion (after-tax), which follows a more than 65% increase in PV-10 during 2010.

The following table details our proved reserves for the three years ended 2009-2011:

Proved Oil and Gas Reserves:

		Year Ended December 31,
		2011	2010		2009
		(Bcfe)
Proved Reserves:
	Beginning of year	3,712		3,616		2,950
	Reserve additions	909		676		1,342
	Reserve revisions	(288)		(289)		(384)
	Sales	(122)		(3)		(35)
	Production	(300)		(288)		(257)
	End of year	3,911		3,712		3,616
Proved Developed Reserves:
	Beginning of year	2,164		1,908		1,827
	End of year	2,129		2,164		1,908

Newfield’s proved natural gas reserves at year-end 2011 were 2.3 Tcf compared to 2.5 Tcf at year-end 2010 and 2.6 Tcf at year-end 2009. The Company’s proved crude oil and condensate reserves at year-end 2011 were 263 million barrels compared to 204 million barrels at year-end 2010 and 169 million barrels at year-end 2009. Natural gas comprised about 60%, 67% and 72% of proved reserves at year-end 2011, 2010 and 2009, respectively.

Our total proved reserve revisions in 2011 were 288 Bcfe. Price-related and other revisions were negligible. Of proved undeveloped natural gas reserves, 87 Bcfe were reclassified to probable reserves as the Company directed capital to higher margin oil drilling and the locations associated with these reserves moved outside of a five-year development horizon. Negative performance revisions in 2011 were 198 Bcfe, which included (i) well performance as efforts to extend the Greater Monument Butte Unit (GMBU) Green River section to the northwest encountered higher than expected gas production, (ii) the timing of waterflood response recognition in the GMBU, (iii) wellbore failures in gas reservoirs along the Gulf Coast and (iv) offset well interference in older vertical gas wells in the Mid-Continent, which were adversely impacted by new horizontal well completions.

Beginning with the year-end 2009, SEC guidelines limit proved undeveloped reserves to those expected to be developed within five years. In long-lived resource plays with a lengthy inventory of drilling locations, such as our Woodford Shale and Uinta Basin plays, this time limit may have a material impact on the total reserves that could otherwise be recognized as proved. At year-end 2011, a total of approximately 1.1 Tcfe, or 42%, of Newfield’s probable reserves meet the definition of proved undeveloped reserves except for the fact that their planned development timing is beyond the prescribed five-year (2012-2016) development horizon for proved reserves.

2011 Capital Expenditures:

	2011
	(in millions)
Domestic property acquisitions:
Unproved	$	361
Proved		72
Domestic exploration and development		1,775
International costs incurred*		363
Total costs incurred**	$	2,571

* International costs incurred includes $19 million (under the terms of the PSC) associated with first oil from the East Piatu field offshore Malaysia.

** Total costs incurred include $194 million of capitalized interest and overhead and $33 million of asset retirement obligations.

Operational Highlights:

Rocky Mountains

Uinta Basin – Through several transactions in 2011, Newfield added more than 75,000 net acres in the Central Basin of Utah (north and adjacent to Monument Butte) and today owns interest in approximately 230,000 net acres in the Uinta Basin. The acquisition introduced additional play types including the Uteland Butte, Wasatch and Black Shale. Current Uinta Basin net oil production is approximately 22,000 BOEPD net.

The Uinta Basin will be the centerpiece of Newfield’s domestic oil growth in 2012. With a planned 7-8 rig program, production from the area is expected to grow about 20% over 2011 levels. In the Central Basin, Newfield is currently drilling its first pressured well in the Uteland Butte and multiple horizontal tests of other pressured targets (Wasatch and Black Shale) are planned in 2012. Initial results from these wells are expected in the second quarter.

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 Salt Lake City area refiners. These agreements captured 38,000 BOPD of refining capacity.

