EXHIBIT 99.1

News Release

Pioneer Natural Resources Reports

Third Quarter 2010 Financial and Operating Results

Dallas, Texas, October 26, 2010 -- Pioneer Natural Resources Company (NYSE:PXD) ("Pioneer" or "the Company") today announced financial and operating results for the quarter ended September 30, 2010.

Pioneer reported third quarter net income attributable to common stockholders of $112 million, or $.94 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 $63 million after tax, or $.53 per diluted share.  Without the effect of this item, adjusted income for the third quarter of 2010 would have been $49 million, or $.41 per diluted share.

Also included in Pioneer's third quarter results was a net gain of $7 million after tax, or $.06 per diluted share, related to unusual items.  These unusual items included:

·   Alaska Petroleum Production Tax (PPT) credits of $8 million after tax ($.06 per diluted share),

·   a net hurricane-related insurance recovery of $2 million after tax ($.02 per diluted share), primarily related to reclamation work required at Pioneer's East Cameron 322 Gulf of Mexico property that was destroyed by Hurricane Rita in 2005,

·   income related to discontinued operations in the Gulf of Mexico and Argentina of $1 million after tax ($.01 per diluted share), offset by

·   a $4 million after tax charge ($.03 per diluted share) to reduce the carrying value of unused dry gas well pipe inventory to its estimated net realizable value.

Third quarter and other recent highlights included:

·   producing 114.6 thousand barrels oil equivalent per day (MBOEPD), up 1% from the second quarter of 2010, primarily reflecting continued production growth in the Spraberry field,

·   ramping up Spraberry drilling as planned; currently running 25 rigs and expect to be at 30 rigs by year-end 2010,

·   drilling deeper to the Lower Wolfcamp and Strawn intervals in the Spraberry field, with production results exceeding expectations,

·   ramping up Eagle Ford Shale drilling as planned; currently running seven rigs,

·   continuing to deliver strong initial production rates from recently drilled wells in the Eagle Ford Shale,

·   executing third-party gas processing, fractionation and transportation agreement for Eagle Ford Shale gas and oil production with Enterprise Product Partners L.P.,

·   drilling three successful operated wells in Tunisia, with two additional wells currently drilling and

·   adding attractive oil derivative positions for 2012 and 2013.

Scott Sheffield, Chairman and CEO, stated, "We are executing on our plan to significantly ramp-up drilling in the Spraberry field and the Eagle Ford Shale and to vertically integrate in both fields.  As a result, we continue to expect the Company to deliver compound annual production growth of 15+% over the 2011 through 2013 period.  Cash flow is forecasted to substantially increase from $1.2 billion in 2010 to $2.0 billion in 2013, assuming current NYMEX strip prices and taking into account the Company's attractive oil and gas derivatives position.  We remain committed to spending within cash flow and maintaining our strong financial position."

Operations Update

In the Spraberry field in West Texas, Pioneer's drilling ramp-up continues to be on schedule, with 25 rigs currently operating.  The Company expects to drill approximately 440 wells during 2010 and anticipates increasing the rig count to 30 rigs by year end and to be at 40 rigs in 2012.

As forecasted, this drilling program is generating quarter-to-quarter Spraberry production growth during 2010.  Third quarter production was 35 MBOEPD, up 7% from the second quarter of 2010. The third quarter production level exceeded Pioneer's forecast for the quarter by 1.5 MBOEPD due to better well performance associated with deeper drilling in the field.  Production is expected to increase further to approximately 36 MBOEPD during the fourth quarter of 2010, which is 2 MBOEPD more than the Company's prior forecast for the fourth quarter.  At this level, Pioneer's fourth quarter 2010 production will be 16% more than the fourth quarter of 2009 and will significantly exceed the Company's prior forecast of 10+% over this period.

The 2010 drilling program is adding incremental production and proved reserves from completions in the Lower Wolfcamp, shale/silt and the deeper Strawn intervals.  Initial cumulative five-month production rates from wells drilled to these intervals in 2010 have averaged 30+% higher than the cumulative five-month production rates of a traditional Spraberry/Dean/Upper Wolfcamp well.  Pioneer's internal rate of return on its 2010 Spraberry drilling program has been approximately 50% before tax based on current NYMEX strip commodity prices and estimated future production costs.

