EXHIBIT 99.1

News Release

Pioneer Natural Resources Reports

Third Quarter 2012 Financial and Operating Results

Dallas, Texas, October 31, 2012 -- Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today announced financial and operating results for the quarter ended September 30, 2012.

Pioneer reported third quarter net income attributable to common stockholders of $19 million, or $0.15 per diluted share (see attached schedule for a description of the net income per diluted share calculation). Without the effect of noncash derivative mark-to-market losses and other unusual items, adjusted income for the third quarter was $104 million after tax, or $0.82 per share.

Third quarter and other recent highlights included:

• producing 159.9 thousand barrels oil equivalent per day (MBOEPD), which is above the top end of the Company's third-quarter guidance range of 155 MBOEPD to 159 MBOEPD (these third quarter production volumes include 6.9 MBOEPD from Pioneer's Barnett Shale properties since production from these properties was included in Pioneer's third quarter guidance range; the Barnett Shale properties were reclassified to discontinued operations during the third quarter as a result of the Company's decision to divest of these properties),

• producing 153.0 MBOEPD from continuing operations (excludes Barnett Shale and South Africa production, which is reflected in discontinued operations), an increase from the second quarter of 2012 of 10 MBOEPD, or 7%, and 33 MBOEPD, or 28%, from the third quarter of 2011 as a result of continued strong production growth in the Company's Spraberry vertical, horizontal Wolfcamp Shale and Eagle Ford Shale areas,

• continuing to deliver strong well performance from deeper vertical drilling to the Strawn, Atoka and Mississippian intervals,

• achieving record production levels in the Eagle Ford Shale as a result of continued strong well performance,

• narrowing Pioneer's 2012 production growth guidance range from 25% to 29% to 27% to 28% based on year-to-date results,

• continuing to drill successful horizontal Wolfcamp Shale wells, with well performance in the Company's southern 200,000 acres of the play meeting type curve expectations,

• beginning to drill delineation wells in the Company's northern acreage of the horizontal Wolfcamp Shale play,

• progressing data room activities to pursue a joint venture partner to accelerate development of the horizontal Wolfcamp Shale play in the southern 200,000 acres of Pioneer's total prospective acreage position,

• increasing the 2012 drilling budget by $100 million primarily to accelerate horizontal Wolfcamp Shale appraisal activity,

• drilling two successful Jo Mill interval horizontal wells in the Spraberry field,

• opening a data room to progress the planned divestiture of the Company's Barnett Shale properties, which will allow the reallocation of capital to the higher-return Spraberry vertical, horizontal Wolfcamp Shale and Eagle Ford Shale areas,

• adding oil derivative positions for 2013 through 2015 and gas derivative positions for 2014 through 2015,

• expecting the Company to exercise its right to call the convertible senior notes due 2038 for redemption early in 2013 (based on the September 30^th closing stock price of $104.40, conversion of the notes would result in paying $480 million cash and issuing approximately 3.3 million shares) and

• recognizing that the Company's oil production will increase by 3,500 barrels oil per day (BOPD) at the end of 2012 with the expiration of the final Spraberry volumetric production payment (VPP) commitment.

Scott Sheffield, Chairman and CEO, stated, “Our Spraberry vertical and Eagle Ford Shale plays continued to exceed production growth expectations in the third quarter. Our drilling results from the horizontal Wolfcamp Shale play are also continuing to meet expectations, and we expect this asset to significantly contribute to our production growth going forward. Our joint venture data room for the southern 200,000 acres of the play has been very active, and the data room for the Barnett Shale divestiture has just opened. We were also able to begin drilling horizontal wells on our northern acreage earlier than anticipated to appraise the potential of the horizontal Wolfcamp Shale in this area.”

Mark-To-Market Derivative Losses and Unusual Items Included in Third Quarter 2012 Earnings

Pioneer's third quarter earnings included unrealized mark-to-market losses on derivatives of $146 million after tax, or $1.19 per diluted share.

Third quarter earnings also included income of $61 million after tax, or $0.52 per diluted share, related to unusual items. These unusual items included:

• a net gain of $28 million after tax, or $0.23 per diluted share, for 2014 and 2015 gas derivatives and interest rate swaps that were liquidated during the third quarter,

• income of $32 million after tax, or $0.26 per diluted share, associated with the sale of Pioneer's South Africa properties (recorded in discontinued operations),

• other small items that net to income of $1 million after tax, with a nominal per diluted share impact and

• a $0.03 per diluted share impact of excluding four million incremental dilutive shares in computing adjusted income per share that, in accordance with GAAP, were not included in the net income per diluted share computation because the Company reported a net loss from continuing operations for the third quarter of 2012.

Operations Update and Drilling Program

Pioneer is the largest acreage holder in the horizontal Wolfcamp Shale play where the Company believes it has significant resource potential based on its extensive geologic data covering the Wolfcamp A, B, C and D intervals and its successful drilling results to date as described below.

Drilling is currently focused primarily in the southern 200,000 acres of Pioneer's leasehold in the play (Upton, Reagan and Irion counties) where the Company expects to drill 90 wells by the end of 2013 to hold expiring acreage totaling 50,000 acres. Thirty to thirty-five of these wells are targeted to be drilled in 2012. Twenty-seven wells have been drilled to date, with 17 wells placed on production.

