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 September 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 November 1, 2011 116,881,280

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 September 30, 2011 and December 31, 2010		5
	Consolidated Statements of Operations for the three and nine months ended September 30, 2011 and 2010		7
	Consolidated Statement of Stockholders’ Equity for the nine months ended September 30, 2011		8
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2011 and 2010		9
	Consolidated Statements of Comprehensive Income for the three and nine months ended September 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		36
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		51
Item 4.	Controls and Procedures		54
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings		55
Item 1A.	Risk Factors		55
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		56
Item 6.	Exhibits		57
Signatures			58
Exhibit Index			59

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 and “Part II, Item 1A. Risk Factors” in the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 for a description of various factors that could materially affect the ability of Pioneer to achieve the anticipated results described in the forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. The Company undertakes no duty to publicly update these statements except as required by law.

3

PIONEER NATURAL RESOURCES COMPANY

Definitions of Certain Terms and Conventions Used Herein

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

• “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.

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

• “BOEPD” means BOE per day.

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

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

• “DD&A” means depletion, depreciation and amortization.

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

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

• “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 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)

	September 30, 2011			December 31, 2010
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	210,565		$	111,160
Accounts receivable:
Trade, net of allowance for doubtful accounts of $755 and $1,155 as of September 30, 2011 and December 31, 2010, respectively		272,154			237,511
Due from affiliates		6,034			7,792
Income taxes receivable		2,312			30,901
Inventories		260,356			173,615
Prepaid expenses		18,910			11,441
Deferred income taxes		92,140			156,650
Discontinued operations held for sale		—			281,741
Other current assets:
Derivatives		234,806			171,679
Other		6,366			14,693
Total current assets		1,103,643			1,197,183
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties		12,092,300			10,739,114
Unproved properties		249,537			191,112
Accumulated depletion, depreciation and amortization		(3,788,686	)		(3,366,440	)
Total property, plant and equipment		8,553,151			7,563,786
Deferred income taxes		7,358			—
Goodwill		298,154			298,182
Other property and equipment, net		500,709			283,542
Other assets:
Investment in unconsolidated affiliate		164,107			72,045
Derivatives		224,754			151,011
Other, net of allowance for doubtful accounts of $348 and $2,519 as of September 30, 2011 and December 31, 2010, respectively		133,167			113,353
	$	10,985,043		$	9,679,102

The financial information included as of September 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)

	September 30, 2011			December 31, 2010
	(Unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	583,383		$	354,890
Due to affiliates		48,421			64,260
Interest payable		33,955			59,008
Income taxes payable		15,604			19,168
Deferred income taxes		—			1,144
Discontinued operations held for sale		—			108,592
Other current liabilities:
Derivatives		12,377			80,997
Deferred revenue		42,825			44,951
Other		39,552			36,210
Total current liabilities		776,117			769,220
Long-term debt		2,587,371			2,601,670
Derivatives		16,946			56,574
Deferred income taxes		2,133,147			1,751,310
Deferred revenue		46,701			42,069
Other liabilities		228,094			232,234
Stockholders’ equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 127,614,963 and 126,212,256 shares issued at September 30, 2011 and December 31, 2010, respectively		1,276			1,262
Additional paid-in capital		3,082,058			3,022,768
Treasury stock, at cost: 11,264,660 and 10,903,743 at September 30, 2011 and December 31, 2010, respectively		(458,258	)		(421,235	)
Retained earnings		2,446,217			1,510,427
Accumulated other comprehensive income (loss) - net deferred hedge gains (losses), net of tax		(58	)		7,361
Total stockholders’ equity attributable to common stockholders		5,071,235			4,120,583
Noncontrolling interests in consolidating subsidiaries		125,432			105,442
Total stockholders’ equity		5,196,667			4,226,025
Commitments and contingencies
	$	10,985,043		$	9,679,102

The financial information included as of September 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 September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Revenues and other income:
Oil and gas	$	610,509		$	437,411		$	1,691,570		$	1,331,498
Interest and other		17,573			14,969			68,714			49,929
Derivative gains, net		401,072			127,581			386,118			570,585
Gain (loss) on disposition of assets, net		1,048			2,383			(1,439	)		26,971
Hurricane activity, net		1,487			3,452			1,418			5,678
		1,031,689			585,796			2,146,381			1,984,661
Costs and expenses:
Oil and gas production		119,609			100,717			321,995			280,829
Production and ad valorem taxes		38,542			33,045			107,702			85,444
Depletion, depreciation and amortization		166,536			147,096			460,807			435,833
Exploration and abandonments		20,026			21,610			57,583			61,201
General and administrative		49,812			43,417			138,562			122,165
Accretion of discount on asset retirement obligations		2,806			2,521			8,119			7,909
Interest		45,559			45,002			136,554			137,893
Other		17,183			19,687			49,452			49,826
		460,073			413,095			1,280,774			1,181,100
Income from continuing operations before income taxes		571,616			172,701			865,607			803,561
Income tax provision		(185,471	)		(76,211	)		(283,016	)		(303,438	)
Income from continuing operations		386,145			96,490			582,591			500,123
Income (loss) from discontinued operations, net of tax		(547	)		18,083			412,511			63,745
Net income		385,598			114,573			995,102			563,868
Net income attributable to the noncontrolling interests		(34,134	)		(2,538	)		(49,467	)		(39,003	)
Net income attributable to common stockholders	$	351,464		$	112,035		$	945,635		$	524,865
Basic earnings per share:
Income from continuing operations attributable to common stockholders	$	2.96		$	0.80		$	4.51		$	3.92
Income (loss) from discontinued operations attributable to common stockholders		—			0.15			3.49			0.54
Net income attributable to common stockholders	$	2.96		$	0.95		$	8.00		$	4.46
Diluted earnings per share:
Income from continuing operations attributable to common stockholders	$	2.95		$	0.79		$	4.42		$	3.89
Income (loss) from discontinued operations attributable to common stockholders		—			0.15			3.43			0.54
Net income attributable to common stockholders	$	2.95		$	0.94		$	7.85		$	4.43
Weighted average shares outstanding:
Basic		116,281			115,191			116,122			114,985
Diluted		117,075			116,021			118,350			115,832
Dividends declared per share	$	0.04		$	0.04		$	0.08		$	0.08
Amounts attributable to common stockholders:
Income from continuing operations	$	352,011		$	93,952		$	533,124		$	461,120
Income (loss) from discontinued operations, net of tax		(547	)		18,083			412,511			63,745
Net income	$	351,464		$	112,035		$	945,635		$	524,865

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)

	Shares Outstanding			Stockholders’ Equity Attributable To Common Stockholders														Noncontrolling Interests			Total Stockholders’ Equity
				Common Stock		Additional Paid-in Capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income (Loss)
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 ($0.08 per share)		—			—		—			—			(9,493	)		—			—			(9,493	)
Exercise of long-term incentive plan stock options and employee stock purchases		79			—		951			3,091			(352	)		—			—			3,690
Treasury stock purchases		(439	)		—		—			(40,128	)		—			—			(198	)		(40,326	)
Conversion of 2.875% senior convertible notes		—			—		(20	)		14			—			—			—			(6	)
Tax benefit related to stock-based compensation		—			—		28,123			—			—			—			—			28,123
Disposition of subsidiary		—			—		(510	)		—			—			—			—			(510	)
Compensation costs:
Vested compensation awards, net		1,401			14		(14	)		—			—			—			—			—
Compensation costs included in net income		—			—		30,760			—			—			—			940			31,700
Cash distributions to noncontrolling interests		—			—		—			—			—			—			(19,944	)		(19,944	)
Net income		—			—		—			—			945,635			—			49,467			995,102
Other comprehensive activity:
Deferred hedging activity, net of tax:
Net hedge gains included in continuing operations		—			—		—			—			—			(7,419	)		(10,275	)		(17,694	)
Balance as of September 30, 2011		116,350		$	1,276	$	3,082,058		$	(458,258	)	$	2,446,217		$	(58	)	$	125,432		$	5,196,667

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)

	Nine Months Ended September 30,
	2011			2010
Cash flows from operating activities:
Net income	$	995,102		$	563,868
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization		460,807			435,833
Exploration expenses, including dry holes		6,008			16,655
Hurricane activity, net		—			3,500
Deferred income taxes		249,040			283,283
(Gain) loss on disposition of assets, net		1,439			(26,971	)
Accretion of discount on asset retirement obligations		8,119			7,909
Discontinued operations		(407,353	)		43,339
Interest expense		23,412			22,567
Derivative related activity		(269,746	)		(549,387	)
Amortization of stock-based compensation		31,525			28,631
Amortization of deferred revenue		(33,620	)		(67,739	)
Other noncash items		(15,773	)		10,440
Change in operating assets and liabilities
Accounts receivable, net		(35,252	)		97,873
Income taxes receivable		28,588			16,689
Inventories		(115,961	)		(6,459	)
Prepaid expenses		(7,558	)		(8,975	)
Other current assets		8,520			2,162
Accounts payable		83,632			62,349
Interest payable		(25,053	)		(13,211	)
Income taxes payable		(1,807	)		1,307
Other current liabilities		45,969			(21,941	)
Net cash provided by operating activities		1,030,038			901,722
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold		819,638			297,742
Investment in unconsolidated subsidiary		(89,620	)		(15,651	)
Additions to oil and gas properties		(1,319,131	)		(714,014	)
Additions to other assets and other property and equipment, net		(265,740	)		(132,279	)
Net cash used in investing activities		(854,853	)		(564,202	)
Cash flows from financing activities:
Borrowings under long-term debt		102,616			199,784
Principal payments on long-term debt		(135,883	)		(438,894	)
Contributions from noncontrolling interests		—			1,151
Distributions to noncontrolling interests		(19,944	)		(20,160	)
Payments of other liabilities		(503	)		(20,668	)
Exercise of long-term incentive plan stock options		3,690			6,736
Purchases of treasury stock		(40,326	)		(13,776	)
Excess tax benefits from share-based payment arrangements		28,123			4,032
Payment of financing fees		(8,741	)		(145	)
Dividends paid		(4,812	)		(4,783	)
Net cash used in financing activities		(75,780	)		(286,723	)
Net increase in cash and cash equivalents		99,405			50,797
Cash and cash equivalents, beginning of period		111,160			27,368
Cash and cash equivalents, end of period	$	210,565		$	78,165

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 September 30,						Nine Months  Ended September 30,
	2011			2010			2011			2010
Net income	$	385,598		$	114,573		$	995,102		$	563,868
Other comprehensive activity:
Net hedge gains included in continuing operations		(8,224	)		(21,913	)		(24,418	)		(63,536	)
Income tax provision		1,838			5,988			6,724			17,060
Other comprehensive activity		(6,386	)		(15,925	)		(17,694	)		(46,476	)
Comprehensive income		379,212			98,648			977,408			517,392
Comprehensive (income) loss attributable to the noncontrolling interests		(30,670	)		1,898			(39,192	)		(25,860	)
Comprehensive income attributable to common stockholders	$	348,542		$	100,546		$	938,216		$	491,532

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

September 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 September 30, 2011 and for the three and nine months ended September 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.

Certain reclassifications have been made to the 2010 financial statement and footnote amounts in order to conform to the 2011 presentations.

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 nine months ended September 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 nine months ended September 30, 2010, which were originally classified as continuing operations). See Note Q for more information regarding the sale of Pioneer Tunisia.

During the nine months ended September 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 September 30, 2011 and December 31, 2010, the Company’s allowances for doubtful accounts totaled $1.1 million and $3.7 million, respectively. Changes in the Company’s allowance for doubtful accounts during the three and nine months ended September 30, 2011 are summarized in the following table:

	Three Months  Ended September 30, 2011			Nine Months  Ended September 30, 2011
	(in thousands)
Beginning allowance for doubtful accounts balance	$	1,414		$	3,674
Amount recorded in other expense for bad debt expense (recoveries)		51			(1,746	)
Other net decreases		(362	)		(825	)
Ending allowance for doubtful accounts balance	$	1,103		$	1,103

Inventories. Inventories used in continuing operations consisted of $283.3 million and $183.4 million of materials and supplies and $4.2 million and $3.9 million of commodities as of September 30, 2011 and December 31, 2010, respectively. As of September 30, 2011 and December 31, 2010, the Company’s materials and supplies inventory was net of $1.0 million and $3.6 million, respectively, of valuation reserve allowances. As of September 30,

11

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

2011 and December 31, 2010, the Company estimated that $27.2 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 (loss) – net deferred hedge gains (losses), 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.

Impairment of long-lived assets. 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.

During the third quarter of 2011, events and circumstances provided indications of possible impairment of certain of the Company’s dry gas assets, including assets in the Company’s South Texas (excluding the Eagle Ford Shale), Raton Basin and Barnett Shale areas. The events and circumstances indicating a possible impairment in these areas are primarily related to a reduction in management’s price outlooks that led to a decrease in estimated future undiscounted net cash flows attributable to the properties’ proved reserves. However, the Company’s estimate of undiscounted future net cash flows still indicated that such carrying amounts were expected to be recovered.

The Company’s primary assumptions of the estimated future net cash flows attributable to oil and gas properties include (i) utilizing proved reserves (including development of proved undeveloped reserves) and appropriate risk-adjusted probable and possible reserves and (ii) management’s commodity price outlook. Nonetheless, it is reasonably possible that the estimate of undiscounted future net cash flows attributable to these or other properties may change in the near or distant future resulting in the need to impair the assets’ carrying values. The primary factors that may affect future cash flows are (i) future reserve adjustments, both positive and negative, (ii) results of future drilling activities, (iii) management’s outlook on commodity prices and (iv) increases or decreases in production and capital costs associated with these assets.

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 2011, 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.

12

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

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 $125.4 million and $105.4 million as of September 30, 2011 and December 31, 2010, respectively. The Company recorded net income attributable to the noncontrolling interests of $34.1 million and $49.5 million for the three and nine months ended September 30, 2011, respectively (principally related to Pioneer Southwest), compared to net income attributable to the noncontrolling interests of $2.5 million and $39.0 million for the three and nine months ended September 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.

Revenue recognition. The Company does not recognize revenues until they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.

The Company uses the entitlements method of accounting for oil, natural gas liquids (“NGL”) and gas revenues. Sales proceeds in excess of the Company’s entitlement are included in other liabilities and the Company’s share of sales taken by others is included in other assets in the accompanying consolidated balance sheets.

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 September 30, 2011 and December 31, 2010, accounts payable – due to affiliates includes $4.5 million and $4.9 million, respectively, of liabilities attributable to Liability Awards.

For the three and nine months ended September 30, 2011, the Company recorded $11.7 million and $38.1 million, respectively, of stock-based compensation costs for all plans, as compared to $11.0 million and $31.6 million for the same respective periods of 2010. As of September 30, 2011, there was $78.0 million of unrecognized compensation expense related to unvested share- and unit-based compensation plan awards, including $16.9 million attributable to Liability Awards. This compensation will be recognized over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis.

13

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

The Company’s issued shares, as reflected in the consolidated balance sheets at September 30, 2011 and December 31, 2010, do not include 533,125 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 nine months ended September 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		443,060			202,436			43,495			86,903			6,812			30,039
Awards vested		(1,075,993	)		(69,805	)		(14,807	)		—			(11,532	)		—
Options exercised		—			—			—			(30,398	)		—			—
Awards forfeited		(51,204	)		(20,491	)		—			—			—			—
Outstanding at September 30, 2011		1,875,642			327,274			292,417			564,044			7,492			65,157

New accounting pronouncements. In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-04, “Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRSs.” ASU 2011-04 amended Accounting Standards Codification (“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 future financial position, results of operation or liquidity.

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 impact the Company’s future financial position, results of operations or liquidity.

In September 2011, the FASB issued ASU No. 2011-08 “Intangibles—Goodwill and Other (Topic 350).” ASU 2011-08 amends ASC 350 to permit an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The adoption of ASU 2011-08 is not expected to have a material impact on the future carrying value of the Company’s goodwill. See “Goodwill” above for more information about the Company’s policy for assessing goodwill for impairment.

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 accompanying consolidated balance sheets. If the exploratory well or project is determined to be impaired, the impaired costs are charged to exploration and abandonments expense.

