EXHIBIT 99.1

News Release

Pioneer Natural Resources Reports Second Quarter 2009 Results

Dallas, Texas, August 4, 2009 -- Pioneer Natural Resources Company (NYSE:PXD) today announced financial and operating results for the quarter ended June 30, 2009.

Pioneer reported a second quarter net loss attributable to common stockholders of $92 million, or $.80 per diluted share. The loss included a noncash unrealized loss on commodity derivatives of $110 million after tax, or $.96 per diluted share. Without the effect of this item, adjusted income for the second quarter of 2009 would have been $18 million, or $.16 per diluted share.

Included in Pioneer’s second quarter results were unusual items that net to a gain of $31 million after tax, or $.26 per diluted share. These after-tax unusual items included:

• Alaska Petroleum Production Tax credits of $55 million after tax ($.48 per diluted share),

• hurricane-related charges covered by insurance of $10 million after tax ($.09 per diluted share) and

• terminated and stacked rig charges of $14 million after tax ($.13 per diluted share).

Including discontinued operations, second quarter average daily oil and gas production grew by 3% from the prior year quarter to 117 thousand barrels oil equivalent per day (MBOEPD), consistent with second quarter guidance. Second quarter production was negatively impacted by the loss of approximately 2 MBOEPD of production that was shut in during the quarter as a result of unplanned third-party pipeline repairs in Alaska and the Mid-Continent area.

Production from continuing operations was 115 MBOEPD, reflecting Pioneer’s agreement to sell its remaining Gulf of Mexico Shelf properties during the third quarter. Production attributable to these properties was approximately 1,400 barrels oil equivalent per day (BOEPD) during the second quarter.

Other highlights related to the quarter include:

• Lease operating expenses (LOE) were reduced by 15% from the first quarter of 2009 in response to the Company’s aggressive cost reduction initiatives.

• Debt was reduced by $97 million during the second quarter.

• Oil derivatives were added for 2010 and 2011 with price upside, bringing forecasted oil production coverage to approximately 80% in 2010 and 65% in 2011.

• Gas derivatives were added for 2010 and 2011 with price upside, bringing forecasted gas production coverage to approximately 80% in 2010 and 30% in 2011.

• Two wells in Alaska were successfully fracture stimulated with a combined initial gross production rate of 5,400 barrels of oil per day (BOPD).

• A Purchase and Sale Agreement was signed to sell Pioneer’s remaining Gulf of Mexico Shelf properties; the transaction is expected to close during the third quarter.

Scott Sheffield, Chairman and CEO, stated, “We remain committed to a free cash flow model, with excess cash flow being used to reduce debt. Despite a significantly reduced capital program for 2009 of approximately $300 million, our high-quality assets delivered production growth of 9% during the first six months compared to last year, and we continue to expect full-year production growth of at least 5% per share.”

“The improving outlook for oil prices, coupled with our strong derivative positions, provide confidence in achieving cash flow of approximately $1 billion in 2010. As a result, we are preparing to resume an oil-focused drilling program with strong returns in the Spraberry field and Tunisia at the beginning of 2010. Additionally, we will continue our successful oil development program in Alaska and actively assess the resource potential of the Eagle Ford Shale play. This drilling program and the expiration of our 5 MBOEPD volumetric production payment obligation at the end of 2009 are expected to once again generate a quarterly production growth profile starting in the first quarter of 2010.”

Operations Update

In the Spraberry field, first half 2009 daily production increased 12% as compared to the first half of 2008, reflecting the success of the 2008 drilling program, improved well performance and sales of inventoried natural gas liquids (NGLs) that were not fractionated and sold in the fourth quarter of 2008 as a result of hurricane damage to third-party fractionation facilities. The Company had no rigs running in the Spraberry field during the second quarter but will resume drilling with one rig in August. With substantially reduced well costs and the strip price for oil exceeding $60 per barrel for 2010 and 2011, the Company is planning to have ten to twelve rigs running by January 2010, drilling approximately 250 wells during the year. The majority of these wells will include completions in additional zones, including the Wolfcamp and shale/silt intervals. Pioneer also plans to implement a full-scale waterflood project in 2010.

