EXHIBIT 99.1

News Release

Pioneer Natural Resources Reports

Second Quarter 2011 Financial and Operating Results

Dallas, Texas, August 3, 2011 -- Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today announced financial and operating results for the quarter ended June 30, 2011.

Pioneer reported second quarter net income attributable to common stockholders of $246 million, or $2.03 per diluted share (see attached schedule for a description of the earnings per diluted share calculation).  Net income included unrealized mark-to-market gains on derivatives of $133 million after tax, or $1.10 per diluted share.  Without the effect of this item, adjusted income for the second quarter would have been $113 million, or $0.93 per diluted share.

Also included in Pioneer’s second quarter results was a loss from discontinued operations of $2 million after tax, or $0.01 per diluted share, primarily related to post-closing adjustments associated with the sale of Pioneer’s Tunisian subsidiaries in February 2011.

Scott Sheffield, Chairman and CEO, stated, “The Company delivered another strong quarter, with second quarter production increasing to 119 thousand barrels oil equivalent per day (MBOEPD), an increase of 8 MBOEPD, or 7%, from the first quarter of 2011, despite losing 2 MBOEPD of production during the second quarter due to a shortage of third-party oil transport trucks in the Spraberry field.  Our three core growth assets (Spraberry field, Eagle Ford Shale and the Barnett Shale Combo) all contributed to the quarterly production increase.  Second half production is forecasted to grow by approximately 10 MBOEPD per quarter as these three assets continue to deliver quarterly production growth and incremental oil transportation capacity is added in the Spraberry field.  We continue to expect to deliver full-year 2011 production ranging from 125 MBOEPD to 130 MBOEPD, recognizing that production is likely to be towards the lower end of the range due to the severe weather and unplanned third-party impacts we experienced during the first half of the year.”

“In the Spraberry field, we are increasing our rig count from 35 rigs to 45 rigs by year-end 2011, earlier than previously anticipated.  Based on the accelerated drilling activity, combined with the production additions being delivered from our successful deeper drilling program in the Spraberry field and the production growth anticipated for the Eagle Ford Shale and the Barnett Shale Combo plays, we are increasing the Company’s 2012  production growth target from 18+% to 20+%.  We are also extending our compound annual production growth target of 18+% through 2014.  We are increasing our drilling budget in 2011 by $200 million to fund the accelerated drilling and deeper drilling in the Spraberry field.  The budget increase also includes third-party service cost inflation and utilizing more third-party equipment as a result of delays in the delivery of certain Company-owned fracture stimulation equipment earlier in the year. Third-party service cost inflation has been limited to 3%, reflecting the significant benefits being generated by the Company’s expanding vertical integration investments.”

“Owning fracture stimulation fleets, rigs and other service-related equipment is not only enhancing the execution of our drilling program, but it is also providing significant cash savings versus contracting for these services at market rates.  We estimate that by year-end 2011, the Company’s annualized cash savings from vertical integration investments compared to third-party services will be greater than $450 million per year.  To further ensure execution of our drilling program and reduce costs by an additional $80 million per year beginning in 2012, we have recently purchased additional well service equipment for the Spraberry field and have ordered additional fracture stimulation fleets for delivery in mid-2012.  The related increase to our 2011 vertical integration budget will be $100 million.”

“We are funding our drilling program for 2011 from forecasted operating cash flow of $1.5 billion and the redeployment of a portion of the proceeds from the sale of Tunisia earlier this year.  Our forecasted production growth generates a 30+% compound annual operating cash flow growth over the 2011 through 2014 period.  Pioneer has a strong financial position, with a net debt-to-book capitalization of 32% as of June 30, 2011, and is committed to maintaining net debt-to-book capitalization below 35% and net debt to operating cash flow at less than 1.75 times.”

Operations Update and Drilling Program

In the Spraberry field in West Texas, Pioneer’s drilling program has continued to ramp up, with 35 rigs operating at mid-year, including 14 Company-owned rigs.  The Company is accelerating its planned drilling ramp-up in the field and is on track to increase to 45 rigs by year-end 2011 instead of during 2012.

As Pioneer ramps up drilling in the Spraberry field, the Company continues to expand its integrated services to control drilling costs and support the execution of its accelerated drilling program.  Four Company-owned fracture stimulation fleets are currently operating, with one additional fleet scheduled to be operational during the fourth quarter of 2011. To support its growing operations, the Company also owns other oil field service equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools.  In addition, the Company has contracted for tubular and pumping unit requirements through 2012, forecasted fracture stimulation sand supply requirements through 2015 and well cementing services through 2016.

Vertical integration in the Spraberry field is saving Pioneer up to $500 thousand per well compared to utilizing third-party services at market rates.  Pioneer expects that its vertical integration equipment will provide approximately one third of its rig requirements and two thirds of its fracture stimulation requirements in 2011.  As a result, the blended Pioneer and third-party 2011 well cost is expected to average $1.5 million to $1.6 million per well.  Pioneer’s internal rate of return on its 2011 Spraberry drilling program is expected to be 45% before tax based on current NYMEX strip commodity prices and estimated future production costs.