14

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

The following table reflects the Company’s capitalized exploratory well and project activity during the three and nine months ended September 30, 2011:

	Three Months  Ended September 30, 2011			Nine Months  Ended September 30, 2011
	(in thousands)
Beginning capitalized exploratory costs	$	85,111		$	96,193
Additions to exploratory costs pending the determination of proved reserves		158,448			372,793
Reclassification due to determination of proved reserves		(139,624	)		(335,306	)
Disposition of assets sold		—			(28,938	)
Exploratory well costs charged to exploration expense		(126	)		(933	)
Ending capitalized exploratory costs	$	103,809		$	103,809

15

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

The following table provides an aging, as of September 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:

	September 30, 2011		December 31, 2010
	(in thousands, except project counts)
Capitalized exploratory costs that have been suspended:
One year or less	$	95,790	$	70,635
More than one year		8,019		25,558
	$	103,809	$	96,193
Number of projects with exploratory costs that have been suspended for a period greater than one year		1		3

As of September 30, 2011, the Company had one project with exploratory costs that had 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 September 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 fourth quarter 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.

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.

16

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

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 September 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 September 30, 2011
	(in thousands)
Assets:
Trading securities	$	283	$	146	$	—	$	429
Commodity derivatives		—		459,560		—		459,560
Deferred compensation plan assets		35,786		—		—		35,786
Total assets	$	36,069	$	459,706	$	—	$	495,775
Liabilities:
Commodity derivatives	$	—	$	16,659	$	—	$	16,659
Interest rate derivatives		—		12,664		—		12,664
Pioneer Southwest credit facility		—		94,917		—		94,917
5.875% senior notes due 2016		475,878		—		—		475,878
6.65% senior notes due 2017		522,695		—		—		522,695
6.875% senior notes due 2018		480,965		—		—		480,965
7.50% senior notes due 2020		506,250		—		—		506,250
7.20% senior notes due 2028		259,875		—		—		259,875
2.875% senior convertible notes due 2038 (a)		578,589		—		—		578,589
Total liabilities	$	2,824,252	$	124,240	$	—	$	2,948,492

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

The Company’s natural gas liquid (“NGL”) derivative contracts were classified as Level 3 in the fair value hierarchy prior to the three months ended September 30, 2011. The Company’s NGL derivative contracts are now classified as Level 2 in the fair value hierarchy as a result of the Company being able to obtain independent market-quoted NGL forward prices.

The following table presents changes in the fair values of the Company’s commodity derivative assets and liabilities that were previously classified as Level 3 in the fair value hierarchy:

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)	Three Months  Ended September 30, 2011			Nine Months  Ended September 30, 2011
	(in thousands)
Beginning liability balance	$	(13,351	)	$	(9,556	)
Fair value changes (a):
Net unrealized gains included in earnings		3,983			188
Net realized losses included in earnings		(4,478	)		(11,803	)
Settlement payments		4,478			11,803
Transfers out of Level 3		9,368			9,368
Ending liability balance	$	—		$	—

(a) Changes in fair value are included in net derivative gains in the accompanying consolidated statements of operations.

17

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

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

	September 30, 2011				December 31, 2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Assets:
Commodity price derivatives	$	459,560	$	459,560	$	304,434	$	304,434
Interest rate derivatives	$	—	$	—	$	18,256	$	18,256
Trading securities	$	429	$	429	$	467	$	467
Deferred compensation plan assets	$	35,786	$	35,786	$	36,162	$	36,162
Liabilities:
Commodity price derivatives	$	16,659	$	16,659	$	136,867	$	136,867
Interest rate derivatives	$	12,664	$	12,664	$	704	$	704
Pioneer credit facility	$	—	$	—	$	49,000	$	58,382
Pioneer Southwest credit facility	$	97,000	$	94,917	$	81,200	$	77,241
5.875 % senior notes due 2016	$	403,188	$	475,878	$	396,880	$	475,194
6.65 % senior notes due 2017	$	484,149	$	522,695	$	484,046	$	516,632
6.875 % senior notes due 2018	$	449,217	$	480,965	$	449,192	$	480,969
7.50 % senior notes due 2020	$	446,643	$	506,250	$	446,433	$	494,145
7.20 % senior notes due 2028	$	249,928	$	259,875	$	249,925	$	259,350
2.875% senior convertible notes due 2038 (a)	$	457,246	$	578,589	$	444,994	$	728,400

(a) 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 are comprised of securities that are both actively traded and not actively traded on major exchanges. The Company’s deferred compensation plan assets represent investments in equity and mutual fund securities that are actively traded on major exchanges as of the measurement date. As of September 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 with broker quotes representing Level 2 inputs.

Interest rate derivatives. The Company’s interest rate derivative assets and liabilities as of September 30, 2011 represent interest rate swap contracts that, at their inception, locked in a fixed forward 10-year annual rate of 3.06 percent on $200 million notional amount of debt for a period of one year. The net derivative values attributable to the Company’s interest rate derivative contracts as of September 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, collar contracts with short puts (which are also known as three-way collar contracts) and NGL percentage of oil index contracts. The Company’s oil, gas, NGL and diesel swap, collar, three-way collar and NGL percentage of oil index derivative contract asset and liability measurements represent Level 2 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.

18

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

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 Company has also entered into NGL swaps under terms whereby the Company pays variable NGL component market prices and receives a percentage of NYMEX WTI market prices (“NGL Percentage of WTI Oil Prices”). 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 commodity and NGL component prices, (iii) independent active NYMEX futures price quotes for WTI oil and (iv) 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 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 deferred tax attributes in the U.S., state, local and foreign tax jurisdictions will be utilized prior to their expiration. As of September 30, 2011 and December 31, 2010, the Company’s valuation allowances were $5.3 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 September 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 September 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.

19

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

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 nine months ended September 30, 2011 and 2010:

	Three Months  Ended September 30,						Nine Months  Ended September 30,
	2011			2010			2011			2010
	(in thousands)
Current:
U.S. federal	$	—		$	(1,550	)	$	—		$	(4,850	)
U.S. state		(2,978	)		(1,520	)		(7,915	)		(4,644	)
Foreign		(8,960	)		(10,211	)		(26,061	)		(10,661	)
		(11,938	)		(13,281	)		(33,976	)		(20,155	)
Deferred:
U.S. federal		(174,758	)		(66,198	)		(274,918	)		(269,256	)
U.S. state		(5,138	)		(6,854	)		5,591			(23,354	)
Foreign		6,363			10,122			20,287			9,327
		(173,533	)		(62,930	)		(249,040	)		(283,283	)
Income tax provision	$	(185,471	)	$	(76,211	)	$	(283,016	)	$	(303,438	)

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

	Three Months  Ended September 30,						Nine Months  Ended September 30,
	2011			2010			2011			2010
	(in thousands)
Current:
U.S. federal	$	—		$	(4,700	)	$	—		$	(4,700	)
U.S. state		(99	)	$	(400	)	$	(4,034	)	$	(400	)
Foreign		(336	)		(6,142	)		(5,937	)		(11,436	)
		(435	)		(11,242	)		(9,971	)		(16,536	)
Deferred:
U.S. federal		802			4,167			(221,686	)		(8,672	)
U.S. state		(76	)		—			(2,144	)		—
Foreign		(429	)		5,606			(8,083	)		(17,354	)
		297			9,773			(231,913	)		(26,026	)
Income tax provision	$	(138	)	$	(1,469	)	$	(241,884	)	$	(42,562	)

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 September 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

20

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

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 September 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 nine months ended September 30, 2011 (see Note P).

Convertible senior notes. As of September 30, 2011 and December 31, 2010, the Company had $479.9 million of 2.875% Convertible Senior Notes outstanding. The 2.875% Convertible Senior Notes are convertible under certain circumstances, using a net share settlement process, into a combination of cash and the Company’s common stock pursuant to a formula set forth in the indenture supplement pursuant to which the 2.875% Convertible Senior Notes were issued.

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, certain holders of the 2.875% Convertible Senior Notes tendered $70 thousand principal amount of the notes for conversion during the three months ended June 30, 2011. During July and August 2011, the Company paid the tendering holders a total of $71 thousand of cash and issued to the tendering holders 340 shares of the Company’s common stock in accordance with the terms of the 2.875% Convertible Senior Notes indenture supplement.

During June 2011 and September 2011, the Company’s stock price performance did not qualify the 2.875% Convertible Senior Notes for conversion at the option of the holders during either of the three months ended September 30, 2011 or December 31, 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 qualified and been converted on September 30, 2011, the note holders would have received approximately 185 thousand shares of the Company’s common stock, which had a market value of $12.1 million as of the close of business on September 30, 2011.

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 September 30, 2011 under the Company’s oil derivative contracts and the weighted average oil prices per Bbl for those contracts:

21

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Outstanding Average
Average daily oil production associated with derivatives (Bbls):
2011 – Swap contracts
Volume								750		750
NYMEX price							$	77.25	$	77.25
2011 – Collar contracts
Volume								2,000		2,000
NYMEX price:
Ceiling							$	170.00	$	170.00
Floor							$	115.00	$	115.00
2011 – Collar contracts with short puts
Volume								32,000		32,000
NYMEX price:
Ceiling							$	99.33	$	99.33
Floor							$	73.75	$	73.75
Short put							$	59.31	$	59.31
2012 – Swap contracts
Volume		3,000		3,000		3,000		3,000		3,000
NYMEX price (a)	$	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		28,000		28,000		28,000		28,000		28,000
NYMEX price:
Ceiling	$	120.62	$	120.62	$	120.62	$	120.62	$	120.62
Floor	$	83.68	$	83.68	$	83.68	$	83.68	$	83.68
Short put	$	65.82	$	65.82	$	65.82	$	65.82	$	65.82
2014 – Collar contracts with short puts (a)
Volume		16,500		16,500		16,500		16,500		16,500
NYMEX price:
Ceiling	$	129.69	$	129.69	$	129.69	$	129.69	$	129.69
Floor	$	88.48	$	88.48	$	88.48	$	88.48	$	88.48
Short put	$	71.97	$	71.97	$	71.97	$	71.97	$	71.97

(a) Subsequent to September 30, 2011, the Company entered into (i) NYMEX swap contracts on 3,000 Bbls per day of March 2012 through May 2012 forecasted production, whereby the Company receives $0.28 per Bbl and pays the difference between (a) each day’s price per Bbl of WTI for the first nearby month less (b) the price per Bbl of WTI for the second nearby NYMEX month, multiplied by .6667; plus (c) each day’s price per Bbl of WTI for the first nearby month less (d) the price per Bbl of WTI for the third nearby NYMEX month, multiplied by .3333 and (ii) additional collar contracts with short puts for 3,000 Bbls per day of the Company’s 2013 production with a ceiling price of $111.95 per Bbl, a floor price of $85.00 per Bbl and a short put price of $70.00 per Bbl and (iii) terminated collar contracts with short puts for 6,500 Bbls per day of the Company’s 2014 production with an average ceiling price of $133.12 per Bbl, an average floor price of $90.00 per Bbl and an average short put price of $65.00 per Bbl.

22

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 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. Historically, NGL market prices have correlated well with WTI oil prices. The Company has entered into a limited number of NGL Percentage of WTI Oil Prices derivatives to reduce the risk of volatility in NGL to WTI price differentials. The following table sets forth the volumes in Bbls outstanding as of September 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
Blended index price										$	51.50		$	51.50
2011 – Collar contracts
Volume											2,650			2,650
Blended index price:
Ceiling										$	64.23		$	64.23
Floor										$	53.29		$	53.29
2012 – Swap contracts
Volume		750			750			750			750			750
Blended index price	$	35.03		$	35.03		$	35.03		$	35.03		$	35.03
2012 – NGL Percentage of WTI Oil Prices contracts (a)
Volume		2,000			2,000			2,000			2,000			2,000
Percent of WTI oil price		85	%		85	%		85	%		85	%		85	%

(a) Subsequent to September 30, 2011, the Company (i) entered into additional NGL Percentage of WTI Oil Prices contracts for 1,000 Bbls per day of the Company’s 2012 production priced at 68 percent of WTI and (ii) converted 3,000 Bbls per day of the Company’s 2012 production from NGL Percentage of WTI Oil Prices contracts to NGL collar contracts with short puts with an average ceiling price of $79.99 per Bbl, an average floor price of $67.70 per Bbl and an average short put price of $55.76 per Bbl.

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 September 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
NYMEX price							$	6.13		$	6.13
2011 – Collar contracts with short puts
Volume								200,000			200,000
NYMEX price:
Ceiling							$	8.55		$	8.55
Floor							$	6.32		$	6.32
Short put							$	4.88		$	4.88
2011 – Basis swap contracts
Volume								143,500			143,500
Price differential							$	(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

23

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

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		136,000			136,000			136,000			136,000			136,000
Price differential	$	(0.34	)	$	(0.34	)	$	(0.34	)	$	(0.34	)	$	(0.34	)
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		72,500			72,500			72,500			72,500			72,500
Price differential	$	(0.26	)	$	(0.26	)	$	(0.26	)	$	(0.26	)	$	(0.26	)
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		60,000			60,000			60,000			60,000			60,000
NYMEX price:
Ceiling	$	7.80		$	7.80		$	7.80		$	7.80		$	7.80
Floor	$	5.83		$	5.83		$	5.83		$	5.83		$	5.83
Short put	$	4.42		$	4.42		$	4.42		$	4.42		$	4.42
2014 – Basis swap contracts
Volume		55,000			55,000			55,000			55,000			55,000
Price differential	$	(0.24	)	$	(0.24	)	$	(0.24	)	$	(0.24	)	$	(0.24	)
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

24

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

2015 – Collar contracts with short puts
Volume		30,000		30,000		30,000		30,000		30,000
NYMEX price:
Ceiling	$	7.11	$	7.11	$	7.11	$	7.11	$	7.11
Floor	$	5.00	$	5.00	$	5.00	$	5.00	$	5.00
Short put	$	4.00	$	4.00	$	4.00	$	4.00	$	4.00

Diesel prices. As of September 30, 2011, the Company has diesel derivative swap contracts for 250 notional Bbls per day for the period from October 2011 through December 2011 at an average per Bbl fixed price of $123.90 and for all of 2012 at an average per Bbl fixed price of $119.28. The diesel derivative swap contracts are priced at an index that is highly correlated to the prices that the Company incurs to fuel its drilling rigs and fracture stimulation fleet equipment. The Company purchases diesel derivative swap contracts to mitigate fuel price risk.

Interest rates. As of September 30, 2011, the Company is a party to interest rate derivative contracts that lock in, through July 2012, a fixed forward 10-year annual interest rate of 3.06 percent on $200 million notional amount of debt.

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

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

Fair Value of Derivative Instruments as of September 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	$	247,036	Derivatives - current	$	24,607
Commodity price derivatives	Derivatives - noncurrent		230,875	Derivatives - noncurrent		10,403
Interest rate derivatives	Derivatives - noncurrent		—	Derivatives - noncurrent		12,664
		$	477,911		$	47,674

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.

25

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 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 September 30,						Nine Months  Ended September 30,
		2011			2010			2011			2010
		(in thousands)
Commodity price derivatives	Oil and gas revenue	$	8,295		$	21,976		$	24,627		$	67,634
Interest rate derivatives	Interest expense		(71	)		(63	)		(209	)		(1,633	)
Interest rate derivatives	Derivative gains, net		—			—			—			(2,465	)
Total		$	8,224		$	21,913		$	24,418		$	63,536

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 September 30,					Nine Months Ended September 30,
			2011			2010		2011		2010
			(in thousands)
Commodity price derivatives		Derivative gains, net	$	407,407		$	112,733	$	380,030	$	520,486
Interest rate derivatives		Derivative gains, net		(6,335	)		14,848		6,088		52,564
Total			$	401,072		$	127,581	$	386,118	$	573,050

AOCI - Hedging. As of September 30, 2011 AOCI – Hedging represented net deferred losses of $58 thousand compared to net deferred gains of $7.4 million as of December 31, 2010. The AOCI – Hedging balance as of September 30, 2011 was comprised of $5.1 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 $0.1 million of associated net deferred tax benefits, reduced by $3.5 million of AOCI – Hedging net deferred gains attributable to and classified as noncontrolling interests in consolidated subsidiaries.

During the twelve months ending September 30, 2012, the Company expects to reclassify $5.9 million of AOCI – Hedging net deferred gains to oil revenues (including $3.5 million related to noncontrolling interests) and $308 thousand of AOCI – Hedging net deferred losses to interest expense. The Company also expects to reclassify $777 thousand of net deferred income tax provisions associated with hedge derivatives during the twelve months ending September 30, 2012 from AOCI – Hedging to income tax expense.

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.