Of the 17 wells placed on production, two wells are located in northern Upton county in the Giddings Estate area, and 15 wells are located further south in Upton and Reagan counties in the University Lands area.

Pioneer's first two successful horizontal Wolfcamp Shale wells were drilled in northern Upton County in the Upper B interval in the Giddings Estate area. The first well had its one-year anniversary from first production in mid-October and has produced 135 thousand barrels oil equivalent (MBOE) to date. The second well has been on production for ten months and has delivered cumulative production of 105 MBOE.

For perspective, a typical vertical well drilled to the Wolfcamp interval generally takes 40 years to 50 years to produce 140 MBOE.

Of the 15 wells in the University Lands area, 13 wells were drilled in the Upper B interval and two were drilled in the A interval. Eight of the Upper B wells and the two A interval wells were placed on production in the third quarter.

The eight Upper B wells placed on production in the third quarter had initial 24-hour production rates ranging from 312 barrels oil equivalent per day (BOEPD) to 759 BOEPD. These wells were drilled to depths ranging from 7,745 feet to 8,352 feet and have stimulated lateral lengths ranging from 5,892 feet to 7,142 feet. The wells have oil content ranging from 80% to 91%.

Earlier this year, based on strong production results and extensive petrophysical analysis, Pioneer increased its estimated ultimate recovery (EUR) to 575 MBOE for wells drilled in the Upper B interval in southern Upton, Reagan and Irion counties, with a stimulated lateral length of 7,000 feet. Average production from the 15 Upper B interval wells drilled to date normalized to a 7,000-foot lateral length, except for one well that had a mechanical failure, is consistent with the Company's 575 MBOE type curve.

The two A interval wells were placed on production during the third quarter, drilled to depths of 7,483 feet and 7,586 feet, with lateral lengths of 6,902 feet and 6,422 feet. One was successful and had an initial production rate of 585 BOEPD, of which 85% was oil. The other was drilled through a fault due to 3-D seismic not being available at the time the well was drilled. The fracture stimulation was not effective on this well and it had an initial production rate of 156 BOEPD, of which 70% was oil. Two additional A interval wells have been drilled and are awaiting completion. Pioneer has also drilled its first Wolfcamp Lower B interval well which is also awaiting completion.

In the Spraberry interval, Pioneer drilled two highly successful horizontal Jo Mill wells with lateral lengths of 2,628 feet and 2,178 feet. Current 24-hour production rates are 554 BOEPD and 308 BOEPD, with oil content greater than 80%. The Company plans drilling additional horizontal Jo Mill wells in the future, likely with significantly longer laterals.

Pioneer currently has four horizontal rigs running in the southern 200,000 acres of the play and plans to add three rigs in this area late in the fourth quarter of 2012 or early in the first quarter of 2013. During the third quarter, Pioneer added a fifth horizontal rig to accelerate the delineation of the Company's northern portion of its Spraberry acreage position in Midland, Martin and Gaines Counties. Pioneer continues to believe a successful drilling program in this area could substantially increase its prospective horizontal Wolfcamp Shale acreage position.

In order to better delineate the Wolfcamp intervals, a high percentage of the horizontal wells drilled to date have been drilled and completed with extra “science,” including coring, extensive logging and micro-seismic, resulting in well costs of $9 million to $10 million per well. Pioneer began drilling “development” wells in the third quarter and is targeting to lower its well cost to $7 million per well for a 7,000-foot stimulated lateral with 35 to 40 fracture stimulation stages. This will include the utilization of Brady Brown^® sand produced by the U.S. industrial sands business acquired by Pioneer in early April. Pioneer is currently targeting 7,000-foot or longer laterals on most of its horizontal wells. The Company recently drilled its first 10,000-foot lateral in 19 days.

Pioneer has a data room underway to pursue a joint venture partner to accelerate the development of the horizontal Wolfcamp Shale in the southern 200,000 acres of the Company's total prospective acreage position. Pioneer is offering 33% to 50% of its working interest in the southern acreage. The acreage position being offered is estimated to have more than 4,000 potential horizontal development locations, with downspacing upside, and a total gross resource potential of more than two billion barrels oil equivalent. Wells in this area are expected to have liquids content of approximately 90% and EURs of 575 MBOE for 7,000-foot laterals.

Pioneer had originally planned to reduce the vertical drilling program in the Spraberry field from 40 rigs to 27 to 30 rigs during the second half of 2012 as the Company increased its horizontal rig count in the Wolfcamp Shale play. However, the Company has reduced its vertical rig count to 25 rigs in response to the earlier-than-anticipated increase to five horizontal Wolfcamp Shale rigs.