Williston Basin – Newfield owns approximately 100,000 net acres in the Williston Basin (includes 40,000 acres in Elm Coulee) where current net production is approximately 7,500 BOEPD. In late 2011, Newfield voluntarily slowed its drilling and completion activities in the Williston Basin. As a result, the completion of 17 wells was deferred into 2012. Subsequently, the Company monetized a 23,000 acre package in Williams County, North Dakota for $276 million. Net production from these assets was approximately 300 BOEPD. Eight of the uncompleted wells were sold as part of this transaction. The remaining wells are planned for completion in the first half of 2012.

In January 2012, Newfield resumed its activity levels in the Williston Basin. Six of the nine remaining deferred completions are in various stages and expected to commence production in the first half of 2012. Three recent wells have commenced production with average 24-hour initial production rates of 2,900 BOEPD. The Company plans to operate 2-4 drilling rigs in the Williston Basin throughout 2012 and production is expected to increase approximately 35% over 2011 levels.

Mid-Continent

As a result of low natural gas prices, Newfield is decreasing activities in the dry gas portion of the Woodford Shale (Arkoma Basin) and in the Granite Wash. In the first quarter of 2012, the Company curtailed approximately 2 Bcfe of production through the deferred timing of completions and shut-ins in the Mid-Continent. Natural gas production from the Mid-Continent region is expected to decline approximately 5-10% in 2012. Current net daily production in the region is approximately 350 MMcfe/d.

Granite Wash – Net production in the Granite Wash during 2011 averaged 105 MMcfe/d (current production 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. Newfield plans to reallocate capital in 2012 to the Cana Woodford play. Net production for the year in the Granite Wash is expected to average about 90 MMcfe/d, or a decrease of about 15% over 2011 levels. In the first quarter of 2012, Newfield expects to run a single-rig program, focused primarily on the condensate and “liquids rich” Marmaton formation in Stiles/Britt Ranch.

Woodford Shale – Net production in the Arkoma Woodford in 2011 averaged approximately 180 MMcfe/d (current net production is approximately 160 MMcfe/d). With current low gas prices, the Company has ceased drilling in the Arkoma Woodford for 2012 and expects that annual net production from the Woodford Shale will average about 160 MMcfe/d.

Cana Woodford – Newfield’s drilling efforts have shifted from the Arkoma Woodford to the oil and “liquids rich” Cana Woodford, located in the Anadarko Basin. The Company assembled a 125,000 net-acre lease position as a southeast extension of this play in 2011. The Company plans to operate up to seven rigs in 2012 to assess this new acreage.

Onshore Gulf Coast

Current net daily production from the Onshore Gulf Coast region is approximately 85 MMcfe/d. Newfield’s active program in the Maverick Basin today encompasses more than 250,000 net acres. The Company plans to run a single-rig program in 2012 and test four super extended laterals (approximately 7,500’ laterals) in the Eagle Ford Shale. Of the SXL wells, two have been drilled to date and are awaiting completion. In addition, tests are planned in the Austin Chalk, the Georgetown and Glen Rose formations.

International

Newfield’s net oil production today in Malaysia is at a record 29,000 BOPD. Production commenced in late 2011 from two new offshore developments – East Piatu and Puteri. East Piatu is today producing 12,500 BOPD gross and Puteri is producing 8,000 BOPD gross. Production from Malaysia in 2012 is expected to increase approximately 25% over 2011 levels.

In 2012, approximately $100 million will be invested in the development of the Pearl oil field, located offshore China in the Pearl River Mouth Basin. First production is expected in late 2013 or early 2014.

Gulf of Mexico

In early 2012, Newfield declared its Gulf of Mexico assets “non-strategic” and is currently exploring options to maximize value. For 2012, Newfield’s production is expected to decline approximately 10% from 2011 levels. The Company’s Pyrenees development commenced production in February 2012 and is currently producing about 3,300 BOEPD net.

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.

**This release contains forward-looking information. All information other than historical facts included in this release, 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 natural 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 press release 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.