On the North Slope of Alaska, production from Pioneer’s Oooguruk field averaged 4 thousand barrels of oil per day (MBOPD) during the first half 2009. Second quarter production from high-rate Kuparuk wells was curtailed by approximately 1 MBOPD due to constraints in the third-party water delivery system that provides water for reservoir pressure management. Sufficient water injection volumes are now available to meet current needs. Pioneer plans to drill a total of five horizontal Nuiqsut laterals during the second and third quarters, of which three will be fracture-stimulated production wells and two will be unstimulated water injection wells. The first unstimulated water injector has been producing oil at a stabilized rate of approximately 1 MBOPD and will be converted to injection during August. Early results from the first two fracture-stimulated production wells, which had a combined initial flow rate of 5,400 BOPD, suggest that stabilized production will be two to three times that of the unstimulated injector. Net production from Alaska for second half 2009 is forecast to average 6 MBOPD to 7 MBOPD.

In South Texas, Pioneer’s first half 2009 daily production rose 16% versus the prior year period as a result of a strong drilling program in the Edwards Trend during 2008. The Company fracture stimulated its first horizontal well in the Eagle Ford Shale play where it holds 310,000 acres overlaying the Edwards Trend. The well incurred mechanical problems but still delivered an initial flow rate of 3.7 million cubic feet equivalent per day (MMCFEPD) with only two of five fracture stimulation stages contributing. The Company is implementing a multi-well drilling program beginning in the third quarter to delineate the play and assess its resource potential.

In the low-decline Raton and Mid-Continent areas where no drilling took place during the first half of 2009, production was down 4% and 8%, respectively, compared to last year. The reduction in Mid-Continent production included the curtailment of approximately 6 MMCFEPD during the second quarter of 2009 due to an unexpected third-party pipeline repair. The repair has now been completed and production is back to normal at approximately 110 MMCFEPD. Pioneer’s Mid-Continent production will increase by approximately 28 MMCFEPD on January 1, 2010 with the expiration of a volumetric production payment (VPP) obligation in the Hugoton field.

Daily production in Tunisia increased 29% compared to the first half of 2008. Drilling has been curtailed until early 2010 when new 3-D seismic will be fully processed.

In South Africa, first half 2009 daily production increased 51% compared to the same period in 2008 reflecting the commencement of production from the most prolific well in Pioneer’s South

Coast Gas project during fourth quarter 2008. Looking forward, a major maintenance shutdown is scheduled during the fourth quarter of 2009 at the Mossel Bay gas-to-liquids plant where the gas production is sold. As a result, fourth quarter forecasted production is expected to be curtailed from approximately 6 MBOEPD to 4 MBOEPD.

Pioneer and Pioneer Southwest (the master limited partnership in which Pioneer has a 68% interest) are evaluating the potential sale of certain developed and undeveloped oil and gas properties from Pioneer to Pioneer Southwest, which is dependent on market conditions, among other items.

Cost Reduction Initiatives

Pioneer’s asset teams have continued to aggressively implement initiatives to reduce 2009 LOE. Second quarter LOE was 15% lower compared to the first quarter of 2009. The Company has achieved significant reductions in electricity, water disposal, well servicing, facilities and compression costs.

The Company is also continuing to work with service providers to reduce drilling and completion costs. Since the third quarter of 2008, when drilling and completion costs peaked, Pioneer has achieved a reduction of greater than 30% in the cost of drilling and completing a well for the majority of its domestic drilling inventory based on current market conditions.

General and administrative expenses were down 4% from the first quarter, again reflecting the Company’s focus on reducing costs.

