10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________________

FORM 10-Q

______________________________

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2012

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                     to                     

Commission File Number: 1-13245

______________________________ 

PIONEER NATURAL RESOURCES COMPANY

(Exact name of Registrant as specified in its charter)

______________________________

Delaware	75-2702753
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
5205 N. O'Connor Blvd., Suite 200, Irving, Texas	75039
(Address of principal executive offices)	(Zip Code)

(972) 444-9001

(Registrant's telephone number, including area code)

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

______________________________

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes  ý    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No   ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer	ý	Accelerated filer	¨
Non-accelerated filer	o (Do not check if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes   ¨    No  ý

Number of shares of Common Stock outstanding as of August 1, 2012                     123,035,765

PIONEER NATURAL RESOURCES COMPANY

TABLE OF CONTENTS

		Page
Cautionary Statement Concerning Forward-Looking Statements		3
Definitions of Certain Terms and Conventions Used Herein		4
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Balance Sheets as of June 30, 2012 and December 31, 2011	5
	Consolidated Statements of Operations for the three and six months ended June 30, 2012 and 2011	7
	Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2012 and 2011	8
	Consolidated Statement of Equity for the six months ended June 30, 2012	9
	Consolidated Statements of Cash Flows for the six months ended June 30, 2012 and 2011	10
	Notes to Consolidated Financial Statements	11
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	41
Item 4.	Controls and Procedures	45
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 4.	Mine Safety Disclosures	46
Item 6.	Exhibits	47
Signatures		48
Exhibit Index		49

2

PIONEER NATURAL RESOURCES COMPANY

Cautionary Statement Concerning Forward-Looking Statements

The information in this Quarterly Report on Form 10-Q (the "Report") contains forward-looking statements that involve risks and uncertainties. When used in this document, the words "believes," "plans," "expects," "anticipates," "forecasts," "intends," "continue," "may," "will," "could," "should," "future," "potential," "estimate" or the negative of such terms and similar expressions as they relate to Pioneer Natural Resources Company ("Pioneer" or the "Company") are intended to identify forward-looking statements. The forward-looking statements are based on the Company's current expectations, assumptions, estimates and projections about the Company and the industry in which the Company operates. Although the Company believes that the expectations and assumptions reflected in the forward-looking statements are reasonable, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond the Company's control.

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 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 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, international operations and acts of war or terrorism. These and other risks are described in the Company's Annual Report on Form 10-K, this and other Quarterly Reports on Form 10-Q and other filings with the United States Securities and Exchange Commission (the "SEC"). In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse effect on it. Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. See "Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations," "Part 1, Item 3. Quantitative and Qualitative Disclosures About Market Risk" and "Part II, Item 1A. Risk Factors" in this Report and "Part I, Item 1. Business — Competition, Markets and Regulations," "Part I, Item 1A. Risk Factors," "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk" in the Company's Annual Report on Form 10-K for the year ended December 31, 2011 for a description of various factors that could materially affect the ability of Pioneer to achieve the anticipated results described in the forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. The Company undertakes no duty to publicly update these statements except as required by law.

3

PIONEER NATURAL RESOURCES COMPANY

Definitions of Certain Terms and Conventions Used Herein

Within this Report, the following terms and conventions have specific meanings:

• "BBL" means a standard barrel containing 42 United States gallons.

• "BOE" means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of six thousand cubic feet of gas to one BBL of oil or natural gas liquid.

• "BOEPD" means BOE per day.

• "BTU" means British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.

• "Conway" means the daily average natural gas liquids components as priced in Oil Price Information Service ("OPIS") in the table "U.S. and Canada LP – Gas Weekly Averages" at Conway, Kansas.

• "DD&A" means depletion, depreciation and amortization.

• "GAAP" means accounting principles that are generally accepted in the United States of America.

• "LIBOR" means London Interbank Offered Rate, which is a market rate of interest.

• "MCF" means one thousand cubic feet and is a measure of gas volume.

• "MMBTU" means one million BTUs.

• "MMBTUPD" means MMBTU per day.

• "Mont Belvieu" means the daily average natural gas liquids components as priced in OPIS in the table "U.S. and Canada LP – Gas Weekly Averages" at Mont Belvieu, Texas.

• "NGL" means natural gas liquid.

• "NYMEX" means the New York Mercantile Exchange.

• "Pioneer" or the "Company" means Pioneer Natural Resources Company and its subsidiaries.

• "Pioneer Southwest" means Pioneer Southwest Energy Partners L.P. and its subsidiaries.

•"Proved reserves" mean the quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons ("LKH") as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil ("HKO") elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

• "U.S." means United States.

• With respect to information on the working interest in wells, drilling locations and acreage, "net" wells, drilling locations and acres are determined by multiplying "gross" wells, drilling locations and acres by the Company's working interest in such wells, drilling locations or acres. Unless otherwise specified, wells, drilling locations and acreage statistics quoted herein represent gross wells, drilling locations or acres.

• Unless otherwise indicated, all currency amounts are expressed in U.S. dollars.

4

PART I. FINANCIAL INFORMATION

Item 1.Financial Statements

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS

(in thousands)

	June 30, 2012			December 31, 2011
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	317,769		$	537,484
Accounts receivable:
Trade, net of allowance for doubtful accounts of $706 and $806 as of June 30, 2012 and December 31, 2011, respectively	250,192			275,991
Due from affiliates	2,301			7,822
Income taxes receivable	2,417			3
Inventories	277,539			241,609
Prepaid expenses	28,213			14,263
Discontinued operations held for sale	70,177			73,349
Other current assets:
Derivatives	308,762			238,835
Other	26,663			12,936
Total current assets	1,284,033			1,402,292
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	12,964,291			12,013,805
Unproved properties	296,827			235,527
Accumulated depletion, depreciation and amortization	(4,013,770		)	(3,648,465		)
Total property, plant and equipment	9,247,348			8,600,867
Goodwill	298,142			298,142
Other property and equipment, net	1,134,532			573,075
Other assets:
Investment in unconsolidated affiliate	184,374			169,532
Derivatives	260,929			243,240
Other, net of allowance for doubtful accounts of $655 and $340 as of June 30, 2012 and December 31, 2011, respectively	160,376			160,008
	$	12,569,734		$	11,447,156

The financial information included as of June 30, 2012 has been prepared by management

without audit by independent registered public accountants.

The accompanying notes are an integral part of these consolidated financial statements.

5

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS (continued)

(in thousands, except share data)

	June 30, 2012			December 31, 2011
	(Unaudited)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	769,611		$	647,455
Due to affiliates	39,547			68,756
Interest payable	57,329			57,240
Income taxes payable	1,881			9,788
Deferred income taxes	89,656			57,713
Discontinued operations held for sale	77,310			75,901
Other current liabilities:
Derivatives	30,650			74,415
Deferred revenue	21,150			42,069
Other	41,857			36,174
Total current liabilities	1,128,991			1,069,511
Long-term debt	3,285,497			2,528,905
Derivatives	17,785			33,561
Deferred income taxes	2,154,301			1,942,446
Other liabilities	226,184			221,595
Equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 134,763,095 and 133,121,092 shares issued at June 30, 2012 and December 31, 2011, respectively	1,348			1,331
Additional paid-in capital	3,611,799			3,613,808
Treasury stock at cost: 11,727,359 and 11,264,936 at June 30, 2012 and December 31, 2011, respectively	(511,628		)	(458,281		)
Retained earnings	2,473,504			2,335,066
Accumulated other comprehensive loss - net deferred hedge losses, net of tax	—			(3,130		)
Total equity attributable to common stockholders	5,575,023			5,488,794
Noncontrolling interests in consolidating subsidiaries	181,953			162,344
Total equity	5,756,976			5,651,138
Commitments and contingencies
	$	12,569,734		$	11,447,156

The financial information included as of June 30, 2012 has been prepared by management

without audit by independent registered public accountants.

The accompanying notes are an integral part of these consolidated financial statements.

6

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Revenues and other income:
Oil and gas	$	641,737		$	562,412		$	1,360,693		$	1,038,140
Interest and other	6,043			13,594			34,491			42,067
Derivative gains (losses), net	275,812			229,478			367,562			(14,954		)
Gain (loss) on disposition of assets, net	1,140			(296		)	44,736			(2,487		)
	924,732			805,188			1,807,482			1,062,766
Costs and expenses:
Oil and gas production	156,838			101,741			295,159			200,576
Production and ad valorem taxes	44,495			35,864			90,291			69,160
Depletion, depreciation and amortization	200,921			135,511			382,339			258,345
Impairment of oil and gas properties	444,880			—			444,880			—
Exploration and abandonments	37,178			19,732			90,465			37,216
General and administrative	54,957			44,339			118,024			88,250
Accretion of discount on asset retirement obligations	2,444			2,048			4,874			4,092
Interest	49,008			44,995			95,866			90,222
Hurricane activity, net	—			(2		)	—			69
Other	30,651			12,053			54,258			29,914
	1,021,372			396,281			1,576,156			777,844
Income (loss) from continuing operations before income taxes	(96,640		)	408,907			231,326			284,922
Income tax benefit (provision)	45,086			(140,182		)	(72,617		)	(92,275		)
Income (loss) from continuing operations	(51,554		)	268,725			158,709			192,647
Income (loss) from discontinued operations, net of tax	12,017			(3,025		)	22,712			416,857
Net income (loss)	(39,537		)	265,700			181,421			609,504
Net income attributable to noncontrolling interests	(30,855		)	(20,123		)	(37,194		)	(15,333		)
Net income (loss) attributable to common stockholders	$	(70,392	)	$	245,577		$	144,227		$	594,171
Basic earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	(0.67	)	$	2.10		$	0.98		$	1.50
Income (loss) from discontinued operations attributable to common stockholders	0.10			(0.03		)	0.18			3.53
Net income (loss) attributable to common stockholders	$	(0.57	)	$	2.07		$	1.16		$	5.03
Diluted earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$	(0.67	)	$	2.06		$	0.95		$	1.46
Income (loss) from discontinued operations attributable to common stockholders	0.10			(0.03		)	0.18			3.44
Net income (loss) attributable to common stockholders	$	(0.57	)	$	2.03		$	1.13		$	4.90
Weighted average shares outstanding:
Basic	123,028			116,213			122,754			116,042
Diluted	123,028			118,592			125,772			118,986
Dividends declared per share	$	—		$	—		$	0.04		$	0.04
Amounts attributable to common stockholders:
Income (loss) from continuing operations	$	(82,409	)	$	248,602		$	121,515		$	177,314
Income (loss) from discontinued operations, net of tax	12,017			(3,025		)	22,712			416,857
Net income (loss)	$	(70,392	)	$	245,577		$	144,227		$	594,171

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

The accompanying notes are an integral part of these consolidated financial statements.

7

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Net income (loss)	$	(39,537	)	$	265,700		$	181,421		$	609,504
Other comprehensive activity:
Net hedge (gains) losses included in continuing operations	2,347			(8,139		)	4,855			(16,195		)
Income tax (benefit) provision	(797		)	4,138			(1,725		)	4,886
Other comprehensive activity	1,550			(4,001		)	3,130			(11,309		)
Comprehensive income (loss)	(37,987		)	261,699			184,551			598,195
Comprehensive (income) loss attributable to the noncontrolling interests	(30,855		)	(16,698		)	(37,194		)	(8,522		)
Comprehensive income (loss) attributable to common stockholders	$	(68,842	)	$	245,001		$	147,357		$	589,673

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

The accompanying notes are an integral part of these consolidated financial statements.

8

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENT OF EQUITY

(in thousands, except dividends per share)

(Unaudited)

			Equity Attributable To Common Stockholders
	Shares Outstanding		Common Stock		Additional Paid-in Capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Loss			Noncontrolling Interests			Total Equity
Balance as of December 31, 2011	121,856		$	1,331	$	3,613,808		$	(458,281	)	$	2,335,066		$	(3,130	)	$	162,344		$	5,651,138
Dividends declared ($0.04 per share)	—		—		—			—			(4,982		)	—			—			(4,982		)
Exercise of long-term incentive plan stock options	65		—		(965		)	2,780			(807		)	—			—			1,008
Treasury stock purchases	(527	)	—		—			(56,129		)	—			—			(188		)	(56,317		)
Conversion of 2.875% senior convertible notes	—		—		(2		)	2			—			—			—			—
Tax benefit related to stock-based compensation	—		—		17,545			—			—			—			—			17,545
Deferred tax provision attributable to 2008 Pioneer Southwest initial public offering	—		—		(49,072		)	—			—			—			—			(49,072		)
Compensation costs:
Vested compensation awards, net	1,642		17		(17		)	—			—			—			—			—
Compensation costs included in net income	—		—		30,502			—			—			—			559			31,061
Cash distributions to noncontrolling interests	—		—		—			—			—			—			(17,956		)	(17,956		)
Net income	—		—		—			—			144,227			—			37,194			181,421
Other comprehensive activity:
Deferred hedging activity, net of tax:
Net hedge losses included in continuing operations	—		—		—			—			—			3,130			—			3,130
Balance as of June 30, 2012	123,036		$	1,348	$	3,611,799		$	(511,628	)	$	2,473,504		$	—		$	181,953		$	5,756,976

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

The accompanying notes are an integral part of these consolidated financial statements.

9

PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Six Months Ended June 30,
	2012			2011
Cash flows from operating activities:
Net income	$	181,421		$	609,504
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	382,339			258,345
Impairment of oil and gas properties	444,880			—
Exploration expenses, including dry holes	39,730			4,275
Deferred income taxes	57,291			87,337
(Gain) loss on disposition of assets, net	(44,736		)	2,487
Accretion of discount on asset retirement obligations	4,874			4,092
Discontinued operations	3,597			(390,868		)
Interest expense	18,152			15,432
Derivative related activity	(144,000		)	56,380
Amortization of stock-based compensation	30,970			21,155
Amortization of deferred revenue	(20,919		)	(22,290		)
Other noncash items	(7,513		)	(9,207		)
Change in operating assets and liabilities, net of effects from acquisitions and dispositions:
Accounts receivable, net	33,881			(23,605		)
Income taxes receivable	(1,452		)	27,226
Inventories	(33,318		)	(74,136		)
Prepaid expenses	(13,425		)	(9,990		)
Other current assets	(8,846		)	8,772
Accounts payable	30,580			6,201
Interest payable	82			(1,642		)
Income taxes payable	(7,907		)	(11,485		)
Other current liabilities	(20,271		)	6,471
Net cash provided by operating activities	925,410			564,454
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold	62,945			813,520
Payments for acquisition, net of cash acquired	(295,974		)	—
Investment in unconsolidated subsidiary	—			(82,857		)
Additions to oil and gas properties	(1,424,807		)	(757,148		)
Additions to other assets and other property and equipment, net	(164,230		)	(215,367		)
Net cash used in investing activities	(1,822,066		)	(241,852		)
Cash flows from financing activities:
Borrowings under long-term debt	1,339,093			72,610
Principal payments on long-term debt	(596,000		)	(115,810		)
Distributions to noncontrolling interests	(17,956		)	(13,366		)
Payments of other liabilities	(744		)	(305		)
Exercise of long-term incentive plan stock options	1,008			362
Purchases of treasury stock	(56,317		)	(39,218		)
Excess tax benefits from share-based payment arrangements	17,545			27,937
Payment of financing fees	(4,660		)	(8,739		)
Dividends paid	(5,028		)	(4,812		)
Net cash provided by (used in) financing activities	676,941			(81,341		)
Net increase (decrease) in cash and cash equivalents	(219,715		)	241,261
Cash and cash equivalents, beginning of period	537,484			111,160
Cash and cash equivalents, end of period	$	317,769		$	352,421

The financial information included herein has been prepared by management

without audit by independent registered public accountants.

The accompanying notes are an integral part of these consolidated financial statements.

10

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

NOTE A. Organization and Nature of Operations

Pioneer Natural Resources Company ("Pioneer" or the "Company") is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. The Company is a large independent oil and gas exploration and production company with continuing operations in the United States.

NOTE B. Basis of Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of June 30, 2012 and for the three and six months ended June 30, 2012 and 2011 include all adjustments and accruals, consisting only of normal recurring accrual adjustments, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year.

Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States ("GAAP") have been condensed or omitted in this Report pursuant to the rules and regulations of the United States Securities and Exchange Commission (the "SEC"). These consolidated financial statements should be read together with the consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2011.

Certain reclassifications have been made to the 2011 financial statement and footnote amounts in order to conform to the 2012 presentation.

On May 6, 2008, the Company recognized a noncash gain on the sale of Pioneer Southwest Energy Partners L.P.'s ("Pioneer Southwest," a majority-owned and consolidated subsidiary) common units as a component of additional paid-in capital in stockholders' equity. In accordance with the Financial Accounting Standards Board ("FASB") Accounting Standards Codification (“ASC”) Topic 740 Income Taxes, deferred income taxes of $49.1 million should be recognized for the future tax effects arising from the noncash gain on the sale of the Pioneer Southwest common units, with a corresponding decrease to additional paid-in capital. The Company recorded the deferred income taxes associated with this transaction in June 2012. The effect of this adjustment is immaterial to the accompanying financial statements.

Revision for deferred income taxes. The accompanying consolidated balance sheet as of December 31, 2011 has been revised for a change in the classification of deferred income taxes associated with the Company's unrealized current derivative net gains as of December 31, 2011. The noncash revisions resulted in a $77.0 million decrease in current deferred tax assets, a $57.7 million increase in current deferred tax liabilities and a $134.7 million decrease in noncurrent deferred tax liabilities from the amounts previously reported at December 31, 2011. Such revisions were made to appropriately reflect the impact on deferred income taxes based on the expected settlement periods related to derivatives, which remained subject to market risk as of December 31, 2011. See "- Derivatives and hedging," below and Notes F and H for more information about derivative fair values and market risk.

Derivatives and hedging. All derivatives are recorded in the accompanying consolidated balance sheets at their estimated fair values. See Note E for further information regarding the fair value of the Company's derivatives. Effective February 1, 2009, the Company discontinued hedge accounting on all of its then-existing derivative hedge contracts. Changes in the fair value of effective cash flow hedges prior to the Company's discontinuance of hedge accounting were recorded as a component of accumulated other comprehensive income or loss ("AOCI - Hedging"), in the equity section of the Company's consolidated balance sheets, and were transferred to earnings during the same periods in which the hedged transactions were recognized in the Company's earnings. As of June 30, 2012, all of the hedge gains or losses that were previously deferred in AOCI - Hedging have been transferred to earnings. The Company now recognizes all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they occur.

The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company's and Pioneer Southwest's credit-adjusted risk-free rate curves. The credit-adjusted risk-free rate curves for the Company and its counterparties are generally based on their independent market-quoted credit default swap rate curves plus the United States Treasury Bill yield

11

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

curve as of the valuation date. Pioneer Southwest's credit-adjusted risk-free rate curve is based on independent market-quoted forward London Interbank Offered Rate ("LIBOR") curves plus 162.5 basis points, representing Pioneer Southwest's borrowing rate.

Impairment of assets. The Company reviews its long-lived assets for impairment, including oil and gas properties, whenever events or circumstances indicate that their carrying values may not be fully recoverable. If the carrying value of long-lived assets is determined to be impaired, it is reduced to its estimated fair value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. See Note O for additional information about the Company's impairment charge for the three and six months ended June 30, 2012, and future impairment risk.

Goodwill is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired, it is reduced for the impaired value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. During the third quarter of 2011, the Company performed its annual assessment of goodwill impairment and determined that there was no impairment.

New accounting pronouncement. In September 2011, the FASB issued Accounting Standards Update ("ASU") No. 2011-08 Intangibles - Goodwill and Other (Topic 350) ("ASU 2011-08"). ASU 2011-08 amended FASB ASC Topic 350 to permit an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. ASU 2011-08 became effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The adoption of ASU 2011-08 did not impact the carrying value of the Company's goodwill. See Note O for information regarding the Company's impairment assessments.

NOTE C. Acquisitions and Divestitures

Premier Silica Business Combination

On April 2, 2012, a wholly-owned subsidiary of Pioneer acquired 100 percent of the share capital of Industrial Sands Holding Company and its wholly-owned subsidiary, Oglebay Norton Industrial Sands, LLC (the "Acquisition"). During April 2012, the name of Oglebay Norton Industrial Sands, LLC was changed to Premier Silica LLC ("Premier Silica"). Premier Silica's core business is the operation of mines and processing facilities that produce, process and sell sand, primarily to upstream oil and gas companies for proppant used in the fracture stimulation of oil and gas wells in the United States. Premier Silica's business is supportive to the Company's vertical integration strategy of controlling major cost components of the Company's drilling and production activities in the areas where the Company has a significant inventory of drilling locations and a significant number of producing wells. The aggregate purchase price of Premier Silica was $296.0 million, including estimated closing adjustments, and was funded from available cash and borrowings under the Company's credit facility.

The Acquisition was accounted for as a business combination which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. The Company's assessment of the fair values of Premier Silica's assets and liabilities is preliminary, and may be adjusted as a result of normal closing adjustments. The fair value of the tangible assets acquired totaled $468.9 million and were primarily comprised of proved sand reserves, probable sand reserves and mine processing facilities and equipment of $454.5 million. The fair value of liabilities assumed totaled $172.9 million and were primarily comprised of deferred income taxes of $150.8 million.

The Company recognized $1.2 million and $2.2 million of acquisition-related costs that were expensed in the three and six months ended June 30, 2012. These costs are included in other expense in the accompanying consolidated statements of operations for the three and six months ended June 30, 2012.

Divestitures Recorded as Discontinued Operations

South Africa. During December 2011, the Company committed to a plan to exit South Africa and initiated a process to divest of its net assets in South Africa ("Pioneer South Africa"). In March 2012, the Company agreed to sell its net assets in Pioneer

12

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

South Africa to an unaffiliated third party, using a January 1, 2012 effective date, for net cash proceeds of $52.0 million, before normal closing adjustments. The sale is expected to close in the third quarter of 2012. The Company has classified (i) Pioneer South Africa's assets and liabilities as discontinued operations held for sale in the Company's accompanying consolidated balance sheets as of June 30, 2012 and December 31, 2011 and (ii) Pioneer South Africa's results of operations as income from discontinued operations, net of tax in the accompanying consolidated statements of operations (representing a recasting of Pioneer South Africa results of operations for the three and six months ended June 30, 2011, which were originally classified as continuing operations).

Tunisia. In February 2011, the Company sold 100 percent of the Company's share holdings in Pioneer Natural Resources Tunisia Ltd. and Pioneer Natural Resources Anaguid Ltd. (referred to in the aggregate as "Pioneer Tunisia") to an unaffiliated third party for cash proceeds of $802.5 million, including normal closing adjustments and excluding cash and cash equivalents sold, resulting in a pretax gain of $645.2 million. Accordingly, the Company has classified the results of operations of Pioneer Tunisia, prior to its sale, as discontinued operations, net of tax in the accompanying consolidated statement of operations for the six months ended June 30, 2011.

Gulf of Mexico. During the six months ended June 30, 2011, the Bureau of Ocean Energy Management, Regulation, and Enforcement paid the Company $2.0 million of interest on excess royalty payments associated with properties that were sold by the Company during 2006. Accordingly, the interest income is classified as income from discontinued operations.

The following table represents the components of the Company's discontinued operations for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)
Revenues and other income:
Oil and gas	$	20,172		$	21,520		$	39,765		$	65,051
Interest and other	—			35			20			4,971
Gain (loss) on disposition of assets, net	—			(4,574		)	(23		)	645,298
	20,172			16,981			39,762			715,320
Costs and expenses:
Oil and gas production	1,345			714			2,135			3,937
Depletion, depreciation and amortization (a)	—			13,544			—			27,236
Exploration and abandonments	1			1,875			86			4,587
General and administrative	12			2,582			1,132			9,397
Accretion of discount on asset retirement obligations (a)	652			610			1,304			1,302
Interest	—			773			(75		)	773
Other	1,581			3,012			1,185			4,214
	3,591			23,110			5,767			51,446
Income (loss) from discontinued operations before income taxes	16,581			(6,129		)	33,995			663,874
Current tax provision	(3,334		)	(12,745		)	(8,739		)	(26,638		)
Deferred tax (provision) benefit (a)	(1,230		)	15,849			(2,544		)	(220,379		)
Income (loss) from discontinued operations	$	12,017		$	(3,025	)	$	22,712		$	416,857

 ____________________

(a) Represents the significant noncash components of discontinued operations.

Divestitures Recorded in Continuing Operations

The Company's net gain/loss on disposition of assets for the three and six months ended June 30, 2012 of $1.1 million and $44.7 million, respectively, was primarily associated with the sale of a portion of its interest in an unproved oil and gas property in the Eagle Ford Shale field during the three months ended March 31, 2012 to unaffiliated third parties for proceeds of $54.7

13

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

million, including normal closing adjustments. Associated therewith, the Company recorded a pretax gain of $42.6 million.

During the three and six months ended June 30, 2011, the Company's net loss on disposition of assets was primarily associated with the sales of excess materials and supplies inventory.

NOTE D. Exploratory Costs

The Company capitalizes exploratory well and project costs until a determination is made that the well or project has either found proved reserves, is impaired or is sold. The Company's capitalized exploratory well and project costs are presented in proved properties in the accompanying consolidated balance sheets. If the exploratory well or project is determined to be impaired, the impaired costs are charged to exploration and abandonments expense.

The following table reflects the Company's capitalized exploratory well and project activity during the three and six months ended June 30, 2012:

	Three Months Ended June 30, 2012			Six Months Ended June 30, 2012
	(in thousands)
Beginning capitalized exploratory costs	$	138,002		$	107,596
Additions to exploratory costs pending the determination of proved reserves	205,938			380,832
Reclassification due to determination of proved reserves	(148,805		)	(266,415		)
Exploratory well costs charged to exploration expense	(1,408		)	(28,286		)
Ending capitalized exploratory costs	$	193,727		$	193,727

As of June 30, 2012 and December 31, 2011, the Company had no exploratory projects for which exploratory costs have been capitalized for a period greater than one year from the date drilling was completed.

NOTE E. Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The three input levels of the fair value hierarchy are as follows:

• Level 1 – quoted prices for identical assets or liabilities in active markets.

• Level 2 – quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means.

• Level 3 – unobservable inputs for the asset or liability.

Assets and liabilities measured at fair value on a recurring basis. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.

14

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

The following table presents the Company's assets and liabilities that are measured at fair value as of June 30, 2012:

	Fair Value Measurement at the End of the Reporting Period Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Fair Value at June 30, 2012
	(in thousands)
Recurring fair value measurements
Assets:
Trading securities	$	251	$	168		$	—	$	419
Commodity derivatives	—		569,691			—		569,691
Deferred compensation plan assets	44,191		—			—		44,191
Total assets	$	44,442	$	569,859		$	—	$	614,301
Liabilities:
Commodity derivatives	$	—	$	(13,742	)	$	—	$	(13,742	)
Interest rate derivatives	—		(34,693		)	—		(34,693		)
Total liabilities	$	—	$	(48,435	)	$	—	$	(48,435	)
Total recurring fair value measurements	$	44,442	$	521,424		$	—	$	565,866

Trading securities and deferred compensation plan assets. The Company's trading securities are comprised of securities that are both actively traded and not actively traded on major exchanges. The Company's deferred compensation plan assets represent investments in equity and mutual fund securities that are actively traded on major exchanges. These investments are measured based on directly observable prices on major exchanges. As of June 30, 2012, all significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs. Inputs for certain trading securities that are not actively traded on major exchanges were classified as Level 2 inputs.

Interest rate derivatives. The Company's interest rate derivative liabilities as of June 30, 2012 represent interest rate swap contracts. The Company utilizes discounted cash flow models for valuing its interest rate derivatives. The net derivative values attributable to the Company's interest rate derivative contracts as of June 30, 2012 are based on (i) the contracted notional amounts, (ii) LIBOR rate yield curves provided by counterparties and corroborated with forward active market-quoted LIBOR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company's interest rate derivative liability measurements represent Level 2 inputs in the hierarchy priority.

Commodity derivatives. The Company's commodity derivatives represent oil, natural gas liquids ("NGL"), gas and diesel swap contracts, collar contracts and collar contracts with short puts (which are also known as three-way collar contracts). The Company's oil, gas, NGL and diesel swap, collar and three-way collar derivative contract asset and liability measurements represent Level 2 inputs in the hierarchy priority. The Company utilizes discounted cash flow and option-pricing models for valuing its commodity derivatives.

The asset and liability values attributable to the Company's commodity derivatives were determined based on inputs which include (i) the contracted notional volumes, (ii) independent active market price quotes, (iii) the applicable estimated credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar and three-way collar contracts, which is based on active and independent market-quoted volatility factors.

15

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

Financial instruments not carried at fair value. Carrying values and fair values of financial instruments that are not carried at fair value in the consolidated balance sheet as of June 30, 2012 and December 31, 2011 are as follows:

	June 30, 2012				December 31, 2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Long-term debt	$	3,285,497	$	3,934,014	$	2,528,905	$	3,105,585

Long term debt includes the Company's credit facility, the Pioneer Southwest credit facility and the Company's senior notes. The fair value of debt is determined utilizing inputs that are Level 2 measurements in the fair value hierarchy.

Credit facilities. The fair values of the Company's and Pioneer Southwest's credit facilities are calculated using a discounted cash flow model based on (i) forecasted contractual interest and fee payments, (ii) forward active market-quoted United States Treasury Bill rate (in the case of the Company's credit facility) or LIBOR (in the case of the Pioneer Southwest credit facility) yield curves and (iii) the applicable credit-adjustments.

Senior notes. The Company's senior notes represent debt securities that are not actively traded on major exchanges. The fair values of the Company's senior notes are based on their periodic values as quoted on the major exchanges.

The Company has other financial instruments consisting primarily of cash equivalents, short-term receivables, accounts payable trade and other liabilities that approximate fair value due to the nature of the instrument and relatively short maturities. Non-financial assets and liabilities initially measured at fair value include certain assets acquired and liabilities assumed in a business combination, goodwill and asset retirement obligations.

