10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2011

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  x    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  x    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	x	Accelerated filer	¨
Non-accelerated filer	¨  (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  x

Number of shares of Common Stock outstanding as of August 1, 2011 116,782,548

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, 2011 and December 31, 2010		5
	Consolidated Statements of Operations for the three and six months ended June 30, 2011 and 2010		7
	Consolidated Statement of Stockholders’ Equity for the six months ended June 30, 2011		8
	Consolidated Statements of Cash Flows for the six months ended June 30, 2011 and 2010		9
	Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2011 and 2010		10
	Notes to Consolidated Financial Statements		11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		48
Item 4.	Controls and Procedures		51
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings		52
Item 1A.	Risk Factors		52
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		53
Item 6.	Exhibits		54
Signatures			55
Exhibit Index			56

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 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, 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, 2010 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:

• “AOCI - Hedging” means accumulated other comprehensive income – net deferred hedge gains, net of tax, a component of the Company’s consolidated stockholders’ equity in the accompanying consolidated balance sheets.

• “Bbl” means a standard barrel containing 42 United States gallons.

• “Bcf” means one billion cubic feet.

• “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.

• “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.

• “MBbl” means one thousand Bbls.

• “MBOE” means one thousand BOEs.

• “Mcf” means one thousand cubic feet and is a measure of gas volume.

• “MMBbl” means one million Bbls.

• “MMBOE” means one million BOEs.

• “MMBtu” means one million Btus.

• “MMcf” means one million cubic feet.

• “MMcfpd” means one million cubic feet per day.

• “Mont Belvieu–posted-price” 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 Mont Belvieu, Texas.

• “NGL” means natural gas liquid.

• “NYMEX” means the New York Mercantile Exchange.

• “NYSE” means the New York Stock 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.

• “Standardized Measure” means the after-tax present value of estimated future net cash flows of proved reserves, determined in accordance with the rules and regulations of the SEC, using prices and costs employed in the determination of proved reserves and a ten percent discount rate.

• “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, 2011			December 31, 2010
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	352,421		$	111,160
Accounts receivable:
Trade, net of allowance for doubtful accounts of $1,056 and $1,155 as of June 30, 2011 and December 31, 2010, respectively		266,476			237,511
Due from affiliates		2,702			7,792
Income taxes receivable		3,674			30,901
Inventories		234,108			173,615
Prepaid expenses		21,342			11,441
Deferred income taxes		163			156,650
Discontinued operations held for sale		—			281,741
Other current assets:
Derivatives		154,129			171,679
Other		36,092			14,693
Total current assets		1,071,107			1,197,183
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties		11,541,101			10,739,114
Unproved properties		213,230			191,112
Accumulated depletion, depreciation and amortization		(3,637,605	)		(3,366,440	)
Total property, plant and equipment		8,116,726			7,563,786
Deferred income taxes		1,878			—
Goodwill		298,177			298,182
Other property and equipment, net		431,214			283,542
Other assets:
Investment in unconsolidated affiliate		155,701			72,045
Derivatives		142,361			151,011
Other, net of allowance for doubtful accounts of $358 and $2,519 as of June 30, 2011 and December 31, 2010, respectively		135,924			113,353
	$	10,353,088		$	9,679,102

The financial information included as of June 30, 2011 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, 2011			December 31, 2010
	(Unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	490,434		$	354,890
Due to affiliates		26,962			64,260
Interest payable		57,366			59,008
Income taxes payable		5,927			19,168
Deferred income taxes		19,588			1,144
Discontinued operations held for sale		—			108,592
Other current liabilities:
Derivatives		76,008			80,997
Deferred revenue		43,580			44,951
Other		35,776			36,210
Total current liabilities		755,641			769,220
Long-term debt		2,570,978			2,601,670
Derivatives		108,075			56,574
Deferred income taxes		1,844,503			1,751,310
Deferred revenue		21,150			42,069
Other liabilities		236,777			232,234
Stockholders’ equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 127,554,683 and 126,212,256 shares issued at June 30, 2011 and December 31, 2010, respectively		1,276			1,262
Additional paid-in capital		3,070,827			3,022,768
Treasury stock, at cost: 11,311,097 and 10,903,743 at June 30, 2011 and December 31, 2010, respectively		(459,657	)		(421,235	)
Retained earnings		2,099,623			1,510,427
Accumulated other comprehensive income - net deferred hedge gains, net of tax		2,863			7,361
Total stockholders’ equity attributable to common stockholders		4,714,932			4,120,583
Noncontrolling interests in consolidating subsidiaries		101,032			105,442
Total stockholders’ equity		4,815,964			4,226,025
Commitments and contingencies
	$	10,353,088		$	9,679,102

The financial information included as of June 30, 2011 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,
	2011			2010			2011			2010
Revenues and other income:
Oil and gas	$	583,931		$	422,042		$	1,081,061		$	894,087
Interest and other		18,454			16,952			51,141			34,960
Gain (loss) on disposition of assets, net		(296	)		7,645			(2,487	)		24,588
		602,089			446,639			1,129,715			953,635
Costs and expenses:
Oil and gas production		102,455			94,012			202,386			180,112
Production and ad valorem taxes		35,864			25,338			69,160			52,399
Depletion, depreciation and amortization		153,898			144,309			294,271			288,737
Exploration and abandonments		19,914			22,743			37,557			39,591
General and administrative		44,644			40,433			88,750			78,748
Accretion of discount on asset retirement obligations		2,658			2,529			5,313			5,388
Interest		45,768			45,368			90,995			92,891
Hurricane activity, net		(2	)		5,184			69			(2,226	)
Derivative (gains) losses, net		(229,478	)		(177,528	)		14,954			(443,004	)
Other		14,388			14,193			32,269			30,139
		190,109			216,581			835,724			322,775
Income from continuing operations before income taxes		411,980			230,058			293,991			630,860
Income tax provision		(144,696	)		(83,220	)		(97,545	)		(227,227	)
Income from continuing operations		267,284			146,838			196,446			403,633
Income (loss) from discontinued operations, net of tax		(1,584	)		41,851			413,058			45,662
Net income		265,700			188,689			609,504			449,295
Net income attributable to the noncontrolling interests		(20,123	)		(21,113	)		(15,333	)		(36,465	)
Net income attributable to common stockholders	$	245,577		$	167,576		$	594,171		$	412,830
Basic earnings per share:
Income from continuing operations attributable to common stockholders	$	2.08		$	1.07		$	1.53		$	3.12
Income (loss) from discontinued operations attributable to common stockholders		(0.01	)		0.35			3.50			0.39
Net income attributable to common stockholders	$	2.07		$	1.42		$	5.03		$	3.51
Diluted earnings per share:
Income from continuing operations attributable to common stockholders	$	2.04		$	1.06		$	1.50		$	3.10
Income (loss) from discontinued operations attributable to common stockholders		(0.01	)		0.35			3.40			0.39
Net income attributable to common stockholders	$	2.03		$	1.41		$	4.90		$	3.49
Weighted average shares outstanding:
Basic		116,213			115,104			116,042			114,880
Diluted		118,592			116,006			118,986			115,735
Dividends declared per share	$	—		$	—		$	0.04		$	0.04
Amounts attributable to common stockholders:
Income from continuing operations	$	247,161		$	125,725		$	181,113		$	367,168
Income (loss) from discontinued operations, net of tax		(1,584	)		41,851			413,058			45,662
Net income	$	245,577		$	167,576		$	594,171		$	412,830

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 STATEMENT OF STOCKHOLDERS’ EQUITY

(in thousands, except dividends per share)

(Unaudited)

				Stockholders’ Equity Attributable To Common Stockholders
	Shares Outstanding			Common Stock		Additional Paid-in Capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income			Noncontrolling Interests			Total Stockholders’ Equity
Balance as of December 31, 2010		115,309		$	1,262	$	3,022,768		$	(421,235	)	$	1,510,427		$	7,361		$	105,442		$	4,226,025
Dividends declared ($0.04 per share)		—			—		—			—			(4,739	)		—			—			(4,739	)
Exercise of long-term incentive plan stock options		16			—		—			598			(236	)		—			—			362
Treasury stock purchases		(424	)		—		—			(39,020	)		—			—			(198	)		(39,218	)
Tax benefit related to stock-based compensation		—			—		27,937			—			—			—			—			27,937
Disposition of subsidiary		—			—		(508	)		—			—			—			—			(508	)
Compensation costs:
Vested compensation awards, net		1,343			14		(14	)		—			—			—			—			—
Compensation costs included in net income		—			—		20,644			—			—			—			632			21,276
Cash distributions to noncontrolling interests		—			—		—			—			—			—			(13,366	)		(13,366	)
Net income		—			—		—			—			594,171			—			15,333			609,504
Other comprehensive activity:
Deferred hedging activity, net of tax:
Net hedge gains included in continuing operations		—			—		—			—			—			(4,498	)		(6,811	)		(11,309	)
Balance as of June 30, 2011		116,244		$	1,276	$	3,070,827		$	(459,657	)	$	2,099,623		$	2,863		$	101,032		$	4,815,964

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 STATEMENTS OF CASH FLOWS

(in thousands)

(Unaudited)

	Six Months Ended June 30,
	2011			2010
Cash flows from operating activities:
Net income	$	609,504		$	449,295
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization		294,271			288,737
Exploration expenses, including dry holes		4,275			7,973
Hurricane activity, net		—			3,500
Deferred income taxes		75,507			220,352
(Gain) loss on disposition of assets, net		2,487			(24,588	)
Accretion of discount on asset retirement obligations		5,313			5,388
Discontinued operations		(407,115	)		41,463
Interest expense		15,432			14,920
Derivative related activity		56,380			(442,087	)
Amortization of stock-based compensation		21,155			19,049
Amortization of deferred revenue		(22,290	)		(45,070	)
Other noncash items		(18,277	)		1,324
Change in operating assets and liabilities
Accounts receivable, net		(23,605	)		96,376
Income taxes receivable		27,226			23,440
Inventories		(74,136	)		12,479
Prepaid expenses		(9,990	)		(10,204	)
Other current assets		8,772			(7,192	)
Accounts payable		6,201			50,458
Interest payable		(1,642	)		7,014
Income taxes payable		(11,485	)		(4,470	)
Other current liabilities		6,471			(14,943	)
Net cash provided by operating activities		564,454			693,214
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold		813,520			297,312
Investment in unconsolidated subsidiary		(82,857	)		(108	)
Additions to oil and gas properties		(757,148	)		(461,502	)
Additions to other assets and other property and equipment, net		(215,367	)		(74,075	)
Net cash used in investing activities		(241,852	)		(238,373	)
Cash flows from financing activities:
Borrowings under long-term debt		72,610			182,997
Principal payments on long-term debt		(115,810	)		(424,107	)
Contributions from noncontrolling interests		—			1,151
Distributions to noncontrolling interests		(13,366	)		(13,451	)
Payments of other liabilities		(305	)		(20,325	)
Exercise of long-term incentive plan stock options		362			3,452
Purchases of treasury stock		(39,218	)		(13,402	)
Excess tax benefits from share-based payment arrangements		27,937			4,090
Payment of financing fees		(8,739	)		(145	)
Dividends paid		(4,812	)		(4,783	)
Net cash used in financing activities		(81,341	)		(284,523	)
Net increase in cash and cash equivalents		241,261			170,318
Cash and cash equivalents, beginning of period		111,160			27,368
Cash and cash equivalents, end of period	$	352,421		$	197,686

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 COMPREHENSIVE INCOME

(in thousands)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Net income	$	265,700		$	188,689		$	609,504		$	449,295
Other comprehensive activity:
Net hedge gains included in continuing operations		(8,139	)		(20,697	)		(16,195	)		(41,623	)
Income tax provision		4,138			6,037			4,886			11,072
Other comprehensive activity		(4,001	)		(14,660	)		(11,309	)		(30,551	)
Comprehensive income		261,699			174,029			598,195			418,744
Comprehensive income attributable to the noncontrolling interests		(16,698	)		(16,740	)		(8,522	)		(27,758	)
Comprehensive income attributable to common stockholders	$	245,001		$	157,289		$	589,673		$	390,986

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, 2011

(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 and South Africa.

NOTE B.    Basis of Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of June 30, 2011 and for the three and six months ended June 30, 2011 and 2010 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 in connection 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, 2010.

Discontinued operations. During December 2010, the Company committed to a plan to divest 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”). In February 2011, the Company completed the sale of Pioneer Tunisia to an unaffiliated third party. Accordingly, the Company classified the assets and liabilities of Pioneer Tunisia as discontinued operations held for sale in the accompanying balance sheet as of December 31, 2010 and has classified the results of operations of Pioneer Tunisia as discontinued operations, net of tax for the three and six months ended June 30, 2011 and 2010 in the accompanying consolidated statements of operations (representing a recasting of the Pioneer Tunisia results of operations for the three and six months ended June 30, 2010, which were originally classified as continuing operations). See Note Q for more information regarding the sale of Pioneer Tunisia.

During the six months ended June 30, 2011 and 2010, the Bureau of Ocean Energy Management, Regulation, and Enforcement (the “BOEMRE”) paid the Company $2.0 million and $35.3 million, respectively, of interest on excess royalty payments associated with properties that were sold by the Company during 2006. Accordingly, the Company has classified the interest income as components of income from discontinued operations, net of tax in the accompanying consolidated statements of operations.

Allowances for doubtful accounts. As of June 30, 2011 and December 31, 2010, the Company’s allowances for doubtful accounts totaled $1.4 million and $3.7 million, respectively. Changes in the Company’s allowance for doubtful accounts during the three and six months ended June 30, 2011 are summarized in the following table:

	Three Months  Ended June 30, 2011			Six Months Ended June 30, 2011
	(in thousands)
Beginning allowance for doubtful accounts balance	$	3,535		$	3,674
Amount recorded in other expense for bad debt recoveries		(1,815	)		(1,797	)
Other net decreases		(306	)		(463	)
Ending allowance for doubtful accounts balance	$	1,414		$	1,414

Inventories. Inventories used in continuing operations consisted of $247.9 million and $183.4 million of materials and supplies and $4.1 million and $3.9 million of commodities as of June 30, 2011 and December 31, 2010, respectively. As of June 30, 2011 and December 31, 2010, the Company’s materials and supplies inventory was net of $2.5 million and $3.6 million, respectively, of valuation reserve allowances. As of June 30, 2011 and December 31, 2010, the Company estimated that $17.9 million and $13.7 million, respectively, of its materials and supplies inventory would not be utilized or sold within one year. Accordingly, those inventory values have been classified as other noncurrent assets in the accompanying consolidated balance sheets. As of December 31, 2010, the Company also had inventory in Tunisia totaling $13.6 million that is classified as discontinued operations held for sale in the accompanying consolidated balance sheet as of December 31, 2010.

11

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

Derivatives and hedging. All derivatives are recorded in the accompanying consolidated balance sheets at estimated fair value. See Note D 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 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 – net deferred hedge gains, net of tax (“AOCI – Hedging”), in the stockholders’ equity section of the accompanying consolidated balance sheets, and are being transferred to earnings during the same periods in which the hedged transactions are recognized in the Company’s earnings. Since February 1, 2009, the Company has recognized 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 Energy Partners L.P.’s (“Pioneer Southwest,” a majority-owned and consolidated subsidiary) credit-adjusted risk-free rate curves. The credit-adjusted risk-free rate curves for the Company and the counterparties are 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 250 basis points, representing Pioneer Southwest’s estimated borrowing rate.

Goodwill. 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 2010, the Company performed its annual assessment of goodwill impairment and determined that there was no impairment.

Noncontrolling interest in consolidated subsidiaries. The Company owns a 0.1 percent general partner interest and a 61.9 percent limited partner interest in Pioneer Southwest. Pioneer Southwest owns interests in certain oil and gas properties in the Spraberry field in the Permian Basin of West Texas. The financial position, results of operations and cash flows of Pioneer Southwest are consolidated with those of the Company.

The Company also owns a majority interest in Sendero Drilling Company, LLC (“Sendero”), which owns and operates land-based drilling rigs in the United States. In addition, the Company owns the majority interests in certain other subsidiaries with operations in the United States.

Noncontrolling interest in the net assets of consolidated subsidiaries totaled $101.0 million and $105.4 million as of June 30, 2011 and December 31, 2010, respectively. The Company recorded net income attributable to the noncontrolling interests of $20.1 million and $15.3 million for the three and six months ended June 30, 2011, respectively (principally related to Pioneer Southwest), compared to net income attributable to the noncontrolling interests of $21.1 million and $36.5 million for the three and six months ended June 30, 2010, respectively.

Investment in unconsolidated affiliate. The Company owns a 50.1 percent interest in EFS Midstream LLC (“EFS Midstream”), which owns and operates natural gas and liquids gathering, treating and transportation assets in the Eagle Ford Shale area of South Texas.

The Company accounts for the EFS Midstream investment under the equity method of accounting for investments in unconsolidated affiliates. Under the equity method, the Company’s investment in unconsolidated affiliates is increased for investments made and the investor’s share of the investee’s net income, and decreased for distributions received, the carrying value of investor’s interests sold and the investor’s share of the investee’s net losses. The Company’s equity interest in the net income of EFS Midstream is recorded in interest and other income in the Company’s accompanying consolidated statements of operations.

Stock-based compensation. For stock-based compensation equity awards granted or modified, compensation expense is being recognized in the Company’s financial statements on a straight line basis over the awards’ vesting periods based on their fair values on the dates of grant. The amount of compensation expense recognized at any date is at least equal to the portion of the measurement date (normally the grant date) value of the award that is vested at that date. The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options,

12

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

(ii) the prior day’s closing stock price on the date of grant for the fair value of restricted stock, restricted stock units, partnership unit awards or phantom unit awards that are expected to be settled wholly in the Company’s common stock or Pioneer Southwest common units (“Equity Awards”), (iii) the Monte Carlo simulation method for the fair value of performance unit awards and (iv) a probabilistic forecasted fair value method for series B unit awards issued by Sendero.

Stock-based compensation liability awards are awards that are expected to be settled wholly or partially in cash on their vesting dates, rather than in shares or units (“Liability Awards”). Stock-based Liability Awards are recorded as accounts payable – affiliates based on the fair value of the services that have been rendered on the unvested portions of the awards on the balance sheet date. The fair values of Liability Awards are updated at each balance sheet date and changes in the fair values of the unvested portions of the awards for which services have been rendered are recorded as increases or decreases to compensation expense. As of June 30, 2011, accounts payable – due to affiliates includes $3.9 million of liabilities attributable to the Liability Awards.

For the three and six months ended June 30, 2011, the Company recorded $13.8 million and $26.4 million, respectively, of stock-based compensation costs for all plans, as compared to $10.5 million and $20.6 million for the same respective periods of 2010. As of June 30, 2011, there was $93.1 million of unrecognized compensation expense related to unvested share- and unit-based compensation plan awards, including $21.6 million attributable to Liability Awards. This compensation will be recognized over the remaining vesting periods of the awards, which on a weighted average basis is a period of less than three years.

The Company’s issued shares, as reflected in the consolidated balance sheets at June 30, 2011 and December 31, 2010, do not include 536,775 and 825,796 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, 2011, 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, 2010		2,559,779			215,134			263,729			507,539			12,212			35,118
Awards granted		427,384			182,982			43,495			86,903			6,812			30,039
Awards vested		(1,015,713	)		(63,556	)		(14,807	)		—			(11,532	)		—
Options exercised		—			—			—			(15,290	)		—			—
Awards forfeited		(37,914	)		(11,931	)		—			—			—			—
Outstanding at June 30, 2011		1,933,536			322,629			292,417			579,152			7,492			65,157

New accounting pronouncements. During December 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-28, “Intangibles-Goodwill and Other (Topic 350).” ASU No. 2010-28 modifies step one of the goodwill impairment test for reporting units with zero or negative carrying amounts, requiring that an entity perform step two of the goodwill impairment test if it is more likely than not that a goodwill impairment exists for those reporting units. The Company adopted the provisions of ASU No. 2010-28 effective January 1, 2011. The adoption of ASU No. 2010-28 had no effect on the Company’s goodwill balance. See “Goodwill” above for more information about the Company’s policy for assessing impairment of its goodwill.

In May 2011, the FASB issued ASU 2011-04, “Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRSs.” ASU 2011-04 amended ASC 820 to converge the fair value measurement guidance in GAAP and International Financial Reporting Standards. Certain of the amendments clarify the application of existing fair value measurement requirements, while other amendments change a particular principle in ASC 820. In addition, ASU 2011-04 requires additional fair value disclosures. The amendments will be applied prospectively and are effective for annual periods beginning after December 15, 2011. The Company does not believe the adoption of this guidance will have a material impact on its consolidated financial statements.

13

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

In June 2011, the FASB issued ASU No. 2011-05 “Presentation of Comprehensive Income (Topic 220).” To increase the prominence of items reported in other comprehensive income, ASU 2011-05 requires comprehensive income, the components of net income, and the components of other comprehensive income to be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The amendments do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. The amendments will be applied retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2011. The adoption of ASU 2011-05 will not have a material impact on the Company’s consolidated financial statements.

NOTE C.    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 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, 2011:

	Three Months Ended June  30, 2011			Six Months Ended June 30, 2011
	(in thousands)
Beginning capitalized exploratory costs	$	80,530		$	96,193
Additions to exploratory costs pending the determination of proved reserves		140,081			214,345
Reclassification due to determination of proved reserves		(135,338	)		(195,682	)
Disposition of assets sold		—			(28,938	)
Exploratory well costs charged to exploration expense		(162	)		(807	)
Ending capitalized exploratory costs	$	85,111		$	85,111

The following table provides an aging, as of June 30, 2011 and December 31, 2010 of capitalized exploratory costs and the number of projects for which exploratory costs have been capitalized for a period greater than one year, based on the date drilling was completed:

	June 30, 2011		December 31, 2010
	(in thousands, except project counts)
Capitalized exploratory costs that have been suspended:
One year or less	$	77,129	$	70,635
More than one year		7,982		25,558
	$	85,111	$	96,193
Number of projects with exploratory costs that have been suspended for a period greater than one year		1		3

As of June 30, 2011, the Company has one project with exploratory costs that has been suspended for a period of one year or more, which is described below. As of December 31, 2010, the Company had three Tunisian projects with exploratory costs that had been suspended for a period of one year or more, all of which were included in the Pioneer Tunisia assets sold during February 2011.

South Texas Project. As of June 30, 2011, the Company has $8.0 million of suspended exploratory costs associated with a formation test well in South Texas. The well is currently awaiting finalization of the project’s ongoing fracture stimulation and completion designs. The Company successfully completed one other test well in the project and plans to drill a third test well during the second half of 2011. Information gained from the wells is being utilized to finalize the project’s fracture stimulation and completion designs. Future production from the project would utilize existing production and marketing infrastructure.

14

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

NOTE D.    Disclosures About Fair Value Measurements

In accordance with GAAP, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. 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. These two types of inputs are further prioritized into the following fair value input hierarchy:

• 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.

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 on a recurring basis as of June 30, 2011, for each of the fair value hierarchy levels:

	Fair Value Measurements at Reporting Date 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, 2011
	(in thousands)
Assets:
Trading securities	$	289	$	30,149	$	—	$	30,438
Commodity derivatives		—		271,544		—		271,544
Interest rate derivatives (a)		—		24,946		—		24,946
Deferred compensation plan assets		40,223		—		—		40,223
Total assets	$	40,512	$	326,639	$	—	$	367,151
Liabilities:
Commodity derivatives	$	—	$	170,732	$	13,351	$	184,083
Pioneer Southwest credit facility		—		84,542		—		84,542
5.875% senior notes due 2016		482,139		—		—		482,139
6.65% senior notes due 2017		529,972		—		—		529,972
6.875% senior notes due 2018		496,698		—		—		496,698
7.50% senior notes due 2020		512,158		—		—		512,158
7.20% senior notes due 2028		250,000		—		—		250,000
2.875% senior convertible notes due 2038 (b)		742,800		—		—		742,800
Total liabilities	$	3,013,767	$	255,274	$	13,351	$	3,282,392

(a) Subsequent to June 30, 2011, the Company terminated the interest rate derivatives shown in the table above and received proceeds of $26.1 million. See Note G for additional information about the Company’s interest rate derivatives.

(b) The fair value of the 2.875% senior convertible notes includes the fair value of the conversion privilege.

15

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

The following table presents the changes in the fair values of the Company’s natural gas liquid (“NGL”) derivative liabilities classified as Level 3 in the fair value hierarchy:

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)	Three Months Ended June  30, 2011			Six Months Ended June 30, 2011
	(in thousands)
Beginning liability balance	$	(16,675	)	$	(9,556	)
Total gains and losses:
Net unrealized gains (losses) included in earnings (a)		3,324			(3,795	)
Net realized losses included in earnings (a)		(4,629	)		(7,325	)
Settlement payments		4,629			7,325
Ending liability balance	$	(13,351	)	$	(13,351	)

(a) Non-hedge derivatives gains and losses are included in net derivative (gains) losses in the accompanying consolidated statements of operations.

The following table presents the carrying amounts and fair values of the Company’s financial instruments as of June 30, 2011 and December 31, 2010:

	June 30, 2011				December 31, 2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Assets:
Commodity price derivatives	$	271,544	$	271,544	$	304,434	$	304,434
Interest rate derivatives (a)	$	24,946	$	24,946	$	18,256	$	18,256
Trading securities	$	30,438	$	30,438	$	467	$	467
Deferred compensation plan assets	$	40,223	$	40,223	$	36,162	$	36,162
Liabilities:
Commodity price derivatives	$	184,083	$	184,083	$	136,867	$	136,867
Interest rate derivatives	$	—	$	—	$	704	$	704
Pioneer credit facility	$	—	$	—	$	49,000	$	58,382
Pioneer Southwest credit facility	$	87,000	$	84,542	$	81,200	$	77,241
5.875 % senior notes due 2016	$	401,037	$	482,139	$	396,880	$	475,194
6.65 % senior notes due 2017	$	484,114	$	529,972	$	484,046	$	516,632
6.875 % senior notes due 2018	$	449,209	$	496,698	$	449,192	$	480,969
7.50 % senior notes due 2020	$	446,572	$	512,158	$	446,433	$	494,145
7.20 % senior notes due 2028	$	249,927	$	250,000	$	249,925	$	259,350
2.875% senior convertible notes due 2038 (b)	$	453,119	$	742,800	$	444,994	$	728,400

(a) Subsequent to June 30, 2011, the Company terminated the interest rate derivatives shown in the table above and received $26.1 million of proceeds. See Note G for additional information about the Company’s interest rate derivatives.

(b) The fair value of the 2.875% senior convertible notes includes the fair value of the conversion privilege.

Trading securities and deferred compensation plan assets. The Company’s trading securities represent 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 plus unallocated contributions as of the measurement date. As of June 30, 2011, all significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs except inputs for certain trading securities that are not actively traded on major exchanges, which were corroborated broker quotes representing Level 2 inputs.

Interest rate derivatives. The Company’s interest rate derivative assets and liabilities as of June 30, 2011 represent swap contracts for $470 million notional amount of debt, whereby the Company pays a variable LIBOR-based rate and the counterparty pays a fixed rate of interest. The net derivative values attributable to the Company’s

16

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

interest rate derivative contracts as of June 30, 2011 are based on (i) the contracted notional amounts, (ii) LIBOR rate yield curves provided by counterparties and corroborated with forward active market-quoted LIBOR rate yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company’s interest rate derivative asset and liability measurements represent Level 2 inputs in the hierarchy priority.

Commodity derivatives. The Company’s commodity derivatives represent oil, 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 and diesel swap, collar and three-way collar derivative contract asset and liability measurements represent Level 2 inputs in the hierarchy priority and NGL derivative contract asset and liability measurements represent Level 3 inputs in the hierarchy priority.

Oil derivatives. The Company’s oil derivatives are swap, collar and three-way collar contracts for notional barrels (“Bbls”) of oil at fixed (in the case of swap contracts) or interval (in the case of collar and three-way collar contracts) New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) oil prices. The asset and liability values attributable to the Company’s oil derivatives were determined based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil, (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. The implied rates of volatility inherent in the Company’s collar contracts were determined based on average volatility factors provided by certain independent brokers who are active in buying and selling oil options and were corroborated by market-quoted volatility factors.

NGL derivatives. The Company’s NGL derivatives include swap and collar contracts for notional blended Bbls of Mont Belvieu-posted-price NGLs, Conway-posted-price NGLs or NGL component prices per Bbl. The asset and liability values attributable to the Company’s NGL derivatives were determined based on (i) the contracted notional volumes, (ii) independent active market-quoted NGL component prices and (iii) the applicable credit-adjusted risk-free rate yield curve. The implied rates of volatility inherent in the Company’s collar contracts were determined based on average volatility factors provided by certain independent brokers who are active in buying and selling NGL options and were corroborated by market-quoted volatility factors.

Gas derivatives. The Company’s gas derivatives are swap, collar and three-way collar contracts for notional volumes of gas (expressed in millions of British thermal units “MMBtus”) contracted at various posted price indexes, including NYMEX Henry Hub (“HH”) contracts coupled with basis swap contracts that convert the HH price index point to other price indexes. The asset and liability values attributable to the Company’s gas derivative contracts were determined based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent market-quoted forward index prices, (iv) the applicable credit-adjusted risk-free rate yield curve and (v) the implied rate of volatility inherent in the collar and three-way collar contracts. The implied rates of volatility inherent in the Company’s collar contracts and three-way collar contracts were determined based on average volatility factors provided by certain independent brokers who are active in buying and selling gas options and were corroborated by market-quoted volatility factors.

Diesel derivatives. The Company’s diesel derivatives are comprised of swap contracts for notional Bbls posted as Gulf Coast Ultra Low Sulfur (Pipeline) diesel by a posting service. The asset and liability values attributable to the Company’s diesel derivatives were determined based on (i) the contracted notional volumes, (ii) independent active market-quoted diesel prices and (iii) the applicable credit-adjusted risk-free rate yield curve.

Credit facility. The fair value of the Company’s credit facility and Pioneer Southwest’s credit facility is based on (i) forecasted contractual interest and fee payments, (ii) forward active market-quoted LIBOR rate yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve.

Senior notes. The Company’s senior notes represent debt securities that are 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.

NOTE E.    Income Taxes

The Company accounts for income taxes in accordance with the provisions of ASC Topic 740, which requires that the Company continually assess both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and worldwide economic factors to assess the likelihood that the Company’s net operating loss carry forwards

17

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

(“NOLs”) and other deferred tax attributes in the U.S., state, local and foreign tax jurisdictions will be utilized prior to their expiration. As of June 30, 2011 and December 31, 2010, the Company’s valuation allowances were $9.9 million and $6.6 million, respectively. As of December 31, 2010, the Company also had a $26.5 million valuation allowance related to Tunisia operations, which was classified as discontinued operations held for sale.

ASC 740 also clarifies the accounting for uncertainty in income taxes recognized and prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of June 30, 2011, the Company had no significant unrecognized tax benefits. The Company’s policy is to account for interest charges with respect to income taxes as interest expense and any penalties, with respect to income taxes, as other expense in the consolidated statements of operations. 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 2005. As of June 30, 2011, 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.

Income tax (provisions) benefits. 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, 2011 and 2010:

	Three Months Ended June  30,						Six Months Ended June  30,
	2011			2010			2011			2010
	(in thousands)
Current:
U.S. federal	$	—		$	(2,199	)	$	—		$	(3,301	)
U.S. state		(2,538	)		(1,800	)		(4,936	)		(3,124	)
Foreign		(10,782	)		(413	)		(17,102	)		(450	)
		(13,320	)		(4,412	)		(22,038	)		(6,875	)
Deferred:
U.S. federal		(140,948	)		(71,929	)		(100,160	)		(203,056	)
U.S. state		304			(7,040	)		10,729			(16,500	)
Foreign		9,268			161			13,924			(796	)
		(131,376	)		(78,808	)		(75,507	)		(220,352	)
Income tax provision	$	(144,696	)	$	(83,220	)	$	(97,545	)	$	(227,227	)

Discontinued operations. The Company’s income tax (provisions) benefits attributable to income from discontinued operations consisted of the following for the three and six months ended June 30, 2011 and 2010:

	Three Months Ended June  30,						Six Months Ended June  30,
	2011			2010			2011			2010
	(in thousands)
Current:
U.S. state	$	1,790		$	—		$	(3,935	)	$	—
Foreign		(3,753	)		(5,737	)		(5,602	)		(5,294	)
		(1,963	)		(5,737	)		(9,537	)		(5,294	)
Deferred:
U.S. federal		4,832			(12,909	)		(222,490	)		(12,839	)
U.S. state		80			—			(2,068	)		—
Foreign		4,669			(5,979	)		(7,653	)		(22,960	)
		9,581			(18,888	)		(232,211	)		(35,799	)
Income tax (provision) benefit	$	7,618		$	(24,625	)	$	(241,748	)	$	(41,093	)

18

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

NOTE F.    Long-term Debt

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. The Credit Facility replaces the Company’s Amended and Restated 5-Year Revolving Credit Agreement entered into in April 2007 (the “Expired Credit Facility”) and provides for aggregate loan commitments of $1.25 billion. As of June 30, 2011, the Company had no outstanding borrowings under the Credit Facility and $65.1 million of undrawn letters of credit, all of which were commitments under the Credit Facility, leaving the Company with $1.2 billion of unused borrowing capacity under the Credit Facility.