The Company’s increasing fracture stimulation capacity in the Spraberry field is accelerating the pace at which wells are being placed on production as evidenced by 146 wells being placed on production during the second quarter, an increase of 50 wells from the first quarter.  Further increases are expected during the second half of the year.

Second quarter production from the Spraberry field averaged 41 MBOEPD.  Spraberry production was reduced by approximately 2 MBOEPD due to a shortage of third-party oil transport trucks in the Permian Basin.  The truck shortage was primarily caused by third-party transporters diverting their trucks to other areas.  To alleviate this shortage and cover forecasted production growth, Pioneer has contracted with several third parties for additional oil transport trucks beginning in the third quarter.  The Company is also aggressively adding new gathering pipelines to reduce trucking requirements.

As a result of the Company’s initiatives to increase the rate at which wells are placed on production and add incremental oil transportation capacity, Spraberry production is forecasted to continue to grow quarterly over the remainder of the year, with full-year 2011 production expected to average 43 MBOEPD to 46 MBOEPD. Production is forecasted to further increase to 54 MBOEPD to 59 MBOEPD in 2012, 68 MBOEPD to 74 MBOEPD in 2013 and 77 MBOEPD to 84 MBOEPD in 2014.  The forecast for 2012 represents an increase of approximately 5% to the previous forecast for 2012 as a result of increasing the rig count from 35 rigs to 45 rigs by the end of 2011 instead of during 2012.  The accelerated rig count growth is also expected to benefit production in 2013 and 2014.

During 2010, Pioneer successfully added incremental production and proved reserves from vertical completions in the Lower Wolfcamp and organic rich shale/silt intervals.  The testing of deeper intervals below the Wolfcamp in certain areas of the field is now underway. This deeper interval testing includes the Strawn, the Atoka and, more recently, the Mississippian intervals.  The Company anticipates a potential increase of up to 110 thousand barrels oil equivalent (MBOE) in the estimated ultimate recovery (EUR) of a Spraberry well in areas of the field where the Strawn and Atoka intervals are both present.

Pioneer has completed 85 Spraberry wells in the Strawn interval since the testing program began in 2010.  Initial peak production rates from this interval, when tested alone, have averaged 70 barrels oil equivalent per day (BOEPD).  Production data to date suggests a potential incremental EUR per well of 20 MBOE to 40 MBOE from the Strawn interval. The incremental cost per well for this deeper drilling and one additional fracture stimulation stage is approximately $60 thousand.  Pioneer believes the Strawn interval is prospective in 40% of its Spraberry acreage and expects to complete and commingle this interval with upper intervals in 25% of the wells in its 2011 drilling program.

The Company completed its first two vertical Atoka wells in the second quarter of 2011.  The initial peak production rate from this interval alone averaged 150 BOEPD.  The Company plans to test the Atoka interval for six months and then comingle this production with production from upper intervals.  The incremental cost to drill an Atoka well ranges from approximately $250 thousand to $750 thousand.  The high end of the range reflects deeper drilling, adding an intermediate casing string and a CO2 fracture stimulation, while the low end of the range reflects shallower drilling and a water fracture stimulation, but no intermediate casing string.  The Company plans to test 10 Atoka wells in 2011.  Pioneer believes the Atoka interval is prospective in 25% to 50% of its Spraberry acreage.  Incremental EURs per well from this interval are estimated to range from 50 MBOE to 70 MBOE based on offset well data.

Pioneer completed its first vertical test of the Mississippian interval in the second quarter, with an initial peak production rate of 105 BOEPD.  The incremental cost per well for this deeper drilling and one additional fracture stimulation stage is approximately $150 thousand to $250 thousand.  Offset well data indicates a potential incremental EUR per well of 15 MBOE to 30 MBOE.  Pioneer believes the Mississippian interval is prospective in 10% to 20% of its Spraberry acreage. The Company expects to drill 24 wells to test the play, with 10 of these wells scheduled for 2011.

The Company has one rig dedicated towards research and development of horizontal drilling applications in multiple intervals of the Spraberry field.  The first well to test the Lower Wolfcamp shale interval was a 3,500-foot lateral with a 15-stage fracture stimulation completion.  The well had an initial production rate of 200 barrels oil per day and 120 thousand cubic feet (MCF) of gas per day with less than 50% of its load water recovered.  The program calls for drilling six more horizontal wells during the second half of 2011 targeting the Tippett Shale (Middle Wolfcamp) and Jo Mill (Middle Spraberry) intervals.  The first Tippett Shale well, with a planned lateral section of 6,000 feet and a 30-stage fracture stimulation completion, is currently being drilled.

The Company continues to test downspacing in the Spraberry field from 40 acres to 20 acres.  Twenty-four 20-acre wells have been drilled since 2010.  These 20-acre wells are producing from the Lower Wolfcamp, Strawn and shale/silt intervals.  Results continue to indicate production from these wells is outperforming the previous 110 MBOE type curve for a traditional Spraberry/Dean well.  The Company expects to drill 10 to 20 additional 20-acre downspaced wells in 2011.

