PIONEER NATURAL RESOURCES CO - FORM 8-K - EX-99.1 - PXD 11/1/11 EARNINGS RELEASE 8-K EXH 99.1

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EXHIBIT 99.1

News Release

Pioneer Natural Resources Reports

Third Quarter 2011 Financial and Operating Results

Dallas, Texas, November 1, 2011 -- Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today announced financial and operating results for the quarter ended September 30, 2011.

Pioneer reported third quarter net income attributable to common stockholders of $351 million, or $2.95 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 $191 million after tax, or $1.60 per diluted share. Without the effect of this item, adjusted income for the third quarter would have been $160 million, or $1.35 per diluted share. Also included in Pioneer’s third quarter results was income of $26 million after tax, or $0.21 per diluted share, related to unwinding certain oil and interest rate derivatives.

Scott Sheffield, Chairman and CEO, stated, “The Company delivered another strong quarter, with production increasing to 128 thousand barrels oil equivalent per day (MBOEPD), an increase of 9 MBOEPD, or 8%, from the second quarter of 2011. This follows an increase of 7 MBOEPD, or 7%, from the first quarter to the second quarter. Our three core Texas liquids-rich growth assets, the Spraberry field, Eagle Ford Shale and the Barnett Shale Combo, were the drivers of these quarterly production increases. Fourth quarter production is forecasted to grow by approximately 10 MBOEPD, reflecting the continued successful drilling in these three assets. For 2011, production is expected to average approximately 125 MBOEPD.”

“Based on our drilling plans for the Spraberry field, the Eagle Ford Shale and the Barnett Shale Combo play, we expect the Company to deliver production growth of 20+% in 2012 compared to 2011 and U.S. production growth of 22+%. We also expect the Company to achieve a compound annual production growth rate of 18+% through 2014, with liquids increasing from 44% of total production in 2010 to 60% in 2014. This strong, liquids-focused production growth is forecasted to generate compound annual operating cash flow growth of 30+% over the 2011 through 2014 period.”

“We are excited about the successful horizontal well we recently completed in the Wolfcamp Shale. It continues to flow naturally with a peak seven-day average rate of 732 barrels oil equivalent per day (BOEPD) and a peak 24-hour rate of 854 BOEPD, even with flow line restrictions. This result, coupled with the strong production from other industry players drilling horizontal wells in this interval and Pioneer’s extensive geologic interpretation of the area, suggests significant horizontal Wolfcamp Shale potential exists within Pioneer’s acreage. We are currently focusing our efforts on more than 200,000 acres in the southern part of the field. We plan to drill three additional horizontal Wolfcamp Shale wells by early 2012 and expect to expand our horizontal drilling program in this area next year.”

“Owning fracture stimulation fleets, drilling 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 will be greater than $450 million.”

“We are funding our 2011 capital program of $2.1 billion from forecasted operating cash flow of $1.4 billion to $1.5 billion and the redeployment of proceeds from the sale of Tunisia. Pioneer has a strong financial position, with a net

debt-to-book capitalization of 31% as of September 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

The Spraberry field and the Eagle Ford Shale are the two most active plays in the U.S., with the industry operating 225 rigs and 200 rigs in each play, respectively. Pioneer is a drilling, production and technology leader in both of these liquids-rich, high-margin plays.

In the Spraberry oil field in West Texas, Pioneer has increased its drilling program to an average of 38 rigs in the third quarter, including 15 Company-owned rigs. The Company has continued to expand its integrated services to control drilling costs and support the execution of its accelerated drilling program. Five Company-owned fracture stimulation fleets are currently operating in the Spraberry field. 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 forecasted 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 its vertical integration equipment will provide approximately one third of its rig requirements and two thirds of its fracture stimulation requirements by the end of 2011. As a result, the blended Pioneer and third-party well cost is expected to average $1.5 million to $1.6 million per well for 2011. Pioneer’s internal rate of return on its 2011 Spraberry drilling program is expected to be approximately 40% before tax based on flat commodity prices of $90 per barrel for oil and $5 per thousand cubic feet (MCF) for gas, estimated future production costs and an estimated ultimate recovery (EUR) of 140 thousand barrels oil equivalent (MBOE) for a vertical well completed through the Lower Wolfcamp.