The Company continues to drill vertically to deeper intervals in the Spraberry field below the Wolfcamp interval (vertical Wolfcamp 40-acre type curve EUR of 140 MBOE with typical 24-hour initial production (“IP”) rate of 90 BOEPD). Production from this deeper drilling has exceeded expectations and is the primary contributor to the production outperformance by this asset over the first nine months of 2012. The deeper drilling includes the Strawn, Atoka and Mississippian intervals. The original 2012 drilling program called for the Wolfcamp to be the deepest interval completed in approximately 50% of the wells, with the remaining 50% of the wells to be drilled deeper to intervals below the Wolfcamp interval. The latest drilling program now calls for 65% of the wells to be deepened below the Wolfcamp interval.

Pioneer placed 43 vertical comingled Strawn wells on production in the third quarter, with an average 24-hour IP rate of 175 BOEPD. Production data continues to support an incremental gross EUR per well from the Strawn interval of 30 MBOE. Pioneer continues to estimate that 70% of its Spraberry acreage position is prospective for the Strawn interval.

The Company placed 27 comingled vertical Atoka wells on production during the third quarter, with an average 24-hour IP rate of 167 BOEPD. Results from well tests continue to support an incremental gross EUR of 50 MBOE to 70 MBOE for wells completed in the Atoka interval. Pioneer continues to believe the Atoka interval is prospective in 40% to 50% of its Spraberry acreage position.

Thirty-one comingled vertical wells were also placed on production through the Mississippian interval during the third quarter, with an average initial 24-hour IP rate of 118 BOEPD. Data from Mississippian wells drilled to date continues to support an incremental gross EUR per well of 15 MBOE to 40 MBOE from this interval. Pioneer continues to believe the Mississippian interval is prospective in 20% of its Spraberry acreage.

Third quarter production from the Spraberry field averaged 69 MBOEPD, an increase of 5 MBOEPD from the second quarter of 2012. Production benefited by approximately 1,800 barrels per day (BPD) from the partial drawdown of NGL inventory at Mont Belvieu that was built during the second quarter as a result of third-party NGL fractionation capacity constraints. However, this benefit was offset by a production loss of approximately 4,000 BOEPD due to continuing NGL fractionation constraints during the third quarter. The fractionation capacity constraints were resolved in early October.

The remaining NGL inventory of 90 thousand barrels (approximately 1,000 BPD) is expected to be drawn down in the fourth quarter, but will be offset by line fill requirements that Pioneer must provide during the quarter for the start-up of the new Lone Star NGL pipeline. Pioneer has also been informed that gas processing capacity in the Spraberry area is expected to be nearing capacity in the fourth quarter due to greater-than-anticipated Pioneer and industry production growth. This is expected to negatively impact Pioneer's fourth quarter production by 1,000 BOEPD to 2,000 BOEPD due to reduced ethane recoveries and result in total Spraberry production ranging from 69 MBOEPD to 71 MBOEPD for the quarter. New gas processing capacity is expected to be on line late in the first quarter or early in the second quarter of 2013 to alleviate the capacity bottleneck and increase ethane recoveries.

Based on the Company's fourth quarter production forecast, Spraberry production is forecasted to grow from an average of 45 MBOEPD in 2011 to 66 MBOEPD to 67 MBOEPD in 2012. This reflects achieving the top end of Pioneer's original guidance range for 2012.

In the liquids-rich Eagle Ford Shale in South Texas, Pioneer expects to drill approximately 125 wells in 2012. The 2012 drilling program continues to focus on liquids-rich drilling, with only 10% of the wells

designated to hold strategic dry gas acreage in response to the current low gas price environment. The Company drilled 38 wells in the third quarter and placed 35 wells on production.

Pioneer's drilling operations in the Eagle Ford Shale continue to become more efficient. The Company's average drilling cost per foot has decreased by 18% and drilling feet per day has increased by 28% since the second quarter of 2011. The number of wells drilled from pads, as opposed to single-well locations, is expected to increase from 30% of the wells drilled in the first nine months of 2012 to 80% of the wells drilled in 2013, reflecting the fact that most of Pioneer's acreage will be held by production next year.

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. The Company is now expanding the use of white sand proppant to deeper areas of the field to further define its performance limits. The Company has tested 74 wells with white sand proppant through the third quarter, three of which were deeper dry gas wells, with a savings of approximately $700 thousand per well. Early well performance has been similar to direct offset ceramic-stimulated wells. Pioneer is continuing to monitor the performance of these wells and expects that 50% of its 2012 drilling program will have used the lower-cost white sand proppant. During 2013, the Company expects that greater than 50% of the wells drilled will use white sand proppant.

Pioneer increased its Eagle Ford Shale production from 24 MBOEPD in the second quarter of 2012 to 29 MBOEPD in the third quarter, achieving another record production level. Strong well performance continues to drive this growth. Fifty percent of Pioneer's wells across the entire play are in the top quartile of industry EURs, while 80% of the Company's wells are above the industry mean EUR. The choke management program being utilized by Pioneer on its wells is contributing to the strong well performance. The Company expects fourth quarter production to range from 32 MBOEPD to 35 MBOEPD. On a full-year basis, this will result in average production of 27 MBOEPD to 28 MBOEPD, up from 12 MBOEPD in 2011. The updated production forecast for 2012 reflects a narrowing from the previous guidance range of 25 MBOEPD to 29 MBOEPD.