Borrowings under the Credit Facility may be in the form of revolving loans or swing line loans. Aggregate outstanding swing line loans may not exceed $150 million. Revolving loans under the Credit Facility bear interest, at the option of the Company, based on (a) a rate per annum equal to the higher of the prime rate announced from time to time by Wells Fargo Bank, National Association or the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System during the last preceding business day plus 0.5 percent plus a defined alternate base rate spread margin (“ABR Margin”), which is currently one percent based on the Company’s debt rating or (b) a base Eurodollar rate, substantially equal to LIBOR, plus a margin (the “Applicable Margin”), which is currently two percent and is also determined by the Company’s debt rating. Swing line loans under the Credit Facility bear interest at a rate per annum equal to the “ASK” rate for Federal funds periodically published by the Dow Jones Market Service plus the Applicable Margin. Letters of credit outstanding under the Credit Facility are subject to a per annum fee, representing the Applicable Margin plus 0.125 percent. The Company also pays commitment fees on undrawn amounts under the Credit Facility that are determined by the Company’s debt rating (currently 0.375 percent).

The Credit Facility contains certain financial covenants, which include the maintenance of a ratio of total debt to book capitalization less intangible assets, accumulated other comprehensive income and certain noncash asset impairments not to exceed .60 to 1.0. The covenants also include the maintenance of a ratio of the net present value of the Company’s oil and gas properties to total debt of at least 1.75 to 1.0 until the Company achieves an investment grade rating by Moody’s Investors Service, Inc. or Standard & Poors Ratings Group, Inc.

As of June 30, 2011, the Company and Pioneer Southwest were in compliance with all of their debt covenants.

In accordance with GAAP, the Company accounted for the entry into the Credit Facility as an extinguishment of the Expired Credit Facility. Associated therewith, the Company recorded a $2.4 million loss on extinguishment of debt to write off the unamortized issuance costs of the Company’s Expired Credit Facility, which is included in other expense in the accompanying consolidated statement of operations for the six months ended June 30, 2011 (see Note P).

Convertible senior notes. As of June 30, 2011 and December 31, 2010, the Company had $480 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 pursuant to a formula.

The Company’s stock price during March 2011 caused the Company’s 2.875% Convertible Senior Notes to become convertible at the option of the holders during the three months ended June 30, 2011. Associated therewith, 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 July and August 2011, the Company paid the holders a total of $71 thousand of cash and issued 340 shares of the Company’s common stock.

During June 2011, 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, 2011. The Company’s 2.875% Convertible Senior Notes may become convertible in future quarters depending on the Company’s stock price performance or under certain other conditions. If all of the 2.875% Convertible Senior Notes had been converted on June 30, 2011, 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 calculated over the last 20 trading days of June and valued at $158.8 million.

19

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

NOTE G.    Derivative Financial Instruments

The Company utilizes commodity derivative contracts 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 prices. All material physical sales contracts governing the Company’s oil production are tied directly or indirectly to NYMEX WTI oil prices. The following table sets forth the volumes in Bbls outstanding as of June 30, 2011 under the Company’s oil derivative contracts and the weighted average oil prices per Bbl for those contracts:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Outstanding Average
Average daily oil production associated with derivatives (Bbls):
2011 – Swap contracts
Volume						750		750		750
NYMEX price					$	77.25	$	77.25	$	77.25
2011 – Collar contracts
Volume						2,000		2,000		2,000
NYMEX price:
Ceiling					$	170.00	$	170.00	$	170.00
Floor					$	115.00	$	115.00	$	115.00
2011 – Collar contracts with short puts
Volume						32,000		32,000		32,000
NYMEX price:
Ceiling					$	99.33	$	99.33	$	99.33
Floor					$	73.75	$	73.75	$	73.75
Short put					$	59.31	$	59.31	$	59.31
2012 – Swap contracts
Volume		3,000		3,000		3,000		3,000		3,000
NYMEX price	$	79.32	$	79.32	$	79.32	$	79.32	$	79.32
2012 – Collar contracts
Volume		2,000		2,000		2,000		2,000		2,000
NYMEX price:
Ceiling	$	127.00	$	127.00	$	127.00	$	127.00	$	127.00
Floor	$	90.00	$	90.00	$	90.00	$	90.00	$	90.00
2012 – Collar contracts with short puts
Volume		36,000		36,000		36,000		36,000		36,000
NYMEX price:
Ceiling	$	117.99	$	117.99	$	117.99	$	117.99	$	117.99
Floor	$	80.42	$	80.42	$	80.42	$	80.42	$	80.42
Short put	$	65.00	$	65.00	$	65.00	$	65.00	$	65.00
2013 – Swap contracts
Volume		3,000		3,000		3,000		3,000		3,000
NYMEX price	$	81.02	$	81.02	$	81.02	$	81.02	$	81.02
2013 – Collar contracts with short puts (a)
Volume		21,250		21,250		21,250		21,250		21,250
NYMEX price:
Ceiling	$	117.38	$	117.38	$	117.38	$	117.38	$	117.38
Floor	$	80.18	$	80.18	$	80.18	$	80.18	$	80.18
Short put	$	65.18	$	65.18	$	65.18	$	65.18	$	65.18
2014 – Collar contracts with short puts (a)
Volume		12,000		12,000		12,000		12,000		12,000
NYMEX price:
Ceiling	$	128.16	$	128.16	$	128.16	$	128.16	$	128.16
Floor	$	87.92	$	87.92	$	87.92	$	87.92	$	87.92
Short put	$	72.92	$	72.92	$	72.92	$	72.92	$	72.92

(a) Subsequent to June 30, 2011, the Company entered into additional collar contracts with short puts for (i) 10,000 Bbls per day of the Company’s 2013 production with a ceiling price of $127.51 per Bbl, a floor price of $90.00 per Bbl and a short put price of $67.00 per Bbl and (ii) 10,000 Bbls per day of the Company’s 2014 production with a ceiling price of $131.68 per Bbl, a floor price of $90.00 per Bbl and a short put price of $67.00 per Bbl.

20

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

Natural gas liquids prices. 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. The following table sets forth the volumes in Bbls outstanding as of June 30, 2011 under the Company’s NGL derivative contracts and the weighted average NGL prices per Bbl for those contracts:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Outstanding Average
Average daily NGL production associated with derivatives (Bbls):
2011 – Swap contracts
Volume						1,150		1,150		1,150
Blended index price					$	51.50	$	51.50	$	51.50
2011 – Collar contracts
Volume						2,650		2,650		2,650
Index price:
Ceiling					$	64.23	$	64.23	$	64.23
Floor					$	53.29	$	53.29	$	53.29
2012 – Swap contracts
Volume		750		750		750		750		750
Index price	$	35.03	$	35.03	$	35.03	$	35.03	$	35.03

Gas prices. 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 HH prices and actual index prices at which the gas is sold. The following table sets forth the volumes in MMBtus outstanding as of June 30, 2011 under the Company’s gas derivative contracts and the weighted average gas prices per MMBtu for those contracts:

	First Quarter	Second Quarter	Third Quarter			Fourth Quarter			Outstanding Average
Average daily gas production associated with derivatives (MMBtus):
2011 – Swap contracts
Volume				117,500			117,500			117,500
NYMEX price			$	6.13		$	6.13		$	6.13
2011 – Collar contracts with short puts
Volume				200,000			200,000			200,000
NYMEX price:
Ceiling			$	8.55		$	8.55		$	8.55
Floor			$	6.32		$	6.32		$	6.32
Short put			$	4.88		$	4.88		$	4.88
2011 – Basis swap contracts
Volume				143,500			143,500			143,500
Price differential			$	(0.56	)	$	(0.56	)	$	(0.56	)

21

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

2012 – Swap contracts
Volume		105,000			105,000			105,000			105,000			105,000
NYMEX price	$	5.82		$	5.82		$	5.82		$	5.82		$	5.82
2012 – Collar contracts
Volume		65,000			65,000			65,000			65,000			65,000
NYMEX price:
Ceiling	$	6.60		$	6.60		$	6.60		$	6.60		$	6.60
Floor	$	5.00		$	5.00		$	5.00		$	5.00		$	5.00
2012 – Collar contracts with short puts
Volume		190,000			190,000			190,000			190,000			190,000
NYMEX price:
Ceiling	$	7.96		$	7.96		$	7.96		$	7.96		$	7.96
Floor	$	6.12		$	6.12		$	6.12		$	6.12		$	6.12
Short put	$	4.55		$	4.55		$	4.55		$	4.55		$	4.55
2012 – Basis swap contracts
Volume		126,000			126,000			126,000			126,000			126,000
Price differential	$	(0.35	)	$	(0.35	)	$	(0.35	)	$	(0.35	)	$	(0.35	)
2013 – Swap contracts
Volume		67,500			67,500			67,500			67,500			67,500
NYMEX price	$	6.11		$	6.11		$	6.11		$	6.11		$	6.11
2013 – Collar contracts
Volume		150,000			150,000			150,000			150,000			150,000
NYMEX price:
Ceiling	$	6.25		$	6.25		$	6.25		$	6.25		$	6.25
Floor	$	5.00		$	5.00		$	5.00		$	5.00		$	5.00
2013 – Collar contracts with short puts
Volume		45,000			45,000			45,000			45,000			45,000
NYMEX price:
Ceiling	$	7.49		$	7.49		$	7.49		$	7.49		$	7.49
Floor	$	6.00		$	6.00		$	6.00		$	6.00		$	6.00
Short put	$	4.50		$	4.50		$	4.50		$	4.50		$	4.50
2013 – Basis swap contracts
Volume		52,500			52,500			52,500			52,500			52,500
Price differential	$	(0.25	)	$	(0.25	)	$	(0.25	)	$	(0.25	)	$	(0.25	)
2014 – Swap contracts
Volume		50,000			50,000			50,000			50,000			50,000
NYMEX price	$	6.05		$	6.05		$	6.05		$	6.05		$	6.05
2014 – Collar contracts
Volume		140,000			140,000			140,000			140,000			140,000
NYMEX price:
Ceiling	$	6.44		$	6.44		$	6.44		$	6.44		$	6.44
Floor	$	5.00		$	5.00		$	5.00		$	5.00		$	5.00
2014 – Collar contracts with short puts
Volume		50,000			50,000			50,000			50,000			50,000
NYMEX price:
Ceiling	$	8.08		$	8.08		$	8.08		$	8.08		$	8.08
Floor	$	6.00		$	6.00		$	6.00		$	6.00		$	6.00
Short put	$	4.50		$	4.50		$	4.50		$	4.50		$	4.50
2014 – Basis swap contracts
Volume		20,000			20,000			20,000			20,000			20,000
Price differential	$	(0.14	)	$	(0.14	)	$	(0.14	)	$	(0.14	)	$	(0.14	)
2015 – Collar contracts
Volume		50,000			50,000			50,000			50,000			50,000
NYMEX price:
Ceiling	$	7.92		$	7.92		$	7.92		$	7.92		$	7.92
Floor	$	5.00		$	5.00		$	5.00		$	5.00		$	5.00

22

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

Diesel prices. During the second quarter of 2011, the Company purchased diesel derivative swap contracts for 250 notional Bbls per day, for the period from July 2011 through December 2011, at an average per Bbl fixed price of $123.90. The diesel derivative swap contracts are priced at an index that is highly correlated to the prices that the Company incurs to fuel its drilling rigs and fracture stimulation fleet equipment. The Company purchases diesel derivative swap contracts to mitigate fuel price risk.

Interest rates. The following table sets forth as of June 30, 2011 the notional amount of the Company’s debt under outstanding fixed-for-variable interest rate swap contracts, the weighted average fixed annual interest rate and termination date for those contracts:

Type	Notional Amount		Weighted Average Fixed Interest Rate		Termination Date
	(in thousands)
Fixed-for-variable	$	400,000		2.87 percent		July 2016
Fixed-for-variable	$	70,000		3.23 percent		March 2017

During July 2011, the Company terminated the $470 million notional amount of fixed-for-variable interest rate derivative contracts and received $26.1 million of proceeds.

Tabular disclosure of derivative financial instruments. All of the Company’s derivatives are accounted for as non-hedge derivatives as of June 30, 2011 and December 31, 2010. The following tables provide disclosure of the Company’s derivative instruments:

Fair Value of Derivative Instruments as of June 30, 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	$	153,812	Derivatives - current	$	87,944
Interest rate derivatives	Derivatives - current		12,253	Derivatives - current		—
Commodity price derivatives	Derivatives - noncurrent		135,927	Derivatives - noncurrent		114,334
Interest rate derivatives	Derivatives - noncurrent		17,870	Derivatives - noncurrent		5,177
		$	319,862		$	207,455
Fair Value of Derivative Instruments as of December 31, 2010
	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	$	167,406	Derivatives - current	$	87,741
Interest rate derivatives	Derivatives - current		11,903	Derivatives - current		886
Commodity price derivatives	Derivatives - noncurrent		152,731	Derivatives - noncurrent		64,829
Interest rate derivatives	Derivatives - noncurrent		15,762	Derivatives - noncurrent		9,227
		$	347,802		$	162,683

(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.

23

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

Derivatives in Cash Flow Hedging Relationships	Location of Gain/(Loss) Reclassified from AOCI into Earnings		Amount of Gain/(Loss) Reclassified from AOCI into Earnings
			Three Months Ended June  30,						Six Months Ended June  30,
			2011			2010			2011			2010
			in thousands
Interest rate derivatives		Interest expense	$	(69	)	$	(312	)	$	(137	)	$	(1,370	)
Interest rate derivatives		Derivative gains (losses), net		—			(1,523	)		—			(2,665	)
Commodity price derivatives		Oil and gas revenue		8,208			22,532			16,332			45,658
Total			$	8,139		$	20,697		$	16,195		$	41,623
Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Earnings on Derivatives		Amount of Gain (Loss) Recognized in Earnings on Derivatives
			Three Months Ended June 30,						Six Months Ended June 30,
			2011			2010			2011			2010
			(in thousands)
Interest rate derivatives		Derivative gains (losses), net	$	14,575		$	26,517		$	12,423		$	37,916
Commodity price derivatives		Derivative gains (losses), net		214,903			152,534			(27,377)			407,753
Total			$	229,478		$	179,051		$	(14,954)		$	445,669

AOCI - Hedging. As of June 30, 2011 and December 31, 2010, AOCI – Hedging represented net deferred gains of $2.9 million and $7.4 million, respectively. The AOCI – Hedging balance as of June 30, 2011 was comprised of $13.4 million of net deferred gains on the effective portions of discontinued commodity hedges, $1.8 million of net deferred losses on the effective portions of discontinued interest rate hedges and $1.8 million of associated net deferred tax provisions, reduced by $6.9 million of AOCI – Hedging net deferred gains attributable to and classified as noncontrolling interests in consolidated subsidiaries.

During the twelve months ending June 30, 2012, the Company expects to reclassify $15.0 million of AOCI – Hedging net deferred gains to oil revenues (including $7.0 million related to noncontrolling interests) and $299 thousand of AOCI – Hedging net deferred losses to interest expense. The Company also expects to reclassify $2.8 million of net deferred income tax provisions associated with hedge derivatives during the twelve months ending June 30, 2012 from AOCI – Hedging to income tax expense. For the remaining six months of 2011, the Company expects to reclassify deferred gains on discontinued commodity hedges of $16.6 million to oil revenues. During 2012, the Company expects to reclassify deferred losses on commodity hedges of $3.2 million to oil revenues. The aforementioned $1.8 million of net deferred hedge losses on the effective portion of interest rate hedges will be transferred from AOCI-Hedging to interest expense ratably through April 2018.

NOTE H.    Asset Retirement Obligations

The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells 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.

24

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

The following table summarizes the Company’s asset retirement obligation activity during the three and six months ended June 30, 2011 and 2010:

	Three Months Ended June  30,						Six Months Ended June  30,
	2011			2010			2011			2010
	(in thousands)
Beginning asset retirement obligations	$	154,689		$	142,270		$	152,291		$	166,434
Liabilities assumed in acquisitions		—			6			6			6
New wells placed on production		1,404			4,365			2,075			4,644
Changes in estimates		(179	)		—			121			—
Disposition of wells		(367	)		(3,291	)		(448	)		(29,540	)
Liabilities settled		(6,235	)		(8,801	)		(7,469	)		(9,955	)
Accretion of discount from continuing operations		2,658			2,529			5,313			5,388
Accretion of discount from discontinued operations		—			103			81			204
Ending asset retirement obligations	$	151,970		$	137,181		$	151,970		$	137,181

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, 2011 and December 31, 2010, the current portions of the Company’s asset retirement obligations were $14.9 million and $19.9 million, respectively.

NOTE I.    Postretirement Benefit Obligations

As of June 30, 2011 and December 31, 2010, the Company had $7.0 million and $7.4 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 plans of which four relate to predecessor entities that the Company acquired in prior years. These plans had no assets as of June 30, 2011 or December 31, 2010. The participants of the predecessor plans are not current employees of the Company.

The following table reconciles changes in the Company’s unfunded accumulated postretirement benefit obligations during the three and six months ended June 30, 2011 and 2010:

	Three Months Ended June  30,						Six Months Ended June  30,
	2011			2010			2011			2010
	(in thousands)
Beginning accumulated postretirement benefit obligations	$	7,231		$	8,951		$	7,408		$	9,075
Net benefit payments		(375	)		(272	)		(691	)		(584	)
Service costs		61			81			122			161
Net actuarial losses		—			100			—			100
Accretion of interest		79			108			157			216
Ending accumulated postretirement benefit obligations	$	6,996		$	8,968		$	6,996		$	8,968

NOTE J.    Commitments and Contingencies

Legal actions. In addition to the legal action described below, the Company is a party to other 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 other 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 will continue to evaluate its litigation on a quarter-by-quarter basis and will establish and adjust any litigation reserves as appropriate to reflect its assessment of the then current status of litigation.

25

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

Investigation by the Alaska Oil and Gas Conservation Commission (the “AOGCC”). During the second quarter of 2010, the AOGCC commenced an investigation into allegations by a former Pioneer employee regarding the Company’s Oooguruk facility on the North Slope of Alaska. Among the allegations are claims that the Company did not have authorization to inject certain non-hazardous substances into its enhanced oil recovery well, that the Company mishandled disposal of waste products and that the Company’s operating practices are harmful to the project’s oil reservoirs. Upon initially becoming aware of the allegations, the Company informed the AOGCC and other relevant federal, state and local agencies and commenced its own investigation, which confirmed injections of non-hazardous fluids into the Oooguruk enhanced oil recovery well without prior authorizations to do so. The results of the Company’s investigation were reported to the agencies. In December 2010, the AOGCC investigator submitted a report outlining its findings, which (i) found that the Company’s operating practices have not harmed the project’s oil reservoirs and (ii) raised certain regulatory compliance issues, all of which the Company previously reported or has since taken actions to remedy. Although the Company does not know at this time what action the AOGCC will take in response to the report, based on the facts as known to date, the Company believes that compliance with any order or other action of the AOGCC will not materially affect the Company’s liquidity, financial position or future results of operations.

Obligations following divestitures. In April 2006, the Company provided the purchaser of its Argentine assets certain indemnifications. The Company remains responsible for certain contingent liabilities related to such indemnifications, subject to defined limitations, including matters of litigation, environmental contingencies, royalty obligations and income taxes. The Company has also retained certain liabilities and indemnified buyers for certain matters in connection with other divestitures, including the sale in 2007 of its Canadian assets and the February 2011 sale of Pioneer Tunisia. The Company does not believe that these obligations are probable of having a material impact on its liquidity, financial position or future results of operations.

NOTE K.    Net Income (Loss) Per Share

In accordance with GAAP, 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.

26

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

The following tables reconcile the Company’s net income from continuing operations, income (loss) from discontinued operations and net income attributable to common stockholders to the basic and diluted earnings used in the two-class method to determine the Company’s net income per share amounts for the three and six months ended June 30, 2011 and 2010:

	Three Months Ended June 30, 2011									Six Months Ended June 30, 2011
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Income (loss) as reported	$	267,284		$	(1,584	)	$	265,700		$	196,446		$	413,058		$	609,504
Net income attributable to the noncontrolling interests		(20,123	)		—			(20,123	)		(15,333	)		—			(15,333	)
Participating basic earnings		(4,847	)		—			(4,847	)		(3,307	)		(7,542	)		(10,849	)
Basic net income (loss) attributable to common stockholders		242,314			(1,584	)		240,730			177,806			405,516			583,322
Reallocation of participating earnings		164			—			164			82			189			271
Diluted income (loss) attributable to common stockholders	$	242,478		$	(1,584	)	$	240,894		$	177,888		$	405,705		$	583,593

	Three Months Ended June 30, 2010									Six Months Ended June 30, 2010
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Income as reported	$	146,838		$	41,851		$	188,689		$	403,633		$	45,662		$	449,295
Net income attributable to the noncontrolling interests		(21,113	)		—			(21,113	)		(36,465	)		—			(36,465	)
Participating basic earnings		(3,063	)		(1,020	)		(4,083	)		(8,351	)		(1,039	)		(9,390	)
Basic income attributable to common stockholders		122,662			40,831			163,493			358,817			44,623			403,440
Reallocation of participating earnings		84			28			112			98			12			110
Diluted income attributable to common stockholders	$	122,746		$	40,859		$	163,605		$	358,915		$	44,635		$	403,550

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

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

27

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

NOTE L.    Geographic Operating Segment Information

The Company has reportable operations in only one industry segment, that being the oil and gas exploration and production industry; however, the Company is organizationally structured along geographic operating segments or regions. The Company has reportable continuing operations in the United States and South Africa.

The following tables provide the Company’s geographic operating segment data for the three and six months ended June 30, 2011 and 2010. Geographic operating segment income tax (provisions) benefits have been determined based on statutory rates existing in the various tax jurisdictions where the Company has oil and gas producing activities. The “Headquarters” table column includes income and expenses that are not routinely included in the earnings measures internally reported to management on a geographic operating segment basis.

	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Three Months Ended June 30, 2011
Revenues and other income:
Oil and gas	$	562,411		$	21,520		$	—		$	583,931
Interest and other		13,725			—			4,729			18,454
Loss on disposition of assets, net		—			—			(296	)		(296	)
		576,136			21,520			4,433			602,089
Costs and expenses:
Oil and gas production		101,741			714			—			102,455
Production and ad valorem taxes		35,864			—			—			35,864
Depletion, depreciation and amortization		127,864			13,536			12,498			153,898
Exploration and abandonments		19,731			183			—			19,914
General and administrative		—			—			44,644			44,644
Accretion of discount on asset retirement obligations		2,047			611			—			2,658
Interest		—			—			45,768			45,768
Hurricane activity, net		(2	)		—			—			(2	)
Derivative gains, net		—			—			(229,478	)		(229,478	)
Other		5,410			—			8,978			14,388
		292,655			15,044			(117,590	)		190,109
Income from continuing operations before income taxes		283,481			6,476			122,023			411,980
Income tax provision		(104,888	)		(1,813	)		(37,995	)		(144,696	)
Income from continuing operations	$	178,593		$	4,663		$	84,028		$	267,284

28

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Three Months Ended June 30, 2010
Revenues and other income:
Oil and gas	$	401,540		$	20,502		$	—		$	422,042
Interest and other		998			—			15,954			16,952
Gain on disposition of assets, net		7,560			—			85			7,645
		410,098			20,502			16,039			446,639
Costs and expenses:
Oil and gas production		93,116			896			—			94,012
Production and ad valorem taxes		25,338			—			—			25,338
Depletion, depreciation and amortization		117,859			18,442			8,008			144,309
Exploration and abandonments		22,689			54			—			22,743
General and administrative		—			—			40,433			40,433
Accretion of discount on asset retirement obligations		1,907			622			—			2,529
Interest		—			—			45,368			45,368
Hurricane activity, net		5,184			—			—			5,184
Derivative gains, net		—			—			(177,528	)		(177,528	)
Other		10,270			—			3,923			14,193
		276,363			20,014			(79,796	)		216,581
Income from continuing operations before income taxes		133,735			488			95,835			230,058
Income tax provision		(49,482	)		(137	)		(33,601	)		(83,220	)
Income from continuing operations	$	84,253		$	351		$	62,234		$	146,838

	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Six Months Ended June 30, 2011
Revenues and other income:
Oil and gas	$	1,038,140		$	42,921		$	—		$	1,081,061
Interest and other		16,603			—			34,538			51,141
Loss on disposition of assets, net		—			—			(2,487	)		(2,487	)
		1,054,743			42,921			32,051			1,129,715
Costs and expenses:
Oil and gas production		200,576			1,810			—			202,386
Production and ad valorem taxes		69,160			—			—			69,160
Depletion, depreciation and amortization		244,404			27,221			22,646			294,271
Exploration and abandonments		37,216			341			—			37,557
General and administrative		—			—			88,750			88,750
Accretion of discount on asset retirement obligations		4,091			1,222			—			5,313
Interest		—			—			90,995			90,995
Hurricane activity, net		69			—			—			69
Derivative losses, net		—			—			14,954			14,954
Other		10,569			—			21,700			32,269
		566,085			30,594			239,045			835,724
Income (loss) from continuing operations before income taxes		488,658			12,327			(206,994	)		293,991
Income tax benefit (provision)		(180,803	)		(3,452	)		86,710			(97,545	)
Income (loss) from continuing operations	$	307,855		$	8,875		$	(120,284	)	$	196,446

29

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Six Months Ended June 30, 2010
Revenues and other income:
Oil and gas	$	848,204		$	45,883		$	—		$	894,087
Interest and other		1,507			—			33,453			34,960
Gain (loss) on disposition of assets, net		24,979			—			(391	)		24,588
		874,690			45,883			33,062			953,635
Costs and expenses:
Oil and gas production		178,440			1,672			—			180,112
Production and ad valorem taxes		52,399			—			—			52,399
Depletion, depreciation and amortization		233,364			40,339			15,034			288,737
Exploration and abandonments		39,465			126			—			39,591
General and administrative		—			—			78,748			78,748
Accretion of discount on asset retirement obligations		4,144			1,244			—			5,388
Interest		—			—			92,891			92,891
Hurricane activity, net		(2,226	)		—			—			(2,226	)
Derivative gains, net		—			—			(443,004	)		(443,004	)
Other		20,551			—			9,588			30,139
		526,137			43,381			(246,743	)		322,775
Income from continuing operations before income taxes		348,553			2,502			279,805			630,860
Income tax provision		(128,965	)		(701	)		(97,561	)		(227,227	)
Income from continuing operations	$	219,588		$	1,801		$	182,244		$	403,633

	June 30, 2011		December 31, 2010
	(in thousands)
Consolidating Assets by Geographic Area:
United States	$	10,222,200	$	8,987,141
South Africa		85,017		134,901
Tunisia		—		325,942
Headquarters		45,871		231,118
Total consolidated assets	$	10,353,088	$	9,679,102

NOTE M.     Volumetric Production Payments

The Company’s remaining VPP represents a limited-term overriding royalty interest in oil reserves that: (i) entitles the purchaser to receive production volumes over a period of time from specific lease interests, (ii) is free and clear of all associated future production costs and capital expenditures associated with the reserves, (iii) is nonrecourse to the Company (i.e., the purchaser’s only recourse is to the reserves acquired), (iv) transfer title of the reserves to the purchaser and (v) allow the Company to retain the remaining reserves after the VPP’s volumetric quantities have been delivered.

At the inception of the VPP agreement, the Company (i) removed the proved reserves associated with the VPP, (ii) recognized VPP proceeds as deferred revenue which are being amortized on a unit-of-production basis to oil revenues over the remaining term of the VPP, (iii) retained responsibility for 100 percent of the production costs and capital costs related to VPP interests and (iv) no longer recognizes production associated with the VPP volumes.

The following table provides information about changes in the deferred revenue carrying values of the Company's VPP for the six months ended June 30, 2011 (in thousands):

Deferred revenue at December 31, 2010	$	87,020
Less: 2011 amortization		(22,290	)
Deferred revenue at June 30, 2011	$	64,730

30

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

The remaining deferred revenue amounts will be recognized in oil revenues in the consolidated statements of operations as noted below, assuming the related VPP production volumes are delivered as scheduled (in thousands):

Remaining 2011	$	22,659
2012	$	42,071

NOTE N.    Gain (Loss) on Disposition of Assets, Net

For the three and six months ended June 30, 2011, the Company recorded $296 thousand and $2.5 million of net losses on disposition of assets from continuing operations, respectively, as compared to $7.6 million and $24.6 million, respectively, of net gains from continuing operations for the three and six months ended June 30, 2010.

The Company’s net losses during the three and six months ended June 30, 2011 are primarily associated with sales of excess materials and supplies inventory. During the three and six months ended June 30, 2010, the Company’s net gains are primarily attributable to the Company’s Eagle Ford Shale joint venture transaction that was completed during June 2010, and the sale of proved and unproved oil and gas properties in the Uinta/Piceance area.

See Note Q for information about the Company’s gains and losses during the three and six months ended June 30, 2011 from the sale of its Tunisia subsidiaries that are included in discontinued operations.

NOTE O.    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,
	2011		2010		2011		2010
	(in thousands)
Alaskan Petroleum Production Tax credits (a)	$	—	$	13,613	$	27,452	$	27,861
Third-party income from vertical integration services (b)		13,725		998		16,603		1,507
Other income		1,912		1,131		2,913		1,783
Eagle Ford Shale land fees		1,802		—		1,802		—
Deferred compensation plan income		299		174		1,166		684
Equity interest in income of unconsolidated affiliate		502		—		801		—
Interest income		214		92		404		476
Sales and other tax refunds		—		944		—		984
Insurance claim recovery		—		—		—		1,665
Total interest and other income	$	18,454	$	16,952	$	51,141	$	34,960

(a) 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.

(b) Third-party income from vertical integration services primarily represents income associated with Company-provided fracture stimulation, drilling and related services.

31

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

NOTE P.    Other Expense

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

	Three Months Ended June  30,						Six Months Ended June  30,
	2011			2010			2011			2010
	(in thousands)
Transportation commitment charge (a)	$	5,688		$	—		$	10,960		$	—
Above market drilling rig related costs (b)		5,410			10,270			10,569			20,551
Other		1,909			2,617			4,193			3,170
Loss on extinguishment of debt		—			—			2,367			—
Contingency and environmental accrual adjustments		1,587			94			2,882			247
Cancelled well costs (recoveries)		(442	)		(126	)		759			(29	)
Inventory impairment (c)		302			13			587			1,570
Tax penalties		1,749			—			1,749			—
Bad debt recoveries		(1,815	)		(254	)		(1,797	)		(30	)
Well servicing operations (d)		—			1,579			—			4,660
Total other expense	$	14,388		$	14,193		$	32,269		$	30,139

(a) Primarily represents firm transportation contract deficiency payment obligations.

(b) Primarily represents charges for the portion of Pioneer’s contracted drilling rig rates that are above market rates and are not charged to joint operations.

(c) Represents impairment charges on excess materials and supplies inventories.

(d) Represents idle well servicing costs.

NOTE Q.    Discontinued Operations

During December 2010, the Company committed to a plan to sell Pioneer Tunisia and in February 2011 completed the sale of 100 percent of the Company’s share holdings in Pioneer Tunisia to an unaffiliated party for net cash proceeds of $853.7 million, including normal post-closing adjustments, resulting in a pretax gain of $645.3 million. During the three months ended June 30, 2011, the Company reduced the net gain on the transaction by $4.6 million. The historical results of operations of Pioneer Tunisia have been classified as discontinued operations herein.

During the six months ended June 30, 2011 and 2010, the BOEMRE paid the Company $2.0 million and $35.3 million, respectively, 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. See Note B for additional information about the BOEMRE payments.

32

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2011

(Unaudited)

The following table represents the components of the Company’s discontinued operations for the three and six months ended June 30, 2011 and 2010:

	Three Months Ended June  30,						Six Months Ended June  30,
	2011			2010			2011			2010
	(in thousands)
Revenues and other income:
Oil and gas	$	—		$	40,096		$	22,130		$	75,848
Interest and other		18			42,619			4,586			44,414
Gain (loss) on disposition of assets, net (a)		(4,574	)		—			645,298			—
		(4,556	)		82,715			672,014			120,262
Costs and expenses:
Oil and gas production		—			3,278			2,126			6,894
Depletion, depreciation and amortization (a)		—			6,006			—			12,346
Exploration and abandonments		1,692			4,379			4,246			8,329
General and administrative		2,279			1,940			8,898			4,573
Accretion of discount on asset retirement obligations (a)		—			103			81			204
Other		675			533			1,857			1,161
		4,646			16,239			17,208			33,507
Income (loss) from discontinued operations before income taxes		(9,202	)		66,476			654,806			86,755
Current tax provision (b)		(1,963	)		(5,737	)		(9,537	)		(5,294	)
Deferred tax (provision) benefit (a) (b)		9,581			(18,888	)		(232,211	)		(35,799	)
	$	(1,584	)	$	41,851		$	413,058		$	45,662

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

(b) During the three months ended June 30, 2011, the Company’s taxes from discontinued operations include (i) a current provision and a deferred benefit amounting to $5.2 million associated with a Tunisian reinvestment reserve adjustment and (ii) a $3.7 million deferred foreign tax credit carryover benefit.