During 2010, Pioneer successfully added incremental production and proved reserves from vertical completions in the Lower Wolfcamp and organic rich shale/silt intervals. The Company is also continuing to drill deeper intervals below the Wolfcamp in certain areas of the field. This deeper drilling includes the Strawn, the Atoka and the Mississippian intervals. The Company anticipates a potential increase of up to 110 MBOE in the EUR of a Lower Wolfcamp well in areas of the field where the Strawn and Atoka intervals are both present.

Pioneer has completed 113 vertical wells in the Strawn interval since the drilling program began in 2010. Initial peak production rates from this interval, when tested alone, have averaged 70 BOEPD. For wells that have been on production for at least ten months, production has increased by more than 25% compared to offset wells that have been drilled only to the Lower Wolfcamp. This data 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 all zones in 25% of the vertical wells drilled in the fourth quarter of 2011 and during 2012.

The Company completed its third vertical Atoka well in the third quarter of 2011. The initial peak production rate from this interval alone averaged 127 BOEPD. The Company plans to test the Atoka interval for approximately six months and will then commingle this production with production from all zones. The incremental cost to drill an Atoka well ranges from approximately $300 thousand to $350 thousand as a result of deeper drilling, larger casing and two additional fracture stimulation stages. 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. The Company plans to test two to three additional single-zone Atoka

wells in the fourth quarter and is forecasting that 15% to 20% of its 2012 vertical drilling program in the Spraberry will include wells drilled to the Atoka interval, with production commingled from all zones.

Pioneer completed its second vertical test of the Mississippian interval in the third quarter, with an initial peak production rate of 92 BOEPD. The incremental cost per well for this deeper drilling, larger casing and two additional fracture stimulation stages is approximately $300 thousand to $350 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 complete one to two additional single-zone wells in the fourth quarter and is forecasting that 10% of its 2012 vertical drilling program in the Spraberry will include wells drilled to the Mississippian interval, with production commingled from all zones.

The Company continues to test vertical downspacing in the Spraberry field from 40 acres to 20 acres. Eleven 20-acre vertical wells have been drilled during 2011, with six put on production. These 20-acre wells are producing from the Lower Wolfcamp, Strawn and shale/silt intervals. As was the case with 20-acre wells drilled during 2010, results continue to indicate that production from these wells is significantly outperforming the previous 110 MBOE type curve for a traditional Spraberry/Dean well. The Company expects to drill three to five additional 20-acre downspaced wells in 2011 and is targeting 30 to 50 20-acre wells in its 2012 vertical drilling program.

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 has flattened and an increase in production is now being observed. Cumulative production from the area flooded in the Upper Spraberry has increased by greater than 10% compared to forecasted base production decline, with further increases expected as additional wells respond to the water injection. Based on these early results, reserve adds related to the waterflood are likely during 2011.

The Company has one dedicated rig drilling horizontal wells in the Wolfcamp Shale in the Spraberry field area. The Company successfully completed its first horizontal well in Upton County, Texas with a 30-stage fracture stimulation in a 5,800-foot lateral section. The XBC Giddings Estate 2041H continues to flow naturally with a peak seven-day average rate of 732 BOEPD (591 barrels oil per day, 86 barrels natural gas liquids (NGLs) per day and 332 MCF per day), and a peak 24-hour rate of 854 BOEPD (686 barrels oil per day, 102 barrels NGLs per day and 395 MCF per day), even with flow line restrictions. Pioneer’s micro-seismic analysis of the completion showed that the entire 800 foot thick target zone was successfully fracture stimulated. The well is producing to sales.

The results of the XBC Giddings 2041H well are encouraging, as this well is 30 miles to 60 miles northwest of the area where most of the recent successful industry drilling of horizontal Wolfcamp Shale wells has been occurring. Based on this successful drilling activity and Pioneer’s extensive geologic interpretation of the Wolfcamp Shale, the Company believes it has significant horizontal Wolfcamp Shale potential within its acreage and is currently focusing its efforts on more than 200,000 acres in the southern part of the field. Pioneer has not been drilling vertical Spraberry wells in this area because the returns are marginal and the southern acreage is not prospective for the deeper Strawn, Atoka and Mississippian intervals.

Pioneer is currently drilling its second horizontal Wolfcamp Shale well in Upton County with a planned 6,000-foot lateral section and 30-stage fracture stimulation. Two additional horizontal Wolfcamp Shale wells are planned in southern Reagan County by early 2012. These two wells are expected to test longer lateral lengths and additional fracture stimulation stages. Pioneer expects to expand its horizontal drilling program in 2012.