Eleven central gathering plants (CGPs) are now operational as part of the joint venture's Eagle Ford Shale midstream business. Pioneer's share of its Eagle Ford Shale joint venture midstream activities is conducted through a partially-owned, unconsolidated entity. Funding for ongoing midstream infrastructure build-out costs that are in excess of operating cash flow is 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.

On the North Slope of Alaska, Pioneer continues to operate one rig and drill development wells from its island drill site targeting the Nuiqsut and Torok intervals. The Company's third quarter production was 4.5 thousand barrels oil per day, down slightly as expected from the second quarter of 2012. During the first quarter of 2012, the Company completed its first successful mechanically diverted fracture stimulation of a Nuiqsut interval well. Based on the success of this mechanically diverted fracture stimulation, the Company is currently drilling four more wells that will be stimulated early next year during the winter drilling season. Three of these wells will be in the Nuiqsut interval and one will be in the Torok interval. During the first quarter of 2012, the Company also drilled a successful onshore appraisal well to test the southern extent of the Torok interval. The production and subsurface data provided by this successful well supported the addition of 50 million barrels of oil to the resource potential of the Torok interval within Pioneer's acreage. The well is now shut in awaiting permanent onshore production facilities for which an onshore development FEED study has been initiated. Pioneer is planning a second onshore Torok well for the first quarter of next year (winter drilling season) to further appraise this interval.

2012 Capital Budget

Pioneer's capital program for 2012 of $3.0 billion (excludes acquisitions, asset retirement obligations, capitalized interest and geological and geophysical G&A) includes drilling capital of $2.5 billion and capital for vertical integration of $0.5 billion.

The Company is increasing its 2012 drilling budget from $2.4 billion to $2.5 billion. The increase of $100 million primarily supports the acceleration of appraisal activity in the horizontal Wolfcamp Shale. The overall program continues to be focused on liquids-rich drilling, with approximately 75% of the spending earmarked for Spraberry vertical and horizontal Wolfcamp Shale drilling and 10% for Eagle Ford Shale drilling.

The capital for vertical integration of $500 million includes $300 million for the U.S. industrial sands business acquired by Pioneer in early April, $100 million for pressure pumping and well service equipment and $100 million for the accelerated construction of field offices and facilities from 2013 into 2012.

The 2012 capital budget is expected to be funded from forecasted operating cash flow of $1.8 billion, assuming commodity prices of $85 per barrel for oil and $3 per thousand cubic feet (MCF) for gas for the fourth quarter of 2012; proceeds of $500 million from Pioneer's equity offering during the fourth quarter of 2011; net proceeds of $200 million from the liquidation of certain 2014 and 2015 gas derivatives, liquidating expiring interest rate swaps and the utilization of existing pipe and equipment inventory; proceeds from the divestiture of South African and certain South Texas assets of $100 million and borrowings of $400 million under Pioneer's credit facility.

Third Quarter 2012 Financial Review

The following financial results for the third quarter of 2012 reflect continuing operations and exclude the results of operations attributable to South Africa and the Barnett Shale that are included in discontinued operations.

Liquids and gas sales averaged 153 MBOEPD, consisting of oil sales averaging 63 thousand barrels per day (MBPD), NGL sales averaging 30 MBPD and gas sales averaging 357 million cubic feet per day (MMCFPD).

The average price for oil was $89.87 per barrel including $1.82 per barrel related to deferred revenue from VPPs for which production was not recorded. The average reported price for NGLs was $31.28 per barrel and the average reported price for gas was $2.62 per MCF.

Production costs averaged $16.03 per barrel oil equivalent (BOE). These costs were higher than the second quarter of 2012 by $1.54 per BOE, primarily due to increases in salt water disposal costs (principally water hauling costs), higher electricity costs associated with the increase in gas prices, higher repair and maintenance costs and higher per-BOE costs resulting from the approximately 4,000 BOEPD of lost sales volumes associated with the NGL fractionation capacity constraints at Mont Belvieu. Depreciation, depletion and amortization (DD&A) expense averaged $14.51 per BOE. Exploration and abandonment costs were $27 million for the quarter and included $3 million of seismic related activity, $9 million associated with the abandonment of dry gas acreage that is not expected to be drilled and $11 million for personnel costs. General and administrative expense totaled $63 million. Interest expense was $54 million, and other expense was $32 million, including $7 million for non-recurring rig termination fees.

Fourth Quarter 2012 Financial Outlook

The Company's fourth quarter 2012 outlook for certain operating and financial items (excluding the Barnett Shale, which will be reflected in discontinued operations) is provided below.

Production is forecasted to average 154 MBOEPD to 158 MBOEPD. This assumes the remaining NGL inventory at Mont Belvieu of 90,000 barrels (approximately 1,000 BPD) will be drawn down during the

fourth quarter, but will be offset by line fill requirements in the fourth quarter for the new Lone Star NGL pipeline in which Pioneer will be a shipper. The fourth quarter production estimate also assumes a negative impact ranging from 1,000 BOEPD to 2,000 BOEPD due to reduced ethane recoveries associated with gas processing facilities in the Spraberry field nearing capacity during the fourth quarter as described above.