Water injection was initiated in the third quarter of 2010 on the Company’s 7,000-acre waterflood project in the Upper Spraberry interval.  Results continue to be encouraging, as the production decline from 110 producing wells in the surveillance area continues to flatten.  Oil production response has also been observed in additional wells, with no premature water breakthrough.  Based on the results of historical waterflood projects, an ultimate 50% uptick in production from the flooded Upper Spraberry interval is expected.

In the highly prospective Eagle Ford Shale in South Texas, Pioneer and its joint venture partners have increased the rig count from 9 rigs in the second quarter to 12 rigs currently, with expected further increases to 14 rigs in early 2012, 16 rigs in early 2013 and 19 rigs in 2014.  To improve the execution of its drilling and completions program and reduce costs, Pioneer purchased two fracture stimulation fleets for its Eagle Ford Shale completions.  One fleet was placed in service in April and the other fleet is expected to be operational during the fourth quarter of 2011.  The Company also entered into a two-year contract for a dedicated third-party fracture stimulation fleet, which commenced operating in April.  With the start-up of these two fleets and some spot market fracture stimulation capacity that became available for a short period in the second quarter, Pioneer was able to increase the number of wells placed on production from 5 wells in the first quarter to 18 wells in the second quarter.  Further increases in the number of wells placed on production are expected during the second half of the year.

Six central gathering plants (CGPs) have been completed as part of the joint venture’s Eagle Ford Shale midstream business.  The seventh CGP is scheduled to commence operation during the third quarter, with the eighth CGP expected to commence operation in the fourth quarter.

Pioneer’s gross well cost in the Eagle Ford Shale ranges from $7 million to $8 million per well.  Using this cost and current NYMEX strip commodity prices, and excluding the benefit of the joint-venture drilling carry, before tax internal rates of return are estimated to be greater than 100% for high condensate yield wells (200 barrels per million cubic feet) and 75% for lean condensate yield wells (60 barrels per million cubic feet).

As a result of the increased rig count and fracture stimulation capacity in the Eagle Ford Shale, Pioneer increased its Eagle Ford Shale production from 5 MBOEPD in the first quarter to 8 MBOEPD in the second quarter.   With the number of wells placed on production expected to further increase during the second half of 2011 and future years, annual production is forecasted to average 12 MBOEPD to 15 MBOEPD in 2011 and grow to 26 MBOEPD to 30 MBOEPD in 2012, 40 MBOEPD to 45 MBOEPD in 2013 and 54 MBOEPD to 60 MBOEPD in 2014.

In the liquids-rich Barnett Shale Combo play, Pioneer has built a 72,000-acre position, representing more than 600 drilling locations.  Pioneer is currently operating two rigs in the play.  The Company has acquired 160 square miles of 3-D seismic covering its acreage and is in the process of permitting an additional 190 square miles.  Fourteen wells were placed on production during the second quarter with 7-day initial production rates averaging 350 BOEPD, including the incremental uplift from natural gas liquids (NGLs).

Production in the second quarter for the Barnett Shale Combo play was 3 MBOEPD, up from 2 MBOEPD in the first quarter.  The Company expects to generate quarterly production growth over the remainder of 2011 and average 4 MBOEPD to 5 MBOEPD for the full year.  The Company plans to increase the rig count from 2 rigs in 2011 to 4 rigs in 2012, which is expected to further increase production to 9 MBOEPD to 12 MBOEPD in 2012, 18 MBOEPD to 22 MBOEPD in 2013 and 26 MBOEPD to 31 MBOEPD in 2014.  Assuming current NYMEX strip commodity prices, an average per well drilling cost of $3 million and a gross EUR of 320 MBOE, Pioneer’s internal rate of return in the Barnett Shale Combo play is expected to be 50% before tax.  A Pioneer-owned fracture stimulation fleet commenced operating in the play during the second quarter.

2011 Capital Budget

Pioneer’s capital budget for 2011 is being increased from $1.8 billion to $2.1 billion, consisting of $1.8 billion for drilling operations and $300 million for vertical integration and facilities.  Of the $300 million increase, $200 million is

attributable to drilling and $100 million to vertical integration.  The 2011 budget excludes acquisitions, asset retirement obligations, capitalized interest and geological and geophysical G&A.

The increase of $200 million for drilling is primarily due to:

·   deeper drilling to the Strawn, Atoka and Mississippian intervals in the Spraberry field and the Company’s horizontal research and development drilling program in the field ($50 million),

·   increasing from 35 rigs to 45 rigs in the Spraberry field by year end, which is earlier than anticipated ($50 million),

·   the unplanned use of third-party fracture stimulation services due to delays in the delivery of Company-owned equipment during the first half of 2011 ($50 million) and

·   third-party service cost creep of only 3% ($50 million), reflecting the substantial benefits of the Company’s vertical integration investments, particularly in fracture stimulation fleets.

The increase of $100 million for vertical integration is primarily due to:

·   adding well service and water trucks in the Spraberry field and

·   ordering additional Company-owned fracture stimulation fleets for delivery in mid-2012.