Third quarter production from the Spraberry field averaged 47 MBOEPD, an increase of 6 MBOEPD from the second quarter. Current production is approximately 51 MBOEPD. Spraberry production is forecasted to continue to grow to 51 MBOEPD to 53 MBOEPD in the fourth quarter, with full-year 2011 production expected to be towards the high end of the Company’s full-year average guidance of 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 through 2014 excludes the potential contributions from drilling vertical wells deeper to intervals below the Lower Wolfcamp and the impacts from the expected expansion of horizontal Wolfcamp Shale drilling.

In the liquids-rich Eagle Ford Shale in South Texas, Pioneer and its joint venture partners are currently running 12 rigs. 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 later in the fourth quarter. 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, Pioneer has been able to significantly increase the number of wells put on production, with a further increase expected when the second Company-owned fleet commences operations later this quarter.

The Company continues to see strong performance from its Eagle Ford Shale drilling program. Wells drilled during the third quarter continued to yield approximately 65% liquids, consisting of oil, condensate and NGLs. The lateral length of each well continues to average approximately 5,500 feet and is being completed with a 13-stage fracture stimulation.

Eight central gathering plants (CGPs) have been completed as part of the joint venture’s Eagle Ford Shale midstream business. Three additional CGPs are planned for 2012. 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 ongoing midstream infrastructure build-out costs that are in excess of operating cash flow are expected to be 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 $1.4 billion to $1.5 billion in 2011.

Pioneer’s gross well cost in the Eagle Ford Shale ranges from $7 million to $8 million per well. Using this cost, flat commodity prices of $90 per barrel for oil and $5 per MCF for gas, estimated future production costs, and excluding the benefit of the joint-venture drilling carry, before tax internal rates of return are estimated to be 80% for high condensate yield wells (200 barrels per million cubic feet) and 60% for lean condensate yield wells (60 barrels per million cubic feet).

Pioneer has been testing the use of lower-cost white sand instead of ceramic proppant to fracture stimulate wells drilled in shallower areas of the field. Twenty wells have been tested to date, with a savings of approximately $700 thousand per well. Early well performance has been similar to direct offset ceramic-stimulated wells. Pioneer plans to continue to monitor the performance of these wells and plans to use white sand in approximately 30% of its 2012 drilling program.

Pioneer increased its Eagle Ford Shale production from 8 MBOEPD in the second quarter to 14 MBOEPD in the third quarter as it continued to successfully bring new wells on production. Current production is approximately 20 MBOEPD. A further increase to 20 MBOEPD to 23 MBOEPD is forecasted for the fourth quarter. As a result, annual production for 2011 is forecasted to average 12 MBOEPD to 15 MBOEPD 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 76,000-acre position, representing more than 700 drilling locations. Pioneer is currently operating two rigs in the play. The Company continued to see performance from new wells improve in the third quarter. Production is liquids-rich, with approximately 75% of the production being oil and NGLs.

Production in the third quarter for the Barnett Shale Combo play was 4 MBOEPD, up from 3 MBOEPD in the second quarter. Current production is approximately 5 MBOEPD. The Company expects production to increase to 5 MBOEPD to 7 MBOEPD in the fourth quarter and average 4 MBOEPD to 5 MBOEPD for the full year. Current plans call for a further increase in 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 flat commodity prices of $90 per barrel for oil and $5 per MCF for gas, estimated future production costs, 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 40% before tax.

South Africa production was shut in for approximately three weeks during the third quarter due to unplanned third-party gas-to-liquids plant downtime. As a result, Pioneer’s third quarter production was reduced by approximately 1 MBOEPD. The plant was again shut down in late September due to an unrelated issue and has just come back on line at the end of October. As a result, Pioneer’s fourth quarter production guidance has been reduced by approximately 1.5 MBOEPD.