For information, contact:

Investor Relations: Steve Campbell (281) 210-5200

Danny Aguirre (281) 210-5203

Media Relations: Keith Schmidt (281) 210-5202

							4Q11 Actual
4Q11 Actual Results							Domestic			Int'l			Total

Production/LiftingsNote 1
		Natural Gas - Bcf					44.1			0.1			44.2
		Oil and condensate - MMBbls					3.6			2.3			5.9
		Total Bcfe					65.3			14.0			79.3

Average Realized PricesNote 1,2
		Natural Gas - $/Mcf				$	4.69	$		3.95		$	4.69
		Oil and condensate - $/Bbl				$	75.63	$		107.00		$	88.04
		Mcf equivalent - $/Mcfe				$	7.36	$		17.75		$	9.24

Operating Expenses:
	Lease operating ($MM)
		Recurring				$	62.1	$		20.7		$	82.8
		Major (workovers, etc.)				$	9.9	$		1.9		$	11.8
		Transportation				$	25.3	$		—		$	25.3

	Lease operating (per Mcfe)
		Recurring				$	0.98	$		1.48		$	1.07
		Major (workovers, etc.)				$	0.16	$		0.14		$	0.15
		Transportation				$	0.40	$		—		$	0.33

	Production and other taxes ($MM)					$	12.2	$		72.7		$	84.9
		per Mcfe				$	0.19	$		5.20		$	1.10

	General and administrative (G&A), net ($MM)					$	51.5	$		1.6		$	53.1
		per Mcfe				$	0.81	$		0.11		$	0.69

				Capitalized internal costs ($MM)								$	(32.1)
					per Mcfe							$	(0.41)

Interest expense ($MM)												$	51.0
		per Mcfe										$	0.66

Capitalized interest ($MM)												$	(21.1)
			per Mcfe									$	(0.27)
__________	_______

					Note 1: Beginning in 2011, Newfield reported NGLs with its reported oil production. For comparative purposes, the following table depicts 4Q2010 production and realized prices pro-forma this change:
							Domestic				Int'l		Total
Production/Liftings
		Natural Gas - Bcf					49.9				—		49.9
		Oil, condensate & NGLs- MMBbls					2.7				1.9		4.6
		Total Bcfe					66.0				11.3		77.3

Average Realized Prices
		Natural Gas - $/Mcf				$	5.19		$		—	$	5.19
		Oil, condensate & NGLs - $/Bbl				$	82.89		$		82.86	$	82.88
		Mcf equivalent - $/Mcfe				$	7.41		$		13.81	$	8.37


					Note 2: Average realized prices include the effects of hedging contracts. If the effects of these contracts were excluded, the average realized price for total natural gas would have been $3.54 per Mcf and the domestic and total oil and condensate average realized prices would have been $78.38 and $89.71 per barrel, respectively.


CONSOLIDATED STATEMENT OF NET INCOME
(Unaudited, in millions, except per share data)
	For the Three Months Ended December 31,						For the Twelve Months Ended December 31,
	2011			2010			2011			2010

Oil and gas revenues	$	677		$	528		$	2,471		$	1,883

Operating expenses:
Lease operating		120			89			453			326
Production and other taxes		85			49			330			126
Depreciation, depletion and amortization		239			181			767			644
General and administrative		53			39			185			156
Ceiling test and other impairments		—			7			—			7
Other		—			—			—			10
Total operating expenses		497			365			1,735			1,269

Income from operations		180			163			736			614

Other income (expenses):
Interest expense		(51	)		(40	)		(175	)		(156	)
Capitalized interest		21			15			82			58
Commodity derivative income (expense)		(54	)		(98	)		195			316
Other		—			(5	)		2			(3	)
Total other income (expense)		(84	)		(128	)		104			215