NOTE R.    Subsequent Events

The Company has evaluated subsequent events through the date of issuance of its unaudited consolidated financial statements. Except as disclosed in Notes D and G, the Company is not aware of any reportable subsequent events.

33

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 2011 included the following highlights:

• Earnings attributable to common stockholders were $245.6 million ($2.03 per diluted share), as compared to $167.6 million ($1.41 per diluted share) for the second quarter of 2010. The increase in earnings attributable to common stockholders is primarily due to (i) an increase in oil and NGL sales volumes and commodity prices, offset by increases in associated production costs, depletion expense and income taxes, and (ii) a $52.0 million increase in mark-to-market derivative gains.

• Net cash provided by operating activities increased to $421.2 million for the three months ended June 30, 2011, as compared to $393.9 million for the three months ended June 30, 2010. The $27.3 million increase in net cash provided by operating activities was primarily due to an increase in earnings as noted above, partially offset by working capital changes.

• Net debt to book capitalization decreased to 32 percent at June 30, 2011, as compared to 37 percent at December 31, 2010, principally due to the cash proceeds received from the sale of Pioneer Tunisia and the associated gain recorded on the sale.

• Average reported oil, NGL and gas prices increased during the second quarter of 2011 to $104.35 per Bbl, $48.16 per Bbl and $4.31 per Mcf, respectively, as compared to respective prices of $89.21 per Bbl, $34.40 per Bbl and $4.05 per Mcf during the second quarter of 2010.

• During the second quarter of 2011, daily sales volumes increased by 10 percent to 118,585 BOEPD, as compared to 107,834 BOEPD during the second quarter of 2010. The increase in second quarter 2011 sales volumes, as compared to the second quarter of 2010, was primarily due to the Company’s successful drilling program in 2010 and the first half of 2011.

• Average per-BOE oil and gas production costs (including production and ad valorem taxes and transportation costs) increased during the second quarter of 2011 to $12.82, as compared to $12.17 per BOE during the second quarter of 2010, as a result of higher production taxes associated with the increase in commodity prices and cost inflation, primarily associated with oilfield services.

Third Quarter 2011 Outlook

Based on current estimates, the Company expects that third quarter 2011 production will average 125,000 to 131,000 BOEPD. The Company’s South Africa production was shut in during late-July due to unplanned third-party gas-to-liquids plant downtime. The third quarter production guidance does not reflect the potential for this downtime to extend beyond four weeks, which is a possibility.

Third quarter production costs (including production and ad valorem taxes and transportation costs) are expected to average $12.00 to $14.00 per BOE based on current NYMEX strip prices for oil, NGLs and gas. Depletion, depreciation and amortization (“DD&A”) expense is expected to average $13.50 to $15.00 per BOE.

Total exploration and abandonment expense for the quarter is expected to be $25 million to $35 million. General and administrative expense is expected to be $45 million to $50 million. Interest expense is expected to be $44 million to $48 million, and other expense is expected to be $20 million to $30 million. Accretion of discount on asset retirement obligations is expected to be $2 million to $4 million.

Noncontrolling interest in consolidated subsidiaries’ 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 third quarter effective income tax rate is expected to range from 35 percent to 45 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, principally related to South African income taxes.

34

PIONEER NATURAL RESOURCES COMPANY

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, 2011:

	Oil (Bbls)		NGLs (Bbls)		Gas (Mcf)		Total (BOE)
United States:
Permian Basin		23,321		10,748		45,640		41,676
Raton Basin		—		—		161,822		26,970
Mid-Continent		3,948		7,062		52,005		19,677
South Texas		106		—		46,664		7,884
Eagle Ford Shale		2,403		1,497		17,269		6,779
Alaska		4,864		—		—		4,864
Barnett Shale		258		941		7,841		2,506
Other		4		3		54		15
		34,904		20,251		331,295		110,371
South Africa		571		—		23,867		4,549
Total Worldwide		35,475		20,251		355,162		114,920

The Company’s 2011 capital expenditures, including integrated services capital expenditures, but excluding the effects of acquisitions, asset retirement obligations, capitalized interest, geological and geophysical administrative costs and EFS Midstream investments, are expected to be funded by internally-generated operating cash flow and reinvesting a portion of the proceeds from the Pioneer Tunisia sale.

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, 2011:

	Acquisition Costs					Exploration Costs		Development Costs		Asset Retirement Obligations			Total
	Proved		Unproved
	(in thousands)
United States:
Permian Basin	$	4,733	$	5,130		$	34,947	$	490,364	$	1,212		$	536,386
Raton Basin		82		(53	)		3,596		19,689		120			23,434
Mid-Continent		12		107			3,135		6,421		27			9,702
South Texas		—		1,146			6,051		10,080		3			17,280
Eagle Ford Shale		—		18,737			53,040		2,367		6			74,150
Alaska		—		—			5,561		50,731		866			57,158
Barnett Shale		—		14,676			119,726		4,848		147			139,397
Other		—		420			3,570		—		—			3,990
		4,827		40,163			229,626		584,500		2,381			861,497
South Africa		—		—			341		—		(179	)		162
Total Worldwide	$	4,827	$	40,163		$	229,967	$	584,500	$	2,202		$	861,659

The following table summarizes the Company’s development and exploration/extension drilling activities for the six months ended June 30, 2011:

	Development Drilling
	Beginning Wells in Progress		Wells Spud		Successful Wells		Unsuccessful Wells		Ending Wells in Progress
United States		146		336		278		5		199

35

PIONEER NATURAL RESOURCES COMPANY

	Exploration/Extension Drilling
	Beginning Wells in Progress		Wells Spud		Successful Wells		Unsuccessful Wells		Ending Wells in Progress
United States		38		85		64		—		59

Permian Basin area. During the first half of 2011, the Company drilled 278 wells in the Spraberry field, of which 273 were successful. The Company had 35 rigs operating as of June 30, 2011, and plans to increase its rig count to 45 rigs by the end of the year. The Company’s drilling program continues to include the deepening of wells to the Lower Wolfcamp formation, and in certain drilling areas, to the Strawn interval with positive production results. In addition, the Company has recently drilled two successful wells to the Atoka interval and one successful well to the Mississippian interval.

The Company continues to expand its integrated services to control drilling costs and support the execution of its accelerating drilling program. The Company has increased its owned drilling rigs to 14 and has four Company-owned fracture stimulation fleets currently operating in the Spraberry field. One additional fracture stimulation fleet is being built and is expected to be operational during the fourth quarter of 2011. 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 forecasted fracture stimulation sand supply requirements through 2015, tubular and pumping unit requirements through 2012 and well cementing services through 2016.

The Company believes that vertical integration equipment will provide approximately one third of Pioneer’s drilling rig requirements and two thirds of fracture stimulation requirements in the Spraberry field during 2011. The Company’s growing fracture stimulation capacity in the Spraberry field is accelerating the pace at which wells are being placed on production and providing significant savings as compared to similar services provided by third-party contractors.

The Company has completed 85 wells in the Strawn interval since the testing program began in the first quarter of 2010. Initial peak production rates from this interval, when tested alone, have averaged 70 BOEPD. Early results suggest an increase of up to 20 percent in cumulative production over the first 12 months compared to production from offset Lower Wolfcamp wells over the same time period. The incremental cost per well for this deeper drilling and one additional fracture stimulation stage is approximately $60 thousand. The Company believes that the Strawn interval is prospective in 40 percent of its Spraberry acreage and expects to complete this interval in 25 percent of the wells in its 2011 Spraberry drilling program.

The Company has completed two Atoka wells in 2011. The initial peak production rate from this interval, when tested alone, averaged 150 BOEPD. The Company plans to test the Atoka interval for up to six months and then comingle this production with production from upper intervals in the Spraberry and Wolfcamp zones. The incremental cost to drill an Atoka well is estimated to be $250 thousand to $750 thousand, with the higher end of the range reflecting the addition of an intermediate casing string and either a water or carbon dioxide fracture stimulation. The Company plans to drill approximately 10 Atoka wells during 2011 to further evaluate the interval’s development potential. The Company believes that the Atoka interval is prospective in 25 percent to 50 percent of its Spraberry acreage.

The Company has completed its first Mississippian well in 2011. The first vertical test had an initial peak production rate of 105 BOEPD. The Company plans to test the interval for at least six months and then commingle the production with production from upper intervals in the Spraberry and Wolfcamp. The incremental cost per well for this deeper interval and one additional fracture stimulation stage is approximately $150 thousand to $250 thousand. The Company believes the Mississippian interval is prospective in 10 percent to 20 percent of its Spraberry acreage. The Company plans to drill approximately 10 Mississippian wells during 2011.

The Company has also dedicated one drilling rig towards research and development of horizontal drilling applications in multiple intervals of the Spraberry field. The first well to test the Lower Wolfcamp shale interval was a 3,500-foot lateral with a 15-stage fracture stimulation completion. The well had an initial production rate of 200 barrels of oil per day (“BOPD”) and 120 MCFPD with less than 50 percent of the load water recovered.

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PIONEER NATURAL RESOURCES COMPANY

The Company plans to drill six additional horizontal wells during the second half of 2011, targeting the Tippett shale (Middle Wolfcamp) and Jo Mill (Middle Spraberry) intervals. The first Tippett shale well, with a planned lateral section of 6,000 feet and a 30-stage fracture stimulation completion, is currently being drilled.

The Company continues to test downspacing in the Spraberry field from 40 acres to 20 acres. Eighteen 20-acre wells were drilled in 2010, and all of these wells are on production. These 20-acre wells are capturing pay from the Lower Wolfcamp, Strawn and shale/silt intervals, with encouraging results. The Company plans to drill 10 to 20 additional 20-acre downspaced wells in 2011.

South Texas and Eagle Ford Shale area. The Company’s drilling activities in the South Texas area during 2011 continue to be primarily focused on delineation and development of Pioneer’s substantial acreage position in the Eagle Ford Shale play. The Company has increased its drilling rigs in the Eagle Ford Shale play from nine during the second quarter of 2011 to 12 drilling rigs currently, with plans to increase the Eagle Ford Shale rig count to 14 rigs in 2012, 16 rigs in 2013 and 19 rigs in 2014.

The Company has drilled and completed 39 horizontal Eagle Ford Shale wells during the first six months of 2011. On June 30, 2011, 23 Eagle Ford Shale wells were in progress or awaiting completion and hookup. Completion of wells in the first quarter of 2011 had been delayed primarily due to limited third-party fracture stimulation fleet availability.

To improve the execution of its drilling and completions program and reduce costs, the Company has purchased two fracture stimulation fleets for Eagle Ford Shale operations. One fleet was placed in service in April 2011 and the other is expected to be operational during the fourth quarter of 2011. The Company also entered into a two-year contract for a dedicated third-party fracture stimulation fleet, which commenced operating in April 2011. The increases in available fracture stimulation fleets has resulted in a reduction in wells awaiting completion,

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. Construction of the midstream assets is underway, with the majority of the construction expected to be completed by 2013. Five of the 12 planned central gathering plants (“CGPs”) were completed as of June 30, 2011. EFS Midstream plans to build three additional CGPs during the remainder of 2011, including two during the third quarter of 2011. As construction of CGPs is completed, EFS Midstream will provide gathering, treating and transportation services for the Company during a 20-year contractual term. The Company has invested $155.7 million of capital in EFS Midstream, $82.9 million of which was contributed during the six months ended June 30, 2011. During June 2011, EFS Midstream entered into a $300 million, five-year revolving credit facility that will be used to fund infrastructure investments that are in excess of operating cash flow.

Alaska. The Company owns a 70 percent working interest and is the operator of the Oooguruk development project. The Company has drilled 12 production wells and seven injection wells of the estimated 17 production and 16 injection wells planned to fully develop this project. The Company drilled a horizontal exploration well in the Torok formation during 2010 and completed a second Torok well in the first quarter of 2011. Based on the performance to date, the Company plans to drill and fracture stimulate an additional Torok well in early 2012 to further evaluate the productivity of the formation and the feasibility of future development expansion.

Barnett Shale. During the first half of 2011, the Company operated two drilling rigs and drilled and completed 16 Barnett Shale wells. The Company plans to increase its drilling rigs in the Barnett Shale to four rigs during 2012. A Pioneer-owned fracture stimulation fleet commenced operating in the Barnett Shale during the second quarter of 2011. As of June 30, 2011, 27 Barnett Shale wells were in progress. In addition, the Company has acquired 160 square miles of 3-D seismic covering its acreage and expects to increase this coverage by 190 square miles by year end. The Company is utilizing the 3-D seismic to high-grade future drilling location selections.

Results of Operations

Oil and gas revenues. Oil and gas revenues totaled $583.9 million and $1.1 billion for the three and six months ended June 30, 2011, respectively, as compared to $422.0 million and $894.1 million for the same respective periods of 2010.

The increase in oil and gas revenues during the three months ended June 30, 2011, as compared to the same period of 2010, is reflective of increases in worldwide average reported oil, NGL and gas prices and United States oil,

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PIONEER NATURAL RESOURCES COMPANY

NGL and gas sales volumes, partially offset by decreases in average South Africa oil and gas sales volumes. The increase in oil and gas revenues during the six months ended June 30, 2011, as compared to the same period of 2010, is reflective of increases in worldwide average reported oil and NGL prices and United States oil, NGL and gas sales volumes, partially offset by decreases in worldwide average reported gas prices and average South Africa oil and gas sales volumes.

During March 2011, a third-party fractionator for the Company’s Mid-Continent NGL production experienced a longer-than-anticipated turnaround. As a result, the NGL production was inventoried in March and was fractionated and sold during the second quarter of 2011. The impact of the fractionator’s turnaround increased second quarter NGL sales by approximately 1 MBOEPD.

The following table provides average daily sales volumes from continuing operations, by geographic area and in total, for the three and six months ended June 30, 2011 and 2010:

	Three Months Ended June  30,				Six Months Ended June  30,
	2011		2010		2011		2010
Oil (Bbls):
United States		35,872		27,447		34,904		26,630
South Africa		616		641		571		875
Worldwide		36,488		28,088		35,475		27,505
NGLs (Bbls):
United States		21,839		19,291		20,251		19,204
Gas (Mcf):
United States		337,354		333,916		331,295		340,048
South Africa		24,193		28,810		23,867		29,915
Worldwide		361,547		362,726		355,162		369,963
Total (BOE):
United States		113,937		102,391		110,371		102,508
South Africa		4,648		5,443		4,549		5,861
Worldwide		118,585		107,834		114,920		108,369

In the United States, average daily BOE sales volumes increased by 11 percent and eight percent for the three and six months ended June 30, 2011, respectively, as compared to the same respective periods of 2010 due to results from the Company’s successful drilling programs and declines in scheduled VPP deliveries. For the three and six months ended June 30, 2011, average South Africa daily BOE sales volumes decreased by 15 percent and 22 percent, respectively, as compared to the same respective periods of 2010, due to normal well decline rates. See “Third Quarter Outlook” for information about South Africa production curtailment due to unplanned third-party gas-to-liquid plant downtime.

During the three and six months ended June 30, 2011, as compared to the three and six months ended June 30, 2010, oil volumes delivered under the Company’s VPPs decreased by 45 percent for each period. The Company completed its oil delivery obligations under one of the VPP agreements at the end of 2010.

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 commodity 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 cash flow hedging activities and the amortization of deferred VPP revenue.

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PIONEER NATURAL RESOURCES COMPANY

The following table provides 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) by geographic area and in total, for the three and six months ended June 30, 2011 and 2010:

	Three Months Ended June  30,				Six Months Ended June  30,
	2011		2010		2011		2010
Average reported prices:
Oil (per Bbl):
United States	$	104.34	$	89.50	$	100.05	$	90.74
South Africa	$	104.86	$	76.88	$	105.56	$	77.32
Worldwide	$	104.35	$	89.21	$	100.13	$	90.31
NGL (per Bbl):
United States	$	48.16	$	34.40	$	45.42	$	38.07
Gas (per Mcf):
United States	$	4.11	$	3.87	$	4.00	$	4.52
South Africa	$	7.10	$	6.11	$	7.41	$	6.21
Worldwide	$	4.31	$	4.05	$	4.23	$	4.66
Total (per BOE)
United States	$	54.24	$	43.09	$	51.97	$	45.72
South Africa	$	50.88	$	41.39	$	52.13	$	43.25
Worldwide	$	54.11	$	43.01	$	51.97	$	45.58
Average realized prices:
Oil (per Bbl):
United States	$	98.39	$	72.53	$	93.93	$	73.05
South Africa	$	104.86	$	76.88	$	105.56	$	77.32
Worldwide	$	98.50	$	72.63	$	94.12	$	73.18
NGL (per Bbl):
United States	$	48.16	$	33.36	$	45.42	$	37.03
Gas (per Mcf):
United States	$	4.11	$	3.84	$	4.00	$	4.50
South Africa	$	7.10	$	6.11	$	7.41	$	6.21
Worldwide	$	4.31	$	4.02	$	4.23	$	4.63
Total (per BOE)
United States	$	52.37	$	38.25	$	50.03	$	40.83
South Africa	$	50.88	$	41.39	$	52.13	$	43.25
Worldwide	$	52.31	$	38.41	$	50.12	$	40.96

Derivative activities. The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts in order 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. See Note G of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for the scheduled amortization of net deferred gains and losses on discontinued commodity hedges that will be recognized as increases or decreases to future oil revenues.

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PIONEER NATURAL RESOURCES COMPANY

The following table provides the transfers of deferred hedge gains from AOCI-Hedging associated with oil, NGL and gas price cash flow hedges to oil, NGL and gas revenue for the three and six months ended June 30, 2011 and 2010:

	Three Months Ended June  30,				Six Months Ended June  30,
	2011		2010		2011		2010
	(in thousands)
Increase to oil revenue from AOCI-Hedging transfers	$	8,208	$	19,792	$	16,332	$	40,209
Increase to NGL revenue from AOCI-Hedging transfers		—		1,820		—		3,619
Increase to gas revenue from AOCI-Hedging transfers		—		920		—		1,830
Total	$	8,208	$	22,532	$	16,332	$	45,658

Deferred revenue. During the three and six months ended June 30, 2011, the Company’s amortization of deferred VPP revenue increased oil revenues by $11.2 million and $22.3 million, respectively, as compared to an increase of $22.6 million and $45.1 million during the same respective periods of 2010. See Note M of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for specific information regarding the Company’s VPPs.

Interest and other income. Interest and other income for the three and six months ended June 30, 2011 was $18.5 million and $51.1 million, respectively, as compared to $17.0 million and $35.0 million for the same respective periods in 2010. The $1.5 million increase in interest and other income during the three months ended June 30, 2011, as compared to the same period in 2010, was primarily due to a $12.7 million increase in third-party income from vertical integration services and $1.8 million in Eagle Ford Shale land fee receipts, partially offset by a $13.6 million decrease in Alaskan Petroleum Production tax credit recoveries. The $16.1 million increase in interest and other income during the six months ended June 30, 2011, as compared to the same period in 2010, was primarily due to a $15.1 million increase in third-party income from vertical integration services and the aforementioned $1.8 million in Eagle Ford Shale land fees. See Note O 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 losses on the disposition of assets of $296 thousand and $2.5 million during the three and six months ended June 30, 2011, respectively, as compared to net gains on the disposition of assets of $7.6 million and $24.6 million for the three and six months ended June 30, 2010, respectively. The 2011 net losses were primarily associated with sales of excess materials and supplies inventory. During the three and six months ended June 30, 2010, the Company recorded gains associated with the Company’s Eagle Ford Shale joint venture transaction and the sale of proved and unproved oil and gas properties in the Uinta/Piceance area. See Note N of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding the Company’s gains and losses on dispositions of assets.

Oil and gas production costs. The Company recorded oil and gas production costs of $102.5 million and $202.4 million during the three and six months ended June 30, 2011, respectively, as compared to $94.0 million and $180.1 million during the same respective periods of 2010. In general, lease operating expenses and workover expenses 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 gathering and processing of third party gas in Company-owned facilities.

Total oil and gas production costs per BOE from continuing operations for the three months ended June 30, 2011 were consistent with the three months ended June 30, 2010, while they increased by six percent during the six months ended June 30, 2011 compared to the same period in 2010. The increase in United States production costs per BOE during the six months ended June 30, 2011 is primarily due to repairs associated with severe winter weather disruptions encountered during the first quarter of 2011 and inflation in well servicing costs, partially offset by the reduction in VPP delivery commitments.

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PIONEER NATURAL RESOURCES COMPANY

The following tables provide the components of the Company’s oil and gas production costs per BOE from continuing operations and total production costs per BOE from continuing operations by geographic area for the three and six months ended June 30, 2011 and 2010:

	Three Months Ended June  30,					Six Months Ended June  30,
	2011			2010		2011		2010
Lease operating expenses	$	7.70		$	7.76	$	7.76	$	7.47
Third-party transportation charges		1.06			0.84		1.03		0.85
Net natural gas plant/gathering charges (credits)		(0.25	)		0.31		0.06		0.03
Workover costs		0.99			0.67		0.89		0.84
Total production costs	$	9.50		$	9.58	$	9.74	$	9.19
	Three Months Ended June  30,					Six Months Ended June  30,
	2011			2010		2011		2010
United States	$	9.81		$	10.01	$	10.05	$	9.62
South Africa	$	1.69		$	1.81	$	2.20	$	1.58
Worldwide	$	9.50		$	9.58	$	9.74	$	9.19

Production and ad valorem taxes. The Company recorded production and ad valorem taxes of $35.9 million and $69.2 million during the three and six months ended June 30, 2011, respectively, as compared to $25.3 million and $52.4 million for the same respective periods of 2010. 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 and six months ended June 30, 2011, the Company’s production and ad valorem taxes per BOE have, in the aggregate, increased 28 percent and 24 percent, primarily reflecting increasing commodity prices during the relevant periods, partially offset by a decline in per-BOE ad valorem taxes.

The following table provides the Company’s production and ad valorem taxes per BOE from continuing operations for the three and six months ended June 30, 2011 and 2010:

	Three Months Ended June  30,				Six Months Ended June  30,
	2011		2010		2011		2010
Ad valorem taxes	$	1.35	$	1.58	$	1.39	$	1.53
Production taxes		1.97		1.01		1.93		1.14
Total ad valorem and production taxes	$	3.32	$	2.59	$	3.32	$	2.67

Depletion, depreciation and amortization expense. The Company’s total DD&A expense was $153.9 million ($14.26 per BOE) and $294.3 million ($14.15 per BOE) for the three and six months ended June 30, 2011, respectively, as compared to $144.3 million ($14.71 per BOE) and $288.7 million ($14.72 per BOE) during the same respective periods of 2010. The decrease in DD&A expense per BOE during the three and six months ended June 30, 2011, as compared to the same respective periods of 2010, is primarily due to a decrease in depletion expense per BOE on oil and gas properties.

Depletion expense on oil and gas properties was $13.10 per BOE and $13.06 per BOE during the three and six months ended June 30, 2011, respectively, as compared to $13.89 per BOE and $13.95 per BOE during the same respective periods of 2010. The six percent decreases in per-BOE depletion expense during the three and six months ended June 30, 2011 are primarily due to increases in proved reserves as a result of the Company’s successful drilling program and higher first-day-of-the-month commodity prices during the 12-month period ending on June 30, 2011, which had the effect of extending the economic lives of proved properties.

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PIONEER NATURAL RESOURCES COMPANY

The following table provides depletion expense per BOE from continuing operations by geographic area for the three and six months ended June 30, 2011 and 2010:

	Three Months Ended June  30,				Six Months Ended June  30,
	2011		2010		2011		2010
United States	$	12.33	$	12.65	$	12.23	$	12.58
South Africa	$	32.00	$	37.23	$	33.06	$	38.03
Worldwide	$	13.10	$	13.89	$	13.06	$	13.95

Impairment of oil and gas properties. The Company reviews its long-lived assets to be held and used, including oil and gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable from their estimated future cash flows.

The Company’s primary assumptions of the estimated future cash flows attributable to oil and gas properties are based on (i) proved reserves and risk-adjusted probable and possible reserves and (ii) management’s commodity price outlooks, which are based in part on forward market quotes.

Exploration and abandonments expense. The following tables provide the Company’s geological and geophysical costs, exploratory dry holes expense and lease abandonments and other exploration expense by geographic area for the three and six months ended June 30, 2011 and 2010 (in thousands):

	United States			South Africa		Total
Three Months Ended June 30, 2011
Geological and geophysical	$	16,780		$	183	$	16,963
Exploratory dry holes		163			—		163
Leasehold abandonments and other		2,788			—		2,788
	$	19,731		$	183	$	19,914
Three Months Ended June 30, 2010
Geological and geophysical	$	18,051		$	54	$	18,105
Exploratory dry holes		(125	)		—		(125	)
Leasehold abandonments and other		4,763			—		4,763
	$	22,689		$	54	$	22,743
	United States			South Africa		Total
Six Months Ended June 30, 2011
Geological and geophysical	$	32,393		$	341	$	32,734
Exploratory dry holes		808			—		808
Leasehold abandonments and other		4,015			—		4,015
	$	37,216		$	341	$	37,557
Six Months Ended June 30, 2010
Geological and geophysical	$	31,117		$	126	$	31,243
Exploratory dry holes		(234	)		—		(234	)
Leasehold abandonments and other		8,582			—		8,582
	$	39,465		$	126	$	39,591

The Company’s exploration and abandonment expense during the three and six months ended June 30, 2011 is primarily comprised of acquisitions of 3-D seismic, geological and geophysical personnel costs and unproved property abandonments in the United States.

During the six months ended June 30, 2011, the Company drilled and evaluated 64 exploration/extension wells, all of which were successfully completed as discoveries. During the same period in 2010, the Company drilled and evaluated 11 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, 2011 was $44.6 million and $88.8 million, respectively, as compared to $40.4 million and $78.7 million during the same respective periods of 2010. The increase in general and administrative expense for the three and six months ended June 30, 2011, as compared to the same periods of 2010, was primarily due to an increase in compensation expense related to hiring activities since June 30, 2010 in support of the Company’s capital expansion initiatives and vertical integration efforts, partially offset by an increase in producing, drilling, and other overhead recoveries. In support of these strategic growth initiatives, the Company anticipates continued growth in total employees and compensation-related expenses.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations was $2.7 million and $5.3 million for the three and six months ended June 30, 2011, respectively, as compared to $2.5 million and $5.4 million during the same respective periods of 2010. See Note H 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 $45.8 million and $91.0 million for the three and six months ended June 30, 2011, respectively, as compared to $45.4 million and $92.9 million during the same respective periods of 2010. The $1.9 million decrease in interest expense during the six months ended June 30, 2011, as compared to the same period of 2010, is primarily due to a decrease in credit facility borrowings, partially offset by an increase in the weighted average interest rate. The weighted average interest rate on the Company’s indebtedness for both the three and six months ended June 30, 2011, including the effects of capitalized interest, was 7.3 percent, as compared to 7.0 percent and 6.9 percent for the same respective periods of 2010.

Derivative (gains) losses, net. During the three months ended June 30, 2011, the Company recorded $229.5 million of net derivative gains on commodity price and interest rate derivatives. For the three months ended June 30, 2011, $221.2 million represented unrealized gains and $8.3 million represented realized gains. During the six months ended June 30, 2011, the Company recorded $15.0 million of net derivative losses on commodity price and interest rate derivatives. For the six months ended June 30, 2011, $54.6 million represented unrealized losses and $39.6 million represented realized gains. During the three and six months ended June 30, 2010, the Company recorded $177.5 million and $443.0 million of net derivative gains. Derivative gains and losses result from changes in the fair values of the Company’s derivative contracts. See Notes D and G 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.

Hurricane activity, net. Hurricane activity is associated with the Company’s East Cameron platform facility, located on the Gulf of Mexico shelf, which was destroyed during 2005 by Hurricane Rita. Operations to reclaim and abandon the East Cameron 322 facility began in 2006 and are substantially complete.

Other expense. Other expense for the three and six months ended June 30, 2011 was $14.4 million and $32.3 million, respectively, as compared to $14.2 million and $30.1 million for the same respective periods of 2010. The increase in other expense for the three months ended June 30, 2011, as compared to the same period in 2010, is primarily attributable to a $5.7 million increase in unused gas transportation costs, partially offset by a $4.9 million decrease in charges recorded for the difference between Pioneer contracted rig rates and market rig rates that are charged to joint operations. The increase in other expense for the six months ended June 30, 2011, as compared to the same period in 2010, is primarily attributable to a $11.0 million increase in unused gas transportation costs and a $2.4 million charge associated with renewing the Company’s credit facility, partially offset by a $10.0 million decrease in above market drilling rig related costs. See Note P of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information.

Income tax provision. The Company recorded income tax provisions from continuing operations of $144.7 million and $97.5 million during the three and six months ended June 30, 2011, respectively, as compared to $83.2 million and $227.2 million during the same respective periods of 2010. The changes in the income tax provisions for the three and six months ended June 30, 2011, as compared to the same periods of 2010, are primarily due to noncash derivative gains and losses associated with mark-to-market accounting. The Company’s effective tax rate of 37 percent and 35 percent during the three and six months ended June 30, 2011, excluding net income attributable to noncontrolling interests, are consistent with the Company’s combined United States federal and state statutory rate of approximately 37 percent.

See Note E of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding the Company’s income taxes.

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PIONEER NATURAL RESOURCES COMPANY

Income (loss) from discontinued operations, net of tax. The Company reported a loss from discontinued operations, net of tax of $1.6 million and income from discontinued operations, net of tax of $413.1 million for the three and six months ended June 30, 2011, respectively, as compared to income from discontinued operations, net of tax of $41.9 million and $45.7 million for the same respective periods of 2010.

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 $853.7 million, including normal post-closing adjustments, resulting in a pretax gain of $645.3 million. During the three months ended June 30, 2011, post-closing adjustments reduced the net gain on the transaction by $4.6 million.

The loss from discontinued operations for the three months ended June 30, 2011 is primarily comprised of the after tax impact of the aforementioned adjustment to net gain on the sale of Pioneer Tunisia. Discontinued operations for the three and six months ended June 30, 2010 include the historical results of operations of Pioneer Tunisia. See Note Q of the Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for specific information regarding the Company’s discontinued operations.

Net income attributable to noncontrolling interest. Net income attributable to the noncontrolling interests for the three and six months ended June 30, 2011 was $20.1 million and $15.3 million, respectively, as compared to net income attributable to the noncontrolling interests of $21.1 million and $36.5 million for the same respective periods of 2010. The $1.0 million and $21.2 million decreases in net income attributable to noncontrolling interests for the three and six months ended June 30, 2011, as compared to the same respective periods in 2010, are primarily due to fluctuations in Pioneer Southwest’s mark-to-market derivative gains and losses. See Note B of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding Pioneer Southwest and the Company’s noncontrolling interests.

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, including EFS Midstream capital funding commitments, 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 or external financing sources as discussed in “Capital resources” below. The Company expects that it will be able to fund its needs for cash (excluding acquisitions) with internally-generated cash flows, cash on hand and with its liquidity under its credit facility, although no assurances can be given that such funding sources will be adequate to meet the Company’s future needs.

The Company generally strives to limit its capital expenditures to a level that allows the Company to deliver net cash flow from operating activities in excess of capital requirements in order to enhance and preserve financial flexibility. However, during 2011, the Company will redeploy a portion of the proceeds from the sale of Pioneer Tunisia to accelerate drilling in the Eagle Ford Shale, Spraberry and Barnett Shale Combo areas. During 2011, the Company’s capital budget will continue to focus on oil- and liquid-rich-gas drilling activities with total expenditures forecasted to be $2.1 billion (excluding effects of acquisitions, asset retirement obligations, capitalized interest, geological and geophysical administrative costs and EFS Midstream investments), consisting of $1.8 billion for drilling operations and $300 million for vertical integration and facilities. Based on results for the first half of 2011 and the forecasted production volumes and NYMEX commodity prices for the second half of 2011, the Company expects its cash flows from operating activities plus a portion of the proceeds from the sale of Pioneer Tunisia to be sufficient to fund its planned capital expenditures and contractual obligations. During the first six months of 2011, the Company’s costs incurred (excluding effects of acquisitions, asset retirement obligations, capitalized interest, geological and geophysical administrative costs and EFS Midstream investments) were $801.8 million, as compared to $399.0 million during the first six months of 2010. In addition, during the first six months of 2011, the Company paid $215.4 million for additions to other assets and other property and equipment, net, which includes amounts associated with vertical integration and facilities, as compared to $74.1 million during the fisrt six months of 2010.