Financial Review

Second quarter sales from continuing operations averaged 115,436 BOEPD, consisting of oil sales averaging 31,406 barrels per day (BPD), NGL sales averaging 18,921 BPD and gas sales averaging 391 million cubic feet per day (MMCFPD).

The reported second quarter average price for oil was $70.89 per barrel and included $8.62 per barrel related to deferred revenue from VPPs for which production was not recorded. The reported price for NGLs was $26.78 per barrel. The reported price for gas was $3.43 per thousand cubic feet (MCF) and included $.35 per MCF related to deferred revenue from VPPs for which production was not recorded.

Second quarter production costs averaged $10.33 per barrel oil equivalent (BOE), down $1.92 per BOE or 16%, from the first quarter of 2009, as a result of the Company’s cost reduction initiatives and reduced production taxes associated with lower commodity prices.

Depreciation, depletion and amortization (DD&A) expense averaged $15.80 per BOE for the second quarter. Exploration and abandonment costs were $22 million for the quarter and included $10 million of acreage and unsuccessful drilling costs and $12 million of geologic and geophysical expenses and personnel costs.

Cash flow from operating activities for the second quarter was $224 million.

Commodity Derivatives

Prior to February 1, 2009, Pioneer entered into and designated certain commodity and interest rate derivative instruments as cash flow hedges of commodity price risk and interest rate risk in accordance with generally accepted accounting principles in the United States (GAAP). Effective February 1, 2009, the Company discontinued hedge accounting on all of its existing derivative instruments and since that date has accounted for derivative instruments using the mark-to-market (MTM) accounting method.

On January 31, 2009, the Company determined the fair value of its derivative hedge instruments and adjusted the effective portion of its net hedge gains in accumulated other comprehensive income – deferred hedge gains, net of tax (AOCI), in the equity portion of its consolidated balance sheet to $88 million. In accordance with GAAP, the Company transfers the net hedge gains included in AOCI to oil and gas revenues and interest expense in the same periods in which the transactions that they hedged are recognized in earnings. Excluding VPP hedge losses for the three and six month periods ended June 30, 2009, the Company transferred $29 million and $67 million of net gains from AOCI to oil and gas revenues, respectively, attributable to discontinued and terminated hedge derivatives.

Under the MTM accounting method, since February 1, 2009, the Company has accounted for all changes in the fair values of its derivative instruments as gains or losses in the earnings of the periods in which they occurred. The Company’s MTM net derivative losses that were recorded to earnings for the three and six month periods ended June 30, 2009 and the scheduled amortization of net deferred gains on discontinued and terminated commodity hedges to oil and gas revenue are shown in the attached schedules.

Pioneer has increased its 2010 and 2011 oil and gas derivative positions to support the Company’s free cash flow model and the resumption of oil drilling. In particular, the Company added 12,000 BPD of three-way oil collar derivatives in 2010 and 2011, with upside to approximately $90 per barrel and $100 per barrel, respectively. The Company also added 50,000 million British Thermal Units per day of three-way gas collar derivatives in 2011, with upside to $8.55 per million British Thermal Units. The new derivatives bring Pioneer’s 2010 derivative coverage to 80% of forecasted production for both oil and gas, and 2011 coverage to 65% for oil and 35% for gas.

Financial Outlook

Third quarter 2009 guidance excludes discontinued operations related to the sale of Gulf of Mexico Shelf properties. The production and expense estimates below include amounts attributable to the public ownership in Pioneer Southwest.

Third quarter production is forecasted to average 110,000 BOEPD to 115,000 BOEPD.

Third quarter production costs (including production and ad valorem taxes and transportation costs) are expected to average $10.00 to $11.00 per BOE based on current NYMEX strip prices for oil and gas. DD&A expense is expected to average $15.50 to $16.50 per BOE, also based on current strip prices.

Total exploration and abandonment expense during the third quarter is expected to be $15 million to $25 million, primarily related to exploration wells, including related acreage costs, and seismic and personnel costs.