Benefits from the increased capital spending for drilling and vertical integration include:

·   increasing the Company’s production growth target for 2012 from 18+% to 20+%, resulting primarily from increasing the Spraberry production forecast from 52 MBOEPD to 56 MBOEPD to 54 MBOEPD to 59 MBOEPD,

·   adding incremental EUR from deeper Spraberry intervals,

·   funding the Spraberry horizontal research and development program and

·   increasing annual cash savings from vertical integration by an incremental $80 million in 2012 compared to current third-party service cost rates (year-end 2011 annualized cash savings estimated to be greater than $450 million).

The revised 2011 drilling capital of $1.8 billion continues to be focused on oil and liquids-rich drilling, with 75% of the capital allocated to the Spraberry and Eagle Ford Shale plays.  The following provides a breakdown of the forecasted spending by asset:

·   Spraberry - $1.3 billion

·   Eagle Ford Shale - $120 million (reflects 25% of anticipated 2011 drilling costs; remaining 75% covered by drilling carry from Reliance Industries Limited)

·   Barnett Shale Combo - $210 million

·   Alaska - $100 million

·   Other assets - $100 million

The vertical integration funds of $300 million are for the expansion of Pioneer’s integrated well service operations in the Spraberry field, the establishment of similar services in the Eagle Ford Shale and Barnett Shale Combo plays, and the build-out of facilities to support vertical integration (yards, buildings and shops).  This spending is being recorded in Other Property and Equipment.

Eagle Ford Shale Midstream Operations

Pioneer’s share of its Eagle Ford Shale joint-venture midstream activities is conducted through a partially-owned, unconsolidated entity.  Beginning in June 2011, funding for the ongoing midstream infrastructure build-out is being provided from external debt sources. Cash flow from the services provided by the midstream operations is not included in Pioneer’s forecasted operating cash flow of $1.5 billion in 2011.

Second Quarter 2011 Financial Review

The following financial results for the second quarter of 2011 reflect continuing operations.

Sales averaged 119 MBOEPD, consisting of oil sales averaging 36 thousand barrels per day (MBPD), NGL sales averaging 22 MBPD and gas sales averaging 362 million cubic feet per day.

The average reported price for oil was $104.35 per barrel and included $3.38 per barrel related to deferred revenue from volumetric production payments (VPPs) for which production was not recorded.  The average reported price for NGLs was $48.16 per barrel.  The average reported price for gas was $4.31 per MCF.

Production costs averaged $12.82 per barrel oil equivalent (BOE), a decrease of $0.49 per BOE from the first quarter of 2011.  This decrease was primarily related to increased third-party throughput volumes at Pioneer’s natural gas processing facilities, higher NGL price realizations on third-party volumes and reduced gathering system operating costs.

Depreciation, depletion and amortization (DD&A) expense averaged $14.26 per BOE. Exploration and abandonment costs were $20 million for the quarter and included $3 million of acreage abandonments and $17 million of geologic and geophysical expenses and personnel costs.

Third Quarter 2011 Financial Outlook

The Company’s third quarter 2011 outlook for certain operating and financial items is provided below.

Production is forecasted to average 125 MBOEPD to 131 MBOEPD.  South Africa production is currently shut in due to unplanned third-party gas-to-liquids plant downtime.  Production guidance excludes the potential for this downtime to be extended beyond four weeks.

Production costs are expected to average $12.00 to $14.00 per BOE, based on current NYMEX strip commodity prices.  DD&A expense is expected to average $13.50 to $15.00 per BOE.  Total exploration and abandonment expense is forecasted to be $25 million to $35 million.

General and administrative expense is expected to be $45 million to $50 million, interest expense is expected to be $44 million to $48 million, and other expense is expected to be $20 million to $30 million. Accretion of discount on asset retirement obligations is expected to be $2 million to $4 million.

Noncontrolling interest in consolidated subsidiaries’ income, excluding unrealized derivative 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 35% to 45% based on current capital spending plans and the assumption of no significant unrealized derivative mark-to-market changes in the Company’s derivative position.  Current income taxes are expected to be $5 million to $10 million and are primarily attributable to South Africa.

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

Earnings Conference Call

On Thursday, August 4, 2011, at 10:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended June 30, 2011, 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) 741-4245 confirmation code: 3333505 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 August 25 by dialing (888) 203-1112 confirmation code: 3333505.

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 with third parties on mutually acceptable terms, litigation, the costs and results of drilling and operations, availability of equipment, services and personnel required to complete the Company’s operating activities, access to and availability of 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, including the possible impacts of climate change, international operations 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.

Cautionary Note to U.S. Investors --The U.S. Securities and Exchange Commission (the "SEC") prohibits oil and gas companies, in their filings with the SEC, from disclosing estimates of oil or gas resources other than “reserves,” as that term is defined by the SEC. In this news release, Pioneer includes estimates of quantities of oil and gas using certain terms, such as “resource potential,” “estimated ultimate recovery,” “EUR” or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC’s definitions of proved, probable and possible reserves, and which the SEC's guidelines strictly prohibit Pioneer from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by Pioneer. U.S. investors are urged to consider closely the disclosures in the Company’s periodic filings with the SEC.  Such filings are available from the Company at 5205 N. O'Connor Blvd., Suite 200, Irving, Texas 75039, Attention: Investor Relations, and the Company’s website at www.pxd.com. These filings also can be obtained from the SEC by calling 1-800-SEC-0330.

