EXHIBIT 99.1

News Release

Pioneer Natural Resources Reports Fourth Quarter 2009 Results

Dallas, Texas, February 2, 2010 -- Pioneer Natural Resources Company (NYSE:PXD) today announced financial and operating results for the quarter and year ended December 31, 2009.

Pioneer reported fourth quarter net income attributable to common stockholders of $57 million, or $.48 per diluted share.  Net income included a noncash unrealized loss on commodity derivatives of $38 million after tax, or $.32 per diluted share.  Without the effect of this item, adjusted income for the fourth quarter of 2009 would have been $95 million, or $.80 per diluted share.

Also included in Pioneer’s fourth quarter results was income of $73 million after tax, or $.62 per diluted share, related to unusual items. These unusual items included:

·   the recognition of a $119 million ($75 million after tax) royalty refund receivable from the Minerals Management Service (MMS) related to the overpayment of royalties on production from deepwater Gulf of Mexico properties prior to the January 1, 2006 effective date of their sale ($.64 per diluted share),

·   a net hurricane-related insurance recovery of $1 million after tax ($.01 per diluted share) and

·   stacked rig charges of $3 million after tax ($.03 per diluted share).

2009, fourth quarter and recent highlights included:

·   2009 production of 115 thousand barrels oil equivalent per day (MBOEPD), a 3% increase from 2008 and a 5% increase from 2008 on a per-share basis, reflecting the strong performance of Pioneer’s low-decline assets during a period when drilling was severely curtailed,

·   reducing long-term debt by $205 million during 2009 (excludes $67 million of long-term debt of Pioneer Southwest Energy Partners L.P.),

·   issuing $450 million of 7.5% Senior Notes due 2020, with the net proceeds being used to reduce credit facility indebtedness,

·   adding 52 million barrels oil equivalent of proved reserves in 2009, or 114% of full-year production, from discoveries, extensions and technical revisions, despite a severely curtailed drilling program,

·   delivering a drillbit finding and development (F&D) cost of $7.42 per barrel oil equivalent (BOE) (excluding price revisions), a continuing downward trend in the Company’s drillbit F&D cost, and an all-in F&D cost of $9.15 per BOE (excluding price revisions),

·   fourth quarter production of 106 MBOEPD, which reflects an incremental production curtailment of 2.5 MBOEPD due to the longer-than-anticipated maintenance shutdown at the gas-to-liquids plant in South Africa where the Company’s gas production is sold (full production resumed in early January),

·   adding oil derivatives with price upside in 2011 and 2012, bringing forecasted oil production coverage to approximately 90% and 35%, respectively,

·   adding gas derivatives in 2010, 2011 and 2012 (combination of swaps, collars and three-way collars), bringing forecasted gas production coverage to approximately 85%, 70% and 25%, respectively,

·   ramping up Spraberry drilling activity as planned, and

·   successfully completing a second Eagle Ford Shale well with an initial production rate of 17 million cubic feet per day of gas (MMCFPD), the highest gas rate well drilled in the play to date.

Scott Sheffield, Chairman and CEO, stated, “Despite a substantial reduction in drilling activity for 2009, our high-quality assets delivered year-over-year production growth.  We also delivered free cash flow and improved financial flexibility.  We remain committed to a free cash flow model going forward.”

“Improved oil prices and our strong derivative positions support operating cash flow forecasts of approximately $1.0 billion in 2010 and $1.3 billion in 2011.  As a result, we have aggressively ramped up our drilling program in the Spraberry field and will continue our successful development program in Alaska.  We also have 2 rigs operating in the burgeoning Eagle Ford Shale play.  With this drilling program and the expiration of our 5 MBOEPD volumetric production payment obligation, we expect to generate quarterly production growth in 2010 and thereby increase production by at least 10% between the fourth quarter of 2009 and the fourth quarter of 2010. This growth rate could be higher when we significantly ramp up drilling activity in the Eagle Ford Shale later in 2010.  Beyond 2010, we expect a further increase in our Spraberry and Eagle Ford Shale drilling programs and expect to resume double-digit annual production growth in 2011 and beyond.”

Operations Update

In the Spraberry field, Pioneer grew production for the fourth consecutive year.  Despite the significant reduction in drilling activity from 370 wells in 2008 to 48 wells in 2009, production in 2009 was 8% higher than in 2008. This production growth reflects the success of the 2008 drilling program, improved well performance and the Spraberry field’s low production decline rates.  The Spraberry field is the largest onshore oil field in the U.S. lower 48 states, and Pioneer is the largest producer in the field.  With a substantial reduction in well costs, Pioneer’s internal rate of return on Spraberry field drilling has improved to approximately 50% before tax at current NYMEX strip prices for oil and gas.  As a result, the Company is aggressively ramping up drilling activity in the field with 14 rigs running in February, increasing to 19 rigs by midyear and 24 rigs by year end.