Third Quarter 2011 Financial Review

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

Sales averaged 128 MBOEPD, consisting of oil sales averaging 43 thousand barrels per day (MBPD), NGL sales averaging 23 MBPD and gas sales averaging 370 million cubic feet per day (MMCFPD). Compared to the second quarter, third quarter oil sales increased by 6 MBPD, primarily due to continued successful drilling and the addition of incremental oil transport trucks in the Spraberry field. NGL sales during the third quarter were essentially flat compared to the second quarter due to unplanned downtime and takeaway limitations at the Midkiff/Benedum plants in the Spraberry field. The plants are now back in full operations and the takeaway limitations have been resolved. Gas sales during the third quarter increased by 9 MMCFPD compared to the second quarter as higher sales in the Eagle Ford Shale and Barnett Shale Combo were partly offset by unplanned plant downtime in South Africa and the constraints at Midkiff/Benedum.

The average reported price for oil was $92.24 per barrel and included $2.88 per barrel related to deferred revenue from volumetric production payments (VPPs) for which production was not recorded. The average reported price for NGLs was $48.36 per barrel. The average reported price for gas was $4.24 per MCF.

Production costs averaged $13.47 per barrel oil equivalent (BOE), an increase of $0.65 per BOE from the second quarter of 2011. This increase was primarily due to higher lease operating expenses related in large part to increases in labor rates, chemical costs and electricity rates. Higher natural gas processing expenses increased as a result of unplanned downtime and NGL takeaway limitations at the Midkiff/Benedum plants.

Depreciation, depletion and amortization (DD&A) expense averaged $14.18 per BOE. Exploration and abandonment costs were $20 million for the quarter and included $2 million of acreage abandonments and $18 million of geologic and geophysical expenses and personnel costs.

Fourth Quarter 2011 Financial Outlook

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

Production is forecasted to average 136 MBOEPD to 141 MBOEPD. South Africa production was shut-in during the month of October due to unplanned third-party gas-to-liquids plant downtime. The plant is now back in operation and production guidance for the quarter reflects the October downtime and assumes the plant will be in full operation over the remainder of the quarter.

Production costs are expected to average $12.50 to $14.50 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 $47 million to $52 million, interest expense is expected to be $45 million to $49 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 40% 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 $10 million to $15 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 Wednesday, November 2, 2011, at 11:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended September 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) 718-5111 confirmation code: 3367644 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 November 30 by dialing (888) 203-1112 confirmation code: 3367644.

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)

			September 30, 2011		December 31, 2010
ASSETS
Current assets:
	Cash and cash equivalents		$	210,565	$	111,160
	Accounts receivable, net			278,188		245,303
	Income taxes receivable			2,312		30,901
	Inventories			260,356		173,615
	Prepaid expenses			18,910		11,441
	Deferred income taxes			92,140		156,650
	Discontinued operations held for sale			-		281,741
	Derivatives			234,806		171,679
	Other current assets, net			6,366		14,693

		Total current assets		1,103,643		1,197,183

Property, plant and equipment, at cost:
	Oil and gas properties, using the successful efforts method of accounting			12,341,837		10,930,226
	Accumulated depletion, depreciation and amortization			(3,788,686)		(3,366,440)

		Total property, plant and equipment		8,553,151		7,563,786

Deferred income taxes				7,358		-
Goodwill				298,154		298,182
Other property and equipment, net				500,709		283,542
Investment in unconsolidated affiliate				164,107		72,045
Derivatives				224,754		151,011
Other assets, net				133,167		113,353

			$	10,985,043	$	9,679,102

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable		$	631,804	$	419,150
	Interest payable			33,955		59,008
	Income taxes payable			15,604		19,168
	Deferred income taxes			-		1,144
	Discontinued operations held for sale			-		108,592
	Deferred revenue			42,825		44,951
	Derivatives			12,377		80,997
	Other current liabilities			39,552		36,210

		Total current liabilities		776,117		769,220

Long-term debt				2,587,371		2,601,670
Deferred income taxes				2,133,147		1,751,310
Deferred revenue				46,701		42,069
Derivatives				16,946		56,574
Other liabilities				228,094		232,234
Stockholders' equity				5,196,667		4,226,025