The Company has commenced a two-well program to test horizontal drilling in the Wolfcamp interval.  Both wells are expected to be completed by the end of the year.  Water injection was initiated in August on the Company's 7,000-acre waterflood project, with first oil response expected during the first half of 2011.

Based on the planned ramp-up schedule to 40 drilling rigs in 2012 and the incremental production being generated from drilling to deeper intervals, Spraberry field production is expected to at least double from 2010 to 2013, reflecting a compounded annual production growth rate of more than 25%.

As Pioneer ramps up Spraberry field activity, the Company continues to focus on controlling drilling and production costs.  The Company is expanding its integrated services in the Spraberry field and plans to internally provide 30% to 60% of its service requirements by 2012.  A second Company-owned fracture stimulation fleet has recently commenced operating in the field.  Two additional fleets are being built, with one being delivered in the first quarter of 2011 and the second in the second quarter of 2011.  To support its fracture stimulation operations, Pioneer has contracts in place for its forecasted sand needs through 2015.  Frac tank ownership will more than double from 250 tanks currently to 550 tanks by year end.  Tubular requirements have been contracted through 2012, and pumping unit requirements have been contracted through 2011.  In addition, the Company has nine owned drilling rigs currently operating and has recently acquired three additional rigs that will be operational by year end.  Four pulling units are being added, which will bring the total fleet to 23 units by mid-2011.  The Company also has hot oil units, water transport trucks, reverse units and fishing tools to support its growing operations.  Vertical integration is expected to save Pioneer $200 thousand to $300 thousand per well compared to utilizing third-party services.

In the highly prospective Eagle Ford Shale in South Texas, Pioneer has successfully drilled and completed 14 horizontal wells.  Six of the wells are on production, including one which began flowing to sales this month after the startup of Pioneer's first central gathering plant which provides gas processing and condensate stabilization.  The remaining eight wells are expected to be brought online by mid-January following the completion of four additional central gathering plants.  Eight additional wells are awaiting completion and will also be brought online as the four central gathering plants are completed.

The Company's drilling program in the Eagle Ford Shale has continued to deliver strong initial production rates.  Average initial production rates for the eight wells drilled during the June through October period averaged 2 MBOEPD on 24-hour restricted flow tests with an average condensate yield of 120 barrels per million cubic feet, a liquids yield of 55% and an average heat content of 1,220 British thermal units per cubic foot.  The average flowing tubing pressure on these wells was 6,200 pounds per square inch.

Pioneer now has seven rigs running in the play as planned.  Along with the drilling ramp up, drilling efficiency improvements are also being achieved, with drilling times having been reduced by 20% since inception.  Pioneer and its joint venture partners have agreed to a joint venture development plan which will allow the joint venture to maintain its substantial acreage position.  Plans currently call for drilling 70 wells in 2011, 120 wells in 2012 and 140 wells in 2013.

To support the drilling program, Pioneer is purchasing a fracture stimulation fleet that is expected to be in service by the second quarter of 2011 and has entered into a two-year contract for third-party fracture stimulation services beginning in the first quarter of 2011.  The Company has also executed an agreement with Enterprise Products Partners L.P. to process, fractionate and transport gas and oil production.

Based on the joint venture development plan, Pioneer expects to exit 2010 in the Eagle Ford Shale at a net production rate of approximately 5 MBOEPD.  Average annual production in 2011 is expected to grow to a range of 10 MBOEPD to 13 MBOEPD with a further increase to a range of 32 MBOEPD to 41 MBOEPD in 2013.

Pioneer continues to acquire acreage in the liquids-rich Barnett Shale Combo Play, where the Company has more than 48,000 net acres under lease, representing approximately 500 drilling locations.  The Company has commenced drilling in the play with one rig.  The Company has acquired 70 square miles of 3-D seismic covering its acreage and expects to increase this coverage to 150 square miles by year end.  Assuming current NYMEX strip commodity prices, a drilling cost of $2.8 million and a gross estimated ultimate recovery (EUR) of 320 thousand barrels oil equivalent (BOE), Pioneer's internal rate of return in the Barnett Shale Combo Play is expected to be approximately 45% before tax. The Company is also participating in six non-operated wells in the Barnett Shale during 2010.