NOTE F. Income Taxes

The Company's income tax (provisions) benefits attributable to income from continuing operations consisted of the following for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)
Current	$	(3,494	)	$	(2,540	)	$	(15,326	)	$	(4,938	)
Deferred	48,580			(137,642		)	(57,291		)	(87,337		)
Income tax benefit (provision)	$	45,086		$	(140,182	)	$	(72,617	)	$	(92,275	)
Effective tax rate (a)	35		%	36		%	37		%	34		%

 ____________________

(a) Represents the income tax benefit or provision divided by the income or loss from continuing operations before income taxes excluding the effect of net income attributable to noncontrolling interests.

The Company files income tax returns in the U.S. federal and various state and foreign jurisdictions. With few exceptions, the Company believes that it is no longer subject to examinations by tax authorities for years before 2006. As of June 30, 2012, no adjustments had been proposed in any jurisdiction that would have a significant effect on the Company's liquidity, future results of operations or financial position.

NOTE G. Long-term Debt

The Company's long-term debt consists of senior notes and revolving credit facilities, including the effects of net deferred fair value hedge losses and issuance discounts. As of June 30, 2012, the Company and Pioneer Southwest were in compliance with all of their debt covenants.

Credit facility. During March 2011, the Company entered into a Second Amended and Restated 5-Year Revolving Credit Agreement (the "Credit Facility") with a syndicate of financial institutions that matures in March 2016, unless extended in

16

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

accordance with the terms of the Credit Facility. As of June 30, 2012, the Company had $110.0 million of outstanding borrowings under the Credit Facility and $40.1 million of undrawn letters of credit, all of which were commitments under the Credit Facility, leaving the Company with $1.1 billion of unused borrowing capacity under the Credit Facility. During July 2012, $39.0 million of the undrawn letters of credit were canceled.

Pioneer Southwest credit facility. During March 2012, Pioneer entered into an Amended and Restated 5-Year Revolving Credit Agreement (the "Pioneer Southwest Credit Facility") with a syndicate of financial institutions that matures in March 2017, unless extended in accordance with the terms of the Pioneer Southwest Credit Facility. The Pioneer Southwest Credit Facility provides for aggregate loan commitments of $300 million. As of June 30, 2012, Pioneer Southwest had $69.0 million of outstanding borrowings and $231.0 million of unused borrowing capacity under the Pioneer Southwest Credit Facility.

The Pioneer Southwest Credit Facility is available for general partnership purposes, including working capital, capital expenditures and distributions. Borrowings under the Pioneer Southwest Credit Facility may be in the form of Eurodollar rate loans, base rate committed loans or swing line loans. The Pioneer Southwest Credit Facility contains certain financial covenants, including (i) the maintenance of a quarter end maximum leverage ratio of not more than 3.5 to 1.00 and (ii) the maintenance of a ratio of the net present value of Pioneer Southwest's projected future cash flows from its oil and gas properties to total debt of at least 1.75 to 1.0.

Senior notes. During June 2012, the Company issued $600 million of 3.95% Senior Notes due 2022 and received proceeds, net of $8.5 million of offering discounts and costs, of $591.5 million. The Company used the net proceeds to reduce outstanding borrowings under the Credit Facility.

Convertible senior notes. As of June 30, 2012 and December 31, 2011, the Company had $479.9 million of 2.875% Convertible Senior Notes outstanding. The 2.875% Convertible Senior Notes are convertible under certain circumstances, using a net share settlement process, into a combination of cash and the Company's common stock based on a formula set forth in the indenture supplement pursuant to which the 2.875% Convertible Senior Notes were issued.

The Company's stock prices during March 2012 met the average price threshold that caused the Company's 2.875% Convertible Senior Notes to become convertible at the option of the holders during the following three months ended June 30, 2012. Associated therewith, certain holders of the 2.875% Convertible Senior Notes tendered $22 thousand principal amount of the notes for conversion. The Company paid certain of the tendering holders a total of $7 thousand cash and issued to the tendering holders 50 shares of the Company's common stock in May 2012 in accordance with the terms of the 2.875% Convertible Senior Notes indenture supplement. In August 2012, the Company anticipates paying the other tendering holders $15 thousand cash for the remaining notes tendered and issuing shares to be determined based upon the conversion calculation in accordance with the terms of the 2.875% Convertible Senior Notes indenture supplement.

The Company's stock prices during March 2011 met the average price threshold that caused the Company's 2.875% Convertible Senior Notes to become convertible at the option of the holders during the following three month period. Associated therewith, certain holders of the 2.875% Convertible Senior Notes tendered $70 thousand principal amount of the notes for conversion during the three months ended June 30, 2011. During the third quarter of 2011, the Company paid the tendering holders a total of $71 thousand cash, including accrued interest, and issued to the tendering holders 340 shares of the Company's common stock in accordance with the terms of the 2.875% Convertible Senior Notes indenture supplement.

During June 2012, the Company's stock price performance did not qualify the 2.875% Convertible Senior Notes for conversion at the option of the holders for the three months ended September 30, 2012. The Company's 2.875% Convertible Senior Notes may become convertible in future quarters depending on the Company's stock price or other conditions. If the 2.875% Convertible Senior Notes had qualified for and been converted as of June 30, 2012, the note holders would have received $479.9 million of cash and approximately 1.8 million  shares of the Company's common stock, which was valued at $161.0 million at June 30, 2012.

On January 15, 2013, the 2.875% Convertible Senior Notes become redeemable at the option of the Company and on January 15, 2013, January 15, 2018, January 15, 2023, January 15, 2028 and January 15, 2033 the holders may require the Company to repurchase the notes for cash. The Company has the intent and ability to fund cash payments that may be required upon the conversion, redemption or repurchase of the 2.875% Convertible Senior Notes with borrowing capacity under the Credit Facility. Accordingly, the 2.875% Convertible Senior Notes are classified as long-term debt in the accompanying balance sheets.

17

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

NOTE H. Derivative Financial Instruments

The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company also, from time to time, utilizes interest rate contracts to reduce the effect of interest rate volatility on the Company's indebtedness and forward currency exchange rate agreements to reduce the effect of exchange rate volatility.

Oil production derivative activities. All material physical sales contracts governing the Company's oil production are tied directly to, or are highly correlated with, New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI") oil prices.

The following table sets forth the volumes per day in barrels ("BBLs") outstanding as of June 30, 2012 under the Company's oil derivative contracts and the weighted average oil prices per BBL for those contracts:

	Six Months Ending December 31,			Twelve Months Ending December 31,
	2012			2013		2014
Collar contracts with short puts:
Volume (BBL) (a)	51,610			67,290		40,000
Average price per BBL:
Ceiling	$	118.73		$	120.61	$	122.77
Floor	$	84.80		$	88.88	$	91.50
Short put	$	69.12		$	71.72	$	74.88
Collar contracts:
Volume (BBL)	2,000			—		—
Average price per BBL:
Ceiling	$	127.00		$	—	$	—
Floor	$	90.00		$	—	$	—
Swap contracts:
Volume (BBL) (a)	3,000			3,000		—
Average price per BBL	$	79.32		$	81.02	$	—
Rollfactor swap contracts:
Volume (BBL)	—			6,000		—
NYMEX roll price (b)	$	—		$	0.43	$	—
Basis swap contracts:
Index swap volume (BBL)	20,000			—		—
Average price per BBL (c)	$	(1.15	)	$	—	$	—

 ____________________

(a) Subsequent to June 30, 2012, the Company entered into additional NYMEX (i) swap contracts for 8,000 BBLs per day of August 2012 through December 2012 production with a price of $93.09 per BBL and (ii) collar contracts with short puts for 5,000 BBLs per day of 2014 production with a ceiling price of $102.22 per BBL, a floor price of $95.00 per BBL and a short put price of $80.00 per BBL.

(b) Represents swaps that fix the difference between (i) each day's price per BBL of 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.

(c) Basis differential price between Midland WTI and Cushing WTI.

NGL production derivative activities. All material physical sales contracts governing the Company's NGL production are tied directly or indirectly to either Mont Belvieu or Conway fractionation facilities' NGL product component prices. As of June

18

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

30, 2012, the Company had NGL swap derivatives for 750 BBLs per day of July 2012 through December 2012 NGL sales at an average price of $35.03 per BBL and NGL collar contracts with short put derivatives for 3,000 BBLs per day of July 2012 through December 2012 sales with a ceiling price of $79.99 per BBL, a floor price of $67.70 per BBL and a short put price of $55.76 per BBL. Subsequent to June 30, 2012, the Company entered into additional NGL swap contracts for 2,000 BBLs per day of August 2012 through December 2012 production priced at $80.06 per BBL.

Gas production derivative activities. All material physical sales contracts governing the Company's gas production are tied directly or indirectly to regional index prices where the gas is sold. The Company uses derivative contracts to manage gas price volatility and reduce basis risk between NYMEX Henry Hub ("HH") prices and actual index prices at which the gas is sold.

The following table sets forth the volumes per day in millions of British thermal units ("MMBTU") outstanding as of June 30, 2012 under the Company's gas derivative contracts and the weighted average gas prices per MMBTU for those contracts:

	Six Months Ending December 31,			Twelve Months Ending December 31,
	2012			2013			2014 (a)			2015 (a)
Collar contracts with short puts:
Volume (MMBTU)	—			—			30,000			135,000
Price per MMBTU:
Ceiling	$	—		$	—		$	7.66		$	5.44
Floor	$	—		$	—		$	5.67		$	4.22
Short put	$	—		$	—		$	4.33		$	3.22
Collar contracts:
Volume (MMBTU)	65,000			150,000			80,000			50,000
Price per MMBTU:
Ceiling	$	6.60		$	6.25		$	6.39		$	7.92
Floor	$	5.00		$	5.00		$	5.00		$	5.00
Swap contracts:
Volume (MMBTU)	275,000			112,500			10,000			—
Price per MMBTU	$	4.97		$	5.62		$	6.18		$	—
Basis swap contracts:
Volume (MMBTU)	136,000			142,500			140,000			—
Price per MMBTU	$	(0.34	)	$	(0.22	)	$	(0.21	)	$	—

____________________

(a) Subsequent to June 30, 2012, the Company (i) terminated its 2014 gas derivative positions, including basis swaps, for net proceeds of $47.1 million, (ii) terminated its 2015 collar contracts for proceeds of $19.4 million and (iii) terminated 2015 collar contracts with short puts for 30,000MMBTU per day with a ceiling price of $7.11 per MMBTU, a floor price of $5.00 per MMBTU and a short put price of $4.00 per MMBTU for proceeds of $4.7 million.

Marketing and basis transfer derivative activities. Periodically, the Company enters into gas buy and sell marketing arrangements to utilize unused firm pipeline transportation commitments. Associated with these gas marketing arrangements, the Company may enter into gas index swaps to mitigate the related 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.

19

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

The following table sets forth the contract volumes outstanding as of June 30, 2012 under the Company's marketing and basis transfer derivative contracts and the weighted average gas prices per MMBTU for those contracts:

	Six Months Ending December 31,
	2012
Average Daily Gas Production Associated with Marketing Derivatives (MMBTU):
Basis swap contracts:
Index swap volume	26,739
Price differential ($/MMBTU)	$	0.25
Average Daily Gas Production Associated with Basis Transfer Derivatives (MMBTU):
Basis swap contracts:
Short index swap volume	3,343
NGI-So Cal Border Monthly price differential to NYMEX HH ($/MMBTU)	$	0.12
Long index swap volume	$	(3,343	)
IF-HSC price differential to NYMEX HH ($/MMBTU)	$	(0.05	)

Diesel derivative activities. The Company utilizes diesel derivative swap contracts to mitigate its fuel price risk associated with diesel used in Company-owned drilling rigs and fracture stimulation fleet equipment. As of June 30, 2012, the Company has diesel derivative swap contracts for 250 BBLs per day for 2013 at an average per BBL fixed price of $111.30. The diesel derivative contracts are priced at an index that is highly correlated to the prices that the Company incurs to fuel its drilling rigs and fracture stimulation fleet equipment.

Interest rates. As of June 30, 2012, the Company was a party to interest rate derivative contracts that lock in a fixed forward annual interest rate of 3.06 percent, for a 10-year period ending in August 2022, on a notional amount of $200 million. These derivative contracts mature and settle by their terms during August 2012. Subsequent to June 30, 2012, the Company terminated its 2012 interest rate swap positions at a cost of $28.4 million.

During April 2012, the Company entered into interest rate derivative contracts that lock in a fixed forward annual interest rate of 3.21 percent, 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.

Tabular disclosure of derivative financial instruments. All of the Company's derivatives are accounted for as non-hedge derivatives as of June 30, 2012 and December 31, 2011. The following tables provide disclosure of the Company's derivative instruments:

Fair Value of Derivative Instruments as of June 30, 2012
	Asset Derivatives (a)			Liability Derivatives (a)
Type	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(in thousands)			(in thousands)
Derivatives not designated as hedging instruments
Commodity price derivatives	Derivatives - current	$	318,503	Derivatives - current	$	17,108
Interest rate derivatives	Derivatives - current	—		Derivatives - current	23,283
Commodity price derivatives	Derivatives - noncurrent	270,681		Derivatives - noncurrent	16,127
Interest rate derivatives	Derivatives - noncurrent	—		Derivatives - noncurrent	11,410
		$	589,184		$	67,928

20

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

Fair Value of Derivative Instruments as of December 31, 2011
	Asset Derivatives (a)			Liability Derivatives (a)
Type	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(in thousands)			(in thousands)
Derivatives not designated as hedging instruments
Commodity price derivatives	Derivatives - current	$	248,809	Derivatives - current	$	68,735
Interest rate derivatives	Derivatives - current	—		Derivatives - current	15,654
Commodity price derivatives	Derivatives - noncurrent	257,368		Derivatives - noncurrent	47,689
		$	506,177		$	132,078

 ___________________

(a) Derivative assets and liabilities shown in the tables above are presented as gross assets and liabilities, without regard to master netting arrangements which are considered in the presentations of derivative assets and liabilities in the accompanying consolidated balance sheets.

Derivatives in Cash Flow Hedging	Location of Gain/(Loss) Reclassified from	Amount of Gain/(Loss) Reclassified from AOCI into Earnings
		Three Months Ended June 30,						Six Months Ended June 30,
Relationships	AOCI into Earnings	2012			2011			2012			2011
		(in thousands)
Commodity price derivatives	Oil and gas revenue	$	(2,347	)	$	8,208		$	(3,156	)	$	16,332
Interest rate derivatives	Interest expense	—			(69		)	(1,699		)	(137		)
Total		$	(2,347	)	$	8,139		$	(4,855	)	$	16,195

		Amount of Gain (Loss) Recognized in Earnings on Derivatives
Derivatives Not Designated as Hedging	Location of Gain (Loss) Recognized in	Three Months Ended June 30,					Six Months Ended June 30,
Instruments	Earnings on Derivatives	2012			2011		2012			2011
		(in thousands)
Commodity price derivatives	Derivative gains (losses), net	$	298,471		$	214,903	$	386,601		$	(27,377	)
Interest rate derivatives	Derivative gains (losses), net	(22,659		)	14,575		(19,039		)	12,423
Total		$	275,812		$	229,478	$	367,562		$	(14,954	)

AOCI - Hedging. As of December 31, 2011, the Company had $3.2 million and $1.7 million of net deferred losses on the effective portions of discontinued oil and interest rate hedges, respectively, and $1.8 million of associated net deferred tax benefits classified in AOCI—Hedging in the accompanying consolidated balance sheet. During the six months ended June 30, 2012, the Company transferred the respective AOCI - Hedging balances to oil revenue, interest expense and income tax provisions.

Derivative counterparties. The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company's credit risk policies and procedures.

21

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

The following table provides the Company's derivative assets and liabilities by counterparty as of June 30, 2012:

	Assets		Liabilities
	(in thousands)
JP Morgan Chase	$	119,358	$	15,217
Citibank, N.A.	87,788		438
Barclays Capital	53,131		—
BMO Financial Group	42,192		—
BNP Paribas	40,677		—
J. Aron & Company	33,071		—
Wells Fargo Bank, N.A.	31,419		20,981
Credit Suisse	29,795		—
Toronto Dominion	29,206		—
Credit Agricole	28,179		2,177
Societe Generale	24,356		—
Merrill Lynch	16,880		2,775
Morgan Stanley	16,184		885
Den Norske Bank	9,790		—
BP Corporation North America	4,040		—
Deutsche Bank	2,194		2,363
Vitol	1,345		—
Macquarie Bank	86		—
Royal Bank of Canada	—		262
UBS	—		3,337
Total	$	569,691	$	48,435

NOTE I. Asset Retirement Obligations

The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells, restoration of certain sand mines and related facilities. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company's credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations.

22

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

The following table summarizes the Company's asset retirement obligation activity during the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)
Beginning asset retirement obligations	$	134,314		$	154,689		$	136,742		$	152,291
Liabilities assumed in acquisitions	8,515			—			8,515			6
New wells placed on production	1,581			1,404			2,411			2,075
Changes in estimates	1,603			(179		)	1,603			121
Disposition of wells	—			(367		)	—			(448		)
Liabilities settled	(3,054		)	(6,235		)	(8,742		)	(7,469		)
Accretion of discount from continuing operations	2,444			2,048			4,874			4,092
Accretion of discount from integrated services (a)	54			—			54			—
Accretion of discount from discontinued operations	—			610			—			1,302
Ending asset retirement obligations	$	145,457		$	151,970		$	145,457		$	151,970

_____________________

(a) Accretion of discount from integrated services includes Premier Silica accretion expense, which is recorded as a reduction in third-party income from vertical integration services in interest and other income in the Company's accompanying consolidated statements of operations. See Note M for more information about interest and other income.

The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets. As of June 30, 2012 and December 31, 2011, the current portions of the Company's asset retirement obligations were $18.6 million and $14.2 million, respectively.

NOTE J. Incentive Plans

Stock-based compensation

For the three and six months ended June 30, 2012, the Company recorded $21.7 million and $43.3 million, respectively, of stock-based compensation expense for all plans, as compared to $13.8 million and $26.4 million for the same respective periods of 2011. As of June 30, 2012, there was $156.0 million of unrecognized compensation expense related to unvested share- and unit-based compensation plan awards, including $27.0 million attributable to stock-based awards that are expected to be settled in cash on their vesting date, rather than in equity shares ("Liability Awards"). This compensation will be recognized over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis. As of June 30, 2012 and December 31, 2011, accounts payable – due to affiliates includes $8.2 million and $9.2 million, respectively, of liabilities attributable to Liability Awards.

The Company's issued shares, as reflected in the consolidated balance sheets at June 30, 2012 and December 31, 2011, do not include 304,260 and 533,125 common shares, respectively, associated with unvested stock-based compensation awards that have voting rights.

23

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

The following table summarizes the activity that occurred during the six months ended June 30, 2012, for each type of share-based incentive award issued by Pioneer:

	Restricted Stock Equity Awards		Restricted Stock Liability Awards		Performance Units	Stock Options		Pioneer Southwest LTIP Restricted Units		Pioneer Southwest LTIP Phantom Units
Outstanding at December 31, 2011	1,857,612		322,925		114,128	564,044		7,492		65,157
Awards granted	897,591		223,375		47,875	98,819		7,496		37,487
Awards vested	(1,199,536	)	(115,700	)	—	—		(7,492	)	—
Options exercised	—		—		—	(64,509	)	—		—
Awards forfeited	(15,145	)	(10,342	)	—	—		—		—
Outstanding as of June 30, 2012	1,540,522		420,258		162,003	598,354		7,496		102,644

Postretirement Benefit Obligations

As of June 30, 2012 and December 31, 2011, the Company had $8.5 million and $7.5 million, respectively, of unfunded accumulated postretirement benefit obligations, the current and noncurrent portions of which are included in other current liabilities and other liabilities in the accompanying consolidated balance sheets. These obligations are comprised of five unfunded plans, of which four relate to predecessor entities that the Company acquired in prior years, and two funded plans that the Company assumed sponsorship for in conjunction with the acquisition of Premier Silica.

The unfunded plans had no assets as of June 30, 2012 or December 31, 2011. The Company's funding policy for the Premier Silica plans is to contribute amounts sufficient to meet legal funding requirements, plus any additional amounts that the Company may determine to be appropriate considering the funded status of the plan, tax deductibility, the cash flow generated by the Company, and other factors. The Company continually reassesses the amount and timing of any discretionary contributions and could elect to make such a contribution in 2012.

NOTE K. Commitments and Contingencies

The Company is a party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

NOTE L. Net Income (Loss) Per Share

The Company uses the two-class method of calculating net income (loss) per share because certain of the Company's and its consolidated subsidiaries' unvested share-based awards qualify as participating securities. Participating securities participate in the Company's dividend distributions and are assumed to participate in the Company's undistributed income proportionate to weighted average outstanding common shares, but are not assumed to participate in the Company's net losses because they are not contractually obligated to do so. Accordingly, allocations of earnings to participating securities are included in the Company's calculations of basic and diluted earnings per share from continuing operations, discontinued operations and net income attributable to common stockholders.

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 from continuing operations; therefore, conversion into common stock is assumed not to occur.

24

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

The following tables reconcile the Company's net income (loss) attributable to common stockholders to basic net income (loss) attributable to common stockholders and diluted net income (loss) attributable to common stockholders for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30, 2012								Six Months Ended June 30, 2012
	Continuing Operations			Discontinued Operations		Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income (loss) attributable to common stockholders	$	(82,409	)	$	12,017	$	(70,392	)	$	121,515		$	22,712		$	144,227
Participating basic earnings	(265		)	—		(265		)	(1,833		)	(343		)	(2,176		)
Basic net income (loss) attributable to common stockholders	(82,674		)	12,017		(70,657		)	119,682			22,369			142,051
Reallocation of participating earnings	—			—		—			130			24			154
Diluted income (loss) attributable to common stockholders	$	(82,674	)	$	12,017	$	(70,657	)	$	119,812		$	22,393		$	142,205

	Three Months Ended June 30, 2011									Six Months Ended June 30, 2011
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income (loss) attributable to common stockholders	$	248,602		$	(3,025	)	$	245,577		$	177,314		$	416,857		$	594,171
Participating basic earnings	(4,847		)	—			(4,847		)	(3,238		)	(7,611		)	(10,849		)
Basic net income (loss) attributable to common stockholders	243,755			(3,025		)	240,730			174,076			409,246			583,322
Reallocation of participating earnings	164			—			164			81			190			271
Diluted income (loss) attributable to common stockholders	$	243,919		$	(3,025	)	$	240,894		$	174,157		$	409,436		$	583,593

25

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,		Six Months Ended June 30,
	2012	2011	2012	2011
	(in thousands)
Weighted average common shares outstanding:
Basic	123,028	116,213	122,754	116,042
Dilutive common stock options (a)	—	178	205	188
Convertible senior notes dilution (a)	—	1,772	2,642	2,333
Contingently issuable performance unit shares (a)	—	429	171	423
Diluted	123,028	118,592	125,772	118,986

 ____________________

(a) The following common share equivalents were excluded from the weighted average diluted shares for the three months ended June 30, 2012 because they would have been anti-dilutive to the loss recorded for the period: 206,495 outstanding options to purchase the Company's common stock, 184,236 common shares attributable to unvested performance units and 1,825,147 common shares issuable if holders of the Company's 2.875% Convertible Senior Notes had exercised their conversion rights (see Note G). Options to purchase 185,772 shares of the Company's common stock were excluded from the diluted income per share calculations for the six months ended June 30, 2012 because they would have been anti-dilutive to the calculation.

NOTE M. Interest and Other Income

The following table provides the components of the Company's interest and other income:

	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012		2011
	(in thousands)
Equity in income of unconsolidated affiliate (a)	$	7,861		$	502	$	14,842	$	801
Alaskan Petroleum Production Tax credits and refunds (b)	—			—		11,846		27,452
Third-party income (loss) from vertical integration services (c)	(3,820		)	8,881		2,729		7,913
Other income	592			3,698		2,234		4,334
Deferred compensation plan income	150			299		1,523		1,166
Interest income	1,260			214		1,317		401
Total interest and other income	$	6,043		$	13,594	$	34,491	$	42,067

 ____________________

(a) Represents the Company's equity in the earnings of EFS Midstream LLC ("EFS Midstream"), which owns and operates gas and liquids gathering, treating and transportation assets in the Eagle Ford Shale area of South Texas.

(b) The Company earns Alaskan Petroleum Production Tax ("PPT") credits on qualifying capital expenditures. The Company recognizes income from PPT credits when they are realized through cash refunds or as reductions in production and ad valorem taxes if realizable as offsets to PPT expense.

(c) Third-party income (loss) from vertical integration services represents third-party working interests' share of earnings associated with Company-provided fracture stimulation, drilling and related services.

26

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

NOTE N. Other Expense

The following table provides the components of the Company's other expense:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012		2011
	(in thousands)
Transportation commitment charges (a)	$	9,227		$	5,688		$	17,680	$	10,960
Above market drilling rig rates (b)	5,760			5,410			10,746		10,569
Terminated drilling rig contract charges (c)	8,960			—			8,960		—
Inventory valuation charges (d)	1,262			302			7,454		587
Other	4,578			(934		)	6,346		2,549
Premier Silica acquisition costs	1,190			—			2,173		—
Contingency and environmental accrual adjustments	(326		)	1,587			702		2,882
Loss on extinguishment of debt	—			—			197		2,367
Total other expense	$	30,651		$	12,053		$	54,258	$	29,914

 ____________________

(a) Primarily represents firm transportation payments on excess pipeline capacity commitments.

(b) Primarily represents expenses attributable to the portion of Pioneer's contracted drilling rig rates that are above current market rates and idle drilling rig fees, neither of which are charged to joint operations.

(c) Primarily represents charges to terminate rig contracts that are not required to meet planned drilling activities.

(d) Represents valuation charges on excess materials and supplies inventories; principally related to dry gas assets.

NOTE O. Impairment

The Company reviews its long-lived assets for impairment, including oil and gas properties, whenever events or circumstances indicate their carrying values may not be fully recoverable. During the past year, reductions in management's outlook for commodity prices have provided indications of possible impairment of the Company's predominately dry gas properties in the Edwards Trend and Austin Chalk fields in South Texas, the Barnett Shale field in North Texas and the Raton field in Southeastern Colorado. As a result of management's assessments, during the fourth quarter of 2011 and second quarter of 2012, the Company recognized pretax noncash impairment charges of $354.4 million and $444.9 million, respectively, to reduce the carrying value of the Edwards Trend/Austin Chalk fields and the Barnett Shale field to their estimated fair values. The Company calculated the estimated fair value of the Barnett Shale field as of June 30, 2012 using a discounted cash flow model. Significant Level 3 assumptions associated with the calculation of discounted cash flows include management's outlook for (i) oil and gas prices of $87.09 per BBL for oil and $4.64 per MCF of gas, (ii) production costs, (iii) capital expenditures and (iv) production and estimated proved reserves and risk-adjusted probable reserves. Management's commodity price outlooks represent longer-term outlooks that are developed based on third-party futures price outlooks as of a measurement date. The expected future net cash flows were discounted using an annual rate of 10 percent to determine estimated fair value.

Impairment risk. The Company's estimates of undiscounted future net cash flows attributable to the Raton field's gas properties indicated on June 30, 2012 that its carrying amount was expected to be recovered. However, the carrying value of this field continues to be at risk for impairment if future estimates of undiscounted cash flows decline. As of June 30, 2012, the Company's Raton field has a carrying value of $2.3 billion.

It is reasonably possible that the estimate of undiscounted future net cash flows attributable to this or other properties may change in the future resulting in the need to impair their carrying values. The primary factors that may affect estimates of futures cash flows are (i) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, (ii) results of future drilling activities, (iii) management's commodity price outlooks and (iv) increases or decreases in production and capital costs associated with the fields.

27

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(Unaudited)

NOTE P. Subsequent Event

Distribution declaration. In July 2012, Pioneer Southwest declared a cash distribution of $0.52 per common unit for the period from April 1, 2012 to June 30, 2012. The distribution is payable on August 9, 2012 to unitholders of record at the close of business on August 2, 2012. Associated therewith, Pioneer Southwest expects to pay $18.6 million of aggregate distributions.

28

PIONEER NATURAL RESOURCES COMPANY

Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations

Financial and Operating Performance

The Company's financial and operating performance for the second quarter of 2012 included the following highlights:

• Earnings attributable to common stockholders was a net loss of $70.4 million ($0.57 per diluted share), as compared to net income attributable to common stockholders of $245.6 million ($2.03 per diluted share) for the second quarter of 2011. The decrease in earnings attributable to common stockholders is primarily comprised of a $331.0 million decrease in earnings from continuing operations, which includes:

▪ a $444.9 million pretax charge for impairment of oil and gas properties in the Barnett Shale field associated with reductions in management's commodity price outlook (see Note O of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Results of Operations," below);

▪ a $55.1 million increase in oil and gas production costs, primarily due to increases in variable lease operating expenses and third-party transportation fees due to higher sales volumes and a decrease in revenues attributable to processing third-party gas volumes in Company-owned facilities;

▪ a $65.4 million increase in DD&A, primarily due to increased sales volumes;

▪ an $18.6 million increase in other expense, primarily associated with $9.0 million of drilling rig contract termination fees and a $3.5 million increase in unused firm transportation costs; and

▪ a $17.4 million increase in exploration and abandonments expense, primarily associated with an $8.5 million increase in unproved leasehold abandonments and a $7.6 million increase in geological and geophysical costs; partially offset by

▪ $185.3 million of incremental income tax benefits associated with the loss from continuing operations;

▪ a $79.3 million increase in oil and gas revenues as a result of an increase in sales volumes, partially offset by lower average commodity prices; and

▪ a $46.3 million increase in net derivative gains from net derivative settlements and unrealized mark-to-market adjustments.