Investing activities. Investing activities used $241.9 million of cash during the six months ended June 30, 2011, as compared to $238.4 million used during the six months ended June 30, 2010. The $3.5 million increase in net cash used by investing activities for the six months ending June 30, 2011, as compared to the six months ended June 30, 2010, is primarily due to a $516.2 million increase in proceeds from disposition of assets due to the sale of Pioneer Tunisia, substantially offset by a $295.6 million increase in additions to oil and gas properties due to the Company’s increased drilling activities in 2011, a $141.3 million increase in additions to other assets and other property and equipment, primarily comprising purchases of drilling rigs, fracture stimulation equipment and well servicing

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PIONEER NATURAL RESOURCES COMPANY

equipment, and an $82.7 million increase in investments in unconsolidated affiliates. During the six months ended June 30, 2011, the Company’s expenditures for additions to oil and gas properties were funded by net cash provided by operating activities and a portion of the proceeds from the sale of Pioneer Tunisia. During the same period in 2010, the Company’s expenditures for additions to oil and gas properties were funded by net cash provided by operating activities.

Dividends/distributions. During February of both 2011 and 2010, the Company’s board of directors (“the Board”) declared semiannual dividends of $0.04 per common share. Associated therewith, the Company paid $4.8 million of aggregate dividends during each of the six months ended June 30, 2011 and 2010. 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 2011 and April 2011, the Pioneer Southwest board of directors (the “Pioneer Southwest Board”) declared quarterly distributions of $0.50 and $0.51 per limited partner unit, respectively, compared to the $0.50 per limited partner unit quarterly distribution declared in January and April 2010. Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling unitholders of $12.7 million and $12.6 million during the six months ended June 30, 2011 and 2010, respectively. During July 2011, the Pioneer Southwest Board declared a quarterly distribution of $0.51 per limited partner unit for unitholders of record on August 1, 2011, payable August 11, 2011. Future distributions are at the discretion of the Pioneer Southwest Board, and, if declared, the Pioneer Southwest Board may change the current 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, other liabilities, transportation commitments, VPP obligations and EFS Midstream capital funding commitments. Additionally, the Company has entered into a gathering, treating and transportation agreement with EFS Midstream. Under the terms of the agreement, the Company is obligated to deliver production from substantially all of the properties that the Company operates in the Eagle Ford Shale play to EFS Midstream for gathering, treating and transportation services over a 20-year contractual term, contingent upon EFS Midstream constructing the equipment necessary to perform the services. 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, 2011, 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) transportation commitments, (iv) open purchase commitments (v) VPP obligations (to physically deliver volumes and pay related lease operating expenses in the future) and (vi) 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. During June 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. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect the Company’s liquidity or availability of or requirements for capital resources. Since December 31, 2010, the material changes in the Company’s contractual obligations include (i) a $30.7 million decrease in outstanding long-term debt, (ii) a $22.3 million decrease in the Company’s VPP obligations and (iii) a $46.5 million increase in the Company’s derivative liabilities.

In accordance with GAAP, the Company periodically measures and records certain assets and liabilities at fair value. The assets and liabilities that the Company periodically measures and records at fair value include trading securities, deferred compensation plan assets, commodity derivative contracts and interest rate derivative contracts. See Note D of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding these assets and liabilities and the valuation techniques used to measure their fair values.

The Company’s commodity and interest rate derivative contracts that are periodically measured and recorded at fair value represent those derivatives that continue to be subject to market or credit risk. As of June 30, 2011, these contracts represented net assets of $112.4 million. The ultimate liquidation value of the Company’s commodity and interest rate derivatives that are subject to market risk 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, 2011. See Note G 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.

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PIONEER NATURAL RESOURCES COMPANY

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 borrowings under its credit facility, issuances of debt or equity securities or from other sources, such as asset sales.

Operating activities. Net cash provided by operating activities during the six months ended June 30, 2011 was $564.5 million as compared to $693.2 million during the same period of 2010. The decrease in net cash provided by operating activities for the six months ended June 30, 2011, as compared to the six months ended June 30, 2010, is primarily due to the 2010 recovery of $119.3 million of excess royalty payments associated with properties that were sold by the Company during 2006, plus $35.3 million of associated interest, and operating cash flow from Pioneer Tunisia during 2010, partially offset by an increase in oil and NGL production and prices.

Asset divestitures. 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 $853.7 million, including normal post-closing adjustments, resulting in a pretax gain of $645.3 million. The net cash proceeds from the sale of Pioneer Tunisia were determined in accordance with the sale and purchase agreement that the Company entered into with the purchaser, which provided for certain customary adjustments for matters occurring after the effective date of the sale, such as capital contributions and distributions, and working capital adjustments. Adjustments to net cash proceeds involve management’s best estimate about the realizable value of working capital items, including that the amounts are reasonably assured of collection. Differences between actual working capital amounts and management’s estimates recorded as of June 30, 2011, if any, will be recorded as income or loss from discontinued operations in future periods. See Note Q of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for information regarding the Company’s discontinued operations.

During the first six months of 2010, the Company’s asset divestitures included the completion of the Eagle Ford Shale joint venture transactions for net proceeds of $272.0 million, the sale of certain Uinta/Piceance proved and unproved oil and gas properties for $11.8 million of net proceeds and the collection of certain Tunisia past cost receivables. See Note N of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for information regarding the Company’s divestitures.

Financing activities. Net cash used in financing activities during the six months ended June 30, 2011 and 2010 was $81.3 million and $284.5 million, respectively. The $203.2 million decrease in cash used in financing activities during the six months ended June 30, 2011, as compared to the six months ended June 30, 2010, is primarily due to (i) a $197.9 million decline in net payments on long-term debt and (ii) a $23.8 million increase in excess tax benefits from share-based payment arrangements, partially offset by (iii) a $25.8 million increase in treasury shares purchased to satisfy withholding tax payments related to the vesting of employee share-based awards.

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. The Credit Facility replaces the Company’s Amended and Restated 5-Year Revolving Credit Agreement entered into in April 2007 (the “expired Credit Facility”) and provides for aggregate loan commitments of $1.25 billion. See Note F 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 Credit Facility.

The Company’s stock price during March 2011 caused the Company’s 2.875% Convertible Senior Notes to be convertible at the option of the holders during the three months ended June 30, 2011. Associated therewith, holders of 2.875% Convertible Senior Notes tendered $70 thousand principal amount of the notes for conversion during the three months ended June 30, 2011. During July and August 2011, the Company paid the holders a total of $71 thousand of cash and issued 340 shares of the Company’s common stock. During June 2011, 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, 2011. The Company’s 2.875% Convertible Senior Notes may become convertible in future quarters depending on the Company’s stock price performance or under certain other conditions. The Company intends to fund the cash portion of future conversion payments, if any, with cash on hand and borrowings under the Credit Facility. See Note F of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for more information about the Company’s 2.875% Convertible Senior Notes.

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PIONEER NATURAL RESOURCES COMPANY

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, 2011, the Company had no outstanding borrowings under its Credit Facility and was in compliance with all of its debt covenants. After adjusting for $65.1 million of undrawn and outstanding letters of credit under its Credit Facility, the Company had approximately $1.2 billion of unused borrowing capacity as of June 30, 2011. 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 from other sources, such as asset sales. 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 borrowing capacity under the Company’s Credit Facility will be adequate to fund 2011 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. For instance, the amount that the Company may borrow under the Credit Facility in the future could be reduced as a result of lower oil, NGL or gas prices, among other items.

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.

Book capitalization and current ratio. The Company’s net book capitalization at June 30, 2011 was $7 billion, consisting of $352.4 million of cash and cash equivalents, debt of $2.6 billion and stockholders’ equity of $4.8 billion. The Company’s net debt to net book capitalization was 32 percent and 37 percent at June 30, 2011 and December 31, 2010, respectively. The Company’s ratio of current assets to current liabilities was 1.42 to 1.00 at June 30, 2011 as compared to 1.56 to 1.00 at December 31, 2010.

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, 2010. 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, 2010.

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. All of the Company’s market risk sensitive instruments are entered into for purposes other than speculation.

The following table reconciles the changes that occurred in the fair values of the Company’s open derivative contracts during the six months ending 2011:

	Derivative Contract Net Assets
	Commodities			Interest Rates			Total
	(in thousands)
Fair value of contracts outstanding as of December 31, 2010	$	167,567		$	17,552		$	185,119
Changes in contract fair value (a)		(27,377	)		12,423			(14,954	)
Contract maturities		(52,729	)		(5,029	)		(57,758	)
Fair value of contracts outstanding as of June 30, 2011	$	87,461		$	24,946		$	112,407

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

Interest rate sensitivity. See Note F 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, 2011 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, 2011. 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 2, 2011.

	Six Months Ending December 31, 2011			Year Ending December 31,																	Asset (Liability) Fair Value at June 30, 2011
				2012			2013			2014			2015			Thereafter			Total
	($ in thousands)
Total Debt:
Fixed rate principal maturities (a)	$	—		$	—		$	480,000		$	—		$	—		$	2,089,985		$	2,569,985	$	(3,013,767	)
Weighted average interest rate		6.05	%		6.05	%		6.73	%		6.78	%		6.78	%		7.13	%
Variable rate principal maturities:
Pioneer Southwest credit facility	$	—		$	—		$	87,000		$	—		$	—		$	—		$	87,000	$	(84,542	)
Weighted average interest rate		1.34	%		1.48	%		1.71	%		—			—			—
Interest Rate Swaps (b):
Notional debt amount (c)	$	470,000		$	470,000		$	470,000		$	470,000		$	470,000		$	470,000				$	24,946
Fixed rate receivable (%)		2.92	%		2.92	%		2.92	%		2.92	%		2.92	%		3.09	%
Variable rate payable (%)		0.46	%		0.60	%		0.83	%		1.89	%		2.40	%		2.54	%

(a) Represents maturities of principal amounts excluding debt issuance discounts and premiums and net deferred fair value hedge losses. The Company’s $480.0 million of 2.875% Convertible Senior Notes do not qualify for redemption during the third quarter of 2011, as disclosed in Note F of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.”

(b) During July 2011, the Company terminated the $470 million notional amount of fixed-for-variable interest rate derivatives and received $26.1 million of proceeds.

(c) Represents weighted average notional contract amounts of interest rate derivatives.

Commodity derivative instruments and price sensitivity. The following table provides information about the Company’s oil, NGL, gas and diesel derivative financial instruments that were sensitive to changes in oil, NGL, gas and diesel fuel prices as of June 30, 2011. Although mitigated by the Company’s derivative activities, declines in oil, NGL and gas prices would reduce the Company’s revenues and increases in diesel prices would increase the Company’s internally-provided workover, capital and related services costs.

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 G 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, gas or diesel prices.

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PIONEER NATURAL RESOURCES COMPANY

	Six Months Ending December 31, 2011														Asset (Liability) Fair Value at June 30, 2011
				Year Ending December 31,
				2012			2013			2014			2015
															(in thousands)
Oil Derivatives:
Average daily notional Bbl volumes:
Swap contracts		750			3,000			3,000			—			—	$	(44,846	)
Weighted average fixed price per Bbl	$	77.25		$	79.32		$	81.02		$	—		$	—
Collar contracts		2,000			2,000			—			—			—	$	9,184
Weighted average ceiling price per Bbl	$	170.00		$	127.00		$	—		$	—		$	—
Weighted average floor price per Bbl	$	115.00		$	90.00		$	—		$	—		$	—
Collar contracts with short puts (a)		32,000			36,000			21,250			12,000			—	$	(124,152	)
Weighted average ceiling price per Bbl	$	99.33		$	117.99		$	117.38		$	128.16		$	—
Weighted average floor price per Bbl	$	73.75		$	80.42		$	80.18		$	87.92		$	—
Weighted average short put price per Bbl	$	59.31		$	65.00		$	65.18		$	72.92		$	—
Average forward NYMEX oil prices (b)	$	95.57		$	98.79		$	101.12		$	101.68		$	—
NGL Derivatives:
Average daily notional Bbl volumes:
Swap contracts		1,150			750			—			—			—	$	(8,514	)
Weighted average fixed price per Bbl	$	51.50		$	35.03		$	—		$	—		$	—
Collar contracts		2,650			—			—			—			—	$	(4,837	)
Weighted average ceiling price per Bbl	$	64.23		$	—		$	—		$	—		$	—
Weighted average floor price per Bbl	$	53.29		$	—		$	—		$	—		$	—
Average forward NGL prices (c)	$	75.76		$	56.25		$	—		$	—		$	—
Gas Derivatives:
Average daily notional MMBtu volumes:
Swap contracts		117,500			105,000			67,500			50,000			—	$	106,756
Weighted average fixed price per MMBtu	$	6.13		$	5.82		$	6.11		$	6.05		$	—
Collar contracts		—			65,000			150,000			140,000			50,000	$	34,217
Weighted average ceiling price per MMBtu	$	—		$	6.60		$	6.25		$	6.44		$	7.92
Weighted average floor price per MMBtu	$	—		$	5.00		$	5.00		$	5.00		$	5.00
Collar contracts with short puts		200,000			190,000			45,000			50,000			—	$	139,403
Weighted average ceiling price per MMBtu	$	8.55		$	7.96		$	7.49		$	8.08		$	—
Weighted average floor price per MMBtu	$	6.32		$	6.12		$	6.00		$	6.00		$	—
Weighted average short put price per MMBtu	$	4.88		$	4.55		$	4.50		$	4.50		$	—
Average forward NYMEX gas prices (b)	$	4.30		$	4.66		$	5.10		$	5.40		$	5.67
Basis swap contracts		143,500			126,000			52,500			20,000			—	$	(19,846	)
Weighted average fixed price per MMBtu	$	(0.56	)	$	(0.35	)	$	(0.25	)	$	(0.14	)	$	—
Average forward basis differential prices (d)	$	(0.15	)	$	(0.17	)	$	(0.15	)	$	(0.13	)	$	—
Diesel Derivatives:
Average daily notional Bbl volumes:
Swap contracts		250			—			—			—			—	$	96
Weighted average fixed price per Bbl	$	123.90		$	—		$	—		$	—		$	—
Average forward diesel prices (e)	$	131.88		$	—		$	—		$	—		$	—

(a) Subsequent to June 30, 2011, the Company entered into additional collar contracts with short puts for (i) 10,000 Bbls per day of the Company’s 2013 production with a ceiling price of $127.51 per Bbl, a floor price of $90.00 per Bbl and a short put price of $67.00 per Bbl and (ii) 10,000 Bbls per day of the Company’s 2014 production with a ceiling price of $131.68 per Bbl, a floor price of $90.00 per Bbl and a short put price of $67.00 per Bbl.

(b) The average forward NYMEX oil and gas prices are based on August 1, 2011 market quotes.

(c) Forward component NGL prices are derived from active-market NGL component price quotes. The forward prices represent estimates as of August 1, 2011 provided by third parties who actively trade in NGL derivatives.

(d) The average forward basis differential prices are based on July 29, 2011 market quotes for basis differentials between the relevant index prices and NYMEX-quoted forward prices.

(e) The average forward diesel prices are based on July 29, 2011 market quotes.

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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, 2011 that have materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.

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PIONEER NATURAL RESOURCES COMPANY

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

The Company is party to the legal proceeding described in Note J of Notes to Consolidated Financial Statements included in “Part I, Item 1. Financial Statements.” The Company is also party to other proceedings and claims incidental to its business. While many of these other matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to such other 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,” which risks could materially affect the Company’s business, financial condition or future results. Except as set forth below, there has been no material change in the Company’s risk factors from those described in the Annual Report on Form 10-K.

Recently Proposed Rules Regulating Air Emissions from Oil and Gas Operations Could Cause the Company to Incur Increased Capital Expenditures and Operating Costs

On July 28, 2011, the Environmental Protection Agency (“EPA”) proposed rules that would establish new air emission controls for oil and gas production and gas processing operations. Specifically, the EPA’s proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and gas production and processing activities. The EPA’s proposal would require the reduction of VOC emissions from oil and gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and NGLs that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules would establish new leak detection requirements for gas processing plants. The EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them by February 28, 2012. If finalized, these rules could require a number of modifications to the Company’s operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact the Company’s business.

The Company is growing production in areas of high industry activity, which may impact its ability to obtain the personnel, equipment, services, resources and facilities access needed to complete its development activities as planned or result in increased costs.

The Company’s strategy is to expand drilling activity in areas in which industry activity has increased rapidly, particularly in the Spraberry Trend area, the Eagle Ford shale play in South Texas and the Barnett Shale Combo play in North Texas. As a result, demand for personnel, equipment, hydraulic fracturing, water and other services and resources, as well as access to transportation, processing and refining facilities in these areas has increased, as has the costs for those items. A delay or inability to secure the personnel, equipment, services, resources and facilities access necessary for the Company to complete its development activities as planned could result in a rate of oil and gas production below the rate forecasted, and significant increases in costs would impact the Company’s profitability.

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 materially adversely affect the Company’s business, financial condition or future results.

52

PIONEER NATURAL RESOURCES COMPANY

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 during the three months ended June 30, 2011:

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 (b)
April 2011		—		—		—
May 2011		36,347	$	91.83		—
June 2011		—		—		—
Total		36,347	$	91.83		—	$	355,789,018

(a) Consists of shares withheld to satisfy tax withholding on employees’ share-based awards.

(b) During 2007, the Board approved a share repurchase program authorizing the purchase of up to $750 million of the Company’s common stock.

53

PIONEER NATURAL RESOURCES COMPANY

Item 6. Exhibits

Exhibits

Exhibit Number		Description
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.
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.

54

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 5, 2011	By:	/s/ Richard P. Dealy
		Richard P. Dealy
		Executive Vice President and Chief
		Financial Officer
Date: August 5, 2011	By:	/s/ Frank W. Hall
		Frank W. Hall
		Vice President and Chief
		Accounting Officer

55

PIONEER NATURAL RESOURCES COMPANY

Exhibit Index

Exhibit Number		Description
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.
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.

56

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 5, 2011
	/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 5, 2011
	/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, 2011 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 5, 2011

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, 2011 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 5, 2011

XML



Income Taxes (Discontinued Operations) (Details) (USD $) In Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2011		Jun. 30, 2010		Jun. 30, 2011		Jun. 30, 2010
Income Taxes
U.S. state	$ 1,790				$ (3,935)
Foreign	(3,753)		(5,737)		(5,602)		(5,294)
Total current tax (provision) benefit	(1,963)	[1]	(5,737)	[1]	(9,537)	[1]	(5,294)	[1]
U.S. federal	4,832		(12,909)		(222,490)		(12,839)
U.S. state	80				(2,068)
Foreign	4,669		(5,979)		(7,653)		(22,960)
Total deferred tax (provision) benefit	9,581	[1],[2]	(18,888)	[1],[2]	(232,211)	[1],[2]	(35,799)	[1],[2]
Income tax (provision) benefit	$ 7,618		$ (24,625)		$ (241,748)		$ (41,093)

[1] During the three months ended June 30, 2011, the Company's taxes from discontinued operations include (i) a current provision and a deferred benefit amounting to $5.2 million associated with a Tunisian reinvestment reserve adjustment and (ii) a $3.7 million deferred foreign tax credit carryover benefit.

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

XML



Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data	Jun. 30, 2011	Dec. 31, 2010
Consolidated Balance Sheets
Trade, allowance for doubtful accounts	$ 1,056	$ 1,155
Other, allowance for doubtful accounts	$ 358	$ 2,519
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	500,000,000	500,000,000
Common stock, shares issued	127,554,683	126,212,256
Treasury stock, shares	11,311,097	10,903,743

XML



Consolidated Statements Of Operations (USD $) In Thousands, except Per Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Revenues and other income:
Oil and gas	$ 583,931	$ 422,042	$ 1,081,061	$ 894,087
Interest and other	18,454	16,952	51,141	34,960
Gain (loss) on disposition of assets, net	(296)	7,645	(2,487)	24,588
Revenues and other income	602,089	446,639	1,129,715	953,635
Costs and expenses:
Oil and gas production	102,455	94,012	202,386	180,112
Production and ad valorem taxes	35,864	25,338	69,160	52,399
Depletion, depreciation and amortization	153,898	144,309	294,271	288,737
Exploration and abandonments	19,914	22,743	37,557	39,591
General and administrative	44,644	40,433	88,750	78,748
Accretion of discount on asset retirement obligations	2,658	2,529	5,313	5,388
Interest	45,768	45,368	90,995	92,891
Hurricane activity, net	(2)	5,184	69	(2,226)
Derivative (gains) losses, net	(229,478)	(177,528)	14,954	(443,004)
Other	14,388	14,193	32,269	30,139
Costs and expenses, Total	190,109	216,581	835,724	322,775
Income from continuing operations before income taxes	411,980	230,058	293,991	630,860
Income tax provision	(144,696)	(83,220)	(97,545)	(227,227)
Income from continuing operations	267,284	146,838	196,446	403,633
Income (loss) from discontinued operations, net of tax	(1,584)	41,851	413,058	45,662
Net income	265,700	188,689	609,504	449,295
Net income attributable to the noncontrolling interests	(20,123)	(21,113)	(15,333)	(36,465)
Net income attributable to common stockholders	245,577	167,576	594,171	412,830
Basic earnings per share:
Income from continuing operations attributable to common stockholders	$ 2.08	$ 1.07	$ 1.53	$ 3.12
Income (loss) from discontinued operations attributable to common stockholders	$ (0.01)	$ 0.35	$ 3.50	$ 0.39
Net income attributable to common stockholders	$ 2.07	$ 1.42	$ 5.03	$ 3.51
Diluted earnings per share:
Income from continuing operations attributable to common stockholders	$ 2.04	$ 1.06	$ 1.50	$ 3.10
Income (loss) from discontinued operations attributable to common stockholders	$ (0.01)	$ 0.35	$ 3.40	$ 0.39
Net income attributable to common stockholders	$ 2.03	$ 1.41	$ 4.90	$ 3.49
Weighted average shares outstanding:
Basic	116,213	115,104	116,042	114,880
Diluted	118,592	116,006	118,986	115,735
Dividends declared per share			$ 0.04	$ 0.04
Amounts attributable to common stockholders:
Income from continuing operations	247,161	125,725	181,113	367,168
Income (loss) from discontinued operations, net of tax	(1,584)	41,851	413,058	45,662
Net income	$ 245,577	$ 167,576	$ 594,171	$ 412,830

XML



Discontinued Operations (Schedule Of Discontinued Operations) (Details) (USD $)	3 Months Ended				6 Months Ended				1 Months Ended	3 Months Ended
	Jun. 30, 2011		Jun. 30, 2010		Jun. 30, 2011		Jun. 30, 2010		Feb. 28, 2011 Pioneer Tunisia [Member]	Jun. 30, 2011 Pioneer Tunisia [Member]
Oil and gas			$ 40,096,000		$ 22,130,000		$ 75,848,000
Interest and other	18,000		42,619,000		4,586,000		44,414,000
Gain (loss) on disposition of assets, net	(4,574,000)				645,298,000
Total revenues and other income from discontinued operations	(4,556,000)		82,715,000		672,014,000		120,262,000
Oil and gas production			3,278,000		2,126,000		6,894,000
Depletion, depreciation and amortization			6,006,000	[1]			12,346,000	[1]
Exploration and abandonments	1,692,000		4,379,000		4,246,000		8,329,000
General and administrative	2,279,000		1,940,000		8,898,000		4,573,000
Accretion of discount on asset retirement obligations			103,000	[1]	81,000	[1]	204,000	[1]
Other	675,000		533,000		1,857,000		1,161,000
Total costs and expenses from discontinued operations	4,646,000		16,239,000		17,208,000		33,507,000
Income (loss) from discontinued operations before income taxes	(9,202,000)		66,476,000		654,806,000		86,755,000
Current tax provision	(1,963,000)	[2]	(5,737,000)	[2]	(9,537,000)	[2]	(5,294,000)	[2]
Deferred tax (provision) benefit	9,581,000	[1],[2]	(18,888,000)	[1],[2]	(232,211,000)	[1],[2]	(35,799,000)	[1],[2]
Income (loss) from discontinued operations	(1,584,000)		41,851,000		413,058,000		45,662,000
Percentage sale of ownership in subsidiary									100.00%
Cash proceeds from sale of subsidiaries, net									853,700,000
Gain on sale of subsidiaries, pretax									645,300,000
Reduction in net gain										4,600,000
Interest and other	18,454,000		16,952,000		51,141,000		34,960,000
Discontinued operations reinvestment reserve	5,200,000
Foreign tax carryover	3,700,000
Discontinued Operation, Current Foreign Tax Effect of Discontinued Operation	$ 3,753,000		$ 5,737,000		$ 5,602,000		$ 5,294,000

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

[2] During the three months ended June 30, 2011, the Company's taxes from discontinued operations include (i) a current provision and a deferred benefit amounting to $5.2 million associated with a Tunisian reinvestment reserve adjustment and (ii) a $3.7 million deferred foreign tax credit carryover benefit.

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Derivative Financial Instruments (Oil Derivative Contracts Volume And Weighted Average Price) (Details)	3 Months Ended				12 Months Ended
	Dec. 31, 2011 bbl Mmbtu	Sep. 30, 2011 bbl Mmbtu	Jun. 30, 2011 bbl Mmbtu	Mar. 31, 2011 bbl Mmbtu	Dec. 31, 2011 Mmbtu bbl
2011 - Swap Contracts [Member]
Volume	750,000,000,000	750,000,000,000			750,000,000,000
NYMEX price	77.25	77.25			77.25
2011 - Collar Contracts [Member]
Volume	2,000,000,000,000	2,000,000,000,000			2,000,000,000,000
2011 - Collar Contracts [Member] | Ceiling [Member]
NYMEX price	170.00	170.00			170.00
2011 - Collar Contracts [Member] | Floor [Member]
NYMEX price	115.00	115.00			115.00
2011 - Collar Contracts With Short Puts [Member]
Volume	32,000,000,000,000	32,000,000,000,000			32,000,000,000,000
2011 - Collar Contracts With Short Puts [Member] | Ceiling [Member]
NYMEX price	99.33	99.33			99.33
2011 - Collar Contracts With Short Puts [Member] | Floor [Member]
NYMEX price	73.75	73.75			73.75
2011 - Collar Contracts With Short Puts [Member] | Short Put [Member]
NYMEX price	59.31	59.31			59.31
2012 - Swap Contracts [Member]
Volume	3,000,000,000,000	3,000,000,000,000	3,000,000,000,000	3,000,000,000,000	3,000,000,000,000
NYMEX price	79.32	79.32	79.32	79.32	79.32
2012 - Collar Contracts [Member]
Volume	2,000,000,000,000	2,000,000,000,000	2,000,000,000,000	2,000,000,000,000	2,000,000,000,000
2012 - Collar Contracts [Member] | Ceiling [Member]
NYMEX price	127.00	127.00	127.00	127.00	127.00
2012 - Collar Contracts [Member] | Floor [Member]
NYMEX price	90.00	90.00	90.00	90.00	90.00
2012 - Collar Contracts With Short Puts [Member]
Volume	36,000,000,000,000	36,000,000,000,000	36,000,000,000,000	36,000,000,000,000	36,000,000,000,000
2012 - Collar Contracts With Short Puts [Member] | Ceiling [Member]
NYMEX price	117.99	117.99	117.99	117.99	117.99
2012 - Collar Contracts With Short Puts [Member] | Floor [Member]
NYMEX price	80.42	80.42	80.42	80.42	80.42
2012 - Collar Contracts With Short Puts [Member] | Short Put [Member]
NYMEX price	65.00	65.00	65.00	65.00	65.00
2013 - Swap Contracts [Member]
Volume	3,000,000,000,000	3,000,000,000,000	3,000,000,000,000	3,000,000,000,000	3,000,000,000,000
NYMEX price	81.02	81.02	81.02	81.02	81.02
2013 - Collar Contracts With Short Puts [Member]
Volume	21,250,000,000,000	21,250,000,000,000	21,250,000,000,000	21,250,000,000,000	21,250,000,000,000
2013 - Collar Contracts With Short Puts [Member] | Ceiling [Member]
NYMEX price	117.38	117.38	117.38	117.38	117.38
2013 - Collar Contracts With Short Puts [Member] | Floor [Member]
NYMEX price	80.18	80.18	80.18	80.18	80.18
2013 - Collar Contracts With Short Puts [Member] | Short Put [Member]
NYMEX price	65.18	65.18	65.18	65.18	65.18
2014 - Collar Contracts With Short Puts [Member]
Volume	12,000,000,000,000	12,000,000,000,000	12,000,000,000,000	12,000,000,000,000	12,000,000,000,000
2014 - Collar Contracts With Short Puts [Member] | Ceiling [Member]
NYMEX price	128.16	128.16	128.16	128.16	128.16
2014 - Collar Contracts With Short Puts [Member] | Floor [Member]
NYMEX price	87.92	87.92	87.92	87.92	87.92
2014 - Collar Contracts With Short Puts [Member] | Short Put [Member]
NYMEX price	72.92	72.92	72.92	72.92	72.92

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Interest And Other Income

6 Months Ended

Jun. 30, 2011

Interest And Other Income

Interest And Other Income

NOTE O. 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,
	2011		2010		2011		2010
	(in thousands)
Alaskan Petroleum Production Tax credits (a)	$	—	$	13,613	$	27,452	$	27,861
Third-party income from vertical integration services (b)		13,725		998		16,603		1,507
Other income		1,912		1,131		2,913		1,783
Eagle Ford Shale land fees		1,802		—		1,802		—
Deferred compensation plan income		299		174		1,166		684
Equity interest in income of unconsolidated affiliate		502		—		801		—
Interest income		214		92		404		476
Sales and other tax refunds		—		944		—		984
Insurance claim recovery		—		—		—		1,665
Total interest and other income	$	18,454	$	16,952	$	51,141	$	34,960

(a) 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.

(b) Third-party income from vertical integration services primarily represents income associated with Company-provided fracture stimulation, drilling and related services.

XML



Document And Entity Information	6 Months Ended
	Jun. 30, 2011	Aug. 01, 2011
Document And Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2011
Document Fiscal Year Focus	2011
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		116,782,548

XML



Income Taxes (Narrative) (Details) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Valuation allowances	$ 9.9	$ 6.6
Tunisia [Member]
Valuation allowances		$ 26.5

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Subsequent Events

6 Months Ended

Jun. 30, 2011

Subsequent Events

Subsequent Events

NOTE R.    Subsequent Events

The Company has evaluated subsequent events through the date of issuance of its unaudited consolidated financial statements. Except as disclosed in Notes D and G, the Company is not aware of any reportable subsequent events.

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Disclosures About Fair Value Measurements (Fair Values Of The Company's Financial Instruments) (Details) (USD $)	6 Months Ended
	Jun. 30, 2011		Dec. 31, 2010
Liabilities
Proceeds from termination of interest rate derivatives	$ 26,100,000
Interest Rate Derivatives [Member]
Assets
Carrying Value	24,946,000	[1]	18,256,000	[1]
Fair Value	24,946,000	[1]	18,256,000	[1]
Liabilities
Carrying Value			704,000
Fair Value			704,000
Pioneer Southwest Credit Facility [Member]
Liabilities
Carrying Value	87,000,000		81,200,000
Fair Value	84,542,000		77,241,000
Pioneer Credit Facility [Member]
Liabilities
Carrying Value			49,000,000
Fair Value			58,382,000
Trading Securities [Member]
Assets
Carrying Value	30,438,000		467,000
Fair Value	30,438,000		467,000
Commodity Derivatives [Member]
Assets
Carrying Value	271,544,000		304,434,000
Fair Value	271,544,000		304,434,000
Liabilities
Carrying Value	184,083,000		136,867,000
Fair Value	184,083,000		136,867,000
Deferred Compensation Plan Assets [Member]
Assets
Carrying Value	40,223,000		36,162,000
Fair Value	40,223,000		36,162,000
5.875% Senior Notes Due 2016 [Member]
Liabilities
Carrying Value	401,037,000		396,880,000
Fair Value	482,139,000		475,194,000
Senior notes, interest rate	5.875%
Debt instrument expiration date	2016
6.65% Senior Notes Due 2017 [Member]
Liabilities
Carrying Value	484,114,000		484,046,000
Fair Value	529,972,000		516,632,000
Senior notes, interest rate	6.65%
Debt instrument expiration date	2017
6.875% Senior Notes Due 2018 [Member]
Liabilities
Carrying Value	449,209,000		449,192,000
Fair Value	496,698,000		480,969,000
Senior notes, interest rate	6.875%
Debt instrument expiration date	2018
7.50% Senior Notes Due 2020 [Member]
Liabilities
Carrying Value	446,572,000		446,433,000
Fair Value	512,158,000		494,145,000
Senior notes, interest rate	7.50%
Debt instrument expiration date	2020
7.20% Senior Notes Due 2028 [Member]
Liabilities
Carrying Value	249,927,000		249,925,000
Fair Value	250,000,000		259,350,000
Senior notes, interest rate	7.20%
Debt instrument expiration date	2028
2.875% Convertible Senior Notes Due 2038 [Member]
Liabilities
Carrying Value	453,119,000	[2]	444,994,000	[2]
Fair Value	$ 742,800,000	[2]	$ 728,400,000	[2]
Senior notes, interest rate	2.875%
Debt instrument expiration date	2038

[1] Subsequent to June 30, 2011, the Company terminated the interest rate derivatives shown in the table above and received $26.1 million of proceeds. See Note G for additional information about the Company's interest rate derivatives.