26

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands)
Beginning asset retirement obligations	$	151,970		$	137,181		$	152,291		$	166,434
Liabilities assumed in acquisitions		—			—			6			6
New wells placed on production		1,132			2,356			3,206			7,000
Changes in estimates (a)		(5,453	)		—			(5,331	)		—
Disposition of wells		—			(131	)		(448	)		(29,671	)
Liabilities settled		(2,808	)		(6,141	)		(10,277	)		(16,096	)
Accretion of discount from continuing operations		2,806			2,521			8,119			7,909
Accretion of discount from discontinued operations		—			105			81			309
Ending asset retirement obligations	$	147,647		$	135,891		$	147,647		$	135,891

(a) Changes in estimates during 2011 are primarily associated with the deferral of the future abandonment of the Company’s South Africa oil and gas properties to allow Petroleum Oil and Gas Corporation of South Africa, Ltd (“PetroSA”) to recover take-or-pay make up gas (see Note M) and a $1.5 million reduction in East Cameron 322 reclamation costs.

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 September 30, 2011 and December 31, 2010, the current portions of the Company’s asset retirement obligations were $13.6 million and $19.9 million, respectively.

NOTE I. Postretirement Benefit Obligations

As of September 30, 2011 and December 31, 2010, the Company had $6.9 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 are predecessor plans of entities acquired by the Company. These plans had no assets as of September 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 nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands)
Beginning accumulated postretirement benefit obligations	$	6,996		$	8,968		$	7,408		$	9,075
Net benefit payments		(271	)		(543	)		(962	)		(1,127	)
Service costs		61			80			183			241
Net actuarial losses		—			100			—			200
Accretion of interest		79			108			236			324
Ending accumulated postretirement benefit obligations	$	6,865		$	8,713		$	6,865		$	8,713

27

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

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.

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.

28

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 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 nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30, 2011									Nine Months Ended September 30, 2011
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Income (loss) as reported	$	386,145		$	(547	)	$	385,598		$	582,591		$	412,511		$	995,102
Net income attributable to the noncontrolling interests		(34,134	)		—			(34,134	)		(49,467	)		—			(49,467	)
Participating basic earnings		(6,797	)		—			(6,797	)		(10,062	)		(7,124	)		(17,186	)
Basic net income (loss) attributable to common stockholders		345,214			(547	)		344,667			523,062			405,387			928,449
Reallocation of participating earnings		189			—			189			268			190			458
Diluted income (loss) attributable to common stockholders	$	345,403		$	(547	)	$	344,856		$	523,330		$	405,577		$	928,907

	Three Months Ended September 30, 2010									Nine Months Ended September 30, 2010
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Income as reported	$	96,490		$	18,083		$	114,573		$	500,123		$	63,745		$	563,868
Net income attributable to the noncontrolling interests		(2,538	)		—			(2,538	)		(39,003	)		—			(39,003	)
Participating basic earnings		(2,265	)		(424	)		(2,689	)		(10,661	)		(1,359	)		(12,020	)
Basic income attributable to common stockholders		91,687			17,659			109,346			450,459			62,386			512,845
Reallocation of participating earnings		16			3			19			112			15			127
Diluted income attributable to common stockholders	$	91,703		$	17,662		$	109,365		$	450,571		$	62,401		$	512,972

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(in thousands)
Weighted average common shares outstanding:
Basic		116,281		115,191		116,122		114,985
Dilutive common stock options		166		168		181		218
Convertible senior notes dilution		185		—		1,618		—
Contingently issuable performance unit shares		443		662		429		629
Diluted		117,075		116,021		118,350		115,832

29

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 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 nine months ended September 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 September 30, 2011
Revenues and other income:
Oil and gas	$	591,147		$	19,362		$	—		$	610,509
Interest and other		13,691			—			3,882			17,573
Derivative gains, net		—			—			401,072			401,072
Gain (loss) on disposition of assets, net		1,523			—			(475	)		1,048
Hurricane activity, net		1,487			—			—			1,487
		607,848			19,362			404,479			1,031,689
Costs and expenses:
Oil and gas production		118,989			620			—			119,609
Production and ad valorem taxes		38,542			—			—			38,542
Depletion, depreciation and amortization		142,632			8,449			15,455			166,536
Exploration and abandonments		20,026			—			—			20,026
General and administrative		—			—			49,812			49,812
Accretion of discount on asset retirement obligations		2,072			734			—			2,806
Interest		—			—			45,559			45,559
Other		9,773			—			7,410			17,183
		332,034			9,803			118,236			460,073
Income from continuing operations before income taxes		275,814			9,559			286,243			571,616
Income tax provision		(102,051	)		(2,677	)		(80,743	)		(185,471	)
Income from continuing operations	$	173,763		$	6,882		$	205,500		$	386,145

30

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Three Months Ended September 30, 2010
Revenues and other income:
Oil and gas	$	416,112		$	21,299		$	—		$	437,411
Interest and other		268			—			14,701			14,969
Derivative gains, net		—			—			127,581			127,581
Gain (loss) on disposition of assets, net		2,429			—			(46	)		2,383
Hurricane activity, net		3,452			—			—			3,452
		422,261			21,299			142,236			585,796
Costs and expenses:
Oil and gas production		99,717			1,000			—			100,717
Production and ad valorem taxes		33,045			—			—			33,045
Depletion, depreciation and amortization		119,726			18,338			9,032			147,096
Exploration and abandonments		21,308			302			—			21,610
General and administrative		—			—			43,417			43,417
Accretion of discount on asset retirement obligations		1,899			622			—			2,521
Interest		—			—			45,002			45,002
Other		9,682			—			10,005			19,687
		285,377			20,262			107,456			413,095
Income from continuing operations before income taxes		136,884			1,037			34,780			172,701
Income tax provision		(50,647	)		(290	)		(25,274	)		(76,211	)
Income from continuing operations	$	86,237		$	747		$	9,506		$	96,490
	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Nine Months Ended September 30, 2011
Revenues and other income:
Oil and gas	$	1,629,287		$	62,283		$	—		$	1,691,570
Interest and other		30,294			—			38,420			68,714
Derivative gains, net		—			—			386,118			386,118
Gain (loss) on disposition of assets, net		1,523			—			(2,962	)		(1,439	)
Hurricane activity, net		1,418			—			—			1,418
		1,662,522			62,283			421,576			2,146,381
Costs and expenses:
Oil and gas production		319,564			2,431			—			321,995
Production and ad valorem taxes		107,702			—			—			107,702
Depletion, depreciation and amortization		387,035			35,671			38,101			460,807
Exploration and abandonments		57,242			341			—			57,583
General and administrative		—			—			138,562			138,562
Accretion of discount on asset retirement obligations		6,164			1,955			—			8,119
Interest		—			—			136,554			136,554
Other		31,302			—			18,150			49,452
		909,009			40,398			331,367			1,280,774
Income from continuing operations before income taxes		753,513			21,885			90,209			865,607
Income tax benefit (provision)		(278,800	)		(6,128	)		1,912			(283,016	)
Income from continuing operations	$	474,713		$	15,757		$	92,121		$	582,591

31

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Nine Months Ended September 30, 2010
Revenues and other income:
Oil and gas	$	1,264,316		$	67,182		$	—		$	1,331,498
Interest and other		1,776			—			48,153			49,929
Derivative gains, net		—			—			570,585			570,585
Gain (loss) on disposition of assets, net		27,408			—			(437	)		26,971
Hurricane activity, net		5,678			—			—			5,678
		1,299,178			67,182			618,301			1,984,661
Costs and expenses:
Oil and gas production		278,157			2,672			—			280,829
Production and ad valorem taxes		85,444			—			—			85,444
Depletion, depreciation and amortization		353,090			58,677			24,066			435,833
Exploration and abandonments		60,773			428			—			61,201
General and administrative		—			—			122,165			122,165
Accretion of discount on asset retirement obligations		6,043			1,866			—			7,909
Interest		—			—			137,893			137,893
Other		30,233			—			19,593			49,826
		813,740			63,643			303,717			1,181,100
Income from continuing operations before income taxes		485,438			3,539			314,584			803,561
Income tax provision		(179,612	)		(991	)		(122,835	)		(303,438	)
Income from continuing operations	$	305,826		$	2,548		$	191,749		$	500,123

	September 30, 2011		December 31, 2010
	(in thousands)
Consolidating Assets by Geographic Area:
United States	$	10,775,975	$	8,987,141
South Africa		86,710		134,901
Tunisia		—		325,942
Headquarters		122,358		231,118
Total consolidated assets	$	10,985,043	$	9,679,102

NOTE M.    Deferred Revenue

The Company’s deferred revenue is associated with a United States volumetric production payment obligation (“VPP”) and take-or-pay gas receipts under the Company’s South Africa gas sales agreement that are each expected to be recovered volumetrically by the purchasers.

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) transferred title of the reserves to the purchaser and (v) allows 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.

32

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

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

VPP Deferred revenue at December 31, 2010	$	87,020
Less: 2011 VPP amortization		(33,620	)
VPP Deferred revenue at September 30, 2011	$	53,400

The remaining VPP 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	$	11,329
2012	$	42,071

During July 2011, the Company received $36.1 million of cash take-or-pay proceeds from PetroSA in accordance with the terms of its South Coast Gas Project gas sales agreement (the “GSA”). The terms of the GSA obligate PetroSA to purchase certain minimum volumes of gas per year as a source for its gas-to-liquids plant in South Africa. Under certain circumstances, if PetroSA fails to take such minimum volumes, then PetroSA is contractually obligated to make take-or-pay payments to the Company. The GSA allows PetroSA to take delivery of available take-or-pay make up volumes during certain stipulated periods, including a period of one year beyond the date the GSA would otherwise expire.

The Company recorded the take-or-pay receipt as noncurrent deferred revenue in the accompanying consolidated balance sheet as of September 30, 2011. The deferred revenue associated with take-or-pay volumes will be recognized in gas revenues in the consolidated statements of operations as PetroSA takes delivery of the take-or-pay make up volumes or in the earnings of any period during which the future make up of the take-or-pay volumes were to become unlikely beyond a reasonable doubt.

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

For the three and nine months ended September 30, 2011, the Company recorded $1.0 million of net gains and $1.4 million of net losses on disposition of assets from continuing operations, respectively, as compared to $2.4 million and $27.0 million, respectively, of net gains from continuing operations for the three and nine months ended September 30, 2010.

The Company’s net gains for the three months ended September 30, 2011 are primarily associated with the sale of unproved oil and gas properties while the net losses during the nine months ended September 30, 2011 are primarily associated with the sale of excess materials and supplies inventory, partially offset by gains on the aforementioned unproved property sale. During the nine months ended September 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 nine months ended September 30, 2011 from the sale of its Tunisia subsidiaries that are included in discontinued operations.

33

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

NOTE O.    Interest and Other Income

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011		2010			2011		2010
	(in thousands)
Alaskan Petroleum Production Tax credits (a)	$	95	$	12,129		$	27,547	$	39,990
Third-party income from vertical integration services (b)		13,691		268			30,294		1,776
Other income (loss)		222		(478	)		3,135		1,304
Eagle Ford Shale land fees		1,001		—			2,803		—
Equity interest in income (loss) of unconsolidated affiliate		1,641		(269	)		2,442		(269	)
Deferred compensation plan income		288		206			1,454		890
Change in asset retirement estimates		556		—			556		—
Interest income		79		3,113			483		3,589
Insurance claim recovery		—		—			—		1,665
Sales and other tax refunds		—		—			—		984
Total interest and other income	$	17,573	$	14,969		$	68,714	$	49,929

(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 gross margins from vertical integration services primarily represents third party revenues less operating costs associated with Company-provided fracture stimulation, drilling and related services.

NOTE P.    Other Expense

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011		2010			2011			2010
	(in thousands)
Transportation commitment charges (a)	$	5,141	$	—		$	16,101		$	—
Above market drilling rig related costs (b)		4,632		9,682			15,201			30,233
Other		1,150		2,102			4,176			4,028
Contingency and environmental accrual adjustments		588		260			3,470			507
Tax penalties (recoveries)		190		(18	)		2,478			668
Loss on extinguishment of debt		—		—			2,367			—
Inventory impairments (c)		1,745		5,660			2,332			7,230
Legal settlements		1,573		224			2,201			716
Cancelled well costs		2,113		19			2,872			56
Bad debt expense (recoveries)		51		(547	)		(1,746	)		(577	)
Well servicing operations (d)		—		2,305			—			6,965
Total other expense	$	17,183	$	19,687		$	49,452		$	49,826

(a) Primarily represents contract deficiency payments on excess pipeline capacity.

(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.

34

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

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 $853.6 million, including normal post-closing adjustments, resulting in a pretax gain of $645.2 million. During the three months ended September 30, 2011, the Company reduced the net gain on the transaction by $57 thousand. The historical results of operations of Pioneer Tunisia have been classified as discontinued operations herein.

During the nine months ended September 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 nine months ended September 30, 2011 and 2010:

	Three Months  Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands)
Revenues and other income:
Oil and gas	$	—		$	33,965		$	22,130		$	109,813
Interest and other		43			229			4,629			44,643
Gain (loss) on disposition of assets, net (a)		(57	)		—			645,241			—
		(14	)		34,194			672,000			154,456
Costs and expenses:
Oil and gas production		—			3,628			2,126			10,522
Depletion, depreciation and amortization (a)		—			5,740			—			18,086
Exploration and abandonments		—			2,853			4,246			11,182
General and administrative		275			1,343			9,173			5,916
Accretion of discount on asset retirement obligations (a)		—			105			81			309
Other		120			973			1,979			2,134
		395			14,642			17,605			48,149
Income (loss) from discontinued operations before income taxes		(409	)		19,552			654,395			106,307
Current tax provision		(435	)		(11,242	)		(9,971	)		(16,536	)
Deferred tax (provision) benefit (a)		297			9,773			(231,913	)		(26,026	)
Income (loss) from discontinued operations	$	(547	)	$	18,083		$	412,511		$	63,745

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

NOTE R.    Subsequent Events

The Company has evaluated subsequent events through the date of issuance of its unaudited consolidated financial statements. The Company is not aware of any reportable subsequent events.

35

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 third quarter of 2011 included the following highlights:

• Earnings attributable to common stockholders were $351.5 million ($2.95 per diluted share), as compared to $112.0 million ($0.94 per diluted share) for the third quarter of 2010. The increase in earnings attributable to common stockholders is primarily due to (i) a $173.1 million increase in oil and gas revenue as a result of increasing sales volumes and higher commodity prices and (ii) a $273.5 million increase in mark-to-market derivative gains, partially offset by (iii) associated increases in oil and gas production costs, production and ad valorem taxes, depletion, depreciation and amortization expense and income tax provisions.

• Net cash provided by operating activities increased to $465.6 million for the three months ended September 30, 2011, as compared to $208.5 million for the three months ended September 30, 2010. The $257.1 million increase in net cash provided by operating activities was primarily due to increases in oil and gas sales, realized derivative gains and a $36.1 million cash receipt of South Africa take-or-pay proceeds, partially offset by working capital changes.

• Net debt to book capitalization decreased to 31 percent at September 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 and NGL prices increased during the third quarter of 2011 to $92.24 per Bbl and $48.36 per Bbl, respectively, as compared to respective prices of $85.93 per Bbl and $34.46 per Bbl during the third quarter of 2010. Average reported gas prices during the third quarter of 2011 were consistent with the third quarter of 2010.

• During the third quarter of 2011, daily sales volumes increased by 16 percent to 127,676 BOEPD, as compared to 109,681 BOEPD during the third quarter of 2010. The increase in third quarter 2011 sales volumes, as compared to the third quarter of 2010, was primarily due to the Company’s successful United States drilling program during 2010 and the first three quarters of 2011.

Fourth Quarter 2011 Outlook

Based on current estimates, the Company expects that fourth quarter 2011 production will average 136,000 to 141,000 BOEPD. The Company’s South Africa production was shut in during late-September and throughout October due to unplanned third-party gas-to-liquids plant downtime. The plant resumed operations in early November. The production guidance for the fourth quarter reflects the October downtime and assumes the plant will be in full operation for the remainder of the quarter.

Fourth quarter production costs (including production and ad valorem taxes and transportation costs) are expected to average $12.50 to $14.50 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 $47 million to $52 million. Interest expense is expected to be $45 million to $49 million, and other expense is expected to be $20 million to $30 million. Accretion of discount on asset retirement obligations is expected to be $2 million to $4 million.

Noncontrolling interest in consolidated subsidiaries’ 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 fourth quarter effective income tax rate is expected to range from 35 percent to 40 percent, assuming current capital spending plans and no significant mark-to-market changes in the Company’s derivative position. Cash income taxes are expected to range from $10 million to $15 million, principally related to South African income taxes.