Production costs are expected to average $14.50 to $16.50 per BOE, based on continuing higher salt water disposal and electricity costs, higher per-BOE costs resulting from the gas processing capacity limitations negatively impacting sales volumes and current NYMEX strip commodity prices. DD&A expense is expected to average $13.50 to $15.50 per BOE. Total exploration and abandonment expense is forecasted to be $25 million to $35 million.

General and administrative expense is expected to be $60 million to $65 million, interest expense is expected to be $53 million to $58 million and other expense is expected to be $25 million to $35 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 $8 million to $11 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 $2 million to $7 million and are primarily attributable to state taxes.

The Company's financial and derivative mark-to-market results, open derivatives positions and future VPP amortization are outlined on the attached schedules.

Earnings Conference Call

On Thursday, November 1, 2012, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended September 30, 2012, 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 & Webcasts” to listen to the discussion, view the presentation and see other related material.

Telephone: Dial (888) 296-4217 confirmation code: 4877153 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 20 by dialing (888) 203-1112 confirmation code: 4877153.

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

Except for historical information contained herein, the statements in this news release are forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause Pioneer's actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties include, among other things, volatility of commodity prices, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the ability to obtain approvals from third parties and negotiate agreements (including joint venture agreements) with third parties on mutually acceptable terms, litigation, the costs and results of drilling and operations,

availability of equipment, services, resources 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, the risks associated with the ownership and operation of an industrial sand mining business 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 U.S. Securities and Exchange Commission (SEC). 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 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

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, 2012			December 31, 2011
ASSETS
Current assets:
Cash and cash equivalents	$	333,886		$	537,484
Accounts receivable, net	300,570			283,813
Income taxes receivable	10,126			3
Inventories	277,419			241,609
Prepaid expenses	21,657			14,263
Discontinued operations held for sale	400,392			73,349
Derivatives	225,900			238,835
Other current assets, net	9,934			12,936
Total current assets	1,579,884			1,402,292
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting	13,453,534			12,249,332
Accumulated depletion, depreciation and amortization	(4,107,432		)	(3,648,465		)
Total property, plant and equipment	9,346,102			8,600,867
Goodwill	293,449			298,142
Other property and equipment, net	1,186,131			573,075
Investment in unconsolidated affiliate	194,003			169,532
Derivatives	101,023			243,240
Other assets, net	113,409			160,008
	$	12,814,001		$	11,447,156
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	804,636		$	716,211
Interest payable	40,960			57,240
Income taxes payable	222			9,788
Current deferred income taxes	63,927			57,713
Discontinued operations held for sale	5,919			75,901
Deferred revenue	10,575			42,069
Derivatives	14,815			74,415
Other current liabilities	50,794			36,174
Total current liabilities	991,848			1,069,511
Long-term debt	3,562,070			2,528,905
Deferred income taxes	2,209,472			1,942,446
Derivatives	27,938			33,561
Other liabilities	222,564			221,595
Equity	5,800,109			5,651,138
	$	12,814,001		$	11,447,156

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,
	2012			2011			2012			2011
Revenues and other income:
Oil and gas	$	695,422		$	574,114		$	2,014,920		$	1,595,563
Interest and other	18,733			7,311			53,224			49,378
Derivative gains (losses), net	(123,994		)	401,072			243,568			386,118
Gain (loss) on disposition of assets, net	13,237			1,048			57,973			(1,439		)
	603,398			983,545			2,369,685			2,029,620
Costs and expenses:
Oil and gas production	176,711			112,661			449,861			305,098
Production and ad valorem taxes	49,036			37,713			137,797			105,982
Depletion, depreciation and amortization	204,264			138,413			557,064			387,320
Exploration and abandonments	26,652			14,021			108,914			42,809
General and administrative	62,567			49,618			180,591			137,868
Accretion of discount on asset retirement obligations	2,369			1,993			6,994			5,930
Interest	54,441			45,560			150,307			135,782
Hurricane activity, net	—			(1,487		)	—			(1,418		)
Other	31,923			17,057			86,028			46,971
	607,963			415,549			1,677,556			1,166,342
Income (loss) from continuing operations before income taxes	(4,565		)	567,996			692,129			863,278
Income tax provision	(8,386		)	(182,728		)	(248,535		)	(278,732		)
Income (loss) from continuing operations	(12,951		)	385,268			443,594			584,546
Income (loss) from discontinued operations, net of tax	34,650			330			(240,474		)	410,556
Net income	21,699			385,598			203,120			995,102
Net income attributable to noncontrolling interests	(2,475		)	(34,134		)	(39,669		)	(49,467		)
Net income attributable to common stockholders	$	19,224		$	351,464		$	163,451		$	945,635
Basic earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	(0.13	)	$	2.96		$	3.27		$	4.53
Income (loss) from discontinued operations attributable to common stockholders	0.28			—			(1.96		)	3.47
Net income attributable to common stockholders	$	0.15		$	2.96		$	1.31		$	8.00
Diluted earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	(0.13	)	$	2.95		$	3.19		$	4.44
Income (loss) from discontinued operations attributable to common stockholders	0.28			—			(1.91		)	3.41
Net income attributable to common stockholders	$	0.15		$	2.95		$	1.28		$	7.85
Weighted average shares outstanding:
Basic	123,111			116,281			122,874			116,122
Diluted	123,111			117,075			126,111			118,350