On the North Slope of Alaska, Pioneer drilled one Nuiqsut well during the third quarter to test the production capability of a dual lateral.  The well tested at a rate of 1,900 barrels oil per day (MBOPD) and is now producing to sales.  Pioneer plans to drill two additional Nuiqsut dual lateral wells and one Kuparuk well during the fourth quarter.  Further testing of the Moraine zone will begin during the first quarter of 2011.  Production in Alaska was 7 MBOPD during the third quarter, essentially flat compared to the second quarter, as unplanned maintenance and outages on the Trans Alaska Pipeline offset production increases from new wells.

In the Mid-Continent area (Panhandle of Texas and western Kansas), third quarter 2010 production was 21 MBOEPD, essentially flat compared to the second quarter of 2010.  In the Raton Basin (southeastern Colorado) and the Edwards Trend (South Texas), where gas drilling has been curtailed since the beginning of 2009 due to low gas prices, third quarter 2010 production was 169 million cubic feet per day (MMCFPD) and 51 MMCFPD, respectively.  These rates were essentially flat with production in the second quarter of 2010.

In Tunisia, production for the third quarter was 5 MBOEPD, essentially the same as the second quarter.  During the second and third quarters, Pioneer drilled three successful operated wells identified from new 3-D seismic reprocessing in its Cherouq and Anaguid concessions.  The wells tested at a combined gross production rate of 10 MBOEPD.  Production from all three wells is expected to be flowing to sales in early 2011.  Based on the successful results of these three wells, Pioneer will drill two additional appraisal wells during the fourth

quarter.  Pioneer anticipates that after drilling and completing these two wells, the Company's net production from Tunisia will be in the range of 8 MBOEPD to 9 MBOEPD by early 2011.

In South Africa, third quarter production was 5.6 MBOEPD, essentially flat with the second quarter of 2010.

2010 Capital Expenditures

Pioneer's capital program for 2010 (including midstream investments) continues to be forecasted to total $1.2 billion.  Drilling capital (excluding asset retirement obligations, capitalized interest and G&G G&A) is forecast at $960 million and is focused on oil drilling.  This includes 440 Spraberry wells ($580 million), 35 wells in the Eagle Ford Shale ($100 million, including the benefit of the drilling carry paid or to be paid by Reliance in accordance with the joint venture agreement), one rig in Alaska ($120 million), eight wells in Tunisia ($65 million, including five operated and three non-operated wells), one rig in the liquids-rich areas of the Barnett Shale Combo Play and other drilling-related activities across Pioneer's other assets ($45 million).  Land capital is forecasted at $150 million to add acreage in the Eagle Ford Shale, the liquids-rich areas of the Barnett Shale and the Spraberry field.  Another $50 million will be spent on midstream facility development activity in the Eagle Ford Shale.  Dry gas drilling continues to be curtailed.

Operating cash flow to fund this capital spending is forecasted to be $1.2 billion, assuming current NYMEX strip commodity prices and including the receipt earlier this year of a refund of past royalty overpayments plus interest totaling $155 million from the Minerals Management Service (now the Bureau of Ocean Energy Management, Regulation and Enforcement).  The operating cash flow of $1.2 billion excludes the upfront cash payment of $266 million received from Reliance related to the Eagle Ford Shale joint venture transaction.

Third Quarter 2010 Financial Review

Third quarter sales from continuing operations averaged 114.6 MBOEPD, consisting of oil sales averaging 33.7 MBOPD, natural gas liquids (NGL) sales averaging 20.5 thousand barrels per day and gas sales averaging 362 MMCFPD.

The average reported third quarter price for oil was $84.71 per barrel and included $7.31 per barrel related to deferred revenue from volumetric production payments (VPPs) for which production was not recorded.  The average reported price for NGLs was $34.46 per barrel.  The average reported price for gas was $4.31 per thousand cubic feet.

Third quarter production costs averaged $13.03 per BOE and were higher than the second quarter of 2010 by $1.15 per BOE.  This increase was primarily due to production tax refunds received in the second quarter and more workover activities during the third quarter.

Depreciation, depletion and amortization (DD&A) expense averaged $14.50 per BOE for the third quarter. Exploration and abandonment costs were $23 million for the quarter and included $9 million of acreage abandonments and $14 million of geologic and geophysical expenses and personnel costs.

Cash flow from operating activities for the third quarter was $209 million.