Income before income taxes		96			35			840			829

Income tax provision		28			13			301			306

Net income	$	68		$	22		$	539		$	523

Income per share:
Basic	$	0.51		$	0.17		$	4.03		$	3.97

Diluted	$	0.51		$	0.17		$	3.99		$	3.91

Weighted-average number of shares outstanding for basic income per share		134			133			134			132

Weighted-average number of shares outstanding for diluted income per share		135			134			135			134


CONDENSED CONSOLIDATED BALANCE SHEET
(Unaudited, in millions)
	December 31,			December 31,
	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	76		$	39
Derivative assets		129			197
Other current assets		570			495
Total current assets		775			731

Property and equipment, net (full cost method)		8,020			6,608
Derivative assets		61			39
Other assets		135			116
Total assets	$	8,991		$	7,494

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Derivative liabilities		50			53
Other current liabilities		882			875
Total current liabilities		932			928

Other liabilities		179			153
Derivative liabilities		3			46
Long-term debt		3,006			2,304
Deferred taxes		951			720
Total long-term liabilities		4,139			3,223



STOCKHOLDERS' EQUITY
Common stock and additional paid-in capital		1,446			1,410
Accumulated other comprehensive loss		(10	)		(12	)
Retained earnings		2,484			1,945
Total stockholders' equity		3,920			3,343
Total liabilities and stockholders' equity	$	8,991		$	7,494


CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited, in millions)
	For the Twelve Months Ended December 31,
	2011			2010
Cash flows from operating activities:
Net income	$	539		$	523
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization		767			644
Deferred tax provision		208			247
Stock-based compensation		29			22
Commodity derivative income		(195	)		(316	)
Cash receipts on derivative settlements, net		195			456
Ceiling test and other impairments		—			7
Other non-cash charges		6			7
		1,549			1,590
Changes in operating assets and liabilities		40			40
Net cash provided by operating activities		1,589			1,630

Cash flows from investing activities:
Additions to oil and gas properties and other		(2,340	)		(1,658	)
Acquisitions of oil and gas properties		(304	)		(313	)
Proceeds from sales of oil and gas properties		406			12
Redemptions of investments		2			8
Net cash used in investing activities		(2,236	)		(1,951	)

Cash flows from financing activities:
Net repayments under credit arrangements		(49	)		(249	)
Net proceeds from issuance of senior notes		742			—
Net proceeds from issuance of senior subordinated notes		—			686
Repayment of senior notes		—			(175	)
Other		(9	)		20
Net cash provided by financing activities		684			282

Increase (decrease) in cash and cash equivalents		37			(39	)
Cash and cash equivalents, beginning of period		39			78

Cash and cash equivalents, end of period	$	76		$	39

Explanation and Reconciliation of Non-GAAP Financial Measures

Earnings Stated Without the Effect of Certain Items

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

A reconciliation of earnings for the fourth quarter of 2011 stated without the effect of certain items to net income is shown below:

		4Q11
	(in millions)
Net income	$	68
Net unrealized loss on commodity derivatives(1)		93
Income tax adjustment for above items		(34	)
Earnings stated without the effect of the above items	$	127


(1) The determination of "Net unrealized loss on commodity derivatives" for the fourth quarter 2011 is as follows:

		4Q11
	(in millions)
Commodity derivative expense	$	(54	)
Cash receipts on derivative settlements, net		(39	)
Net unrealized loss on commodity derivatives	$	(93	)

Net Cash Provided by Operating Activities Before Changes in Operating Assets and Liabilities

Net cash provided by operating activities before changes in operating assets and liabilities is presented because of its acceptance as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt. This measure should not be considered as an alternative to net cash provided by operating activities as defined by generally accepted accounting principles.

A reconciliation of net cash provided by operating activities before changes in operating assets and liabilities to net cash provided by operating activities is shown below:

		4Q11			2011
	(in millions)
Net cash provided by operating activities	$	416		$	1,589
Net change in operating assets and liabilities		(29	)		(40	)
Net cash provided by operating activities before changes
in operating assets and liabilities	$	387		$	1,549

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