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Cash flows from operating activities:
Net income	$	21,699		$	385,598		$	203,120		$	995,102
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	204,264			138,413			557,064			387,320
Exploration expenses, including dry holes	13,005			1,586			52,574			5,228
Deferred income taxes	21,438			179,693			241,608			270,657
(Gain) loss on disposition of assets, net	(13,237		)	(1,048		)	(57,973		)	1,439
Accretion of discount on asset retirement obligations	2,369			1,993			6,994			5,930
Discontinued operations	(21,901		)	12,503			293,646			(371,767		)
Interest expense	8,660			7,980			26,812			23,412
Derivative related activity	237,088			(326,126		)	93,088			(269,746		)
Amortization of stock-based compensation	15,929			10,370			46,899			31,525
Amortization of deferred revenue	(10,575		)	(11,330		)	(31,494		)	(33,620		)
Other noncash items	(13,485		)	12,686			(20,998		)	3,480
Change in operating assets and liabilities, net of effects from acquisitions and dispositions:
Accounts receivable, net	(41,827		)	(11,647		)	(7,946		)	(35,252		)
Income taxes receivable	(7,180		)	1,362			(8,632		)	28,588
Inventories	26,971			(41,825		)	(6,347		)	(115,961		)
Prepaid expenses	6,653			2,432			(6,772		)	(7,558		)
Other current assets	16,744			(252		)	7,898			8,520
Accounts payable	(7,026		)	77,431			23,554			83,632
Interest payable	(16,384		)	(23,411		)	(16,302		)	(25,053		)
Income taxes payable	(1,659		)	9,678			(9,566		)	(1,807		)
Other current liabilities	(9,486		)	39,498			(29,757		)	45,969
Net cash provided by operating activities	432,060			465,584			1,357,470			1,030,038
Net cash used in investing activities	(694,023		)	(613,001		)	(2,516,089		)	(854,853		)
Net cash provided by (used in) financing activities	278,080			5,561			955,021			(75,780		)
Net increase (decrease) in cash and cash equivalents	16,117			(141,856		)	(203,598		)	99,405
Cash and cash equivalents, beginning of period	317,769			352,421			537,484			111,160
Cash and cash equivalents, end of period	$	333,886		$	210,565		$	333,886		$	210,565

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUMMARY PRODUCTION AND PRICE DATA

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Average Daily Sales Volumes from Continuing Operations:
Oil (Bbls) -	63,125		41,463		60,070		36,943
Natural gas liquids ("NGL") (Bbls) -	30,352		21,748		26,526		20,132
Gas (Mcf) -	357,232		338,321		354,468		328,464
Total (BOE) -	153,016		119,597		145,674		111,819
Average Reported Prices (a):
Oil (per Bbl) -	$	89.87	$	92.11	$	92.83	$	97.06
NGL (per Bbl) -	$	31.28	$	48.33	$	35.10	$	46.59
Gas (per Mcf) -	$	2.62	$	4.05	$	2.39	$	4.02
Total (BOE) -	$	49.40	$	52.18	$	50.48	$	52.27

__________

(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, generally acceptable accounting principles ("GAAP") provide 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, 2012 and 2011:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(in thousands)
Net income attributable to common stockholders	$	19,224		$	351,464		$	163,451		$	945,635
Participating basic earnings	(357		)	(6,797		)	(2,499		)	(17,186		)
Basic net income attributable to common stockholders	18,867			344,667			160,952			928,449
Reallocation of participating earnings	—			189			134			458
Diluted net income attributable to common stockholders	$	18,867		$	344,856		$	161,086		$	928,907

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, 2012 and 2011:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2012	2011	2012	2011
	(in thousands)
Weighted average common shares outstanding:
Basic	123,111	116,281	122,874	116,122
Dilutive common stock options	—	166	196	181
Contingently issuable performance unit shares	—	443	175	429
Convertible senior notes dilution	—	185	2,866	1,618
Diluted	123,111	117,075	126,111	118,350

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 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,
	2012			2011			2012			2011
Net income	$	21,699		$	385,598		$	203,120		$	995,102
Depletion, depreciation and amortization	204,264			138,413			557,064			387,320
Exploration and abandonments	26,652			14,021			108,914			42,809
Hurricane activity, net	—			(1,487		)	—			(1,418		)
Accretion of discount on asset retirement obligations	2,369			1,993			6,994			5,930
Interest expense	54,441			45,560			150,307			135,782
Income tax provision	8,386			182,728			248,535			278,732
(Gain) loss on disposition of assets, net	(13,237		)	(1,048		)	(57,973		)	1,439
(Income) loss from discontinued operations	(34,650		)	(330		)	240,474			(410,556		)
Derivative related activity	237,088			(326,126		)	93,088			(269,746		)
Amortization of stock-based compensation	15,929			10,370			46,899			31,525
Amortization of deferred revenue	(10,575		)	(11,330		)	(31,494		)	(33,620		)
Other noncash items	(13,485		)	12,686			(20,998		)	3,480
EBITDAX (a)	498,881			451,048			1,544,930			1,166,779
Cash interest expense	(45,781		)	(37,580		)	(123,495		)	(112,370		)
Current income tax (provision) benefit	13,052			(3,035		)	(6,927		)	(8,075		)
Discretionary cash flow (b)	466,152			410,433			1,414,508			1,046,334
Cash hurricane activity	—			1,487			—			1,418
Discontinued operations cash activity	12,749			12,833			53,172			38,789
Cash exploration expense	(13,647		)	(12,435		)	(56,340		)	(37,581		)
Changes in operating assets and liabilities	(33,194		)	53,266			(53,870		)	(18,922		)
Net cash provided by operating activities	$	432,060		$	465,584		$	1,357,470		$	1,030,038