Fourth Quarter 2010 Financial Outlook

The following paragraphs provide the Company's fourth quarter of 2010 outlook for certain operating and financial items.

Production is forecasted to average 115 MBOEPD to 120 MBOEPD, reflecting planned drilling activity and the oil lifting schedule for Tunisia.

Production costs are expected to average $11.75 to $13.75 per BOE, based on current NYMEX strip commodity prices.  DD&A expense is expected to average $14.25 to $15.50 per BOE.

Total exploration and abandonment expense is forecasted to be $35 million to $45 million, primarily related to exploration wells, including related acreage costs, and seismic and personnel costs.

General and administrative expense is expected to be $43 million to $47 million, interest expense is expected to be $44 million to $47 million, and other expense is expected to be $15 million to $20 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 mark-to-market adjustments, is expected to be $9 million to $12 million, primarily reflecting the public ownership in Pioneer Southwest Energy Partners L.P.

The Company's effective income tax rate is expected to range from 40% to 50% based on current capital spending plans, higher tax rates in Tunisia and the assumption of no significant unrealized mark-to-market changes in the Company's derivative position.  Cash taxes are expected to be $15 million to $25 million and are primarily attributable to Tunisia and South Africa.

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

Earnings Conference Call

On October 27, 2010, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended September 30, 2010, 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 (888) 554-1429 confirmation code: 4755364 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 17 by dialing (888) 203-1112 confirmation code: 4755364.

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, international operations and associated international political and economic instability, 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, and acts of war or terrorism. Sensitivity price cases for proved reserves mentioned in this presentation may not be attained or sustained. 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 presentation, Pioneer includes estimates of quantities of oil and gas using certain terms, such as "resource potential," "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

Nolan Badders – 972-969-3955

Brian Hansen – 972-969-4017

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, 2010		December 31, 2009
ASSETS
Current assets:
	Cash and cash equivalents			$	78,165	$	27,368
	Accounts receivable, net				211,716		331,748
	Income taxes receivable				8,333		25,022
	Inventories				182,238		139,177
	Prepaid expenses				17,868		9,011
	Deferred income taxes				-		26,857
	Derivatives				189,635		48,713
	Other current assets, net				1,521		8,222
		Total current assets			689,476		616,118
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting					10,979,208		10,512,904
Accumulated depletion, depreciation and amortization					(3,312,709)		(2,946,048)
			Total property, plant and equipment		7,666,499		7,566,856
Deferred income taxes					15,045		387
Goodwill					298,413		309,259
Derivatives					210,823		43,631
Other assets, net					416,864		331,014
				$	9,297,120	$	8,867,265
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
	Accounts payable			$	363,794	$	253,583
	Interest payable				33,798		47,009
	Income taxes payable				18,718		17,411
	Deferred income taxes				52,043		128
	Deferred revenue				56,097		90,215
	Derivatives				34,730		116,015
	Other current liabilities				37,041		46,830
		Total current liabilities			596,221		571,191
Long-term debt					2,539,416		2,761,011
Deferred income taxes					1,694,575		1,470,899
Deferred revenue					53,400		87,021
Derivatives					31,477		133,645
Other liabilities					224,193		200,467
Stockholders' equity					4,157,838		3,643,031
				$	9,297,120	$	8,867,265