General and administrative expense is expected to be $33 million to $37 million. Interest expense is expected to be $42 million to $45 million. Accretion of discount on asset retirement obligations is expected to be $2 million to $4 million.

Noncontrolling interest in consolidated subsidiaries’ net income is expected to be $4 million to $7 million, primarily reflecting the public ownership in Pioneer Southwest.

The Company also expects to recognize $10 million to $15 million of charges in other expense associated with certain drilling rigs stacked as a result of the low price environment.

The Company’s third quarter 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 $5 million to $10 million and are primarily attributable to Tunisia.

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

Earnings Conference Call

On Wednesday, August 5 at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results with an accompanying presentation. The call will be webcast on Pioneer’s website, www.pxd.com. The presentation will be available on the website for preview in advance of the call. At the website, select ‘INVESTORS’ at the top of the page. For those who cannot listen to the live webcast, a replay will be available shortly thereafter. Or you may choose to dial (877) 741-4240 (confirmation code: 8449625) to listen by telephone and view the accompanying presentation at the website above. A telephone replay will be available by dialing (888) 203-1112 (confirmation code: 8449625).

Pioneer is a large independent oil and gas exploration and production company, headquartered in Dallas, with operations in the United States, South Africa and Tunisia. 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 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.

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

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

	June 30,			December 31,
	2009			2008
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	64,323		$	48,337
Accounts receivable, net		152,931			207,553
Income taxes receivable		28,777			60,573
Inventories		119,077			76,901
Prepaid expenses		19,870			12,464
Deferred income taxes		9,239			6,510
Discontinued operations held for sale		16,874			—
Derivatives		63,830			59,622
Other current assets, net		6,929			14,951
Total current assets		481,850			486,911
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of     accounting		10,327,830			10,371,403
Accumulated depletion, depreciation and amortization		(2,695,971	)		(2,511,401	)
Total property, plant and equipment		7,631,859			7,860,002
Deferred income taxes		1,134			553
Goodwill		310,551			310,563
Derivatives		40,337			72,594
Other assets, net		407,111			431,162
	$	8,872,842		$	9,161,785
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	205,804		$	356,972
Interest payable		43,348			43,247
Income taxes payable		17,713			3,618
Deferred income taxes		370			—
Deferred revenue		119,281			147,905
Discontinued operations held for sale		16,706			—
Derivatives		108,360			49,561
Other current liabilities		68,177			93,694
Total current liabilities		579,759			694,997
Long-term debt		2,978,819			2,899,241
Deferred income taxes		1,424,769			1,501,459
Deferred revenue		132,166			177,236
Derivatives		47,645			20,584
Other liabilities		168,598			187,409
Stockholders' equity		3,541,086			3,680,859
	$	8,872,842		$	9,161,785