Pioneer Natural Resources Contacts:

Investors

Frank Hopkins – 972-969-4065

Brian Hansen – 972-969-4017

Eric Pregler – 972-969-5756

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)

			June 30, 2011		December 31, 2010
ASSETS
Current assets:
	Cash and cash equivalents		$	352,421	$	111,160
	Accounts receivable, net			269,178		245,303
	Income taxes receivable			3,674		30,901
	Inventories			234,108		173,615
	Prepaid expenses			21,342		11,441
	Deferred income taxes			163		156,650
	Discontinued operations held for sale			-		281,741
	Derivatives			154,129		171,679
	Other current assets, net			36,092		14,693
		Total current assets		1,071,107		1,197,183
Property, plant and equipment, at cost:
	Oil and gas properties, using the successful efforts method of accounting			11,754,331		10,930,226
	Accumulated depletion, depreciation and amortization			(3,637,605)		(3,366,440)
		Total property, plant and equipment		8,116,726		7,563,786
Deferred income taxes				1,878		-
Goodwill				298,177		298,182
Other property and equipment, net				431,214		283,542
Investment in unconsolidated affiliate				155,701		72,045
Derivatives				142,361		151,011
Other assets, net				135,924		113,353
			$	10,353,088	$	9,679,102
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable		$	517,396	$	419,150
	Interest payable			57,366		59,008
	Income taxes payable			5,927		19,168
	Deferred income taxes			19,588		1,144
	Discontinued operations held for sale			-		108,592
	Deferred revenue			43,580		44,951
	Derivatives			76,008		80,997
	Other current liabilities			35,776		36,210
		Total current liabilities		755,641		769,220
Long-term debt				2,570,978		2,601,670
Deferred income taxes				1,844,503		1,751,310
Deferred revenue				21,150		42,069
Derivatives				108,075		56,574
Other liabilities				236,777		232,234
Stockholders' equity				4,815,964		4,226,025
			$	10,353,088	$	9,679,102

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

			Three Months Ended June 30,				Six Months Ended June 30,
			2011		2010		2011			2010
Revenues and other income:
	Oil and gas		$	583,931	$	422,042	$	1,081,061	$	894,087
	Interest and other			18,454		16,952		51,141		34,960
	Gain (loss) on disposition of assets, net			(296)		7,645		(2,487)		24,588
				602,089		446,639		1,129,715		953,635
Costs and expenses:
	Oil and gas production			102,455		94,012		202,386		180,112
	Production and ad valorem taxes			35,864		25,338		69,160		52,399
	Depletion, depreciation and  amortization			153,898		144,309		294,271		288,737
	Exploration and abandonments			19,914		22,743		37,557		39,591
	General and administrative			44,644		40,433		88,750		78,748
	Accretion of discount on asset retirement obligations			2,658		2,529		5,313		5,388
	Interest			45,768		45,368		90,995		92,891
	Hurricane activity, net			(2)		5,184		69		(2,226)
	Derivative (gains) losses, net			(229,478)		(177,528)		14,954		(443,004)
	Other			14,388		14,193		32,269		30,139
				190,109		216,581		835,724		322,775
Income from continuing operations before income taxes				411,980		230,058		293,991		630,860
Income tax provision				(144,696)		(83,220)		(97,545)		(227,227)
Income from continuing operations				267,284		146,838		196,446		403,633
Income (loss) from discontinued operations, net of tax				(1,584)		41,851		413,058		45,662
Net income				265,700		188,689		609,504		449,295
	Net income attributable to the noncontrolling interests			(20,123)		(21,113)		(15,333)		(36,465)
Net income attributable to common stockholders			$	245,577	$	167,576	$	594,171	$	412,830
Basic earnings per share:
	Income from continuing operations attributable to common stockholders		$	2.08	$	1.07	$	1.53	$	3.12
	Income (loss) from discontinued operations attributable to common
		stockholders		(0.01)		0.35		3.50		0.39
	Net income attributable to common stockholders		$	2.07	$	1.42	$	5.03	$	3.51
Diluted earnings per share:
	Income from continuing operations attributable to common stockholders		$	2.04	$	1.06	$	1.50	$	3.10
	Income (loss) from discontinued operations attributable to common
		stockholders		(0.01)		0.35		3.40		0.39
	Net income attributable to common stockholders		$	2.03	$	1.41	$	4.90	$	3.49
Weighted average shares outstanding:
	Basic			116,213		115,104		116,042		114,880
	Diluted			118,592		116,006		118,986		115,735