36

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 nine months ended September 30, 2011:

	Oil (Bbls)		NGLs (Bbls)		Gas (Mcf)		Total (BOE)
United States:
Permian Basin		25,180		10,839		46,402		43,752
Raton Basin		—		—		161,472		26,912
Mid-Continent		3,711		7,073		51,965		19,444
Eagle Ford Shale		3,315		2,218		22,136		9,222
South Texas		97		1		46,423		7,835
Alaska		4,637		—		—		4,637
Barnett Shale		435		1,117		9,366		3,113
Other		3		1		66		17
		37,378		21,249		337,830		114,932
South Africa		556		—		22,384		4,287
Total Worldwide		37,934		21,249		360,214		119,219

The Company’s 2011 capital expenditures are expected to be funded by internally-generated operating cash flow and 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 nine months ended September 30, 2011:

	Acquisition Costs					Exploration Costs		Development Costs		Asset Retirement Obligations			Total
	Proved		Unproved
	(in thousands)
United States:
Permian Basin	$	5,383	$	29,740		$	63,859	$	839,783	$	1,922		$	940,687
Raton Basin		150		(53	)		5,536		40,335		226			46,194
Mid-Continent		15		272			4,141		10,693		27			15,148
Eagle Ford Shale		—		23,738			90,749		4,009		47			118,543
South Texas		—		1,451			7,826		10,492		3			19,772
Alaska		—		—			24,369		65,588		1,061			91,018
Barnett Shale		—		25,247			199,722		8,308		227			233,504
Other		—		3,194			4,382		—		—			7,576
		5,548		83,589			400,584		979,208		3,513			1,472,442
South Africa and other		—		—			7,160		7,633		(3,589	)		11,204
Total Worldwide	$	5,548	$	83,589		$	407,744	$	986,841	$	(76	)	$	1,483,646

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

	Development Drilling
	Beginning Wells in Progress		Wells Spud		Successful Wells		Unsuccessful Wells		Ending Wells in Progress
United States
Permian Basin		144		490		469		7		158
Raton Basin		—		48		34		—		14
Mid-Continent		—		2		2		—		—
South Texas		1		1		2		—		—
Alaska		1		—		1		—		—
Total Worldwide		146		541		508		7		172

37

PIONEER NATURAL RESOURCES COMPANY

	Exploration/Extension Drilling
	Beginning Wells in Progress		Wells Spud		Successful Wells		Unsuccessful Wells		Ending Wells in Progress
United States
Permian Basin		3		23		20		—		6
Mid-Continent		—		5		—		—		5
South Texas		2		—		1		—		1
Eagle Ford Shale		22		74		62		—		34
Alaska		—		1		—		—		1
Barnett Shale		11		49		33		—		27
Total Worldwide		38		152		116		—		74

Permian Basin area. During the first nine months of 2011, the Company drilled 496 wells in the Spraberry field, of which 489 were successful. The Company had 42 rigs operating as of September 30, 2011. 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 three successful wells to the Atoka interval and two successful wells to the Mississippian interval.

The Company has completed 113 vertical 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. For wells that have been on production for at least ten months, production has increased by more than 25 percent compared to offset wells that have been drilled and completed in all zones through the Lower Wolfcamp. The incremental cost per well for this deeper drilling and one additional fracture stimulation stage is approximately $60 thousand. The Company believes the Strawn interval is prospective in 40 percent of its Spraberry acreage and expects to complete and commingle this interval with all zones in 25 percent of the vertical wells drilled in the fourth of quarter of 2011 and during 2012.

The Company has completed three vertical Atoka wells in 2011. The initial peak production rate from this interval, when tested alone, averaged 109 BOEPD. The Company plans to test the Atoka interval for up to six months and then commingle this production with production from all zones. The incremental cost to drill an Atoka well ranges from $300 thousand to $350 thousand as a result of deeper drilling, larger casing and adding two additional fracture stimulation stages. The Company believes that the Atoka interval is prospective in 25 percent to 50 percent of its Spraberry field acreage. The Company plans to test two to three additional single-zone Atoka wells in the fourth quarter and is forecasting that 15 percent to 20 percent of its 2012 vertical drilling program in the Spraberry field will include wells drilled to the Atoka interval with production commingled from all zones.

The Company has completed two vertical Mississippian wells in 2011. The well tests had an average initial peak production rate of 99 BOEPD. The Company plans to test the interval for at least six months and then commingle the production with all zones. The incremental cost per well for this deeper interval, larger casing and two additional fracture stimulation stages is approximately $300 thousand to $350 thousand. The Company believes the Mississippian interval is prospective in 10 percent to 20 percent of its Spraberry field acreage. The Company expects to complete one to two additional single-zone wells in the fourth quarter of 2011 and is forecasting that 10 percent of its 2012 vertical drilling program in the Spraberry field will include wells drilled to the Mississippian interval, with production commingled from all zones.

38

PIONEER NATURAL RESOURCES COMPANY

The Company continues to test downspacing in the Spraberry field from 40 acres to 20 acres. Eleven 20-acre wells have been drilled in 2011, with six of these wells having been placed 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 three to five additional 20-acre downspaced wells during the remainder of 2011.

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 15 and has five Company-owned fracture stimulation fleets currently operating in the Spraberry field. To support its growing operations, the Company also owns other field service equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. In addition, the Company has contracted for tubular and pumping unit requirements through 2012, forecasted fracture stimulation sand supply requirements through 2015 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 the Company’s fracture stimulation requirements in the Spraberry field by the end of 2011. The Company’s growing fracture stimulation capacity, along with its other integrated services 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 one dedicated rig drilling horizontal wells in the Wolfcamp Shale in the Spraberry field area. The Company successfully completed its first horizontal well in Upton County, Texas in the Wolfcamp Shale interval with a 30-stage fracture stimulation in a 5,800-foot lateral section. The well had a peak 24-hour rate of 854 BOEPD (686 barrels oil per day, 102 barrels NGLs per day and 395 Mcf per day), even with flow line restrictions. Pioneer’s analysis of the completion showed that the entire 800 foot thick target zone was successfully fracture stimulated. The well is producing to sales.

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

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

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.

The Company has drilled and completed 62 horizontal Eagle Ford Shale wells during the first nine months of 2011, all of which were successful. On September 30, 2011, 34 other Eagle Ford Shale wells were in progress or awaiting completion and hookup.

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

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. With the start-up of the two fleets in April 2011, the Company has been able to increase the pace at which wells are placed on production, with a further increase expected when the second Company-owned fleet commences operations later this year.

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

The unconsolidated affiliate formed by the Company to operate gathering facilities in the Eagle Ford Shale area, EFS Midstream, is obligated to construct midstream assets in the Eagle Ford Shale area. Construction of the midstream assets is underway, with the majority of the construction expected to be completed by 2013. Eight of the 12 planned central gathering plants (“CGPs”) were completed as of September 30, 2011. EFS Midstream plans to build three additional CGPs in 2012. 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 $164.1 million of capital in EFS Midstream, $92.1 million of which was contributed during the nine months ended September 30, 2011. During June 2011, EFS Midstream entered into a $300 million, five-year revolving credit facility that may be used to fund infrastructure investments that exceed its operating cash flows.

39

PIONEER NATURAL RESOURCES COMPANY

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 has contracted another rig to drill two exploration wells (“Nuna #1” and “Sikumi #1”) during the first quarter of 2012. The Nuna #1 well will be drilled from an onshore location to further evaluate the productivity of the Torok formation and the feasibility of future development expansion to the south. The Sikumi #1 well will be drilled from an ice pad on the west side of the Oooguruk unit to test the deeper Ivishak zone, which is the main producing horizon in the Prudhoe Bay field.

Barnett Shale. During the first nine months of 2011, the Company had two drilling rigs operating and drilled and completed 33 Barnett Shale wells, all of which were successful. A Pioneer-owned fracture stimulation fleet commenced operating in the Barnett Shale during the second quarter of 2011. As of September 30, 2011, 27 Barnett Shale wells were in progress or awaiting completion and hookup. 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 during the fourth quarter of 2011. 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 $610.5 million and $1.7 billion for the three and nine months ended September 30, 2011, respectively, as compared to $437.4 million and $1.3 billion for the same respective periods of 2010.

The increase in oil and gas revenues during the three months ended September 30, 2011, as compared to the same period of 2010, is reflective of seven percent and 40 percent increases in worldwide average reported oil and NGL prices, respectively, and 46 percent, 13 percent and three percent increases in oil, NGL and gas sales volumes, respectively. The increase in oil and gas revenues during the nine months ended September 30, 2011, as compared to the same period of 2010, is reflective of nine percent and 26 percent increases in worldwide average reported oil and NGL prices, respectively, and 35 percent and eight percent increases in oil and NGL sales volumes; partially offset by a seven percent decrease in worldwide average reported gas prices and a two percent decrease in gas sales volumes.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Oil (Bbls):
United States		42,245		28,880		37,378		27,388
South Africa		527		445		556		730
Worldwide		42,772		29,325		37,934		28,118
NGLs (Bbls):
United States		23,212		20,525		21,249		19,649
Gas (Mcf):
United States		350,687		327,917		337,830		335,960
South Africa		19,468		31,069		22,384		30,304
Worldwide		370,155		358,986		360,214		366,264
Total (BOE):
United States		123,905		104,058		114,932		103,030
South Africa		3,771		5,623		4,287		5,781
Worldwide		127,676		109,681		119,219		108,811

In the United States, average daily BOE sales volumes increased by 19 percent and 12 percent for the three and nine months ended September 30, 2011, respectively, as compared to the same respective periods of 2010 principally due to the Company’s successful United States drilling program and declines in scheduled VPP deliveries. For the three and nine months ended September 30, 2011, average South Africa daily BOE sales volumes decreased by 33 percent and 26 percent, respectively, as compared to the same respective periods of 2010, due to unplanned production curtailments resulting from third-party gas-to-liquid plant downtime and normal well decline rates.

40

PIONEER NATURAL RESOURCES COMPANY

During the three and nine months ended September 30, 2011, as compared to the three and nine months ended September 30, 2010, oil volumes delivered under the Company’s VPPs decreased by 45 percent for each period. The Company’s remaining obligations under the VPP agreements are to deliver 345,000 Bbls of oil during the fourth quarter of 2011 and 1,281,000 Bbls of oil during 2012.

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

41

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 nine months ended September 30, 2011 and 2010:

	Three Months  Ended September 30,				Nine Months  Ended September 30,
	2011		2010		2011		2010
Average reported prices:
Oil (per Bbl):
United States	$	92.01	$	86.06	$	96.98	$	89.08
South Africa	$	110.65	$	77.84	$	107.18	$	77.43
Worldwide	$	92.24	$	85.93	$	97.13	$	88.77
NGL (per Bbl):
United States	$	48.36	$	34.46	$	46.50	$	36.80
Gas (per Mcf):
United States	$	4.04	$	4.06	$	4.01	$	4.37
South Africa	$	7.82	$	6.34	$	7.53	$	6.26
Worldwide	$	4.24	$	4.25	$	4.23	$	4.53
Total (per BOE)
United States	$	51.86	$	43.47	$	51.93	$	44.95
South Africa	$	55.80	$	41.17	$	53.22	$	42.57
Worldwide	$	51.97	$	43.35	$	51.97	$	44.82
Average realized prices:
Oil (per Bbl):
United States	$	86.96	$	70.30	$	91.28	$	72.07
South Africa	$	110.65	$	77.84	$	107.18	$	77.43
Worldwide	$	87.25	$	70.41	$	91.51	$	72.21
NGL (per Bbl):
United States	$	48.36	$	33.49	$	46.50	$	35.78
Gas (per Mcf):
United States	$	4.04	$	4.03	$	4.01	$	4.34
South Africa	$	7.82	$	6.34	$	7.53	$	6.26
Worldwide	$	4.24	$	4.23	$	4.23	$	4.50
Total (per BOE)
United States	$	50.14	$	38.80	$	50.07	$	40.14
South Africa	$	55.80	$	41.17	$	53.22	$	42.57
Worldwide	$	50.30	$	38.92	$	50.18	$	40.27

Derivative activities. The primary purposes for which the Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts are to (i) reduce the effect of price volatility on the commodities the Company produces, sells and consumes, (ii) support the Company’s annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects.

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 nine months ended September 30, 2011 and 2010:

	Three Months  Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(in thousands)
Increase to oil revenue from AOCI - Hedging transfers	$	8,295	$	19,206	$	24,627	$	59,415
Increase to NGL revenue from AOCI - Hedging transfers		—		1,839		—		5,458
Increase to gas revenue from AOCI - Hedging transfers		—		931		—		2,761
Total	$	8,295	$	21,976	$	24,627	$	67,634

42

PIONEER NATURAL RESOURCES COMPANY

Deferred revenue. During the three and nine months ended September 30, 2011, the Company’s amortization of deferred VPP revenue increased oil revenues by $11.3 million and $33.6 million, respectively, as compared to an increase of $22.7 million and $67.7 million during the same respective periods of 2010. See Note M of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information about the Company’s VPPs.

Derivative gains, net. During the three months ended September 30, 2011, the Company recorded $401.1 million of net derivative gains on commodity price and interest rate derivatives. For the three months ended September 30, 2011, $327.1 million represented unrealized net gains and $74.0 million represented realized net gains. During the nine months ended September 30, 2011, the Company recorded $386.1 million of net derivative gains on commodity price and interest rate derivatives. For the nine months ended September 30, 2011, $272.4 million represented unrealized gains and $113.7 million represented realized net gains. During the three and nine months ended September 30, 2010, the Company recorded $127.6 million and $570.6 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.

Interest and other income. Interest and other income for the three and nine months ended September 30, 2011 was $17.6 million and $68.7 million, respectively, as compared to $15.0 million and $49.9 million for the same respective periods in 2010. The $2.6 million increase in interest and other income during the three months ended September 30, 2011, as compared to the same period in 2010, was primarily due to a $13.4 million increase in third-party income from vertical integration services, a $1.9 million increase in equity earnings from EFS Midstream and $1.0 million in Eagle Ford Shale land fees, partially offset by a $12.0 million decrease in PPT credit recoveries and a $3.0 million decrease in interest income. The $18.8 million increase in interest and other income during the nine months ended September 30, 2011, as compared to the same period in 2010, was primarily due to a $28.5 million increase in third-party income from vertical integration services, $2.8 million in Eagle Ford Shale land fees and a $2.7 million increase in equity earnings from EFS Midstream, partially offset by a $12.4 million decrease in PPT credit recoveries and a $3.1 million decrease in interest income. 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 a net gain on the disposition of assets of $1.0 million during the three months ended September 30, 2011 and a net loss on the disposition of assets of $1.4 million during the nine months ended September 30, 2011, as compared to net gains on the disposition of assets of $2.4 million and $27.0 million for the three and nine months ended September 30, 2010, respectively. The net gain for the three months ended September 30, 2011 was primarily associated with the sale of certain unproved property in the United States while the net loss for the nine months ended September 30, 2011 was primarily associated with sales of excess materials and supplies inventory, partially offset by the aforementioned gain on the sale of unproved property. During the three and nine months ended September 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 the disposition of assets.

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 were substantially complete as of September 30, 2011.

Oil and gas production costs. The Company recorded oil and gas production costs of $119.6 million and $322.0 million during the three and nine months ended September 30, 2011, respectively, as compared to $100.7 million and $280.8 million during the same respective periods of 2010. In general, lease operating expenses and workover costs represent the components of oil and gas production costs over which the Company has management control, while third-party transportation charges represent the cost to transport volumes produced to a sales point. Net natural gas plant/gathering charges represent the net costs to gather and process the Company’s gas, reduced by net revenues earned from the gathering and processing of third-party gas in Company-owned facilities.

Total oil and gas production costs per BOE from continuing operations for the three and nine months ended September 30, 2011 increased by two percent and five percent, respectively, as compared to the same periods in 2010. The modest increase in production costs per BOE during the three months ended September 30, 2011, as compared to the third quarter of 2010, is primarily due to inflation in well servicing costs, including labor costs, and maintenance

43

PIONEER NATURAL RESOURCES COMPANY

costs, partially offset by a decrease in per BOE workover costs. The increase in United States production costs per BOE during the nine months ended September 30, 2011, as compared to the nine months ended September 30, 2010, is primarily due to repairs associated with severe winter weather disruptions encountered during the first quarter of 2011 and inflation in well servicing costs, including labor costs, partially offset by continued reductions in VPP delivery commitments.