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,
		2010		2009		2010			2009
Revenues and other income:
	Oil and gas	$	471,372	$	409,969	$	1,441,310	$	1,148,512
	Interest and other		11,864		503		51,930		99,761
	Derivative gains (losses), net		127,581		(15,222)		570,585		(85,583)
	Gain (loss) on disposition of assets, net		2,383		(385)		26,971		(447)
	Hurricane activity, net		3,452		(1,830)		5,678		(18,280)
			616,652		393,035		2,096,474		1,143,963
Costs and expenses:
	Oil and gas production		104,339		90,394		291,348		285,617
	Production and ad valorem taxes		33,045		28,089		85,444		79,503
	Depletion, depreciation and  amortization		152,838		162,605		453,920		509,422
	Impairment of oil and gas properties		-		-		-		21,091
	Exploration and abandonments		22,963		25,073		70,883		77,861
	General and administrative		44,759		34,799		128,081		102,728
	Accretion of discount on asset retirement obligations		2,626		2,754		8,218		8,259
	Interest		45,002		43,438		137,893		128,051
	Other		20,927		21,363		52,228		89,467
			426,499		408,515		1,228,015		1,301,999
Income (loss) from continuing operations before income taxes			190,153		(15,480)		868,459		(158,036)
Income tax benefit (provision)			(76,661)		5,206		(331,828)		47,671
Income (loss) from continuing operations			113,492		(10,274)		536,631		(110,365)
Income from discontinued operations, net of tax			1,082		12,107		27,238		13,868
Net income (loss)			114,574		1,833		563,869		(96,497)
	Net income attributable to the noncontrolling interests		(2,538)		(8,998)		(39,003)		(12,269)
Net income (loss) attributable to common stockholders		$	112,036	$	(7,165)	$	524,866	$	(108,766)
Basic earnings per share:
	Income (loss) from continuing operations attributable to common stockholders	$	0.94	$	(0.17)	$	4.23	$	(1.07)
	Income from discontinued operations attributable to common stockholders		0.01		0.11		0.23		0.12
	Net income (loss) attributable to common stockholders	$	0.95	$	(0.06)	$	4.46	$	(0.95)
Diluted earnings per share:
	Income (loss) from continuing operations attributable to common stockholders	$	0.93	$	(0.17)	$	4.20	$	(1.07)
	Income from discontinued operations attributable to common stockholders		0.01		0.11		0.23		0.12
	Net income (loss) attributable to common stockholders	$	0.94	$	(0.06)	$	4.43	$	(0.95)
Weighted average shares outstanding:
	Basic		115,191		114,123		114,985		114,118
	Diluted		116,021		114,123		115,832		114,118

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

						Three Months Ended September 30,				Nine Months Ended September 30,
						2010		2009		2010		2009
Cash flows from operating activities:
	Net income (loss)				$	114,574	$	1,833	$	563,869	$	(96,497)
	Adjustments to reconcile net income (loss) to net cash provided by
		operating activities:
			Depletion, depreciation and amortization			152,838		162,605		453,920		509,422
			Impairment of oil and gas properties			-		-		-		21,091
			Exploration expenses, including dry holes			8,714		12,745		16,771		40,699
			Hurricane activity, net			-		1,200		3,500		16,200
			Deferred income taxes			57,251		(17,456)		300,303		(67,397)
			(Gain) loss on disposition of assets, net			(2,383)		385		(26,971)		447
			Accretion of discount on asset retirement obligations			2,626		2,754		8,218		8,259
			Discontinued operations			(2,594)		(10,581)		8,626		(5,373)
			Interest expense			7,647		7,165		22,567		20,694
			Derivative related activity			(107,300)		70		(549,387)		48,305
			Amortization of stock-based compensation			9,582		10,096		28,631		29,319
			Amortization of deferred revenue			(22,669)		(37,206)		(67,739)		(110,901)
			Other noncash items			13,386		5,824		9,620		30,664
	Change in operating assets and liabilities
			Accounts receivable, net			1,497		17,133		97,873		71,074
			Income taxes receivable			(6,751)		12,966		16,689		44,762
			Inventories			(18,938)		5,620		(6,459)		(52,069)
			Prepaid expenses			1,229		7,287		(8,975)		(6,900)
			Other current assets			9,354		31,612		2,162		98,532
			Accounts payable			11,891		13,150		62,349		(94,238)
			Interest payable			(20,225)		(14,867)		(13,211)		(14,766)
			Income taxes payable			5,777		(4,790)		1,307		9,127
			Other current liabilities			(6,998)		(45,048)		(21,941)		(89,629)
				Net cash provided by operating activities		208,508		162,497		901,722		410,825
Net cash used in investing activities						(325,829)		(53,184)		(564,202)		(312,991)
Net cash used in financing activities						(2,200)		(118,021)		(286,723)		(90,556)
Net increase (decrease) in cash and cash equivalents						(119,521)		(8,708)		50,797		7,278
Cash and cash equivalents, beginning of period						197,686		64,323		27,368		48,337
Cash and cash equivalents, end of period					$	78,165	$	55,615	$	78,165	$	55,615

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUMMARY PRODUCTION AND PRICE DATA