• During the second quarter of 2012, average daily sales volumes increased by 32 percent to 150,506 BOEPD, as compared to 113,937 BOEPD during the second quarter of 2011. The increase in second quarter 2012 average daily sales volumes, as compared to the second quarter of 2011, was primarily due to the Company's successful drilling program during the last six months of 2011 and the first half of 2012;

• Average reported oil, NGL and gas prices decreased during the second quarter of 2012 to $88.32 per BBL, $32.62 per BBL and $2.00 per MCF, respectively, as compared to $104.34 per BBL, $48.16 per BBL and $4.11 per MCF, respectively, in the second quarter of 2011;

• Average oil and gas production costs per BOE increased to $11.45 for the second quarter of 2012, as compared to $9.81 for the second quarter of 2011, primarily due to a decrease in revenues attributable to processing third-party gas volumes in Company-owned facilities as a result of lower gas and NGL prices and an increase in third party transportation and processing charges associated with increasing Eagle Ford Shale production (see "Results of Operations," below, for more information about changes in production costs);

• Net cash provided by operating activities increased to $499.3 million for the three months ended June 30, 2012, as compared to $421.2 million for the three months ended June 30, 2011. The $78.1 million increase in net cash provided by operating activities was primarily due to increases in oil and gas sales volumes and realized derivative gains;

• During April 2012, the Company acquired 100 percent of the share capital of Industrial Sands Holding Company and its wholly-owned subsidiary, Oglebay Norton Industrial Sands, LLC. The Company changed the name of Oglebay Norton Industrial Sands, LLC to Premier Silica LLC ("Premier Silica") in April 2012. Premier Silica's core business is the operation of mines and processing facilities that produce, process and sell sand, primarily to upstream oil and gas companies for proppant used in the fracture stimulation of oil and gas wells in the United States. The aggregate purchase price of Premier Silica was $296.0 million, including estimated closing adjustments, and was funded from available cash and borrowings under the Company's credit facility;

• During June 2012, the Company issued $600 million of 3.95% Senior Notes due 2022 and received proceeds, net of $8.5 million of offering discounts and costs, of $591.5 million. The Company used the net proceeds to reduce outstanding borrowings under its credit facility;

29

PIONEER NATURAL RESOURCES COMPANY

• As of June 30, 2012, the Company's net debt to book capitalization was 34 percent, as compared to 26 percent as of December 31, 2011. The Company was upgraded to investment grade by one of its debt rating agencies during the fourth quarter of 2011 and by another agency during the second quarter of 2012;

• In June and July 2012, the Company liquidated swap, collar and three-way collar derivatives for 250,000 MMBTUPD of 2014 gas production and 80,000 MMBTUPD of 2015 gas production. These liquidated volumes represent 100 percent and 43 percent of Pioneer's gas derivative positions in 2014 and 2015, respectively. The Company also liquidated 140,000 MMBTUPD of gas basis swaps for 2014. As a result of these liquidations, the Company realized $143.1 million of net cash proceeds, of which $71.9 million was realized during June 2012 and $71.2 million was realized during July 2012.

Third Quarter 2012 Outlook

Based on current estimates, the Company expects the following operations and financial results for the quarter ending September 30, 2012:

Production is forecasted to average 155,000 to 159,000 BOEPD.

Production costs (including production and ad valorem taxes and transportation costs) are expected to average $13.50 to $15.50 per BOE based on current NYMEX strip prices for oil, NGLs and gas. DD&A expense is expected to average $13.00 to $15.00 per BOE.

Total exploration and abandonment expense is expected to be $25 million to $40 million. General and administrative expense is expected to be $55 million to $60 million. Interest expense is expected to be $51 million to $56 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' net income, excluding noncash mark-to-market adjustments, is expected to be $9 million to $12 million, primarily reflecting the public ownership in Pioneer Southwest.

The Company's effective income tax rate, excluding the effect of net income attributable to noncontrolling interest, is expected to range from 35 percent to 40 percent, assuming current capital spending plans and no significant mark-to-market changes in the Company's derivative position. Cash income taxes are expected to range from $5 million to $10 million, primarily attributable to alternative minimum tax and state taxes.

Operations and Drilling Highlights

The following table summarizes the Company's average daily oil, NGL, gas and total production by asset area during the six months ended June 30, 2012:

	Oil (BBLs)	NGLs (BBLs)	Gas (MCF)	Total (BOE)
Permian Basin	42,117	12,092	59,530	64,130
Raton Basin	—	—	153,397	25,566
South Texas - Eagle Ford Shale	8,852	5,639	53,130	23,346
Mid-Continent	3,198	6,856	48,251	18,096
South Texas - Edwards and Austin Chalk	71	1	38,642	6,513
Barnett Shale	1,024	2,631	17,997	6,654
Alaska	4,285	—	—	4,285
Other	3	3	121	27
	59,550	27,222	371,068	148,617

During 2012 and 2011, the Company has focused its capital budget expenditures on oil- and liquids-rich-gas drilling activities as a result of the decline in gas prices. As a result of these capital activities and commodity price changes, the Company's total liquids production and revenue from continuing operations has increased to 58 percent and 89 percent, respectively, for the six months ended June 30, 2012 from 50 percent and 77 percent, respectively, for the same period last year.

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PIONEER NATURAL RESOURCES COMPANY

The following table summarizes by geographic area the Company's finding and development costs incurred from continuing operations during the six months ended June 30, 2012:

	Acquisition Costs					Exploration		Development		Asset Retirement
	Proved		Unproved			Costs		Costs		Obligations		Total
	(in thousands)
Permian Basin	$	1,942	$	51,098		$	141,310	$	932,518	$	1,592	$	1,128,460
Raton Basin	49		(23		)	4,401		6,122		—		10,549
South Texas - Eagle Ford Shale	—		4,901			90,328		3,546		32		98,807
Mid-Continent	—		2,318			2,944		6,737		—		11,999
South Texas - Edwards and Austin Chalk	—		207			2,835		4,478		—		7,520
Barnett Shale	5,012		5,005			112,416		27,102		175		149,710
Alaska	—		—			60,346		55,934		2,256		118,536
Other	—		33,250			1,014		6		—		34,270
	$	7,003	$	96,756		$	415,594	$	1,036,443	$	4,055	$	1,559,851

The following table summarizes the Company's development and exploration/extension drilling activities for the six months ended June 30, 2012:

	Development Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells in Progress
Permian Basin	161	362	426	7	90
Raton Basin	5	—	4	—	1
Barnett Shale	—	2	2		—
Alaska	1	2	2	—	1
Total United States	167	366	434	7	92

	Exploration/Extension Drilling
	Beginning Wells in Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells in Progress
Permian Basin	—	20	5	—	15
South Texas - Eagle Ford Shale	39	63	64	—	38
Mid-Continent	5	—	—	5	—
Barnett Shale	26	16	22	—	20
Alaska	1	2	1	1	1
Total United States	71	101	92	6	74

Permian Basin area. The Company currently has 34 rigs operating in the Spraberry field, of which 30 are drilling vertical wells and four are drilling Wolfcamp Shale horizontal wells. The Company plans to operate 27 to 30 vertical rigs during the remainder of 2012 and increase its horizontal Wolfcamp Shale rig count to seven near year end. During 2012, the Company expects to drill approximately 660 vertical wells and 35 to 40 horizontal Wolfcamp Shale wells. During the six months ended June 30, 2012, the Company completed 435 vertical wells and three horizontal Wolfcamp Shale wells.

In the horizontal Wolfcamp Shale play, the Company believes it has significant resource potential within its acreage based on its extensive geologic data covering the Wolfcamp A, B, C and D intervals and its drilling results to-date. The Company's horizontal drilling activity for the remainder of 2012 will be focused on the 200,000 acres in the southern part of the play to hold expiring acreage. The Company plans to continue drilling in the B interval and to test the A interval in this area. Pioneer's first two A interval wells have been drilled and are awaiting completion.

The Company expects to drill approximately 90 horizontal wells in the southern part of the play by the end of 2013 to hold approximately 50,000 expiring acres, with 30 to 35 horizontal wells being drilled in 2012. During the fourth quarter of 2012, the Company plans to begin delineating the northern part of its Spraberry acreage position by drilling in Midland, Martin and Gaines Counties. Wells drilled in this area are expected to benefit from greater original oil in place and higher reservoir pressures associated with deeper drilling depths compared to the southern part of the play. Pioneer believes a successful drilling program in this area could substantially increase its prospective horizontal Wolfcamp Shale acreage position.

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PIONEER NATURAL RESOURCES COMPANY

The Company plans 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. The Company plans to offer a 33 percent to 50 percent working interest in the southern acreage. No assurance can be provided that the Company will be successful in attracting a joint venture partner or that a joint venture partner will offer an acquisition price that is acceptable to the Company.

The Company continues to drill vertically to deeper intervals in the Spraberry field below the Wolfcamp interval. This deeper drilling includes the Strawn, Atoka and Mississippian intervals. Production from these deeper intervals has contributed significantly to the Company's production growth (see "Results of Operations" below). The original 2012 drilling program planned for the Wolfcamp to be the deepest interval completed in approximately 50 percent of the wells. The remaining 50 percent of the wells were to be deepened below the Wolfcamp interval. The latest drilling program now reflects 65 percent of the wells being deepened below the Wolfcamp interval. Based on results to-date, the Company estimates that 70 percent of its Spraberry acreage position is prospective for the Strawn interval and that 40 percent to 50 percent of its acreage position is prospective for the Atoka interval. The Company continues to believe the Mississippian interval is prospective in 20 percent of its Spraberry acreage.

The Company continues to expand its integrated services to control drilling costs and support the execution of its accelerating drilling program. The Company has 15 Company-owned drilling rigs, five Company-owned vertical fracture stimulation fleets and two Company-owned horizontal fracture stimulation fleets currently operating in the Spraberry field. To support its growing operations, the Company also owns other field service equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. In addition, the Company has contracted for tubular and pumping unit requirements through 2012 and well cementing services through 2016.

In early April 2012, the Company completed the acquisition of Premier Silica, which is expected to supply the Company's growing brown sand requirements for fracture stimulating wells in the vertical Spraberry and horizontal Wolfcamp Shale plays along with the Barnett Shale Combo play.

Eagle Ford Shale area. The Company's drilling activities in the South Texas area during 2012 continue to be primarily focused on delineation and development of Pioneer's substantial acreage position in the Eagle Ford Shale play. The 2012 drilling program will continue to focus on liquids-rich drilling, with only 10 percent of the wells designated to hold strategic dry gas acreage.

The Company completed 64 horizontal Eagle Ford Shale wells during the first six months of 2012, all of which were successful, with average lateral lengths of approximately 5,500 feet and, on average, 13-stage fracture stimulations. The Company is currently running 12 drilling rigs and three fracture stimulation fleets, two of which are Pioneer-owned fleets, in the play.

To improve the execution of its drilling and completions program and reduce costs, the Company is testing the use of lower-cost white sand instead of ceramic proppant to fracture stimulate wells drilled in shallower areas of the field. Early well performance has been similar to direct offset ceramic-stimulated wells. The Company plans to continue to monitor the performance of these wells and plans to use white sand in 50 percent of its 2012 drilling program.

The unconsolidated affiliate formed by the Company to operate gathering facilities in the Eagle Ford Shale area, EFS Midstream, is obligated to construct midstream assets in the Eagle Ford Shale area. Eleven of the 13 planned central gathering plants ("CGPs") were completed as of June 30, 2012. Additionally, EFS Midstream plans to replace one CGP that is currently in operation with a larger, higher capacity CGP within five years. EFS Midstream is providing gathering, treating and transportation services for the Company during a 20-year contractual term. During 2011, EFS Midstream entered into a $300 million, five-year revolving credit facility that is being used to fund infrastructure investments that exceed its operating cash flows.

Alaska. The Company owns a 70 percent working interest in, and is the operator of, the Oooguruk development project. Since inception, the Company has drilled 15 production wells and nine injection wells to develop this project. During the first quarter of 2012, the Company drilled two exploration wells, the first of which was drilled from an onshore location to further evaluate the productivity of the Torok formation and the feasibility of future development expansion.  The Company flow tested the well during April 2012 until production could no longer be transported along the ice road being utilized. The well was successful with a gross initial production rate of approximately 2,000 barrels of oil per day, which was constrained due to surface facility capacity limitations. Based on the better than expected production results from this well, the Company plans to drill an appraisal well during the first quarter of 2013 to further delineate the discovery. The second exploration well was drilled from an ice pad on the west side of the Oooguruk unit to test the Ivishak formation, which is the main producing horizon in the Prudhoe Bay field.  This well was non-commercial and was plugged and abandoned.

The Company also tested a new fracture stimulation design on new wells completed in the Nuiqsut and Torok intervals from the Oooguruk development facilities. Gross production from the Nuiqsut well averaged approximately 3,000 barrels of oil per day during the second quarter. The Company plans to drill up to four additional Nuiqsut wells over the remainder of 2012 that will be

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PIONEER NATURAL RESOURCES COMPANY

similarly fracture stimulated this winter.

Barnett Shale. During the first six months of 2012, the Company had two drilling rigs and one Pioneer-owned fracture stimulation fleet operating in the field and completed 24 Barnett Shale Combo wells, all of which were successful. During August 2012, the Company plans to reduce to one drilling rig as a result of lower NGL and gas prices. In total, the Company has accumulated over 93,000 gross acres in the liquid-rich area of the field and has acquired approximately 340 square miles of proprietary 3-D seismic covering its acreage, which it is using to high-grade future drilling location selections.

Results of Operations from Continuing Operations

Oil and gas revenues. Oil and gas revenues totaled $641.7 million and $1.4 billion for the three and six months ended June 30, 2012, respectively, as compared to $562.4 million and $1.0 billion for the same respective periods in 2011.

The increase in oil and gas revenues during the three months ended June 30, 2012, as compared to the same period in 2011, is reflective of 71 percent, 23 percent and 10 percent increases in daily oil, NGL and gas sales volumes, respectively. Partially offsetting the effects of these production increases in the quarter-to-quarter comparison were declines of 15 percent, 32 percent and 51 percent in reported oil, NGL and gas prices, respectively. The increase in oil and gas revenues during the six months ended June 30, 2012, as compared to the same period in 2011, is reflective of 71 percent, 34 percent and 12 percent increases in daily oil, NGL and gas sales volumes, respectively. Partially offsetting the effects of these production increases in the six month comparisons were declines of six percent, 18 percent and 44 percent in reported oil, NGL and gas prices, respectively.

The following table provides average daily sales volumes for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,		Six Months Ended June 30,
	2012	2011	2012	2011
Oil (BBLs)	61,428	35,872	59,550	34,904
NGLs (BBLs)	26,960	21,839	27,222	20,251
Gas (MCF)	372,713	337,354	371,068	331,295
Total (BOE)	150,506	113,937	148,617	110,371

Average daily BOE sales volumes increased by 32 percent and 35 percent for the three and six months ended June 30, 2012, as compared to the same respective periods in 2011, principally due to the Company's successful drilling program. However, the production growth for the three and six months ended June 30, 2012, as compared to the same periods in 2011, would have been higher had production not been negatively impacted during the second quarter of 2012 by approximately 4,800 BOEPD due to unplanned third-party NGL fractionation downtime and NGL fractionation capacity limitations at Mont Belvieu, Texas. Specifically, portions of the Company's gas production include NGLs that are separated at the Midkiff/Benedum and Sale Ranch gas processing facilities in West Texas. These NGLs are then transported to third-party fractionation facilities at Mont Belvieu. During May, a significant third-party facility was shut down for planned maintenance. When the facility came back on line in late May, it had operating problems and was not able to achieve its pre-shutdown fractionation capacity. As a result of this problem and the fractionation capacity limitations across the Mont Belvieu complex, the Company built an NGL inventory of 256 thousand barrels that could not be processed for sale in June, thereby negatively impacting production for the second quarter by approximately 2,800 BOEPD. Within the next month, the fractionation facility is expected to increase processing rates to its pre-shutdown processing capacity, thereby allowing the Company's NGL inventory and ongoing production to be fractionated and sold over the remainder of 2012.

The Midkiff/Benedum gas processing plants were also forced to reject ethane into the residue gas stream during the second quarter of 2012 as a result of the NGL capacity limitations at Mont Belvieu. The net impact of rejecting ethane was a loss in production of approximately 2,000 BOEPD. Ethane rejection continues and is expected to impact the Company's production over the remainder of 2012 based on the outlook for continuing tight fractionation capacity at Mont Belvieu. Due to low ethane prices, there is not a significant economic impact to rejecting ethane versus recovering and selling it. Pioneer estimates that its revenues are lower as a result of ethane rejection by approximately $18 thousand per day at current gas and NGL prices.

The oil, NGL and gas prices that the Company reports are based on the market prices received for the commodities adjusted for transfers of the Company's deferred hedge gains and losses from AOCI-Hedging and the amortization of deferred VPP revenue. See "Derivative activities" and "Deferred revenue" discussion below for additional information regarding the Company's past cash flow hedging activities and the amortization of deferred VPP revenue.

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PIONEER NATURAL RESOURCES COMPANY

The following table provides the Company's average reported prices (including transfers of deferred hedge gains and losses and the amortization of deferred VPP revenue) and average realized prices (excluding transfers of deferred hedge gains and losses and the amortization of deferred VPP revenue) for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Average reported prices:
Oil (per BBL)	$	88.32	$	104.34	$	94.45	$	100.05
NGL (per BBL)	$	32.62	$	48.16	$	37.26	$	45.42
Gas (per MCF)	$	2.00	$	4.11	$	2.26	$	4.00
Total (per BOE)	$	46.86	$	54.24	$	50.31	$	51.97
Average realized prices:
Oil (per BBL)	$	86.87	$	98.39	$	92.81	$	93.93
NGL (per BBL)	$	32.62	$	48.16	$	37.26	$	45.42
Gas (per MCF)	$	2.00	$	4.11	$	2.26	$	4.00
Total (per BOE)	$	46.26	$	52.37	$	49.65	$	50.03

Derivative activities. The primary purposes for which the Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts are to (i) reduce the effect of price volatility on the commodities the Company produces, sells and consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. During the three and six months ended June 30, 2012, the Company transferred $2.3 million and $3.2 million, respectively, of deferred oil hedge losses from AOCI-Hedging to oil revenue, as compared to transferring $8.2 million and $16.3 million of deferred oil hedge gains, respectively, from AOCI-Hedging to oil revenue during the same respective periods in 2011.

Deferred revenue. During the three and six months ended June 30, 2012, the Company's amortization of deferred VPP revenue increased oil revenues by $10.4 million and $20.9 million as compared to an increase of $11.2 million and $22.3 million during the same respective periods in 2011.

Derivative gains, net. During the three months ended June 30, 2012, the Company recorded $275.8 million of net derivative gains on commodity price and interest rate derivatives, of which $119.1 million represented unrealized net gains and $156.7 million represented realized net gains. During the six months ended June 30, 2012, the Company recorded $367.6 million of net derivative gains on commodity price and interest rate derivatives, of which $147.2 million represented unrealized net gains and $220.4 million represented realized net gains. During the three and six months ended June 30, 2011, the Company recorded $229.5 million of net derivative gains and $15.0 million of net derivative losses, respectively. Derivative gains and losses result from changes in the fair values of the Company's derivative contracts. In June 2012 and July 2012, the Company liquidated swap, collar and three-way collar derivatives for 250,000 MMBTUPD of 2014 gas production and 80,000 MMBTUPD of 2015 gas production. These liquidated volumes represented 100 percent and 43 percent of Pioneer's gas derivative positions in 2014 and 2015, respectively. The Company also liquidated 140,000 MMBTUPD of gas basis swaps for 2014. As a result of these liquidations, the Company realized approximately $143.1 million of net cash proceeds, of which $71.9 million was realized during June 2012 and $71.2 million was realized during July 2012. See Notes E and H of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information regarding the Company's derivative activities and market risks associated with those activities.

Interest and other income. Interest and other income for the three and six months ended June 30, 2012 was $6.0 million and $34.5 million, respectively, as compared to $13.6 million and $42.1 million, respectively, for the same periods in 2011. The $7.6 million decrease in interest and other income during the three months ended June 30, 2012, as compared to the same period in 2011, was primarily due to a $12.7 million decrease in third-party income from vertical integration services, partially offset by a $7.4 million increase in equity earnings from EFS Midstream. The $7.6 million decrease in interest and other income during the six months ended June 30, 2012, as compared to the same period in 2011, was primarily due to a $15.6 million decrease in Alaskan PPT credit recoveries and a $5.2 million decrease in third-party income from vertical integration services, partially offset by a $14.0 million increase in equity earnings from EFS Midstream. See Note M of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding interest and other income.

Gain (Loss) on disposition of assets, net. The Company recorded net gains on the disposition of assets of $1.1 million and $44.7 million, respectively, during the three and six months ended June 30, 2012 as compared to net losses on the disposition of assets of $296 thousand and $2.5 million, respectively, for the same periods of 2011. The net gain for the three months ended June 30, 2012 is primarily associated with sales of transportation equipment. The net gain for the six months ended June 30, 2012 is

34

PIONEER NATURAL RESOURCES COMPANY

primarily attributable to the Company's sale of a portion of its working interest in an unproved oil and gas property in the Eagle Ford Shale to unaffiliated third parties. The net losses for the three and six months ended June 30, 2011 were primarily associated with sales of excess materials and supplies inventory. See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's gains and losses on the disposition of assets.

Oil and gas production costs. The Company recorded oil and gas production costs of $156.8 million and $295.2 million during the three and six months ended June 30, 2012, respectively, as compared to $101.7 million and $200.6 million during the same respective periods in 2011. In general, lease operating expenses and workover costs represent the components of oil and gas production costs over which the Company has management control, while third-party transportation charges represent the cost to transport volumes produced to a sales point. Net natural gas plant/gathering charges represent the net costs to gather and process the Company's gas, reduced by net revenues earned from the gathering and processing of third-party gas in Company-owned facilities.

Total oil and gas production costs per BOE for the three and six months ended June 30, 2012 increased by 17 percent and 9 percent, respectively, as compared to the same periods in 2011. The increase in production costs per BOE during the three and six months ended June 30, 2012, as compared to the same three and six months in 2011, is primarily due to increases in third-party transportation and processing charges associated with increasing Eagle Ford Shale production and decreases in net natural gas plant margins as a result of lower gas and NGL prices.

The following table provides the components of the Company's oil and gas production costs per BOE for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,					Six Months Ended June 30,
	2012		2011			2012		2011
Lease operating expenses	$	8.08	$	7.94		$	7.90	$	7.99
Third-party transportation charges	1.77		1.10			1.75		1.07
Net natural gas plant/gathering charges	0.64		(0.26		)	0.44		0.06
Workover costs	0.96		1.03			0.83		0.93
Total production costs	$	11.45	$	9.81		$	10.92	$	10.05

Production and ad valorem taxes. The Company's production and ad valorem taxes were $44.5 million and $90.3 million during the three and six months ended June 30, 2012, respectively, as compared to $35.9 million and $69.2 million for the same respective periods in 2011. In general, production and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices. During the three months ended June 30, 2012, the Company's per-BOE production taxes decreased, as compared to the three months ended June 30, 2011, primarily due to lower 2012 commodity prices. During the six months ended June 30, 2012, the Company's per-BOE ad valorem taxes declined, as compared to the six months ended June 30, 2011, primarily due to increased production from new wells placed on production, partially offset by higher 2011 commodity prices.

The following table provides the Company's production and ad valorem taxes per BOE for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Ad valorem taxes	$	1.44	$	1.41	$	1.27	$	1.45
Production taxes	1.81		2.05		2.07		2.01
Total ad valorem and production taxes	$	3.25	$	3.46	$	3.34	$	3.46

Depletion, depreciation and amortization expense. The Company's DD&A expense was $200.9 million ($14.67 per BOE) and $382.3 million ($14.14 per BOE) for the three and six months ended June 30, 2012, respectively, as compared to $135.5 million ($13.07 per BOE) and $258.3 million ($12.93 per BOE) during the same respective periods in 2011. The increase in per BOE depletion expense during the three and six months ended June 30, 2012, as compared to the same period of 2011, is primarily due to increases in depletion expense per BOE on oil and gas properties, partially offset by the per-BOE effect of increasing production on relatively fixed depreciation on other property and equipment.

Depletion expense on oil and gas properties was $14.05 per BOE and $13.53 per BOE during the three and six months ended June 30, 2012, respectively, as compared to $12.33 and $12.23 per BOE during the same respective periods in 2011. The 14 percent

35

PIONEER NATURAL RESOURCES COMPANY

and 11 percent increases in per-BOE depletion expense during the three and six months ended June 30, 2012, as compared to the same respective periods in 2011, are primarily due to (i) increased drilling expenditures on proved undeveloped locations, primarily in the Spraberry field and (ii) declines in proved gas reserves due to lower first-day-of-the-month gas prices during the 12-month period ending on June 30, 2012, partially offset by (iii) the impact of the fourth quarter 2011 impairment of $354.4 million of South Texas Edwards and Austin Chalk field carrying values.

Impairment of oil and gas properties. The Company reviews its long-lived assets for impairment, including oil and gas properties, whenever events or circumstances indicate their carrying values may not be fully recoverable. During the past year, reductions in management's outlook for commodity prices have provided indications of possible impairment of the Company's predominately dry gas properties in the Edwards Trend and Austin Chalk fields in South Texas, the Barnett Shale field in North Texas and the Raton field in Southeastern Colorado. As a result of management's assessments, during the fourth quarter of 2011 and second quarter of 2012, the Company recognized pretax noncash impairment charges of $354.4 million and $444.9 million, respectively, to reduce the carrying values of the South Texas Edwards Trend/Austin Chalk fields and Barnett Shale field to their estimated fair values.

The Company's estimates of undiscounted future net cash flows attributable to the Raton field oil and gas properties indicated on June 30, 2012 that its carrying amount was expected to be recovered. However, the carrying value of this field continues to be at risk for impairment if future estimates of undiscounted cash flows decline. For example, the Company estimates that the carrying value of the Raton field may become partially impaired if management's outlook for gas prices, which was $4.64 per MCF as of June 30, 2012, were to decline by approximately $0.10 per MCF to $0.20 per MCF, assuming none of the other impairment inputs changed. The Company's Raton field is a relatively long-lived asset that had a carrying value of $2.3 billion as of June 30, 2012. If the Raton field were to become impaired in a future quarter, the Company would recognize noncash, pretax impairment charges in that period that could range from $1.5 billion to $1.8 billion.

It is reasonably possible that the estimate of undiscounted future net cash flows attributable to these or other properties may change in the future resulting in the need to impair their carrying values. The primary factors that may affect estimates of future cash flows are (i) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, (ii) results of future drilling activities, (iii) management's outlook for commodity prices and (iv) increases or decreases in production and capital costs associated with these fields.

See Note O of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for more information about impairment of oil and gas properties and continuing impairment risks.

Exploration and abandonments expense. The following table provides the Company's geological and geophysical costs, exploratory dry holes expense and lease abandonments and other exploration expense for the three and six months ended June 30, 2012 and 2011 (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Geological and geophysical	$	24,391	$	16,780	$	50,426	$	32,393
Exploratory dry holes	1,409		163		28,286		808
Leasehold abandonments and other	11,378		2,789		11,753		4,015
	$	37,178	$	19,732	$	90,465	$	37,216

The Company's geological and geophysical costs increased by $7.6 million and $18.0 million during the three and six months ended June 30, 2012, as compared to the same respective periods in 2011, primarily as a result of increased seismic expenditures supportive of drilling activities in the Spraberry and Barnett Shale fields. The Company's leasehold abandonments and other expense increased by $8.6 million and $7.7 million during the three and six months ended June 30, 2012, as compared to the same respective periods in 2011, primarily due to increases in leasehold abandonments in dry gas areas. The Company's exploratory dry holes increased by $1.2 million and $27.5 million during the three and six months ended June 30, 2012, as compared to the same respective periods in 2011, primarily due to dry hole provisions of $1.1 million and $20.2 million, respectively, related to an unsuccessful exploration well in Alaska, and first quarter 2012 dry hole provisions in the South Texas Austin Chalk field and Mid-Continent area.

During the six months ended June 30, 2012, the Company drilled and evaluated 98 exploration/extension wells, 92 of which were successfully completed as discoveries. During the same period in 2011, the Company drilled and evaluated 64 exploration/extension wells, all of which were successfully completed as discoveries.

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PIONEER NATURAL RESOURCES COMPANY

General and administrative expense. General and administrative expense for the three and six months ended June 30, 2012 was $55.0 million and $118.0 million, respectively, as compared to $44.3 million and $88.3 million during the same respective periods in 2011. The $10.7 million increase in general and administrative expense for the three months ended June 30, 2012, as compared to the same period in 2011, was primarily due to increases of $4.7 million, $4.7 million and $1.8 million in share-based compensation, salaries and occupancy expense, respectively, related to staffing increases in support of the Company's capital expansion and integrated services initiatives. The $29.7 million increase in general and administrative expense for the six months ended June 30, 2012, as compared to the same period in 2011, was primarily due to increases of $12.1 million, $9.4 million, $2.7 million and $2.6 million in share-based compensation, salaries, occupancy and contract services expenses, respectively, related to staffing increases and other costs supportive of the Company's capital expansion and integrated services initiatives.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations was $2.4 million and $4.9 million for the three and six months ended June 30, 2012, respectively, as compared to $2.0 million and $4.1 million during the same respective periods in 2011. See Note I of Notes to Consolidated Financial Statements in "Item 1. Financial Statements" for information regarding the Company's asset retirement obligations.

Interest expense. Interest expense was $49.0 million and $95.9 million for the three and six months ended June 30, 2012, respectively, as compared to $45.0 million and $90.2 million during the same respective periods in 2011. The weighted average interest rate on the Company's indebtedness for the three and six months ended June 30, 2012, including the effects of capitalized interest, was 6.2 percent and 6.8 percent, as compared to 7.3 percent for each of the same respective periods in 2011. Interest expense increased by $4.0 million and $5.6 million during the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011, primarily due to increases of $2.5 million and $1.8 million, respectively, in interest on credit facility borrowings; decreases of $1.1 million and $929 thousand, respectively, in capitalized interest and a $2.6 million increase in amortization of note discounts and deferred hedge losses in the six-month comparison.

Other expense. Other expense for the three and six months ended June 30, 2012 was $30.7 million and $54.3 million, respectively, as compared to $12.1 million and $29.9 million for the same respective periods in 2011. The $18.6 million increase in other expense for the three months ended June 30, 2012, as compared to the same period in 2011, is primarily attributable to a $9.0 million increase in second quarter 2012 rig contract termination fees, associated with reducing the Spraberry vertical drilling rig count from 40 rigs to 30 rigs, and a $3.5 million increase in unused gas transportation commitment charges. The $24.4 million increase in other expense for the six months ended June 30, 2012, as compared to the same period in 2011, is primarily attributable to the aforementioned $9.0 million in rig contract termination fees, a $6.9 million increase in inventory valuation charges and a $6.7 million increase in unused gas transportation commitment charges. See Note N of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.