Approximately 425 Spraberry wells are expected to be drilled during 2010, which is expected to generate quarter-to-quarter production growth.  Fourth quarter 2009 production averaged 31 MBOEPD and is forecasted to increase by at least 10% to approximately 34 MBOEPD in the fourth quarter of 2010.  The majority of these wells will include completions in additional zones, including the Wolfcamp and shale/silt intervals.  Pioneer has also commenced a 7,000-acre waterflood project and expects to see an initial response by early 2011.

The Company plans to continue to add rigs beyond 2010, targeting 40 rigs and drilling 1,000 wells per year by 2012. From 2009 through 2013, Spraberry field production is expected to double, reflecting a compounded annual production growth rate of approximately 20%.

As Pioneer ramps up Spraberry field drilling, the Company will continue to focus on controlling drilling costs.  Tubular and pumping unit requirements have been contracted through 2011, and sand supply has been contracted through 2012.  The Company is also expanding its integrated services in the Spraberry field.  One of the Company-owned fracture stimulation fleets has been transferred from the Raton field to the Spraberry field, and a second fleet is being acquired to commence completions in 2011.  The Company also plans to purchase ten drilling rigs to cover 20% to 25% of its forecasted 2012 and forward Spraberry field drilling programs.

In South Texas, the Company recently announced its second successful well in the Eagle Ford Shale play.  The Crawley #1 well flowed at an initial rate of 17 MMCFPD of gas, representing the highest gas rate reported to date in the play, and confirms that dry gas wells provide strong economics at today’s prices.

The Company holds 310,000 gross acres in the Eagle Ford Shale play, mostly in the condensate window.  To accelerate development of this substantial acreage position, the Company is actively pursuing a joint venture, with bids expected in the second quarter of 2010.  In response to the joint venture effort and in preparation for an aggressive development drilling program to be initiated in this play later in 2010, Pioneer formed a new asset team to focus solely on the Eagle Ford Shale.  

Pioneer is a technology leader in the Eagle Ford Shale with greater than 2,000 square miles of 3-D seismic data, logs from more than 150 operated wells, proprietary core samples and micro-seismic results.  The Company is currently operating a two-rig horizontal drilling program, with wells underway in DeWitt and Karnes Counties, both targeting liquids-rich areas.

Pioneer’s forecasted daily production from South Texas is expected to increase approximately 10% in the fourth quarter of 2010 as compared to the fourth quarter of 2009.  The increase assumes that risked production from a two-rig Eagle Ford Shale drilling program will more than offset natural field declines in the Edwards Trend.  Additional production growth is anticipated once the Company completes the joint venture process and begins ramping up its drilling program beyond two rigs, which is expected later in 2010.

On the North Slope of Alaska, production from Pioneer’s Oooguruk field grew more than 300% in 2009, as compared to 2008, in response to the successful drilling of two Kuparuk wells (one production well and one water injection well) and five Nuiqsut wells (three fracture-stimulated production wells and two unstimulated water injection wells). The Company recently resumed drilling in the Kuparuk formation, where it has previously drilled two high-rate producing wells. After the winter drilling season ends for the Kuparuk formation, drilling will resume in the Nuiqsut formation.  A third reservoir will also be tested during the first half of 2010.  As a result of this drilling program, Pioneer is forecasting that production in the fourth quarter of 2010 will grow by 60% to 70%, as compared to the fourth quarter 2009 production rate of 5.5 thousand barrels oil per day (MBOPD).

In the Raton and Mid-Continent areas where drilling was curtailed during 2009, production decreased 6% to 186 MMCFPD and 8% to 107 million cubic feet equivalent per day (MMCFEPD), respectively, compared to 2008, reflecting the low production decline characteristics of these assets. The reduction in Mid-Continent production included the curtailment of approximately 6 MMCFEPD during the second quarter of 2009 due to an unscheduled third-party pipeline repair.  Raton production is forecasted to decline by approximately 6% between the fourth quarter of 2009 and the fourth quarter of 2010, assuming drilling continues to be curtailed in this field.  In the Mid-Continent area, production increased by approximately 28 MMCFPD on January 1, 2010 with the expiration of the volumetric production payment (VPP) obligation in the Hugoton field.  As a result, although no significant drilling is scheduled for the Mid-Continent area in 2010, production in the fourth quarter of 2010 is expected to be approximately 18% higher than the comparable quarter in 2009.

Daily production in Tunisia increased 4% to 7 MBOEPD in 2009 as compared to 2008.  Pioneer-operated drilling will resume in March 2010, targeting three new prospects identified from new 3-D seismic.  The Company will also be participating in three non-operated wells during 2010.  This drilling program is expected to provide production growth of approximately 10% to 15% between the fourth quarter of 2009 and the fourth quarter of 2010.