				Three Months Ended September 30,				Nine Months Ended September 30,
				2010		2009		2010		2009
Average Daily Sales Volumes
	from Continuing Operations:
		Oil (Bbls) -	U.S.		28,880		24,754		27,388		24,989
			South Africa		445		575		730		401
			Tunisia		4,409		6,334		4,845		6,612
			Worldwide		33,734		31,663		32,963		32,002
		Natural gas liquids (Bbls) -	U.S.		20,525		18,602		19,649		20,044
		Gas (Mcf) -	U.S.		327,917		341,874		335,960		360,896
			South Africa		31,069		31,372		30,304		31,637
			Tunisia		2,760		904		2,711		1,662
			Worldwide		361,746		374,150		368,975		394,195
		Total (BOE) -	U.S.		104,058		100,335		103,030		105,182
			South Africa		5,623		5,803		5,781		5,674
			Tunisia		4,869		6,485		5,297		6,890
			Worldwide		114,550		112,623		114,108		117,746
Average Reported Prices (a):
		Oil (per Bbl) -	U.S.	$	86.06	$	81.57	$	89.08	$	70.13
			South Africa	$	77.84	$	70.30	$	77.43	$	63.08
			Tunisia	$	76.54	$	65.76	$	76.72	$	56.83
			Worldwide	$	84.71	$	78.20	$	87.00	$	67.29
		Natural gas liquids (per Bbl) -	U.S.	$	34.46	$	33.13	$	36.80	$	27.33
		Gas (per Mcf) -	U.S.	$	4.06	$	3.42	$	4.37	$	3.69
			South Africa	$	6.34	$	5.93	$	6.26	$	5.08
			Tunisia	$	11.50	$	9.35	$	11.27	$	7.22
			Worldwide	$	4.31	$	3.64	$	4.58	$	3.82
		Total (BOE) -	U.S.	$	43.46	$	37.92	$	44.95	$	34.54
			South Africa	$	41.17	$	39.03	$	42.57	$	32.80
			Tunisia	$	75.83	$	65.54	$	75.94	$	56.28
			Worldwide	$	44.73	$	39.57	$	46.27	$	35.73

__________

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

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED 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 (loss) per share attributable to common stockholders is computed as (i) net income (loss) 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 (loss) per share attributable to common stockholders is computed as (i) basic net income (loss) attributable to common stockholders, (ii) plus adjustments to participating undistributed 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 not be dilutive to loss per share and conversion into common stock is assumed not to occur.

The following table is a reconciliation of the Company's net income (loss) attributable to common stockholders to basic net income (loss) attributable to common stockholders and to diluted net income (loss) attributable to common stockholders for thethree and nine months ended September 30, 2010 and 2009:

		Three Months Ended September 30,				Nine Months Ended September 30,
		2010		2009		2010		2009
		(in thousands)
Net income (loss) attributable to common stockholders		$	112,036	$	(7,165)	$	524,866	$	(108,766)
	Participating basic distributed earnings		(18)		-		(125)		(94)
	Participating basic undistributed earnings		(2,672)		-		(11,895)		-
Basic net income (loss) attributable to common stockholders			109,346		(7,165)		512,846		(108,860)
	Diluted adjustments to share- and unit-based earnings		19		-		128		-
Diluted net income (loss) attributable to common
	stockholders	$	109,365	$	(7,165)	$	512,974	$	(108,860)

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, 2010 and 2009:

		Three Months Ended September 30,		Nine Months Ended September 30,
		2010	2009	2010	2009
		(in thousands)
Weighted average common shares outstanding:
	Basic	115,191	114,123	114,985	114,118
	Dilutive common stock options	168	-	218	-
	Contingently issuable - performance shares	662	-	629	-
	Diluted	116,021	114,123	115,832	114,118

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY NON-GAAP FINANCIAL MEASURES