Income tax provision/benefit. The Company recorded an income tax benefit from continuing operations of $45.1 million for the three months ended June 30, 2012 and an income tax provision of $72.6 million for the six months ended June 30, 2012, as compared to income tax provisions of $140.2 million and $92.3 million for the same respective periods in 2011. The Company's effective tax rates, excluding net income attributable to noncontrolling interests, for the three and six months ended June 30, 2012 were 35 percent and 37 percent, respectively, as compared to the Company's combined United States federal and state statutory rate of approximately 37 percent.

See Note F of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's income taxes.

Income from discontinued operations, net of tax. The Company reported income from discontinued operations, net of tax of $12.0 million and $22.7 million for the three and six months ended June 30, 2012, respectively, as compared to a loss from discontinued operations, net of tax of $3.0 million for the three months ended June 30, 2011 and income from discontinued operations, net of tax of $416.9 million for the six months ended June 30, 2011.

During December 2011, the Company committed to a plan to exit South Africa and initiated a process to divest of its net assets in South Africa. In March 2012, the Company agreed to sell its net assets in South Africa to an unaffiliated third party, using a January 1, 2012 effective date, for net cash proceeds of $52.0 million, before normal closing adjustments. The sale is expected to close during the third quarter of 2012.

During February 2011, the Company completed the sale of 100 percent of the Company's share holdings in Pioneer Tunisia to an unaffiliated party for net cash proceeds of $802.5 million, including normal post-closing adjustments and excluding cash and cash equivalents sold, resulting in a pretax gain of $645.2 million.

See Note C of the Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for specific information regarding the Company's discontinued operations.

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PIONEER NATURAL RESOURCES COMPANY

Net income attributable to noncontrolling interest. Net income attributable to the noncontrolling interests for the three and six months ended June 30, 2012 was $30.9 million and $37.2 million, respectively, as compared to $20.1 million and $15.3 million for the same respective periods of 2011. The $10.8 million and $21.9 million increases in income attributable to noncontrolling interests for the three and six months ended June 30, 2012, as compared to the same respective periods in 2011, is primarily due to fluctuations in Pioneer Southwest's mark-to-market derivative gains and losses.

Capital Commitments, Capital Resources and Liquidity

Capital commitments. The Company's primary needs for cash are for capital expenditures and acquisition expenditures on oil and gas properties and related vertical integration assets and facilities, payment of contractual obligations, dividends/distributions and working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow, proceeds from the disposition of nonstrategic assets, joint ventures or external financing sources as discussed in "Capital resources" below.

The Company's capital budget for 2012 is focused on oil- and liquids-rich-gas drilling activities with total expenditures of $2.9 billion (excluding effects of acquisitions, asset retirement obligations, capitalized interest and geological and geophysical administrative costs), consisting of $2.4 billion for drilling operations and $500 million for vertical integration and infrastructure facilities additions, including the April 2012 acquisition of Premier Silica for $296.0 million. Based on results for the six months ended June 30, 2012 and management's commodity price outlook, the Company expects its cash flows from operating activities, rig reductions in the Spraberry and Barnett Shale Combo plays, proceeds from asset divestitures, including 2014 and 2015 gas derivatives, and availability under its credit facility to be sufficient to fund its planned capital expenditures and contractual obligations for the remainder of 2012.

Investing activities. Investing activities used $1.8 billion of cash during the six months ended June 30, 2012 as compared to $241.9 million of cash used in investing activities during the six months ended June 30, 2011. The $1.6 billion increase in cash used in investing activities for the six months ending June 30, 2012, as compared to the six months ended June 30, 2011, is primarily due to (i) a $750.6 million decrease in proceeds from disposition of assets primarily attributable to the 2011 sale of Pioneer Tunisia, (ii) a $667.7 million increase in additions to oil and gas properties and (iii) the $296.0 million acquisition of Premier Silica, partially offset by (iv)  an $82.9 million decrease in investments in EFS Midstream and (v) a $51.1 million decrease in additions to other assets and other property and equipment, primarily comprised of drilling rigs, fracture stimulation equipment and well servicing equipment used in the Company's vertical integration services. During the six months ended June 30, 2012, the Company's investing activities were funded by net cash provided by operating activities, cash on hand and borrowings under its credit facility.

Dividends/distributions. During February of both 2012 and 2011, the Company's board of directors ("the Board") declared semiannual dividends of $0.04 per common share. Future dividends are at the discretion of the Board, and, if declared, the Board may change the current dividend amount based on the Company's liquidity and capital resources at the time.

During January 2012 and April 2012, the Pioneer Southwest board of directors (the "Pioneer Southwest Board") declared a quarterly distribution of $0.51 and $0.52 per limited partner unit, respectively, compared to the quarterly distributions of $0.50 and $0.51 per limited partner unit declared in January and April 2011 respectively. Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling unitholders of $17.5 million and $12.7 million during the six months ended June 30, 2012 and 2011, respectively. During July 2012, the Pioneer Southwest Board declared quarterly distribution of $0.52 per limited partner unit for unitholders of record on August 2, 2012, payable August 9, 2012. Future distributions by Pioneer Southwest are at the discretion of the Pioneer Southwest Board, and, if declared, the Pioneer Southwest Board may change the distribution amount based on Pioneer Southwest's liquidity and capital resources at the time.

Contractual obligations, including off-balance sheet obligations. The Company's contractual obligations include long-term debt, operating leases, drilling commitments, derivative obligations, transportation commitments, VPP obligations, EFS Midstream capital funding commitments and other liabilities. From time-to-time, the Company enters into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations of the Company. As of June 30, 2012, the material off-balance sheet arrangements and transactions that the Company has entered into included (i) undrawn letters of credit, (ii) operating lease agreements, (iii) drilling, gathering, treating, fractionation and transportation commitments, (iv) open purchase commitments, (v) a VPP obligation (to physically deliver volumes and pay related lease operating expenses and capital costs in the future), (vi) take-or-pay obligations that allow the payer to recover make up volumes in the future and (vii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other parties that are reasonably likely to materially affect the Company's liquidity or availability of or requirements for capital resources. Since December 31, 2011, the material changes in the Company's contractual obligations include (i) a $757.0 million increase in the principal balances of outstanding long-term debt, (ii) a $20.9 million decrease in the Company's VPP obligations and (iii) a $147.2 million increase in

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PIONEER NATURAL RESOURCES COMPANY

the Company's derivative net assets. During 2011, EFS Midstream entered into a $300 million, five-year revolving credit facility to fund infrastructure investments that are in excess of operating cash flow; accordingly, future capital needs of EFS Midstream are expected to be funded from its operating cash flow and the borrowings under its credit facility.

The Company's commodity and interest rate derivative contracts are periodically measured and recorded at fair value and continue to be subject to market or credit risk. As of June 30, 2012, these contracts represented net assets of $521.3 million. The ultimate liquidation value of the Company's commodity and interest rate derivatives will be dependent upon actual future commodity prices and interest rates, which may differ materially from the inputs used to determine the derivatives' fair values as of June 30, 2012. See Note H of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information about the Company's derivative instruments and market risk.

Capital resources. The Company's primary capital resources are net cash provided by operating activities, proceeds from sales of nonstrategic assets and proceeds from financing activities (principally borrowings under the Company's credit facility). If internal cash flows and cash on hand do not meet the Company's expectations, the Company may reduce its level of capital expenditures, reduce dividend payments, and/or fund a portion of its capital expenditures using availability under its credit facility, issuances of debt or equity securities or from other sources, such as asset sales or joint ventures.

In early August 2012, the Company announced plans 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. The Company plans to offer a 33 percent to 50 percent working interest in the southern acreage. No assurance can be provided that the Company will be successful in attracting a joint venture partner or that a joint venture partner will offer an acquisition price that is acceptable to the Company.

Operating activities. Net cash provided by operating activities during the six months ended June 30, 2012 was $925.4 million as compared to $564.5 million during the same period of 2011. The increase in net cash provided by operating activities for the six months ended June 30, 2012, as compared to the six months ended June 30, 2011, is primarily due to increases in oil and gas sales volumes, realized derivative gains and working capital changes.

Asset divestitures. During the first quarter of 2012, the Company completed a sale of a portion of its interest in an unproved oil and gas property in the Eagle Ford Shale to unaffiliated third parties for proceeds of $54.7 million. Associated therewith, the Company recorded a pretax gain of $42.6 million.

During February 2011, the Company completed the sale of 100 percent of the Company's share holdings in Pioneer Tunisia to an unaffiliated third party for net cash proceeds of $802.5 million, including normal post-closing adjustments and excluding cash and cash equivalents sold, resulting in a pretax gain of $645.2 million. See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for information regarding the Company's discontinued operations and divestitures.

Financing activities. Net cash provided by financing activities during the six months ended June 30, 2012 was $676.9 million as compared to net cash used in financing activities of $81.3 million during the six months ended 2011. The $758.2 million increase in cash provided by financing activities during the six months ended June 30, 2012, as compared to the six months ended June 30, 2011, is primarily due to (i) a $786.3 million increase in net borrowings on long-term debt, partially offset by (ii) a $17.1 million increase in treasury stock purchases from employees to satisfy employee withholding tax payments on the vesting of share-based awards and (iii) a $10.4 million decrease in excess tax benefits from share-based payment arrangements.

During March 2012, Pioneer Southwest entered into the Pioneer Southwest Credit Facility with a syndicate of financial institutions that matures in March 2017, unless extended in accordance with the terms of the Pioneer Southwest Credit Facility. The Pioneer Southwest Credit Facility provides for aggregate loan commitments of $300.0 million. As of June 30, 2012, there were $69.0 million of outstanding borrowings under the Pioneer Southwest Credit Facility. See Note G of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for information about the available loans, interest rates and debt covenant terms of the Company's credit facility and the Pioneer Southwest Credit Facility.

Effective April 1, 2012, the Company's 2.875% Convertible Senior Notes became convertible at the option of the holders for the quarter ended June 30, 2012. Associated therewith, certain holders of the 2.875% Convertible Senior Notes tendered $22 thousand principal amount of the notes for conversion. The Company paid certain of the tendering holders a total of $7 thousand cash and issued to the tendering holders 50 shares of the Company's common stock in May 2012 in accordance with the terms of the 2.875% Convertible Senior Notes indenture supplement. In August 2012, the Company anticipates paying the other tendering holders $15 thousand cash for the remaining notes tendered and issuing shares to be determined based upon the conversion calculation in accordance with the terms of the 2.875% Convertible Senior Notes indenture supplement.

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PIONEER NATURAL RESOURCES COMPANY

During June 2012, the Company's stock price performance did not qualify the 2.875% Convertible Senior Notes for conversion at the option of the holders for the three months ending September 30, 2012. The Company's 2.875% Convertible Senior Notes may become convertible in future quarters depending on the Company's stock price or other conditions. If the 2.875% Convertible Senior Notes had qualified for and been converted as of June 30, 2012, the note holders would have received $479.9 million of cash and approximately 1.8 million shares of the Company's common stock, which was valued at $161.0 million at June 30, 2012.

On January 15, 2013, the 2.875% Convertible Senior Notes become redeemable at the option of the Company and on January 15, 2013, January 15, 2018, January 15, 2023, January 15, 2028 and January 15, 2033 the holders may require the Company to repurchase the notes for cash. The Company has the intent and ability to fund cash payments that may be required upon the conversion, redemption or repurchase of the 2.875% Convertible Senior Notes with borrowing capacity under its credit facility. Accordingly, the 2.875% Convertible Senior Notes are classified as long-term debt in the accompanying balance sheets.

During June 2012, the Company issued $600 million of 3.95% Senior Notes due 2022 and received proceeds, net of $8.5 million of offering discounts and costs, of $591.5 million. The Company used the net proceeds to reduce outstanding borrowings under its credit facility.

As the Company pursues its strategy, it may utilize various financing sources, including, to the extent available, fixed and floating rate debt, convertible securities, preferred stock or common stock. The Company may also issue securities in exchange for oil and gas properties, stock or other interests in other oil and gas companies or related assets. Additional securities may be of a class preferred to common stock with respect to such matters as dividends and liquidation rights and may also have other rights and preferences as determined by the Board.

Liquidity. The Company's principal sources of short-term liquidity are cash on hand and unused borrowing capacity under its credit facility. As of June 30, 2012, the Company had $110.0 million in outstanding borrowings under its credit facility and was in compliance with all of its debt covenants. After adjusting for $40.1 million of undrawn and outstanding letters of credit under its credit facility, the Company had $1.1 billion of unused borrowing capacity as of June 30, 2012. If internal cash flows and cash on hand do not meet the Company's expectations, the Company may reduce its level of capital expenditures, reduce dividend payments, and/or fund a portion of its capital expenditures using borrowings under its credit facility, issuances of debt or equity securities or other sources, such as asset sales or joint ventures. The Company cannot provide any assurance that needed short-term or long-term liquidity will be available on acceptable terms or at all. Although the Company expects that internal operating cash flows, cash on hand and available capacity under the Company's credit facility will be adequate to fund 2012 capital expenditures and dividend/distribution payments and provide adequate liquidity to fund other needs, no assurances can be given that such funding sources will be adequate to meet the Company's future needs.

Debt ratings. The Company receives debt credit ratings from several of the major ratings agencies, which are subject to regular reviews. The Company believes that each of the rating agencies considers many factors in determining the Company's ratings including: production growth opportunities, liquidity, debt levels, asset composition and proved reserve mix. A reduction in the Company's debt ratings could negatively impact the Company's ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing. In November 2011, the Company achieved an investment grade rating with one of the credit rating agencies and in May 2012 received an investment grade rating from a second credit rating agency.

Book capitalization and current ratio. The Company's net book capitalization at June 30, 2012 was $8.7 billion, consisting of $317.8 million of cash and cash equivalents, debt of $3.3 billion and equity of $5.8 billion. The Company's net debt to net book capitalization was 34 percent and 26 percent at June 30, 2012 and December 31, 2011, respectively. The Company's ratio of current assets to current liabilities was 1.14 to 1.00 at June 30, 2012 as compared to 1.31 to 1.00 at December 31, 2011.

New accounting pronouncements. The effects of new accounting pronouncements are discussed in Note B of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements."

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PIONEER NATURAL RESOURCES COMPANY

Item 3.Quantitative and Qualitative Disclosures About Market Risk

The following quantitative and qualitative disclosures about market risk are supplementary to the quantitative and qualitative disclosures provided in the Company's Annual Report on Form 10-K for the year ended December 31, 2011. As such, the information contained herein should be read in conjunction with the related disclosures in the Company's Annual Report on Form 10-K for the year ended December 31, 2011.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about the Company's potential exposure to market risks. The term "market risks," insofar as it relates to currently anticipated transactions of the Company, refers to the risk of loss arising from changes in commodity prices, foreign exchange rates and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how the Company views and manages ongoing market risk exposures. None of the Company's market risk sensitive instruments are entered into for speculative purposes.

The following table reconciles the changes that occurred in the fair values of the Company's open derivative contracts during the six months ending June 30, 2012:

	Derivative Contract Net Assets
	Commodities			Interest Rates			Total
	(in thousands)
Fair value of contracts outstanding as of December 31, 2011	$	389,753		$	(15,654	)	$	374,099
Changes in contract fair value (a)	386,601			(19,039		)	367,562
Contract maturities	(146,689		)	—			(146,689		)
Contract terminations	(73,716		)	—			(73,716		)
Fair value of contracts outstanding as of June 30, 2012	$	555,949		$	(34,693	)	$	521,256

 ____________________

(a) At inception, new derivative contracts entered into by the Company had no intrinsic value.

Interest rate sensitivity. See Note G of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and Capital Commitments, Capital Resources and Liquidity included in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" for information regarding debt transactions.

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PIONEER NATURAL RESOURCES COMPANY

The following table provides information about financial instruments to which the Company was a party as of June 30, 2012 and that are sensitive to changes in interest rates. For debt obligations, the table presents maturities by expected maturity dates, the weighted average interest rates expected to be paid on the debt given current contractual terms and market conditions and the debt's estimated fair value. For fixed rate debt, the weighted average interest rate represents the contractual fixed rates that the Company was obligated to periodically pay on the debt as of June 30, 2012. For variable rate debt, the average interest rate represents the average rates being paid on the debt projected forward proportionate to the forward yield curve for LIBOR on August 1, 2012.

	Six Months Ending December 31,			Year Ending December 31,																	Liability Fair Value at June 30.
	2012			2013			2014			2015			2016			Thereafter			Total		2012
	($ in thousands)
Total Debt:
Fixed rate principal maturities (a)	$	—		$	479,923		$	—		$	—		$	455,385		$	2,234,600		$	3,169,908	$	(3,738,296	)
Weighted average interest rate	6.02		%	5.41		%	5.27		%	6.78		%	6.88		%	5.89		%
Variable rate principal maturities:
Pioneer Natural Resources credit facility	$	—		$	—		$	—		$	—		$	110,000		$	—		$	110,000	$	(126,351	)
Weighted average interest rate	2.13		%	2.17		%	2.31		%	2.59		%	2.81		%	—
Pioneer Southwest credit facility	$	—		$	—		$	—		$	—		$	—		$	69,000		$	69,000	$	(69,367	)
Weighted average interest rate	2.01		%	2.04		%	2.18		%	2.46		%	2.68		%	2.85		%
Interest Rate Swaps: (b)
Notional debt amount	$	117,222		$	—		$	—		$	250,000		$	—		$	—		$	367,222	$	(34,693	)
Fixed rate payable (%)	3.06		%	—		%	—		%	3.21		%	—		%	—		%
Variable rate receivable (%)	0.38		%	—		%	—		%	0.84		%	—		%	—		%

 ____________________

(a) Represents maturities of principal amounts excluding debt issuance discounts and premiums and net deferred fair value hedge losses.

(b) Subsequent to June 30, 2012, the Company terminated its 2012 interest rate swap positions at a cost of $28.4 million.

Commodity derivative instruments and price sensitivity. The following table provides information about the Company's oil, NGL and gas derivative financial instruments that were sensitive to changes in oil, NGL and gas prices as of June 30, 2012. Although mitigated by the Company's derivative activities, declines in oil, NGL and gas prices would reduce the Company's revenues.

The Company manages commodity price risk with derivative contracts, such as swap contracts, collar contracts and collar contracts with short put options. Swap contracts provide a fixed price for a notional amount of sales volumes. Collar contracts provide minimum ("floor" or "long put") and maximum ("ceiling") prices on a notional amount of sales volumes, thereby allowing some price participation if the relevant index price closes above the floor price. Collar contracts with short put options differ from other collar contracts by virtue of the short put option price, below which the Company's realized price will exceed the variable market prices by the long put-to-short put price differential.

See Note H of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for a description of the accounting procedures followed by the Company relative to its derivative financial instruments and for specific information regarding the terms of the Company's derivative financial instruments that are sensitive to changes in oil, NGL or gas prices.

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PIONEER NATURAL RESOURCES COMPANY

	Six Months Ending December 31,			Year Ending December 31,								Asset (Liability) Fair Value at June 30,
	2012			2013			2014			2015		2012
												(in thousands)
Oil Derivatives:
Average daily notional BBL volumes:
Collar contracts with short puts (a)	51,610			67,290			40,000			—		$	201,428
Weighted average ceiling price per BBL	$	118.73		$	120.61		$	122.77		$	—
Weighted average floor price per BBL	$	84.80		$	88.88		$	91.50		$	—
Weighted average short put price per BBL	$	69.12		$	71.72		$	74.88		$	—
Collar contracts	2,000			—			—			—		$	2,803
Weighted average ceiling price per BBL	$	127.00		$	—		$	—		$	—
Weighted average floor price per BBL	$	90.00		$	—		$	—		$	—
Swap contracts (a)	3,000			3,000			—			—		$	(11,668	)
Weighted average fixed price per BBL	$	79.32		$	81.02		$	—		$	—
Average forward NYMEX oil prices (b)	$	89.40		$	91.11		$	90.19		$	—
Rollfactor swap contracts	—			6,000			—			—		$	1,167
Weighted average fixed price per BBL (c)	$	—		$	0.43		$	—		$	—
Average forward rollfactor prices (b)	$	—		$	(0.04	)	$	—		$	—
Basis swap contracts	20,000			—			—			—		$	5,384
Weighted average fixed price per BBL	$	(1.15	)	$	—		$	—		$	—
Average forward basis differential prices (d)	$	(1.08	)	$	—		$	—		$	—
NGL Derivatives:
Average daily notional BBL volumes:
Collar contracts with short puts	3,000			—			—			—		$	11,766
Weighted average ceiling price per BBL	$	79.99		$	—		$	—		$	—
Weighted average floor price per BBL	$	67.70		$	—		$	—		$	—
Weighted average short put price per BBL	$	55.76		$	—		$	—		$	—
Swap contracts (e)	750			—			—			—		$	19
Weighted average fixed price per BBL	$	35.03		$	—		$	—		$	—
Average forward NGL prices (f)	$	49.02		$	—		$	—		$	—
Diesel swap contracts	—			250			—			—		$	235
Weighted average fixed price per BBL	$	—		$	111.30		$	—		$	—
Average forward diesel prices (g)	$	—		$	121.73		$	—		$	—
Gas Derivatives:
Average daily notional MMBTU volumes:
Collar contracts with short puts (h)	—			—			30,000			135,000		$	10,483
Weighted average ceiling price per MMBTU	$	—		$	—		$	7.66		$	5.44
Weighted average floor price per MMBTU	$	—		$	—		$	5.67		$	4.22
Weighted average short put price per MMBTU	$	—		$	—		$	4.33		$	3.22
Collar contracts (h)	65,000			150,000			80,000			50,000		$	158,240
Weighted average ceiling price per MMBTU	$	6.60		$	6.25		$	6.39		$	7.92
Weighted average floor price per MMBTU	$	5.00		$	5.00		$	5.00		$	5.00
Swap contracts (h)	275,000			112,500			10,000			—		$	191,085
Weighted average fixed price per MMBTU	$	4.97		$	5.62		$	6.18		$	—
Average forward NYMEX gas prices (b)	$	3.29		$	3.73		$	4.09		$	4.28
Basis swap contracts (h)	136,000			142,500			140,000			—		$	(15,096	)
Weighted average fixed price per MMBTU	$	(0.34	)	$	(0.22	)	$	(0.21	)	$	—
Average forward basis differential prices (i)	$	(0.09	)	$	(0.13	)	$	(0.15	)	$	—

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PIONEER NATURAL RESOURCES COMPANY

___________________

(a) Subsequent to June 30, 2012, the Company entered into additional NYMEX (i) swap contracts for 8,000 BBLs per day of August 2012 through December 2012 production with a price of $93.09 per BBL and (ii) collar contracts with short puts for 5,000 BBLs per day of 2014 production with a ceiling price of $102.22 per BBL, a floor price of $95.00 per BBL and a short put price of $80.00 per BBL.

(b) The average forward NYMEX oil and gas prices are based on August 1, 2012 market quotes.

(c) Represents swaps that fix the difference between (i) each day's price per BBL of 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.

(d) The average forward basis differential prices are based on August 1, 2012 market quotes for basis differentials between Midland WTI and Cushing WTI.

(e) Subsequent to June 30, 2012, the Company entered into additional NGL swap contracts for 2,000 BBLs per day of August 2012 through December 2012 production priced at $80.06 per BBL.

(f) Forward component NGL prices are derived from active-market NGL component price quotes as of August 1, 2012.

(g) The average forward diesel price is based on August 1, 2012 market quotes.

(h) Subsequent to June 30, 2012, the Company (i) terminated its 2014 gas derivative positions, including basis swaps, for net proceeds of $47.1 million, (ii) terminated its 2015 collar contracts for proceeds of $19.4 million and (iii) terminated 2015 collar contracts with short puts for 30,000MMBTU per day with a ceiling price of $7.11 per MMBTU, a floor price of $5.00 per MMBTU and a short put price of $4.00 per MMBTU for proceeds of $4.7 million.

(i) The average forward basis differential prices are based on August 1, 2012 market quotes for basis differentials between the relevant index prices and NYMEX-quoted forward prices.

Marketing and basis transfer derivative instruments and price sensitivity. The Company manages commodity price risk and mitigates firm transportation commitment costs with derivative contracts. Periodically, the Company enters into gas buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these 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 provides information about the Company's marketing and basis transfer derivative financial instruments that were sensitive to changes in gas prices as of June 30, 2012:

	Six Months Ending December 31,			Asset Fair Value at June 30,
	2012			2012
				(in thousands)
Average Daily Gas Production Associated with Marketing Derivatives (MMBTU):
Basis swap contracts:
Index swap volume	26,739			$	73
Price differential ($/MMBTU)	$	0.25
Average forward basis differential prices (a)	$	0.10
Average Daily Gas Production Associated with Basis Transfer Derivatives (MMBTU):
Basis swap contracts:
Index swap volume	3,343			$	30
NGI-So Cal Border Monthly price differential to NYMEX HH ($/MMBTU)	$	0.12
Index swap volume	(3,343		)
IF-HSC price differential to NYMEX HH ($/MMBTU)	$	(0.05	)
Average forward basis differential prices (b)	$	0.07

 ____________________

(a) The average forward basis differential prices are based on August 1, 2012 market quotes for basis differentials between the relevant index prices and NYMEX-quoted forward prices.

44

PIONEER NATURAL RESOURCES COMPANY

Item 4.Controls and Procedures

Evaluation of disclosure controls and procedures. The Company's management, with the participation of its principal executive officer and principal financial officer, have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 (the "Exchange Act"), the effectiveness of the Company's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this Report. Based on that evaluation, the principal executive officer and principal financial officer concluded that the Company's disclosure controls and procedures were effective, as of the end of the period covered by this Report, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, including that such information is accumulated and communicated to the Company's management, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in internal control over financial reporting. There have been no changes in the Company's internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended June 30, 2012 that have materially affected or are reasonably likely to materially affect the Company's internal control over financial reporting.

45

PIONEER NATURAL RESOURCES COMPANY

PART II. OTHER INFORMATION

Item 1.Legal Proceedings

The Company is party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. 

Item 1A. Risk Factors

In addition to the other information set forth in this Report, you should carefully consider the risks discussed in the Company's Annual Report on Form 10-K under the headings "Part I, Item 1. Business – Competition, Markets and Regulations," "Part I, Item 1A. Risk Factors" and "Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk," as updated by the discussions in Part II of the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, which risks could materially affect the Company's business, financial condition or future results. There has been no material change in the Company's risk factors from those described in the Annual Report on Form 10-K except as updated by the referenced Form 10-Q.

These risks are not the only risks facing the Company. Additional risks and uncertainties not currently known to the Company or that it currently deems to be immaterial also may have a material adverse effect on the Company's business, financial condition or future results.

Item 2.Unregistered Sales of Equity Securities and Use of Proceeds

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes the Company's purchases of treasury stock under plans or programs during the three months ended June 30, 2012:

Period	Total Number of Shares (or Units) Purchased (a)	Average Price Paid per Share (or Unit)		Total Number of Shares (or Units) Purchased As Part of Publicly Announced Plans or Programs	Approximate Dollar Amount of Shares that May Yet Be  Purchased under Plans or Programs
April 2012	—	$	—	—
May 2012	—	$	—	—
June 2012	—	$	—	—
Total	—	$	—	—	$	—

 ____________________

(a) Consists of shares purchased from employees in order for the employee to satisfy tax withholding payments related to share-based awards that vested during the period.

Item 4.Mine Safety Disclosures

The Company's sand mines are subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95.1 to this Quarterly Report filed on Form 10-Q.

46

PIONEER NATURAL RESOURCES COMPANY

Item 6.Exhibits

Exhibits

Exhibit Number		Description
3.1	—	Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333-26951).
3.2	—	Certificate of Amendment of the Amended and Restated Certificate of Incorporation effective May 18, 2012 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K , File No. File No. 1-13245, filed with the SEC on May 18, 2012).
3.3	—	Third Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K , File No. File No. 1-13245, filed with the SEC on May 18, 2012).
4.1	—	Indenture dated June 26, 2012 between the Company and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 28, 2012).
4.2	—	First Supplemental Indenture, dated June 26, 2012, by and among the Company, Pioneer Natural Resources USA, Inc. and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.1 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 28, 2012).
10.1	—	First Amendment to Amended and Restated Pioneer Natural Resources Company Employee Stock Purchase Plan dated effective September 1, 2012 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. File No. 1-13245, filed with the SEC on May 18, 2012).
10.2	(a) —	Amendment to Restricted Stock Award Agreement between the Company and Scott D. Sheffield dated as of May 25, 2012.
31.1	(a) —	Chief Executive Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.
31.2	(a) —	Chief Financial Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.
32.1	(b) —	Chief Executive Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.
32.2	(b) —	Chief Financial Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.
95.1	(a) —	Mine Safety Disclosures
101.INS	(a) —	XBRL Instance Document.
101.SCH	(a) —	XBRL Taxonomy Extension Schema.
101.CAL	(a) —	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	(a) —	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB	(a) —	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	(a) —	XBRL Taxonomy Extension Presentation Linkbase Document.

 _____________

(a) Filed herewith.

(b) Furnished herewith.

47

PIONEER NATURAL RESOURCES COMPANY

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned hereto duly authorized.

	PIONEER NATURAL RESOURCES COMPANY
Date: August 6, 2012	By:	/s/    RICHARD P. DEALY
		Richard P. Dealy
		Executive Vice President and Chief Financial Officer
Date: August 6, 2012	By:	/s/    FRANK W. HALL
		Frank W. Hall
		Vice President and Chief Accounting Officer

48

PIONEER NATURAL RESOURCES COMPANY

Exhibit Index

Exhibit Number		Description
3.1	—	Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333-26951).
3.2	—	Certificate of Amendment of the Amended and Restated Certificate of Incorporation effective May 18, 2012 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K , File No. File No. 1-13245, filed with the SEC on May 18, 2012).
3.3	—	Third Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K , File No. File No. 1-13245, filed with the SEC on May 18, 2012).
4.1	—	Indenture dated June 26, 2012 between the Company and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 28, 2012).
4.2	—	First Supplemental Indenture, dated June 26, 2012, by and among the Company, Pioneer Natural Resources USA, Inc. and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.1 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 28, 2012).
10.1	—	First Amendment to Amended and Restated Pioneer Natural Resources Company Employee Stock Purchase Plan dated effective September 1, 2012 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. File No. 1-13245, filed with the SEC on May 18, 2012).
10.2	(a) —	Amendment to Restricted Stock Award Agreement between the Company and Scott D. Sheffield dated as of May 25, 2012.
31.1	(a) —	Chief Executive Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.
31.2	(a) —	Chief Financial Officer certification under Section 302 of Sarbanes-Oxley Act of 2002.
32.1	(b) —	Chief Executive Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.
32.2	(b) —	Chief Financial Officer certification under Section 906 of Sarbanes-Oxley Act of 2002.
95.1	(a) —	Mine Safety Disclosures
101.INS	(a) —	XBRL Instance Document.
101.SCH	(a) —	XBRL Taxonomy Extension Schema.
101.CAL	(a) —	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	(a) —	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB	(a) —	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	(a) —	XBRL Taxonomy Extension Presentation Linkbase Document.