In South Africa, a major maintenance shutdown commenced in late September and was expected to be completed in early November at the Mossel Bay gas-to-liquids plant where Pioneer’s gas production is sold.  As a result, Pioneer’s fourth quarter production was expected to be curtailed by approximately 12 MMCFEPD and average 24 MMCFEPD.  However, the shutdown lasted longer than anticipated, resulting in fourth quarter production averaging only 9 MMCFEPD.  Production resumed at full capacity in early January and is expected to be approximately 200% higher in the fourth quarter of 2010 than the fourth quarter of 2009.

MMS Royalty Refund

The royalty refund from the MMS of $119 million before tax, recognized by Pioneer in fourth quarter earnings, relates to a federal court ruling that the MMS did not have the authority to insert price thresholds into deepwater Outer Continental Shelf (OCS) leases that were issued pursuant to the OCS Deep Water Royalty Relief Act of 1995, an act designed to encourage deepwater exploration by providing lessees with royalty free leases until certain volume thresholds were achieved.  Since Pioneer operated in the deepwater Gulf of Mexico and paid royalties on certain leases subject to that act, the Company has filed for a refund from the MMS of $119 million before tax and expects to receive the refund in the first half of 2010.

Capital Expenditures

Capital spending for 2010 (excluding lease extensions, acquisitions, asset retirement obligations, capitalized interest and G&G G&A) is initially targeted at $800 million to $900 million and is focused on oil drilling.  The lower end of the range includes drilling 425 Spraberry wells, running two rigs in the Eagle Ford Shale and one rig in Alaska, and drilling six wells in Tunisia (three operated and three non-operated).  The upper end of the range assumes gas prices strengthen to a sustainable level that would support the recommencement of drilling in the Raton, Edwards Trend and Barnett Shale. Operating cash flow to fund this capital spending is forecasted to be approximately $1 billion, assuming current NYMEX strip pricing.  Proceeds from the MMS refund will likely be used to support a further increase in Spraberry and Eagle Ford Shale drilling.

Cost Reduction Initiatives

Pioneer’s asset teams have aggressively implemented initiatives to reduce 2009 production costs. Fourth quarter production costs were 22% lower per BOE than the same period in 2008.  The Company achieved significant reductions in electricity, water disposal, well servicing, facilities and compression costs.  Compared to the third quarter of 2009, fourth quarter production costs per BOE were up slightly (1%), primarily as a result of the reduced production from the Company’s lower operating expense South Africa asset and increased workover expenses being offset by production tax refunds recorded during the quarter.  The increased workover activity was primarily related to restoring production on oil wells with the improvement in oil prices.

The Company has also worked with service providers to reduce drilling and completion costs.  Since the third quarter of 2008 when these costs peaked, Pioneer’s drilling and completion costs have decreased by more than 30% per well for the majority of its domestic drilling inventory.

Financial Review

Fourth quarter sales from continuing operations averaged 106 MBOEPD, consisting of oil sales averaging 31 MBOPD, NGL sales averaging 19 thousand barrels per day and gas sales averaging 338 MMCFPD.

The reported fourth quarter average price for oil was $88.16 per barrel and included $8.47 per barrel related to deferred revenue from VPPs for which production was not recorded.  The reported price for NGLs was $37.54 per barrel.  The reported price for gas was $4.56 per thousand cubic feet (MCF) and included $.40 per MCF related to deferred revenue from VPPs for which production was not recorded.

Fourth quarter production costs averaged $11.60 per BOE.

Depreciation, depletion and amortization (DD&A) expense averaged $14.52 per BOE for the fourth quarter.  Exploration and abandonment costs were $20 million for the quarter and included $6 million of acreage abandonment and unsuccessful drilling costs and $14 million of geologic and geophysical expenses and personnel costs.

Cash flow from operating activities for the fourth quarter was $132 million.

Financial Outlook

First quarter 2010 production is forecasted to average 112 MBOEPD to 117 MBOEPD, reflecting increased 2010 drilling activity, the expiration of the VPP obligation in the Hugoton field, the return of production in South Africa after the maintenance shutdown and the planned oil lifting schedule for Tunisia.

First quarter production costs are expected to average $11.50 to $13.50 per BOE, based on current NYMEX strip prices for oil and gas.  DD&A expense is expected to average $14.50 to $16.00 per BOE.

Total exploration and abandonment expense during the first quarter is expected to be $25 million to $35 million, primarily related to exploration wells, including related acreage costs, and seismic and personnel costs.

General and administrative expense is expected to be $35 million to $39 million, interest expense is expected to be $45 million to $48 million, and other expense is expected to be $12 million to $17 million.  Accretion of discount on asset retirement obligations is expected to be $2 million to $4 million.

Noncontrolling interest in consolidated subsidiaries’ income, excluding noncash mark-to-market adjustments, is expected to be $9 million to $12 million, primarily reflecting the public ownership in Pioneer Southwest Energy Partners L.P.

The Company’s effective income tax rate is expected to range from 40% to 50% based on current capital spending plans, higher tax rates in Tunisia and no significant mark-to-market changes in the Company’s derivative position.  Cash taxes are expected to be $10 million to $15 million and are primarily attributable to Tunisia.