__________

(a)

“EBITDAX” represents earnings before depletion, depreciation and amortization expense; exploration and abandonments; net hurricane activity; accretion of discount on asset retirement obligations; interest expense; income taxes; (gain) loss on the disposition of assets, net; (income) loss from discontinued operations; noncash derivative related activity; amortization of stock-based compensation; amortization of deferred revenue and other noncash items.

(b)

Discretionary cash flow equals cash flows from operating activities before changes in operating assets and liabilities and cash activity reflected in discontinued operations, hurricane activity and exploration expense.

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (continued)

(in thousands, except per share data)

Adjusted income excluding unrealized mark-to-market ("MTM") derivative losses, and adjusted income excluding unrealized MTM derivative losses and unusual items, as presented in this press release, are presented and reconciled to Pioneer's net income attributable to common stockholders and diluted common shares outstanding (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, 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 these non-GAAP measures may enhance investors' ability to assess Pioneer's historical and future financial performance. These non-GAAP financial measures are not intended to be substitutes for the comparable GAAP measure and should be read only in conjunction with Pioneer's consolidated financial statements prepared in accordance with GAAP. Unrealized MTM derivative gains and losses and unusual items will recur in future periods; however, the amount and frequency can vary significantly from period to period. The tables below reconcile Pioneer's net income attributable to common stockholders and diluted shares outstanding for the three months ended September 30, 2012, as determined in accordance with GAAP, to income adjusted for unrealized MTM derivative losses and adjusted income excluding unrealized MTM derivative losses and unusual items for that quarter.

	After-tax Amounts			Amounts Per Share
Net income attributable to common stockholders	$	19,224		$	0.15
Unrealized MTM derivative losses	145,892			1.19
Income adjusted for unrealized MTM derivative losses	165,116			1.34
Income from discontinued operations (excluding Barnett Shale activity)	(32,358		)	(0.26		)
Realized termination gains on commodity and interest rate derivatives	(28,048		)	(0.23		)
Gain on sale of Alaska Cosmopolitan prospect	(7,924		)	(0.06		)
Abandonment of dry gas acreage	5,917			0.05
Drilling rig termination fees	4,288			0.03
Alaska production tax credit recoveries	(2,507		)	(0.02		)
Incremental share dilution attributable to common stock equivalents	—			(0.03		)
Adjusted income excluding unrealized MTM derivative losses and unusual items and adjusting for incremental share dilution	$	104,484		$	0.82
	Three Months Ended September 30,
Diluted common shares outstanding	123,111
Common stock equivalents dilutive to adjusted income	3,676
Diluted common shares outstanding including common stock equivalents	126,787

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Open Commodity Derivative Positions as of October 30, 2012

(Volumes are average daily amounts)

	2012			Twelve Months Ending December 31,
	Fourth Quarter			2013			2014		2015
Average Daily Oil Production Associated with Derivatives (Bbls):
Collar contracts with short puts:
Volume	53,110			71,029			60,000		26,000
NYMEX price:
Ceiling	$	118.85		$	119.76		$	117.06	$	104.45
Floor	$	85.09		$	92.27		$	92.67	$	95.00
Short put	$	69.44		$	74.28		$	76.58	$	80.00
Collar contracts:
Volume	2,000			—			—		—
NYMEX price:
Ceiling	$	127.00		$	—		$	—	$	—
Floor	$	90.00		$	—		$	—	$	—
Swap contracts:
Volume	11,000			3,000			—		—
NYMEX price	$	89.34		$	81.02		$	—	$	—
Rollfactor swap contracts:
Volume	—			6,000			—		—
NYMEX roll price (a)	$	—		$	0.43		$	—	$	—
Basis swap contracts:
Index swap volume	20,000			—			—		—
Price (b)	$	(1.15	)	$	—		$	—	$	—
Average Daily NGL Production Associated with Derivatives (Bbls):
Collar contracts with short puts:
Volume	3,000			1,064			1,000		—
Index price (c):
Ceiling	$	79.99		$	105.28		$	109.50	$	—
Floor	$	67.70		$	89.30		$	95.00	$	—
Short put	$	55.76		$	75.20		$	80.00	$	—
Swap contracts:
Volume	2,750			—			—		—
Index price (c)	$	67.85		$	—		$	—	$	—
Average Daily Gas Production Associated with Derivatives (MMBtu):
Collar contracts with short puts:
Volume	—			—			—		205,000
NYMEX price:
Ceiling	$	—		$	—		$	—	$	5.07
Floor	$	—		$	—		$	—	$	4.00
Short put	$	—		$	—		$	—	$	3.00
Collar contracts:
Volume	65,000			150,000			—		—
NYMEX price:
Ceiling	$	6.60		$	6.25		$	—	$	—
Floor	$	5.00		$	5.00		$	—	$	—
Swap contracts:
Volume	275,000			162,500			105,000		—
NYMEX price (d)	$	4.97		$	5.13		$	4.03	$	—
Basis swap contracts:
Permian Basin index swap volume (e)	32,500			52,500			—		—
Price differential ($/MMBtu)	$	(0.38	)	$	(0.23	)	$	—	$	—
Mid-Continent index swap volume (e)	50,000			30,000			—		—
Price differential ($/MMBtu)	$	(0.53	)	$	(0.38	)	$	—	$	—
Gulf Coast index swap volume (e)	53,500			60,000			—		—
Price differential ($/MMBtu)	$	(0.15	)	$	(0.14	)	$	—	$	—