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

						Three Months Ended June 30,				Six Months Ended June 30,
						2011		2010		2011		2010
Cash flows from operating activities:
	Net income				$	265,700	$	188,689	$	609,504	$	449,295
		Adjustments to reconcile net income to net cash provided by
		operating activities:
			Depletion, depreciation and amortization			153,898		144,309		294,271		288,737
			Exploration expenses, including dry holes			2,794		4,386		4,275		7,973
			Hurricane activity, net			-		3,500		-		3,500
			Deferred income taxes			131,375		78,807		75,507		220,352
			(Gain) loss on disposition of assets, net			296		(7,645)		2,487		(24,588)
			Accretion of discount on asset retirement obligations			2,658		2,529		5,313		5,388
			Discontinued operations			950		19,905		(407,115)		41,463
			Interest expense			7,795		7,513		15,432		14,920
			Derivative related activity			(220,303)		(160,216)		56,380		(442,087)
			Amortization of stock-based compensation			10,981		9,425		21,155		19,049
			Amortization of deferred revenue			(11,207)		(22,588)		(22,290)		(45,070)
			Other noncash items			2,211		1,727		(18,277)		1,324
	Change in operating assets and liabilities:
			Accounts receivable, net			1,665		48,296		(23,605)		96,376
			Income taxes receivable			27,225		2,176		27,226		23,440
			Inventories			(44,817)		(4,950)		(74,136)		12,479
			Prepaid expenses			(11,332)		(10,639)		(9,990)		(10,204)
			Other current assets			5,467		(8,418)		8,772		(7,192)
			Accounts payable			96,181		84,754		6,201		50,458
			Interest payable			23,424		20,328		(1,642)		7,014
			Income taxes payable			(26,839)		(2,934)		(11,485)		(4,470)
			Other current liabilities			3,118		(5,103)		6,471		(14,943)
				Net cash provided by operating activities		421,240		393,851		564,454		693,214
Net cash used in investing activities						(576,020)		(71,830)		(241,852)		(238,373)
Net cash used in financing activities						(13,450)		(158,875)		(81,341)		(284,523)
Net increase (decrease) in cash and cash equivalents						(168,230)		163,146		241,261		170,318
Cash and cash equivalents, beginning of period						520,651		34,540		111,160		27,368
Cash and cash equivalents, end of period					$	352,421	$	197,686	$	352,421	$	197,686

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUMMARY PRODUCTION AND PRICE DATA

				Three Months Ended June 30,				Six Months Ended June 30,
				2011		2010		2011		2010
Average Daily Sales Volumes
	from Continuing Operations:
		Oil (Bbls) -	U.S.		35,872		27,447		34,904		26,630
			South Africa		616		641		571		875
			Worldwide		36,488		28,088		35,475		27,505
		Natural gas liquids (Bbls) -	U.S.		21,839		19,291		20,251		19,204
		Gas (Mcf) -	U.S.		337,354		333,916		331,295		340,048
			South Africa		24,193		28,810		23,867		29,915
			Worldwide		361,547		362,726		355,162		369,963
		Total (BOE) -	U.S.		113,937		102,391		110,371		102,508
			South Africa		4,648		5,443		4,549		5,861
			Worldwide		118,585		107,834		114,920		108,369
Average Reported Prices (a):
		Oil (per Bbl) -	U.S.	$	104.34	$	89.50	$	100.05	$	90.74
			South Africa	$	104.86	$	76.88	$	105.56	$	77.32
			Worldwide	$	104.35	$	89.21	$	100.13	$	90.31
		Natural gas liquids (per Bbl) -	U.S.	$	48.16	$	34.40	$	45.42	$	38.07
		Gas (per Mcf) -	U.S.	$	4.11	$	3.87	$	4.00	$	4.52
			South Africa	$	7.10	$	6.11	$	7.41	$	6.21
			Worldwide	$	4.31	$	4.05	$	4.23	$	4.66
		Total (BOE) -	U.S.	$	54.24	$	43.09	$	51.97	$	45.72
			South Africa	$	50.88	$	41.39	$	52.13	$	43.25
			Worldwide	$	54.11	$	43.01	$	51.97	$	45.58

__________

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

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY EARNINGS PER SHARE INFORMATION

The Company uses the two-class method of calculating basic and diluted earnings per share.  Under the two-class method of calculating earnings per share, GAAP provides that share- and unit-based awards with guaranteed dividend or distribution participation rights qualify as "participating securities" during their vesting periods.  The Company's basic net income per share attributable to common stockholders is computed as (i) net income attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company's diluted net income per share attributable to common stockholders is computed as (i) basic net income attributable to common stockholders, (ii) plus the reallocation of participating earnings (iii) divided by weighted average diluted shares outstanding. During periods in which the Company realizes a loss from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would be dilutive to loss per share; therefore, conversion into common stock is assumed not to occur.