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except for per share data)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Revenues and other income:
Oil and gas	$	370,692		$	635,123		$	738,543		$	1,177,166
Derivative gains, net		—			881			—			1,908
Interest and other		88,598			6,887			99,258			31,911
Gain (loss) on disposition of assets, net		53			3,901			(62	)		4,578
		459,343			646,792			837,739			1,215,563
Costs and expenses:
Oil and gas production		84,793			97,327			195,223			190,140
Production and ad valorem taxes		23,715			45,658			51,414			83,546
Depletion, depreciation and amortization		165,943			112,251			354,087			216,888
Impairment of oil and gas properties		—			—			21,091			—
Exploration and abandonments		21,618			26,108			52,788			63,293
General and administrative		33,275			35,596			67,929			72,117
Accretion of discount on asset retirement obligations		2,753			1,961			5,505			3,904
Interest		43,475			41,670			84,613			81,948
Hurricane activity, net		16,075			1,401			16,450			1,859
Derivative losses, net		170,224			—			70,361			—
Other		36,715			8,275			68,104			20,190
		598,586			370,247			987,565			733,885
Income (loss) from continuing operations before income taxes		(139,243	)		276,545			(149,826	)		481,678
Income tax benefit (provision)		44,398			(120,975	)		45,139			(204,451	)
Income (loss) from continuing operations		(94,845	)		155,570			(104,687	)		277,227
Income from discontinued operations, net of tax		2,731			7,351			1,761			14,391
Net income (loss)		(92,114	)		162,921			(102,926	)		291,618
Net (income) loss attributable to noncontrolling interests		522			(6,227	)		(3,271	)		(6,965	)
Net income (loss) attributable to common stockholders	$	(91,592	)	$	156,694		$	(106,197	)	$	284,653
Basic earnings per share:
Income (loss) from continuing operations   attributable to common stockholders	$	(0.82	)	$	1.24		$	(0.95	)	$	2.26
Income from discontinued operations, net of    tax, attributable to common stockholders		0.02			0.06			0.02			0.12
Net income (loss) attributable to common    stockholders	$	(0.80	)	$	1.30		$	(0.93	)	$	2.38
Diluted earnings per share:
Income (loss) from continuing operations    attributable to common stockholders	$	(0.82	)	$	1.23		$	(0.95	)	$	2.25
Income from discontinued operations, net of    tax, attributable to common stockholders		0.02			0.06			0.02			0.12
Net income (loss) attributable to common    stockholders	$	(0.80	)	$	1.29		$	(0.93	)	$	2.37
Weighted average shares outstanding:
Basic		113,979			118,363			114,116			118,149
Diluted		113,979			119,370			114,116			118,816

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Three Months Ended						Six Months Ended
	June, 30						June, 30
	2009			2008			2009			2008
Cash flows from operating activities:
Net income (loss)	$	(92,114	)	$	162,921		$	(102,926	)	$	291,618
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depletion, depreciation and amortization		165,943			112,251			354,087			216,888
Impairment of oil and gas properties		—			—			21,091			—
Exploration expenses, including dry holes		9,705			1,034			27,954			4,582
Hurricane activity		15,000			—			15,000			—
Deferred income taxes		(41,761	)		108,937			(52,793	)		171,310
(Gain) loss on disposition of assets, net		(53	)		(3,901	)		62			(4,578	)
Accretion of discount on asset retirement obligations		2,753			1,961			5,505			3,904
Discontinued operations		312			6,181			5,208			14,464
Interest expense		6,921			7,797			13,529			14,094
Derivative related activity		159,520			7,851			48,235			15,516
Amortization of stock-based compensation		9,926			8,268			19,223			17,248
Amortization of deferred revenue		(36,975	)		(39,457	)		(73,695	)		(78,936	)
Other noncash items		14,146			8,427			24,840			3,788
Changes in operating assets and liabilities:
Accounts receivable, net		11,720			(84,474	)		53,941			(98,535	)
Income taxes receivable		(13,140	)		(9,326	)		31,796			(9,402	)
Inventories		(23,219	)		(14,471	)		(57,689	)		(40,643	)
Prepaid expenses		(16,147	)		166			(14,187	)		1,103
Other current assets, net		40,863			5,191			66,920			7,186
Accounts payable		4,062			32,744			(107,388	)		(1,169	)
Interest payable		15,677			16,489			101			3,154
Income taxes payable		5,554			18,922			14,095			28,112
Other current liabilities		(14,786	)		(14,461	)		(44,581	)		(48,972	)
Net cash provided by operating activities		223,907			333,050			248,328			510,732
Net cash used in investing activities		(88,744	)		(313,941	)		(259,807	)		(491,481	)
Net cash provided by (used in) financing activities		(115,316	)		6,853			27,465			11,860
Net increase in cash and cash equivalents		19,847			25,962			15,986			31,111
Cash and cash equivalents, beginning of period		44,476			17,320			48,337			12,171
Cash and cash equivalents, end of period	$	64,323		$	43,282		$	64,323		$	43,282

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUMMARY PRODUCTION AND PRICE DATA