[2] The fair value of the 2.875% senior convertible notes includes the fair value of the conversion privilege.

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Disclosures About Fair Value Measurements

6 Months Ended

Jun. 30, 2011

Disclosures About Fair Value Measurements

Disclosures About Fair Value Measurements

NOTE D. Disclosures About Fair Value Measurements

In accordance with GAAP, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. 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. These two types of inputs are further prioritized into the following fair value input hierarchy:

• 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.

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 on a recurring basis as of June 30, 2011, for each of the fair value hierarchy levels:

	Fair Value Measurements at Reporting Date 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, 2011
	(in thousands)
Assets:
Trading securities	$	289	$	30,149	$	—	$	30,438
Commodity derivatives		—		271,544		—		271,544
Interest rate derivatives (a)		—		24,946		—		24,946
Deferred compensation plan assets		40,223		—		—		40,223
Total assets	$	40,512	$	326,639	$	—	$	367,151
Liabilities:
Commodity derivatives	$	—	$	170,732	$	13,351	$	184,083
Pioneer Southwest credit facility		—		84,542		—		84,542
5.875% senior notes due 2016		482,139		—		—		482,139
6.65% senior notes due 2017		529,972		—		—		529,972
6.875% senior notes due 2018		496,698		—		—		496,698
7.50% senior notes due 2020		512,158		—		—		512,158
7.20% senior notes due 2028		250,000		—		—		250,000
2.875% senior convertible notes due 2038 (b)		742,800		—		—		742,800
Total liabilities	$	3,013,767	$	255,274	$	13,351	$	3,282,392

(a) Subsequent to June 30, 2011, the Company terminated the interest rate derivatives shown in the table above and received $26.1 million of proceeds. See Note G for additional information about the Company's interest rate derivatives.

(b) The fair value of the 2.875% senior convertible notes includes the fair value of the conversion privilege.

The following table presents the changes in the fair values of the Company's natural gas liquid ("NGL") derivative liabilities classified as Level 3 in the fair value hierarchy:

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)	Three Months Ended June 30, 2011			Six Months Ended June 30, 2011
	(in thousands)
Beginning liability balance	$	(16,675	)	$	(9,556	)
Total gains and losses:
Net unrealized gains (losses) included in earnings (a)		3,324			(3,795	)
Net realized losses included in earnings (a)		(4,629	)		(7,325	)
Settlement payments		4,629			7,325
Ending liability balance	$	(13,351	)	$	(13,351	)

(a) Non-hedge derivatives gains and losses are included in net derivative (gains) losses in the accompanying consolidated statements of operations.

The following table presents the carrying amounts and fair values of the Company's financial instruments as of June 30, 2011 and December 31, 2010:

	June 30, 2011				December 31, 2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Assets:
Commodity price derivatives	$	271,544	$	271,544	$	304,434	$	304,434
Interest rate derivatives (a)	$	24,946	$	24,946	$	18,256	$	18,256
Trading securities	$	30,438	$	30,438	$	467	$	467
Deferred compensation plan assets	$	40,223	$	40,223	$	36,162	$	36,162
Liabilities:
Commodity price derivatives	$	184,083	$	184,083	$	136,867	$	136,867
Interest rate derivatives	$	—	$	—	$	704	$	704
Pioneer credit facility	$	—	$	—	$	49,000	$	58,382
Pioneer Southwest credit facility	$	87,000	$	84,542	$	81,200	$	77,241
5.875 % senior notes due 2016	$	401,037	$	482,139	$	396,880	$	475,194
6.65 % senior notes due 2017	$	484,114	$	529,972	$	484,046	$	516,632
6.875 % senior notes due 2018	$	449,209	$	496,698	$	449,192	$	480,969
7.50 % senior notes due 2020	$	446,572	$	512,158	$	446,433	$	494,145
7.20 % senior notes due 2028	$	249,927	$	250,000	$	249,925	$	259,350
2.875% senior convertible notes due 2038 (b)	$	453,119	$	742,800	$	444,994	$	728,400

(a) Subsequent to June 30, 2011, the Company terminated the interest rate derivatives shown in the table above and received $26.1 million of proceeds. See Note G for additional information about the Company's interest rate derivatives.

(b) The fair value of the 2.875% senior convertible notes includes the fair value of the conversion privilege.

Trading securities and deferred compensation plan assets. The Company's trading securities represent 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 plus unallocated contributions as of the measurement date. As of June 30, 2011, all significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs except inputs for certain trading securities that are not actively traded on major exchanges, which were corroborated broker quotes representing Level 2 inputs.

Interest rate derivatives. The Company's interest rate derivative assets and liabilities as of June 30, 2011 represent swap contracts for $470 million notional amount of debt, whereby the Company pays a variable LIBOR-based rate and the counterparty pays a fixed rate of interest. The net derivative values attributable to the Company's interest rate derivative contracts as of June 30, 2011 are based on (i) the contracted notional amounts, (ii) LIBOR rate yield curves provided by counterparties and corroborated with forward active market-quoted LIBOR rate yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company's interest rate derivative asset and liability measurements represent Level 2 inputs in the hierarchy priority.

Commodity derivatives. The Company's commodity derivatives represent oil, 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 and diesel swap, collar and three-way collar derivative contract asset and liability measurements represent Level 2 inputs in the hierarchy priority and NGL derivative contract asset and liability measurements represent Level 3 inputs in the hierarchy priority.

Oil derivatives. The Company's oil derivatives are swap, collar and three-way collar contracts for notional barrels ("Bbls") of oil at fixed (in the case of swap contracts) or interval (in the case of collar and three-way collar contracts) New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI") oil prices. The asset and liability values attributable to the Company's oil derivatives were determined based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil, (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. The implied rates of volatility inherent in the Company's collar contracts were determined based on average volatility factors provided by certain independent brokers who are active in buying and selling oil options and were corroborated by market-quoted volatility factors.

NGL derivatives. The Company's NGL derivatives include swap and collar contracts for notional blended Bbls of Mont Belvieu-posted-price NGLs, Conway-posted-price NGLs or NGL component prices per Bbl. The asset and liability values attributable to the Company's NGL derivatives were determined based on (i) the contracted notional volumes, (ii) independent active market-quoted NGL component prices and (iii) the applicable credit-adjusted risk-free rate yield curve. The implied rates of volatility inherent in the Company's collar contracts were determined based on average volatility factors provided by certain independent brokers who are active in buying and selling NGL options and were corroborated by market-quoted volatility factors.

Gas derivatives. The Company's gas derivatives are swap, collar and three-way collar contracts for notional volumes of gas (expressed in millions of British thermal units "MMBtus") contracted at various posted price indexes, including NYMEX Henry Hub ("HH") contracts coupled with basis swap contracts that convert the HH price index point to other price indexes. The asset and liability values attributable to the Company's gas derivative contracts were determined based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent market-quoted forward index prices, (iv) the applicable credit-adjusted risk-free rate yield curve and (v) the implied rate of volatility inherent in the collar and three-way collar contracts. The implied rates of volatility inherent in the Company's collar contracts and three-way collar contracts were determined based on average volatility factors provided by certain independent brokers who are active in buying and selling gas options and were corroborated by market-quoted volatility factors.

Diesel derivatives. The Company's diesel derivatives are comprised of swap contracts for notional Bbls posted as Gulf Coast Ultra Low Sulfur (Pipeline) diesel by a posting service. The asset and liability values attributable to the Company's diesel derivatives were determined based on (i) the contracted notional volumes, (ii) independent active market-quoted diesel prices and (iii) the applicable credit-adjusted risk-free rate yield curve.

Credit facility. The fair value of the Company's credit facility and Pioneer Southwest's credit facility is based on (i) forecasted contractual interest and fee payments, (ii) forward active market-quoted LIBOR rate yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve.

Senior notes. The Company's senior notes represent debt securities that are 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.

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Basis Of Presentation (Policy)

6 Months Ended

Jun. 30, 2011

Basis Of Presentation

Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of June 30, 2011 and for the three and six months ended June 30, 2011 and 2010 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 in connection 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, 2010.

Discontinued Operations

Discontinued operations. During December 2010, the Company committed to a plan to divest 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"). In February 2011, the Company completed the sale of Pioneer Tunisia to an unaffiliated third party. Accordingly, the Company classified the assets and liabilities of Pioneer Tunisia as discontinued operations held for sale in the accompanying balance sheet as of December 31, 2010 and has classified the results of operations of Pioneer Tunisia as discontinued operations, net of tax for the three and six months ended June 30, 2011 and 2010 in the accompanying consolidated statements of operations (representing a recasting of the Pioneer Tunisia results of operations for the three and six months ended June 30, 2010, which were originally classified as continuing operations). See Note Q for more information regarding the sale of Pioneer Tunisia.

During the six months ended June 30, 2011 and 2010, the Bureau of Ocean Energy Management, Regulation, and Enforcement (the "BOEMRE") paid the Company $2.0 million and $35.3 million, respectively, of interest on excess royalty payments associated with properties that were sold by the Company during 2006. Accordingly, the Company has classified the interest income as components of income from discontinued operations, net of tax in the accompanying consolidated statements of operations.

Allowances For Doubtful Accounts

Allowances for doubtful accounts. As of June 30, 2011 and December 31, 2010, the Company's allowances for doubtful accounts totaled $1.4 million and $3.7 million, respectively. Changes in the Company's allowance for doubtful accounts during the three and six months ended June 30, 2011 are summarized in the following table:

	Three Months Ended June 30, 2011			Six Months Ended June 30, 2011
	(in thousands)
Beginning allowance for doubtful accounts balance	$	3,535		$	3,674
Amount recorded in other expense for bad debt recoveries		(1,815	)		(1,797	)
Other net decreases		(306	)		(463	)
Ending allowance for doubtful accounts balance	$	1,414		$	1,414

Inventories

Inventories. Inventories used in continuing operations consisted of $247.9 million and $183.4 million of materials and supplies and $4.1 million and $3.9 million of commodities as of June 30, 2011 and December 31, 2010, respectively. As of June 30, 2011 and December 31, 2010, the Company's materials and supplies inventory was net of $2.5 million and $3.6 million, respectively, of valuation reserve allowances. As of June 30, 2011 and December 31, 2010, the Company estimated that $17.9 million and $13.7 million, respectively, of its materials and supplies inventory would not be utilized or sold within one year. Accordingly, those inventory values have been classified as other noncurrent assets in the accompanying consolidated balance sheets. As of December 31, 2010, the Company also had inventory in Tunisia totaling $13.6 million that is classified as discontinued operations held for sale in the accompanying consolidated balance sheet as of December 31, 2010.

Derivatives And Hedging

Derivatives and hedging. All derivatives are recorded in the accompanying consolidated balance sheets at estimated fair value. See Note D 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 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 – net deferred hedge gains, net of tax ("AOCI – Hedging"), in the stockholders' equity section of the accompanying consolidated balance sheets, and are being transferred to earnings during the same periods in which the hedged transactions are recognized in the Company's earnings. Since February 1, 2009, the Company has recognized 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 Energy Partners L.P.'s ("Pioneer Southwest," a majority-owned and consolidated subsidiary) credit-adjusted risk-free rate curves. The credit-adjusted risk-free rate curves for the Company and the counterparties are 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 250 basis points, representing Pioneer Southwest's estimated borrowing rate.

Goodwill

Goodwill. 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 2010, the Company performed its annual assessment of goodwill impairment and determined that there was no impairment

Noncontrolling Interest In Consolidated Subsidiaries

Noncontrolling interest in consolidated subsidiaries. The Company owns a 0.1 percent general partner interest and a 61.9 percent limited partner interest in Pioneer Southwest. Pioneer Southwest owns interests in certain oil and gas properties in the Spraberry field in the Permian Basin of West Texas. The financial position, results of operations and cash flows of Pioneer Southwest are consolidated with those of the Company.

The Company also owns a majority interest in Sendero Drilling Company, LLC ("Sendero"), which owns and operates land-based drilling rigs in the United States. In addition, the Company owns the majority interests in certain other subsidiaries with operations in the United States.

Noncontrolling interest in the net assets of consolidated subsidiaries totaled $101.0 million and $105.4 million as of June 30, 2011 and December 31, 2010, respectively. The Company recorded net income attributable to the noncontrolling interests of $20.1 million and $15.3 million for the three and six months ended June 30, 2011, respectively (principally related to Pioneer Southwest), compared to net income attributable to the noncontrolling interests of $21.1 million and $36.5 million for the three and six months ended June 30, 2010, respectively.

Investment In Unconsolidated Affiliate

Investment in unconsolidated affiliate. The Company owns a 50.1 percent interest in EFS Midstream LLC ("EFS Midstream"), which owns and operates natural gas and liquids gathering, treating and transportation assets in the Eagle Ford Shale area of South Texas.

The Company accounts for the EFS Midstream investment under the equity method of accounting for investments in unconsolidated affiliates. Under the equity method, the Company's investment in unconsolidated affiliates is increased for investments made and the investor's share of the investee's net income, and decreased for distributions received, the carrying value of investor's interests sold and the investor's share of the investee's net losses. The Company's equity interest in the net income of EFS Midstream is recorded in interest and other income in the Company's accompanying consolidated statements of operations.

Stock-Based Compensation

Stock-based compensation. For stock-based compensation equity awards granted or modified, compensation expense is being recognized in the Company's financial statements on a straight line basis over the awards' vesting periods based on their fair values on the dates of grant. The amount of compensation expense recognized at any date is at least equal to the portion of the measurement date (normally the grant date) value of the award that is vested at that date. The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, (ii) the prior day's closing stock price on the date of grant for the fair value of restricted stock, restricted stock units, partnership unit awards or phantom unit awards that are expected to be settled wholly in the Company's common stock or Pioneer Southwest common units ("Equity Awards"), (iii) the Monte Carlo simulation method for the fair value of performance unit awards and (iv) a probabilistic forecasted fair value method for series B unit awards issued by Sendero.

Stock-based compensation liability awards are awards that are expected to be settled wholly or partially in cash on their vesting dates, rather than in shares or units ("Liability Awards"). Stock-based Liability Awards are recorded as accounts payable – affiliates based on the fair value of the services that have been rendered on the unvested portions of the awards on the balance sheet date. The fair values of Liability Awards are updated at each balance sheet date and changes in the fair values of the unvested portions of the awards for which services have been rendered are recorded as increases or decreases to compensation expense. As of June 30, 2011, accounts payable – due to affiliates includes $3.9 million of liabilities attributable to the Liability Awards.

For the three and six months ended June 30, 2011, the Company recorded $13.8 million and $26.4 million, respectively, of stock-based compensation costs for all plans, as compared to $10.5 million and $20.6 million for the same respective periods of 2010. As of June 30, 2011, there was $93.1 million of unrecognized compensation expense related to unvested share- and unit-based compensation plan awards, including $21.6 million attributable to Liability Awards. This compensation will be recognized over the remaining vesting periods of the awards, which on a weighted average basis is a period of less than three years.

The Company's issued shares, as reflected in the consolidated balance sheets at June 30, 2011 and December 31, 2010, do not include 536,775 and 825,796 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, 2011, 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, 2010		2,559,779			215,134			263,729			507,539			12,212			35,118
Awards granted		427,384			182,982			43,495			86,903			6,812			30,039
Awards vested		(1,015,713	)		(63,556	)		(14,807	)		—			(11,532	)		—
Options exercised		—			—			—			(15,290	)		—			—
Awards forfeited		(37,914	)		(11,931	)		—			—			—			—
Outstanding at June 30, 2011		1,933,536			322,629			292,417			579,152			7,492			65,157

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Exploratory Costs (Capitalized Exploratory Well And Project Activity) (Details) (USD $) In Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2011	Dec. 31, 2010
Beginning capitalized exploratory costs	$ 80,530	$ 96,193
Additions to exploratory costs pending the determination of proved reserves	140,081	214,345
Reclassification due to determination of proved reserves	(135,338)	(195,682)
Disposition of assets sold		(28,938)
Exploratory well costs charged to exploration expense	(162)	(807)
Ending capitalized exploratory costs	85,111	85,111
Suspended well costs recorded	7,982	7,982	25,558
Etzler Gas [Member]
Suspended well costs recorded	$ 8,000	$ 8,000

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Interest And Other Income (Tables)

6 Months Ended

Jun. 30, 2011

Interest And Other Income

Interest And Other Income

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(in thousands)
Alaskan Petroleum Production Tax credits (a)	$	—	$	13,613	$	27,452	$	27,861
Third-party income from vertical integration services (b)		13,725		998		16,603		1,507
Other income		1,912		1,131		2,913		1,783
Eagle Ford Shale land fees		1,802		—		1,802		—
Deferred compensation plan income		299		174		1,166		684
Equity interest in income of unconsolidated affiliate		502		—		801		—
Interest income		214		92		404		476
Sales and other tax refunds		—		944		—		984
Insurance claim recovery		—		—		—		1,665
Total interest and other income	$	18,454	$	16,952	$	51,141	$	34,960

(a) 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.

(b) Third-party income from vertical integration services primarily represents income associated with Company-provided fracture stimulation, drilling and related services.

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Discontinued Operations

6 Months Ended

Jun. 30, 2011

Discontinued Operations

Discontinued Operations

NOTE Q. Discontinued Operations

During December 2010, the Company committed to a plan to sell Pioneer Tunisia and in February 2011 completed the sale of 100 percent of the Company's share holdings in Pioneer Tunisia to an unaffiliated party for net cash proceeds of $853.7 million, including normal post closing adjustments, resulting in a pretax gain of $645.3 million. During the three months ended June 30, 2011, the Company reduced the net gain on the transaction by $4.6 million. The historical results of operations of Pioneer Tunisia have been classified as discontinued operations herein.

During the six months ended June 30, 2011 and 2010, the BOEMRE paid the Company $2.0 million and $35.3 million, respectively, 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. See Note B for additional information about the BOEMRE payments.

The following table represents the components of the Company's discontinued operations for the three and six months ended June 30, 2011 and 2010:

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in thousands)
Revenues and other income:
Oil and gas	$	—		$	40,096		$	22,130		$	75,848
Interest and other		18			42,619			4,586			44,414
Gain (loss) on disposition of assets, net (a)		(4,574	)		—			645,298			—
		(4,556	)		82,715			672,014			120,262
Costs and expenses:
Oil and gas production		—			3,278			2,126			6,894
Depletion, depreciation and amortization (a)		—			6,006			—			12,346
Exploration and abandonments		1,692			4,379			4,246			8,329
General and administrative		2,279			1,940			8,898			4,573
Accretion of discount on asset retirement obligations (a)		—			103			81			204
Other		675			533			1,857			1,161
		4,646			16,239			17,208			33,507
Income (loss) from discontinued operations before income taxes		(9,202	)		66,476			654,806			86,755
Current tax provision (b)		(1,963	)		(5,737	)		(9,537	)		(5,294	)
Deferred tax (provision) benefit (a) (b)		9,581			(18,888	)		(232,211	)		(35,799	)
	$	(1,584	)	$	41,851		$	413,058		$	45,662

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

(b) During the three months ended June 30, 2011, the Company's taxes from discontinued operations include (i) a current provision and a deferred benefit amounting to $5.2 million associated with a Tunisian reinvestment reserve adjustment and (ii) a $3.7 million deferred foreign tax credit carryover benefit.

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Postretirement Benefit Obligations

6 Months Ended

Jun. 30, 2011

Postretirement Benefit Obligations

Postretirement Benefit Obligations

NOTE I. Postretirement Benefit Obligations

As of June 30, 2011 and December 31, 2010, the Company had $7.0 million and $7.4 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 plans of which four relate to predecessor entities that the Company acquired in prior years. These plans had no assets as of June 30, 2011 or December 31, 2010. The participants of the predecessor plans are not current employees of the Company.

The following table reconciles changes in the Company's unfunded accumulated postretirement benefit obligations during the three and six months ended June 30, 2011 and 2010:

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in thousands)
Beginning accumulated postretirement benefit obligations	$	7,231		$	8,951		$	7,408		$	9,075
Net benefit payments		(375	)		(272	)		(691	)		(584	)
Service costs		61			81			122			161
Net actuarial losses		—			100			—			100
Accretion of interest		79			108			157			216
Ending accumulated postretirement benefit obligations	$	6,996		$	8,968		$	6,996		$	8,968

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Consolidated Statements Of Comprehensive Income (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Consolidated Statements Of Comprehensive Income
Net income	$ 265,700	$ 188,689	$ 609,504	$ 449,295
Other comprehensive activity:
Net hedge gains included in continuing operations	(8,139)	(20,697)	(16,195)	(41,623)
Income tax provision	4,138	6,037	4,886	11,072
Other comprehensive activity	(4,001)	(14,660)	(11,309)	(30,551)
Comprehensive income	261,699	174,029	598,195	418,744
Comprehensive income attributable to the noncontrolling interests	(16,698)	(16,740)	(8,522)	(27,758)
Comprehensive income attributable to common stockholders	$ 245,001	$ 157,289	$ 589,673	$ 390,986

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Net Income (Loss) Per Share (Tables)

6 Months Ended

Jun. 30, 2011

Net Income (Loss) Per Share

Reconciliation Of Earnings Attributable To Common Stockholders, Basic And Diluted

	Three Months Ended June 30, 2011									Six Months Ended June 30, 2011
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Income (loss) as reported	$	267,284		$	(1,584	)	$	265,700		$	196,446		$	413,058		$	609,504
Net income attributable to the noncontrolling interests		(20,123	)		—			(20,123	)		(15,333	)		—			(15,333	)
Participating basic earnings		(4,847	)		—			(4,847	)		(3,307	)		(7,542	)		(10,849	)
Basic net income (loss) attributable to common stockholders		242,314			(1,584	)		240,730			177,806			405,516			583,322
Reallocation of participating earnings		164			—			164			82			189			271
Diluted income (loss) attributable to common stockholders	$	242,478		$	(1,584	)	$	240,894		$	177,888		$	405,705		$	583,593
	Three Months Ended June 30, 2010									Six Months Ended June 30, 2010
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Income as reported	$	146,838		$	41,851		$	188,689		$	403,633		$	45,662		$	449,295
Net income attributable to the noncontrolling interests		(21,113	)		—			(21,113	)		(36,465	)		—			(36,465	)
Participating basic earnings		(3,063	)		(1,020	)		(4,083	)		(8,351	)		(1,039	)		(9,390	)
Basic income attributable to common stockholders		122,662			40,831			163,493			358,817			44,623			403,440
Reallocation of participating earnings		84			28			112			98			12			110
Diluted income attributable to common stockholders	$	122,746		$	40,859		$	163,605		$	358,915		$	44,635		$	403,550

Reconciliation Of Basic Weighted Average Common Shares

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

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Long-Term Debt

6 Months Ended

Jun. 30, 2011

Long-Term Debt

Long-Term Debt

NOTE F.    Long-term Debt

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. The Credit Facility replaces the Company's Amended and Restated 5-Year Revolving Credit Agreement entered into in April 2007 (the "Expired Credit Facility") and provides for aggregate loan commitments of $1.25 billion. As of June 30, 2011, the Company had no outstanding borrowings under the Credit Facility and $65.1 million of undrawn letters of credit, all of which were commitments under the Credit Facility, leaving the Company with $1.2 billion of unused borrowing capacity under the Credit Facility.

Borrowings under the Credit Facility may be in the form of revolving loans or swing line loans. Aggregate outstanding swing line loans may not exceed $150 million. Revolving loans under the Credit Facility bear interest, at the option of the Company, based on (a) a rate per annum equal to the higher of the prime rate announced from time to time by Wells Fargo Bank, National Association or the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System during the last preceding business day plus 0.5 percent plus a defined alternate base rate spread margin ("ABR Margin"), which is currently one percent based on the Company's debt rating or (b) a base Eurodollar rate, substantially equal to LIBOR, plus a margin (the "Applicable Margin"), which is currently two percent and is also determined by the Company's debt rating. Swing line loans under the Credit Facility bear interest at a rate per annum equal to the "ASK" rate for Federal funds periodically published by the Dow Jones Market Service plus the Applicable Margin. Letters of credit outstanding under the Credit Facility are subject to a per annum fee, representing the Applicable Margin plus 0.125 percent. The Company also pays commitment fees on undrawn amounts under the Credit Facility that are determined by the Company's debt rating (currently 0.375 percent). The Credit Facility contains certain financial covenants, which include the maintenance of a ratio of total debt to book capitalization less intangible assets, accumulated other comprehensive income and certain noncash asset impairments not to exceed .60 to 1.0. The covenants also include the maintenance of a ratio of the net present value of the Company's oil and gas properties to total debt of at least1.75 to 1.0 until the Company achieves an investment grade rating by Moody's Investors Service, Inc. or Standard & Poors Ratings Group, Inc.

As of June 30, 2011, the Company and Pioneer Southwest were in compliance with all of their debt covenants.

In accordance with GAAP, the Company accounted for the entry into the Credit Facility as an extinguishment of the Expired Credit Facility. Associated therewith, the Company recorded a $2.4 million loss on extinguishment of debt to write off the unamortized issuance costs of the Company's Expired Credit Facility, which is included in other expense in the accompanying consolidated statement of operations for the six months ended June 30, 2011 (see Note P).

Convertible senior notes. As of June 30, 2011 and December 31, 2010, the Company had $480 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 pursuant to a formula.

The Company's stock price during March 2011 caused the Company's 2.875% Convertible Senior Notes to become convertible at the option of the holders during the three months ended June 30, 2011. Associated therewith, 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 July and August 2011, the Company paid the holders a total of $71 thousand of cash and issued 340 shares of the Company's common stock.

During June 2011, 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, 2011. The Company's 2.875% Convertible Senior Notes may become convertible in future quarters depending on the Company's stock price performance or under certain other conditions. If all of the 2.875% Convertible Senior Notes had been converted on June 30, 2011, 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 calculated over the last 20 trading days of June and valued at $158.8 million.

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Net Income (Loss) Per Share

6 Months Ended

Jun. 30, 2011

Net Income (Loss) Per Share

Net Income (Loss) Per Share

NOTE K. Net Income (Loss) Per Share

In accordance with GAAP, 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 from continuing operations, income (loss) from discontinued operations and net income attributable to common stockholders to the basic and diluted earnings used in the two-class method to determine the Company's net income per share amounts for the three and six months ended June 30, 2011 and 2010:

	Three Months Ended June 30, 2011									Six Months Ended June 30, 2011
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Income (loss) as reported	$	267,284		$	(1,584	)	$	265,700		$	196,446		$	413,058		$	609,504
Net income attributable to the noncontrolling interests		(20,123	)		—			(20,123	)		(15,333	)		—			(15,333	)
Participating basic earnings		(4,847	)		—			(4,847	)		(3,307	)		(7,542	)		(10,849	)
Basic net income (loss) attributable to common stockholders		242,314			(1,584	)		240,730			177,806			405,516			583,322
Reallocation of participating earnings		164			—			164			82			189			271
Diluted income (loss) attributable to common stockholders	$	242,478		$	(1,584	)	$	240,894		$	177,888		$	405,705		$	583,593
	Three Months Ended June 30, 2010									Six Months Ended June 30, 2010
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Income as reported	$	146,838		$	41,851		$	188,689		$	403,633		$	45,662		$	449,295
Net income attributable to the noncontrolling interests		(21,113	)		—			(21,113	)		(36,465	)		—			(36,465	)
Participating basic earnings		(3,063	)		(1,020	)		(4,083	)		(8,351	)		(1,039	)		(9,390	)
Basic income attributable to common stockholders		122,662			40,831			163,493			358,817			44,623			403,440
Reallocation of participating earnings		84			28			112			98			12			110
Diluted income attributable to common stockholders	$	122,746		$	40,859		$	163,605		$	358,915		$	44,635		$	403,550

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

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

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Derivative Financial Instruments

6 Months Ended

Jun. 30, 2011

Derivative Financial Instruments

Derivative Financial Instruments

NOTE G. Derivative Financial Instruments

The Company utilizes commodity derivative contracts 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 prices. All material physical sales contracts governing the Company's oil production are tied directly or indirectly to NYMEX WTI oil prices. The following table sets forth the volumes in Bbls outstanding as of June 30, 2011 under the Company's oil derivative contracts and the weighted average oil prices per Bbl for those contracts:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Outstanding Average
Average daily oil production associated with derivatives (Bbls):
2011 – Swap contracts
Volume						750		750		750
NYMEX price					$	77.25	$	77.25	$	77.25
2011 – Collar contracts
Volume						2,000		2,000		2,000
NYMEX price:
Ceiling					$	170.00	$	170.00	$	170.00
Floor					$	115.00	$	115.00	$	115.00
2011 – Collar contracts with short puts
Volume						32,000		32,000		32,000
NYMEX price:
Ceiling					$	99.33	$	99.33	$	99.33
Floor					$	73.75	$	73.75	$	73.75
Short put					$	59.31	$	59.31	$	59.31
2012 – Swap contracts
Volume		3,000		3,000		3,000		3,000		3,000
NYMEX price	$	79.32	$	79.32	$	79.32	$	79.32	$	79.32
2012 – Collar contracts
Volume		2,000		2,000		2,000		2,000		2,000
NYMEX price:
Ceiling	$	127.00	$	127.00	$	127.00	$	127.00	$	127.00
Floor	$	90.00	$	90.00	$	90.00	$	90.00	$	90.00
2012 – Collar contracts with short puts
Volume		36,000		36,000		36,000		36,000		36,000
NYMEX price:
Ceiling	$	117.99	$	117.99	$	117.99	$	117.99	$	117.99
Floor	$	80.42	$	80.42	$	80.42	$	80.42	$	80.42
Short put	$	65.00	$	65.00	$	65.00	$	65.00	$	65.00
2013 – Swap contracts
Volume		3,000		3,000		3,000		3,000		3,000
NYMEX price	$	81.02	$	81.02	$	81.02	$	81.02	$	81.02
2013 – Collar contracts with short puts (a)
Volume		21,250		21,250		21,250		21,250		21,250
NYMEX price:
Ceiling	$	117.38	$	117.38	$	117.38	$	117.38	$	117.38
Floor	$	80.18	$	80.18	$	80.18	$	80.18	$	80.18
Short put	$	65.18	$	65.18	$	65.18	$	65.18	$	65.18
2014 – Collar contracts with short puts (a)
Volume		12,000		12,000		12,000		12,000		12,000
NYMEX price:
Ceiling	$	128.16	$	128.16	$	128.16	$	128.16	$	128.16
Floor	$	87.92	$	87.92	$	87.92	$	87.92	$	87.92
Short put	$	72.92	$	72.92	$	72.92	$	72.92	$	72.92

(a) Subsequent to June 30, 2011, the Company entered into additional collar contracts with short puts for (i) 10,000 Bbls per day of the Company's 2013 production with a ceiling price of $127.51 per Bbl, a floor price of $90.00 per Bbl and a short put price of $67.00 per Bbl and (ii) 10,000 Bbls per day of the Company's 2014 production with a ceiling price of $131.68 per Bbl, a floor price of $90.00 per Bbl and a short put price of $67.00 per Bbl.