Pioneer has increased its 2010 through 2012 commodity price derivative positions to support the Company’s free cash flow model and the resumption of oil drilling. The Company has derivative positions covering approximately 85%, 90% and 35% of its forecasted oil production for 2010, 2011 and 2012, respectively, and derivative positions covering 85%, 70% and 25% of its forecasted gas production for 2010, 2011 and 2012, respectively.

The Company's financial and mark-to-market results, derivatives for oil, NGL and gas, amortization of net deferred gains on discontinued/terminated commodity hedges and future VPP amortization are outlined on the attached schedules.

Earnings Conference Call

On Wednesday, February 3, 2010 at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter and year ended December 31, 2009, with an accompanying presentation.  Instructions for listening to the call and viewing the accompanying presentation are shown below. 

                Internet:  www.pxd.com

Select “Investors,” then “Earnings Calls & Webcasts” to listen to the discussion and view the presentation.

Telephone: Dial (877) 675-4751 confirmation code: 9545624 five minutes before the call.  View the presentation via Pioneer’s internet address above.

A replay of the webcast will be archived on Pioneer’s website.  A telephone replay will be available through March 3 by dialing (888) 203-1112, confirmation code: 9545624.

Pioneer is a large independent oil and gas exploration and production company, headquartered in Dallas, Texas, with operations primarily in the United States.  For more information, visit Pioneer’s website at www.pxd.com.

Except for historical information contained herein, the statements in this News Release are forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995.  Forward-looking statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause Pioneer’s actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties include, among other things, volatility of commodity prices, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the ability to obtain approvals from third parties and negotiate agreements (including joint venture agreements) with third parties on mutually acceptable terms, international operations and associated international political and economic instability, litigation, the costs and results of drilling and operations, access to and availability of drilling equipment and transportation, processing and refining facilities, Pioneer's ability to replace reserves, implement its business plans or complete its development activities as scheduled, access to and cost of capital, the financial strength of counterparties to Pioneer’s credit facility and derivative contracts and the purchasers of Pioneer’s oil, NGL and gas production, uncertainties about estimates of reserves and resource potential and the ability to add proved reserves in the future, the assumptions underlying production forecasts, quality of technical data, environmental and weather risks, and acts of war or terrorism. These and other risks are described in Pioneer’s 10-K and 10-Q Reports and other filings with the Securities and Exchange Commission. In addition, Pioneer may be subject to currently unforeseen risks that may have a materially adverse impact on it. Pioneer undertakes no duty to publicly update these statements except as required by law.

"Finding and development cost per BOE" means total costs incurred divided by the summation of annual proved reserves, on a BOE basis, attributable to revisions of previous estimates, purchases of minerals-in-place and discoveries and extensions. Consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred.

"Drillbit finding and development cost per BOE" means the summation of exploration and development costs incurred divided by the summation of annual proved reserves, on a BOE basis, attributable to revisions of previous estimates and discoveries and extensions. Consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred.

Pioneer Natural Resources Contacts:

Investors

Frank Hopkins – 972-969-4065

Matt Gallagher – 972-969-4017

Nolan Badders – 972-969-3955

Media and Public Affairs

Susan Spratlen – 972-969-4018

Suzanne Hicks – 972-969-4020

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31,				December 31,
	2009				2008
ASSETS
Current assets:
Cash and cash equivalents	$	27,368			$	48,337
Accounts receivable, net		331,748				207,553
Income taxes receivable		25,022				60,573
Inventories		139,177				76,901
Prepaid expenses		9,011				12,464
Deferred income taxes		26,857				6,510
Derivatives		48,713				59,622
Other current assets, net		8,222				14,951
Total current assets		616,118				486,911
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting		10,512,904				10,371,403
Accumulated depletion, depreciation and amortization		(2,946,048		)		(2,511,401	)
Total property, plant and equipment		7,566,856				7,860,002
Deferred income taxes		387				553
Goodwill		309,259				310,563
Derivatives		43,631				72,594
Other assets, net		331,014				431,162
	$	8,867,265			$	9,161,785
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$		253,583		$	356,972
Interest payable			47,009			43,247
Income taxes payable			17,411			3,618
Deferred income taxes			128			-
Deferred revenue			90,215			147,905
Derivatives			116,015			49,561
Other current liabilities			46,830			93,694
Total current liabilities			571,191			694,997
Long-term debt			2,761,011			2,899,241
Deferred income taxes			1,470,899			1,501,459
Deferred revenue			87,021			177,236
Derivatives			133,645			20,584
Other liabilities			200,467			187,409
Stockholders' equity			3,643,031			3,680,859
	$		8,867,265		$	9,161,785

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except for per share data)