			$	10,985,043	$	9,679,102

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

			Three Months Ended September 30,				Nine Months Ended September 30,
			2011		2010		2011			2010
Revenues and other income:
	Oil and gas		$	610,509	$	437,411	$	1,691,570	$	1,331,498
	Interest and other			17,573		14,969		68,714		49,929
	Derivative gains, net			401,072		127,581		386,118		570,585
	Gain (loss) on disposition of assets, net			1,048		2,383		(1,439)		26,971
	Hurricane activity, net			1,487		3,452		1,418		5,678
				1,031,689		585,796		2,146,381		1,984,661
Costs and expenses:
	Oil and gas production			119,609		100,717		321,995		280,829
	Production and ad valorem taxes			38,542		33,045		107,702		85,444
	Depletion, depreciation and amortization			166,536		147,096		460,807		435,833
	Exploration and abandonments			20,026		21,610		57,583		61,201
	General and administrative			49,812		43,417		138,562		122,165
	Accretion of discount on asset retirement obligations			2,806		2,521		8,119		7,909
	Interest			45,559		45,002		136,554		137,893
	Other			17,183		19,687		49,452		49,826
				460,073		413,095		1,280,774		1,181,100

Income from continuing operations before income taxes				571,616		172,701		865,607		803,561
Income tax provision				(185,471)		(76,211)		(283,016)		(303,438)
Income from continuing operations				386,145		96,490		582,591		500,123
Income (loss) from discontinued operations, net of tax				(547)		18,083		412,511		63,745
Net income				385,598		114,573		995,102		563,868
	Net income attributable to the noncontrolling interests			(34,134)		(2,538)		(49,467)		(39,003)
Net income attributable to common stockholders			$	351,464	$	112,035	$	945,635	$	524,865

Basic earnings per share:
	Income from continuing operations attributable to common stockholders		$	2.96	$	0.80	$	4.51	$	3.92
	Income (loss) from discontinued operations attributable to common
		stockholders		-		0.15		3.49		0.54
	Net income attributable to common stockholders		$	2.96	$	0.95	$	8.00	$	4.46

Diluted earnings per share:
	Income from continuing operations attributable to common stockholders		$	2.95	$	0.79	$	4.42	$	3.89
	Income (loss) from discontinued operations attributable to common
		stockholders		-		0.15		3.43		0.54
	Net income attributable to common stockholders		$	2.95	$	0.94	$	7.85	$	4.43

Weighted average shares outstanding:
	Basic			116,281		115,191		116,122		114,985
	Diluted			117,075		116,021		118,350		115,832

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

							Three Months Ended September 30,				Nine Months Ended September 30,
							2011		2010		2011		2010
Cash flows from operating activities:
	Net income					$	385,598	$	114,573	$	995,102	$	563,868
		Adjustments to reconcile net income to net cash provided by
			operating activities:
				Depletion, depreciation and amortization			166,536		147,096		460,807		435,833
				Exploration expenses, including dry holes			1,733		8,682		6,008		16,655
				Hurricane activity, net			-		-		-		3,500
				Deferred income taxes			173,533		62,931		249,040		283,283
				(Gain) loss on disposition of assets, net			(1,048)		(2,383)		1,439		(26,971)
				Accretion of discount on asset retirement obligations			2,806		2,521		8,119		7,909
				Discontinued operations			(238)		1,877		(407,353)		43,339
				Interest expense			7,980		7,647		23,412		22,567
				Derivative related activity			(326,126)		(107,300)		(269,746)		(549,387)
				Amortization of stock-based compensation			10,370		9,582		31,525		28,631
				Amortization of deferred revenue			(11,330)		(22,669)		(33,620)		(67,739)
				Other noncash items			2,504		9,115		(15,773)		10,440
	Change in operating assets and liabilities:
				Accounts receivable, net			(11,647)		1,497		(35,252)		97,873
				Income taxes receivable			1,362		(6,751)		28,588		16,689
				Inventories			(41,825)		(18,938)		(115,961)		(6,459)
				Prepaid expenses			2,432		1,229		(7,558)		(8,975)
				Other current assets			(252)		9,354		8,520		2,162
				Accounts payable			77,431		11,891		83,632		62,349
				Interest payable			(23,411)		(20,225)		(25,053)		(13,211)
				Income taxes payable			9,678		5,777		(1,807)		1,307
				Other current liabilities			39,498		(6,998)		45,969		(21,941)
					Net cash provided by operating activities		465,584		208,508		1,030,038		901,722
Net cash used in investing activities							(613,001)		(325,829)		(854,853)		(564,202)
Net cash provided by (used in) financing activities							5,561		(2,200)		(75,780)		(286,723)
Net increase (decrease) in cash and cash equivalents							(141,856)		(119,521)		99,405		50,797
Cash and cash equivalents, beginning of period							352,421		197,686		111,160		27,368
Cash and cash equivalents, end of period						$	210,565	$	78,165	$	210,565	$	78,165