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 nine months ended September 30, 2011 and 2010:

	Three Months  Ended September 30,				Nine Months  Ended September 30,
	2011		2010		2011		2010
Lease operating expenses	$	8.16	$	7.71	$	7.90	$	7.54
Third-party transportation charges		1.14		0.82		1.07		0.84
Net natural gas plant/gathering charges		0.14		0.39		0.09		0.15
Workover costs		0.75		1.08		0.84		0.92
Total production costs	$	10.19	$	10.00	$	9.90	$	9.45
	Three Months  Ended September 30,				Nine Months  Ended September 30,
	2011		2010		2011		2010
United States	$	10.43	$	10.42	$	10.19	$	9.89
South Africa	$	1.79	$	1.93	$	2.08	$	1.69
Worldwide	$	10.19	$	10.00	$	9.90	$	9.45

Production and ad valorem taxes. The Company recorded production and ad valorem taxes of $38.5 million and $107.7 million during the three and nine months ended September 30, 2011, respectively, as compared to $33.0 million and $85.4 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 months ended September 30, 2011, the Company’s production and ad valorem taxes per BOE have, in the aggregate, remained consistent with those of the three months ended September 30, 2010, reflecting the offsetting effects of a per-BOE decrease in ad valorem taxes (primarily due to increasing sales volumes) and an increase in production taxes (primarily due to higher commodity prices). During the nine months ended September 30, 2011, the Company’s production and ad valorem taxes per BOE increased by 15 percent in the aggregate, primarily reflecting the impact of higher commodity prices on production taxes, partially offset by a decline in per-BOE ad valorem taxes as a result of the increase in sales volumes.

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

	Three Months  Ended September 30,				Nine Months  Ended September 30,
	2011		2010		2011		2010
Ad valorem taxes	$	1.18	$	1.67	$	1.32	$	1.58
Production taxes		2.10		1.60		1.99		1.30
Total ad valorem and production taxes	$	3.28	$	3.27	$	3.31	$	2.88

Depletion, depreciation and amortization expense. The Company’s total DD&A expense was $166.5 million ($14.18 per BOE) and $460.8 million ($14.16 per BOE) for the three and nine months ended September 30, 2011, respectively, as compared to $147.1 million ($14.58 per BOE) and $435.8 million ($14.67 per BOE) during the same respective periods of 2010. The decrease in DD&A expense per BOE during the three and nine months ended September 30, 2011, as compared to the same respective periods of 2010, is primarily due to decreases in depletion

44

PIONEER NATURAL RESOURCES COMPANY

expense per BOE on oil and gas properties and the per-BOE effect of increasing production on relatively fixed depreciation on vertical integration equipment and other property and equipment.

Depletion expense on oil and gas properties was $12.86 per BOE and $12.99 per BOE during the three and nine months ended September 30, 2011, respectively, as compared to $13.68 per BOE and $13.86 per BOE during the same respective periods of 2010. The six percent decreases in per-BOE depletion expense during the three and nine months ended September 30, 2011, as compared to the same periods of 2010, are primarily due to increases in proved reserves as a result of (i) the Company’s successful drilling program, (ii) higher first-day-of-the-month commodity prices during the 12-month period ending on September 30, 2011, which had the effect of extending the economic lives of proved properties and (iii) collection of $36.1 million of South African take-or-pay proceeds, which had the effect of extending the Company’s GSA for one year to allow delivery of the take-or-pay volumes, thereby increasing the Company’s South African proved gas reserves. See Note M of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for more information about the South Africa take-or-pay proceeds.

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

	Three Months  Ended September 30,				Nine Months  Ended September 30,
	2011		2010		2011		2010
United States	$	12.51	$	12.51	$	12.34	$	12.55
South Africa	$	24.35	$	35.45	$	30.48	$	37.18
Worldwide	$	12.86	$	13.68	$	12.99	$	13.86

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.

During the third quarter of 2011, events and circumstances provided indications of possible impairment of certain of the Company’s dry gas assets, including assets in the Company’s South Texas (excluding the Eagle Ford Shale), Raton Basin and Barnett Shale areas. However, the Company’s estimate of undiscounted future net cash flows still indicated that such carrying amounts were expected to be recovered. See Note B of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements” for more information about continuing impairment risks and the events and circumstances that indicated the possible impairment of these assets.

45

PIONEER NATURAL RESOURCES COMPANY

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 nine months ended September 30, 2011 and 2010 (in thousands):

	United States		South Africa		Total
Three Months Ended September 30, 2011
Geological and geophysical	$	18,236	$	—	$	18,236
Exploratory dry holes		126		—		126
Leasehold abandonments and other		1,664		—		1,664
	$	20,026	$	—	$	20,026
Three Months Ended September 30, 2010
Geological and geophysical	$	12,547	$	302	$	12,849
Exploratory dry holes		2,393		—		2,393
Leasehold abandonments and other		6,368		—		6,368
	$	21,308	$	302	$	21,610
	United States		South Africa		Total
Nine Months Ended September 30, 2011
Geological and geophysical	$	50,631	$	341	$	50,972
Exploratory dry holes		934		—		934
Leasehold abandonments and other		5,677		—		5,677
	$	57,242	$	341	$	57,583
Nine Months Ended September 30, 2010
Geological and geophysical	$	43,664	$	428	$	44,092
Exploratory dry holes		2,159		—		2,159
Leasehold abandonments and other		14,950		—		14,950
	$	60,773	$	428	$	61,201

The Company’s exploration and abandonment expense during the three and nine months ended September 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 nine months ended September 30, 2011, the Company drilled and evaluated 116 exploration/extension wells, all of which were successfully completed as discoveries. During the same period in 2010, the Company drilled and evaluated 26 exploration/extension wells, 25 of which were successfully completed as discoveries.

General and administrative expense. General and administrative expense for the three and nine months ended September 30, 2011 was $49.8 million and $138.6 million, respectively, as compared to $43.4 million and $122.2 million during the same respective periods of 2010. The increase in general and administrative expense for the three and nine months ended September 30, 2011, as compared to the same periods of 2010, was primarily due to increases in compensation and occupancy expenses related to staffing increases 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.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations was $2.8 million and $8.1 million for the three and nine months ended September 30, 2011, respectively, as compared to $2.5 million and $7.9 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 $45.6 million and $136.6 million for the three and nine months ended September 30, 2011, respectively, as compared to $45.0 million and $137.9 million during the same respective periods of 2010. The $1.3 million decrease in interest expense during the nine months ended September 30, 2011, as

46

PIONEER NATURAL RESOURCES COMPANY

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 nine months ended September 30, 2011, including the effects of capitalized interest, was 7.2 percent, as compared to 7.3 percent and 7.0 percent for the same respective periods of 2010.

Other expense. Other expense for the three and nine months ended September 30, 2011 was $17.2 million and $49.5 million, respectively, as compared to $19.7 million and $49.8 million for the same respective periods of 2010. The decrease in other expense for the three months ended September 30, 2011, as compared to the same period in 2010, is primarily attributable to a $5.1 million decrease in charges recorded for the difference between Pioneer contracted rig rates and market rig rates that are charged to joint operations and a $3.9 million decrease in inventory impairment charges, partially offset by a $5.1 million increase in charges associated with excess gas transportation capacity. Aggregate other expense for the nine months ended September 30, 2011 did not significantly differ from that of the nine months ended September 30, 2010, due to essentially offsetting impacts of an increase in charges associated with excess gas transportation capacity and a decrease in above-market drilling rig 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 $185.5 million and $283.0 million during the three and nine months ended September 30, 2011, respectively, as compared to $76.2 million and $303.4 million during the same respective periods of 2010. The changes in the income tax provisions for the three and nine months ended September 30, 2011, as compared to the same periods of 2010, are primarily due to the differences in derivative gains associated with mark-to-market accounting and increased oil and gas sales in 2011. The Company’s effective tax rate of 35 percent during each of the three and nine months ended September 30, 2011, excluding net income attributable to noncontrolling interests, is consistent with the Company’s combined United States federal and state statutory rate.

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

Income (loss) from discontinued operations, net of tax. The Company reported a loss from discontinued operations, net of tax of $547 thousand and income from discontinued operations, net of tax of $412.5 million for the three and nine months ended September 30, 2011, respectively, as compared to income from discontinued operations, net of tax of $18.1 million and $63.7 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 $853.6 million, including normal post-closing adjustments, resulting in a pretax gain of $645.2 million.

Discontinued operations for the three and nine 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 nine months ended September 30, 2011 was $34.1 million and $49.5 million, respectively, as compared to net income attributable to the noncontrolling interests of $2.5 million and $39.0 million for the same respective periods of 2010. The $31.6 million and $10.5 million increases in net income attributable to noncontrolling interests for the three and nine months ended September 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 requirements in excess of their ability to internally fund capital 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. During 2011, 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 liquidity under its credit facility.

47

PIONEER NATURAL RESOURCES COMPANY

The Company’s capital budget for 2011 has continued 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 three quarters of 2011 and the forecasted production volumes and NYMEX strip commodity prices for the fourth quarter of 2011, the Company expects its cash flows from operating activities plus the proceeds from the sale of Pioneer Tunisia to be sufficient to fund its planned capital expenditures and contractual obligations for 2011. During the first nine 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 $1.4 billion, as compared to $642.8 million during the first nine months of 2010. In addition, during the first nine months of 2011, the Company paid $265.7 million for additions to other assets and other property and equipment, which includes amounts associated with vertical integration and facilities, as compared to $132.3 million during the first nine months of 2010.

Investing activities. Investing activities used $854.9 million of cash during the nine months ended September 30, 2011, as compared to $564.2 million used during the nine months ended September 30, 2010. The $290.7 million increase in net cash used by investing activities for the nine months ending September 30, 2011, as compared to the nine months ended September 30, 2010, is primarily due to a $605.1 million, or 85 percent, increase in additions to oil and gas properties, reflective of the Company’s increased drilling activities in 2011; a $133.5 million, or 101 percent, increase in additions to other assets and other property and equipment, primarily comprised of purchases of drilling rigs, fracture stimulation equipment and well servicing equipment used in the Company’s vertical integration services; and a $74.0 million increase in investments in EFS Midstream; partially offset by a $521.9 million increase in proceeds from disposition of assets attributable to the sale of Pioneer Tunisia during February 2011. During the nine months ended September 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 and August 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 nine months ended September 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, April 2011 and July 2011, the Pioneer Southwest board of directors (the “Pioneer Southwest Board”) declared quarterly distributions of $0.50, $0.51 and $0.51 per limited partner unit, respectively, compared to the quarterly distributions of $0.50 per limited partner unit declared in January, April and July 2010. Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling unitholders of $19.1 million and $18.9 million during the nine months ended September 30, 2011 and 2010, respectively. During October 2011, the Pioneer Southwest Board declared a quarterly distribution of $0.51 per limited partner unit for unitholders of record on October 31, 2011, payable November 11, 2011. Future distributions by Pioneer Southwest 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, take-or-pay 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 September 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), (vi) take-or-pay obligations that allow the payer to recover make up volumes in the future and (vii) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other parties that

48

PIONEER NATURAL RESOURCES COMPANY

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 $14.3 million decrease in outstanding long-term debt, (ii) a $33.6 million decrease in the Company’s VPP obligations, (iii) a $36.1 million receipt of take-or-pay proceeds subject to volumetric make up rights, (iv) entry into certain fractionation and NGL purchase agreements under which the Company becomes contractually obligated to perform only after future performance by third parties and (v) a $245.1 million increase in the Company’s derivative net assets. 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; accordingly, future capital needs of EFS Midstream are expected to be funded from its operating cash flow and the borrowings under its credit facility.

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 September 30, 2011, these contracts represented net assets of $430.2 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 September 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.

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 nine months ended September 30, 2011 was $1.0 billion as compared to $901.7 million during the same period of 2010. The increase in net cash provided by operating activities for the nine months ended September 30, 2011, as compared to the nine months ended September 30, 2010, is primarily due to increases in oil and gas sales volumes, increases in oil and NGL prices and realized derivative gains and the collection of $36.1 million of South African take-or-pay proceeds, partially offset by 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.

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 $853.6 million, including normal post-closing adjustments, resulting in a pretax gain of $645.2 million. 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 nine 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 and the sale of certain Uinta/Piceance proved and unproved oil and gas properties for $11.8 million of net proceeds. 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 nine months ended September 30, 2011 and 2010 was $75.8 million and $286.7 million, respectively. The $210.9 million decrease in cash used in financing activities during the nine months ended September 30, 2011, as compared to the nine months ended September 30, 2010, is primarily due to (i) a $205.8 million decline in net payments on long-term debt and (ii) a $24.1 million increase in excess tax benefits from share-based payment arrangements, partially offset by (iii) a $26.6 million increase in treasury shares purchased from employees to satisfy withholding tax payments on the vesting of share-based awards.

49

PIONEER NATURAL RESOURCES COMPANY

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 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 tendering holders $71 thousand of cash and issued tendering holders 340 shares of the Company’s common stock. During June and September 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 or December 31, 2011, respectively. 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 or 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.

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 September 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 September 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 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 September 30, 2011 was $7.6 billion, consisting of $210.6 million of cash and cash equivalents, debt of $2.6 billion and stockholders’ equity of $5.2 billion. The Company’s net debt to net book capitalization was 31 percent and 37 percent at September 30, 2011 and December 31, 2010, respectively. The Company’s ratio of current assets to current liabilities was 1.42 to 1.00 at September 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.”

50

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. None of the Company’s market risk sensitive instruments are entered into for speculative purposes.

The following table reconciles the changes that occurred in the fair values of the Company’s open derivative contracts during the nine 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)		380,030			6,088			386,118
Contract maturities		(90,182	)		(10,191	)		(100,373	)
Contract terminations (b) (c)		(14,514	)		(26,113	)		(40,627	)
Fair value of contracts outstanding as of September 30, 2011	$	442,901		$	(12,664	)	$	430,237

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

(b) During the three months ended September 30, 2011, the Company terminated oil collar contracts with short puts for (i) 3,250 Bbls per day of the Company’s 2013 production with an average ceiling price of $120.58 per Bbl, an average floor price of $80.23 per Bbl and an average short put price of $65.23 per Bbl and (ii) 5,500 Bbls per day of the Company’s 2014 production with an average ceiling price of $129.98 per Bbl, an average floor price of $90.00 per Bbl and an average short put price of $65.00 per Bbl.

(c) During July 2011, the Company terminated $470 million notional amount of fixed-for-variable interest rate derivatives.

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.

51

PIONEER NATURAL RESOURCES COMPANY

The following table provides information about financial instruments to which the Company was a party as of September 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 September 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 November 1, 2011.

	Three  Months Ending December  31, 2011			Year Ending December 31,												Thereafter			Total		Liability Fair Value at September 30, 2011
				2012			2013			2014			2015
	($ in thousands)
Total Debt:
Fixed rate principal maturities (a)	$	—		$	—		$	479,930		$	—		$	—		$	2,089,985		$	2,569,915	$	(2,824,252	)
Weighted average interest rate		6.05	%		6.05	%		6.75	%		6.78	%		6.78	%		7.13	%
Variable rate principal maturities:
Pioneer Southwest credit facility	$	—		$	—		$	97,000		$	—		$	—		$	—		$	97,000	$	(94,917	)
Weighted average interest rate		1.40	%		1.46	%		1.55	%		—			—			—
Interest Rate Swaps:
Notional debt amount (b)	$	200,000		$	117,222		$	—		$	—		$	—		$	—				$	(12,664	)
Fixed rate payable (%)		3.06	%		3.06	%		—			—			—			—
Variable rate receivable (%)		0.53	%		0.58	%		—			—			—			—

(a) Represents maturities of principal amounts excluding debt issuance discounts and premiums and net deferred fair value hedge losses. The Company’s $479.9 million of 2.875% Convertible Senior Notes do not qualify for redemption during the fourth quarter of 2011, as disclosed in Note F of Notes to Consolidated Financial Statements included in “Item 1. Financial Statements.”

(b) 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 September 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 services costs.

The Company manages commodity price risk with derivative contracts, such as swap contracts, collar contracts, collar contracts with short put options and NGL percentage of oil index contracts. 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. NGL percentage of oil index contracts link certain NGL components to NYMEX oil prices. Such NGL components are highly correlated to NYMEX oil prices.

The Company purchases diesel derivative swap contracts to mitigate fuel price risk. The diesel derivative swap contracts that the Company enters into 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.

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.