_____________ 

(a) Filed herewith.

(b) Furnished herewith.

49

EX-10.2

EXHIBIT 10.2

AMENDMENT TO

RESTRICTED STOCK AWARD AGREEMENT

PIONEER NATURAL RESOURCES COMPANY

2006 LONG TERM INCENTIVE PLAN

This Amendment to Restricted Stock Award Agreement (“Amendment”) is entered into by Pioneer Natural Resources Company (the “Company”) and Scott D. Sheffield (the “Participant”) as of May 25, 2012.

W I T N E S S E T H:

WHEREAS, pursuant to that certain Restricted Stock Award Agreement dated February 16, 2010 (the “Agreement”), the Company granted to the Participant an award under the Pioneer Natural Resources Company 2006 Long Term Incentive Plan;

WHEREAS, the Participant and the Company desire to amend the Agreement in certain respects to limit the Participant's benefits in the event of his retirement;

NOW, THEREFORE, the Participant and the Company hereby as follows:

1. Section 6(a) of the Agreement is hereby amended to read in its entirety as follows:

(a)Termination By Employee Without Good Reason. If your employment relationship with the Company or any of its Subsidiaries is terminated voluntarily by you prior to the Vesting Date and such termination is not a Termination for Good Reason (as such term is defined in the Severance Agreement between you and the Company or one of its Subsidiaries), or if such termination is a result of your Normal Retirement, then all Restricted Shares granted pursuant to this Agreement shall become null and void as of the date of such termination. For purposes of this Section 6(a), “Normal Retirement” shall mean the termination of your employment relationship with the Company and each of its Subsidiaries by which you are employed due to your retirement on or after the date you attain age 60.

2.Section 6(d) of the Agreement is hereby amended to read in its entirety as follows:

(d)Other Termination Events. If your employment relationship with the Company and each of its Subsidiaries by which you are employed is terminated prior to the Vesting Date as a result of any of the following events:

(i)your death; or

(ii)your Disability;

then the restrictions on a number of Restricted Shares shall automatically lapse such that the number of Restricted Shares for which the restrictions have lapsed as of your date of termination will be equal to the product of (i) the total number of Restricted Shares granted to you pursuant to this Agreement, times (ii) a fraction, the numerator of which is the number of full months (counting the month in which your termination of employment occurs as a full month), beginning with the first full month following the date of this Agreement, during which you were employed by the Company and/or any Subsidiary and the denominator of which is 36. The portion, if any, of your Restricted Shares for which restrictions have not lapsed as of the date of the

termination of your employment relationship shall become null and void as of the date of termination; provided, however, that the portion, if any, of this Award for which forfeiture restrictions have lapsed as of the date of termination will survive. For purposes of this Section 6(d), “Disability” shall have the meaning ascribed to it in the Severance Agreement between you and the Company or one of its Subsidiaries.

3.Except as set forth above, the Agreement shall continue to read in its current state.

IN WITNESS WHEREOF, the Participant and the Company have caused this Amendment to be executed as of the date and year first above written.

	PIONEER NATURAL RESOURCES COMPANY
By:	/s/ Larry N. Paulsen
	Larry N. Paulsen
	Vice President, Administration and Risk Management
	/s/ Scott D. Sheffield
	Scott D. Sheffield

EX-31.1

EXHIBIT 31.1

CHIEF EXECUTIVE OFFICER CERTIFICATION

I, Scott D. Sheffield, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Pioneer Natural Resources Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

August 6, 2012

/s/ Scott D. Sheffield

Scott D. Sheffield, Chairman and

Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CHIEF FINANCIAL OFFICER CERTIFICATION

I, Richard P. Dealy, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Pioneer Natural Resources Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

August 6, 2012

/s/ Richard P. Dealy

Richard P. Dealy, Executive Vice President

and Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER

OF PIONEER NATURAL RESOURCES COMPANY

PURSUANT TO 18 U.S.C. § 1350

I, Scott D. Sheffield, Chairman and Chief Executive Officer of Pioneer Natural Resources Company (the “Company”), hereby certify that the accompanying Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012 and filed with the Securities and Exchange Commission pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Report”) by the Company fully complies with the requirements of that section.

I further certify that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Scott D. Sheffield
Name:	Scott D. Sheffield, Chairman and
	Chief Executive Officer
Date:	August 6, 2012

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF

CHIEF FINANCIAL OFFICER

OF PIONEER NATURAL RESOURCES COMPANY

PURSUANT TO 18 U.S.C. § 1350

I, Richard P. Dealy, Executive Vice President and Chief Financial Officer of Pioneer Natural Resources Company (the “Company”), hereby certify that the accompanying Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012 and filed with the Securities and Exchange Commission pursuant to Section 13(a) of the Securities Exchange Act of 1934 (the “Report”) by the Company fully complies with the requirements of that section.

I further certify that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Richard P. Dealy
Name:	Richard P. Dealy, Executive Vice
	President and Chief Financial Officer
Date:	August 6, 2012

EX-95.1

EXHIBIT 95.1

Mine Safety Disclosure

The following disclosures are provided pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Act") and Item 104 of Regulation S-K, which requires certain disclosures by companies required to file periodic reports under the Securities Exchange Act of 1934, as amended, that operate mines regulated under the Federal Mine Safety and Health Act of 1977 (the "Mine Act").

Whenever the Federal Mine Safety and Health Administration ("MSHA") believes a violation of the Mine Act, any health or safety standard or any regulation has occurred, it may issue a citation which describes the alleged violation and fixes a time within which the U.S. mining operator must abate the alleged violation. In some situations, such as when MSHA believes that conditions pose a hazard to miners, MSHA may issue an order removing miners from the area of the mine affected by the condition until the alleged hazards are corrected. When MSHA issues a citation or order, it generally proposes a civil penalty, or fine, as a result of the alleged violation, that the operator is ordered to pay. Citations and orders can be contested and appealed, and as part of that process, are often reduced in severity and amount, and are sometimes dismissed. The number of citations, orders and proposed assessments vary depending on the size and type (underground or surface) of the mine as well as by the MSHA inspector(s) assigned.

The table below sets forth for the three months ended June 30, 2012 for each sand mine of Pioneer Natural Resources Company or its subsidiaries (the "Company"), (i) the total number of citations for violations of mandatory health or safety standards that could significantly and substantially contribute to the cause and effect of mine safety or health hazard under section 104 of the Mine Act for which the operator received a citation from MSHA; (ii) the total number of orders issued under section 104(b) of the Mine Act; (iii) the total number of citations and orders for unwarrantable failure of the mine operator to comply with mandatory health or safety standards under section 104(d) of the Mine Act; (iv) the total number of flagrant violations under section 110(b)(2) of the Mine Act; (v) the total number of imminent danger orders issued under section 107(a) of the Mine Act; (vi) the total dollar value of proposed assessments from MSHA; (vii) the total number of mining-related fatalities; (viii) whether or not the mine has received any notices from MSHA of a pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of mine health or safety hazards under section 104(e) of the Mine Act; (ix) whether or not the mine has received any notices from MSHA regarding the potential to have a pattern of violations as referenced in (viii) above; and (x) the total number of pending legal actions before the Federal Mine Safety and Health Review Commission (the "Commission") (as of June 30, 2012) involving such mine, as well as the aggregate number of legal actions instituted and the aggregate number of legal actions resolved during the reporting period. The MSHA citations, orders and assessments are those initially issued or proposed by MSHA. They do not reflect any subsequent changes in the level of severity of a citation or order or the value of an assessment that may occur as a result of proceedings conducted in accordance with MSHA rules.

Mine/MSHA Identification Number(1)	Section  104 S&S Citations	Section 104(b) Orders	Section 104(d) Citations and  Orders	Section 110(b)(2) Violations	Section 107(a) Orders	Total Dollar Value of Proposed Assessments		Mining Related Fatalities	Received Notice of Pattern of Violations under Section 104(e) (yes/no)	Received Notice of Potential to have Pattern under Section 104(e) (yes/no)	Legal Actions Pending as of Last Day of Period	Legal Actions Initiated During Period	Legal Actions Resolved During Period
Orange County Operation / 0402801	—	—	—	—	—	$	—	—	No	No	—	—	—
Riverside Operation / 0404263	—	—	—	—	—	$	—	—	No	No	—	—	—
Colorado Springs Operation / 0503295	—	—	—	—	—	$	—	—	No	No	—	—	—
Glass Rock Operation / 3301354	—	—	—	—	—	$	—	—	No	No	—	—	—
Millwood Operation / 3301355	3	—	—	—	—	$	1,821	—	No	No	—	—	—
Voca Pit and Plant / 4101003	—	—	—	—	—	$	—	—	No	No	—	—	—
Brady Plant / 4101371	—	—	—	—	—	$	—	—	No	No	—	—	—
Voca West / 4103618	—	—	—	—	—	$	200	—	No	No	—	—	—

_______________

(1 ) The definition of mine under section three of the Mine Act includes the mine, as well as other items used in, or to be used in, or resulting from, the work of extracting minerals, such as land, structures, facilities, equipment, machines, tools and minerals preparation facilities. Unless otherwise indicated, any of these other items associated with a single mine have been aggregated in the totals for that mine. MSHA assigns an identification number to each mine and may or may not assign separate identification numbers to related facilities such as preparation facilities.

XML

Acquisitions and Divestitures (Estimated Fair Values Of The Assets Acquired And Liabilities Assumed) (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Acquisitions and Divestitures [Abstract]
Business acquisition, cost of acquired entity, purchase price	$ 296,000,000		$ 296,000,000
Business acquisition, purchase price allocation, assets acquired	468,900,000		468,900,000
Business acquisition, purchase price allocation, property, plant and equipment	454,500,000		454,500,000
Business acquisition, purchase price allocation, liabilities assumed	(172,900,000)		(172,900,000)
Business acquisition, purchase price allocation, deferred taxes asset (liability), net, noncurrent	(150,800,000)		(150,800,000)
Business combination, acquisition related costs	$ 1,190,000	$ 0	$ 2,173,000	$ 0

XML

Asset Retirement Obligations (Details) (USD $)	3 Months Ended				6 Months Ended
	Jun. 30, 2012		Jun. 30, 2011		Jun. 30, 2012		Jun. 30, 2011		Dec. 31, 2011
Asset Retirement Obligation [Abstract]
Beginning asset retirement obligations	$ 134,314,000		$ 154,689,000		$ 136,742,000		$ 152,291,000
Liabilities assumed in acquisitions	8,515,000		0		8,515,000		6,000
New wells placed on production	1,581,000		1,404,000		2,411,000		2,075,000
Changes in estimates	1,603,000		(179,000)		1,603,000		121,000
Disposition of wells	0		367,000		0		448,000
Liabilities settled	3,054,000		6,235,000		8,742,000		7,469,000
Accretion of discount from continuing operations	2,444,000		2,048,000		4,874,000		4,092,000
Accretion of discount from integrated services	54,000	[1]	0	[1]	54,000	[1]	0	[1]
Accretion of discount from discontinued operations	0		610,000		0		1,302,000
Ending asset retirement obligations	145,457,000		151,970,000		145,457,000		151,970,000
Asset retirement obligations, current portions	$ 18,600,000				$ 18,600,000				$ 14,200,000

[1] Accretion of discount from integrated services includes Premier Silica accretion expense, which is recorded as a reduction in third-party income from vertical integration services in interest and other income in the Company's accompanying consolidated statements of operations. See Note M for more information about interest and other income.

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Derivative Financial Instruments (Narrative) (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended		1 Months Ended			3 Months Ended		1 Months Ended	3 Months Ended		1 Months Ended	3 Months Ended		1 Months Ended	3 Months Ended		1 Months Ended	3 Months Ended		6 Months Ended	3 Months Ended	1 Months Ended		3 Months Ended			1 Months Ended
	Apr. 30, 2012	Jun. 30, 2012	Dec. 31, 2011	Aug. 03, 2012 2015 Gas Derivatives [Member] [Member]	Aug. 03, 2012 2014 Gas Derivatives [Member]	Aug. 03, 2012 2012 Swap Contracts [Member] bbl	Jun. 30, 2012 2012 Swap Contracts [Member] bbl MMBTU		Aug. 03, 2012 2014 - Collar Contracts With Short Puts [Member] bbl	Jun. 30, 2012 2014 - Collar Contracts With Short Puts [Member] MMBTU bbl		Aug. 03, 2012 2014 - Collar Contracts With Short Puts [Member] Ceiling [Member]	Jun. 30, 2012 2014 - Collar Contracts With Short Puts [Member] Ceiling [Member]		Aug. 03, 2012 2014 - Collar Contracts With Short Puts [Member] Floor [Member]	Jun. 30, 2012 2014 - Collar Contracts With Short Puts [Member] Floor [Member]		Aug. 03, 2012 2014 - Collar Contracts With Short Puts [Member] Short Put [Member]	Jun. 30, 2012 2014 - Collar Contracts With Short Puts [Member] Short Put [Member]		Jun. 30, 2012 Rollfactor Swap Contracts [Member]	Jun. 30, 2012 2013 Diesel Swaps [Member] bbl	Aug. 03, 2012 2012 Interest Rate Derivatives [Member]	Aug. 03, 2012 NGL Swap [Member] bbl	Jun. 30, 2012 NGL Swap [Member] bbl	Jun. 30, 2012 NGL Collar Contracts With Short Put [Member] bbl	Jun. 30, 2012 NGL Collar Contracts With Short Put [Member] Short Put [Member]	Aug. 03, 2012 2015 Gas Collars with Short Puts Derivatives [Member] MMBTU	Aug. 03, 2012 2015 Gas Collars with Short Puts Derivatives [Member] Ceiling [Member]	Aug. 03, 2012 2015 Gas Collars with Short Puts Derivatives [Member] Floor [Member]	Aug. 03, 2012 2015 Gas Collars with Short Puts Derivatives [Member] Short Put [Member]
Schedule of Trading Securities and Other Trading Assets [Line Items]
Volume (Bbl)						8,000	3,000	[1]	5,000	40,000
Average Daily Oil Production Derivative Price Per Barrel						93.09	79.32					102.22	122.77		95.00	91.50		80.00	74.88
NYMEX swap multiple, second nearby month																					0.6667
NYMEX swap multiple, third nearby month																					0.3333
Terminated Derivatives Proceeds				$ 19.4	$ 47.1																		$ 28.4					$ 4.7
Derivative Nonmonetary Notional Volume per Day (BBL)																						250		2,000	750	3,000
Derivative, Average Cap Price (per BBL)																										79.99
Derivative, Average Floor Price (per BBL)																										67.70
Derivative, Nonmonetary Notional Amount, Price (per BBL)																											55.76
Average fixed price (per BBL)																						111.30		80.06	35.03
Derivative, Fixed Interest Rate	3.21%	3.06%
Notional amount of debt	250	200
Net deferred losses from hedging in AOCI			(3.2)
Net deferred gains or losses associated to net deferred tax benefits			1.8
Derivative Instruments Loss From Discontinued Interest Rate Hedges In Aoci			$ 1.7
Average Daily Gas Production Derivatives Volume (MMBTU)							275,000			30,000	[2]																	30,000
Average Daily Gas Production Derivatives Price Per MMBtu							4.97						7.66	[2]		5.67	[2]		4.33	[2]									7.11	5.00	4.00

[1] Subsequent to June 30, 2012, the Company entered into additional NYMEX (i) swap contracts for 8,000 BBLs per day of August 2012 through December 2012 production with a price of $93.09 per BBL and (ii) collar contracts with short puts for 5,000 BBLs per day of 2014 production with a ceiling price of $102.22 per BBL, a floor price of $95.00 per BBL and a short put price of $80.00 per BBL.

[2] Subsequent to June 30, 2012, the Company (i) terminated its 2014 gas derivative positions, including basis swaps, for net proceeds of $47.1 million, (ii) terminated its 2015 collar contracts for proceeds of $19.4 million and (iii) terminated 2015 collar contracts with short puts for 30,000 MMBTU per day with a ceiling price of $7.11 per MMBTU, a floor price of $5.00 per MMBTU and a short put price of $4.00 per MMBTU for proceeds of $4.7 million.

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Incentive Plans Incentive Plans (Stock-based compensation) (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 21.7	$ 13.8	$ 43.3	$ 26.4
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	156.0		156.0
Share Based Compensation Arrangement By Share Based Payment Award Liability	27.0
Amount Of Liabilities Attributable To Liability Awards Included In Accounts Payable	8.2		8.2		9.2
Restricted Stock Awards Unvested Shares At Balance Sheet Date	304,260				533,125
Postretirement benefit obligation revaluation	$ 8.5		$ 8.5		$ 7.5
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	1,540,522		1,540,522		1,857,612
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures			897,591
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period			(1,199,536)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period			0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period			(15,145)
Pioneer Southwest Ltip Restricted Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	7,496		7,496		7,492
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures			7,496
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period			(7,492)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period			0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period			0
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	598,354		598,354		564,044
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures			98,819
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period			0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period			(64,509)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period			0
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	162,003		162,003		114,128
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures			47,875
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period			0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period			0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period			0
Restricted Stock Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	420,258		420,258		322,925
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures			223,375
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period			(115,700)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period			0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period			(10,342)
Pioneer Southwest Ltip Phantom Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	102,644		102,644		65,157
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures			37,487
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period			0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period			0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period			0

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Income Taxes (Schedule Of Income Tax (Provisions) Benefits Attributable To Income From Continuing Operations) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Income Tax Disclosure [Abstract]
Current Income Tax Expense (Benefit)	$ (3,494)	$ (2,540)	$ (15,326)	$ (4,938)
Deferred income tax (provision) benefit	48,580	(137,642)	(57,291)	(87,337)
Income tax (provision) benefit	$ 45,086	$ (140,182)	$ (72,617)	$ (92,275)
U.S. federal	35.00%	36.00%	37.00%	34.00%

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Net Income (Loss) Per Share (Tables)

6 Months Ended

Jun. 30, 2012

Earnings Per Share [Abstract]

Reconciliation of earnings attributable to common stockholders, basic and diluted

The following tables reconcile the Company's net income (loss) attributable to common stockholders to basic net income (loss) attributable to common stockholders and diluted net income (loss) attributable to common stockholders for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30, 2012								Six Months Ended June 30, 2012
	Continuing Operations			Discontinued Operations		Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income (loss) attributable to common stockholders	$	(82,409	)	$	12,017	$	(70,392	)	$	121,515		$	22,712		$	144,227
Participating basic earnings	(265		)	—		(265		)	(1,833		)	(343		)	(2,176		)
Basic net income (loss) attributable to common stockholders	(82,674		)	12,017		(70,657		)	119,682			22,369			142,051
Reallocation of participating earnings	—			—		—			130			24			154
Diluted income (loss) attributable to common stockholders	$	(82,674	)	$	12,017	$	(70,657	)	$	119,812		$	22,393		$	142,205

	Three Months Ended June 30, 2011									Six Months Ended June 30, 2011
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income (loss) attributable to common stockholders	$	248,602		$	(3,025	)	$	245,577		$	177,314		$	416,857		$	594,171
Participating basic earnings	(4,847		)	—			(4,847		)	(3,238		)	(7,611		)	(10,849		)
Basic net income (loss) attributable to common stockholders	243,755			(3,025		)	240,730			174,076			409,246			583,322
Reallocation of participating earnings	164			—			164			81			190			271
Diluted income (loss) attributable to common stockholders	$	243,919		$	(3,025	)	$	240,894		$	174,157		$	409,436		$	583,593

Reconciliation Of Basic To Diluted Weighted Average Common Shares Outstanding

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,		Six Months Ended June 30,
	2012	2011	2012	2011
	(in thousands)
Weighted average common shares outstanding:
Basic	123,028	116,213	122,754	116,042
Dilutive common stock options (a)	—	178	205	188
Convertible senior notes dilution (a)	—	1,772	2,642	2,333
Contingently issuable performance unit shares (a)	—	429	171	423
Diluted	123,028	118,592	125,772	118,986

 ____________________

(a) The following common share equivalents were excluded from the weighted average diluted shares for the three months ended June 30, 2012 because they would have been anti-dilutive to the loss recorded for the period: 206,495 outstanding options to purchase the Company's common stock, 184,236 common shares attributable to unvested performance units and 1,825,147 common shares issuable if holders of the Company's 2.875% Convertible Senior Notes had exercised their conversion rights (see Note G). Options to purchase 185,772 shares of the Company's common stock were excluded from the diluted income per share calculations for the six months ended June 30, 2012 because they would have been anti-dilutive to the calculation.

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Net Income (Loss) Per Share (Reconciliation Of Basic To Diluted Weighted Average Common Shares Outstanding) (Details)	3 Months Ended				6 Months Ended
	Jun. 30, 2012		Jun. 30, 2011		Jun. 30, 2012		Jun. 30, 2011
Weighted Average Number of Shares Outstanding Reconciliation [Line Items]
Basic	123,028,000		116,213,000		122,754,000		116,042,000
Dilutive common stock options	0	[1]	178,000	[1]	205,000	[1]	188,000	[1]
Convertible senior notes dilution	0	[1]	1,772,000	[1]	2,642,000	[1]	2,333,000	[1]
Contingently issuable performance unit shares	0	[1]	429,000	[1]	171,000	[1]	423,000	[1]
Diluted	123,028,000		118,592,000		125,772,000		118,986,000
Stock Options [Member]
Weighted Average Number of Shares Outstanding Reconciliation [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	206,495				185,772
Unvested Performance units [Member]
Weighted Average Number of Shares Outstanding Reconciliation [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	184,236
Conversion rights [Member]
Weighted Average Number of Shares Outstanding Reconciliation [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	1,825,147

[1] The following common share equivalents were excluded from the weighted average diluted shares for the three months ended June 30, 2012 because they would have been anti-dilutive to the loss recorded for the period: 206,495 outstanding options to purchase the Company's common stock, 184,236 common shares attributable to unvested performance units and 1,825,147 common shares issuable if holders of the Company's 2.875% Convertible Senior Notes had exercised their conversion rights (see Note G). Options to purchase 185,772 shares of the Company's common stock were excluded from the diluted income per share calculations for the six months ended June 30, 2012 because they would have been anti-dilutive to the calculation.

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Basis Of Presentation (Policies)

6 Months Ended

Jun. 30, 2012

Basis Of Presentation [Abstract]

Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of June 30, 2012 and for the three and six months ended June 30, 2012 and 2011 include all adjustments and accruals, consisting only of normal recurring accrual adjustments, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year.

Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States ("GAAP") have been condensed or omitted in this Report pursuant to the rules and regulations of the United States Securities and Exchange Commission (the "SEC"). These consolidated financial statements should be read together with the consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2011.

Certain reclassifications have been made to the 2011 financial statement and footnote amounts in order to conform to the 2012 presentation.

On May 6, 2008, the Company recognized a noncash gain on the sale of Pioneer Southwest Energy Partners L.P.'s ("Pioneer Southwest," a majority-owned and consolidated subsidiary) common units as a component of additional paid-in capital in stockholders' equity. In accordance with the Financial Accounting Standards Board ("FASB") Accounting Standards Codification (“ASC”) Topic 740 Income Taxes, deferred income taxes of $49.1 million should be recognized for the future tax effects arising from the noncash gain on the sale of the Pioneer Southwest common units, with a corresponding decrease to additional paid-in capital. The Company recorded the deferred income taxes associated with this transaction in June 2012. The effect of this adjustment is immaterial to the accompanying financial statements.

Derivatives And Hedging

Derivatives and hedging. All derivatives are recorded in the accompanying consolidated balance sheets at their estimated fair values. See Note E for further information regarding the fair value of the Company's derivatives. Effective February 1, 2009, the Company discontinued hedge accounting on all of its then-existing derivative hedge contracts. Changes in the fair value of effective cash flow hedges prior to the Company's discontinuance of hedge accounting were recorded as a component of accumulated other comprehensive income or loss ("AOCI - Hedging"), in the equity section of the Company's consolidated balance sheets, and were transferred to earnings during the same periods in which the hedged transactions were recognized in the Company's earnings. As of June 30, 2012, all of the hedge gains or losses that were previously deferred in AOCI - Hedging have been transferred to earnings. The Company now recognizes all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they occur.

The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company's and Pioneer Southwest's credit-adjusted risk-free rate curves. The credit-adjusted risk-free rate curves for the Company and its counterparties are generally based on their independent market-quoted credit default swap rate curves plus the United States Treasury Bill yield curve as of the valuation date. Pioneer Southwest's credit-adjusted risk-free rate curve is based on independent market-quoted forward London Interbank Offered Rate ("LIBOR") curves plus 162.5 basis points, representing Pioneer Southwest's borrowing rate.

Impairment Of Long-Lived Assets

Impairment of assets. The Company reviews its long-lived assets for impairment, including oil and gas properties, whenever events or circumstances indicate that their carrying values may not be fully recoverable. If the carrying value of long-lived assets is determined to be impaired, it is reduced to its estimated fair value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. See Note O for additional information about the Company's impairment charge for the three and six months ended June 30, 2012, and future impairment risk.

Goodwill is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired, it is reduced for the impaired value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. During the third quarter of 2011, the Company performed its annual assessment of goodwill impairment and determined that there was no impairment.

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Derivative Financial Instruments (Schedule Of Marketing And Basis Transfer Derivative Contracts) (Details)	3 Months Ended
	Jun. 30, 2012
Average Daily Gas Production Associated with Marketing Derivatives (MMBtu) [Member]
Price Differential	0.25
Average Daily Gas Production Associated with Marketing Derivatives (MMBtu) [Member] | Basic Index Swaps [Member]
Index swap volume	26,739
Average Daily Gas Production Associated with Basis Transfer Derivatives (MMBtu) [Member]
NGI-So Cal Border Monthly price differential to NYMEX HH	0.12
IJ-HSC Price Differential To NYMEX HH	(0.05)
Average Daily Gas Production Associated with Basis Transfer Derivatives (MMBtu) [Member] | Basic Short Index Swaps [Member]
Index swap volume	3,343
Average Daily Gas Production Associated with Basis Transfer Derivatives (MMBtu) [Member] | Basic Long Index Swaps [Member]
Index swap volume	(3,343)

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Acquisitions and Divestitures (Gain Loss On Sale of Assets from Continuing Operations) (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Gain Loss on Sale of Assets [Line Items]
Gain (loss) on disposition of assets, net	$ 1,140,000	$ (296,000)	$ 44,736,000	$ (2,487,000)
Eagle Ford Shale [Member]
Gain Loss on Sale of Assets [Line Items]
Sale of interest in an unproved oil and gas property			54,700,000
Gain (loss) on disposition of assets in continuing operations			$ 42,600,000

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Basis Of Presentation Basis of Presentation (Revision for Deferred Income Taxes) (Details) (Restatement Adjustment [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Decrease in Current Deferred Tax Assets, Revision of Unrealized Current Derivative Gains, Net [Member]
Adjustment to deferred income taxes due to revision of unrealized current derivative gains, net	$ 77.0
Increase in Current Deferred Tax Liabilities, Revision of Unrealized Current Derivative Gains, Net [Member]
Adjustment to deferred income taxes due to revision of unrealized current derivative gains, net	57.7
Decrease in Noncurrent Deferred Tax Liabilities, Revision of Unrealized Current Derivative Gains, Net [Member]
Adjustment to deferred income taxes due to revision of unrealized current derivative gains, net	$ 134.7

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Derivative Financial Instruments (Schedule Of Derivative Obligations Under Terminated Hedge Arrangements) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Derivative [Line Items]
Amount of Gain/(Loss) Reclassified from AOCI into Earnings	$ (2,347)	$ 8,139	$ (4,855)	$ 16,195
Amount of Gain (Loss) Recognized in Earnings on Derivatives	275,812	229,478	367,562	(14,954)
Interest Rate Derivatives [Member] | Interest Expense [Member]
Derivative [Line Items]
Amount of Gain/(Loss) Reclassified from AOCI into Earnings	0	(69)	(1,699)	(137)
Interest Rate Derivatives [Member] | Derivative Gains, Net [Member]
Derivative [Line Items]
Amount of Gain (Loss) Recognized in Earnings on Derivatives	(22,659)	14,575	(19,039)	12,423
Commodity Price Derivatives [Member] | Derivative Gains, Net [Member]
Derivative [Line Items]
Amount of Gain (Loss) Recognized in Earnings on Derivatives	298,471	214,903	386,601	(27,377)
Commodity Price Derivatives [Member] | Oil And Gas revenue [Member]
Derivative [Line Items]
Amount of Gain/(Loss) Reclassified from AOCI into Earnings	$ (2,347)	$ 8,208	$ (3,156)	$ 16,332

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Subsequent Events (Details) (Subsequent Event [Member], Cash Distribution [Member], USD $) In Millions, except Per Share data, unless otherwise specified	1 Months Ended
	Jul. 31, 2012
Subsequent Event [Member] | Cash Distribution [Member]
Subsequent Event [Line Items]
Distribution Made to Member or Limited Partner, Distributions Declared, Per Unit	$ 0.52
Distribution Made to Member or Limited Partner, Cash Distributions Declared	$ 18.6

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Long-Term Debt (Details) (USD $)	6 Months Ended			1 Months Ended				3 Months Ended	6 Months Ended	1 Months Ended	3 Months Ended				6 Months Ended	3 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Jul. 31, 2012 PXD Credit Facility [Member]	Jun. 30, 2012 PXD Credit Facility [Member]	Jun. 30, 2012 Pioneer Southwest Credit Facility [Member]	May 31, 2008 Pioneer Southwest Credit Facility [Member]	Jun. 30, 2012 3.95 percent Senior Notes Due 2022 [Member]	Jun. 30, 2012 3.95 percent Senior Notes Due 2022 [Member]	Aug. 31, 2012 2.875% Convertible Senior Notes Due 2038 [Member]	Jun. 30, 2012 2.875% Convertible Senior Notes Due 2038 [Member]	Sep. 30, 2011 2.875% Convertible Senior Notes Due 2038 [Member]	Jun. 30, 2011 2.875% Convertible Senior Notes Due 2038 [Member]	Dec. 31, 2011 2.875% Convertible Senior Notes Due 2038 [Member]	Jun. 30, 2012 Pioneer Southwest Credit Facility [Member] Rate	Mar. 31, 2012 If Converted [Member] 2.875% Convertible Senior Notes Due 2038 [Member]	Mar. 31, 2012 Non-Cash [Member] If Converted [Member] 2.875% Convertible Senior Notes Due 2038 [Member]
Debt Instrument [Line Items]
Outstanding borrowing					$ 110,000,000	$ 69,000,000
Undrawn letters of credit					40,100,000
Unused borrowing capacity					1,100,000,000	231,000,000
Undrawn Letters Of Credit Cancelled				39,000,000
Debt Instrument Covenant, Maximum Leverage Ratio															350.00%
Debt Instrument Covenant, Net Present Value of Cash Flow to Total Debt Ratio															175.00%
Aggregate loan commitments							300,000,000
Senior Notes								600,000,000	600,000,000
Convertible Debt	479,900,000		479,900,000
Senior notes, interest rate, percentage								3.95%	3.95%		2.875%			2.875%
Value of shares received for conversion of debt											22,000		70,000				161,000,000
Shares issued for conversion of debt											50	340				1,800,000
Cash Paid To Conversion Of Convertible Senior Notes										15,000	7,000	71,000
Cash received from note holders																479,900,000
Senior Note Debt Instrument Maturity Date									2022
Debt Instrument, Unamortized Discount								8,500,000	8,500,000
Proceeds from Issuance of Long-term Debt	$ 1,339,093,000	$ 72,610,000						$ 591,500,000

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Organization And Nature Of Operations

6 Months Ended

Jun. 30, 2012

Organization And Nature Of Operations [Abstract]

Organization And Nature Of Operations

Organization and Nature of Operations

Pioneer Natural Resources Company ("Pioneer" or the "Company") is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. The Company is a large independent oil and gas exploration and production company with continuing operations in the United States.