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

			Three Months Ended September 30,				Nine Months Ended September 30,
			2010		2009		2010		2009
Net income (loss)		$	114,574	$	1,833	$	563,869	$	(96,497)
Depletion, depreciation and amortization			152,838		162,605		453,920		509,422
Impairment of oil and gas properties			-		-		-		21,091
Exploration and abandonments			22,963		25,073		70,883		77,861
Hurricane activity, net			(3,452)		1,830		(5,678)		18,280
Accretion of discount on asset retirement obligations			2,626		2,754		8,218		8,259
Interest expense			45,002		43,438		137,893		128,051
Income tax (benefit) provision			76,661		(5,206)		331,828		(47,671)
(Gain) loss on disposition of assets, net			(2,383)		385		(26,971)		447
Discontinued operations			(1,082)		(12,107)		(27,238)		(13,868)
Derivative related activity			(107,300)		70		(549,387)		48,305
Amortization of stock-based compensation			9,582		10,096		28,631		29,319
Amortization of deferred revenue			(22,669)		(37,206)		(67,739)		(110,901)
Other noncash items			13,386		5,824		9,620		30,664
	EBITDAX (a)		300,746		199,389		927,849		602,762
Cash interest expense			(37,355)		(36,273)		(115,326)		(107,357)
Current income taxes			(19,410)		(12,250)		(31,525)		(19,726)
	Discretionary cash flow (b)		243,981		150,866		780,998		475,679
Cash hurricane activity			3,452		(630)		9,178		(2,080)
Discontinued operations cash activity			(1,512)		1,526		35,864		8,495
Cash exploration expense			(14,249)		(12,328)		(54,112)		(37,162)
Changes in operating assets and liabilities			(23,164)		23,063		129,794		(34,107)
	Net cash provided by operating activities	$	208,508	$	162,497	$	901,722	$	410,825

__________

(a)

“EBITDAX” represents earnings before depletion, depreciation and amortization expense; impairment of oil and gas properties; 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)

Income adjusted for unrealized mark-to-market derivative gains, and income adjusted for unrealized mark-to-market 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 mark-to-market net derivative gains, impairment of dry gas well pipe inventory, Alaskan Petroleum Production Tax credits, net hurricane related credits 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 September 30, 2010, as determined in accordance with GAAP, to income adjusted for unrealized mark-to-market derivative gains, and income adjusted for unrealized mark-to-market derivative gains and unusual items, for that quarter.

		After-tax Amounts		Diluted Amounts Per Share
Net income attributable to common stockholders		$	112	$	0.94
	Unrealized mark-to-market derivative gains, net ($94 pretax)		(63)		(0.53)
Income adjusted for unrealized mark-to-market derivative gains			49		0.41
	Impairment of dry gas well pipe inventory ($6 pretax)		4		0.03
	Petroleum production tax credit income ($12 pretax)		(8)		(0.06)
	Hurricane related credits, net ($3 pretax)		(2)		(0.02)
	Discontinued operations income ($2 pretax)		(1)		(0.01)
Income as adjusted for unrealized mark-to-market derivative gains and unusual items		$	42	$	0.35

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Open Commodity Derivative Positions as of October 25, 2010

(Volumes are average daily amounts)