52

PIONEER NATURAL RESOURCES COMPANY

	Three Months Ending December 31,														Asset (Liability) Fair Value at September 30,
				Year Ending December 31,
	2011			2012			2013			2014			2015		2011
															(in thousands)
Oil Derivatives:
Average daily notional Bbl volumes:
Swap contracts		750			3,000			3,000			—			—	$	(4,423	)
Weighted average fixed price per Bbl (a)	$	77.25		$	79.32		$	81.02		$	—		$	—
Collar contracts		2,000			2,000			—			—			—	$	17,660
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			28,000			16,500			—	$	116,190
Weighted average ceiling price per Bbl	$	99.33		$	117.99		$	120.62		$	129.69		$	—
Weighted average floor price per Bbl	$	73.75		$	80.42		$	83.68		$	88.48		$	—
Weighted average short put price per Bbl	$	59.31		$	65.00		$	65.82		$	71.97		$	—
Average forward NYMEX oil prices (b)	$	93.19		$	92.48		$	91.07		$	90.13		$	—
NGL Derivatives:
Average daily notional Bbl volumes:
Swap contracts		1,150			750			—			—			—	$	(5,669	)
Weighted average fixed price per Bbl	$	51.50		$	35.03		$	—		$	—		$	—
Collar contracts		2,650			—			—			—			—	$	(2,300	)
Weighted average ceiling price per Bbl	$	64.23		$	—		$	—		$	—		$	—
Weighted average floor price per Bbl	$	53.29		$	—		$	—		$	—		$	—
Average forward NGL prices (c)	$	70.61		$	65.49		$	—		$	—		$	—
NGL Percentage of WTI Oil Prices contracts (d)		—			2,000			—			—			—	$	(1,399	)
Percentage of NYMEX WTI received		—			85	%		—			—			—
Average forward NYMEX oil prices (b)	$	—		$	92.48		$	—		$	—		$	—
Gas Derivatives:
Average daily notional MMBtu volumes:
Swap contracts		117,500			105,000			67,500			50,000			—	$	130,466
Weighted average fixed price per MMBtu	$	6.13		$	5.82		$	6.11		$	6.05		$	—
Collar contracts		—			65,000			150,000			140,000			50,000	$	68,016
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			60,000			30,000	$	144,243
Weighted average ceiling price per MMBtu	$	8.55		$	7.96		$	7.49		$	7.80		$	7.11
Weighted average floor price per MMBtu	$	6.32		$	6.12		$	6.00		$	5.83		$	5.00
Weighted average short put price per MMBtu	$	4.88		$	4.55		$	4.50		$	4.42		$	4.00
Average forward NYMEX gas prices (b)	$	3.93		$	4.16		$	4.70		$	5.05		$	5.33
Basis swap contracts		143,500			136,000			72,500			55,000			—	$	(19,265	)
Weighted average fixed price per MMBtu	$	(0.56	)	$	(0.34	)	$	(0.26	)	$	(0.24	)	$	—
Average forward basis differential prices (e)	$	(0.11	)	$	(0.16	)	$	(0.17	)	$	(0.19	)	$	—
Diesel Derivatives:
Average daily notional Bbl volumes:
Swap contracts		250			(250	)		—			—			—	$	(618	)
Weighted average fixed price per Bbl	$	123.90		$	119.28		$	—		$	—		$	—
Average forward diesel prices (f)	$	127.71		$	124.84		$	—		$	—		$	—

(a) Subsequent to September 30, 2011, the Company entered into (i) NYMEX swap contracts on 3,000 Bbls per day of March 2012 through May 2012 forecasted production, whereby the Company receives $0.28 per Bbl and pays the difference between (a) each day’s price per Bbl of WTI for the first nearby month less (b) the price per Bbl of WTI for the second nearby NYMEX month, multiplied by .6667; plus (c) each day’s price per Bbl of WTI for the first nearby month less (d) the price per Bbl of WTI for the third nearby NYMEX month, multiplied by .3333 and (ii) additional collar contracts with short puts for 3,000 Bbls per day of the Company’s 2013 production with a ceiling price of $111.95 per Bbl, a floor price of $85.00 per Bbl and a short put price of $70.00 per Bbl and (iii) terminated collar contracts with short puts for 6,500 Bbls per day of the Company’s 2014 production with an average ceiling price of $133.12 per Bbl, an average floor price of $90.00 per Bbl and an average short put price of $65.00 per Bbl. The Company received cash proceeds of $12.6 million associated with the aforementioned terminated collar contracts with short puts.

(b) The average forward NYMEX oil and gas prices are based on October 31, 2011 market quotes.

53

PIONEER NATURAL RESOURCES COMPANY

(c) Forward component NGL prices are derived from active-market NGL component price quotes. The forward prices represent estimates as of October 31, 2011 provided by third parties who actively trade in NGL derivatives.

(d) Subsequent to September 30, 2011, the Company (i) entered into additional NGL Percentage of WTI Oil Prices contracts for 1,000 Bbls per day of the Company’s 2012 production at 68 percent of WTI price and (ii) converted 3,000 Bbls per day of the Company’s 2012 production from NGL Percentage of WTI Oil Prices contracts to collar contracts with short puts with an average ceiling price of $79.99 per Bbl, an average floor price of $67.70 per Bbl and an average short put price of $55.76 per Bbl.

(e) The average forward basis differential prices are based on October 31, 2011 market quotes for basis differentials between the relevant index prices and NYMEX-quoted forward prices.

(f) The average forward diesel prices are based on October 31, 2011 market quotes.

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 September 30, 2011 that have materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.

54

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, and as set forth in Item 1A of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, there has been no material change in the Company’s risk factors from those described in the Annual Report on Form 10-K.

Laws and regulations pertaining to threatened and endangered species could delay or restrict the Company’s operations and cause it to incur substantial costs.

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitats, migratory birds, wetlands and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act and the Comprehensive Environmental Response, Compensation and Liability Act. The United States Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or oil and gas development. If harm to species or damages to wetlands, habitat or natural resources occur or may occur, government entities, or at times private parties, may act to prevent oil and gas exploration or development activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and may seek damages and, in some cases, criminal penalties.

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.

55

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 under plans or programs during the three months ended September 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)
July 2011		37		93.74		—
August 2011		15,284	$	72.60		—
September 2011		—		—		—
Total		15,321	$	72.65		—		$	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.

The Company has an Employee Stock Purchase Plan (the “ESPP”) that allows eligible employees to annually purchase the Company’s common stock at a discounted price. An employee who elects to participate may make contributions to the ESPP up to 15 percent of the employee’s pay (subject to certain ESPP limits) during an eight-month offering period (January 1 to August 31). Participants in the ESPP purchase the Company’s common stock at a price that is 15 percent below the closing sales price of the Company’s common stock on either the first day or the last day of each offering period, whichever closing sales price is lower. Officers of the Company are not eligible to participate in the ESPP. The ESPP was adopted in 1997 and provides for the issuance of up to a total of 750,000 shares. A total of 578,693 shares had been issued under the ESPP as of the end of 2010. Prior to the closing of the August 2011 offering period, the Company discovered that a total of 500,000 shares issuable under the plan had been registered for sale under the Securities Act of 1933, meaning that the issuance of 15,734 shares in 2009, at a price to the participants of $13.75, and 62,959 shares issued in 2010, at a price to the participants of $40.94, exceeded the number of shares so registered. The Company filed a Registration Statement on Form S-8 in September 2011 with respect to the incremental 250,000 shares issuable under the ESPP. Consequently, the Company may be deemed to have inadvertently failed to register transactions in the ESPP relating to a total of 78,693 shares. The Company has implemented monitoring and reporting procedures to ensure that in the future it timely meets its registration obligations with respect to this and other employee benefit plans. The Company has always treated the shares issued under the ESPP as outstanding for financial reporting purposes and the unregistered transactions do not represent any additional dilution. The Company believes that historically it has provided the participants in the ESPP with the same information they would have received had the registration statement been filed. Nonetheless, original purchasers of the shares may have rescission rights with respect to such shares, which rights represent a potential contingent liability to the extent that the participants realized, or have unrealized, losses. However, the Company believes that any such contingent liability is immaterial given the expiration of applicable statute of limitations under the Securities Act of 1933 and the fact that, in each instance, the market price of the Company’s common stock has exceeded the participants’ purchase price through the expiration of the applicable statute of limitations.

56

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.

57

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: November 4, 2011	By:	/s/ Richard P. Dealy
		Richard P. Dealy Executive Vice President and Chief Financial Officer
Date: November 4, 2011	By:	/s/ Frank W. Hall
		Frank W. Hall Vice President and Chief Accounting Officer

58

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.

59

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.

November 4, 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.

November 4, 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 September 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:	November 4, 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 September 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:	November 4, 2011

XML

Income Taxes (Income Tax (Provisions) Benefits) (Details) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Income Taxes [Abstract]
U.S. federal		$ (1,550)		$ (4,850)
U.S. state	(2,978)	(1,520)	(7,915)	(4,644)
Foreign	(8,960)	(10,211)	(26,061)	(10,661)
Current income tax (provision) benefit	(11,938)	(13,281)	(33,976)	(20,155)
U.S. federal	(174,758)	(66,198)	(274,918)	(269,256)
U.S. state	(5,138)	(6,854)	5,591	(23,354)
Foreign	6,363	10,122	20,287	9,327
Deferred income tax (provision) benefit	(173,533)	(62,930)	(249,040)	(283,283)
Income tax provision	$ (185,471)	$ (76,211)	$ (283,016)	$ (303,438)

XML

Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data	Sep. 30, 2011	Dec. 31, 2010
Consolidated Balance Sheets [Abstract]
Trade, allowance for doubtful accounts	$ 755	$ 1,155
Other, allowance for doubtful accounts	$ 348	$ 2,519
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	500,000,000	500,000,000
Common stock, shares issued	127,614,963	126,212,256
Treasury stock, shares	11,264,660	10,903,743

XML

Consolidated Statements Of Operations (USD $) In Thousands, except Per Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Revenues and other income:
Oil and gas	$ 610,509	$ 437,411	$ 1,691,570	$ 1,331,498
Interest and other	17,573	14,969	68,714	49,929
Derivative gains, net	401,072	127,581	386,118	570,585
Gain (loss) on disposition of assets, net	1,048	2,383	(1,439)	26,971
Hurricane activity, net	1,487	3,452	1,418	5,678
Revenues and other income	1,031,689	585,796	2,146,381	1,984,661
Costs and expenses:
Oil and gas production	119,609	100,717	321,995	280,829
Production and ad valorem taxes	38,542	33,045	107,702	85,444
Depletion, depreciation and amortization	166,536	147,096	460,807	435,833
Exploration and abandonments	20,026	21,610	57,583	61,201
General and administrative	49,812	43,417	138,562	122,165
Accretion of discount on asset retirement obligations	2,806	2,521	8,119	7,909
Interest	45,559	45,002	136,554	137,893
Other	17,183	19,687	49,452	49,826
Costs and expenses, Total	460,073	413,095	1,280,774	1,181,100
Income from continuing operations before income taxes	571,616	172,701	865,607	803,561
Income tax provision	(185,471)	(76,211)	(283,016)	(303,438)
Income from continuing operations	386,145	96,490	582,591	500,123
Income (loss) from discontinued operations, net of tax	(547)	18,083	412,511	63,745
Net income	385,598	114,573	995,102	563,868
Net income attributable to the noncontrolling interests	(34,134)	(2,538)	(49,467)	(39,003)
Net income attributable to common stockholders	351,464	112,035	945,635	524,865
Basic earnings per share:
Income from continuing operations attributable to common stockholders	$ 2.96	$ 0.80	$ 4.51	$ 3.92
Income (loss) from discontinued operations attributable to common stockholders		$ 0.15	$ 3.49	$ 0.54
Net income attributable to common stockholders	$ 2.96	$ 0.95	$ 8.00	$ 4.46
Diluted earnings per share:
Income from continuing operations attributable to common stockholders	$ 2.95	$ 0.79	$ 4.42	$ 3.89
Income (loss) from discontinued operations attributable to common stockholders		$ 0.15	$ 3.43	$ 0.54
Net income attributable to common stockholders	$ 2.95	$ 0.94	$ 7.85	$ 4.43
Weighted average shares outstanding:
Basic	116,281	115,191	116,122	114,985
Diluted	117,075	116,021	118,350	115,832
Dividends declared per share	$ 0.04	$ 0.04	$ 0.08	$ 0.08
Amounts attributable to common stockholders:
Income from continuing operations	352,011	93,952	533,124	461,120
Income (loss) from discontinued operations, net of tax	(547)	18,083	412,511	63,745
Net income	$ 351,464	$ 112,035	$ 945,635	$ 524,865

XML

Discontinued Operations (Schedule Of Discontinued Operations) (Details) (USD $)	3 Months Ended				9 Months Ended				1 Months Ended	3 Months Ended	9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010		Feb. 28, 2011 Pioneer Tunisia [Member]	Sep. 30, 2011 Pioneer Tunisia [Member]	Sep. 30, 2011 BOEMRE [Member]	Sep. 30, 2010 BOEMRE [Member]
Oil and gas			$ 33,965,000		$ 22,130,000		$ 109,813,000
Interest and other	43,000		229,000		4,629,000		44,643,000				2,000,000	35,300,000
Gain (loss) on disposition of assets, net	(57,000)	[1]		[1]	645,241,000	[1]		[1]
Total revenues and other income from discontinued operations	(14,000)		34,194,000		672,000,000		154,456,000
Oil and gas production			3,628,000		2,126,000		10,522,000
Depletion, depreciation and amortization			5,740,000	[1]			18,086,000	[1]
Exploration and abandonments			2,853,000		4,246,000		11,182,000
General and administrative	275,000		1,343,000		9,173,000		5,916,000
Accretion of discount on asset retirement obligations			105,000	[1]	81,000	[1]	309,000	[1]
Other	120,000		973,000		1,979,000		2,134,000
Total costs and expenses from discontinued operations	395,000		14,642,000		17,605,000		48,149,000
Income (loss) from discontinued operations before income taxes	(409,000)		19,552,000		654,395,000		106,307,000
Current tax provision	(435,000)		(11,242,000)		(9,971,000)		(16,536,000)
Deferred tax (provision) benefit	297,000	[1]	9,773,000	[1]	(231,913,000)	[1]	(26,026,000)	[1]
Income (loss) from discontinued operations	(547,000)		18,083,000		412,511,000		63,745,000
Percentage sale of ownership in subsidiary									100.00%
Cash proceeds from sale of subsidiaries, net									853,600,000
Gain on sale of subsidiaries, pretax									645,200,000
Reduction in net gain										57,000
Interest and other	$ 17,573,000		$ 14,969,000		$ 68,714,000		$ 49,929,000

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

XML

Derivative Financial Instruments (Narrative) (Details) (USD $)	9 Months Ended	12 Months Ended		9 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2012	Dec. 31, 2010	Sep. 30, 2011 2011 Diesel Swaps [Member] bbl	Dec. 31, 2011 2011 Diesel Swaps [Member]	Sep. 30, 2011 2012 Diesel Swaps [Member] bbl	Dec. 31, 2012 2012 Diesel Swaps [Member]
Schedule of Trading Securities and Other Trading Assets [Line Items]
Diesel swap contract notional volume Bbls per day				250		250
Average fixed price per Bbl					123.90		119.28
Terminated interest rate derivatives, notional amount	$ 470,000,000
Proceeds from termination of interest rate derivatives	26,100,000
Net deferred losses from hedging in AOCI	(58,000)		7,361,000
Net deferred gains on the effective portions of discontinued commodity hedges	5,100,000
Accumulated other comprehensive income (loss)-net deferred hedge gains (losses), net of tax	(58,000)		7,361,000
Net deferred losses on the effective portions of discontinued interest rate hedges	1,800,000
Net deferred gains or losses associated to net deferred tax provisions	100,000
Net deferred gains or losses attributable to noncontrolling interests	3,500,000
Expected to reclassify accumulated other comprehensive income - Hedging net deferred gains		5,900,000
Accumulated other comprehensive income - Hedging net deferred gains related to noncontrolling interests		3,500,000
Cash flow hedge loss reclassified to interest expense		308,000
Expected to reclassify net deferred income tax provision		777,000
Derivative fixed interest rate	3.06%
Swap contract notional amount fixed rate of interest and variable LIBOR	$ 200,000,000

XML

Interest And Other Income

9 Months Ended

Sep. 30, 2011

Interest And Other Income [Abstract]

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 September 30,					Nine Months Ended September 30,
	2011		2010			2011		2010
	(in thousands)
Alaskan Petroleum Production Tax credits (a)	$	95	$	12,129		$	27,547	$	39,990
Third-party income from vertical integration services (b)		13,691		268			30,294		1,776
Other income (loss)		222		(478	)		3,135		1,304
Eagle Ford Shale land fees		1,001		—			2,803		—
Equity interest in income (loss) of unconsolidated affiliate		1,641		(269	)		2,442		(269	)
Deferred compensation plan income		288		206			1,454		890
Change in asset retirement estimates		556		—			556		—
Interest income		79		3,113			483		3,589
Insurance claim recovery		—		—			—		1,665
Sales and other tax refunds		—		—			—		984
Total interest and other income	$	17,573	$	14,969		$	68,714	$	49,929

(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 gross margins from vertical integration services primarily represents third party revenues less operating costs associated with Company-provided fracture stimulation, drilling and related services.