Natural gas liquids prices. 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. The following table sets forth the volumes in Bbls outstanding as of June 30, 2011 under the Company's NGL derivative contracts and the weighted average NGL prices per Bbl for those contracts:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Outstanding Average
Average daily NGL production associated with derivatives (Bbls):
2011 – Swap contracts
Volume						1,150		1,150		1,150
Blended index price					$	51.50	$	51.50	$	51.50
2011 – Collar contracts
Volume						2,650		2,650		2,650
Index price:
Ceiling					$	64.23	$	64.23	$	64.23
Floor					$	53.29	$	53.29	$	53.29
2012 – Swap contracts
Volume		750		750		750		750		750
Index price	$	35.03	$	35.03	$	35.03	$	35.03	$	35.03

Gas prices. 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 HH prices and actual index prices at which the gas is sold. The following table sets forth the volumes in MMBtus outstanding as of June 30, 2011 under the Company's gas derivative contracts and the weighted average gas prices per MMBtu for those contracts:

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Outstanding Average
Average daily gas production associated with derivatives (MMBtus):
2011 – Swap contracts
Volume								117,500			117,500			117,500
NYMEX price							$	6.13		$	6.13		$	6.13
2011 – Collar contracts with short puts
Volume								200,000			200,000			200,000
NYMEX price:
Ceiling							$	8.55		$	8.55		$	8.55
Floor							$	6.32		$	6.32		$	6.32
Short put							$	4.88		$	4.88		$	4.88
2011 – Basis swap contracts
Volume								143,500			143,500			143,500
Price differential							$	(0.56	)	$	(0.56	)	$	(0.56	)
2012 – Swap contracts
Volume		105,000			105,000			105,000			105,000			105,000
NYMEX price	$	5.82		$	5.82		$	5.82		$	5.82		$	5.82
2012 – Collar contracts
Volume		65,000			65,000			65,000			65,000			65,000
NYMEX price:
Ceiling	$	6.60		$	6.60		$	6.60		$	6.60		$	6.60
Floor	$	5.00		$	5.00		$	5.00		$	5.00		$	5.00
2012 – Collar contracts with short puts
Volume		190,000			190,000			190,000			190,000			190,000
NYMEX price:
Ceiling	$	7.96		$	7.96		$	7.96		$	7.96		$	7.96
Floor	$	6.12		$	6.12		$	6.12		$	6.12		$	6.12
Short put	$	4.55		$	4.55		$	4.55		$	4.55		$	4.55
2012 – Basis swap contracts
Volume		126,000			126,000			126,000			126,000			126,000
Price differential	$	(0.35	)	$	(0.35	)	$	(0.35	)	$	(0.35	)	$	(0.35	)
2013 – Swap contracts
Volume		67,500			67,500			67,500			67,500			67,500
NYMEX price	$	6.11		$	6.11		$	6.11		$	6.11		$	6.11
2013 – Collar contracts
Volume		150,000			150,000			150,000			150,000			150,000
NYMEX price:
Ceiling	$	6.25		$	6.25		$	6.25		$	6.25		$	6.25
Floor	$	5.00		$	5.00		$	5.00		$	5.00		$	5.00
2013 – Collar contracts with short puts
Volume		45,000			45,000			45,000			45,000			45,000
NYMEX price:
Ceiling	$	7.49		$	7.49		$	7.49		$	7.49		$	7.49
Floor	$	6.00		$	6.00		$	6.00		$	6.00		$	6.00
Short put	$	4.50		$	4.50		$	4.50		$	4.50		$	4.50
2013 – Basis swap contracts
Volume		52,500			52,500			52,500			52,500			52,500
Price differential	$	(0.25	)	$	(0.25	)	$	(0.25	)	$	(0.25	)	$	(0.25	)
2014 – Swap contracts
Volume		50,000			50,000			50,000			50,000			50,000
NYMEX price	$	6.05		$	6.05		$	6.05		$	6.05		$	6.05
2014 – Collar contracts
Volume		140,000			140,000			140,000			140,000			140,000
NYMEX price:
Ceiling	$	6.44		$	6.44		$	6.44		$	6.44		$	6.44
Floor	$	5.00		$	5.00		$	5.00		$	5.00		$	5.00
2014 – Collar contracts with short puts
Volume		50,000			50,000			50,000			50,000			50,000
NYMEX price:
Ceiling	$	8.08		$	8.08		$	8.08		$	8.08		$	8.08
Floor	$	6.00		$	6.00		$	6.00		$	6.00		$	6.00
Short put	$	4.50		$	4.50		$	4.50		$	4.50		$	4.50
2014 – Basis swap contracts
Volume		20,000			20,000			20,000			20,000			20,000
Price differential	$	(0.14	)	$	(0.14	)	$	(0.14	)	$	(0.14	)	$	(0.14	)
2015 – Collar contracts
Volume		50,000			50,000			50,000			50,000			50,000
NYMEX price:
Ceiling	$	7.92		$	7.92		$	7.92		$	7.92		$	7.92
Floor	$	5.00		$	5.00		$	5.00		$	5.00		$	5.00

Diesel prices. During the second quarter of 2011, the Company purchased diesel derivative swap contracts for 250 notional Bbls per day, for the period from July 2011 through December 2011, at an average per Bbl fixed price of $123.90. The diesel derivative swap contracts are priced at an index that is highly correlated to the prices that the Company incurs to fuel its drilling rigs and fracture stimulation fleet equipment. The Company purchases diesel derivative swap contracts to mitigate fuel price risk.

Interest rates. The following table sets forth as of June 30, 2011 the notional amount of the Company's debt under outstanding fixed-for-variable interest rate swap contracts, the weighted average fixed annual interest rate and termination date for those contracts:

Type	Notional Amount		Weighted Average Fixed Interest Rate		Termination Date
	(in thousands)
Fixed-for-variable	$	400,000		2.87 percent		July 2016
Fixed-for-variable	$	70,000		3.23 percent		March 2017

During July 2011, the Company terminated the $470 million notional amount of fixed-for-variable interest rate derivative contracts and received $26.1 million of proceeds.

Tabular disclosure of derivative financial instruments. All of the Company's derivatives are accounted for as non-hedge derivatives as of June 30, 2011 and December 31, 2010. The following tables provide disclosure of the Company's derivative instruments:

Fair Value of Derivative Instruments as of June 30, 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	$	153,812	Derivatives - current	$	87,944
Interest rate derivatives	Derivatives - current		12,253	Derivatives - current		—
Commodity price derivatives	Derivatives - noncurrent		135,927	Derivatives - noncurrent		114,334
Interest rate derivatives	Derivatives - noncurrent		17,870	Derivatives - noncurrent		5,177
		$	319,862		$	207,455
Fair Value of Derivative Instruments as of December 31, 2010
	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	$	167,406	Derivatives - current	$	87,741
Interest rate derivatives	Derivatives - current		11,903	Derivatives - current		886
Commodity price derivatives	Derivatives - noncurrent		152,731	Derivatives - noncurrent		64,829
Interest rate derivatives	Derivatives - noncurrent		15,762	Derivatives - noncurrent		9,227
Total derivatives		$	347,802		$	162,683

(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 Relationships	Location of Gain/(Loss) Reclassified from AOCI into Earnings	Amount of Gain/(Loss) Reclassified from AOCI into Earnings
		Three Months Ended June 30,						Six Months Ended June 30,
		2011			2010			2011			2010
		in thousands
Interest rate derivatives	Interest expense	$	(69	)	$	(312	)	$	(137	)	$	(1,370	)
Interest rate derivatives	Derivative gains (losses), net		—			(1,523	)		—			(2,665	)
Commodity price derivatives	Oil and gas revenue		8,208			22,532			16,332			45,658
Total		$	8,139		$	20,697		$	16,195		$	41,623
Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Earnings on Derivatives	Amount of Gain (Loss) Recognized in Earnings on Derivatives
		Three Months Ended June 30,						Six Months Ended June 30,
		2011			2010			2011			2010
		(in thousands)
Interest rate derivatives	Derivative gains (losses), net	$	14,575		$	26,517		$	12,423		$	37,916
Commodity price derivatives	Derivative gains (losses), net		214,903			152,534			(27,377	)		407,753
Total		$	229,478		$	179,051		$	(14,954	)	$	445,669

AOCI – Hedging. As of June 30, 2011 and December 31, 2010, AOCI – Hedging represented net deferred gains of $2.9 million and $7.4 million, respectively. The AOCI – Hedging balance as of June 30, 2011 was comprised of $13.4 million of net deferred gains on the effective portions of discontinued commodity hedges, $1.8 million of net deferred losses on the effective portions of discontinued interest rate hedges and $1.8 million of associated net deferred tax provisions, reduced by $6.9 million of AOCI – Hedging net deferred gains attributable to and classified as noncontrolling interests in consolidated subsidiaries.

During the twelve months ending June 30, 2012, the Company expects to reclassify $15.0 million of AOCI – Hedging net deferred gains to oil revenues (including $7.0 million related to noncontrolling interests) and $299 thousand of AOCI – Hedging net deferred losses to interest expense. The Company also expects to reclassify $2.8 million of net deferred income tax provisions associated with hedge derivatives during the twelve months ending June 30, 2012 from AOCI – Hedging to income tax expense. For the remaining six months of 2011, the Company expects to reclassify deferred gains on discontinued commodity hedges of $16.6 million to oil revenues. During 2012, the Company expects to reclassify deferred losses on commodity hedges of $3.2 million to oil revenues. The aforementioned $1.8 million of net deferred hedge losses on the effective portion of interest rate hedges will be transferred from AOCI-Hedging to interest expense ratably through April 2018.

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Derivative Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2011

Derivative Financial Instruments

Oil Derivative Contracts Volume And Weighted Average Price

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Outstanding Average
Average daily oil production associated with derivatives (Bbls):
2011 – Swap contracts
Volume						750		750		750
NYMEX price					$	77.25	$	77.25	$	77.25
2011 – Collar contracts
Volume						2,000		2,000		2,000
NYMEX price:
Ceiling					$	170.00	$	170.00	$	170.00
Floor					$	115.00	$	115.00	$	115.00
2011 – Collar contracts with short puts
Volume						32,000		32,000		32,000
NYMEX price:
Ceiling					$	99.33	$	99.33	$	99.33
Floor					$	73.75	$	73.75	$	73.75
Short put					$	59.31	$	59.31	$	59.31
2012 – Swap contracts
Volume		3,000		3,000		3,000		3,000		3,000
NYMEX price	$	79.32	$	79.32	$	79.32	$	79.32	$	79.32
2012 – Collar contracts
Volume		2,000		2,000		2,000		2,000		2,000
NYMEX price:
Ceiling	$	127.00	$	127.00	$	127.00	$	127.00	$	127.00
Floor	$	90.00	$	90.00	$	90.00	$	90.00	$	90.00
2012 – Collar contracts with short puts
Volume		36,000		36,000		36,000		36,000		36,000
NYMEX price:
Ceiling	$	117.99	$	117.99	$	117.99	$	117.99	$	117.99
Floor	$	80.42	$	80.42	$	80.42	$	80.42	$	80.42
Short put	$	65.00	$	65.00	$	65.00	$	65.00	$	65.00
2013 – Swap contracts
Volume		3,000		3,000		3,000		3,000		3,000
NYMEX price	$	81.02	$	81.02	$	81.02	$	81.02	$	81.02
2013 – Collar contracts with short puts (a)
Volume		21,250		21,250		21,250		21,250		21,250
NYMEX price:
Ceiling	$	117.38	$	117.38	$	117.38	$	117.38	$	117.38
Floor	$	80.18	$	80.18	$	80.18	$	80.18	$	80.18
Short put	$	65.18	$	65.18	$	65.18	$	65.18	$	65.18
2014 – Collar contracts with short puts (a)
Volume		12,000		12,000		12,000		12,000		12,000
NYMEX price:
Ceiling	$	128.16	$	128.16	$	128.16	$	128.16	$	128.16
Floor	$	87.92	$	87.92	$	87.92	$	87.92	$	87.92
Short put	$	72.92	$	72.92	$	72.92	$	72.92	$	72.92

Natural Gas Liquids Volume And Weighted Average Price

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Outstanding Average
Average daily NGL production associated with derivatives (Bbls):
2011 – Swap contracts
Volume						1,150		1,150		1,150
Blended index price					$	51.50	$	51.50	$	51.50
2011 – Collar contracts
Volume						2,650		2,650		2,650
Index price:
Ceiling					$	64.23	$	64.23	$	64.23
Floor					$	53.29	$	53.29	$	53.29
2012 – Swap contracts
Volume		750		750		750		750		750
Index price	$	35.03	$	35.03	$	35.03	$	35.03	$	35.03

Gas Volume And Weighted Average Price

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Outstanding Average
Average daily gas production associated with derivatives (MMBtus):
2011 – Swap contracts
Volume								117,500			117,500			117,500
NYMEX price							$	6.13		$	6.13		$	6.13
2011 – Collar contracts with short puts
Volume								200,000			200,000			200,000
NYMEX price:
Ceiling							$	8.55		$	8.55		$	8.55
Floor							$	6.32		$	6.32		$	6.32
Short put							$	4.88		$	4.88		$	4.88
2011 – Basis swap contracts
Volume								143,500			143,500			143,500
Price differential							$	(0.56	)	$	(0.56	)	$	(0.56	)
2012 – Swap contracts
Volume		105,000			105,000			105,000			105,000			105,000
NYMEX price	$	5.82		$	5.82		$	5.82		$	5.82		$	5.82
2012 – Collar contracts
Volume		65,000			65,000			65,000			65,000			65,000
NYMEX price:
Ceiling	$	6.60		$	6.60		$	6.60		$	6.60		$	6.60
Floor	$	5.00		$	5.00		$	5.00		$	5.00		$	5.00
2012 – Collar contracts with short puts
Volume		190,000			190,000			190,000			190,000			190,000
NYMEX price:
Ceiling	$	7.96		$	7.96		$	7.96		$	7.96		$	7.96
Floor	$	6.12		$	6.12		$	6.12		$	6.12		$	6.12
Short put	$	4.55		$	4.55		$	4.55		$	4.55		$	4.55
2012 – Basis swap contracts
Volume		126,000			126,000			126,000			126,000			126,000
Price differential	$	(0.35	)	$	(0.35	)	$	(0.35	)	$	(0.35	)	$	(0.35	)
2013 – Swap contracts
Volume		67,500			67,500			67,500			67,500			67,500
NYMEX price	$	6.11		$	6.11		$	6.11		$	6.11		$	6.11
2013 – Collar contracts
Volume		150,000			150,000			150,000			150,000			150,000
NYMEX price:
Ceiling	$	6.25		$	6.25		$	6.25		$	6.25		$	6.25
Floor	$	5.00		$	5.00		$	5.00		$	5.00		$	5.00
2013 – Collar contracts with short puts
Volume		45,000			45,000			45,000			45,000			45,000
NYMEX price:
Ceiling	$	7.49		$	7.49		$	7.49		$	7.49		$	7.49
Floor	$	6.00		$	6.00		$	6.00		$	6.00		$	6.00
Short put	$	4.50		$	4.50		$	4.50		$	4.50		$	4.50
2013 – Basis swap contracts
Volume		52,500			52,500			52,500			52,500			52,500
Price differential	$	(0.25	)	$	(0.25	)	$	(0.25	)	$	(0.25	)	$	(0.25	)
2014 – Swap contracts
Volume		50,000			50,000			50,000			50,000			50,000
NYMEX price	$	6.05		$	6.05		$	6.05		$	6.05		$	6.05
2014 – Collar contracts
Volume		140,000			140,000			140,000			140,000			140,000
NYMEX price:
Ceiling	$	6.44		$	6.44		$	6.44		$	6.44		$	6.44
Floor	$	5.00		$	5.00		$	5.00		$	5.00		$	5.00
2014 – Collar contracts with short puts
Volume		50,000			50,000			50,000			50,000			50,000
NYMEX price:
Ceiling	$	8.08		$	8.08		$	8.08		$	8.08		$	8.08
Floor	$	6.00		$	6.00		$	6.00		$	6.00		$	6.00
Short put	$	4.50		$	4.50		$	4.50		$	4.50		$	4.50
2014 – Basis swap contracts
Volume		20,000			20,000			20,000			20,000			20,000
Price differential	$	(0.14	)	$	(0.14	)	$	(0.14	)	$	(0.14	)	$	(0.14	)
2015 – Collar contracts
Volume		50,000			50,000			50,000			50,000			50,000
NYMEX price:
Ceiling	$	7.92		$	7.92		$	7.92		$	7.92		$	7.92
Floor	$	5.00		$	5.00		$	5.00		$	5.00		$	5.00

Fixed-For-Variable Interest Rates

Type	Notional Amount		Weighted Average Fixed Interest Rate		Termination Date
	(in thousands)
Fixed-for-variable	$	400,000		2.87 percent		July 2016
Fixed-for-variable	$	70,000		3.23 percent		March 2017

Derivative Instruments

Fair Value of Derivative Instruments as of June 30, 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	$	153,812	Derivatives - current	$	87,944
Interest rate derivatives	Derivatives - current		12,253	Derivatives - current		—
Commodity price derivatives	Derivatives - noncurrent		135,927	Derivatives - noncurrent		114,334
Interest rate derivatives	Derivatives - noncurrent		17,870	Derivatives - noncurrent		5,177
		$	319,862		$	207,455
Fair Value of Derivative Instruments as of December 31, 2010
	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	$	167,406	Derivatives - current	$	87,741
Interest rate derivatives	Derivatives - current		11,903	Derivatives - current		886
Commodity price derivatives	Derivatives - noncurrent		152,731	Derivatives - noncurrent		64,829
Interest rate derivatives	Derivatives - noncurrent		15,762	Derivatives - noncurrent		9,227
Total derivatives		$	347,802		$	162,683

(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.

Derivative Obligations Under Terminated Hedge Arrangements

Derivatives in Cash Flow Hedging Relationships	Location of Gain/(Loss) Reclassified from AOCI into Earnings	Amount of Gain/(Loss) Reclassified from AOCI into Earnings
		Three Months Ended June 30,						Six Months Ended June 30,
		2011			2010			2011			2010
		in thousands
Interest rate derivatives	Interest expense	$	(69	)	$	(312	)	$	(137	)	$	(1,370	)
Interest rate derivatives	Derivative gains (losses), net		—			(1,523	)		—			(2,665	)
Commodity price derivatives	Oil and gas revenue		8,208			22,532			16,332			45,658
Total		$	8,139		$	20,697		$	16,195		$	41,623
Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Earnings on Derivatives	Amount of Gain (Loss) Recognized in Earnings on Derivatives
		Three Months Ended June 30,						Six Months Ended June 30,
		2011			2010			2011			2010
		(in thousands)
Interest rate derivatives	Derivative gains (losses), net	$	14,575		$	26,517		$	12,423		$	37,916
Commodity price derivatives	Derivative gains (losses), net		214,903			152,534			(27,377	)		407,753
Total		$	229,478		$	179,051		$	(14,954	)	$	445,669

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Income Taxes

6 Months Ended

Jun. 30, 2011

Income Taxes

Income Taxes

NOTE E. Income Taxes

The Company accounts for income taxes in accordance with the provisions of ASC Topic 740, which requires that the Company continually assess both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and worldwide economic factors to assess the likelihood that the Company's net operating loss carry forwards ("NOLs") and other deferred tax attributes in the U.S., state, local and foreign tax jurisdictions will be utilized prior to their expiration. As of June 30, 2011 and December 31, 2010, the Company's valuation allowances were $9.9 million and $6.6 million, respectively. As of December 31, 2010, the Company also had a $26.5 million valuation allowance related to Tunisia operations, which was classified as discontinued operations held for sale. 

ASC 740 also clarifies the accounting for uncertainty in income taxes recognized and prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of June 30, 2011, the Company had no significant unrecognized tax benefits. The Company's policy is to account for interest charges with respect to income taxes as interest expense and any penalties, with respect to income taxes, as other expense in the consolidated statements of operations. 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 2005. As of June 30, 2011, 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.

Income tax (provisions) benefits. 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, 2011 and 2010:

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in thousands)
Current:
U.S. federal	$	—		$	(2,199	)	$	—		$	(3,301	)
U.S. state		(2,538	)		(1,800	)		(4,936	)		(3,124	)
Foreign		(10,782	)		(413	)		(17,102	)		(450	)
		(13,320	)		(4,412	)		(22,038	)		(6,875	)
Deferred:
U.S. federal		(140,948	)		(71,929	)		(100,160	)		(203,056	)
U.S. state		304			(7,040	)		10,729			(16,500	)
Foreign		9,268			161			13,924			(796	)
		(131,376	)		(78,808	)		(75,507	)		(220,352	)
Income tax provision	$	(144,696	)	$	(83,220	)	$	(97,545	)	$	(227,227	)

Discontinued operations. The Company's income tax (provisions) benefits attributable to income from discontinued operations consisted of the following for the three and six months ended June 30, 2011 and 2010:

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in thousands)
Current:
U.S. state	$	1,790		$	—		$	(3,935	)	$	—
Foreign		(3,753	)		(5,737	)		(5,602	)		(5,294	)
		(1,963	)		(5,737	)		(9,537	)		(5,294	)
Deferred:
U.S. federal		4,832			(12,909	)		(222,490	)		(12,839	)
U.S. state		80			—			(2,068	)		—
Foreign		4,669			(5,979	)		(7,653	)		(22,960	)
		9,581			(18,888	)		(232,211	)		(35,799	)
Income tax (provision) benefit	$	7,618		$	(24,625	)	$	(241,748	)	$	(41,093	)

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Derivative Financial Instruments (Narrative) (Details) (USD $)	6 Months Ended		12 Months Ended		6 Months Ended	3 Months Ended	6 Months Ended
	Dec. 31, 2011	Jun. 30, 2011	Dec. 31, 2012	Mar. 31, 2012	Jun. 30, 2011 Through April 2018 [Member]	Jun. 30, 2011 2011 Diesel Swaps [Member] bbl	Jun. 30, 2011 2013 - Collar Contracts With Short Puts [Member] bbl	Jun. 30, 2011 2014 - Collar Contracts With Short Puts [Member] bbl
Short Puts Contract Volume							10,000	10,000
Contract Ceiling Price							127.51	131.68
Contract Floor Price							90.00	90.00
Contract Short Put Price							67.00	67.00
Diesel swap contract notional volume Bbls per day						250
Average fixed price per Bbl						123.90
Terminated Interest Rate Derivatives, Notional Amount		$ 470,000,000
Proceeds from termination of interest rate derivatives		26,100,000
Net deferred gains on the effective portions of discontinued commodity hedges		13,400,000
Net deferred losses on the effective portions of discontinued interest rate hedges		1,800,000			1,800,000
Net deferred gains or losses associated to net deferred tax provisions		1,800,000
Net deferred gains or losses attributable to noncontrolling interests		6,900,000
Expected to reclassify accumulated other comprehensive income - Hedging net deferred gains				15,000,000
Accumulated other comprehensive income - Hedging net deferred gains related to noncontrolling interests				7,000,000
Cash flow hedge loss reclassified to interest expense				299,000
Expected to reclassify net deferred income tax provision				2,800,000
Expected to reclassify deferred gains (losses) on discontinued commodity hedges	16,600,000
Expected to reclassify accumulated other comprehensive income - Hedging net deferred losses			$ 3,200,000

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Consolidated Statement Of Stockholders' Equity (Parenthetical) (USD $)	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Consolidated Statement Of Stockholders' Equity
Dividends declared, per share	$ 0.04	$ 0.04

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Organization And Nature Of Operations

6 Months Ended

Jun. 30, 2011

Organization And Nature Of Operations

Organization And Nature Of Operations

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 and South Africa.

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Basis Of Presentation (Narrative) (Details) (USD $)	3 Months Ended			6 Months Ended		12 Months Ended
	Jun. 30, 2011	Mar. 31, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Percentage of divest of subsidiaries capital stock				100.00%
Allowance for Doubtful Accounts, Premiums and Other Receivables	$ 1,414,000	$ 3,535,000		$ 1,414,000		$ 3,674,000
Materials and supplies inventories	247,900,000			247,900,000		183,400,000
Commodities	4,100,000			4,100,000		3,900,000
Net materials and supplies inventories reserves	2,500,000			2,500,000		3,600,000
Inventory value classified as other noncurrent assets	17,900,000			17,900,000		13,700,000
Basis points added to variable interest rate				250
Noncontrolling interest in net assets subsidiaries	101,032,000			101,032,000		105,442,000
Net income attributable to the noncontrolling interests	20,123,000		21,113,000	15,333,000	36,465,000
Allocated stock-based compensation expense	13,800,000		10,500,000	26,400,000	20,600,000
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period		three
Restricted stock awards unvested shares at balance sheet date				536,775		825,796
Restricted stock awards liability				21,600,000
Unrecognized compensation expense	93,100,000			93,100,000
Restricted Stock Equity Awards [Member]
Amount of liabilities attributable to liability awards included in accounts payable				3,900,000
Limited Partner Interest [Member] | Pioneer Southwest [Member]
Partnerships interest of oil and gas	61.90%			61.90%
General Partner Interest [Member] | Subsidiaries [Member]
Partnerships interest of oil and gas	0.10%			0.10%
EFS Midstream [Member]
Percent of interest owned				50.10%
Pioneer Southwest [Member]
Net income attributable to the noncontrolling interests	20,100,000		21,100,000	15,300,000	36,500,000
Tunisian Subsidiaries [Member]
Inventories classified as discontinued operations held for sale						13,600,000
BOEMRE [Member]
Interest and other				$ 2,000,000	$ 35,300,000

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Income Taxes (Tables)

6 Months Ended

Jun. 30, 2011

Income Taxes

Income Tax (Provisions) Benefits

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in thousands)
Current:
U.S. federal	$	—		$	(2,199	)	$	—		$	(3,301	)
U.S. state		(2,538	)		(1,800	)		(4,936	)		(3,124	)
Foreign		(10,782	)		(413	)		(17,102	)		(450	)
		(13,320	)		(4,412	)		(22,038	)		(6,875	)
Deferred:
U.S. federal		(140,948	)		(71,929	)		(100,160	)		(203,056	)
U.S. state		304			(7,040	)		10,729			(16,500	)
Foreign		9,268			161			13,924			(796	)
		(131,376	)		(78,808	)		(75,507	)		(220,352	)
Income tax provision	$	(144,696	)	$	(83,220	)	$	(97,545	)	$	(227,227	)

Discontinued Operations

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in thousands)
Current:
U.S. state	$	1,790		$	—		$	(3,935	)	$	—
Foreign		(3,753	)		(5,737	)		(5,602	)		(5,294	)
		(1,963	)		(5,737	)		(9,537	)		(5,294	)
Deferred:
U.S. federal		4,832			(12,909	)		(222,490	)		(12,839	)
U.S. state		80			—			(2,068	)		—
Foreign		4,669			(5,979	)		(7,653	)		(22,960	)
		9,581			(18,888	)		(232,211	)		(35,799	)
Income tax (provision) benefit	$	7,618		$	(24,625	)	$	(241,748	)	$	(41,093	)

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Derivative Financial Instruments (Derivative Obligations Under Terminated Hedge Arrangements) (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Amount of Gain/(Loss) Reclassified from AOCI into Earnings	$ 8,139	$ 20,697	$ 16,195	$ 41,623
Amount of Gain (Loss) Recognized in Earnings on Derivatives	229,478	179,051	(14,954)	445,669
Interest Rate Derivatives [Member] | Interest Expense [Member]
Amount of Gain/(Loss) Reclassified from AOCI into Earnings	(69)	(312)	(137)	(1,370)
Interest Rate Derivatives [Member] | Derivative Gains (Losses), Net [Member]
Amount of Gain/(Loss) Reclassified from AOCI into Earnings		(1,523)		(2,665)
Amount of Gain (Loss) Recognized in Earnings on Derivatives	14,575	26,517	12,423	37,916
Commodity Price Derivatives [Member] | Derivative Gains (Losses), Net [Member]
Amount of Gain (Loss) Recognized in Earnings on Derivatives	214,903	152,534	(27,377)	407,753
Commodity Price Derivatives [Member] | Oil And Gas revenue [Member]
Amount of Gain/(Loss) Reclassified from AOCI into Earnings	$ 8,208	$ 22,532	$ 16,332	$ 45,658

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Postretirement Benefit Obligations (Accumulated Postretirement Benefit Obligations) (Details) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Postretirement Benefit Obligations
Beginning accumulated postretirement benefit obligations	$ 7,231,000	$ 8,951,000	$ 7,408,000	$ 9,075,000	$ 9,075,000
Net benefit payments	(375,000)	(272,000)	(691,000)	(584,000)
Service costs	61,000	81,000	122,000	161,000
Net actuarial losses		100,000		100,000
Accretion of interest	79,000	108,000	157,000	216,000
Ending accumulated postretirement benefit obligations	6,996,000	8,968,000	6,996,000	8,968,000	7,408,000
Unfunded accumulated postretirement benefit obligations			$ 7,000,000		$ 7,400,000

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Long-Term Debt (Narrative) (Details) (USD $)	6 Months Ended	3 Months Ended		6 Months Ended	3 Months Ended	6 Months Ended		3 Months Ended
	Jun. 30, 2011	Jun. 30, 2011 Cash [Member] If Converted [Member] 2.875% Convertible Senior Notes [Member]	Jun. 30, 2011 Cash [Member] 2.875% Convertible Senior Notes [Member]	Jun. 30, 2011 Noncash [Member] If Converted [Member] 2.875% Convertible Senior Notes [Member]	Jun. 30, 2011 If Converted [Member] 2.875% Convertible Senior Notes [Member]	Jun. 30, 2011 Total Debt To Book Capitalization [Member]	Jun. 30, 2011 Company's Oil And Gas Properties To Total Debt [Member]	Jun. 30, 2011 2.875% Convertible Senior Notes [Member]	Dec. 31, 2010 2.875% Convertible Senior Notes [Member]
Line of credit facility, maximum borrowing capacity	$ 1,250,000,000
Outstanding borrowings under the Credit Facility	0
Undrawn letters of credit	65,100,000
Unused borrowing capacity	1,200,000,000
Aggregate outstanding swing line loans maximum	150,000,000
Credit facility, description	(a) a rate per annum equal to the higher of the prime rate announced from time to time by Wells Fargo Bank, National Association or the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System during the last preceding business day plus 0.5 percent plus a defined alternate base rate spread margin ("ABR Margin"), which is currently one percent based on the Company's debt rating or (b) a base Eurodollar rate, substantially equal to LIBOR, plus a margin (the "Applicable Margin"), which is currently two percent and is also determined by the Company's debt rating. Swing line loans under the Credit Facility bear interest at a rate per annum equal to the "ASK" rate for Federal funds periodically published by the Dow Jones Market Service plus the Applicable Margin. Letters of credit outstanding under the Credit Facility are subject to a per annum fee, representing the Applicable Margin plus 0.125 percent. The Company also pays commitment fees on undrawn amounts under the Credit Facility that are determined by the Company's debt rating (currently 0.375 percent).
Loss on extinguishment of debt to write off the unamortized issuance costs	2,400,000
Debt instrument covenant description						.60 to 1.0	1.75 to 1.0
Senior notes, interest rate								2.875%	2.875%
Senior convertible notes, outstanding								480,000,000	480,000,000
Senior convertible notes, principal amount								70,000
Shares received for conversion of debt					1,800,000			340
Days included in calculation	20
Value of shares received for conversion of debt		$ 479,900,000	$ 71,000	$ 158,800,000

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Geographic Operating Segment Information (Reconciliation Of Assets From Segment To Consolidated) (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Total consolidated assets	$ 10,353,088	$ 9,679,102
United States [Member]
Total consolidated assets	10,222,200	8,987,141
South Africa [Member]
Total consolidated assets	85,017	134,901
Tunisia [Member]
Total consolidated assets		325,942
Headquarters [Member]
Total consolidated assets	$ 45,871	$ 231,118

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Basis Of Presentation

6 Months Ended

Jun. 30, 2011

Basis Of Presentation

Basis Of Presentation

NOTE B. Basis of Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of June 30, 2011 and for the three and six months ended June 30, 2011 and 2010 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 in connection 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, 2010.

Discontinued operations. During December 2010, the Company committed to a plan to divest 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"). In February 2011, the Company completed the sale of Pioneer Tunisia to an unaffiliated third party. Accordingly, the Company classified the assets and liabilities of Pioneer Tunisia as discontinued operations held for sale in the accompanying balance sheet as of December 31, 2010 and has classified the results of operations of Pioneer Tunisia as discontinued operations, net of tax for the three and six months ended June 30, 2011 and 2010 in the accompanying consolidated statements of operations (representing a recasting of the Pioneer Tunisia results of operations for the three and six months ended June 30, 2010, which were originally classified as continuing operations). See Note Q for more information regarding the sale of Pioneer Tunisia.

During the six months ended June 30, 2011 and 2010, the Bureau of Ocean Energy Management, Regulation, and Enforcement (the "BOEMRE") paid the Company $2.0 million and $35.3 million, respectively, of interest on excess royalty payments associated with properties that were sold by the Company during 2006. Accordingly, the Company has classified the interest income as components of income from discontinued operations, net of tax in the accompanying consolidated statements of operations.

Allowances for doubtful accounts. As of June 30, 2011 and December 31, 2010, the Company's allowances for doubtful accounts totaled $1.4 million and $3.7 million, respectively. Changes in the Company's allowance for doubtful accounts during the three and six months ended June 30, 2011 are summarized in the following table:

	Three Months Ended June 30, 2011			Six Months Ended June 30, 2011
	(in thousands)
Beginning allowance for doubtful accounts balance	$	3,535		$	3,674
Amount recorded in other expense for bad debt recoveries		(1,815	)		(1,797	)
Other net decreases		(306	)		(463	)
Ending allowance for doubtful accounts balance	$	1,414		$	1,414

Inventories. Inventories used in continuing operations consisted of $247.9 million and $183.4 million of materials and supplies and $4.1 million and $3.9 million of commodities as of June 30, 2011 and December 31, 2010, respectively. As of June 30, 2011 and December 31, 2010, the Company's materials and supplies inventory was net of $2.5 million and $3.6 million, respectively, of valuation reserve allowances. As of June 30, 2011 and December 31, 2010, the Company estimated that $17.9 million and $13.7 million, respectively, of its materials and supplies inventory would not be utilized or sold within one year. Accordingly, those inventory values have been classified as other noncurrent assets in the accompanying consolidated balance sheets. As of December 31, 2010, the Company also had inventory in Tunisia totaling $13.6 million that is classified as discontinued operations held for sale in the accompanying consolidated balance sheet as of December 31, 2010.