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUMMARY PRODUCTION AND PRICE DATA

				Three Months Ended September 30,				Nine Months Ended September 30,
				2011		2010		2011		2010
Average Daily Sales Volumes
	from Continuing Operations:
		Oil (Bbls) -	U.S.		42,245		28,880		37,378		27,388
			South Africa		527		445		556		730
			Worldwide		42,772		29,325		37,934		28,118

		Natural gas liquids ("NGL") (Bbls) -	U.S.		23,212		20,525		21,249		19,649

		Gas (Mcf) -	U.S.		350,687		327,917		337,830		335,960
			South Africa		19,468		31,069		22,384		30,304
			Worldwide		370,155		358,986		360,214		366,264

		Total (BOE) -	U.S.		123,905		104,058		114,932		103,030
			South Africa		3,771		5,623		4,287		5,781
			Worldwide		127,676		109,681		119,219		108,811
Average Reported Prices (a):
		Oil (per Bbl) -	U.S.	$	92.01	$	86.06	$	96.98	$	89.08
			South Africa	$	110.65	$	77.84	$	107.18	$	77.43
			Worldwide	$	92.24	$	85.93	$	97.13	$	88.77

		Natural gas liquids (per Bbl) -	U.S.	$	48.36	$	34.46	$	46.50	$	36.80

		Gas (per Mcf) -	U.S.	$	4.04	$	4.06	$	4.01	$	4.37
			South Africa	$	7.82	$	6.34	$	7.53	$	6.26
			Worldwide	$	4.24	$	4.25	$	4.23	$	4.53

		Total (BOE) -	U.S.	$	51.86	$	43.47	$	51.93	$	44.95
			South Africa	$	55.80	$	41.17	$	53.22	$	42.57
			Worldwide	$	51.97	$	43.35	$	51.97	$	44.82

__________

(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 the three and nine months ended September 30, 2011 and 2010:

		Three Months Ended September 30,				Nine Months Ended September 30,
		2011		2010		2011		2010
		(in thousands)

Net income attributable to common stockholders		$	351,464	$	112,035	$	945,635	$	524,865
	Participating basic earnings		(6,797)		(2,689)		(17,186)		(12,020)
Basic net income attributable to common stockholders			344,667		109,346		928,449		512,845
	Reallocation of participating earnings		189		19		458		127
Diluted net income attributable to common stockholders		$	344,856	$	109,365	$	928,907	$	512,972

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

		Three Months Ended September 30,		Nine Months Ended September 30,
		2011	2010	2011	2010
		(in thousands)

Weighted average common shares outstanding:
	Basic	116,281	115,191	116,122	114,985
	Dilutive common stock options	166	168	181	218
	Contingently issuable performance unit shares	443	662	429	629
	Convertible senior notes dilution	185	-	1,618	-

	Diluted	117,075	116,021	118,350	115,832

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 September 30,				Nine Months Ended September 30,
			2011		2010		2011		2010

Net income		$	385,598	$	114,573	$	995,102	$	563,868
Depletion, depreciation and amortization			166,536		147,096		460,807		435,833
Exploration and abandonments			20,026		21,610		57,583		61,201
Hurricane activity, net			(1,487)		(3,452)		(1,418)		(5,678)
Accretion of discount on asset retirement obligations			2,806		2,521		8,119		7,909
Interest expense			45,559		45,002		136,554		137,893
Income tax provision			185,471		76,211		283,016		303,438
(Gain) loss on disposition of assets, net			(1,048)		(2,383)		1,439		(26,971)
Discontinued operations			547		(18,083)		(412,511)		(63,745)
Derivative related activity			(326,126)		(107,300)		(269,746)		(549,387)
Amortization of stock-based compensation			10,370		9,582		31,525		28,631
Amortization of deferred revenue			(11,330)		(22,669)		(33,620)		(67,739)
Other noncash items			2,504		9,115		(15,773)		10,440

	EBITDAX (a)		479,426		271,823		1,241,077		835,693

Cash interest expense			(37,579)		(37,355)		(113,142)		(115,326)
Current income taxes			(11,938)		(13,280)		(33,976)		(20,155)