__________

(a)	Represent swaps that fix 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.
(b)	Represent swaps that fix the basis differential between Midland WTI and Cushing WTI.
(c)	2012 represents the weighted average index price per Bbl of each NGL component. 2013 and 2014 represent the NYMEX WTI index price per Bbl of natural gasoline.
(d)	Represents the NYMEX Henry Hub 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 and collar contracts.

Interest rate derivatives. As of October 30, 2012, the Company had interest rate derivative contracts that lock in a fixed forward annual interest rate of 3.21%, for a 10-year period ending in December 2025, on a notional amount of $250 million.  These derivative contracts mature and settle by their terms during December 2015.

Marketing and basis transfer derivatives.Periodically, the Company enters into gas buy and sell marketing arrangements to fulfill firm pipeline transportation commitments.  Associated with these gas marketing arrangements, the Company may enter into gas index swaps to mitigate price risk.

From time to time, the Company also enters into long and short gas swap contracts that transfer gas basis risk from one sales index to another sales index.  The following table presents Pioneer’s open marketing and basis transfer derivative positions as of October 30, 2012:

	2012			Twelve Months Ending December 31,
	Fourth Quarter			2013
Average Daily Gas Production Associated with Marketing Derivatives (MMBtu):
Basis swap contracts:
Index swap volume	43,370			9,863
Price differential ($/MMBtu)	$	0.24		$	0.25
Average Daily Gas Production Associated with Basis Transfer Derivatives (MMBtu):
Basis swap contracts:
Short index swap volume	1,685			—
NGI-So Cal Border Monthly price differential ($/MMBtu)	$	0.12		$	—
Long index swap volume	(1,685		)	—
IF-HSC price differential ($/MMBtu)	$	(0.05	)	$	—

PIONEER NATURAL RESOURCES COMPANY

SUPPLEMENTAL INFORMATION

Amortization of Deferred Revenue Associated with Volumetric Production Payments

as of September 30, 2012 (in thousands)

	2012
	Fourth Quarter
Total deferred revenue associated with VPP (a)	$	10,575

__________

(a) Deferred revenue will be amortized as increases to oil revenues during the fourth quarter of 2012.

Derivative Gains (Losses), Net

(in thousands)

	Three Months Ended September 30, 2012			Nine Months Ended September 30, 2012
Noncash changes in fair value:
Oil derivative gains (losses)	$	(73,766	)	$	193,844
NGL derivative gains (losses)	(6,265		)	5,095
Gas derivative losses	(179,798		)	(292,611		)
Diesel derivative losses	(236		)	(270		)
Marketing derivative losses	(183		)	(110		)
Interest rate derivative gains	23,160			4,121
Total noncash derivative losses, net (a)	(237,088		)	(89,931		)
Cash settled changes in fair value:
Oil derivative losses	(620		)	(9,323		)
NGL derivative gains	4,627			11,092
Gas derivative gains (b)	135,677			356,403
Diesel derivative gains (b)	1,633			3,497
Marketing derivative gains	136			189
Interest rate derivative losses (b)	(28,359		)	(28,359		)
Total cash derivative gains, net	113,094			333,499
Total derivative gains (losses), net	$	(123,994	)	$	243,568

__________

(a)

Total net unrealized mark-to-market derivative losses includes $5.5 million of net losses and $13.7 million of net gains attributable to noncontrolling interests in consolidated subsidiaries during the three and nine months ended September 30, 2012, respectively.

(b)

During the nine months ended September 30, 2012, the Company terminated (i) swap, collar, three-way and basis swap derivative contracts for 2014 and 2015 gas production, (ii) swap derivative contracts for 2012 and 2013 diesel fuel and (iii) $200 million notional amount of interest rate derivative contracts. As a result of these transactions, the Company realized $44.5 million of net proceeds during the third quarter of 2012 and $118.2 million of net proceeds during the nine months ended September 30, 2012.