	Three Months Ended						Twelve Months  Ended
	December 31,						December 31,
	2009			2008			2009			2008
Revenues and other income:
Oil and gas	$	461,472		$	450,002		$	1,609,984		$	2,227,581
Interest and other		2,545			23,944			102,306			57,641
Loss on disposition of assets, net		(327	)		(5,150	)		(774	)		(381	)
		463,690			468,796			1,711,516			2,284,841
Costs and expenses:
Oil and gas production		94,709			125,272			380,326			422,571
Production and ad valorem taxes		18,868			34,747			98,371			164,417
Depletion, depreciation and amortization		142,138			151,563			651,560			489,716
Impairment of oil and gas properties		-			-			21,091			89,753
Exploration and abandonments		20,185			54,787			98,046			227,500
General and administrative		37,595			38,183			140,323			141,922
Accretion of discount on asset retirement obligations		2,753			2,018			11,012			7,903
Interest		45,310			43,661			173,361			166,785
Hurricane activity, net		(967	)		9,750			17,313			12,150
Derivative losses, net		109,974			8,697			195,557			10,148
Other		15,544			61,819			105,011			115,973
		486,109			530,497			1,891,971			1,848,838
Income (loss) from continuing operations before income taxes		(22,419	)		(61,701	)		(180,455	)		436,003
Income tax benefit (provision)		437			16,525			48,108			(201,091	)
Income (loss) from continuing operations		(21,982	)		(45,176	)		(132,347	)		234,912
Income (loss) from discontinued operations, net of tax		76,212			(17,975	)		90,080			(3,257	)
Net income (loss)		54,230			(63,151	)		(42,267	)		231,655
Net (income) loss attributable to the noncontrolling interests		2,430			(6,248	)		(9,839	)		(21,635	)
Net income (loss) attributable to common stockholders	$	56,660		$	(69,399	)	$	(52,106	)	$	210,020
Basic earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	(0.18	)	$	(0.44	)	$	(1.25	)	$	1.79
Income (loss) from discontinued operations attributable to common stockholders		0.66			(0.16	)		0.79			(0.03	)
Net income (loss) attributable to common stockholders	$	0.48		$	(0.60	)	$	(0.46	)	$	1.76
Diluted earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	(0.18	)	$	(0.44	)	$	(1.25	)	$	1.79
Income (loss) from discontinued operations attributable to common stockholders		0.66			(0.16	)		0.79			(0.03	)
Net income (loss) attributable to common stockholders	$	0.48		$	(0.60	)	$	(0.46	)	$	1.76
Weighted average shares outstanding:
Basic		114,347			115,455			114,176			117,462
Diluted		114,347			115,455			114,176			117,947

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2009			2008			2009			2008
Cash flows from operating activities:
Net income (loss)	$	54,230		$	(63,151	)	$	(42,267	)	$	231,655
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization		142,138			151,563			651,560			489,716
Impairment of oil and gas properties		-			-			21,091			89,753
Exploration expenses, including dry holes		6,542			36,144			47,241			130,140
Hurricane activity		3,650			9,000			19,850			9,000
Deferred income taxes		11,685			(7,946	)		(55,712	)		152,400
Loss on disposition of assets, net		327			5,150			774			381
Gain on extinguishment of debt		-			(20,515	)		-			(20,515	)
Accretion of discount on asset retirement obligations		2,753			2,018			11,012			7,903
Discontinued operations		(77,626	)		12,845			(82,999	)		37,454
Interest expense		7,303			7,240			27,996			28,492
Derivative related activity		27,328			14,048			75,633			45,166
Amortization of stock-based compensation		8,319			8,506			37,638			34,077
Amortization of deferred revenue		(37,004	)		(39,495	)		(147,905	)		(158,139	)
Other noncash items		4,774			30,273			35,439			60,768
Change in operating assets and liabilities:
Accounts receivable, net		(54,781	)		84,485			16,293			45,446
Income taxes receivable		(8,732	)		(11,006	)		36,030			(20,528	)
Inventories		3,835			(27,413	)		(48,234	)		(82,403	)
Prepaid expenses		3,513			3,747			(3,387	)		(3,405	)
Other current assets, net		(10,890	)		(9,184	)		87,642			(11,745	)
Accounts payable		29,902			50,280			(64,336	)		65,644
Interest payable		18,528			13,951			3,762			1,227
Income taxes payable		4,666			(20,753	)		13,793			(9,225	)
Other current liabilities		(8,226	)		(12,428	)		(97,855	)		(89,399	)
Net cash provided by operating activities		132,234			217,359			543,059			1,033,863
Net cash used in investing activities		(97,994	)		(266,691	)		(410,985	)		(1,151,410	)
Net cash provided by (used in) financing activities		(62,487	)		30,852			(153,043	)		153,713
Net increase (decrease) in cash and cash equivalents		(28,247	)		(18,480	)		(20,969	)		36,166
Cash and cash equivalents, beginning of period		55,615			66,817			48,337			12,171
Cash and cash equivalents, end of period	$	27,368		$	48,337		$	27,368		$	48,337

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUMMARY PRODUCTION AND PRICE DATA