	Discretionary cash flow (b)		429,909		221,188		1,093,959		700,212

Cash hurricane activity			1,487		3,452		1,418		9,178
Discontinued operations cash activity			(785)		19,960		5,158		107,084
Cash exploration expense			(18,293)		(12,928)		(51,575)		(44,546)
Changes in operating assets and liabilities			53,266		(23,164)		(18,922)		129,794

	Net cash provided by operating activities	$	465,584	$	208,508	$	1,030,038	$	901,722

__________

(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 SUPPLEMENTARY NON-GAAP FINANCIAL MEASURES (continued)

(in millions, except per share data)

Adjusted income excluding unrealized mark-to-market ("MTM") derivative gains, as presented in this press release, is presented and reconciled to Pioneer's net income attributable to common stockholders that is determined in accordance with GAAP because Pioneer believes that this non-GAAP financial measure reflects an additional way of viewing aspects of Pioneer's business that, when viewed together with its financial results computed in accordance with GAAP, provides 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 this non-GAAP measure may enhance investors' ability to assess Pioneer's historical and future financial performance. This non-GAAP financial measure is not intended to be a substitute for the comparable GAAP measure and should be read only in conjunction with Pioneer's consolidated financial statements prepared in accordance with GAAP. Unrealized MTM derivative gains and losses will recur in future periods; however, the amount and frequency can vary significantly from period to period. The table below reconciles Pioneer's net income attributable to common stockholders for the three months ended September 30, 2011, as determined in accordance with GAAP, to adjusted income excluding unrealized MTM derivative gains for that quarter.

		After-tax Amounts		Diluted Amounts Per Share

Net income attributable to common stockholders		$	351	$	2.95
	Unrealized MTM derivative gains		(191)		(1.60)
Adjusted income excluding unrealized MTM derivative gains		$	160	$	1.35

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Open Commodity Derivative Positions as of October 14, 2011

(Volumes are average daily amounts)

				2011
				Fourth Quarter		2012		2013		2014		2015
Average Daily Oil Production Associated with
Derivatives (Bbls):
	Swap Contracts:
		Volume			750		3,000		3,000		-		-
		NYMEX price (a)		$	77.25	$	79.32	$	81.02	$	-	$	-
	Collar Contracts:
		Volume			2,000		2,000		-		-		-
		NYMEX price:
			Ceiling	$	170.00	$	127.00	$	-	$	-	$	-
			Floor	$	115.00	$	90.00	$	-	$	-	$	-
	Collar Contracts with Short Puts:
		Volume			32,000		36,000		31,000		10,000		-
		NYMEX price:
			Ceiling	$	99.33	$	117.99	$	119.78	$	127.46	$	-
			Floor	$	73.75	$	80.42	$	83.81	$	87.50	$	-
			Short Put	$	59.31	$	65.00	$	66.23	$	72.50	$	-
	Percent of total oil production (b)				~80%		~75%		~50%		~15%		N/A
Average Daily NGL Production Associated with
Derivatives (Bbls):
	Swap Contracts:
		Volume			1,150		750		-		-		-
		Blended index price (c)		$	51.50	$	35.03	$	-	$	-	$	-
	Collar Contracts:
		Volume			2,650		-		-		-		-
		Index price (c):
			Ceiling	$	64.23	$	-	$	-	$	-	$	-
			Floor	$	53.29	$	-	$	-	$	-	$	-
	Collar Contracts with Short Puts:
		Volume			-		3,000		-		-		-
		Index price (c):
			Ceiling	$	-	$	79.99	$	-	$	-	$	-
			Floor	$	-	$	67.70	$	-	$	-	$	-
			Short Put	$	-	$	55.76	$	-	$	-	$	-
	Percent of total NGL production (b)				~15%		~15%		N/A		N/A		N/A
Average Daily Gas Production Associated with
Derivatives (MMBtu):
	Swap Contracts:
		Volume			117,500		105,000		67,500		50,000		-
		NYMEX price (d)		$	6.13	$	5.82	$	6.11	$	6.05	$	-
	Collar Contracts:
		Volume			-		65,000		150,000		140,000		50,000
		NYMEX price (d):
			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		190,000		45,000		60,000		30,000
		NYMEX price (d):
			Ceiling	$	8.55	$	7.96	$	7.49	$	7.80	$	7.11
			Floor	$	6.32	$	6.12	$	6.00	$	5.83	$	5.00
			Short Put	$	4.88	$	4.55	$	4.50	$	4.42	$	4.00
	Percent of total gas production (b)				~85%		~85%		~55%		~45%		~15%
	Basis Swap Contracts:
		Permian Basin Index Swaps volume (e)			20,000		32,500		22,500		25,000		-
		Price differential ($/MMBtu)		$	(0.30)	$	(0.38)	$	(0.28)	$	(0.30)	$	-
		Mid-Continent Index Swaps volume (e)			100,000		50,000		10,000		10,000		-
		Price differential ($/MMBtu)		$	(0.71)	$	(0.53)	$	(0.71)	$	(0.30)	$	-
		Gulf Coast Index Swaps volume (e)			23,500		53,500		40,000		20,000		-
		Price differential ($/MMBtu)		$	(0.16)	$	(0.15)	$	(0.13)	$	(0.14)	$	-