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2009		2008		2009		2008
Average Daily Sales Volumes
from Continuing Operations:
Oil (Bbls) —	U.S.		23,873		19,829		25,109		19,966
	South Africa		379		2,819		312		2,821
	Tunisia		7,154		6,370		6,754		5,136
	Worldwide		31,406		29,018		32,175		27,923
Natural gas liquids (Bbls) —	U.S.		18,921		20,464		20,778		19,914
Gas (Mcf) —	U.S.		355,661		367,414		370,565		365,983
	South Africa		33,243		5,570		31,771		5,322
	Tunisia		1,753		2,619		2,048		2,098
	Worldwide		390,657		375,603		404,384		373,403
Total (BOE) —	U.S.		102,069		101,529		107,647		100,877
	South Africa		5,920		3,747		5,608		3,708
	Tunisia		7,447		6,806		7,095		5,486
	Worldwide		115,436		112,082		120,350		110,071
Average Daily Sales Volumes
from Discontinued Operations:
Oil (Bbls) —	U.S.		868		1,211		983		1,264
Natural gas liquids (Bbls) —	U.S.		29		45		37		44
Gas (Mcf) —	U.S.		3,276		3,893		3,271		4,580
Total (BOE) —	U.S.		1,443		1,905		1,564		2,071
Average Reported Prices (a):
Oil (per Bbl) —	U.S.	$	75.13	$	70.50	$	64.39	$	69.43
	South Africa	$	62.27	$	131.23	$	56.33	$	116.34
	Tunisia	$	57.23	$	124.58	$	52.57	$	115.00
	Worldwide	$	70.89	$	88.27	$	61.83	$	82.55
Natural gas liquids (per        Bbl) —	U.S.	$	26.78	$	56.28	$	24.69	$	55.10
Gas (per Mcf) —	U.S.	$	3.24	$	8.65	$	3.82	$	8.18
	South Africa	$	5.29	$	8.52	$	4.66	$	8.09
	Tunisia	$	7.78	$	14.89	$	6.74	$	13.39
	Worldwide	$	3.43	$	8.70	$	3.90	$	8.21
Total (BOE) —	U.S.	$	33.81	$	56.43	$	32.94	$	54.30
	South Africa	$	33.71	$	111.39	$	29.52	$	100.12
	Tunisia	$	56.82	$	122.32	$	51.99	$	112.79
	Worldwide	$	35.29	$	62.27	$	33.90	$	58.76

_____________

(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						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Net income (loss)	$	(92,114	)	$	162,921		$	(102,926	)	$	291,618
Depletion, depreciation and amortization		165,943			112,251			354,087			216,888
Impairment of oil and gas properties		—			—			21,091			—
Exploration and abandonments		21,618			26,108			52,788			63,293
Hurricane activity		15,000			—			15,000			—
Accretion of discount on asset retirement obligations		2,753			1,961			5,505			3,904
Interest expense		43,475			41,670			84,613			81,948
Income tax (benefit) provision		(44,398	)		120,975			(45,139	)		204,451
(Gain) loss on disposition of assets, net		(53	)		(3,901	)		62			(4,578	)
Discontinued operations		312			6,181			5,208			14,464
Current income tax (benefit) provision on discontinued operations		—			(348	)		—			171
Cash exploration and abandonment expense on discontinued operations		22			3,980			23			5,472
Derivative related activity		159,520			7,851			48,235			15,516
Amortization of stock-based compensation		9,926			8,268			19,223			17,248
Amortization of deferred revenue		(36,975	)		(39,457	)		(73,695	)		(78,936	)
Other noncash items		14,146			8,427			24,840			3,788
EBITDAX (a)		259,175			456,887			408,915			835,247
Cash interest expense		(36,554	)		(33,873	)		(71,084	)		(67,854	)
Current income taxes		2,637			(11,690	)		(7,654	)		(33,312	)
Discretionary cash flow (b)		225,258			411,324			330,177			734,081
Cash exploration expense		(11,935	)		(29,054	)		(24,857	)		(64,183	)
Changes in operating assets and liabilities		10,584			(49,220	)		(56,992	)		(159,166	)
Net cash provided by operating activities	$	223,907		$	333,050		$	248,328		$	510,732