		Three Months Ended				Twelve Months Ended
		December 31,				December 31,
		2009		2008		2009		2008
Average Daily Sales Volumes
from Continuing Operations:
Oil (Bbls) -	U.S.		24,906		24,584		24,968		21,091
	South Africa		299		991		375		2,405
	Tunisia		6,290		7,586		6,531		6,178
	Worldwide		31,495		33,161		31,874		29,674
Natural gas liquids (Bbls) -	U.S.		18,598		17,497		19,680		19,048
Gas (Mcf) -	U.S.		328,571		370,843		352,749		366,796
	South Africa		7,441		25,224		25,538		10,232
	Tunisia		1,685		2,555		1,668		2,367
	Worldwide		337,697		398,622		379,955		379,395
Total (BOE) -	U.S.		98,267		103,887		103,440		101,271
	South Africa		1,539		5,195		4,631		4,110
	Tunisia		6,570		8,012		6,809		6,573
	Worldwide		106,376		117,094		114,880		111,954
Average Daily Sales Volumes
from Discontinued Operations:
Oil (Bbls) -	U.S.		1		535		554		953
Natural gas liquids (Bbls) -	U.S.		-		13		29		35
Gas (Mcf) -	U.S.		12		1,536		1,899		3,428
Total (BOE) -	U.S.		3		805		900		1,559
Average Reported Prices (a):
Oil (per Bbl) -	U.S.	$	91.88	$	57.10	$	75.60	$	65.74
	South Africa	$	77.33	$	82.74	$	65.94	$	110.21
	Tunisia	$	73.95	$	48.66	$	60.98	$	90.64
	Worldwide	$	88.16	$	55.94	$	72.49	$	74.53
Natural gas liquids (per Bbl) -	U.S.	$	37.54	$	30.98	$	29.76	$	51.31
Gas (per Mcf) -	U.S.	$	4.49	$	6.38	$	3.88	$	7.66
	South Africa	$	6.27	$	4.44	$	5.17	$	5.83
	Tunisia	$	10.82	$	6.01	$	8.14	$	12.04
	Worldwide	$	4.56	$	6.26	$	3.99	$	7.64
Total (BOE) -	U.S.	$	45.42	$	41.51	$	37.15	$	51.08
	South Africa	$	45.32	$	37.35	$	33.85	$	79.00
	Tunisia	$	73.57	$	47.99	$	60.49	$	89.53
	Worldwide	$	47.15	$	41.77	$	38.40	$	54.36

_____________
(a)	Average prices are attributable to continuing operations and include the results of hedging activities and amortization of VPP deferred revenue.

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES

(in thousands)

EBITDAX and discretionary cash flow ("DCF") (as defined below) are presented herein, and reconciled to the generally accepted accounting principle ("GAAP") measures of net income (loss) and net cash provided by operating activities because of their wide acceptance by the investment community as financial indicators of a company's ability to internally fund exploration and development activities and to service or incur debt. The Company also views the non-GAAP measures of EBITDAX and DCF as useful tools for comparisons of the Company's financial indicators with those of peer companies that follow the full cost method of accounting.  EBITDAX and DCF should not be considered as alternatives to net income (loss) or net cash provided by operating activities, as defined by GAAP.

	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2009			2008			2009			2008
Net income (loss)	$	54,230		$	(63,151	)	$	(42,267	)	$	231,655
Depletion, depreciation and amortization		142,138			151,563			651,560			489,716
Impairment of oil and gas properties		-			-			21,091			89,753
Exploration and abandonments		20,185			54,787			98,046			227,500
Hurricane activity		3,650			9,000			19,850			9,000
Gain on extinguishment of debt		-			(20,515	)		-			(20,515	)
Accretion of discount on asset retirement obligations		2,753			2,018			11,012			7,903
Interest expense		45,310			43,661			173,361			166,785
Income tax (benefit) provision		(437	)		(16,525	)		(48,108	)		201,091
Loss on disposition of assets, net		327			5,150			774			381
Discontinued operations		(77,626	)		12,845			(82,999	)		37,454
Current income tax provision on discontinued operations		1,300			(6	)		1,300			300
Cash exploration and abandonment expense on discontinued operations		(21	)		-			9			7,127
Derivative related activity		27,328			14,048			75,633			45,166
Amortization of stock-based compensation		8,319			8,506			37,638			34,077
Amortization of deferred revenue		(37,004	)		(39,495	)		(147,905	)		(158,139	)
Other noncash items		4,774			30,273			35,439			60,768
EBITDAX (a)		195,226			192,159			804,434			1,430,022
Cash interest expense		(38,007	)		(36,421	)		(145,365	)		(138,293	)
Current income taxes		10,822			8,585			(8,904	)		(48,991	)
Discretionary cash flow (b)		168,041			164,323			650,165			1,242,738
Cash exploration expense		(13,622	)		(18,643	)		(50,814	)		(104,487	)
Changes in operating assets and liabilities		(22,185	)		71,679			(56,292	)		(104,388	)
Net cash provided by operating activities	$	132,234		$	217,359		$	543,059		$	1,033,863

_____________
(a)	"EBITDAX" represents earnings before depletion, depreciation and amortization expense; impairment of oil and gas properties; exploration and abandonments; noncash hurricane activity; gain on extinguishment of debt; accretion of discount on asset retirement obligations; interest expense; income taxes; (gain) loss on the disposition of assets, net; noncash effects from discontinued operations; amortization of stock-based compensation; amortization of deferred revenue; and other noncash items.
(b)	Discretionary cash flow equals cash flows from operating activities before changes in operating assets and liabilities and before cash exploration expense.