__________

(a)	During October 2011, the Company entered into NYMEX swap contracts on 3,000 Bbls per day of March 2012 through May 2012 forecasted production, whereby the Company receives $0.28 per Bbl and pays the difference between (i) each day's price per Bbl of West Texas Intermediate oil ("WTI") for the first nearby month less (ii) the price per Bbl of WTI for the second nearby NYMEX month, multiplied by .6667; plus (iii) each day's price per Bbl of WTI for the first nearby month less (iv) the price per Bbl of WTI for the third nearby NYMEX month, multiplied by .3333. These crude oil swap contracts,which are not included in the table above, are referred to as "Roll Factor Swaps" and are highly correlated with certain terms of the Company's physical oil sales.
(b)	Represents an estimated percentage of forecasted production, which may differ from the percentage of actual production.
(c)	Represents weighted average index price per Bbl of each NGL component.

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Open Commodity Derivative Positions as of October 14, 2011

(Volumes are average daily amounts)

(d)	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.
(e)	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. The Company has diesel derivative swap contracts for 250 notional Bbls per day for the period from October 2011 through December 2011 at an average per Bbl fixed price of $123.90 and for 2012 at an average per Bbl fixed price of $119.28. 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.

Interest rates. During July 2011, the Company terminated $470 million notional amount of fixed-for-variable interest rate derivative contracts and received $26.1 million of associated cash proceeds. During August 2011, the Company entered into interest rate derivative contracts that lock in, for a period of one year, a fixed forward 10-year annual interest rate of 3.06% on $200 million notional amount of debt.

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

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

(in thousands)

		2011
		Fourth Quarter		2012		Total

Total deferred revenues (a)		$	11,329	$	42,071	$	53,400
Less derivative losses to be recognized in
	pretax earnings (b)		(904)		(3,160)		(4,064)

Total VPP impact to pretax earnings		$	10,425	$	38,911	$	49,336

__________

(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 September 30, 2011 (a)

(in thousands)

	2011
		Fourth Quarter


Commodity hedge gains - oil (b)		$	9,197

__________

(a)	Excludes deferred hedge losses on terminated derivatives related to the VPPs.
(b)	Deferred commodity hedge gains will be realized as an increase to oil revenues during the fourth quarter of 2011.

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Derivative Gains, Net

(in thousands)

				Three Months Ended September 30, 2011		Nine Months Ended September 30, 2011
Noncash changes in fair value:
	Oil derivative gains			$	298,438	$	257,102
	NGL derivative gains				3,982		188
	Gas derivative gains				62,932		45,955
	Diesel derivative losses				(714)		(618)
	Interest rate derivative losses				(37,610)		(30,216)
		Total noncash derivative gains, net (a)			327,028		272,411

Cash settled changes in fair value:
	Oil derivative gains (losses)				5,535		(35,306)
	NGL derivative losses				(4,478)		(11,803)
	Gas derivative gains				41,655		124,455
	Diesel derivative gains				57		57
	Interest rate derivative gains				31,275		36,304
		Total cash derivative losses, net			74,044		113,707
			Total derivative gains, net	$	401,072	$	386,118

__________

(a)	Total unrealized mark-to-market derivative gains, net includes $23.7 million and $20.0 million of gains attributable to noncontrolling interests in consolidated subsidiaries during the three and nine months ended September 30, 2011, respectively.

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