_____________

(a) "EBITDAX" represents earnings before depletion, depreciation and amortization expense; impairment of oil and gas properties; exploration and abandonments; noncash hurricane activity; noncash derivative activity; 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 thousands, except per share data)

       Income adjusted for unrealized mark-to-market derivative losses, net, and loss as adjusted for unrealized mark-to-market derivative losses, net, and unusual credits, net, as presented in this press release are presented and reconciled to Pioneer’s net loss 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 and many of the other credits and charges are of a type that could 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 loss attributable to common stockholders for the three months ended June 30, 2009, as determined in accordance with GAAP, to the income adjusted for unrealized mark-to-market derivative losses, net, and loss as adjusted for unrealized mark-to-market derivative losses, net, and unusual credits, net, for that quarter.

		After-tax			Per
		Amounts			Share
Net loss attributable to common stockholders	$	(91,592	)	$	(0.80	)
Plus: Unrealized derivative mark-to-market losses, net		109,845			0.96
Income adjusted for unrealized mark-to-
market derivative losses, net		18,253			0.16
Unusual (credits) and charges:
Alaskan Petroleum Production Tax credits		(55,132	)		(0.48	)
Terminated and stacked rig charges		14,258			0.13
Hurricane activity, net		10,127			0.09
Total unusual credits, net		(30,747	)		(0.26	)
Loss as adjusted for unrealized derivative
mark-to-market losses, net and unusual credits, net	$	(12,494	)	$	(0.10	)

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Open Commodity Derivative Positions as of August 3, 2009 (a)

	2009
		Third Quarter			Fourth Quarter			2010			2011			2012			2013
Average Daily Oil Production Associated with Derivatives:
Swap Contracts:
Volume (Bbl)		5,500			11,250			2,500			750			3,000			3,000
NYMEX price (Bbl) (b)	$	74.72		$	63.41		$	93.34		$	77.25		$	79.32		$	81.02
Collar Contracts:
Volume (Bbl)		2,000			2,000			—			2,000			—			—
NYMEX price (Bbl):
Ceiling	$	70.38		$	70.38		$	—		$	170.00		$	—		$	—
Floor	$	52.00		$	52.00		$	—		$	115.00		$	—		$	—
Collar Contracts with Short Puts:
Volume (Bbl)		20,000			15,000			25,000			25,000			1,000			1,000
NYMEX price (Bbl):
Ceiling	$	62.38		$	69.72		$	83.63		$	94.60		$	103.50		$	111.50
Floor	$	51.40		$	51.47		$	66.24		$	72.80		$	80.00		$	83.00
Sold Put Price	$	44.70		$	41.47		$	53.48		$	58.52		$	65.00		$	68.00
Average Daily Natural Gas Liquid Production Associated with Derivatives:
Swap Contracts:
Volume (Bbl)		3,750			3,750			1,250			750			750			—
Blended index price (Bbl) (c)	$	34.28		$	34.28		$	47.38		$	34.65		$	35.03		$	—
Average Daily Gas Production Associated with Derivatives:
Swap Contracts:
Volume (MMBtu)		135,815			137,500			152,295			2,500			2,500			2,500
NYMEX price (MMBtu) (d)	$	6.24		$	6.13		$	6.42		$	6.65		$	6.77		$	6.89
Collar Contracts:																	—
Volume (MMBtu)		20,000			20,000			30,000			—			—
NYMEX price (MMBtu) (d):
Ceiling	$	5.90		$	5.90		$	7.52		$	—		$	—		$	—
Floor	$	4.00		$	4.00		$	6.00		$	—		$	—		$	—
Collar Contracts with Short Puts:
Volume (MMBtu)		150,000			150,000			95,000			100,000			—			—
NYMEX price (MMBtu) (d):
Ceiling	$	5.35		$	5.35		$	7.94		$	8.95		$	—		$	—
Floor	$	4.18		$	4.18		$	6.00		$	6.50		$	—		$	—
Sold Put Price	$	3.18		$	3.18		$	5.00		$	5.25		$	—		$	—
Basis Swap Contracts:
Spraberry Index Swaps – (MMBtu) (e)		35,000			35,000			5,000			—			—			—
Price differential ($/MMBtu)	$	(0.76	)	$	(0.76	)	$	(0.81	)		—			—			—
Mid-Continent Index Swaps – (MMBtu) (e)		220,000			220,000			180,000			100,000			20,000			10,000
Price differential ($/MMBtu)	$	(1.07	)	$	(1.07	)	$	(0.85	)	$	(0.71	)	$	(0.78	)	$	(0.71	)
Gulf Coast Index Swaps – (MMBtu) (e)		30,000			30,000			30,000			—			—			—
Price differential ($/MMBtu)	$	(0.37	)	$	(0.37	)	$	(0.29	)	$	—		$	—		$	—