The following table is a reconciliation of the Company's net income attributable to common stockholders to basic net income attributable to common stockholders and to diluted net income attributable to common stockholders for thethree and six months ended June 30, 2011 and 2010:

		Three Months Ended June 30,				Six Months Ended June 30,
		2011		2010		2011		2010
		(in thousands)
Net income attributable to common stockholders		$	245,577	$	167,576	$	594,171	$	412,830
	Participating basic earnings		(4,847)		(4,083)		(10,849)		(9,390)
Basic net income attributable to common stockholders			240,730		163,493		583,322		403,440
	Reallocation of participating earnings		164		112		271		110
Diluted net income attributable to common stockholders
	stockholders	$	240,894	$	163,605	$	583,593	$	403,550

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and six months ended June 30, 2011 and 2010:

		Three Months Ended June 30,		Six Months Ended June 30,
		2011	2010	2011	2010
		(in thousands)
Weighted average common shares outstanding:
	Basic	116,213	115,104	116,042	114,880
	Dilutive common stock options	178	262	188	243
	Contingently issuable performance unit shares	429	640	423	612
	Convertible senior notes dilution	1,772	-	2,333	-
	Diluted	118,592	116,006	118,986	115,735

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 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 or net cash provided by operating activities, as defined by GAAP.

			Three Months Ended June 30,				Six Months Ended June 30,
			2011		2010		2011		2010
Net income		$	265,700	$	188,689	$	609,504	$	449,295
Depletion, depreciation and amortization			153,898		144,309		294,271		288,737
Exploration and abandonments			19,914		22,743		37,557		39,591
Hurricane activity, net			(2)		5,184		69		(2,226)
Accretion of discount on asset retirement obligations			2,658		2,529		5,313		5,388
Interest expense			45,768		45,368		90,995		92,891
Income tax provision			144,696		83,220		97,545		227,227
(Gain) loss on disposition of assets, net			296		(7,645)		2,487		(24,588)
Discontinued operations			1,584		(41,851)		(413,058)		(45,662)
Derivative related activity			(220,303)		(160,216)		56,380		(442,087)
Amortization of stock-based compensation			10,981		9,425		21,155		19,049
Amortization of deferred revenue			(11,207)		(22,588)		(22,290)		(45,070)
Other noncash items			2,211		1,727		(18,277)		1,324
	EBITDAX (a)		416,194		270,894		761,651		563,869
Cash interest expense			(37,973)		(37,855)		(75,563)		(77,971)
Current income taxes			(13,321)		(4,413)		(22,038)		(6,875)
	Discretionary cash flow (b)		364,900		228,626		664,050		479,023
Cash hurricane activity			2		(1,684)		(69)		5,726
Discontinued operations cash activity			(634)		61,756		5,943		87,125
Cash exploration expense			(17,120)		(18,357)		(33,282)		(31,618)
Changes in operating assets and liabilities			74,092		123,510		(72,188)		152,958
	Net cash provided by operating activities	$	421,240	$	393,851	$	564,454	$	693,214

__________

(a)

“EBITDAX” represents earnings before depletion, depreciation and amortization expense; exploration and abandonments; net hurricane activity; unrealized mark-to-market derivative activity; accretion of discount on asset retirement obligations; interest expense; income taxes; (gain) loss on the disposition of assets, net; 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, cash activity reflected in discontinued operations and hurricane activity, and 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 ("MTM") derivative gains, and income adjusted for unrealized MTM derivative gains and unusual items, 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 measures and should be read only in conjunction with Pioneer's consolidated financial statements prepared in accordance with GAAP.  Unrealized MTM net derivative gains and losses and net discontinued operations 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 June 30, 2011, as determined in accordance with GAAP, to income adjusted for unrealized MTM derivative gains, and income adjusted for unrealized MTM derivative gains and unusual items, for that quarter.

		After-tax Amounts		Diluted Amounts Per Share
Net income attributable to common stockholders		$	246	$	2.03
	Unrealized MTM derivative gains		(133)		(1.10)
Adjusted income excluding unrealized MTM derivative gains			113		0.93
	Discontinued operations		2		0.01
Adjusted income excluding unrealized MTM derivative gains and unusual items		$	115	$	0.94

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Open Commodity Derivative Positions as of August 2, 2011

(Volumes are average daily amounts)