Derivatives and hedging. All derivatives are recorded in the accompanying consolidated balance sheets at estimated fair value. See Note D 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 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 – net deferred hedge gains, net of tax ("AOCI – Hedging"), in the stockholders' equity section of the accompanying consolidated balance sheets, and are being transferred to earnings during the same periods in which the hedged transactions are recognized in the Company's earnings. Since February 1, 2009, the Company has recognized 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 Energy Partners L.P.'s ("Pioneer Southwest," a majority-owned and consolidated subsidiary) credit-adjusted risk-free rate curves. The credit-adjusted risk-free rate curves for the Company and the counterparties are 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 250 basis points, representing Pioneer Southwest's estimated borrowing rate.

Goodwill. 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 2010, the Company performed its annual assessment of goodwill impairment and determined that there was no impairment

Noncontrolling interest in consolidated subsidiaries. The Company owns a 0.1 percent general partner interest and a 61.9 percent limited partner interest in Pioneer Southwest. Pioneer Southwest owns interests in certain oil and gas properties in the Spraberry field in the Permian Basin of West Texas. The financial position, results of operations and cash flows of Pioneer Southwest are consolidated with those of the Company.

The Company also owns a majority interest in Sendero Drilling Company, LLC ("Sendero"), which owns and operates land-based drilling rigs in the United States. In addition, the Company owns the majority interests in certain other subsidiaries with operations in the United States.

Noncontrolling interest in the net assets of consolidated subsidiaries totaled $101.0 million and $105.4 million as of June 30, 2011 and December 31, 2010, respectively. The Company recorded net income attributable to the noncontrolling interests of $20.1 million and $15.3 million for the three and six months ended June 30, 2011, respectively (principally related to Pioneer Southwest), compared to net income attributable to the noncontrolling interests of $21.1 million and $36.5 million for the three and six months ended June 30, 2010, respectively.

Investment in unconsolidated affiliate. The Company owns a 50.1 percent interest in EFS Midstream LLC ("EFS Midstream"), which owns and operates natural gas and liquids gathering, treating and transportation assets in the Eagle Ford Shale area of South Texas.

The Company accounts for the EFS Midstream investment under the equity method of accounting for investments in unconsolidated affiliates. Under the equity method, the Company's investment in unconsolidated affiliates is increased for investments made and the investor's share of the investee's net income, and decreased for distributions received, the carrying value of investor's interests sold and the investor's share of the investee's net losses. The Company's equity interest in the net income of EFS Midstream is recorded in interest and other income in the Company's accompanying consolidated statements of operations.

Stock-based compensation. For stock-based compensation equity awards granted or modified, compensation expense is being recognized in the Company's financial statements on a straight line basis over the awards' vesting periods based on their fair values on the dates of grant. The amount of compensation expense recognized at any date is at least equal to the portion of the measurement date (normally the grant date) value of the award that is vested at that date. The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, (ii) the prior day's closing stock price on the date of grant for the fair value of restricted stock, restricted stock units, partnership unit awards or phantom unit awards that are expected to be settled wholly in the Company's common stock or Pioneer Southwest common units ("Equity Awards"), (iii) the Monte Carlo simulation method for the fair value of performance unit awards and (iv) a probabilistic forecasted fair value method for series B unit awards issued by Sendero.

Stock-based compensation liability awards are awards that are expected to be settled wholly or partially in cash on their vesting dates, rather than in shares or units ("Liability Awards"). Stock-based Liability Awards are recorded as accounts payable – affiliates based on the fair value of the services that have been rendered on the unvested portions of the awards on the balance sheet date. The fair values of Liability Awards are updated at each balance sheet date and changes in the fair values of the unvested portions of the awards for which services have been rendered are recorded as increases or decreases to compensation expense. As of June 30, 2011, accounts payable – due to affiliates includes $3.9 million of liabilities attributable to the Liability Awards.

For the three and six months ended June 30, 2011, the Company recorded $13.8 million and $26.4 million, respectively, of stock-based compensation costs for all plans, as compared to $10.5 million and $20.6 million for the same respective periods of 2010. As of June 30, 2011, there was $93.1 million of unrecognized compensation expense related to unvested share- and unit-based compensation plan awards, including $21.6 million attributable to Liability Awards. This compensation will be recognized over the remaining vesting periods of the awards, which on a weighted average basis is a period of less than three years.

The Company's issued shares, as reflected in the consolidated balance sheets at June 30, 2011 and December 31, 2010, do not include 536,775 and 825,796 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, 2011, 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, 2010		2,559,779			215,134			263,729			507,539			12,212			35,118
Awards granted		427,384			182,982			43,495			86,903			6,812			30,039
Awards vested		(1,015,713	)		(63,556	)		(14,807	)		—			(11,532	)		—
Options exercised		—			—			—			(15,290	)		—			—
Awards forfeited		(37,914	)		(11,931	)		—			—			—			—
Outstanding at June 30, 2011		1,933,536			322,629			292,417			579,152			7,492			65,157

New accounting pronouncements. During December 2010, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2010-28, "Intangibles-Goodwill and Other (Topic 350)." ASU No. 2010-28 modifies step one of the goodwill impairment test for reporting units with zero or negative carrying amounts, requiring that an entity perform step two of the goodwill impairment test if it is more likely than not that a goodwill impairment exists for those reporting units. The Company adopted the provisions of ASU No. 2010-28 effective January 1, 2011. The adoption of ASU No. 2010-28 had no effect on the Company's goodwill balance. See "Goodwill" above for more information about the Company's policy for assessing impairment of its goodwill.

In May 2011, the FASB issued ASU 2011-04, "Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRSs." ASU 2011-04 amended ASC 820 to converge the fair value measurement guidance in GAAP and International Financial Reporting Standards. Certain of the amendments clarify the application of existing fair value measurement requirements, while other amendments change a particular principle in ASC 820. In addition, ASU 2011-04 requires additional fair value disclosures. The amendments will be applied prospectively and are effective for annual periods beginning after December 15, 2011. The Company does not believe the adoption of this guidance will have a material impact on its consolidated financial statements.

In June 2011, the FASB issued ASU No. 2011-05 "Presentation of Comprehensive Income (Topic 220)." To increase the prominence of items reported in other comprehensive income, ASU 2011-05 requires comprehensive income, the components of net income, and the components of other comprehensive income to be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The amendments do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. The amendments will be applied retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2011. The adoption of ASU 2011-05 will not have a material impact on the Company's consolidated financial statements.

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Basis Of Presentation (Stock-Based Awards, Lapses, Exercises And Forfeitures) (Details)	6 Months Ended
	Jun. 30, 2011
Restricted Stock Equity Awards [Member]
Outstanding at December 31, 2010	2,559,779
Awards granted	427,384
Awards vested	(1,015,713)
Awards forfeited	(37,914)
Outstanding at June 30, 2011	1,933,536
Restricted Stock Liability Awards [Member]
Outstanding at December 31, 2010	215,134
Awards granted	182,982
Awards vested	(63,556)
Awards forfeited	(11,931)
Outstanding at June 30, 2011	322,629
Performance Units [Member]
Outstanding at December 31, 2010	263,729
Awards granted	43,495
Awards vested	(14,807)
Outstanding at June 30, 2011	292,417
Stock Options [Member]
Outstanding at December 31, 2010	507,539
Awards granted	86,903
Options exercised	(15,290)
Outstanding at June 30, 2011	579,152
Pioneer Southwest LTIP Restricted Units [Member]
Outstanding at December 31, 2010	12,212
Awards granted	6,812
Awards vested	(11,532)
Outstanding at June 30, 2011	7,492
Pioneer Southwest LTIP Phantom Units [Member]
Outstanding at December 31, 2010	35,118
Awards granted	30,039
Outstanding at June 30, 2011	65,157

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Basis Of Presentation (Tables)

6 Months Ended

Jun. 30, 2011

Basis Of Presentation

Allowance For Doubtful Accounts

	Three Months Ended June 30, 2011			Six Months Ended June 30, 2011
	(in thousands)
Beginning allowance for doubtful accounts balance	$	3,535		$	3,674
Amount recorded in other expense for bad debt recoveries		(1,815	)		(1,797	)
Other net decreases		(306	)		(463	)
Ending allowance for doubtful accounts balance	$	1,414		$	1,414

Stock-Based Awards, Lapses, Exercises And Forfeitures

	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, 2010		2,559,779			215,134			263,729			507,539			12,212			35,118
Awards granted		427,384			182,982			43,495			86,903			6,812			30,039
Awards vested		(1,015,713	)		(63,556	)		(14,807	)		—			(11,532	)		—
Options exercised		—			—			—			(15,290	)		—			—
Awards forfeited		(37,914	)		(11,931	)		—			—			—			—
Outstanding at June 30, 2011		1,933,536			322,629			292,417			579,152			7,492			65,157

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Volumetric Production Payments (Deferred Revenue Carrying Values) (Details) (Volumetric Production Payment [Member], USD $) In Thousands	6 Months Ended
	Jun. 30, 2011
Volumetric Production Payment [Member]
Deferred revenue at December 31, 2010	$ 87,020
Less: 2011 amortization	(22,290)
Deferred revenue at June 30, 2011	$ 64,730

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Net Income (Loss) Per Share (Reconciliation Of Weighted-Average Common Shares Outstanding, Basic And Diluted) (Details) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Net Income (Loss) Per Share
Basic	116,213	115,104	116,042	114,880
Dilutive common stock options	178	262	188	243
Convertible senior notes dilution	1,772		2,333
Contingently issuable performance unit shares	429	640	423	612
Diluted	118,592	116,006	118,986	115,735

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Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2011

Asset Retirement Obligations

Asset Retirement Obligations

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in thousands)
Beginning asset retirement obligations	$	154,689		$	142,270		$	152,291		$	166,434
Liabilities assumed in acquisitions		—			6			6			6
New wells placed on production		1,404			4,365			2,075			4,644
Changes in estimates		(179	)		—			121			—
Disposition of wells		(367	)		(3,291	)		(448	)		(29,540	)
Liabilities settled		(6,235	)		(8,801	)		(7,469	)		(9,955	)
Accretion of discount from continuing operations		2,658			2,529			5,313			5,388
Accretion of discount from discontinued operations		—			103			81			204
Ending asset retirement obligations	$	151,970		$	137,181		$	151,970		$	137,181

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Basis Of Presentation (Allowance For Doubtful Accounts) (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Basis Of Presentation
Beginning allowance for doubtful accounts balance	$ 3,535		$ 3,674
Amount recorded in other expense for bad debt recoveries	(1,815)	(254)	(1,797)	(30)
Other net decreases	(306)		(463)
Ending allowance for doubtful accounts balance	$ 1,414		$ 1,414

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Disclosures About Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2011

Disclosures About Fair Value Measurements

Assets And Liabilities That Are Measured At Fair Value On A Recurring Basis

	Fair Value Measurements at Reporting Date 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, 2011
	(in thousands)
Assets:
Trading securities	$	289	$	30,149	$	—	$	30,438
Commodity derivatives		—		271,544		—		271,544
Interest rate derivatives (a)		—		24,946		—		24,946
Deferred compensation plan assets		40,223		—		—		40,223
Total assets	$	40,512	$	326,639	$	—	$	367,151
Liabilities:
Commodity derivatives	$	—	$	170,732	$	13,351	$	184,083
Pioneer Southwest credit facility		—		84,542		—		84,542
5.875% senior notes due 2016		482,139		—		—		482,139
6.65% senior notes due 2017		529,972		—		—		529,972
6.875% senior notes due 2018		496,698		—		—		496,698
7.50% senior notes due 2020		512,158		—		—		512,158
7.20% senior notes due 2028		250,000		—		—		250,000
2.875% senior convertible notes due 2038 (b)		742,800		—		—		742,800
Total liabilities	$	3,013,767	$	255,274	$	13,351	$	3,282,392

(a) Subsequent to June 30, 2011, the Company terminated the interest rate derivatives shown in the table above and received $26.1 million of proceeds. See Note G for additional information about the Company's interest rate derivatives.

(b) The fair value of the 2.875% senior convertible notes includes the fair value of the conversion privilege.

Fair Value Measurements Using Significant Unobservable Inputs

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)	Three Months Ended June 30, 2011			Six Months Ended June 30, 2011
	(in thousands)
Beginning liability balance	$	(16,675	)	$	(9,556	)
Total gains and losses:
Net unrealized gains (losses) included in earnings (a)		3,324			(3,795	)
Net realized losses included in earnings (a)		(4,629	)		(7,325	)
Settlement payments		4,629			7,325
Ending liability balance	$	(13,351	)	$	(13,351	)

(a) Non-hedge derivatives gains and losses are included in net derivative (gains) losses in the accompanying consolidated statements of operations.

Fair Values Of The Company Financial Instruments

	June 30, 2011				December 31, 2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Assets:
Commodity price derivatives	$	271,544	$	271,544	$	304,434	$	304,434
Interest rate derivatives (a)	$	24,946	$	24,946	$	18,256	$	18,256
Trading securities	$	30,438	$	30,438	$	467	$	467
Deferred compensation plan assets	$	40,223	$	40,223	$	36,162	$	36,162
Liabilities:
Commodity price derivatives	$	184,083	$	184,083	$	136,867	$	136,867
Interest rate derivatives	$	—	$	—	$	704	$	704
Pioneer credit facility	$	—	$	—	$	49,000	$	58,382
Pioneer Southwest credit facility	$	87,000	$	84,542	$	81,200	$	77,241
5.875 % senior notes due 2016	$	401,037	$	482,139	$	396,880	$	475,194
6.65 % senior notes due 2017	$	484,114	$	529,972	$	484,046	$	516,632
6.875 % senior notes due 2018	$	449,209	$	496,698	$	449,192	$	480,969
7.50 % senior notes due 2020	$	446,572	$	512,158	$	446,433	$	494,145
7.20 % senior notes due 2028	$	249,927	$	250,000	$	249,925	$	259,350
2.875% senior convertible notes due 2038 (b)	$	453,119	$	742,800	$	444,994	$	728,400

(a) Subsequent to June 30, 2011, the Company terminated the interest rate derivatives shown in the table above and received $26.1 million of proceeds. See Note G for additional information about the Company's interest rate derivatives.

(b) The fair value of the 2.875% senior convertible notes includes the fair value of the conversion privilege.

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Commitments And Contingencies

6 Months Ended

Jun. 30, 2011

Commitments And Contingencies

Commitments And Contingencies

NOTE J. Commitments and Contingencies

Legal actions. In addition to the legal action described below, the Company is a party to other 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 other 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 will continue to evaluate its litigation on a quarter-by-quarter basis and will establish and adjust any litigation reserves as appropriate to reflect its assessment of the then current status of litigation.

Investigation by the Alaska Oil and Gas Conservation Commission (the "AOGCC"). During the second quarter of 2010, the AOGCC commenced an investigation into allegations by a former Pioneer employee regarding the Company's Oooguruk facility on the North Slope of Alaska. Among the allegations are claims that the Company did not have authorization to inject certain non-hazardous substances into its enhanced oil recovery well, that the Company mishandled disposal of waste products and that the Company's operating practices are harmful to the project's oil reservoirs. Upon initially becoming aware of the allegations, the Company informed the AOGCC and other relevant federal, state and local agencies and commenced its own investigation, which confirmed injections of non-hazardous fluids into the Oooguruk enhanced oil recovery well without prior authorizations to do so. The results of the Company's investigation were reported to the agencies. In December 2010, the AOGCC investigator submitted a report outlining its findings, which (i) found that the Company's operating practices have not harmed the project's oil reservoirs and (ii) raised certain regulatory compliance issues, all of which the Company previously reported or has since taken actions to remedy. Although the Company does not know at this time what action the AOGCC will take in response to the report, based on the facts as known to date, the Company believes that compliance with any order or other action of the AOGCC will not materially affect the Company's liquidity, financial position or future results of operations.

Obligations following divestitures. In April 2006, the Company provided the purchaser of its Argentine assets certain indemnifications. The Company remains responsible for certain contingent liabilities related to such indemnifications, subject to defined limitations, including matters of litigation, environmental contingencies, royalty obligations and income taxes. The Company has also retained certain liabilities and indemnified buyers for certain matters in connection with other divestitures, including the sale in 2007 of its Canadian assets and the February 2011 sale of Pioneer Tunisia. The Company does not believe that these obligations are probable of having a material impact on its liquidity, financial position or future results of operations.

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Derivative Financial Instruments (Fixed-For-Variable Interest Rates) (Details) (Fixed-For-Variable [Member], USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2011
Interest Swap Due July 2016 [Member]
Notional Amount	$ 400,000
Weighted Average Fixed Interest Rate	2.87%
Termination Date	Jul. 01, 2016
Interest Swap Due March 2017 [Member]
Notional Amount	$ 70,000
Weighted Average Fixed Interest Rate	3.23%
Termination Date	Mar. 01, 2017

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Net Income (Loss) Per Share (Reconciliation Of Earnings, Basic And Diluted) (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Income (loss) as reported, Continuing Operations	$ 267,284	$ 146,838	$ 196,446	$ 403,633
Income (loss) from discontinued operations, net of tax	(1,584)	41,851	413,058	45,662
Profit Loss	265,700	188,689	609,504	449,295
Net income attributable to the noncontrolling interests	(20,123)	(21,113)	(15,333)	(36,465)
Participating basic distributed earnings	(4,847)	(4,083)	(10,849)	(9,390)
Basic income (loss) attributable to common stockholders	240,730	163,493	583,322	403,440
Reallocation of participating earnings	164	112	271	110
Diluted income (loss) attributable to common stockholders	240,894	163,605	583,593	403,550
Segment, Continuing Operations [Member]
Income (loss) as reported, Continuing Operations	267,284	146,838	196,446	403,633
Net income attributable to the noncontrolling interests	(20,123)	(21,113)	(15,333)	(36,465)
Participating basic distributed earnings	(4,847)	(3,063)	(3,307)	(8,351)
Basic income (loss) attributable to common stockholders	242,314	122,662	177,806	358,817
Reallocation of participating earnings	164	84	82	98
Diluted income (loss) attributable to common stockholders	242,478	122,746	177,888	358,915
Segment, Discontinued Operations [Member]
Income (loss) from discontinued operations, net of tax	(1,584)	41,851	413,058	45,662
Participating basic distributed earnings		(1,020)	(7,542)	(1,039)
Basic income (loss) attributable to common stockholders	(1,584)	40,831	405,516	44,623
Reallocation of participating earnings		28	189	12
Diluted income (loss) attributable to common stockholders	$ (1,584)	$ 40,859	$ 405,705	$ 44,635

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Exploratory Costs

6 Months Ended

Jun. 30, 2011

Exploratory Costs

Exploratory Costs

NOTE C. 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 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, 2011:

	Three Months Ended June 30, 2011			Six Months Ended June 30, 2011
				(in thousands)
Beginning capitalized exploratory costs	$	80,530		$	96,193
Additions to exploratory costs pending the determination of proved reserves		140,081			214,345
Reclassification due to determination of proved reserves		(135,338	)		(195,682	)
Disposition of assets sold		—			(28,938	)
Exploratory well costs charged to exploration expense		(162	)		(807	)
Ending capitalized exploratory costs	$	85,111		$	85,111

The following table provides an aging, as of June 30, 2011 and December 31, 2010 of capitalized exploratory costs and the number of projects for which exploratory costs have been capitalized for a period greater than one year, based on the date drilling was completed:

	June 30, 2011		December 31, 2010
	(in thousands, except project counts)
Capitalized exploratory costs that have been suspended:
One year or less	$	77,129	$	70,635
More than one year		7,982		25,558
	$	85,111	$	96,193
Number of projects with exploratory costs that have been suspended for a period greater than one year		1		3

As of June 30, 2011, the Company has one project with exploratory costs that has been suspended for a period of one year or more, which is described below. As of December 31, 2010, the Company had three Tunisian projects with exploratory costs that had been suspended for a period of one year or more, all of which were included in the Pioneer Tunisia assets sold during February 2011.

South Texas Project. As of June 30, 2011, the Company has $8.0 million of suspended exploratory costs associated with a formation test well in South Texas. The well is currently awaiting finalization of the project's ongoing fracture stimulation and completion designs. The Company successfully completed one other test well in the project and plans to drill a third test well during the second half of 2011. Information gained from the wells is being utilized to finalize the project's fracture stimulation and completion designs. Future production from the project would utilize existing production and marketing infrastructure.

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Volumetric Production Payments

6 Months Ended

Jun. 30, 2011

Volumetric Production Payments

Volumetric Production Payments

NOTE M.  Volumetric Production Payments

The Company's remaining VPP represents a limited-term overriding royalty interest in oil reserves that: (i) entitles the purchaser to receive production volumes over a period of time from specific lease interests, (ii) is free and clear of all associated future production costs and capital expenditures associated with the reserves, (iii) is nonrecourse to the Company (i.e., the purchaser's only recourse is to the reserves acquired), (iv) transfer title of the reserves to the purchaser and (v) allow the Company to retain the remaining reserves after the VPP's volumetric quantities have been delivered.

At the inception of the VPP agreement, the Company (i) removed the proved reserves associated with the VPP, (ii) recognized VPP proceeds as deferred revenue which are being amortized on a unit-of-production basis to oil revenues over the remaining term of the VPP, (iii) retained responsibility for 100 percent of the production costs and capital costs related to VPP interests and (iv) no longer recognizes production associated with the VPP volumes.

The following table provides information about changes in the deferred revenue carrying values of the Company's VPP for the six months ended June 30, 2011 (in thousands):

Deferred revenue at December 31, 2010	$	87,020
Less: 2011 amortization		(22,290	)
Deferred revenue at June 30, 2011	$	64,730

The remaining deferred revenue amounts will be recognized in oil revenues in the consolidated statements of operations as noted below, assuming the related VPP production volumes are delivered as scheduled (in thousands):

Remaining 2011	$	22,659
2012	$	42,071

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Volumetric Production Payments (Narrative) (Details) (Volumetric Production Payment [Member])	6 Months Ended
	Jun. 30, 2011
Volumetric Production Payment [Member]
Production/capital costs responsibility, in percentage	100.00%

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Geographic Operating Segment Information (Schedule Of Income Statement By Geographic Operating Segment) (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Oil and gas	$ 583,931	$ 422,042	$ 1,081,061	$ 894,087
Interest and other	18,454	16,952	51,141	34,960
Gain (loss) on disposition of assets, net	(296)	7,645	(2,487)	24,588
Revenues and other income	602,089	446,639	1,129,715	953,635
Oil and gas production	102,455	94,012	202,386	180,112
Production and ad valorem taxes	35,864	25,338	69,160	52,399
Depletion, depreciation and amortization	153,898	144,309	294,271	288,737
Exploration and abandonments	19,914	22,743	37,557	39,591
General and administrative	44,644	40,433	88,750	78,748
Accretion of discount on asset retirement obligations	2,658	2,529	5,313	5,388
Interest	45,768	45,368	90,995	92,891
Hurricane activity, net	(2)	5,184	69	(2,226)
Derivative (gains) losses, net	(229,478)	(177,528)	14,954	(443,004)
Other	14,388	14,193	32,269	30,139
Costs and expenses, Total	190,109	216,581	835,724	322,775
Income from continuing operations before income taxes	411,980	230,058	293,991	630,860
Income tax provision	(144,696)	(83,220)	(97,545)	(227,227)
Income from continuing operations	267,284	146,838	196,446	403,633
United States [Member]
Oil and gas	562,411	401,540	1,038,140	848,204
Interest and other	13,725	998	16,603	1,507
Gain (loss) on disposition of assets, net		7,560		24,979
Revenues and other income	576,136	410,098	1,054,743	874,690
Oil and gas production	101,741	93,116	200,576	178,440
Production and ad valorem taxes	35,864	25,338	69,160	52,399
Depletion, depreciation and amortization	127,864	117,859	244,404	233,364
Exploration and abandonments	19,731	22,689	37,216	39,465
Accretion of discount on asset retirement obligations	2,047	1,907	4,091	4,144
Hurricane activity, net	(2)	5,184	69	(2,226)
Other	5,410	10,270	10,569	20,551
Costs and expenses, Total	292,655	276,363	566,085	526,137
Income from continuing operations before income taxes	283,481	133,735	488,658	348,553
Income tax provision	(104,888)	(49,482)	(180,803)	(128,965)
Income from continuing operations	178,593	84,253	307,855	219,588
South Africa [Member]
Oil and gas	21,520	20,502	42,921	45,883
Revenues and other income	21,520	20,502	42,921	45,883
Oil and gas production	714	896	1,810	1,672
Depletion, depreciation and amortization	13,536	18,442	27,221	40,339
Exploration and abandonments	183	54	341	126
Accretion of discount on asset retirement obligations	611	622	1,222	1,244
Costs and expenses, Total	15,044	20,014	30,594	43,381
Income from continuing operations before income taxes	6,476	488	12,327	2,502
Income tax provision	(1,813)	(137)	(3,452)	(701)
Income from continuing operations	4,663	351	8,875	1,801
Headquarters [Member]
Interest and other	4,729	15,954	34,538	33,453
Gain (loss) on disposition of assets, net	(296)	85	(2,487)	(391)
Revenues and other income	4,433	16,039	32,051	33,062
Depletion, depreciation and amortization	12,498	8,008	22,646	15,034
General and administrative	44,644	40,433	88,750	78,748
Interest	45,768	45,368	90,995	92,891
Derivative (gains) losses, net	(229,478)	(177,528)	14,954	(443,004)
Other	8,978	3,923	21,700	9,588
Costs and expenses, Total	(117,590)	(79,796)	239,045	(246,743)
Income from continuing operations before income taxes	122,023	95,835	(206,994)	279,805
Income tax provision	(37,995)	(33,601)	86,710	(97,561)
Income from continuing operations	$ 84,028	$ 62,234	$ (120,284)	$ 182,244

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Other Expense (Tables)

6 Months Ended

Jun. 30, 2011

Other Expense

Schedule Of Components Of Other Expense

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in thousands)
Transportation commitment charge (a)	$	5,688		$	—		$	10,960		$	—
Above market drilling rig related costs (b)		5,410			10,270			10,569			20,551
Other		1,909			2,617			4,193			3,170
Loss on extinguishment of debt		—			—			2,367			—
Contingency and environmental accrual adjustments		1,587			94			2,882			247
Cancelled well costs (recoveries)		(442	)		(126	)		759			(29	)
Inventory impairment (c)		302			13			587			1,570
Tax penalties		1,749			—			1,749			—
Bad debt recoveries		(1,815	)		(254	)		(1,797	)		(30	)
Well servicing operations (d)		—			1,579			—			4,660
Total other expense	$	14,388		$	14,193		$	32,269		$	30,139

(a) Primarily represents firm transportation contract deficiency payment obligations.

(b) Primarily represents charges for the portion of Pioneer's contracted drilling rig rates that are above market rates and are not charged to joint operations.

(c) Represents impairment charges on excess materials and supplies inventories.

(d) Represents idle well servicing costs.

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Other Expense (Schedule Of Components Of Other Expense) (Details) (USD $) In Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2011		Jun. 30, 2010		Jun. 30, 2011		Jun. 30, 2010
Other Expense
Transportation commitment charge	$ 5,688	[1]			$ 10,960	[1]
Above market drilling rig related costs	5,410	[2]	10,270	[2]	10,569	[2]	20,551	[2]
Other	1,909		2,617		4,193		3,170
Loss on extinguishment of debt					2,367
Contingency and environmental accrual adjustments	1,587		94		2,882		247
Cancelled well costs (recoveries)	(442)		(126)		759		(29)
Inventory impairment	302	[3]	13	[3]	587	[3]	1,570	[3]
Tax penalties	1,749				1,749
Bad debt recoveries	(1,815)		(254)		(1,797)		(30)
Well servicing operations			1,579	[4]			4,660	[4]
Total other expense	$ 14,388		$ 14,193		$ 32,269		$ 30,139

[1] Primarily represents firm transportation contract deficiency payment obligations.

[2] Primarily represents charges for the portion of Pioneer's contracted drilling rig rates that are above market rates and are not charged to joint operations.

[3] Represents impairment charges on excess materials and supplies inventories.

[4] Represents idle well servicing costs.

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Exploratory Costs (Tables)

6 Months Ended

Jun. 30, 2011

Exploratory Costs

Capitalized Exploratory Well And Project Activity

	Three Months Ended June 30, 2011			Six Months Ended June 30, 2011
				(in thousands)
Beginning capitalized exploratory costs	$	80,530		$	96,193
Additions to exploratory costs pending the determination of proved reserves		140,081			214,345
Reclassification due to determination of proved reserves		(135,338	)		(195,682	)
Disposition of assets sold		—			(28,938	)
Exploratory well costs charged to exploration expense		(162	)		(807	)
Ending capitalized exploratory costs	$	85,111		$	85,111

Capitalized Exploratory Costs And The Number Of Projects For Which Exploratory Costs Have Been Capitalized

	June 30, 2011		December 31, 2010
	(in thousands, except project counts)
Capitalized exploratory costs that have been suspended:
One year or less	$	77,129	$	70,635
More than one year		7,982		25,558
	$	85,111	$	96,193
Number of projects with exploratory costs that have been suspended for a period greater than one year		1		3

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Consolidated Statement Of Stockholders' Equity (USD $) In Thousands, except Share data	Common Stock [Member]	Additional Paid-In Capital [Member]	Treasury Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income [Member]	Noncontrolling Interests [Member]	Total
Beginning Balance at Dec. 31, 2010	$ 1,262	$ 3,022,768	$ (421,235)	$ 1,510,427	$ 7,361	$ 105,442	$ 4,226,025
Beginning Balance (in shares) at Dec. 31, 2010	115,309,000
Dividends declared ($0.04 per share)				(4,739)			(4,739)
Exercise of long-term incentive plan stock options (in shares)	16,000
Exercise of long-term incentive plan stock options			598	(236)			362
Treasury stock purchases (in shares)	(424,000)
Treasury stock purchases			(39,020)			(198)	(39,218)
Tax benefit related to stock-based compensation		27,937					27,937
Disposition of subsidiary		(508)					(508)
Compensation costs:
Vested compensation awards, net (in shares)	1,343,000
Vested compensation awards, net	14	(14)
Compensation costs included in net income		20,644				632	21,276
Cash distributions to noncontrolling interests						(13,366)	(13,366)
Net income				594,171		15,333	609,504
Deferred hedging activity, net of tax:
Net hedge gains included in continuing operations					(4,498)	(6,811)	(11,309)
Ending Balance at Jun. 30, 2011	$ 1,276	$ 3,070,827	$ (459,657)	$ 2,099,623	$ 2,863	$ 101,032	$ 4,815,964
Ending Balance (in shares) at Jun. 30, 2011	116,244,000

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Gain (Loss) On Disposition Of Assets, Net

6 Months Ended

Jun. 30, 2011

Gain (Loss) On Disposition Of Assets, Net

Gain (Loss) On Disposition Of Assets, Net

NOTE N. Gain (Loss) on Disposition of Assets, Net

For the three and six months ended June 30, 2011, the Company recorded $296 thousand and $2.5 million of net losses on disposition of assets from continuing operations, respectively, as compared to $7.6 million and $24.6 million, respectively, of net gains from continuing operations for the three and six months ended June 30, 2010.

The Company's net losses during the three and six months ended June 30, 2011 are primarily associated with sales of excess materials and supplies inventory. During the three and six months ended June 30, 2010, the Company's net gains are primarily attributable to the Company's Eagle Ford Shale joint venture transaction that was completed during June 2010, and the sale of proved and unproved oil and gas properties in the Uinta/Piceance area.

See Note Q for information about the Company's gains and losses during the three and six months ended June 30, 2011 from the sale of its Tunisia subsidiaries that are included in discontinued operations.

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Exploratory Costs (Capitalized Exploratory Costs And The Number Of Projects For Which Exploratory Costs Have Been Capitalized) (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010
Exploratory Costs
One year or less	$ 77,129		$ 70,635
More than one year	7,982		25,558
Capitalized exploratory costs, total	$ 85,111	$ 80,530	$ 96,193
Number of projects with exploratory costs that have been suspended for a period greater than one year	1		3

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Other Expense

6 Months Ended

Jun. 30, 2011

Other Expense

Other Expense

NOTE P. Other Expense

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in thousands)
Transportation commitment charge (a)	$	5,688		$	—		$	10,960		$	—
Above market drilling rig related costs (b)		5,410			10,270			10,569			20,551
Other		1,909			2,617			4,193			3,170
Loss on extinguishment of debt		—			—			2,367			—
Contingency and environmental accrual adjustments		1,587			94			2,882			247
Cancelled well costs (recoveries)		(442	)		(126	)		759			(29	)
Inventory impairment (c)		302			13			587			1,570
Tax penalties		1,749			—			1,749			—
Bad debt recoveries		(1,815	)		(254	)		(1,797	)		(30	)
Well servicing operations (d)		—			1,579			—			4,660
Total other expense	$	14,388		$	14,193		$	32,269		$	30,139

(a) Primarily represents firm transportation contract deficiency payment obligations.