				2010
				Fourth Quarter		2011		2012		2013		2014
Oil Derivatives (BBLs):
	Swap Contracts:
		Volume			2,500		750		3,000		3,000		-
		NYMEX price		$	93.34	$	77.25	$	79.32	$	81.02	$	-
	Collar Contracts:
		Volume			-		2,000		-		-		-
		NYMEX price:
			Ceiling	$	-	$	170.00	$	-	$	-	$	-
			Floor	$	-	$	115.00	$	-	$	-	$	-
	Collar Contracts with Short Puts:
		Volume			30,250		32,000		37,000		21,250		-
		Price (a):
			Ceiling	$	85.09	$	99.33	$	118.34	$	117.38	$	-
			Floor	$	68.38	$	73.75	$	80.41	$	80.18	$	-
			Short Put	$	55.23	$	59.31	$	65.00	$	65.18	$	-
	Percent of total oil production (b)				~90%		~80%		~85%		~40%		N/A
NGL Derivatives (BBLs):
	Swap Contracts:
		Volume			1,650		750		750		-		-
		Blended index price (c)		$	40.85	$	34.65	$	35.03	$	-	$	-
	Collar Contracts:
		Volume			2,000		1,000		-		-		-
		Index price (c):
			Ceiling	$	49.98	$	50.93	$	-	$	-	$	-
			Floor	$	41.58	$	42.21	$	-	$	-	$	-
	Collar Contracts with Short Puts:
		Volume			2,000		-		-		-		-
		Index price (c):
			Ceiling	$	58.92	$	-	$	-	$	-	$	-
			Floor	$	47.64	$	-	$	-	$	-	$	-
			Short Put	$	38.71	$	-	$	-	$	-	$	-
	Percent of total NGL production (b)				~25%		~5%		<5%		N/A		N/A
Gas Derivatives (MMBtu):
		Swap Contracts:
		Volume			167,500		117,500		105,000		67,500		50,000
		NYMEX price (d)		$	6.26	$	6.13	$	5.82	$	6.11	$	6.05
	Collar Contracts:
		Volume			40,000		-		65,000		100,000		20,000
		NYMEX price (d):
			Ceiling	$	7.19	$	-	$	6.60	$	6.50	$	7.20
			Floor	$	5.75	$	-	$	5.00	$	5.00	$	5.00
	Collar Contracts with Short Puts:
		Volume			95,000		200,000		190,000		45,000		50,000
		NYMEX price (d):
			Ceiling	$	7.94	$	8.55	$	7.96	$	7.49	$	8.08
			Floor	$	6.00	$	6.32	$	6.12	$	6.00	$	6.00
			Short Put	$	5.00	$	4.88	$	4.55	$	4.50	$	4.50
	Percent of total U.S. gas production (b)				~90%		~90%		~85%		~45%		~25%
	Basis Swap Contracts:
		Permian Basin Index Swaps volume - (e)			20,054		10,000		32,500		2,500		-
		Price differential ($/MMBtu)		$	(0.33)	$	(0.31)	$	(0.38)	$	(0.31)	$	-
		Mid-Continent Index Swaps volume - (e)			183,370		100,000		40,000		10,000		-
		Price differential ($/MMBtu)		$	(0.84)	$	(0.71)	$	(0.58)	$	(0.71)	$	-
		Gulf Coast Index Swaps volume - (e)			41,685		23,500		43,500		20,000		10,000
		Price differential ($/MMBtu)		$	(0.22)	$	(0.16)	$	(0.16)	$	(0.16)	$	(0.16)

__________

(a)	Represents NYMEX and Dated Brent average prices of U.S. and foreign production.
(b)	Represents an estimated percentage of forecasted production, which may differ from the percentage of actual production.
(c)	Represents the blended Mont Belvieu index price or respective NGL component prices per Bbl.
(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 indices at which the Company sells its Permian Basin, Mid-Continent and Gulf Coast gas and NYMEX Henry Hub index prices.

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Amortization of Deferred Revenue Associated with Volumetric Production Payments and Net Derivative

Losses as of September 30, 2010

(in thousands)

		2010
		Fourth Quarter		2011		2012		Total
Total deferred revenues (a)		$	22,475	$	44,951	$	42,071	$	109,497
Less derivative losses to be recognized in
	pretax earnings (b)		(538)		(3,571)		(3,159)		(7,268)
Total VPP impact to pretax earnings		$	21,937	$	41,380	$	38,912	$	102,229

__________

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

Deferred Gains on Discontinued and Terminated Commodity Hedges as of September 30, 2010 (a)

(in thousands)

		2010
		Fourth Quarter		2011
Commodity hedge gains (b):
	Oil	$	19,178	$	36,489
	NGL		1,840		-
	Gas		931		-
		$	21,949	$	36,489

__________

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

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Derivative Gains, Net

(in thousands)

				Three Months Ended September 30, 2010		Nine Months Ended September 30, 2010
Unrealized mark-to-market changes in fair value:
	Oil derivative gains (losses)			$	(64,788)	$	120,808
	NGL derivative gains (losses)				(7,130)		14,073
	Gas derivative gains				151,770		324,608
	Interest rate derivative gains				13,881		47,419
		Total unrealized mark-to-market derivative gains, net (a)			93,733		506,908
Cash settled changes in fair value:
	Oil derivative losses				(360)		(12,428)
	NGL derivative losses				(565)		(4,417)
	Gas derivative gains				33,806		77,842
	Interest rate derivative gains				967		2,680
		Total cash derivative gains, net			33,848		63,677
			Total derivative gains, net	$	127,581	$	570,585

__________

(a) Total unrealized mark-to-market derivative gains, net includes $6.4 million of losses and $12.1 million of gains attributable to noncontrolling interests in consolidated subsidiaries during the three and nine month periods ending September 30, 2010, respectively.