_____________

(a) On February 1, 2009, Pioneer Natural Resources Company (the "Company") ceased accounting for commodity derivatives as hedges on a prospective basis. Changes in derivative values from February 1, 2009 forward will be recorded as derivative gains or losses.

(b) Represents NYMEX and Datad Brent average prices on U.S. and foreign production.

(c) Represents the blended Mont Belvieu posted price per Bbl.

(d) Approximate NYMEX price, based on historical differentials to the index price on the derivative trade date.

(e) Represent swaps that fix the basis differentials between Spraberry, Mid-Continent and Gulf Coast indices at which the Company sells its gas and NYMEX prices.

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Amortization of Deferred Revenue Associated with Volumetric

Production Payments and Net Derivative Losses as of June 30, 2009

(in thousands)

	2009
	Second			Third			Fourth
	Quarter			Quarter			Quarter			2010			Thereafter			Total
Total deferred revenues (a)	$	36,975		$	37,207		$	37,003		$	90,215		$	87,022		$	288,422
Less derivative losses to be recognized in pretax earnings (b)		(232	)		(230	)		(822	)		(2,403	)		(6,729	)		(10,416	)
Total VPP impact to pretax earnings	$	36,743		$	36,977		$	36,181		$	87,812		$	80,293		$	278,006

_____________

(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 June 30, 2009 (a)

(in thousands)

	2009
	Second Quarter		Third Quarter		Fourth Quarter		2010		2011
Commodity hedge gains (b):
Oil	$	24,385	$	22,111	$	21,339	$	79,914	$	35,812
NGL		2,342		2,364		2,360		7,297		—
Gas		1,860		1,880		1,881		3,691		—
	$	28,587	$	26,355	$	25,580	$	90,902	$	35,812

_____________

(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

Deferred Losses, Net

(in thousands)

	Three Months Ended			Six Months Ended
	June 30, 2009			June 30, 2008
Noncash mark-to-market changes:
Oil derivative loss	$	109,778		$	114,785
NGL derivative loss		8,666			6,565
Gas derivative loss (gain)		61,241			(16,997	)
Interest rate swap derivative loss		2,209			3,102
Total noncash derivative losses, net (a)		181,894			107,455
Cash settlements:
Oil derivative loss (gain)	$	19,159		$	(2,602	)
NGL derivative loss		780			371
Gas derivative gain		(31,719	)		(35,012	)
Interest rate swap derivative loss		110			149
Total cash derivative gains, net		(11,670	)		(37,094	)
Total derivative losses, net	$	170,224		$	70,361

_____________

(a) Total noncash derivative losses, net include $7.5 million and $10.2 million of losses attributable to noncontrolling interests in consolidated subsidiaries during the three and six month periods ended June 30, 2009, respectively.