XML

Document And Entity Information	9 Months Ended
	Sep. 30, 2011	Nov. 01, 2011
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
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		116,881,280

XML

Disclosures About Fair Value Measurements (Fair Values Of The Company's Financial Instruments) (Details) (USD $)	9 Months Ended
	Sep. 30, 2011		Dec. 31, 2010
Liabilities
Proceeds from termination of interest rate derivatives	$ 26,100,000
Interest Rate Derivatives [Member]
Assets
Carrying Value			18,256,000
Fair Value			18,256,000
Liabilities
Carrying Value	12,664,000		704,000
Fair Value	12,664,000		704,000
Pioneer Southwest Credit Facility [Member]
Liabilities
Carrying Value	97,000,000		81,200,000
Fair Value	94,917,000		77,241,000
Pioneer Credit Facility [Member]
Liabilities
Carrying Value			49,000,000
Fair Value			58,382,000
Trading Securities [Member]
Assets
Carrying Value	429,000		467,000
Fair Value	429,000		467,000
Commodity Derivatives [Member]
Assets
Carrying Value	459,560,000		304,434,000
Fair Value	459,560,000		304,434,000
Liabilities
Carrying Value	16,659,000		136,867,000
Fair Value	16,659,000		136,867,000
Deferred Compensation Plan Assets [Member]
Assets
Carrying Value	35,786,000		36,162,000
Fair Value	35,786,000		36,162,000
5.875% Senior Notes Due 2016 [Member]
Liabilities
Carrying Value	403,188,000		396,880,000
Fair Value	475,878,000		475,194,000
Senior notes, interest rate	5.875%
Debt instrument expiration date	2016
6.65% Senior Notes Due 2017 [Member]
Liabilities
Carrying Value	484,149,000		484,046,000
Fair Value	522,695,000		516,632,000
Senior notes, interest rate	6.65%
Debt instrument expiration date	2017
6.875% Senior Notes Due 2018 [Member]
Liabilities
Carrying Value	449,217,000		449,192,000
Fair Value	480,965,000		480,969,000
Senior notes, interest rate	6.875%
Debt instrument expiration date	2018
7.50% Senior Notes Due 2020 [Member]
Liabilities
Carrying Value	446,643,000		446,433,000
Fair Value	506,250,000		494,145,000
Senior notes, interest rate	7.50%
Debt instrument expiration date	2020
7.20% Senior Notes Due 2028 [Member]
Liabilities
Carrying Value	249,928,000		249,925,000
Fair Value	259,875,000		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	457,246,000	[1]	444,994,000	[1]
Fair Value	$ 578,589,000	[1]	$ 728,400,000	[1]
Senior notes, interest rate	2.875%
Debt instrument expiration date	2038

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

XML

Subsequent Events

9 Months Ended

Sep. 30, 2011

Subsequent Events [Abstract]

Subsequent Events

NOTE R.    Subsequent Events

The Company has evaluated subsequent events through the date of issuance of its unaudited consolidated financial statements. The Company is not aware of any reportable subsequent events.

XML

Disclosures About Fair Value Measurements (Fair Value Measurements Using Significant Unobservable Inputs) (Details) (NGL Swap Contracts [Member], USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011		Sep. 30, 2011
NGL Swap Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Beginning liability balance	$ (13,351)		$ (9,556)
Net unrealized gains included in earnings	3,983	[1]	188	[1]
Net realized losses included in earnings	(4,478)	[1]	(11,803)	[1]
Settlement payments	4,478		11,803
Transfers out of Level 3	9,368		9,368
Ending liability balance

[1] Changes in fair value are included in net derivative gains in the accompanying consolidated statements of operations.

XML

Disclosures About Fair Value Measurements

9 Months Ended

Sep. 30, 2011

Disclosures About Fair Value Measurements [Abstract]

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 September 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 September 30, 2011
	(in thousands)
Assets:
Trading securities	$	283	$	146	$	—	$	429
Commodity derivatives		—		459,560		—		459,560
Deferred compensation plan assets		35,786		—		—		35,786
Total assets	$	36,069	$	459,706	$	—	$	495,775
Liabilities:
Commodity derivatives	$	—	$	16,659	$	—	$	16,659
Interest rate derivatives		—		12,664		—		12,664
Pioneer Southwest credit facility		—		94,917		—		94,917
5.875% senior notes due 2016		475,878		—		—		475,878
6.65% senior notes due 2017		522,695		—		—		522,695
6.875% senior notes due 2018		480,965		—		—		480,965
7.50% senior notes due 2020		506,250		—		—		506,250
7.20% senior notes due 2028		259,875		—		—		259,875
2.875% senior convertible notes due 2038 (a)		578,589		—		—		578,589
Total liabilities	$	2,824,252	$	124,240	$	—	$	2,948,492

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

The Company's natural gas liquid ("NGL") derivative contracts were classified as Level 3 in the fair value hierarchy prior to the three months ended September 30, 2011. The Company's NGL derivative contracts are now classified as Level 2 in the fair value hierarchy as a result of the Company being able to obtain independent market-quoted NGL forward prices.

The following table presents changes in the fair values of the Company's commodity derivative assets and liabilities that were previously classified as Level 3 in the fair value hierarchy:

Fair Value Measurements Using Significant Unobservable Inputs (Level 3)	Three Months  Ended September 30, 2011			Nine Months  Ended September 30, 2011
	(in thousands)
Beginning liability balance	$	(13,351	)	$	(9,556	)
Fair value changes (a):
Net unrealized gains included in earnings		3,983			188
Net realized losses included in earnings		(4,478	)		(11,803	)
Settlement payments		4,478			11,803
Transfers out of Level 3		9,368			9,368
Ending liability balance	$	—		$	—

(a) Changes in fair value are included in net derivative gains 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 September 30, 2011 and December 31, 2010:

	September 30, 2011				December 31, 2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Assets:
Commodity price derivatives	$	459,560	$	459,560	$	304,434	$	304,434
Interest rate derivatives	$	—	$	—	$	18,256	$	18,256
Trading securities	$	429	$	429	$	467	$	467
Deferred compensation plan assets	$	35,786	$	35,786	$	36,162	$	36,162
Liabilities:
Commodity price derivatives	$	16,659	$	16,659	$	136,867	$	136,867
Interest rate derivatives	$	12,664	$	12,664	$	704	$	704
Pioneer credit facility	$	—	$	—	$	49,000	$	58,382
Pioneer Southwest credit facility	$	97,000	$	94,917	$	81,200	$	77,241
5.875 % senior notes due 2016	$	403,188	$	475,878	$	396,880	$	475,194
6.65 % senior notes due 2017	$	484,149	$	522,695	$	484,046	$	516,632
6.875 % senior notes due 2018	$	449,217	$	480,965	$	449,192	$	480,969
7.50 % senior notes due 2020	$	446,643	$	506,250	$	446,433	$	494,145
7.20 % senior notes due 2028	$	249,928	$	259,875	$	249,925	$	259,350
2.875% senior convertible notes due 2038 (a)	$	457,246	$	578,589	$	444,994	$	728,400

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

(a) 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 are comprised of securities that are both actively traded and not actively traded on major exchanges. The Company's deferred compensation plan assets represent investments in equity and mutual fund securities that are actively traded on major exchanges as of the measurement date. As of September 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 with broker quotes representing Level 2 inputs.

Interest rate derivatives. The Company's interest rate derivative assets and liabilities as of September 30, 2011 represent interest rate swap contracts that, at their inception, locked in a fixed forward 10-year annual rate of 3.06 percent on $200 million notional amount of debt for a period of one year. The net derivative values attributable to the Company's interest rate derivative contracts as of September 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, collar contracts with short puts (which are also known as three-way collar contracts) and NGL percentage of oil index contracts. The Company's oil, gas, NGL and diesel swap, collar, three-way collar and NGL percentage of oil index derivative contract asset and liability measurements represent Level 2 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 Company has also entered into NGL swaps under terms whereby the Company pays variable NGL component market prices and receives a percentage of NYMEX WTI market prices ("NGL Percentage of WTI Oil Prices"). 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 commodity and NGL component prices, (iii) independent active NYMEX futures price quotes for WTI oil and (iv) 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.

XML

Basis Of Presentation (Policy)

9 Months Ended

Sep. 30, 2011

Basis Of Presentation [Abstract]

Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of September 30, 2011 and for the three and nine months ended September 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 nine months ended September 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 nine months ended September 30, 2010, which were originally classified as continuing operations). See Note Q for more information regarding the sale of Pioneer Tunisia.

During the nine months ended September 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

for doubtful accounts. As of September 30, 2011 and December 31, 2010, the Company's allowances for doubtful accounts totaled $1.1 million and $3.7 million, respectively. Changes in the Company's allowance for doubtful accounts during the three and nine months ended September 30, 2011 are summarized in the following table:

	Three Months  Ended September 30, 2011			Nine Months  Ended September 30, 2011
	(in thousands)
Beginning allowance for doubtful accounts balance	$	1,414		$	3,674
Amount recorded in other expense for bad debt expense (recoveries)		51			(1,746	)
Other net decreases		(362	)		(825	)
Ending allowance for doubtful accounts balance	$	1,103		$	1,103

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 (loss) – net deferred hedge gains (losses), 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 2011, 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 $125.4 million and $105.4 million as of September 30, 2011 and December 31, 2010, respectively. The Company recorded net income attributable to the noncontrolling interests of $34.1 million and $49.5 million for the three and nine months ended September 30, 2011, respectively (principally related to Pioneer Southwest), compared to net income attributable to the noncontrolling interests of $2.5 million and $39.0 million for the three and nine months ended September 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.

Revenue recognition. The Company does not recognize revenues until they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.

The Company uses the entitlements method of accounting for oil, natural gas liquids ("NGL") and gas revenues. Sales proceeds in excess of the Company's entitlement are included in other liabilities and the Company's share of sales taken by others is included in other assets in the accompanying consolidated balance sheets.

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 September 30, 2011 and December 31, 2010, accounts payable – due to affiliates includes $4.5 million and $4.9 million, respectively, of liabilities attributable to Liability Awards.

For the three and nine months ended September 30, 2011, the Company recorded $11.7 million and $38.1 million, respectively, of stock-based compensation costs for all plans, as compared to $11.0 million and $31.6 million for the same respective periods of 2010. As of September 30, 2011, there was $78.0 million of unrecognized compensation expense related to unvested share- and unit-based compensation plan awards, including $16.9 million attributable to Liability Awards. This compensation will be recognized over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis.

The Company's issued shares, as reflected in the consolidated balance sheets at September 30, 2011 and December 31, 2010, do not include 533,125 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 nine months ended September 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		443,060			202,436			43,495			86,903			6,812			30,039
Awards vested		(1,075,993	)		(69,805	)		(14,807	)		—			(11,532	)		—
Options exercised		—			—			—			(30,398	)		—			—
Awards forfeited		(51,204	)		(20,491	)		—			—			—			—
Outstanding at September 30, 2011		1,875,642			327,274			292,417			564,044			7,492			65,157

 New accounting pronouncements. In May 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2011-04, "Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRSs." ASU 2011-04 amended Accounting Standards Codification ("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 future financial position, results of operation or liquidity.

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 $125.4 million and $105.4 million as of September 30, 2011 and December 31, 2010, respectively. The Company recorded net income attributable to the noncontrolling interests of $34.1 million and $49.5 million for the three and nine months ended September 30, 2011, respectively (principally related to Pioneer Southwest), compared to net income attributable to the noncontrolling interests of $2.5 million and $39.0 million for the three and nine months ended September 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.

Revenue Recognition

Revenue recognition. The Company does not recognize revenues until they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.

The Company uses the entitlements method of accounting for oil, natural gas liquids ("NGL") and gas revenues. Sales proceeds in excess of the Company's entitlement are included in other liabilities and the Company's share of sales taken by others is included in other assets in the accompanying consolidated balance sheets.

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 September 30, 2011 and December 31, 2010, accounts payable – due to affiliates includes $4.5 million and $4.9 million, respectively, of liabilities attributable to Liability Awards.

For the three and nine months ended September 30, 2011, the Company recorded $11.7 million and $38.1 million, respectively, of stock-based compensation costs for all plans, as compared to $11.0 million and $31.6 million for the same respective periods of 2010. As of September 30, 2011, there was $78.0 million of unrecognized compensation expense related to unvested share- and unit-based compensation plan awards, including $16.9 million attributable to Liability Awards. This compensation will be recognized over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis.

The Company's issued shares, as reflected in the consolidated balance sheets at September 30, 2011 and December 31, 2010, do not include 533,125 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 nine months ended September 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		443,060			202,436			43,495			86,903			6,812			30,039
Awards vested		(1,075,993	)		(69,805	)		(14,807	)		—			(11,532	)		—
Options exercised		—			—			—			(30,398	)		—			—
Awards forfeited		(51,204	)		(20,491	)		—			—			—			—
Outstanding at September 30, 2011		1,875,642			327,274			292,417			564,044			7,492			65,157

XML

Exploratory Costs (Capitalized Exploratory Well And Project Activity) (Details) (USD $) In Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2011	Dec. 31, 2010
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Beginning capitalized exploratory costs	$ 85,111	$ 96,193
Additions to exploratory costs pending the determination of proved reserves	158,448	372,793
Reclassification due to determination of proved reserves	(139,624)	(335,306)
Disposition of assets sold		(28,938)
Exploratory well costs charged to exploration expense	(126)	(933)
Ending capitalized exploratory costs	103,809	103,809
Suspended well costs recorded	8,019	8,019	25,558
Etzler Gas [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Suspended well costs recorded	$ 8,000	$ 8,000

XML

Other Expense (Tables)

9 Months Ended

Sep. 30, 2011

Other Expense [Abstract]

Schedule Of Components Of Other Expense

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011		2010			2011			2010
	(in thousands)
Transportation commitment charges (a)	$	5,141	$	—		$	16,101		$	—
Above market drilling rig related costs (b)		4,632		9,682			15,201			30,233
Other		1,150		2,102			4,176			4,028
Contingency and environmental accrual adjustments		588		260			3,470			507
Tax penalties (recoveries)		190		(18	)		2,478			668
Loss on extinguishment of debt		—		—			2,367			—
Inventory impairments (c)		1,745		5,660			2,332			7,230
Legal settlements		1,573		224			2,201			716
Cancelled well costs		2,113		19			2,872			56
Bad debt expense (recoveries)		51		(547	)		(1,746	)		(577	)
Well servicing operations (d)		—		2,305			—			6,965
Total other expense	$	17,183	$	19,687		$	49,452		$	49,826

(a) Primarily represents contract deficiency payments on excess pipeline capacity.

(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.

XML

Discontinued Operations

9 Months Ended

Sep. 30, 2011

Discontinued Operations [Abstract]

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 $853.6 million, including normal post-closing adjustments, resulting in a pretax gain of $645.2 million. During the three months ended September 30, 2011, the Company reduced the net gain on the transaction by $57 thousand. The historical results of operations of Pioneer Tunisia have been classified as discontinued operations herein.