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (continued)

(in millions, except per share data)

Income adjusted for unrealized mark-to-market derivative losses, net, as presented in this press release are presented and reconciled to Pioneer's net income attributable to common stockholders that is determined in accordance with GAAP because Pioneer believes that these non-GAAP financial measures reflect an additional way of viewing aspects of Pioneer's business that, when viewed together with its financial results computed in accordance with GAAP, provide a more complete understanding of factors and trends affecting its historical financial performance and future operating results, greater transparency of underlying trends and greater comparability of results across periods. In addition, management believes that these non-GAAP measures may enhance investors’ ability to assess Pioneer's historical and future financial performance. These non-GAAP financial measures are not intended to be substitutes for the comparable GAAP measure and should be read only in conjunction with Pioneer's consolidated financial statements prepared in accordance with GAAP. Unrealized mark-to-market derivative gains and losses will recur in future periods; however, the amount and frequency of each item can vary significantly from period to period. The table below reconciles Pioneer's net income attributable to common stockholders for the three months ended December 31, 2009, as determined in accordance with GAAP, to income adjusted for unrealized mark-to-market derivative losses, net, for that quarter.

	After-tax Amounts		Per Share
Net income attributable to common stockholders	$	57	$	0.48
Plus: Unrealized derivative mark-to-market losses, net		38		0.32
Income adjusted for unrealized mark-to-market derivative losses, net	$	95	$	0.80

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Open Commodity Derivative Positions as of January 18, 2010

	2010
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			2011			2012			2013
Average Daily Oil Production Associated with   Derivatives:
Swap Contracts:
Volume (Bbl)		2,500			2,500			2,500			2,500			750			3,000			3,000
NYMEX price (Bbl)	$	93.34		$	93.34		$	93.34		$	93.34		$	77.25		$	79.32		$	81.02
Collar Contracts:
Volume (Bbl)		-			-			-			-			2,000			-			-
NYMEX price (Bbl) :
Ceiling	$	-		$	-		$	-		$	-		$	170.00		$	-			-
Floor	$	-		$	-		$	-		$	-		$	115.00		$	-			-
Collar Contracts with Short Puts:
Volume (Bbl)		26,750			27,000			27,000			27,250			37,000			15,000			1,250
NYMEX price (Bbl) (a):
Ceiling	$	83.79		$	83.82		$	83.82		$	83.94		$	99.22		$	118.58			111.50
Floor	$	66.86		$	66.89		$	66.89		$	66.92		$	73.92		$	81.00			83.00
Short Put Price	$	53.95		$	53.96		$	53.96		$	53.97		$	59.41		$	65.00			68.00
Percent of total oil production (b)	~85%			~85%			~85%			~85%			~90%			~35%			~5%
Average Daily Natural Gas Liquid Production   Associated with Derivatives:
Swap Contracts:
Volume (Bbl)		1,578			1,250			1,250			1,250			750			750			-
Blended index price (Bbl) (c)	$	49.00		$	47.37		$	47.38		$	47.38		$	34.65		$	35.03			-
Collar Contracts:
Volume (Bbl)		2,000			2,000			2,000			2,000			1,000			-			-
Index price (Bbl) (c):
Ceiling	$	49.98		$	49.98		$	49.98		$	49.98		$	50.93		$	-			-
Floor	$	41.58		$	41.58		$	41.58		$	41.58		$	42.21		$	-			-
Percentage Contracts of WTI Oil Prices (d):
Volume – (Bbl)		1,672			2,000			2,000			2,000			-			-			-
Percentage of  NYMEX WTI received (%)		59	%		60	%		60	%		60	%		-			-			-
Percent of total NGL production (b)	~30%			~30%			~30%			~30%			~10%			<5%				-
Average Daily Gas Production Associated   with Derivatives:
Swap Contracts:
Volume (MMBtu)		167,500			167,500			167,500			167,500			77,500			2,500			2,500
NYMEX price (MMBtu) (e) $	$	6.26		$	6.26		$	6.26		$	6.26		$	6.35		$	6.77			6.89
Collar Contracts:
Volume (MMBtu)		40,000			40,000			40,000			40,000			-			-			-
NYMEX price (MMBtu) (e):
Ceiling	$	7.19		$	7.19		$	7.19		$	7.19		$	-		$	-			-
Floor	$	5.75		$	5.75		$	5.75		$	5.75		$	-		$	-			-
Collar Contracts with Short Puts:
Volume (MMBtu)		95,000			95,000			95,000			95,000			175,000			90,000			-
NYMEX price (MMBtu) (e):
Ceiling	$	7.94		$	7.94		$	7.94		$	7.94		$	8.69		$	8.72			-
Floor	$	6.00		$	6.00		$	6.00		$	6.00		$	6.36		$	6.25			-
Sold Put Price	$	5.00		$	5.00		$	5.00		$	5.00		$	4.93		$	4.61			-
Percent of U.S. gas production (b)	~85%			~85%			~85%			~85%			~70%			~25%			<5%
Basis Swap Contracts:
Spraberry Index Swaps – (MMBtu) (f)		5,000			5,000			5,000			5,000			-			-			-
Price differential ($/MMBtu)	$	(0.81	)	$	(0.81	)	$	(0.81	)	$	(0.81	)		-			-			-
Mid-Continent Index Swaps – (MMBtu) (f)		180,000			180,000			180,000			180,000			100,000			20,000			10,000
Price differential ($/MMBtu)	$	(0.85	)	$	(0.85	)	$	(0.85	)	$	(0.85	)	$	(0.71	)	$	(0.78	)	$	(0.71	)
Gulf Coast Index Swaps – (MMBtu) (f)		30,000			30,000			30,000			30,000			20,000			20,000			-
Price differential ($/MMBtu)		(0.29	)		(0.29	)		(0.29)			(0.29	)		(0.17	)		(0.17	)		-