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Exploratory Costs (Schedule Of Capitalized Exploratory Well And Project Activity) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2012
Exploratory Costs [Abstract]
Beginning capitalized exploratory costs	$ 138,002	$ 107,596
Additions to exploratory costs pending the determination of proved reserves	205,938	380,832
Reclassification due to determination of proved reserves	(148,805)	(266,415)
Exploratory well costs charged to exploration expense	(1,408)	(28,286)
Ending capitalized exploratory costs	$ 193,727	$ 193,727

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Income Taxes (Tables)

6 Months Ended

Jun. 30, 2012

Income Tax Disclosure [Abstract]

Income tax (provisions) benefits attributable to income from continuing operations

The Company's income tax (provisions) benefits attributable to income from continuing operations consisted of the following for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)
Current	$	(3,494	)	$	(2,540	)	$	(15,326	)	$	(4,938	)
Deferred	48,580			(137,642		)	(57,291		)	(87,337		)
Income tax benefit (provision)	$	45,086		$	(140,182	)	$	(72,617	)	$	(92,275	)
Effective tax rate (a)	35		%	36		%	37		%	34		%

 ____________________

(a) Represents the income tax benefit or provision divided by the income or loss from continuing operations before income taxes excluding the effect of net income attributable to noncontrolling interests.

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2012

Fair Value Disclosures [Abstract]

Schedule of assets and liabilities measured at fair value on a recurring basis

The following table presents the Company's assets and liabilities that are measured at fair value as of June 30, 2012:

	Fair Value Measurement at the End of the Reporting Period Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Fair Value at June 30, 2012
	(in thousands)
Recurring fair value measurements
Assets:
Trading securities	$	251	$	168		$	—	$	419
Commodity derivatives	—		569,691			—		569,691
Deferred compensation plan assets	44,191		—			—		44,191
Total assets	$	44,442	$	569,859		$	—	$	614,301
Liabilities:
Commodity derivatives	$	—	$	(13,742	)	$	—	$	(13,742	)
Interest rate derivatives	—		(34,693		)	—		(34,693		)
Total liabilities	$	—	$	(48,435	)	$	—	$	(48,435	)
Total recurring fair value measurements	$	44,442	$	521,424		$	—	$	565,866

Schedule of carrying values and financial instruments not carried at fair value

Carrying values and fair values of financial instruments that are not carried at fair value in the consolidated balance sheet as of June 30, 2012 and December 31, 2011 are as follows:

	June 30, 2012				December 31, 2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Long-term debt	$	3,285,497	$	3,934,014	$	2,528,905	$	3,105,585

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Net Income (Loss) Per Share (Reconciliation Of Earnings Attributable To Common Stockholders, Basic And Diluted) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Statement Operating Activities Segment [Line Items]
Income (loss) from continuing operations attributable to parent	$ (82,409)	$ 248,602	$ 121,515	$ 177,314
Income (loss) from discontinued operations, net of tax, attributable to parent	12,017	(3,025)	22,712	416,857
Income (loss) as reported	(70,392)	245,577	144,227	594,171
Participating basic earnings	(265)	(4,847)	(2,176)	(10,849)
Basic income attributable to common stockholders	(70,657)	240,730	142,051	583,322
Reallocation of participating earnings	0	164	154	271
Diluted income attributable to common stockholders	(70,657)	240,894	142,205	583,593
Continuing Operations [Member]
Statement Operating Activities Segment [Line Items]
Income (loss) from continuing operations attributable to parent	(82,409)	248,602	121,515	177,314
Participating basic earnings	(265)	(4,847)	(1,833)	(3,238)
Basic income attributable to common stockholders	(82,674)	243,755	119,682	174,076
Reallocation of participating earnings	0	164	130	81
Diluted income attributable to common stockholders	(82,674)	243,919	119,812	174,157
Discontinued Operations [Member]
Statement Operating Activities Segment [Line Items]
Income (loss) from discontinued operations, net of tax, attributable to parent	12,017	(3,025)	22,712	416,857
Participating basic earnings	0	0	(343)	(7,611)
Basic income attributable to common stockholders	12,017	(3,025)	22,369	409,246
Reallocation of participating earnings	0	0	24	190
Diluted income attributable to common stockholders	$ 12,017	$ (3,025)	$ 22,393	$ 409,436

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Fair Value Measurements (Schedule Of Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	$ 614,301
Liabilities, (Fair Value, Total)	(48,435)
Recurring Measurements, (Fair Value, Total)	565,866
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	44,442
Liabilities, (Fair Value, Total)	0
Recurring Measurements, (Fair Value, Total)	44,442
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	569,859
Liabilities, (Fair Value, Total)	(48,435)
Recurring Measurements, (Fair Value, Total)	521,424
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	0
Liabilities, (Fair Value, Total)	0
Recurring Measurements, (Fair Value, Total)	0
Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)	(34,693)
Interest Rate Derivatives [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)	0
Interest Rate Derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)	(34,693)
Interest Rate Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)	0
Trading Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	419
Trading Securities [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	251
Trading Securities [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	168
Trading Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	0
Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	569,691
Liabilities, (Fair Value, Total)	(13,742)
Commodity Derivatives [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	0
Liabilities, (Fair Value, Total)	0
Commodity Derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	569,691
Liabilities, (Fair Value, Total)	(13,742)
Commodity Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	0
Liabilities, (Fair Value, Total)	0
Deferred Compensation Plan Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	44,191
Deferred Compensation Plan Assets [Member] | Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	44,191
Deferred Compensation Plan Assets [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	0
Deferred Compensation Plan Assets [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	$ 0

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Derivative Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of oil derivative contracts volume and weighted average price

The following table sets forth the volumes per day in barrels ("BBLs") outstanding as of June 30, 2012 under the Company's oil derivative contracts and the weighted average oil prices per BBL for those contracts:

	Six Months Ending December 31,			Twelve Months Ending December 31,
	2012			2013		2014
Collar contracts with short puts:
Volume (BBL) (a)	51,610			67,290		40,000
Average price per BBL:
Ceiling	$	118.73		$	120.61	$	122.77
Floor	$	84.80		$	88.88	$	91.50
Short put	$	69.12		$	71.72	$	74.88
Collar contracts:
Volume (BBL)	2,000			—		—
Average price per BBL:
Ceiling	$	127.00		$	—	$	—
Floor	$	90.00		$	—	$	—
Swap contracts:
Volume (BBL) (a)	3,000			3,000		—
Average price per BBL	$	79.32		$	81.02	$	—
Rollfactor swap contracts:
Volume (BBL)	—			6,000		—
NYMEX roll price (b)	$	—		$	0.43	$	—
Basis swap contracts:
Index swap volume (BBL)	20,000			—		—
Average price per BBL (c)	$	(1.15	)	$	—	$	—

Schedule of gas volume and weighted average prices

The following table sets forth the volumes per day in millions of British thermal units ("MMBTU") outstanding as of June 30, 2012 under the Company's gas derivative contracts and the weighted average gas prices per MMBTU for those contracts:

	Six Months Ending December 31,			Twelve Months Ending December 31,
	2012			2013			2014 (a)			2015 (a)
Collar contracts with short puts:
Volume (MMBTU)	—			—			30,000			135,000
Price per MMBTU:
Ceiling	$	—		$	—		$	7.66		$	5.44
Floor	$	—		$	—		$	5.67		$	4.22
Short put	$	—		$	—		$	4.33		$	3.22
Collar contracts:
Volume (MMBTU)	65,000			150,000			80,000			50,000
Price per MMBTU:
Ceiling	$	6.60		$	6.25		$	6.39		$	7.92
Floor	$	5.00		$	5.00		$	5.00		$	5.00
Swap contracts:
Volume (MMBTU)	275,000			112,500			10,000			—
Price per MMBTU	$	4.97		$	5.62		$	6.18		$	—
Basis swap contracts:
Volume (MMBTU)	136,000			142,500			140,000			—
Price per MMBTU	$	(0.34	)	$	(0.22	)	$	(0.21	)	$	—

Schedule of marketing and basis transfer derivative contracts

The following table sets forth the contract volumes outstanding as of June 30, 2012 under the Company's marketing and basis transfer derivative contracts and the weighted average gas prices per MMBTU for those contracts:

	Six Months Ending December 31,
	2012
Average Daily Gas Production Associated with Marketing Derivatives (MMBTU):
Basis swap contracts:
Index swap volume	26,739
Price differential ($/MMBTU)	$	0.25
Average Daily Gas Production Associated with Basis Transfer Derivatives (MMBTU):
Basis swap contracts:
Short index swap volume	3,343
NGI-So Cal Border Monthly price differential to NYMEX HH ($/MMBTU)	$	0.12
Long index swap volume	$	(3,343	)
IF-HSC price differential to NYMEX HH ($/MMBTU)	$	(0.05	)

Schedule of derivative instruments

The following tables provide disclosure of the Company's derivative instruments:

Fair Value of Derivative Instruments as of June 30, 2012
	Asset Derivatives (a)			Liability Derivatives (a)
Type	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(in thousands)			(in thousands)
Derivatives not designated as hedging instruments
Commodity price derivatives	Derivatives - current	$	318,503	Derivatives - current	$	17,108
Interest rate derivatives	Derivatives - current	—		Derivatives - current	23,283
Commodity price derivatives	Derivatives - noncurrent	270,681		Derivatives - noncurrent	16,127
Interest rate derivatives	Derivatives - noncurrent	—		Derivatives - noncurrent	11,410
		$	589,184		$	67,928

Fair Value of Derivative Instruments as of December 31, 2011
	Asset Derivatives (a)			Liability Derivatives (a)
Type	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(in thousands)			(in thousands)
Derivatives not designated as hedging instruments
Commodity price derivatives	Derivatives - current	$	248,809	Derivatives - current	$	68,735
Interest rate derivatives	Derivatives - current	—		Derivatives - current	15,654
Commodity price derivatives	Derivatives - noncurrent	257,368		Derivatives - noncurrent	47,689
		$	506,177		$	132,078

Schedule of derivative obligations under terminated hedge arrangements

Derivatives in Cash Flow Hedging	Location of Gain/(Loss) Reclassified from	Amount of Gain/(Loss) Reclassified from AOCI into Earnings
		Three Months Ended June 30,						Six Months Ended June 30,
Relationships	AOCI into Earnings	2012			2011			2012			2011
		(in thousands)
Commodity price derivatives	Oil and gas revenue	$	(2,347	)	$	8,208		$	(3,156	)	$	16,332
Interest rate derivatives	Interest expense	—			(69		)	(1,699		)	(137		)
Total		$	(2,347	)	$	8,139		$	(4,855	)	$	16,195

		Amount of Gain (Loss) Recognized in Earnings on Derivatives
Derivatives Not Designated as Hedging	Location of Gain (Loss) Recognized in	Three Months Ended June 30,					Six Months Ended June 30,
Instruments	Earnings on Derivatives	2012			2011		2012			2011
		(in thousands)
Commodity price derivatives	Derivative gains (losses), net	$	298,471		$	214,903	$	386,601		$	(27,377	)
Interest rate derivatives	Derivative gains (losses), net	(22,659		)	14,575		(19,039		)	12,423
Total		$	275,812		$	229,478	$	367,562		$	(14,954	)

Schedule of derivative assets and liabilities by counterparty

The following table provides the Company's derivative assets and liabilities by counterparty as of June 30, 2012:

	Assets		Liabilities
	(in thousands)
JP Morgan Chase	$	119,358	$	15,217
Citibank, N.A.	87,788		438
Barclays Capital	53,131		—
BMO Financial Group	42,192		—
BNP Paribas	40,677		—
J. Aron & Company	33,071		—
Wells Fargo Bank, N.A.	31,419		20,981
Credit Suisse	29,795		—
Toronto Dominion	29,206		—
Credit Agricole	28,179		2,177
Societe Generale	24,356		—
Merrill Lynch	16,880		2,775
Morgan Stanley	16,184		885
Den Norske Bank	9,790		—
BP Corporation North America	4,040		—
Deutsche Bank	2,194		2,363
Vitol	1,345		—
Macquarie Bank	86		—
Royal Bank of Canada	—		262
UBS	—		3,337
Total	$	569,691	$	48,435

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Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2012

Asset Retirement Obligation [Abstract]

Schedule of asset retirement obligations

The following table summarizes the Company's asset retirement obligation activity during the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)
Beginning asset retirement obligations	$	134,314		$	154,689		$	136,742		$	152,291
Liabilities assumed in acquisitions	8,515			—			8,515			6
New wells placed on production	1,581			1,404			2,411			2,075
Changes in estimates	1,603			(179		)	1,603			121
Disposition of wells	—			(367		)	—			(448		)
Liabilities settled	(3,054		)	(6,235		)	(8,742		)	(7,469		)
Accretion of discount from continuing operations	2,444			2,048			4,874			4,092
Accretion of discount from integrated services (a)	54			—			54			—
Accretion of discount from discontinued operations	—			610			—			1,302
Ending asset retirement obligations	$	145,457		$	151,970		$	145,457		$	151,970

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Consolidated Statements Of Cash Flows (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
Cash flows from operating activities:
Net income	$ 181,421	$ 609,504
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	382,339	258,345
Impairment of oil and gas properties	444,880	0
Exploration expenses, including dry holes	39,730	4,275
Deferred income taxes	(57,291)	(87,337)
Gain (loss) on disposition of assets, net	(44,736)	2,487
Accretion of discount on asset retirement obligations	4,874	4,092
Discontinued operations	3,597	(390,868)
Interest expense	18,152	15,432
Derivative related activity	(144,000)	56,380
Amortization of stock-based compensation	30,970	21,155
Amortization of deferred revenue	(20,919)	(22,290)
Other noncash items	(7,513)	(9,207)
Change in operating assets and liabilities, net of effects from acquisitions and dispositions:
Accounts receivable, net	33,881	(23,605)
Income taxes receivable	(1,452)	27,226
Inventories	(33,318)	(74,136)
Prepaid expenses	(13,425)	(9,990)
Other current assets	(8,846)	8,772
Accounts payable	30,580	6,201
Interest payable	82	(1,642)
Income taxes payable	(7,907)	(11,485)
Other current liabilities	20,271	(6,471)
Net cash provided by operating activities	925,410	564,454
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold	62,945	813,520
Payments for acquisition, net of cash acquired	(295,974)	0
Investment in unconsolidated subsidiary	0	(82,857)
Additions to oil and gas properties	(1,424,807)	(757,148)
Additions to other assets and other property and equipment, net	(164,230)	(215,367)
Net cash used in investing activities	(1,822,066)	(241,852)
Cash flows from financing activities:
Borrowings under long-term debt	1,339,093	72,610
Principal payments on long-term debt	(596,000)	(115,810)
Distributions to noncontrolling interests	(17,956)	(13,366)
Payments of other liabilities	(744)	(305)
Exercise of long-term incentive plan stock options	1,008	362
Purchases of treasury stock	(56,317)	(39,218)
Excess tax benefits from share-based payment arrangements	17,545	27,937
Payment of financing fees	(4,660)	(8,739)
Dividends paid	(5,028)	(4,812)
Net cash provided by (used in) financing activities	676,941	(81,341)
Net increase (decrease) in cash and cash equivalents	(219,715)	241,261
Cash and cash equivalents, beginning of period	537,484	111,160
Cash and cash equivalents, end of period	$ 317,769	$ 352,421

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Incentive Plans (Tables)

6 Months Ended

Jun. 30, 2012

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Schedule of accumulated postretirement benefit obligations

The following table summarizes the activity that occurred during the six months ended June 30, 2012, for each type of share-based incentive award issued by Pioneer:

	Restricted Stock Equity Awards		Restricted Stock Liability Awards		Performance Units	Stock Options		Pioneer Southwest LTIP Restricted Units		Pioneer Southwest LTIP Phantom Units
Outstanding at December 31, 2011	1,857,612		322,925		114,128	564,044		7,492		65,157
Awards granted	897,591		223,375		47,875	98,819		7,496		37,487
Awards vested	(1,199,536	)	(115,700	)	—	—		(7,492	)	—
Options exercised	—		—		—	(64,509	)	—		—
Awards forfeited	(15,145	)	(10,342	)	—	—		—		—
Outstanding as of June 30, 2012	1,540,522		420,258		162,003	598,354		7,496		102,644

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Acquisitions and Divestitures (Discontinued Operations Narrative) (Details) (USD $)	3 Months Ended		6 Months Ended			12 Months Ended	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012 Pioneer South Africa [Member]	Dec. 31, 2011 Pioneer Tunisia [Member]	Jun. 30, 2011 BOEMRE [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of interest in consolidated subsidiaries					$ 52,000,000	$ 802,500,000
Disposal group, including discontinued operation, gross profit (loss)						645,200,000
Interest and other	$ 0	$ 35,000	$ 20,000	$ 4,971,000			$ 2,000,000

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Derivative Financial Instruments Schedule of Derivative Assets and Liabilities by Counterparty (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets	$ 569,691
Derivative Liabilities	48,435
JP Morgan Chase Counterparty [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets	119,358
Derivative Liabilities	15,217
Citibank, N.A. Counterparty [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets	87,788
Derivative Liabilities	438
Barclays Capital Counterparty [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets	53,131
Derivative Liabilities	0
BMO Financial Group [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets	42,192
Derivative Liabilities	0
BNP Paribas [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets	40,677
Derivative Liabilities	0
J. Aron & Company [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets	33,071
Derivative Liabilities	0
Wells Fargo Bank, N.A. Counterparty [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets	31,419
Derivative Liabilities	20,981
Credit Suisse [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets	29,795
Derivative Liabilities	0
Toronto Dominion Counterparty [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets	29,206
Derivative Liabilities	0
Societe Generale [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets	28,179
Derivative Liabilities	2,177
Merrill Lynch [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets	24,356
Derivative Liabilities	0
Merrill Lynch [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets	16,880
Derivative Liabilities	2,775
Morgan Stanley [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets	16,184
Derivative Liabilities	885
Den Norske Bank [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets	9,790
Derivative Liabilities	0
BP Corporation North America [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets	4,040
Derivative Liabilities	0
Deutsche Bank [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets	2,194
Derivative Liabilities	2,363
Vitol [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets	1,345
Derivative Liabilities	0
Macquarie Bank [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets	86
Derivative Liabilities	0
Royal Bank of Canada [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets	0
Derivative Liabilities	262
UBS [Member]
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items]
Derivative Assets	0
Derivative Liabilities	$ 3,337

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Current assets:
Cash and cash equivalents	$ 317,769	$ 537,484
Accounts receivable:
Trade, net of allowance for doubtful accounts of $706 and $806 as of June 30, 2012 and December 31, 2011, respectively	250,192	275,991
Due from affiliates	2,301	7,822
Income taxes receivable	2,417	3
Inventories	277,539	241,609
Prepaid expenses	28,213	14,263
Discontinued operations held for sale	70,177	73,349
Other current assets:
Derivatives	308,762	238,835
Other	26,663	12,936
Total current assets	1,284,033	1,402,292
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	12,964,291	12,013,805
Unproved properties	296,827	235,527
Accumulated depletion, depreciation and amortization	(4,013,770)	(3,648,465)
Total property, plant and equipment	9,247,348	8,600,867
Goodwill	298,142	298,142
Other property and equipment, net	1,134,532	573,075
Other assets:
Investment in unconsolidated affiliate	184,374	169,532
Derivatives	260,929	243,240
Other, net of allowance for doubtful accounts of $655 and $340 as of June 30, 2012 and December 31, 2011, respectively	160,376	160,008
Assets, Total	12,569,734	11,447,156
Accounts payable:
Trade	769,611	647,455
Due to affiliates	39,547	68,756
Interest payable	57,329	57,240
Income taxes payable	1,881	9,788
Deferred Tax Liabilities, Net, Current	89,656	57,713
Discontinued operations held for sale	77,310	75,901
Other current liabilities:
Derivatives	30,650	74,415
Deferred revenue	21,150	42,069
Other	41,857	36,174
Total current liabilities	1,128,991	1,069,511
Long-term debt	3,285,497	2,528,905
Derivatives	17,785	33,561
Deferred income taxes	2,154,301	1,942,446
Other liabilities	226,184	221,595
Stockholders' equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 134,763,095 and 133,121,092 shares issued at June 30, 2012 and December 31, 2011, respectively	1,348	1,331
Additional paid-in capital	3,611,799	3,613,808
Treasury stock at cost: 11,727,359 and 11,264,936 at June 30, 2012 and December 31, 2011, respectively	(511,628)	(458,281)
Retained earnings	2,473,504	2,335,066
Accumulated other comprehensive loss - net deferred hedge losses, net of tax	0	(3,130)
Total equity attributable to common stockholders	5,575,023	5,488,794
Noncontrolling interests in consolidating subsidiaries	181,953	162,344
Total equity	5,756,976	5,651,138
Commitments and contingencies
Liabilities and Stockholders' Equity, Total	$ 12,569,734	$ 11,447,156

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Fair Value Measurements (Schedule Of Carrying Values And Financial Instruments Not Carried At Fair Value) (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt Element	$ 3,285,497	$ 2,528,905
Carrying Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt Element	3,285,497	2,528,905
Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt Element	$ 3,934,014	$ 3,105,585

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Consolidated Statement Of Equity (USD $) In Thousands, except Share data, unless otherwise specified	Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Treasury Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Noncontrolling Interests [Member]
Balance at Dec. 31, 2011	$ 5,651,138	$ 1,331	$ 3,613,808	$ (458,281)	$ 2,335,066	$ (3,130)	$ 162,344
Balance, shares at Dec. 31, 2011		121,856,000
Dividends declared ($0.04 per share)	(4,982)				(4,982)
Exercise of long-term incentive plan stock options	1,008		(965)	2,780	(807)
Exercise of long-term incentive plan stock options, shares		65,000
Treasury stock purchases	(56,317)			(56,129)			(188)
Treasury stock purchases, shares		(527,000)
Conversion of 2.875% senior convertible notes	0		(2)	2
Tax benefit related to stock-based compensation	17,545		17,545
Deferred tax provision attributable to 2008 Pioneer Southwest initial public offering	(49,072)		(49,072)
Compensation costs:
Vested compensation awards, net	0	17	(17)
Vested compensation awards, net, shares		1,642,000
Compensation costs included in net income	31,061		30,502				559
Cash distributions to noncontrolling interests	(17,956)						(17,956)
Net income	181,421				144,227		37,194
Deferred hedging activity, net of tax:
Net hedge losses included in continuing operations	3,130					3,130
Balance at Jun. 30, 2012	$ 5,756,976	$ 1,348	$ 3,611,799	$ (511,628)	$ 2,473,504	$ 0	$ 181,953
Balance, shares at Jun. 30, 2012		123,036,000

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Other Expense (Schedule Of Components Of Other Expense) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2012		Jun. 30, 2011		Jun. 30, 2012		Jun. 30, 2011
Other Expense [Abstract]
Transportation commitment charges	$ 9,227	[1]	$ 5,688	[1]	$ 17,680	[1]	$ 10,960	[1]
Above market drilling rig rates	5,760	[2]	5,410	[2]	10,746	[2]	10,569	[2]
Terminated drilling rig contract charges	8,960	[3]	0	[3]	8,960	[3]	0	[3]
Inventory valuation charges	1,262	[4]	302	[4]	7,454	[4]	587	[4]
Other	4,578		(934)		6,346		2,549
Premier Silica acquisition costs	1,190		0		2,173		0
Contingency and environmental accrual adjustments	(326)		1,587		702		2,882
Loss on extinguishment of debt	0		0		197		2,367
Total other expense	$ 30,651		$ 12,053		$ 54,258		$ 29,914

[1] Primarily represents firm transportation payments on excess pipeline capacity commitments.

[2] Primarily represents expenses attributable to the portion of Pioneer's contracted drilling rig rates that are above current market rates and idle drilling rig fees, neither of which are charged to joint operations.

[3] Primarily represents charges to terminate rig contracts that are not required to meet planned drilling activities.

[4] Represents valuation charges on excess materials and supplies inventories; principally related to dry gas assets.

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Other Expense (Tables)

6 Months Ended

Jun. 30, 2012

Other Expense [Abstract]

Schedule of components of other expense

The following table provides the components of the Company's other expense:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012		2011
	(in thousands)
Transportation commitment charges (a)	$	9,227		$	5,688		$	17,680	$	10,960
Above market drilling rig rates (b)	5,760			5,410			10,746		10,569
Terminated drilling rig contract charges (c)	8,960			—			8,960		—
Inventory valuation charges (d)	1,262			302			7,454		587
Other	4,578			(934		)	6,346		2,549
Premier Silica acquisition costs	1,190			—			2,173		—
Contingency and environmental accrual adjustments	(326		)	1,587			702		2,882
Loss on extinguishment of debt	—			—			197		2,367
Total other expense	$	30,651		$	12,053		$	54,258	$	29,914

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Other Expense

6 Months Ended

Jun. 30, 2012

Other Expense [Abstract]

Other Expense

Other Expense

The following table provides the components of the Company's other expense:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012		2011
	(in thousands)
Transportation commitment charges (a)	$	9,227		$	5,688		$	17,680	$	10,960
Above market drilling rig rates (b)	5,760			5,410			10,746		10,569
Terminated drilling rig contract charges (c)	8,960			—			8,960		—
Inventory valuation charges (d)	1,262			302			7,454		587
Other	4,578			(934		)	6,346		2,549
Premier Silica acquisition costs	1,190			—			2,173		—
Contingency and environmental accrual adjustments	(326		)	1,587			702		2,882
Loss on extinguishment of debt	—			—			197		2,367
Total other expense	$	30,651		$	12,053		$	54,258	$	29,914

 ____________________

(a) Primarily represents firm transportation payments on excess pipeline capacity commitments.

(b) Primarily represents expenses attributable to the portion of Pioneer's contracted drilling rig rates that are above current market rates and idle drilling rig fees, neither of which are charged to joint operations.

(c) Primarily represents charges to terminate rig contracts that are not required to meet planned drilling activities.

(d) Represents valuation charges on excess materials and supplies inventories; principally related to dry gas assets.

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Basis Of Presentation Basis of Presentation (Equity - Additional Paid in Capital) (Details) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2012
Subsidiary or Equity Method Investee [Line Items]
Deferred tax provision attributable to 2008 Pioneer Southwest initial public offering	$ (49,072)
Pioneer Southwest Ltip [Member]
Subsidiary or Equity Method Investee [Line Items]
Deferred tax provision attributable to 2008 Pioneer Southwest initial public offering	$ (49,072)

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Subsequent Events

1 Months Ended

Aug. 03, 2012

Subsequent Events [Abstract]

Subsequent Events

Subsequent Event

Distribution declaration. In July 2012, Pioneer Southwest declared a cash distribution of $0.52 per common unit for the period from April 1, 2012 to June 30, 2012. The distribution is payable on August 9, 2012 to unitholders of record at the close of business on August 2, 2012. Associated therewith, Pioneer Southwest expects to pay $18.6 million of aggregate distributions.

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Consolidated Statement Of Equity (Parenthetical) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Statement of Stockholders' Equity [Abstract]
Dividends declared per share	$ 0.00	$ 0.00	$ 0.04	$ 0.04

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Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Per Share data, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Statement of Financial Position [Abstract]
Trade, allowance for doubtful accounts	$ 706	$ 806
Other, allowance for doubtful accounts	$ 655	$ 340
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	500,000,000	500,000,000
Common stock, shares issued	134,763,095	133,121,092
Treasury stock, shares	11,727,359	11,264,936

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Asset Retirement Obligations

6 Months Ended

Jun. 30, 2012

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells, restoration of certain sand mines and related facilities. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company's credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations.