(b) Primarily represents charges for the portion of Pioneer's contracted drilling rig rates that are above market rates and are not charged to joint operations.

(c) Represents impairment charges on excess materials and supplies inventories.

(d) Represents idle well servicing costs.

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Gain (Loss) On Disposition Of Assets, Net (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Gain (Loss) On Disposition Of Assets, Net
(Gain) loss on disposition of assets, net	$ 296	$ (7,645)	$ 2,487	$ (24,588)

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Consolidated Statements Of Cash Flows (USD $) In Thousands	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Cash flows from operating activities:
Net income	$ 609,504	$ 449,295
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	294,271	288,737
Exploration expenses, including dry holes	4,275	7,973
Hurricane activity, net		3,500
Deferred income taxes	75,507	220,352
(Gain) loss on disposition of assets, net	2,487	(24,588)
Accretion of discount on asset retirement obligations	5,313	5,388
Discontinued operations	(407,115)	41,463
Interest expense	15,432	14,920
Derivative related activity	56,380	(442,087)
Amortization of stock-based compensation	21,155	19,049
Amortization of deferred revenue	(22,290)	(45,070)
Other noncash items	(18,277)	1,324
Change in operating assets and liabilities
Accounts receivable, net	(23,605)	96,376
Income taxes receivable	27,226	23,440
Inventories	(74,136)	12,479
Prepaid expenses	(9,990)	(10,204)
Other current assets	8,772	(7,192)
Accounts payable	6,201	50,458
Interest payable	(1,642)	7,014
Income taxes payable	(11,485)	(4,470)
Other current liabilities	6,471	(14,943)
Net cash provided by operating activities	564,454	693,214
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold	813,520	297,312
Investment in unconsolidated subsidiary	(82,857)	(108)
Additions to oil and gas properties	(757,148)	(461,502)
Additions to other assets and other property and equipment, net	(215,367)	(74,075)
Net cash used in investing activities	(241,852)	(238,373)
Cash flows from financing activities:
Borrowings under long-term debt	72,610	182,997
Principal payments on long-term debt	(115,810)	(424,107)
Contributions from noncontrolling interests		1,151
Distributions to noncontrolling interests	(13,366)	(13,451)
Payments of other liabilities	(305)	(20,325)
Exercise of long-term incentive plan stock options	362	3,452
Purchases of treasury stock	(39,218)	(13,402)
Excess tax benefits from share-based payment arrangements	27,937	4,090
Payment of financing fees	(8,739)	(145)
Dividends paid	(4,812)	(4,783)
Net cash used in financing activities	(81,341)	(284,523)
Net increase in cash and cash equivalents	241,261	170,318
Cash and cash equivalents, beginning of period	111,160	27,368
Cash and cash equivalents, end of period	$ 352,421	$ 197,686

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Asset Retirement Obligations

6 Months Ended

Jun. 30, 2011

Asset Retirement Obligations

Asset Retirement Obligations

NOTE H. Asset Retirement Obligations

The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells 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, 2011 and 2010:

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in thousands)
Beginning asset retirement obligations	$	154,689		$	142,270		$	152,291		$	166,434
Liabilities assumed in acquisitions		—			6			6			6
New wells placed on production		1,404			4,365			2,075			4,644
Changes in estimates		(179	)		—			121			—
Disposition of wells		(367	)		(3,291	)		(448	)		(29,540	)
Liabilities settled		(6,235	)		(8,801	)		(7,469	)		(9,955	)
Accretion of discount from continuing operations		2,658			2,529			5,313			5,388
Accretion of discount from discontinued operations		—			103			81			204
Ending asset retirement obligations	$	151,970		$	137,181		$	151,970		$	137,181

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, 2011 and December 31, 2010, the current portions of the Company's asset retirement obligations were $14.9 million and $19.9 million, respectively.

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Derivative Financial Instruments (Gas Volume And Weighted Average Price) (Details)	3 Months Ended				12 Months Ended
	Dec. 31, 2011 bbl Mmbtu	Sep. 30, 2011 bbl Mmbtu	Jun. 30, 2011 bbl Mmbtu	Mar. 31, 2011 bbl Mmbtu	Dec. 31, 2011 Mmbtu bbl
2011 - Swap Contracts [Member]
Volume	117,500	117,500			117,500
NYMEX price	6.13	6.13			6.13
2011 - Collar Contracts With Short Puts [Member]
Volume	200,000	200,000			200,000
2011 - Collar Contracts With Short Puts [Member] | Ceiling [Member]
NYMEX price	8.55	8.55			8.55
2011 - Collar Contracts With Short Puts [Member] | Floor [Member]
NYMEX price	6.32	6.32			6.32
2011 - Collar Contracts With Short Puts [Member] | Short Put [Member]
NYMEX price	4.88	4.88			4.88
2011 - Basis Swap Contracts [Member]
Volume	143,500	143,500			143,500
NYMEX price	(0.56)	(0.56)			(0.56)
2012 - Swap Contracts [Member]
Volume	105,000	105,000	105,000	105,000	105,000
NYMEX price	5.82	5.82	5.82	5.82	5.82
2012 - Collar Contracts [Member]
Volume	65,000.00	65,000.00	65,000.00	65,000.00	65,000.00
2012 - Collar Contracts [Member] | Ceiling [Member]
NYMEX price	6.60	6.60	6.60	6.60	6.60
2012 - Collar Contracts [Member] | Floor [Member]
NYMEX price	5.00	5.00	5.00	5.00	5.00
2012 - Collar Contracts With Short Puts [Member]
Volume	190,000	190,000	190,000	190,000	190,000
2012 - Collar Contracts With Short Puts [Member] | Ceiling [Member]
NYMEX price	7.96	7.96	7.96	7.96	7.96
2012 - Collar Contracts With Short Puts [Member] | Floor [Member]
NYMEX price	6.12	6.12	6.12	6.12	6.12
2012 - Collar Contracts With Short Puts [Member] | Short Put [Member]
NYMEX price	4.55	4.55	4.55	4.55	4.55
2012 - Basis Swap Contracts [Member]
Volume	126,000	126,000	126,000	126,000	126,000
NYMEX price	(0.35)	(0.35)	(0.35)	(0.35)	(0.35)
2013 - Swap Contracts [Member]
Volume	67,500	67,500	67,500	67,500	67,500
NYMEX price	6.11	6.11	6.11	6.11	6.11
2013 - Collar Contracts [Member]
Volume	150,000	150,000	150,000	150,000	150,000
2013 - Collar Contracts [Member] | Ceiling [Member]
NYMEX price	6.25	6.25	6.25	6.25	6.25
2013 - Collar Contracts [Member] | Floor [Member]
NYMEX price	5.00	5.00	5.00	5.00	5.00
2013 - Collar Contracts With Short Puts [Member]
Volume	45,000	45,000	45,000	45,000	45,000
2013 - Collar Contracts With Short Puts [Member] | Ceiling [Member]
NYMEX price	7.49	7.49	7.49	7.49	7.49
2013 - Collar Contracts With Short Puts [Member] | Floor [Member]
NYMEX price	6.00	6.00	6.00	6.00	6.00
2013 - Collar Contracts With Short Puts [Member] | Short Put [Member]
NYMEX price	4.50	4.50	4.50	4.50	4.50
2013 - Basis Swap Contracts [Member]
Volume	52,500	52,500	52,500	52,500	52,500
NYMEX price	(0.25)	(0.25)	(0.25)	(0.25)	(0.25)
2014 - Swap Contracts [Member]
Volume	50,000	50,000	50,000	50,000	50,000
NYMEX price	6.05	6.05	6.05	6.05	6.05
2014 - Collar Contracts [Member]
Volume	140,000	140,000	140,000	140,000	140,000
2014 - Collar Contracts [Member] | Ceiling [Member]
NYMEX price	6.44	6.44	6.44	6.44	6.44
2014 - Collar Contracts [Member] | Floor [Member]
NYMEX price	5.00	5.00	5.00	5.00	5.00
2014 - Collar Contracts With Short Puts [Member]
Volume	50,000	50,000	50,000	50,000	50,000
2014 - Collar Contracts With Short Puts [Member] | Ceiling [Member]
NYMEX price	8.08	8.08	8.08	8.08	8.08
2014 - Collar Contracts With Short Puts [Member] | Floor [Member]
NYMEX price	6.00	6.00	6.00	6.00	6.00
2014 - Collar Contracts With Short Puts [Member] | Short Put [Member]
NYMEX price	4.50	4.50	4.50	4.50	4.50
2014 - Basis Swap Contracts [Member]
Volume	20,000	20,000	20,000	20,000	20,000
NYMEX price	(0.14)	(0.14)	(0.14)	(0.14)	(0.14)
2015 - Collar contracts [Member]
Volume	50,000	50,000	50,000	50,000	50,000
2015 - Collar contracts [Member] | Ceiling [Member]
NYMEX price	7.92	7.92	7.92	7.92	7.92
2015 - Collar contracts [Member] | Floor [Member]
NYMEX price	5.00	5.00	5.00	5.00	5.00

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Asset Retirement Obligations (Asset Retirement Obligations) (Details) (USD $)	3 Months Ended			6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010		Jun. 30, 2011		Jun. 30, 2010		Dec. 31, 2010
Asset Retirement Obligations
Beginning asset retirement obligations	$ 154,689,000	$ 142,270,000		$ 152,291,000		$ 166,434,000
Liabilities assumed in acquisitions		6,000		6,000		6,000
New wells placed on production	1,404,000	4,365,000		2,075,000		4,644,000
Changes in estimates	(179,000)			121,000
Disposition of wells	(367,000)	(3,291,000)		(448,000)		(29,540,000)
Liabilities settled	(6,235,000)	(8,801,000)		(7,469,000)		(9,955,000)
Accretion of discount from continuing operations	2,658,000	2,529,000		5,313,000		5,388,000
Accretion of discount from discontinued operations		103,000	[1]	81,000	[1]	204,000	[1]
Ending asset retirement obligations	151,970,000	137,181,000		151,970,000		137,181,000
Asset retirement obligations, current portion	$ 14,900,000			$ 14,900,000				$ 19,900,000

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

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Interest And Other Income (Interest And Other Income) (Details) (USD $) In Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2011		Jun. 30, 2010		Jun. 30, 2011		Jun. 30, 2010
Interest And Other Income
Alaskan Petroleum Production Tax credits			$ 13,613	[1]	$ 27,452	[1]	$ 27,861	[1]
Third-party income from vertical integration services	13,725	[2]	998	[2]	16,603	[2]	1,507	[2]
Deferred compensation plan income	299		174		1,166		684
Other income	1,912		1,131		2,913		1,783
Eagle Ford Shale land fees	1,802				1,802
Equity interest in income of unconsolidated affiliate	502				801
Interest income	214		92		404		476
Sales and other tax refunds			944				984
Insurance claim recovery							1,665
Total interest and other income	$ 18,454		$ 16,952		$ 51,141		$ 34,960

[1] 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.

[2] Third-party income from vertical integration services primarily represents income associated with Company-provided fracture stimulation, drilling and related services.

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Postretirement Benefit Obligations (Tables)

6 Months Ended

Jun. 30, 2011

Postretirement Benefit Obligations

Accumulated Postretirement Benefit Obligations

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in thousands)
Beginning accumulated postretirement benefit obligations	$	7,231		$	8,951		$	7,408		$	9,075
Net benefit payments		(375	)		(272	)		(691	)		(584	)
Service costs		61			81			122			161
Net actuarial losses		—			100			—			100
Accretion of interest		79			108			157			216
Ending accumulated postretirement benefit obligations	$	6,996		$	8,968		$	6,996		$	8,968

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Geographic Operating Segment Information

6 Months Ended

Jun. 30, 2011

Geographic Operating Segment Information

Geographic Operating Segment Information

NOTE L.  Geographic Operating Segment Information

The Company has reportable operations in only one industry segment, that being the oil and gas exploration and production industry; however, the Company is organizationally structured along geographic operating segments or regions. The Company has reportable continuing operations in the United States and South Africa.

The following tables provide the Company's geographic operating segment data for the three and six months ended June 30, 2011 and 2010. Geographic operating segment income tax (provisions) benefits have been determined based on statutory rates existing in the various tax jurisdictions where the Company has oil and gas producing activities. The "Headquarters" table column includes income and expenses that are not routinely included in the earnings measures internally reported to management on a geographic operating segment basis.

	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Three Months Ended June 30, 2011
Revenues and other income:
Oil and gas	$	562,411		$	21,520		$			$	583,931
Interest and other		13,725						4,729			18,454
Loss on disposition of assets, net								(296	)		(296	)
		576,136			21,520			4,433			602,089
Costs and expenses:
Oil and gas production		101,741			714						102,455
Production and ad valorem taxes		35,864									35,864
Depletion, depreciation and amortization		127,864			13,536			12,498			153,898
Exploration and abandonments		19,731			183						19,914
General and administrative								44,644			44,644
Accretion of discount on asset retirement obligations		2,047			611						2,658
Interest								45,768			45,768
Hurricane activity, net		(2	)								(2	)
Derivative gains, net								(229,478	)		(229,478	)
Other		5,410						8,978			14,388
		292,655			15,044			(117,590	)		190,109
Income from continuing operations before income taxes		283,481			6,476			122,023			411,980
Income tax provision		(104,888	)		(1,813	)		(37,995	)		(144,696	)
Income from continuing operations	$	178,593		$	4,663		$	84,028		$	267,284
	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Three Months Ended June 30, 2010
Revenues and other income:
Oil and gas	$	401,540		$	20,502		$			$	422,042
Interest and other		998						15,954			16,952
Gain on disposition of assets, net		7,560						85			7,645
		410,098			20,502			16,039			446,639
Costs and expenses:
Oil and gas production		93,116			896						94,012
Production and ad valorem taxes		25,338									25,338
Depletion, depreciation and amortization		117,859			18,442			8,008			144,309
Exploration and abandonments		22,689			54						22,743
General and administrative								40,433			40,433
Accretion of discount on asset retirement obligations		1,907			622						2,529
Interest								45,368			45,368
Hurricane activity, net		5,184									5,184
Derivative gains, net								(177,528	)		(177,528	)
Other		10,270						3,923			14,193
		276,363			20,014			(79,796	)		216,581
Income from continuing operations before income taxes		133,735			488			95,835			230,058
Income tax provision		(49,482	)		(137	)		(33,601	)		(83,220	)
Income from continuing operations	$	84,253		$	351		$	62,234		$	146,838
	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Six Months Ended June 30, 2011
Revenues and other income:
Oil and gas	$	1,038,140		$	42,921		$			$	1,081,061
Interest and other		16,603						34,538			51,141
Loss on disposition of assets, net								(2,487	)		(2,487	)
		1,054,743			42,921			32,051			1,129,715
Costs and expenses:
Oil and gas production		200,576			1,810						202,386
Production and ad valorem taxes		69,160									69,160
Depletion, depreciation and amortization		244,404			27,221			22,646			294,271
Exploration and abandonments		37,216			341						37,557
General and administrative								88,750			88,750
Accretion of discount on asset retirement obligations		4,091			1,222						5,313
Interest								90,995			90,995
Hurricane activity, net		69									69
Derivative losses, net								14,954			14,954
Other		10,569						21,700			32,269
		566,085			30,594			239,045			835,724
Income (loss) from continuing operations before income taxes		488,658			12,327			(206,994	)		293,991
Income tax benefit (provision)		(180,803	)		(3,452	)		86,710			(97,545	)
Income (loss) from continuing operations	$	307,855		$	8,875		$	(120,284	)	$	196,446
	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Six Months Ended June 30, 2010
Revenues and other income:
Oil and gas	$	848,204		$	45,883		$			$	894,087
Interest and other		1,507						33,453			34,960
Gain (loss) on disposition of assets, net		24,979						(391	)		24,588
		874,690			45,883			33,062			953,635
Costs and expenses:
Oil and gas production		178,440			1,672						180,112
Production and ad valorem taxes		52,399									52,399
Depletion, depreciation and amortization		233,364			40,339			15,034			288,737
Exploration and abandonments		39,465			126						39,591
General and administrative								78,748			78,748
Accretion of discount on asset retirement obligations		4,144			1,244						5,388
Interest								92,891			92,891
Hurricane activity, net		(2,226	)								(2,226	)
Derivative gains, net								(443,004	)		(443,004	)
Other		20,551						9,588			30,139
		526,137			43,381			(246,743	)		322,775
Income from continuing operations before income taxes		348,553			2,502			279,805			630,860
Income tax provision		(128,965	)		(701	)		(97,561	)		(227,227	)
Income from continuing operations	$	219,588		$	1,801		$	182,244		$	403,633

	June 30, 2011		December 31, 2010
	(in thousands)
Consolidating Assets by Geographic Area:
United States	$	10,222,200	$	8,987,141
South Africa		85,017		134,901
Tunisia				325,942
Headquarters		45,871		231,118
Total consolidated assets	$	10,353,088	$	9,679,102

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Consolidated Balance Sheets (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 352,421	$ 111,160
Accounts receivable:
Trade, net of allowance for doubtful accounts of $1,056 and $1,155 as of June 30, 2011 and December 31, 2010, respectively	266,476	237,511
Due from affiliates	2,702	7,792
Income taxes receivable	3,674	30,901
Inventories	234,108	173,615
Prepaid expenses	21,342	11,441
Deferred income taxes	163	156,650
Discontinued operations held for sale		281,741
Other current assets:
Derivatives	154,129	171,679
Other	36,092	14,693
Total current assets	1,071,107	1,197,183
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	11,541,101	10,739,114
Unproved properties	213,230	191,112
Accumulated depletion, depreciation and amortization	(3,637,605)	(3,366,440)
Total property, plant and equipment	8,116,726	7,563,786
Deferred income taxes	1,878
Goodwill	298,177	298,182
Other property and equipment, net	431,214	283,542
Other assets:
Investment in unconsolidated affiliate	155,701	72,045
Derivatives	142,361	151,011
Other, net of allowance for doubtful accounts of $358 and $2,519 as of June 30, 2011 and December 31, 2010, respectively	135,924	113,353
Assets, Total	10,353,088	9,679,102
Accounts payable:
Trade	490,434	354,890
Due to affiliates	26,962	64,260
Interest payable	57,366	59,008
Income taxes payable	5,927	19,168
Deferred income taxes	19,588	1,144
Discontinued operations held for sale		108,592
Other current liabilities:
Derivatives	76,008	80,997
Deferred revenue	43,580	44,951
Other	35,776	36,210
Total current liabilities	755,641	769,220
Long-term debt	2,570,978	2,601,670
Derivatives	108,075	56,574
Deferred income taxes	1,844,503	1,751,310
Deferred revenue	21,150	42,069
Other liabilities	236,777	232,234
Stockholders' equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 127,554,683 and 126,212,256 shares issued at June 30, 2011 and December 31, 2010, respectively	1,276	1,262
Additional paid-in capital	3,070,827	3,022,768
Treasury stock, at cost: 11,311,097 and 10,903,743 at June 30, 2011 and December 31, 2010, respectively	(459,657)	(421,235)
Retained earnings	2,099,623	1,510,427
Accumulated other comprehensive income - net deferred hedge gains, net of tax	2,863	7,361
Total stockholders' equity attributable to common stockholders	4,714,932	4,120,583
Noncontrolling interest in net assets subsidiaries	101,032	105,442
Total stockholders' equity	4,815,964	4,226,025
Commitments and contingencies
Liabilities and Stockholders' Equity, Total	$ 10,353,088	$ 9,679,102

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Geographic Operating Segment Information (Tables)

6 Months Ended

Jun. 30, 2011

Geographic Operating Segment Information

Schedule Of Income Statement By Geographic Operating Segment

	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Three Months Ended June 30, 2011
Revenues and other income:
Oil and gas	$	562,411		$	21,520		$			$	583,931
Interest and other		13,725						4,729			18,454
Loss on disposition of assets, net								(296	)		(296	)
		576,136			21,520			4,433			602,089
Costs and expenses:
Oil and gas production		101,741			714						102,455
Production and ad valorem taxes		35,864									35,864
Depletion, depreciation and amortization		127,864			13,536			12,498			153,898
Exploration and abandonments		19,731			183						19,914
General and administrative								44,644			44,644
Accretion of discount on asset retirement obligations		2,047			611						2,658
Interest								45,768			45,768
Hurricane activity, net		(2	)								(2	)
Derivative gains, net								(229,478	)		(229,478	)
Other		5,410						8,978			14,388
		292,655			15,044			(117,590	)		190,109
Income from continuing operations before income taxes		283,481			6,476			122,023			411,980
Income tax provision		(104,888	)		(1,813	)		(37,995	)		(144,696	)
Income from continuing operations	$	178,593		$	4,663		$	84,028		$	267,284
	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Three Months Ended June 30, 2010
Revenues and other income:
Oil and gas	$	401,540		$	20,502		$			$	422,042
Interest and other		998						15,954			16,952
Gain on disposition of assets, net		7,560						85			7,645
		410,098			20,502			16,039			446,639
Costs and expenses:
Oil and gas production		93,116			896						94,012
Production and ad valorem taxes		25,338									25,338
Depletion, depreciation and amortization		117,859			18,442			8,008			144,309
Exploration and abandonments		22,689			54						22,743
General and administrative								40,433			40,433
Accretion of discount on asset retirement obligations		1,907			622						2,529
Interest								45,368			45,368
Hurricane activity, net		5,184									5,184
Derivative gains, net								(177,528	)		(177,528	)
Other		10,270						3,923			14,193
		276,363			20,014			(79,796	)		216,581
Income from continuing operations before income taxes		133,735			488			95,835			230,058
Income tax provision		(49,482	)		(137	)		(33,601	)		(83,220	)
Income from continuing operations	$	84,253		$	351		$	62,234		$	146,838
	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Six Months Ended June 30, 2011
Revenues and other income:
Oil and gas	$	1,038,140		$	42,921		$			$	1,081,061
Interest and other		16,603						34,538			51,141
Loss on disposition of assets, net								(2,487	)		(2,487	)
		1,054,743			42,921			32,051			1,129,715
Costs and expenses:
Oil and gas production		200,576			1,810						202,386
Production and ad valorem taxes		69,160									69,160
Depletion, depreciation and amortization		244,404			27,221			22,646			294,271
Exploration and abandonments		37,216			341						37,557
General and administrative								88,750			88,750
Accretion of discount on asset retirement obligations		4,091			1,222						5,313
Interest								90,995			90,995
Hurricane activity, net		69									69
Derivative losses, net								14,954			14,954
Other		10,569						21,700			32,269
		566,085			30,594			239,045			835,724
Income (loss) from continuing operations before income taxes		488,658			12,327			(206,994	)		293,991
Income tax benefit (provision)		(180,803	)		(3,452	)		86,710			(97,545	)
Income (loss) from continuing operations	$	307,855		$	8,875		$	(120,284	)	$	196,446
	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Six Months Ended June 30, 2010
Revenues and other income:
Oil and gas	$	848,204		$	45,883		$			$	894,087
Interest and other		1,507						33,453			34,960
Gain (loss) on disposition of assets, net		24,979						(391	)		24,588
		874,690			45,883			33,062			953,635
Costs and expenses:
Oil and gas production		178,440			1,672						180,112
Production and ad valorem taxes		52,399									52,399
Depletion, depreciation and amortization		233,364			40,339			15,034			288,737
Exploration and abandonments		39,465			126						39,591
General and administrative								78,748			78,748
Accretion of discount on asset retirement obligations		4,144			1,244						5,388
Interest								92,891			92,891
Hurricane activity, net		(2,226	)								(2,226	)
Derivative gains, net								(443,004	)		(443,004	)
Other		20,551						9,588			30,139
		526,137			43,381			(246,743	)		322,775
Income from continuing operations before income taxes		348,553			2,502			279,805			630,860
Income tax provision		(128,965	)		(701	)		(97,561	)		(227,227	)
Income from continuing operations	$	219,588		$	1,801		$	182,244		$	403,633

Reconciliation Of Assets From Segment To Consolidated

	June 30, 2011		December 31, 2010
	(in thousands)
Consolidating Assets by Geographic Area:
United States	$	10,222,200	$	8,987,141
South Africa		85,017		134,901
Tunisia				325,942
Headquarters		45,871		231,118
Total consolidated assets	$	10,353,088	$	9,679,102

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Income Taxes (Income Tax (Provisions) Benefits) (Details) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Income Taxes
U.S. federal		$ (2,199)		$ (3,301)
U.S. state	(2,538)	(1,800)	(4,936)	(3,124)
Foreign	(10,782)	(413)	(17,102)	(450)
Current income tax (provision) benefit	(13,320)	(4,412)	(22,038)	(6,875)
U.S. federal	(140,948)	(71,929)	(100,160)	(203,056)
U.S. state	304	(7,040)	10,729	(16,500)
Foreign	9,268	161	13,924	(796)
Deferred income tax (provision) benefit	(131,376)	(78,808)	(75,507)	(220,352)
Income tax provision	$ (144,696)	$ (83,220)	$ (97,545)	$ (227,227)

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Derivative Financial Instruments (Derivative Instruments) (Details) (Not Designated As Hedging Instruments [Member], USD $) In Thousands	Jun. 30, 2011		Dec. 31, 2010
Total derivatives, Asset	$ 319,862	[1]	$ 347,802	[1]
Total derivatives, Liability	207,455	[1]	162,683	[1]
Interest Rate Derivatives [Member] | Derivatives - Current [Member]
Total derivatives, Asset	12,253	[1]	11,903	[1]
Total derivatives, Liability			886	[1]
Interest Rate Derivatives [Member] | Derivatives - Noncurrent [Member]
Total derivatives, Asset	17,870	[1]	15,762	[1]
Total derivatives, Liability	5,177	[1]	9,227	[1]
Commodity Price Derivatives [Member] | Derivatives - Current [Member]
Total derivatives, Asset	153,812	[1]	167,406	[1]
Total derivatives, Liability	87,944	[1]	87,741	[1]
Commodity Price Derivatives [Member] | Derivatives - Noncurrent [Member]
Total derivatives, Asset	135,927	[1]	152,731	[1]
Total derivatives, Liability	$ 114,334	[1]	$ 64,829	[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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Volumetric Production Payments (Revenue Recognition In Future Periods) (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Remaining 2011	$ 43,580	$ 44,951
2012	21,150	42,069
Volumetric Production Payment [Member]
Remaining 2011	22,659
2012	$ 42,071

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Disclosures About Fair Value Measurements (Assets And Liabilities That Are Measured At Fair Value On A Recurring Basis) (Details) (USD $)	6 Months Ended
	Jun. 30, 2011
Assets, (Fair Value, Total)	$ 367,151,000
Liabilities, (Fair Value, Total)	3,282,392,000
Swap contract notional amount fixed rate of interest and variable LIBOR	470,000,000
Proceeds from termination of interest rate derivatives	26,100,000
Interest Rate Derivatives [Member]
Assets, (Fair Value, Total)	24,946,000	[1]
Interest Rate Derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets, (Fair Value, Total)	24,946,000	[1]
Pioneer Southwest Credit Facility [Member]
Liabilities, (Fair Value, Total)	84,542,000
Pioneer Southwest Credit Facility [Member] | Significant Other Observable Inputs (Level 2) [Member]
Liabilities, (Fair Value, Total)	84,542,000
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Assets, (Fair Value, Total)	40,512,000
Liabilities, (Fair Value, Total)	3,013,767,000
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | Trading Securities [Member]
Assets, (Fair Value, Total)	289,000
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | Deferred Compensation Plan Assets [Member]
Assets, (Fair Value, Total)	40,223,000
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | 5.875% Senior Notes Due 2016 [Member]
Liabilities, (Fair Value, Total)	482,139,000
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | 6.65% Senior Notes Due 2017 [Member]
Liabilities, (Fair Value, Total)	529,972,000
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | 6.875% Senior Notes Due 2018 [Member]
Liabilities, (Fair Value, Total)	496,698,000
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | 7.50% Senior Notes Due 2020 [Member]
Liabilities, (Fair Value, Total)	512,158,000
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | 7.20% Senior Notes Due 2028 [Member]
Liabilities, (Fair Value, Total)	250,000,000
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | 2.875% Convertible Senior Notes Due 2038 [Member]
Liabilities, (Fair Value, Total)	742,800,000	[2]
Significant Other Observable Inputs (Level 2) [Member]
Assets, (Fair Value, Total)	326,639,000
Liabilities, (Fair Value, Total)	255,274,000
Significant Other Observable Inputs (Level 2) [Member] | Trading Securities [Member]
Assets, (Fair Value, Total)	30,149,000
Significant Other Observable Inputs (Level 2) [Member] | Commodity Derivatives [Member]
Assets, (Fair Value, Total)	271,544,000
Liabilities, (Fair Value, Total)	170,732,000
Significant Unobservable Inputs (Level 3) [Member]
Liabilities, (Fair Value, Total)	13,351,000
Significant Unobservable Inputs (Level 3) [Member] | Commodity Derivatives [Member]
Liabilities, (Fair Value, Total)	13,351,000
Trading Securities [Member]
Assets, (Fair Value, Total)	30,438,000
Commodity Derivatives [Member]
Assets, (Fair Value, Total)	271,544,000
Liabilities, (Fair Value, Total)	184,083,000
Deferred Compensation Plan Assets [Member]
Assets, (Fair Value, Total)	40,223,000
5.875% Senior Notes Due 2016 [Member]
Liabilities, (Fair Value, Total)	482,139,000
Senior notes, interest rate	5.875%
Debt instrument expiration date	2016
6.65% Senior Notes Due 2017 [Member]
Liabilities, (Fair Value, Total)	529,972,000
Senior notes, interest rate	6.65%
Debt instrument expiration date	2017
6.875% Senior Notes Due 2018 [Member]
Liabilities, (Fair Value, Total)	496,698,000
Senior notes, interest rate	6.875%
Debt instrument expiration date	2018
7.50% Senior Notes Due 2020 [Member]
Liabilities, (Fair Value, Total)	512,158,000
Senior notes, interest rate	7.50%
Debt instrument expiration date	2020
7.20% Senior Notes Due 2028 [Member]
Liabilities, (Fair Value, Total)	250,000,000
Senior notes, interest rate	7.20%
Debt instrument expiration date	2028
2.875% Convertible Senior Notes Due 2038 [Member]
Liabilities, (Fair Value, Total)	$ 742,800,000	[2]
Senior notes, interest rate	2.875%
Debt instrument expiration date	2038

[1] Subsequent to June 30, 2011, the Company terminated the interest rate derivatives shown in the table above and received $26.1 million of proceeds. See Note G for additional information about the Company's interest rate derivatives.

[2] The fair value of the 2.875% senior convertible notes includes the fair value of the conversion privilege.

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Disclosures About Fair Value Measurements (Fair Value Measurements Using Significant Unobservable Inputs) (Details) (NGL Swap Contracts [Member], USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011		Jun. 30, 2011
NGL Swap Contracts [Member]
Beginning liability balance	$ (16,675)		$ (9,556)
Net unrealized gains (losses) included in earnings	3,324	[1]	(3,795)	[1]
Net realized losses included in earnings	(4,629)	[1]	(7,325)	[1]
Settlement payments	4,629		7,325
Ending liability balance	$ (13,351)		$ (13,351)

[1] Non-hedge derivatives gains and losses are included in net derivative (gains) losses in the accompanying consolidated statements of operations.

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Derivative Financial Instruments (Natural Gas Liquids Volume And Weighted Average Price) (Details)	3 Months Ended				12 Months Ended
	Dec. 31, 2011 bbl Mmbtu	Sep. 30, 2011 bbl Mmbtu	Jun. 30, 2011 bbl Mmbtu	Mar. 31, 2011 bbl Mmbtu	Dec. 31, 2011 Mmbtu bbl
2011 - Swap Contracts [Member]
Volume	1,150	1,150			1,150
Index price	51.50	51.50			51.50
2011 - Collar Contracts [Member]
Volume	2,650	2,650			2,650
2011 - Collar Contracts [Member] | Ceiling [Member]
Index price	64.23	64.23			64.23
2011 - Collar Contracts [Member] | Floor [Member]
Index price	53.29	53.29			53.29
2012 - Swap Contracts [Member]
Volume	750	750	750	750	750
Index price	35.03	35.03	35.03	35.03	35.03

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Volumetric Production Payments (Tables)

6 Months Ended

Jun. 30, 2011

Volumetric Production Payments

Deferred Revenue Carrying Values

Deferred revenue at December 31, 2010	$	87,020
Less: 2011 amortization		(22,290	)
Deferred revenue at June 30, 2011	$	64,730

Revenue Recognition In Future Periods

Remaining 2011	$	22,659
2012	$	42,071