_____________
(a)	Represents NYMEX and Dated Brent average prices on U.S. and foreign production.
(b)	Represents the approximate percentage of forecasted production that is covered by derivative contracts.
(c)	Represents the blended Mont Belvieu price or respective NGL product component prices per Bbl.
(d)	Represents swaps whereby the Company pays respective NGL component index price and receives percentage of West Texas Intermediate (“WTI”) NYMEX price.
(e)	Represents the NYMEX Henry Hub index price or approximate NYMEX Henry Hub index price based on historical differentials to the index price on the derivative trade date.
(f)	Represent swaps that fix the basis differentials between indices at which the Company sells its Spraberry, Mid-Continent and Gulf Coast gas and NYMEX Henry Hub index prices.

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Amortization of Deferred Revenue Associated with Volumetric

Production Payments and Net Derivative Losses as of December 31, 2009

(in thousands)

	2010
	First			Second			Third			Fourth
	Quarter			Quarter			Quarter			Quarter			2011			Thereafter			Total
Total deferred revenues (a)	$	22,483		$	22,587		$	22,669		$	22,476		$	44,951		$	42,070		$	177,236
Less derivative losses to be recognized in pretax earnings (b)		(667	)		(620	)		(578	)		(538	)		(3,571	)		(3,158	)		(9,132	)
Total VPP impact to pretax earnings	$	21,816		$	21,967		$	22,091		$	21,938		$	41,380		$	38,912		$	168,104

_____________
(a)	Deferred revenue will be amortized as increases to oil and gas revenues during the indicated future periods.
(b)	Represents the remaining pretax earnings impact of the derivatives assigned in the VPPs.

Deferred Gains on Discontinued and Terminated Commodity Hedges

 as of December 31, 2009 (a)

(in thousands)

	2010
	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter		2011
Commodity hedge gains (b):
Oil	$	19,792	$	20,045	$	20,297	$	20,322	$	36,624
NGL		1,799		1,819		1,839		1,840		-
Gas		910		920		930		931		-
	$	22,501	$	22,784	$	23,066	$	23,093	$	36,624

_____________
(a)	Excludes deferred hedge gains and losses on terminated derivatives related to the VPPs.
(b)	Deferred commodity hedge gains will be amortized as increases to oil and gas revenues during the indicated future periods.

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Derivative Losses, Net

(in thousands)

	Three Months Ended			Twelve Months Ended
	December 31, 2009			December 31, 2009
Noncash mark-to-market changes:
Oil derivative loss	$	84,004		$	150,799
Gas derivative (gain) loss		(37,699	)		6,612
NGL derivative loss		11,946			20,206
Interest rate derivative loss		12,407			13,928
Total noncash derivative loss, net (a)		70,658			191,545
Cash settlements:
Oil derivative loss		35,365			60,604
Gas derivative gain		(1,492	)		(66,428	)
NGL derivate loss		5,546			8,340
Interest rate derivative (gain) loss		(103	)		1,496
Total cash derivative loss, net		39,316			4,012
Total derivative loss, net	$	109,974		$	195,557

_____________
(a)	Total noncash derivative loss, net includes approximately $11.0 million and $19.1 million of losses attributable to noncontrolling interests in consolidated subsidiaries during the three and twelve month periods ended December 31, 2009, respectively.