The following table summarizes the Company's asset retirement obligation activity during the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)
Beginning asset retirement obligations	$	134,314		$	154,689		$	136,742		$	152,291
Liabilities assumed in acquisitions	8,515			—			8,515			6
New wells placed on production	1,581			1,404			2,411			2,075
Changes in estimates	1,603			(179		)	1,603			121
Disposition of wells	—			(367		)	—			(448		)
Liabilities settled	(3,054		)	(6,235		)	(8,742		)	(7,469		)
Accretion of discount from continuing operations	2,444			2,048			4,874			4,092
Accretion of discount from integrated services (a)	54			—			54			—
Accretion of discount from discontinued operations	—			610			—			1,302
Ending asset retirement obligations	$	145,457		$	151,970		$	145,457		$	151,970

_____________________

(a) Accretion of discount from integrated services includes Premier Silica accretion expense, which is recorded as a reduction in third-party income from vertical integration services in interest and other income in the Company's accompanying consolidated statements of operations. See Note M for more information about interest and other income.

The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets. As of June 30, 2012 and December 31, 2011, the current portions of the Company's asset retirement obligations were $18.6 million and $14.2 million, respectively.

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Document And Entity Information	6 Months Ended
	Jun. 30, 2012	Aug. 01, 2012
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q2
Trading Symbol	PXD
Entity Registrant Name	PIONEER NATURAL RESOURCES CO
Entity Central Index Key	0001038357
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		123,035,765

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Incentive Plans

6 Months Ended

Jun. 30, 2012

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Incentive Plans

Incentive Plans

Stock-based compensation

For the three and six months ended June 30, 2012, the Company recorded $21.7 million and $43.3 million, respectively, of stock-based compensation expense for all plans, as compared to $13.8 million and $26.4 million for the same respective periods of 2011. As of June 30, 2012, there was $156.0 million of unrecognized compensation expense related to unvested share- and unit-based compensation plan awards, including $27.0 million attributable to stock-based awards that are expected to be settled in cash on their vesting date, rather than in equity shares ("Liability Awards"). This compensation will be recognized over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis. As of June 30, 2012 and December 31, 2011, accounts payable – due to affiliates includes $8.2 million and $9.2 million, respectively, of liabilities attributable to Liability Awards.

The Company's issued shares, as reflected in the consolidated balance sheets at June 30, 2012 and December 31, 2011, do not include 304,260 and 533,125 common shares, respectively, associated with unvested stock-based compensation awards that have voting rights.

The following table summarizes the activity that occurred during the six months ended June 30, 2012, for each type of share-based incentive award issued by Pioneer:

	Restricted Stock Equity Awards		Restricted Stock Liability Awards		Performance Units	Stock Options		Pioneer Southwest LTIP Restricted Units		Pioneer Southwest LTIP Phantom Units
Outstanding at December 31, 2011	1,857,612		322,925		114,128	564,044		7,492		65,157
Awards granted	897,591		223,375		47,875	98,819		7,496		37,487
Awards vested	(1,199,536	)	(115,700	)	—	—		(7,492	)	—
Options exercised	—		—		—	(64,509	)	—		—
Awards forfeited	(15,145	)	(10,342	)	—	—		—		—
Outstanding as of June 30, 2012	1,540,522		420,258		162,003	598,354		7,496		102,644

Postretirement Benefit Obligations

As of June 30, 2012 and December 31, 2011, the Company had $8.5 million and $7.5 million, respectively, of unfunded accumulated postretirement benefit obligations, the current and noncurrent portions of which are included in other current liabilities and other liabilities in the accompanying consolidated balance sheets. These obligations are comprised of five unfunded plans, of which four relate to predecessor entities that the Company acquired in prior years, and two funded plans that the Company assumed sponsorship for in conjunction with the acquisition of Premier Silica.

The unfunded plans had no assets as of June 30, 2012 or December 31, 2011. The Company's funding policy for the Premier Silica plans is to contribute amounts sufficient to meet legal funding requirements, plus any additional amounts that the Company may determine to be appropriate considering the funded status of the plan, tax deductibility, the cash flow generated by the Company, and other factors. The Company continually reassesses the amount and timing of any discretionary contributions and could elect to make such a contribution in 2012.

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Consolidated Statements Of Operations (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Revenues and other income:
Oil and gas	$ 641,737	$ 562,412	$ 1,360,693	$ 1,038,140
Interest and other	6,043	13,594	34,491	42,067
Derivative gains (losses), net	275,812	229,478	367,562	(14,954)
Gain (loss) on disposition of assets, net	1,140	(296)	44,736	(2,487)
Total revenues and other income	924,732	805,188	1,807,482	1,062,766
Costs and expenses:
Oil and gas production	156,838	101,741	295,159	200,576
Production and ad valorem taxes	44,495	35,864	90,291	69,160
Depletion, depreciation and amortization	200,921	135,511	382,339	258,345
Impairment of oil and gas properties	444,880	0	444,880	0
Exploration and abandonments	37,178	19,732	90,465	37,216
General and administrative	54,957	44,339	118,024	88,250
Accretion of discount on asset retirement obligations	2,444	2,048	4,874	4,092
Interest	49,008	44,995	95,866	90,222
Hurricane activity, net	0	(2)	0	69
Other	30,651	12,053	54,258	29,914
Costs and expenses, Total	1,021,372	396,281	1,576,156	777,844
Income (loss) from continuing operations before income taxes	(96,640)	408,907	231,326	284,922
Income tax benefit (provision)	45,086	(140,182)	(72,617)	(92,275)
Income (loss) from continuing operations	(51,554)	268,725	158,709	192,647
Income (loss) from discontinued operations, net of tax	12,017	(3,025)	22,712	416,857
Net income (loss)	(39,537)	265,700	181,421	609,504
Net income attributable to noncontrolling interests	(30,855)	(20,123)	(37,194)	(15,333)
Net income (loss) attributable to common stockholders	(70,392)	245,577	144,227	594,171
Basic earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$ (0.67)	$ 2.10	$ 0.98	$ 1.50
Income (loss) from discontinued operations attributable to common stockholders	$ 0.10	$ (0.03)	$ 0.18	$ 3.53
Net income (loss) attributable to common stockholders	$ (0.57)	$ 2.07	$ 1.16	$ 5.03
Diluted earnings per share:
Income (loss) from continuing operations attributable to common stockholders	$ (0.67)	$ 2.06	$ 0.95	$ 1.46
Income (loss) from discontinued operations attributable to common stockholders	$ 0.10	$ (0.03)	$ 0.18	$ 3.44
Net income (loss) attributable to common stockholders	$ (0.57)	$ 2.03	$ 1.13	$ 4.90
Weighted average shares outstanding:
Basic	123,028	116,213	122,754	116,042
Diluted	123,028	118,592	125,772	118,986
Dividends declared per share	$ 0.00	$ 0.00	$ 0.04	$ 0.04
Amounts attributable to common stockholders:
Income (loss) from continuing operations	(82,409)	248,602	121,515	177,314
Income (loss) from discontinued operations, net of tax	12,017	(3,025)	22,712	416,857
Net income (loss)	$ (70,392)	$ 245,577	$ 144,227	$ 594,171

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Exploratory Costs

6 Months Ended

Jun. 30, 2012

Exploratory Costs [Abstract]

Exploratory Costs

Exploratory Costs

The Company capitalizes exploratory well and project costs until a determination is made that the well or project has either found proved reserves, is impaired or is sold. The Company's capitalized exploratory well and project costs are presented in proved properties in the accompanying consolidated balance sheets. If the exploratory well or project is determined to be impaired, the impaired costs are charged to exploration and abandonments expense.

The following table reflects the Company's capitalized exploratory well and project activity during the three and six months ended June 30, 2012:

	Three Months Ended June 30, 2012			Six Months Ended June 30, 2012
	(in thousands)
Beginning capitalized exploratory costs	$	138,002		$	107,596
Additions to exploratory costs pending the determination of proved reserves	205,938			380,832
Reclassification due to determination of proved reserves	(148,805		)	(266,415		)
Exploratory well costs charged to exploration expense	(1,408		)	(28,286		)
Ending capitalized exploratory costs	$	193,727		$	193,727

As of June 30, 2012 and December 31, 2011, the Company had no exploratory projects for which exploratory costs have been capitalized for a period greater than one year from the date drilling was completed.

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Acquisitions and Divestitures

6 Months Ended

Jun. 30, 2012

Acquisitions and Divestitures [Abstract]

Acquisition and Divestitures

Acquisitions and Divestitures

Premier Silica Business Combination

On April 2, 2012, a wholly-owned subsidiary of Pioneer acquired 100 percent of the share capital of Industrial Sands Holding Company and its wholly-owned subsidiary, Oglebay Norton Industrial Sands, LLC (the "Acquisition"). During April 2012, the name of Oglebay Norton Industrial Sands, LLC was changed to Premier Silica LLC ("Premier Silica"). Premier Silica's core business is the operation of mines and processing facilities that produce, process and sell sand, primarily to upstream oil and gas companies for proppant used in the fracture stimulation of oil and gas wells in the United States. Premier Silica's business is supportive to the Company's vertical integration strategy of controlling major cost components of the Company's drilling and production activities in the areas where the Company has a significant inventory of drilling locations and a significant number of producing wells. The aggregate purchase price of Premier Silica was $296.0 million, including estimated closing adjustments, and was funded from available cash and borrowings under the Company's credit facility.

The Acquisition was accounted for as a business combination which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. The Company's assessment of the fair values of Premier Silica's assets and liabilities is preliminary, and may be adjusted as a result of normal closing adjustments. The fair value of the tangible assets acquired totaled $468.9 million and were primarily comprised of proved sand reserves, probable sand reserves and mine processing facilities and equipment of $454.5 million. The fair value of liabilities assumed totaled $172.9 million and were primarily comprised of deferred income taxes of $150.8 million.

The Company recognized $1.2 million and $2.2 million of acquisition-related costs that were expensed in the three and six months ended June 30, 2012. These costs are included in other expense in the accompanying consolidated statements of operations for the three and six months ended June 30, 2012.

Divestitures Recorded as Discontinued Operations

South Africa. During December 2011, the Company committed to a plan to exit South Africa and initiated a process to divest of its net assets in South Africa ("Pioneer South Africa"). In March 2012, the Company agreed to sell its net assets in Pioneer South Africa to an unaffiliated third party, using a January 1, 2012 effective date, for net cash proceeds of $52.0 million, before normal closing adjustments. The sale is expected to close in the third quarter of 2012. The Company has classified (i) Pioneer South Africa's assets and liabilities as discontinued operations held for sale in the Company's accompanying consolidated balance sheets as of June 30, 2012 and December 31, 2011 and (ii) Pioneer South Africa's results of operations as income from discontinued operations, net of tax in the accompanying consolidated statements of operations (representing a recasting of Pioneer South Africa results of operations for the three and six months ended June 30, 2011, which were originally classified as continuing operations).

Tunisia. In February 2011, the Company sold 100 percent of the Company's share holdings in Pioneer Natural Resources Tunisia Ltd. and Pioneer Natural Resources Anaguid Ltd. (referred to in the aggregate as "Pioneer Tunisia") to an unaffiliated third party for cash proceeds of $802.5 million, including normal closing adjustments and excluding cash and cash equivalents sold, resulting in a pretax gain of $645.2 million. Accordingly, the Company has classified the results of operations of Pioneer Tunisia, prior to its sale, as discontinued operations, net of tax in the accompanying consolidated statement of operations for the six months ended June 30, 2011.

Gulf of Mexico. During the six months ended June 30, 2011, the Bureau of Ocean Energy Management, Regulation, and Enforcement paid the Company $2.0 million of interest on excess royalty payments associated with properties that were sold by the Company during 2006. Accordingly, the interest income is classified as income from discontinued operations.

The following table represents the components of the Company's discontinued operations for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)
Revenues and other income:
Oil and gas	$	20,172		$	21,520		$	39,765		$	65,051
Interest and other	—			35			20			4,971
Gain (loss) on disposition of assets, net	—			(4,574		)	(23		)	645,298
	20,172			16,981			39,762			715,320
Costs and expenses:
Oil and gas production	1,345			714			2,135			3,937
Depletion, depreciation and amortization (a)	—			13,544			—			27,236
Exploration and abandonments	1			1,875			86			4,587
General and administrative	12			2,582			1,132			9,397
Accretion of discount on asset retirement obligations (a)	652			610			1,304			1,302
Interest	—			773			(75		)	773
Other	1,581			3,012			1,185			4,214
	3,591			23,110			5,767			51,446
Income (loss) from discontinued operations before income taxes	16,581			(6,129		)	33,995			663,874
Current tax provision	(3,334		)	(12,745		)	(8,739		)	(26,638		)
Deferred tax (provision) benefit (a)	(1,230		)	15,849			(2,544		)	(220,379		)
Income (loss) from discontinued operations	$	12,017		$	(3,025	)	$	22,712		$	416,857

 ____________________

(a) Represents the significant noncash components of discontinued operations.

Divestitures Recorded in Continuing Operations

The Company's net gain/loss on disposition of assets for the three and six months ended June 30, 2012 of $1.1 million and $44.7 million, respectively, was primarily associated with the sale of a portion of its interest in an unproved oil and gas property in the Eagle Ford Shale field during the three months ended March 31, 2012 to unaffiliated third parties for proceeds of $54.7 million, including normal closing adjustments. Associated therewith, the Company recorded a pretax gain of $42.6 million.

During the three and six months ended June 30, 2011, the Company's net loss on disposition of assets was primarily associated with the sales of excess materials and supplies inventory.

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Impairment

6 Months Ended

Jun. 30, 2012

Impairment [Abstract]

Impairment

Impairment

The Company reviews its long-lived assets for impairment, including oil and gas properties, whenever events or circumstances indicate their carrying values may not be fully recoverable. During the past year, reductions in management's outlook for commodity prices have provided indications of possible impairment of the Company's predominately dry gas properties in the Edwards Trend and Austin Chalk fields in South Texas, the Barnett Shale field in North Texas and the Raton field in Southeastern Colorado. As a result of management's assessments, during the fourth quarter of 2011 and second quarter of 2012, the Company recognized pretax noncash impairment charges of $354.4 million and $444.9 million, respectively, to reduce the carrying value of the Edwards Trend/Austin Chalk fields and the Barnett Shale field to their estimated fair values. The Company calculated the estimated fair value of the Barnett Shale field as of June 30, 2012 using a discounted cash flow model. Significant Level 3 assumptions associated with the calculation of discounted cash flows include management's outlook for (i) oil and gas prices of $87.09 per BBL for oil and $4.64 per MCF of gas, (ii) production costs, (iii) capital expenditures and (iv) production and estimated proved reserves and risk-adjusted probable reserves. Management's commodity price outlooks represent longer-term outlooks that are developed based on third-party futures price outlooks as of a measurement date. The expected future net cash flows were discounted using an annual rate of 10 percent to determine estimated fair value.

Impairment risk. The Company's estimates of undiscounted future net cash flows attributable to the Raton field's gas properties indicated on June 30, 2012 that its carrying amount was expected to be recovered. However, the carrying value of this field continues to be at risk for impairment if future estimates of undiscounted cash flows decline. As of June 30, 2012, the Company's Raton field has a carrying value of $2.3 billion.

It is reasonably possible that the estimate of undiscounted future net cash flows attributable to this or other properties may change in the future resulting in the need to impair their carrying values. The primary factors that may affect estimates of futures cash flows are (i) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, (ii) results of future drilling activities, (iii) management's commodity price outlooks and (iv) increases or decreases in production and capital costs associated with the fields.

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Commitments And Contingencies

6 Months Ended

Jun. 30, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments And Contingencies

Commitments and Contingencies

The Company is a party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

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Long-Term Debt

6 Months Ended

Jun. 30, 2012

Debt Disclosure [Abstract]

Long-Term Debt

Long-term Debt

The Company's long-term debt consists of senior notes and revolving credit facilities, including the effects of net deferred fair value hedge losses and issuance discounts. As of June 30, 2012, the Company and Pioneer Southwest were in compliance with all of their debt covenants.

Credit facility. During March 2011, the Company entered into a Second Amended and Restated 5-Year Revolving Credit Agreement (the "Credit Facility") with a syndicate of financial institutions that matures in March 2016, unless extended in accordance with the terms of the Credit Facility. As of June 30, 2012, the Company had $110.0 million of outstanding borrowings under the Credit Facility and $40.1 million of undrawn letters of credit, all of which were commitments under the Credit Facility, leaving the Company with $1.1 billion of unused borrowing capacity under the Credit Facility. During July 2012, $39.0 million of the undrawn letters of credit were canceled.

Pioneer Southwest credit facility. During March 2012, Pioneer entered into an Amended and Restated 5-Year Revolving Credit Agreement (the "Pioneer Southwest Credit Facility") with a syndicate of financial institutions that matures in March 2017, unless extended in accordance with the terms of the Pioneer Southwest Credit Facility. The Pioneer Southwest Credit Facility provides for aggregate loan commitments of $300 million. As of June 30, 2012, Pioneer Southwest had $69.0 million of outstanding borrowings and $231.0 million of unused borrowing capacity under the Pioneer Southwest Credit Facility.

The Pioneer Southwest Credit Facility is available for general partnership purposes, including working capital, capital expenditures and distributions. Borrowings under the Pioneer Southwest Credit Facility may be in the form of Eurodollar rate loans, base rate committed loans or swing line loans. The Pioneer Southwest Credit Facility contains certain financial covenants, including (i) the maintenance of a quarter end maximum leverage ratio of not more than 3.5 to 1.00 and (ii) the maintenance of a ratio of the net present value of Pioneer Southwest's projected future cash flows from its oil and gas properties to total debt of at least 1.75 to 1.0.

Senior notes. During June 2012, the Company issued $600 million of 3.95% Senior Notes due 2022 and received proceeds, net of $8.5 million of offering discounts and costs, of $591.5 million. The Company used the net proceeds to reduce outstanding borrowings under the Credit Facility.

Convertible senior notes. As of June 30, 2012 and December 31, 2011, the Company had $479.9 million of 2.875% Convertible Senior Notes outstanding. The 2.875% Convertible Senior Notes are convertible under certain circumstances, using a net share settlement process, into a combination of cash and the Company's common stock based on a formula set forth in the indenture supplement pursuant to which the 2.875% Convertible Senior Notes were issued.

The Company's stock prices during March 2012 met the average price threshold that caused the Company's 2.875% Convertible Senior Notes to become convertible at the option of the holders during the following three months ended June 30, 2012. Associated therewith, certain holders of the 2.875% Convertible Senior Notes tendered $22 thousand principal amount of the notes for conversion. The Company paid certain of the tendering holders a total of $7 thousand cash and issued to the tendering holders 50 shares of the Company's common stock in May 2012 in accordance with the terms of the 2.875% Convertible Senior Notes indenture supplement. In August 2012, the Company anticipates paying the other tendering holders $15 thousand cash for the remaining notes tendered and issuing shares to be determined based upon the conversion calculation in accordance with the terms of the 2.875% Convertible Senior Notes indenture supplement.

The Company's stock prices during March 2011 met the average price threshold that caused the Company's 2.875% Convertible Senior Notes to become convertible at the option of the holders during the following three month period. Associated therewith, certain holders of the 2.875% Convertible Senior Notes tendered $70 thousand principal amount of the notes for conversion during the three months ended June 30, 2011. During the third quarter of 2011, the Company paid the tendering holders a total of $71 thousand cash, including accrued interest, and issued to the tendering holders 340 shares of the Company's common stock in accordance with the terms of the 2.875% Convertible Senior Notes indenture supplement.

During June 2012, the Company's stock price performance did not qualify the 2.875% Convertible Senior Notes for conversion at the option of the holders for the three months ended September 30, 2012. The Company's 2.875% Convertible Senior Notes may become convertible in future quarters depending on the Company's stock price or other conditions. If the 2.875% Convertible Senior Notes had qualified for and been converted as of June 30, 2012, the note holders would have received $479.9 million of cash and approximately 1.8 million  shares of the Company's common stock, which was valued at $161.0 million at June 30, 2012.

On January 15, 2013, the 2.875% Convertible Senior Notes become redeemable at the option of the Company and on January 15, 2013, January 15, 2018, January 15, 2023, January 15, 2028 and January 15, 2033 the holders may require the Company to repurchase the notes for cash. The Company has the intent and ability to fund cash payments that may be required upon the conversion, redemption or repurchase of the 2.875% Convertible Senior Notes with borrowing capacity under the Credit Facility. Accordingly, the 2.875% Convertible Senior Notes are classified as long-term debt in the accompanying balance sheets.

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Impairment (Details) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2012 Rate	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Impairment [Abstract]
Pretax noncash impairment charges	$ 444,880,000	$ 0	$ 444,880,000	$ 0	$ 354,400,000
Management oil price outlook (BBL)	87.09
Management gas price outlook (MCF)	4.64
Discount rate used in impairment calculation	10.00%
Raton Shale Field [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Carrying value of asset group	$ 2,300,000,000		$ 2,300,000,000

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Fair Value Measurements

6 Months Ended

Jun. 30, 2012

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The three input levels of the fair value hierarchy are as follows:

• Level 1 – quoted prices for identical assets or liabilities in active markets.

• Level 2 – quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means.

• Level 3 – unobservable inputs for the asset or liability.

Assets and liabilities measured at fair value on a recurring basis. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.

The following table presents the Company's assets and liabilities that are measured at fair value as of June 30, 2012:

	Fair Value Measurement at the End of the Reporting Period Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Fair Value at June 30, 2012
	(in thousands)
Recurring fair value measurements
Assets:
Trading securities	$	251	$	168		$	—	$	419
Commodity derivatives	—		569,691			—		569,691
Deferred compensation plan assets	44,191		—			—		44,191
Total assets	$	44,442	$	569,859		$	—	$	614,301
Liabilities:
Commodity derivatives	$	—	$	(13,742	)	$	—	$	(13,742	)
Interest rate derivatives	—		(34,693		)	—		(34,693		)
Total liabilities	$	—	$	(48,435	)	$	—	$	(48,435	)
Total recurring fair value measurements	$	44,442	$	521,424		$	—	$	565,866

Trading securities and deferred compensation plan assets. The Company's trading securities are comprised of securities that are both actively traded and not actively traded on major exchanges. The Company's deferred compensation plan assets represent investments in equity and mutual fund securities that are actively traded on major exchanges. These investments are measured based on directly observable prices on major exchanges. As of June 30, 2012, all significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs. Inputs for certain trading securities that are not actively traded on major exchanges were classified as Level 2 inputs.

Interest rate derivatives. The Company's interest rate derivative liabilities as of June 30, 2012 represent interest rate swap contracts. The Company utilizes discounted cash flow models for valuing its interest rate derivatives. The net derivative values attributable to the Company's interest rate derivative contracts as of June 30, 2012 are based on (i) the contracted notional amounts, (ii) LIBOR rate yield curves provided by counterparties and corroborated with forward active market-quoted LIBOR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company's interest rate derivative liability measurements represent Level 2 inputs in the hierarchy priority.

Commodity derivatives. The Company's commodity derivatives represent oil, natural gas liquids ("NGL"), gas and diesel swap contracts, collar contracts and collar contracts with short puts (which are also known as three-way collar contracts). The Company's oil, gas, NGL and diesel swap, collar and three-way collar derivative contract asset and liability measurements represent Level 2 inputs in the hierarchy priority. The Company utilizes discounted cash flow and option-pricing models for valuing its commodity derivatives.

The asset and liability values attributable to the Company's commodity derivatives were determined based on inputs which include (i) the contracted notional volumes, (ii) independent active market price quotes, (iii) the applicable estimated credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar and three-way collar contracts, which is based on active and independent market-quoted volatility factors.

Financial instruments not carried at fair value. Carrying values and fair values of financial instruments that are not carried at fair value in the consolidated balance sheet as of June 30, 2012 and December 31, 2011 are as follows:

	June 30, 2012				December 31, 2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Long-term debt	$	3,285,497	$	3,934,014	$	2,528,905	$	3,105,585

Long term debt includes the Company's credit facility, the Pioneer Southwest credit facility and the Company's senior notes. The fair value of debt is determined utilizing inputs that are Level 2 measurements in the fair value hierarchy.

Credit facilities. The fair values of the Company's and Pioneer Southwest's credit facilities are calculated using a discounted cash flow model based on (i) forecasted contractual interest and fee payments, (ii) forward active market-quoted United States Treasury Bill rate (in the case of the Company's credit facility) or LIBOR (in the case of the Pioneer Southwest credit facility) yield curves and (iii) the applicable credit-adjustments.

Senior notes. The Company's senior notes represent debt securities that are not actively traded on major exchanges. The fair values of the Company's senior notes are based on their periodic values as quoted on the major exchanges.

The Company has other financial instruments consisting primarily of cash equivalents, short-term receivables, accounts payable trade and other liabilities that approximate fair value due to the nature of the instrument and relatively short maturities. Non-financial assets and liabilities initially measured at fair value include certain assets acquired and liabilities assumed in a business combination, goodwill and asset retirement obligations.

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Income Taxes

6 Months Ended

Jun. 30, 2012

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The Company's income tax (provisions) benefits attributable to income from continuing operations consisted of the following for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)
Current	$	(3,494	)	$	(2,540	)	$	(15,326	)	$	(4,938	)
Deferred	48,580			(137,642		)	(57,291		)	(87,337		)
Income tax benefit (provision)	$	45,086		$	(140,182	)	$	(72,617	)	$	(92,275	)
Effective tax rate (a)	35		%	36		%	37		%	34		%

 ____________________

(a) Represents the income tax benefit or provision divided by the income or loss from continuing operations before income taxes excluding the effect of net income attributable to noncontrolling interests.

The Company files income tax returns in the U.S. federal and various state and foreign jurisdictions. With few exceptions, the Company believes that it is no longer subject to examinations by tax authorities for years before 2006. As of June 30, 2012, no adjustments had been proposed in any jurisdiction that would have a significant effect on the Company's liquidity, future results of operations or financial position.

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Derivative Financial Instruments

6 Months Ended

Jun. 30, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments

Derivative Financial Instruments

The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company also, from time to time, utilizes interest rate contracts to reduce the effect of interest rate volatility on the Company's indebtedness and forward currency exchange rate agreements to reduce the effect of exchange rate volatility.

Oil production derivative activities. All material physical sales contracts governing the Company's oil production are tied directly to, or are highly correlated with, New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI") oil prices.

The following table sets forth the volumes per day in barrels ("BBLs") outstanding as of June 30, 2012 under the Company's oil derivative contracts and the weighted average oil prices per BBL for those contracts:

	Six Months Ending December 31,			Twelve Months Ending December 31,
	2012			2013		2014
Collar contracts with short puts:
Volume (BBL) (a)	51,610			67,290		40,000
Average price per BBL:
Ceiling	$	118.73		$	120.61	$	122.77
Floor	$	84.80		$	88.88	$	91.50
Short put	$	69.12		$	71.72	$	74.88
Collar contracts:
Volume (BBL)	2,000			—		—
Average price per BBL:
Ceiling	$	127.00		$	—	$	—
Floor	$	90.00		$	—	$	—
Swap contracts:
Volume (BBL) (a)	3,000			3,000		—
Average price per BBL	$	79.32		$	81.02	$	—
Rollfactor swap contracts:
Volume (BBL)	—			6,000		—
NYMEX roll price (b)	$	—		$	0.43	$	—
Basis swap contracts:
Index swap volume (BBL)	20,000			—		—
Average price per BBL (c)	$	(1.15	)	$	—	$	—

 ____________________

(a) Subsequent to June 30, 2012, the Company entered into additional NYMEX (i) swap contracts for 8,000 BBLs per day of August 2012 through December 2012 production with a price of $93.09 per BBL and (ii) collar contracts with short puts for 5,000 BBLs per day of 2014 production with a ceiling price of $102.22 per BBL, a floor price of $95.00 per BBL and a short put price of $80.00 per BBL.

(b) Represents swaps that fix the difference between (i) each day's price per BBL of 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.

(c) Basis differential price between Midland WTI and Cushing WTI.

NGL production derivative activities. All material physical sales contracts governing the Company's NGL production are tied directly or indirectly to either Mont Belvieu or Conway fractionation facilities' NGL product component prices. As of June 30, 2012, the Company had NGL swap derivatives for 750 BBLs per day of July 2012 through December 2012 NGL sales at an average price of $35.03 per BBL and NGL collar contracts with short put derivatives for 3,000 BBLs per day of July 2012 through December 2012 sales with a ceiling price of $79.99 per BBL, a floor price of $67.70 per BBL and a short put price of $55.76 per BBL. Subsequent to June 30, 2012, the Company entered into additional NGL swap contracts for 2,000 BBLs per day of August 2012 through December 2012 production priced at $80.06 per BBL.

Gas production derivative activities. All material physical sales contracts governing the Company's gas production are tied directly or indirectly to regional index prices where the gas is sold. The Company uses derivative contracts to manage gas price volatility and reduce basis risk between NYMEX Henry Hub ("HH") prices and actual index prices at which the gas is sold.

The following table sets forth the volumes per day in millions of British thermal units ("MMBTU") outstanding as of June 30, 2012 under the Company's gas derivative contracts and the weighted average gas prices per MMBTU for those contracts:

	Six Months Ending December 31,			Twelve Months Ending December 31,
	2012			2013			2014 (a)			2015 (a)
Collar contracts with short puts:
Volume (MMBTU)	—			—			30,000			135,000
Price per MMBTU:
Ceiling	$	—		$	—		$	7.66		$	5.44
Floor	$	—		$	—		$	5.67		$	4.22
Short put	$	—		$	—		$	4.33		$	3.22
Collar contracts:
Volume (MMBTU)	65,000			150,000			80,000			50,000
Price per MMBTU:
Ceiling	$	6.60		$	6.25		$	6.39		$	7.92
Floor	$	5.00		$	5.00		$	5.00		$	5.00
Swap contracts:
Volume (MMBTU)	275,000			112,500			10,000			—
Price per MMBTU	$	4.97		$	5.62		$	6.18		$	—
Basis swap contracts:
Volume (MMBTU)	136,000			142,500			140,000			—
Price per MMBTU	$	(0.34	)	$	(0.22	)	$	(0.21	)	$	—

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(a) Subsequent to June 30, 2012, the Company (i) terminated its 2014 gas derivative positions, including basis swaps, for net proceeds of $47.1 million, (ii) terminated its 2015 collar contracts for proceeds of $19.4 million and (iii) terminated 2015 collar contracts with short puts for 30,000MMBTU per day with a ceiling price of $7.11 per MMBTU, a floor price of $5.00 per MMBTU and a short put price of $4.00 per MMBTU for proceeds of $4.7 million.