				2011
				Third Quarter		Fourth Quarter		2012		2013		2014		2015
Average Daily Oil Production Associated with
Derivatives (Bbls):
	Swap Contracts:
		Volume			750		750		3,000		3,000		-		-
		NYMEX price		$	77.25	$	77.25	$	79.32	$	81.02	$	-	$	-
	Collar Contracts:
		Volume			2,000		2,000		2,000		-		-		-
		NYMEX price:
			Ceiling	$	170.00	$	170.00	$	127.00	$	-	$	-	$	-
			Floor	$	115.00	$	115.00	$	90.00	$	-	$	-	$	-
	Collar Contracts with Short Puts:
		Volume			32,000		32,000		36,000		31,250		22,000		-
		NYMEX price:
			Ceiling	$	99.33	$	99.33	$	117.99	$	120.62	$	129.76	$	-
			Floor	$	73.75	$	73.75	$	80.42	$	83.32	$	88.86	$	-
			Short Put	$	59.31	$	59.31	$	65.00	$	65.76	$	70.23	$	-
	Percent of total oil production (a)				~85%		~80%		~75%		~50%		~25%		N/A
Average Daily NGL Production Associated with
Derivatives (Bbls):
	Swap Contracts:
		Volume			1,150		1,150		750		-		-		-
		Blended index price (b)		$	51.50	$	51.50	$	35.03	$	-	$	-	$	-
	Collar Contracts:
		Volume			2,650		2,650		-		-		-		-
		Index price (b):
			Ceiling	$	64.23	$	64.23	$	-	$	-	$	-	$	-
			Floor	$	53.29	$	53.29	$	-	$	-	$	-	$	-
	Percent of total NGL production (a)				~15%		~15%		<5%		N/A		N/A		N/A
Average Daily Gas Production Associated with
Derivatives (MMBtu):
	Swap Contracts:
		Volume			117,500		117,500		105,000		67,500		50,000		-
		NYMEX price (c)		$	6.13	$	6.13	$	5.82	$	6.11	$	6.05	$	-
	Collar Contracts:
		Volume			-		-		65,000		150,000		140,000		50,000
		NYMEX price (c):
			Ceiling	$	-	$	-	$	6.60	$	6.25	$	6.44	$	7.92
			Floor	$	-	$	-	$	5.00	$	5.00	$	5.00	$	5.00
	Collar Contracts with Short Puts:
		Volume			200,000		200,000		190,000		45,000		50,000		-
		NYMEX price (c):
			Ceiling	$	8.55	$	8.55	$	7.96	$	7.49	$	8.08	$	-
			Floor	$	6.32	$	6.32	$	6.12	$	6.00	$	6.00	$	-
			Short Put	$	4.88	$	4.88	$	4.55	$	4.50	$	4.50	$	-
	Percent of total gas production (a)				~90%		~85%		~80%		~50%		~40%		~5%
	Basis Swap Contracts:
		Permian Basin Index Swaps volume (d)			20,000		20,000		32,500		2,500		-		-
		Price differential ($/MMBtu)		$	(0.30)	$	(0.30)	$	(0.38)	$	(0.31)	$	-	$	-
		Mid-Continent Index Swaps volume (d)			100,000		100,000		40,000		10,000		-		-
		Price differential ($/MMBtu)		$	(0.71)	$	(0.71)	$	(0.58)	$	(0.71)	$	-	$	-
		Gulf Coast Index Swaps volume (d)			23,500		23,500		53,500		40,000		20,000		-
		Price differential ($/MMBtu)		$	(0.16)	$	(0.16)	$	(0.15)	$	(0.13)	$	(0.14)	$	-

__________

(a)	Represents an estimated percentage of forecasted production, which may differ from the percentage of actual production.
(b)	Represents weighted average index price per Bbl of each NGL component.
(c)	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.
(d)	Represent swaps that fix the basis differentials between the indices price at which the Company sells its Permian Basin, Mid-Continent and Gulf Coast gas and the NYMEX Henry Hub index price used in gas swap contracts.

Diesel price derivatives.  During the second quarter of 2011, the Company purchased diesel derivative swap contracts for 250 notional Bbls per day for the period from July 2011 through December 2011 at an average per Bbl fixed price of $123.90.  The diesel derivative swap contracts are priced at an index that is highly correlated to the prices that the Company incurs to fuel its drilling rigs and fracture stimulation fleet equipment.  The Company purchases diesel derivative swap contracts to mitigate fuel price risk.  The Company's diesel derivative swap contracts are not included in the table presented above.

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Amortization of Deferred Revenue Associated with Volumetric Production Payments and Derivative Losses as of June 30, 2011

(in thousands)

		2011
		Third Quarter		Fourth Quarter		2012		Total
Total deferred revenues (a)		$	11,330	$	11,329	$	42,071	$	64,730
Less derivative losses to be recognized in
	pretax earnings (b)		(903)		(904)		(3,160)		(4,967)
Total VPP impact to pretax earnings		$	10,427	$	10,425	$	38,911	$	59,763

__________

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

Deferred Gains on Discontinued Commodity Hedges as of June 30, 2011 (a)

(in thousands)

	2011
	Third Quarter		Fourth Quarter
Commodity hedge gains - oil (b)	$	9,197	$	9,197

__________

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

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Derivative (Gains) Losses, Net

(in thousands)

				Three Months Ended June 30, 2011		Six Months Ended June 30, 2011
Unrealized mark-to-market changes in fair value:
	Oil derivative (gains) losses			$	(171,615)	$	41,336
	NGL derivative (gains) losses				(3,324)		3,794
	Gas derivative (gains) losses				(31,583)		16,977
	Diesel derivative gains				(96)		(96)
	Interest rate derivative gains				(14,575)		(7,394)
		Total unrealized mark-to-market derivative (gains) losses, net (a)			(221,193)		54,617
Cash settled changes in fair value:
	Oil derivative losses				27,607		40,841
	NGL derivative losses				4,629		7,325
	Gas derivative gains				(40,521)		(82,800)
	Interest rate derivative gains				-		(5,029)
		Total cash derivative gains, net			(8,285)		(39,663)
			Total derivative (gains) losses, net	$	(229,478)	$	14,954

__________

(a) Total unrealized mark-to-market derivative (gains) losses, net includes $10.5 million of gains and $3.7 million of losses attributable to noncontrolling interests in consolidated subsidiaries during the three and six months ending June 30, 2011, respectively.