Marketing and basis transfer derivative activities. Periodically, the Company enters into gas buy and sell marketing arrangements to utilize unused firm pipeline transportation commitments. Associated with these gas marketing arrangements, the Company may enter into gas index swaps to mitigate the related 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 sets forth the contract volumes outstanding as of June 30, 2012 under the Company's marketing and basis transfer derivative contracts and the weighted average gas prices per MMBTU for those contracts:

	Six Months Ending December 31,
	2012
Average Daily Gas Production Associated with Marketing Derivatives (MMBTU):
Basis swap contracts:
Index swap volume	26,739
Price differential ($/MMBTU)	$	0.25
Average Daily Gas Production Associated with Basis Transfer Derivatives (MMBTU):
Basis swap contracts:
Short index swap volume	3,343
NGI-So Cal Border Monthly price differential to NYMEX HH ($/MMBTU)	$	0.12
Long index swap volume	$	(3,343	)
IF-HSC price differential to NYMEX HH ($/MMBTU)	$	(0.05	)

Diesel derivative activities. The Company utilizes diesel derivative swap contracts to mitigate its fuel price risk associated with diesel used in Company-owned drilling rigs and fracture stimulation fleet equipment. As of June 30, 2012, the Company has diesel derivative swap contracts for 250 BBLs per day for 2013 at an average per BBL fixed price of $111.30. The diesel derivative contracts are priced at an index that is highly correlated to the prices that the Company incurs to fuel its drilling rigs and fracture stimulation fleet equipment.

Interest rates. As of June 30, 2012, the Company was a party to interest rate derivative contracts that lock in a fixed forward annual interest rate of 3.06 percent, for a 10-year period ending in August 2022, on a notional amount of $200 million. These derivative contracts mature and settle by their terms during August 2012. Subsequent to June 30, 2012, the Company terminated its 2012 interest rate swap positions at a cost of $28.4 million.

During April 2012, the Company entered into interest rate derivative contracts that lock in a fixed forward annual interest rate of 3.21 percent, 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.

Tabular disclosure of derivative financial instruments. All of the Company's derivatives are accounted for as non-hedge derivatives as of June 30, 2012 and December 31, 2011. The following tables provide disclosure of the Company's derivative instruments:

Fair Value of Derivative Instruments as of June 30, 2012
	Asset Derivatives (a)			Liability Derivatives (a)
Type	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(in thousands)			(in thousands)
Derivatives not designated as hedging instruments
Commodity price derivatives	Derivatives - current	$	318,503	Derivatives - current	$	17,108
Interest rate derivatives	Derivatives - current	—		Derivatives - current	23,283
Commodity price derivatives	Derivatives - noncurrent	270,681		Derivatives - noncurrent	16,127
Interest rate derivatives	Derivatives - noncurrent	—		Derivatives - noncurrent	11,410
		$	589,184		$	67,928

Fair Value of Derivative Instruments as of December 31, 2011
	Asset Derivatives (a)			Liability Derivatives (a)
Type	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(in thousands)			(in thousands)
Derivatives not designated as hedging instruments
Commodity price derivatives	Derivatives - current	$	248,809	Derivatives - current	$	68,735
Interest rate derivatives	Derivatives - current	—		Derivatives - current	15,654
Commodity price derivatives	Derivatives - noncurrent	257,368		Derivatives - noncurrent	47,689
		$	506,177		$	132,078

 ___________________

(a) Derivative assets and liabilities shown in the tables above are presented as gross assets and liabilities, without regard to master netting arrangements which are considered in the presentations of derivative assets and liabilities in the accompanying consolidated balance sheets.

Derivatives in Cash Flow Hedging	Location of Gain/(Loss) Reclassified from	Amount of Gain/(Loss) Reclassified from AOCI into Earnings
		Three Months Ended June 30,						Six Months Ended June 30,
Relationships	AOCI into Earnings	2012			2011			2012			2011
		(in thousands)
Commodity price derivatives	Oil and gas revenue	$	(2,347	)	$	8,208		$	(3,156	)	$	16,332
Interest rate derivatives	Interest expense	—			(69		)	(1,699		)	(137		)
Total		$	(2,347	)	$	8,139		$	(4,855	)	$	16,195

		Amount of Gain (Loss) Recognized in Earnings on Derivatives
Derivatives Not Designated as Hedging	Location of Gain (Loss) Recognized in	Three Months Ended June 30,					Six Months Ended June 30,
Instruments	Earnings on Derivatives	2012			2011		2012			2011
		(in thousands)
Commodity price derivatives	Derivative gains (losses), net	$	298,471		$	214,903	$	386,601		$	(27,377	)
Interest rate derivatives	Derivative gains (losses), net	(22,659		)	14,575		(19,039		)	12,423
Total		$	275,812		$	229,478	$	367,562		$	(14,954	)

AOCI - Hedging. As of December 31, 2011, the Company had $3.2 million and $1.7 million of net deferred losses on the effective portions of discontinued oil and interest rate hedges, respectively, and $1.8 million of associated net deferred tax benefits classified in AOCI—Hedging in the accompanying consolidated balance sheet. During the six months ended June 30, 2012, the Company transferred the respective AOCI - Hedging balances to oil revenue, interest expense and income tax provisions.

Derivative counterparties. The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company's credit risk policies and procedures.

The following table provides the Company's derivative assets and liabilities by counterparty as of June 30, 2012:

	Assets		Liabilities
	(in thousands)
JP Morgan Chase	$	119,358	$	15,217
Citibank, N.A.	87,788		438
Barclays Capital	53,131		—
BMO Financial Group	42,192		—
BNP Paribas	40,677		—
J. Aron & Company	33,071		—
Wells Fargo Bank, N.A.	31,419		20,981
Credit Suisse	29,795		—
Toronto Dominion	29,206		—
Credit Agricole	28,179		2,177
Societe Generale	24,356		—
Merrill Lynch	16,880		2,775
Morgan Stanley	16,184		885
Den Norske Bank	9,790		—
BP Corporation North America	4,040		—
Deutsche Bank	2,194		2,363
Vitol	1,345		—
Macquarie Bank	86		—
Royal Bank of Canada	—		262
UBS	—		3,337
Total	$	569,691	$	48,435

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Interest And Other Income (Tables)

6 Months Ended

Jun. 30, 2012

Interest and Other Income [Abstract]

Components of interest and other income

The following table provides the components of the Company's interest and other income:

	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012		2011
	(in thousands)
Equity in income of unconsolidated affiliate (a)	$	7,861		$	502	$	14,842	$	801
Alaskan Petroleum Production Tax credits and refunds (b)	—			—		11,846		27,452
Third-party income (loss) from vertical integration services (c)	(3,820		)	8,881		2,729		7,913
Other income	592			3,698		2,234		4,334
Deferred compensation plan income	150			299		1,523		1,166
Interest income	1,260			214		1,317		401
Total interest and other income	$	6,043		$	13,594	$	34,491	$	42,067

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Derivative Financial Instruments (Schedule Of Derivative Instruments) (Details) (Not Designated As Hedging Instruments [Member], USD $) In Thousands, unless otherwise specified	Jun. 30, 2012		Dec. 31, 2011
Derivative [Line Items]
Total derivatives, Asset	$ 589,184	[1]	$ 506,177	[1]
Total derivatives, Liability	67,928	[1]	132,078	[1]
Commodity Price Derivatives [Member] | Derivatives - Current [Member]
Derivative [Line Items]
Total derivatives, Asset	318,503	[1]	248,809	[1]
Total derivatives, Liability	17,108	[1]	68,735	[1]
Commodity Price Derivatives [Member] | Derivatives - Noncurrent [Member]
Derivative [Line Items]
Total derivatives, Asset	270,681	[1]	257,368	[1]
Total derivatives, Liability	16,127	[1]	47,689	[1]
Interest Rate Derivatives [Member] | Derivatives - Current [Member]
Derivative [Line Items]
Total derivatives, Liability	$ 23,283	[1]	$ 15,654	[1]

[1] Derivative assets and liabilities shown in the tables above are presented as gross assets and liabilities, without regard to master netting arrangements which are considered in the presentations of derivative assets and liabilities in the accompanying consolidated balance sheets.

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Interest And Other Income

6 Months Ended

Jun. 30, 2012

Interest and Other Income [Abstract]

Interest And Other Income

Interest and Other Income

The following table provides the components of the Company's interest and other income:

	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012		2011
	(in thousands)
Equity in income of unconsolidated affiliate (a)	$	7,861		$	502	$	14,842	$	801
Alaskan Petroleum Production Tax credits and refunds (b)	—			—		11,846		27,452
Third-party income (loss) from vertical integration services (c)	(3,820		)	8,881		2,729		7,913
Other income	592			3,698		2,234		4,334
Deferred compensation plan income	150			299		1,523		1,166
Interest income	1,260			214		1,317		401
Total interest and other income	$	6,043		$	13,594	$	34,491	$	42,067

 ____________________

(a) Represents the Company's equity in the earnings of EFS Midstream LLC ("EFS Midstream"), which owns and operates gas and liquids gathering, treating and transportation assets in the Eagle Ford Shale area of South Texas.

(b) The Company earns Alaskan Petroleum Production Tax ("PPT") credits on qualifying capital expenditures. The Company recognizes income from PPT credits when they are realized through cash refunds or as reductions in production and ad valorem taxes if realizable as offsets to PPT expense.

(c) Third-party income (loss) from vertical integration services represents third-party working interests' share of earnings associated with Company-provided fracture stimulation, drilling and related services.

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Acquisitions and Divestitures (Tables)

6 Months Ended

Jun. 30, 2012

Acquisitions and Divestitures [Abstract]

Components of discontinued operations

The following table represents the components of the Company's discontinued operations for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in thousands)
Revenues and other income:
Oil and gas	$	20,172		$	21,520		$	39,765		$	65,051
Interest and other	—			35			20			4,971
Gain (loss) on disposition of assets, net	—			(4,574		)	(23		)	645,298
	20,172			16,981			39,762			715,320
Costs and expenses:
Oil and gas production	1,345			714			2,135			3,937
Depletion, depreciation and amortization (a)	—			13,544			—			27,236
Exploration and abandonments	1			1,875			86			4,587
General and administrative	12			2,582			1,132			9,397
Accretion of discount on asset retirement obligations (a)	652			610			1,304			1,302
Interest	—			773			(75		)	773
Other	1,581			3,012			1,185			4,214
	3,591			23,110			5,767			51,446
Income (loss) from discontinued operations before income taxes	16,581			(6,129		)	33,995			663,874
Current tax provision	(3,334		)	(12,745		)	(8,739		)	(26,638		)
Deferred tax (provision) benefit (a)	(1,230		)	15,849			(2,544		)	(220,379		)
Income (loss) from discontinued operations	$	12,017		$	(3,025	)	$	22,712		$	416,857

 ____________________

(a) Represents the significant noncash components of discontinued operations.

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Derivative Financial Instruments (Schedule Of Oil Derivative Contracts Volume And Weighted Average Prices) (Details)	1 Months Ended	3 Months Ended
	Aug. 03, 2012 bbl	Jun. 30, 2012 MMBTU bbl
2012 - Collar Contracts With Short Puts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Volume (Bbl)		51,610
Average Daily Gas Production Derivatives Volume (MMBTU)		0
2012 - Collar Contracts With Short Puts [Member] | Ceiling [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Price per Bbl		118.73
Average Daily Gas Production Derivatives Price Per MMBtu		0.00
2012 - Collar Contracts With Short Puts [Member] | Floor [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Price per Bbl		84.80
Average Daily Gas Production Derivatives Price Per MMBtu		0.00
2012 - Collar Contracts With Short Puts [Member] | Short Put [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Price per Bbl		69.12
Average Daily Gas Production Derivatives Price Per MMBtu		0.00
2013 - Collar Contracts With Short Puts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Volume (Bbl)		67,290
Average Daily Gas Production Derivatives Volume (MMBTU)		0
2013 - Collar Contracts With Short Puts [Member] | Ceiling [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Price per Bbl		120.61
Average Daily Gas Production Derivatives Price Per MMBtu		0.00
2013 - Collar Contracts With Short Puts [Member] | Floor [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Price per Bbl		88.88
Average Daily Gas Production Derivatives Price Per MMBtu		0.00
2013 - Collar Contracts With Short Puts [Member] | Short Put [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Price per Bbl		71.72
Average Daily Gas Production Derivatives Price Per MMBtu		0.00
2014 - Collar Contracts With Short Puts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Volume (Bbl)	5,000	40,000
Average Daily Gas Production Derivatives Volume (MMBTU)		30,000	[1]
2014 - Collar Contracts With Short Puts [Member] | Ceiling [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Price per Bbl	102.22	122.77
Average Daily Gas Production Derivatives Price Per MMBtu		7.66	[1]
2014 - Collar Contracts With Short Puts [Member] | Floor [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Price per Bbl	95.00	91.50
Average Daily Gas Production Derivatives Price Per MMBtu		5.67	[1]
2014 - Collar Contracts With Short Puts [Member] | Short Put [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Price per Bbl	80.00	74.88
Average Daily Gas Production Derivatives Price Per MMBtu		4.33	[1]
2015 Collar Contracts With Short Puts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Daily Gas Production Derivatives Volume (MMBTU)		135,000	[1]
2015 Collar Contracts With Short Puts [Member] | Ceiling [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Daily Gas Production Derivatives Price Per MMBtu		5.44	[1]
2015 Collar Contracts With Short Puts [Member] | Floor [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Daily Gas Production Derivatives Price Per MMBtu		4.22	[1]
2015 Collar Contracts With Short Puts [Member] | Short Put [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Daily Gas Production Derivatives Price Per MMBtu		3.22	[1]
2012 - Collar Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Volume (Bbl)		2,000
Average Daily Gas Production Derivatives Volume (MMBTU)		65,000
2012 - Collar Contracts [Member] | Ceiling [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Price per Bbl		127.00
Average Daily Gas Production Derivatives Price Per MMBtu		6.60
2012 - Collar Contracts [Member] | Floor [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Price per Bbl		90.00
Average Daily Gas Production Derivatives Price Per MMBtu		5.00
2013 Collar Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Volume (Bbl)		0
Average Daily Gas Production Derivatives Volume (MMBTU)		150,000
2013 Collar Contracts [Member] | Ceiling [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Price per Bbl		0.00
Average Daily Gas Production Derivatives Price Per MMBtu		6.25
2013 Collar Contracts [Member] | Floor [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Price per Bbl		0.00
Average Daily Gas Production Derivatives Price Per MMBtu		5.00
2014 Collar Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Volume (Bbl)		0
Average Daily Gas Production Derivatives Volume (MMBTU)		80,000	[1]
2014 Collar Contracts [Member] | Ceiling [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Price per Bbl		0.00
Average Daily Gas Production Derivatives Price Per MMBtu		6.39	[1]
2014 Collar Contracts [Member] | Floor [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Price per Bbl		0.00
Average Daily Gas Production Derivatives Price Per MMBtu		5.00	[1]
2015 Collar Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Daily Gas Production Derivatives Volume (MMBTU)		50,000	[1]
2015 Collar Contracts [Member] | Ceiling [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Daily Gas Production Derivatives Price Per MMBtu		7.92	[1]
2015 Collar Contracts [Member] | Floor [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Daily Gas Production Derivatives Price Per MMBtu		5.00	[1]
2012 Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Volume (Bbl)	8,000	3,000	[2]
Average Daily Gas Production Derivatives Volume (MMBTU)		275,000
Average Price per Bbl	93.09	79.32
Average Daily Gas Production Derivatives Price Per MMBtu		4.97
2013 Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Volume (Bbl)		3,000	[2]
Average Daily Gas Production Derivatives Volume (MMBTU)		112,500
Average Price per Bbl		81.02
Average Daily Gas Production Derivatives Price Per MMBtu		5.62
2014 Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Volume (Bbl)		0	[2]
Average Daily Gas Production Derivatives Volume (MMBTU)		10,000	[1]
Average Price per Bbl		0.00
Average Daily Gas Production Derivatives Price Per MMBtu		6.18	[1]
2015 Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Daily Gas Production Derivatives Volume (MMBTU)		0	[1]
Average Daily Gas Production Derivatives Price Per MMBtu		0.00	[1]
2012 - Rollfactor Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Volume (Bbl)		0
Average Price per Bbl		0.00	[3]
2013 Rollfactor Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Volume (Bbl)		6,000
Average Price per Bbl		0.43	[3]
2014 Rollfactor Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Volume (Bbl)		0
Average Price per Bbl		0.00	[3]
2012 Basis Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Volume (Bbl)		20,000
Average Daily Gas Production Derivatives Volume (MMBTU)		136,000
Average Price per Bbl		(1.15)	[4]
Average Daily Gas Production Derivatives Price Per MMBtu		(0.34)
2013 Basis Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Volume (Bbl)		0
Average Daily Gas Production Derivatives Volume (MMBTU)		142,500
Average Price per Bbl		0.00	[4]
Average Daily Gas Production Derivatives Price Per MMBtu		(0.22)
2014 Basis Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Volume (Bbl)		0
Average Daily Gas Production Derivatives Volume (MMBTU)		140,000	[1]
Average Price per Bbl		0.00	[4]
Average Daily Gas Production Derivatives Price Per MMBtu		(0.21)	[1]
2015 Basis Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Average Daily Gas Production Derivatives Volume (MMBTU)		0	[1]
Average Daily Gas Production Derivatives Price Per MMBtu		0.00	[1]

[1] Subsequent to June 30, 2012, the Company (i) terminated its 2014 gas derivative positions, including basis swaps, for net proceeds of $47.1 million, (ii) terminated its 2015 collar contracts for proceeds of $19.4 million and (iii) terminated 2015 collar contracts with short puts for 30,000 MMBTU per day with a ceiling price of $7.11 per MMBTU, a floor price of $5.00 per MMBTU and a short put price of $4.00 per MMBTU for proceeds of $4.7 million.

[2] Subsequent to June 30, 2012, the Company entered into additional NYMEX (i) swap contracts for 8,000 BBLs per day of August 2012 through December 2012 production with a price of $93.09 per BBL and (ii) collar contracts with short puts for 5,000 BBLs per day of 2014 production with a ceiling price of $102.22 per BBL, a floor price of $95.00 per BBL and a short put price of $80.00 per BBL.

[3] Represents swaps that fix the difference between (i) each day's price per BBL of 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.

[4] Basis differential price between Midland WTI and Cushing WTI.

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Acquisitions and Divestitures Acquisitions and Divestitures (Components Of Discontinued Operations) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2012		Jun. 30, 2011		Jun. 30, 2012		Jun. 30, 2011
Acquisitions and Divestitures [Abstract]
Oil and gas	$ 20,172		$ 21,520		$ 39,765		$ 65,051
Interest and other	0		35		20		4,971
Gain (loss) on disposition of assets, net	0	[1]	(4,574)	[1]	(23)	[1]	645,298	[1]
Total revenues and other income from discontinued operations	20,172		16,981		39,762		715,320
Oil and gas production	1,345		714		2,135		3,937
Depletion, depreciation and amortization	0	[1]	13,544	[1]	0	[1]	27,236	[1]
Exploration and abandonments	1		1,875		86		4,587
General and administrative	12		2,582		1,132		9,397
Accretion of discount on asset retirement obligations	652	[1]	610	[1]	1,304	[1]	1,302	[1]
Interest	0		773		(75)		773
Other	1,581		3,012		1,185		4,214
Total costs and expenses from discontinued operations	3,591		23,110		5,767		51,446
Income from discontinued operations before income taxes	16,581		(6,129)		33,995		663,874
Current tax provision	(3,334)		(12,745)		(8,739)		(26,638)
Deferred tax provision	(1,230)	[1]	15,849	[1]	(2,544)	[1]	(220,379)	[1]
Income from discontinued operations	$ 12,017		$ (3,025)		$ 22,712		$ 416,857

[1] Represents the significant noncash components of discontinued operations.

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Consolidated Statements Of Comprehensive Income (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Statement of Other Comprehensive Income [Abstract]
Net income (loss)	$ (39,537)	$ 265,700	$ 181,421	$ 609,504
Other comprehensive activity:
Net hedge (gains) losses included in continuing operations	2,347	(8,139)	4,855	(16,195)
Income tax (benefit) provision	(797)	4,138	(1,725)	4,886
Other comprehensive activity	1,550	(4,001)	3,130	(11,309)
Comprehensive income (loss)	(37,987)	261,699	184,551	598,195
Comprehensive (income) loss attributable to the noncontrolling interests	(30,855)	(16,698)	(37,194)	(8,522)
Comprehensive income (loss) attributable to common stockholders	$ (68,842)	$ 245,001	$ 147,357	$ 589,673

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Basis Of Presentation

6 Months Ended

Jun. 30, 2012

Basis Of Presentation [Abstract]

Basis Of Presentation

Basis of Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of June 30, 2012 and for the three and six months ended June 30, 2012 and 2011 include all adjustments and accruals, consisting only of normal recurring accrual adjustments, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year.

Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States ("GAAP") have been condensed or omitted in this Report pursuant to the rules and regulations of the United States Securities and Exchange Commission (the "SEC"). These consolidated financial statements should be read together with the consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2011.

Certain reclassifications have been made to the 2011 financial statement and footnote amounts in order to conform to the 2012 presentation.

On May 6, 2008, the Company recognized a noncash gain on the sale of Pioneer Southwest Energy Partners L.P.'s ("Pioneer Southwest," a majority-owned and consolidated subsidiary) common units as a component of additional paid-in capital in stockholders' equity. In accordance with the Financial Accounting Standards Board ("FASB") Accounting Standards Codification (“ASC”) Topic 740 Income Taxes, deferred income taxes of $49.1 million should be recognized for the future tax effects arising from the noncash gain on the sale of the Pioneer Southwest common units, with a corresponding decrease to additional paid-in capital. The Company recorded the deferred income taxes associated with this transaction in June 2012. The effect of this adjustment is immaterial to the accompanying financial statements.

Revision for deferred income taxes. The accompanying consolidated balance sheet as of December 31, 2011 has been revised for a change in the classification of deferred income taxes associated with the Company's unrealized current derivative net gains as of December 31, 2011. The noncash revisions resulted in a $77.0 million decrease in current deferred tax assets, a $57.7 million increase in current deferred tax liabilities and a $134.7 million decrease in noncurrent deferred tax liabilities from the amounts previously reported at December 31, 2011. Such revisions were made to appropriately reflect the impact on deferred income taxes based on the expected settlement periods related to derivatives, which remained subject to market risk as of December 31, 2011. See "- Derivatives and hedging," below and Notes F and H for more information about derivative fair values and market risk.

Derivatives and hedging. All derivatives are recorded in the accompanying consolidated balance sheets at their estimated fair values. See Note E for further information regarding the fair value of the Company's derivatives. Effective February 1, 2009, the Company discontinued hedge accounting on all of its then-existing derivative hedge contracts. Changes in the fair value of effective cash flow hedges prior to the Company's discontinuance of hedge accounting were recorded as a component of accumulated other comprehensive income or loss ("AOCI - Hedging"), in the equity section of the Company's consolidated balance sheets, and were transferred to earnings during the same periods in which the hedged transactions were recognized in the Company's earnings. As of June 30, 2012, all of the hedge gains or losses that were previously deferred in AOCI - Hedging have been transferred to earnings. The Company now recognizes all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they occur.

The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company's and Pioneer Southwest's credit-adjusted risk-free rate curves. The credit-adjusted risk-free rate curves for the Company and its counterparties are generally based on their independent market-quoted credit default swap rate curves plus the United States Treasury Bill yield curve as of the valuation date. Pioneer Southwest's credit-adjusted risk-free rate curve is based on independent market-quoted forward London Interbank Offered Rate ("LIBOR") curves plus 162.5 basis points, representing Pioneer Southwest's borrowing rate.

Impairment of assets. The Company reviews its long-lived assets for impairment, including oil and gas properties, whenever events or circumstances indicate that their carrying values may not be fully recoverable. If the carrying value of long-lived assets is determined to be impaired, it is reduced to its estimated fair value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. See Note O for additional information about the Company's impairment charge for the three and six months ended June 30, 2012, and future impairment risk.

Goodwill is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired, it is reduced for the impaired value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. During the third quarter of 2011, the Company performed its annual assessment of goodwill impairment and determined that there was no impairment.

New accounting pronouncement. In September 2011, the FASB issued Accounting Standards Update ("ASU") No. 2011-08 Intangibles - Goodwill and Other (Topic 350) ("ASU 2011-08"). ASU 2011-08 amended FASB ASC Topic 350 to permit an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. ASU 2011-08 became effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The adoption of ASU 2011-08 did not impact the carrying value of the Company's goodwill. See Note O for information regarding the Company's impairment assessments.

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Interest And Other Income (Components Of Interest And Other Income) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2012		Jun. 30, 2011		Jun. 30, 2012		Jun. 30, 2011
Interest and Other Income [Abstract]
Equity interest in income of unconsolidated affiliate	$ 7,861	[1]	$ 502	[1]	$ 14,842	[1]	$ 801	[1]
Alaskan Petroleum Production Tax credits and refunds	0	[2]	0	[2]	11,846	[2]	27,452	[2]
Third-party income from vertical integration services	(3,820)	[3]	8,881	[3]	2,729	[3]	7,913	[3]
Other income	592		3,698		2,234		4,334
Deferred compensation plan income	150		299		1,523		1,166
Interest income	1,260		214		1,317		401
Total interest and other income	$ 6,043		$ 13,594		$ 34,491		$ 42,067

[1] Represents the Company's equity in the earnings of EFS Midstream LLC ("EFS Midstream"), which owns and operates gas and liquids gathering, treating and transportation assets in the Eagle Ford Shale area of South Texas.

[2] The Company earns Alaskan Petroleum Production Tax ("PPT") credits on qualifying capital expenditures. The Company recognizes income from PPT credits when they are realized through cash refunds or as reductions in production and ad valorem taxes if realizable as offsets to PPT expense.

[3] Third-party income (loss) from vertical integration services represents third-party working interests' share of earnings associated with Company-provided fracture stimulation, drilling and related services.

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Exploratory Costs (Tables)

6 Months Ended

Jun. 30, 2012

Exploratory Costs [Abstract]

Capitalized exploratory well and project activity

The following table reflects the Company's capitalized exploratory well and project activity during the three and six months ended June 30, 2012:

	Three Months Ended June 30, 2012			Six Months Ended June 30, 2012
	(in thousands)
Beginning capitalized exploratory costs	$	138,002		$	107,596
Additions to exploratory costs pending the determination of proved reserves	205,938			380,832
Reclassification due to determination of proved reserves	(148,805		)	(266,415		)
Exploratory well costs charged to exploration expense	(1,408		)	(28,286		)
Ending capitalized exploratory costs	$	193,727		$	193,727

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Basis Of Presentation (Derivatives and Hedging) (Details) (Pioneer Southwest Ltip [Member])	6 Months Ended
	Jun. 30, 2012
Pioneer Southwest Ltip [Member]
Derivative [Line Items]
Pioneer Southwest's credit-adjusted risk-free rate curve basis	LIBOR
Pioneer Southwest's credit-adjusted risk-free rate curve, spread on variable rate	1.625%

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Net Income (Loss) Per Share

6 Months Ended

Jun. 30, 2012

Earnings Per Share [Abstract]

Net Income (Loss) Per Share

Net Income (Loss) Per Share

The Company uses the two-class method of calculating net income (loss) per share because certain of the Company's and its consolidated subsidiaries' unvested share-based awards qualify as participating securities. Participating securities participate in the Company's dividend distributions and are assumed to participate in the Company's undistributed income proportionate to weighted average outstanding common shares, but are not assumed to participate in the Company's net losses because they are not contractually obligated to do so. Accordingly, allocations of earnings to participating securities are included in the Company's calculations of basic and diluted earnings per share from continuing operations, discontinued operations and net income attributable to common stockholders.

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 from continuing operations; therefore, conversion into common stock is assumed not to occur.

The following tables reconcile the Company's net income (loss) attributable to common stockholders to basic net income (loss) attributable to common stockholders and diluted net income (loss) attributable to common stockholders for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30, 2012								Six Months Ended June 30, 2012
	Continuing Operations			Discontinued Operations		Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income (loss) attributable to common stockholders	$	(82,409	)	$	12,017	$	(70,392	)	$	121,515		$	22,712		$	144,227
Participating basic earnings	(265		)	—		(265		)	(1,833		)	(343		)	(2,176		)
Basic net income (loss) attributable to common stockholders	(82,674		)	12,017		(70,657		)	119,682			22,369			142,051
Reallocation of participating earnings	—			—		—			130			24			154
Diluted income (loss) attributable to common stockholders	$	(82,674	)	$	12,017	$	(70,657	)	$	119,812		$	22,393		$	142,205

	Three Months Ended June 30, 2011									Six Months Ended June 30, 2011
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Net income (loss) attributable to common stockholders	$	248,602		$	(3,025	)	$	245,577		$	177,314		$	416,857		$	594,171
Participating basic earnings	(4,847		)	—			(4,847		)	(3,238		)	(7,611		)	(10,849		)
Basic net income (loss) attributable to common stockholders	243,755			(3,025		)	240,730			174,076			409,246			583,322
Reallocation of participating earnings	164			—			164			81			190			271
Diluted income (loss) attributable to common stockholders	$	243,919		$	(3,025	)	$	240,894		$	174,157		$	409,436		$	583,593

The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,		Six Months Ended June 30,
	2012	2011	2012	2011
	(in thousands)
Weighted average common shares outstanding:
Basic	123,028	116,213	122,754	116,042
Dilutive common stock options (a)	—	178	205	188
Convertible senior notes dilution (a)	—	1,772	2,642	2,333
Contingently issuable performance unit shares (a)	—	429	171	423
Diluted	123,028	118,592	125,772	118,986

 ____________________

(a) The following common share equivalents were excluded from the weighted average diluted shares for the three months ended June 30, 2012 because they would have been anti-dilutive to the loss recorded for the period: 206,495 outstanding options to purchase the Company's common stock, 184,236 common shares attributable to unvested performance units and 1,825,147 common shares issuable if holders of the Company's 2.875% Convertible Senior Notes had exercised their conversion rights (see Note G). Options to purchase 185,772 shares of the Company's common stock were excluded from the diluted income per share calculations for the six months ended June 30, 2012 because they would have been anti-dilutive to the calculation.