During the nine months ended September 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 nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands)
Revenues and other income:
Oil and gas	$	—		$	33,965		$	22,130		$	109,813
Interest and other		43			229			4,629			44,643
Gain (loss) on disposition of assets, net (a)		(57	)		—			645,241			—
		(14	)		34,194			672,000			154,456
Costs and expenses:
Oil and gas production		—			3,628			2,126			10,522
Depletion, depreciation and amortization (a)		—			5,740			—			18,086
Exploration and abandonments		—			2,853			4,246			11,182
General and administrative		275			1,343			9,173			5,916
Accretion of discount on asset retirement obligations (a)		—			105			81			309
Other		120			973			1,979			2,134
		395			14,642			17,605			48,149
Income (loss) from discontinued operations before income taxes		(409	)		19,552			654,395			106,307
Current tax provision		(435	)		(11,242	)		(9,971	)		(16,536	)
Deferred tax (provision) benefit (a)		297			9,773			(231,913	)		(26,026	)
Income (loss) from discontinued operations	$	(547	)	$	18,083		$	412,511		$	63,745

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

XML

Postretirement Benefit Obligations

9 Months Ended

Sep. 30, 2011

Postretirement Benefit Obligations [Abstract]

Postretirement Benefit Obligations

NOTE I.    Postretirement Benefit Obligations

As of September 30, 2011 and December 31, 2010, the Company had $6.9 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 are predecessor plans of entities acquired by the Company. These plans had no assets as of September 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 nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands)
Beginning accumulated postretirement benefit obligations	$	6,996		$	8,968		$	7,408		$	9,075
Net benefit payments		(271	)		(543	)		(962	)		(1,127	)
Service costs		61			80			183			241
Net actuarial losses		—			100			—			200
Accretion of interest		79			108			236			324
Ending accumulated postretirement benefit obligations	$	6,865		$	8,713		$	6,865		$	8,713

XML

Consolidated Statements Of Comprehensive Income (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Consolidated Statements Of Comprehensive Income [Abstract]
Net income	$ 385,598	$ 114,573	$ 995,102	$ 563,868
Other comprehensive activity:
Net hedge gains included in continuing operations	(8,224)	(21,913)	(24,418)	(63,536)
Income tax provision	1,838	5,988	6,724	17,060
Other comprehensive activity	(6,386)	(15,925)	(17,694)	(46,476)
Comprehensive income	379,212	98,648	977,408	517,392
Comprehensive (income) loss attributable to the noncontrolling interests	(30,670)	1,898	(39,192)	(25,860)
Comprehensive income attributable to common stockholders	$ 348,542	$ 100,546	$ 938,216	$ 491,532

XML

Geographic Operating Segment Information (Tables)

9 Months Ended

Sep. 30, 2011

Geographic Operating Segment Information [Abstract]

Schedule Of Income Statement By Geographic Operating Segment

	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Three Months Ended September 30, 2011
Revenues and other income:
Oil and gas	$	591,147		$	19,362		$	—		$	610,509
Interest and other		13,691			—			3,882			17,573
Derivative gains, net		—			—			401,072			401,072
Gain (loss) on disposition of assets, net		1,523			—			(475	)		1,048
Hurricane activity, net		1,487			—			—			1,487
		607,848			19,362			404,479			1,031,689
Costs and expenses:
Oil and gas production		118,989			620			—			119,609
Production and ad valorem taxes		38,542			—			—			38,542
Depletion, depreciation and amortization		142,632			8,449			15,455			166,536
Exploration and abandonments		20,026			—			—			20,026
General and administrative		—			—			49,812			49,812
Accretion of discount on asset retirement obligations		2,072			734			—			2,806
Interest		—			—			45,559			45,559
Other		9,773			—			7,410			17,183
		332,034			9,803			118,236			460,073
Income from continuing operations before income taxes		275,814			9,559			286,243			571,616
Income tax provision		(102,051	)		(2,677	)		(80,743	)		(185,471	)
Income from continuing operations	$	173,763		$	6,882		$	205,500		$	386,145

	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Three Months Ended September 30, 2010
Revenues and other income:
Oil and gas	$	416,112		$	21,299		$	—		$	437,411
Interest and other		268			—			14,701			14,969
Derivative gains, net		—			—			127,581			127,581
Gain (loss) on disposition of assets, net		2,429			—			(46	)		2,383
Hurricane activity, net		3,452			—			—			3,452
		422,261			21,299			142,236			585,796
Costs and expenses:
Oil and gas production		99,717			1,000			—			100,717
Production and ad valorem taxes		33,045			—			—			33,045
Depletion, depreciation and amortization		119,726			18,338			9,032			147,096
Exploration and abandonments		21,308			302			—			21,610
General and administrative		—			—			43,417			43,417
Accretion of discount on asset retirement obligations		1,899			622			—			2,521
Interest		—			—			45,002			45,002
Other		9,682			—			10,005			19,687
		285,377			20,262			107,456			413,095
Income from continuing operations before income taxes		136,884			1,037			34,780			172,701
Income tax provision		(50,647	)		(290	)		(25,274	)		(76,211	)
Income from continuing operations	$	86,237		$	747		$	9,506		$	96,490
	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Nine Months Ended September 30, 2011
Revenues and other income:
Oil and gas	$	1,629,287		$	62,283		$	—		$	1,691,570
Interest and other		30,294			—			38,420			68,714
Derivative gains, net		—			—			386,118			386,118
Gain (loss) on disposition of assets, net		1,523			—			(2,962	)		(1,439	)
Hurricane activity, net		1,418			—			—			1,418
		1,662,522			62,283			421,576			2,146,381
Costs and expenses:
Oil and gas production		319,564			2,431			—			321,995
Production and ad valorem taxes		107,702			—			—			107,702
Depletion, depreciation and amortization		387,035			35,671			38,101			460,807
Exploration and abandonments		57,242			341			—			57,583
General and administrative		—			—			138,562			138,562
Accretion of discount on asset retirement obligations		6,164			1,955			—			8,119
Interest		—			—			136,554			136,554
Other		31,302			—			18,150			49,452
		909,009			40,398			331,367			1,280,774
Income from continuing operations before income taxes		753,513			21,885			90,209			865,607
Income tax benefit (provision)		(278,800	)		(6,128	)		1,912			(283,016	)
Income from continuing operations	$	474,713		$	15,757		$	92,121		$	582,591

	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Nine Months Ended September 30, 2010
Revenues and other income:
Oil and gas	$	1,264,316		$	67,182		$	—		$	1,331,498
Interest and other		1,776			—			48,153			49,929
Derivative gains, net		—			—			570,585			570,585
Gain (loss) on disposition of assets, net		27,408			—			(437	)		26,971
Hurricane activity, net		5,678			—			—			5,678
		1,299,178			67,182			618,301			1,984,661
Costs and expenses:
Oil and gas production		278,157			2,672			—			280,829
Production and ad valorem taxes		85,444			—			—			85,444
Depletion, depreciation and amortization		353,090			58,677			24,066			435,833
Exploration and abandonments		60,773			428			—			61,201
General and administrative		—			—			122,165			122,165
Accretion of discount on asset retirement obligations		6,043			1,866			—			7,909
Interest		—			—			137,893			137,893
Other		30,233			—			19,593			49,826
		813,740			63,643			303,717			1,181,100
Income from continuing operations before income taxes		485,438			3,539			314,584			803,561
Income tax provision		(179,612	)		(991	)		(122,835	)		(303,438	)
Income from continuing operations	$	305,826		$	2,548		$	191,749		$	500,123

	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Nine Months Ended September 30, 2010
Revenues and other income:
Oil and gas	$	1,264,316		$	67,182		$	—		$	1,331,498
Interest and other		1,776			—			48,153			49,929
Derivative gains, net		—			—			570,585			570,585
Gain (loss) on disposition of assets, net		27,408			—			(437	)		26,971
Hurricane activity, net		5,678			—			—			5,678
		1,299,178			67,182			618,301			1,984,661
Costs and expenses:
Oil and gas production		278,157			2,672			—			280,829
Production and ad valorem taxes		85,444			—			—			85,444
Depletion, depreciation and amortization		353,090			58,677			24,066			435,833
Exploration and abandonments		60,773			428			—			61,201
General and administrative		—			—			122,165			122,165
Accretion of discount on asset retirement obligations		6,043			1,866			—			7,909
Interest		—			—			137,893			137,893
Other		30,233			—			19,593			49,826
		813,740			63,643			303,717			1,181,100
Income from continuing operations before income taxes		485,438			3,539			314,584			803,561
Income tax provision		(179,612	)		(991	)		(122,835	)		(303,438	)
Income from continuing operations	$	305,826		$	2,548		$	191,749		$	500,123

	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Nine Months Ended September 30, 2010
Revenues and other income:
Oil and gas	$	1,264,316		$	67,182		$	—		$	1,331,498
Interest and other		1,776			—			48,153			49,929
Derivative gains, net		—			—			570,585			570,585
Gain (loss) on disposition of assets, net		27,408			—			(437	)		26,971
Hurricane activity, net		5,678			—			—			5,678
		1,299,178			67,182			618,301			1,984,661
Costs and expenses:
Oil and gas production		278,157			2,672			—			280,829
Production and ad valorem taxes		85,444			—			—			85,444
Depletion, depreciation and amortization		353,090			58,677			24,066			435,833
Exploration and abandonments		60,773			428			—			61,201
General and administrative		—			—			122,165			122,165
Accretion of discount on asset retirement obligations		6,043			1,866			—			7,909
Interest		—			—			137,893			137,893
Other		30,233			—			19,593			49,826
		813,740			63,643			303,717			1,181,100
Income from continuing operations before income taxes		485,438			3,539			314,584			803,561
Income tax provision		(179,612	)		(991	)		(122,835	)		(303,438	)
Income from continuing operations	$	305,826		$	2,548		$	191,749		$	500,123

Reconciliation Of Assets From Segment To Consolidated

	September 30, 2011		December 31, 2010
	(in thousands)
Consolidating Assets by Geographic Area:
United States	$	10,775,975	$	8,987,141
South Africa		86,710		134,901
Tunisia		—		325,942
Headquarters		122,358		231,118
Total consolidated assets	$	10,985,043	$	9,679,102

XML

Long-Term Debt

9 Months Ended

Sep. 30, 2011

Long-Term Debt [Abstract]

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 September 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 September 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 nine months ended September 30, 2011 (see Note P).

Convertible senior notes. As of September 30, 2011 and December 31, 2010, the Company had $479.9 million of 2.875% Convertible Senior Notes outstanding. The 2.875% Convertible Senior Notes are convertible under certain circumstances, using a net share settlement process, into a combination of cash and the Company's common stock pursuant to a formula set forth in the indenture supplement pursuant to which the 2.875% Convertible Senior Notes were issued.

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, certain holders of the 2.875% Convertible Senior Notes tendered $70 thousand principal amount of the notes for conversion during the three months ended June 30, 2011. During July and August 2011, the Company paid the tendering holders a total of $71 thousand of cash and issued to the tendering holders 340 shares of the Company's common stock in accordance with the terms of the 2.875% Convertible Senior Notes indenture supplement.

During June 2011 and September 2011, the Company's stock price performance did not qualify the 2.875% Convertible Senior Notes for conversion at the option of the holders during either of the three months ended September 30, 2011 or December 31, 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 qualified and been converted on September 30, 2011, the note holders would have received approximately 185 thousand shares of the Company's common stock, which had a market value of $12.1 million as of the close of business on September 30, 2011.

XML

Net Income (Loss) Per Share

9 Months Ended

Sep. 30, 2011

Net Income (Loss) Per Share [Abstract]

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 nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30, 2011									Nine Months Ended September 30, 2011
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Income (loss) as reported	$	386,145		$	(547	)	$	385,598		$	582,591		$	412,511		$	995,102
Net income attributable to the noncontrolling interests		(34,134	)		—			(34,134	)		(49,467	)		—			(49,467	)
Participating basic earnings		(6,797	)		—			(6,797	)		(10,062	)		(7,124	)		(17,186	)
Basic net income (loss) attributable to common stockholders		345,214			(547	)		344,667			523,062			405,387			928,449
Reallocation of participating earnings		189			—			189			268			190			458
Diluted income (loss) attributable to common stockholders	$	345,403		$	(547	)	$	344,856		$	523,330		$	405,577		$	928,907
	Three Months Ended September 30, 2010									Nine Months Ended September 30, 2010
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Income as reported	$	96,490		$	18,083		$	114,573		$	500,123		$	63,745		$	563,868
Net income attributable to the noncontrolling interests		(2,538	)		—			(2,538	)		(39,003	)		—			(39,003	)
Participating basic earnings		(2,265	)		(424	)		(2,689	)		(10,661	)		(1,359	)		(12,020	)
Basic income attributable to common stockholders		91,687			17,659			109,346			450,459			62,386			512,845
Reallocation of participating earnings		16			3			19			112			15			127
Diluted income attributable to common stockholders	$	91,703		$	17,662		$	109,365		$	450,571		$	62,401		$	512,972

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(in thousands)
Weighted average common shares outstanding:
Basic		116,281		115,191		116,122		114,985
Dilutive common stock options		166		168		181		218
Convertible senior notes dilution		185		—		1,618		—
Contingently issuable performance unit shares		443		662		429		629
Diluted		117,075		116,021		118,350		115,832

XML

Derivative Financial Instruments

9 Months Ended

Sep. 30, 2011

Derivative Financial Instruments [Abstract]

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 September 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
NYMEX price							$	77.25	$	77.25
2011 – Collar contracts
Volume								2,000		2,000
NYMEX price:
Ceiling							$	170.00	$	170.00
Floor							$	115.00	$	115.00
2011 – Collar contracts with short puts
Volume								32,000		32,000
NYMEX price:
Ceiling							$	99.33	$	99.33
Floor							$	73.75	$	73.75
Short put							$	59.31	$	59.31
2012 – Swap contracts
Volume		3,000		3,000		3,000		3,000		3,000
NYMEX price (a)	$	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		28,000		28,000		28,000		28,000		28,000
NYMEX price:
Ceiling	$	120.62	$	120.62	$	120.62	$	120.62	$	120.62
Floor	$	83.68	$	83.68	$	83.68	$	83.68	$	83.68
Short put	$	65.82	$	65.82	$	65.82	$	65.82	$	65.82
2014 – Collar contracts with short puts (a)
Volume		16,500		16,500		16,500		16,500		16,500
NYMEX price:
Ceiling	$	129.69	$	129.69	$	129.69	$	129.69	$	129.69
Floor	$	88.48	$	88.48	$	88.48	$	88.48	$	88.48
Short put	$	71.97	$	71.97	$	71.97	$	71.97	$	71.97

(a) Subsequent to September 30, 2011, the Company entered into (i) NYMEX swap contracts on 3,000 Bbls per day of March 2012 through May 2012 forecasted production, whereby the Company receives $0.28 per Bbl and pays the difference between (a) each day's price per Bbl of WTI for the first nearby month less (b) the price per Bbl of WTI for the second nearby NYMEX month, multiplied by .6667; plus (c) each day's price per Bbl of WTI for the first nearby month less (d) the price per Bbl of WTI for the third nearby NYMEX month, multiplied by .3333 and (ii) additional collar contracts with short puts for 3,000 Bbls per day of the Company's 2013 production with a ceiling price of $111.95 per Bbl, a floor price of $85.00 per Bbl and a short put price of $70.00 per Bbl and (iii) terminated collar contracts with short puts for 6,500 Bbls per day of the Company's 2014 production with an average ceiling price of $133.12 per Bbl, an average floor price of $90.00 per Bbl and an average short put price of $65.00 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. Historically, NGL market prices have correlated well with WTI oil prices. The Company has entered into a limited number of NGL Percentage of WTI Oil Prices derivatives to reduce the risk of volatility in NGL to WTI price differentials. The following table sets forth the volumes in Bbls outstanding as of September 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
Blended index price										$	51.50		$	51.50
2011 – Collar contracts
Volume											2,650			2,650
Blended index price:
Ceiling										$	64.23		$	64.23
Floor										$	53.29		$	53.29
2012 – Swap contracts
Volume		750			750			750			750			750
Blended index price	$	35.03		$	35.03		$	35.03		$	35.03		$	35.03
2012 – NGL Percentage of WTI Oil Prices contracts (a)
Volume		2,000			2,000			2,000			2,000			2,000
Percent of WTI oil price		85	%		85	%		85	%		85	%		85	%

(a) Subsequent to September 30, 2011, the Company (i) entered into additional NGL Percentage of WTI Oil Prices contracts for 1,000 Bbls per day of the Company's 2012 production priced at 68 percent of WTI and (ii) converted 3,000 Bbls per day of the Company's 2012 production from NGL Percentage of WTI Oil Prices contracts to NGL collar contracts with short puts with an average ceiling price of $79.99 per Bbl, an average floor price of $67.70 per Bbl and an average short put price of $55.76 per Bbl.

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 September 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
NYMEX price							$	6.13		$	6.13
2011 – Collar contracts with short puts
Volume								200,000			200,000
NYMEX price:
Ceiling							$	8.55		$	8.55
Floor							$	6.32		$	6.32
Short put							$	4.88		$	4.88
2011 – Basis swap contracts
Volume								143,500			143,500
Price differential							$	(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		136,000			136,000			136,000			136,000			136,000
Price differential	$	(0.34	)	$	(0.34	)	$	(0.34	)	$	(0.34	)	$	(0.34	)
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		72,500			72,500			72,500			72,500			72,500
Price differential	$	(0.26	)	$	(0.26	)	$	(0.26	)	$	(0.26	)	$	(0.26	)
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		60,000			60,000			60,000			60,000			60,000
NYMEX price:
Ceiling	$	7.80		$	7.80		$	7.80		$	7.80		$	7.80
Floor	$	5.83		$	5.83		$	5.83		$	5.83		$	5.83
Short put	$	4.42		$	4.42		$	4.42		$	4.42		$	4.42
2014 – Basis swap contracts
Volume		55,000			55,000			55,000			55,000			55,000
Price differential	$	(0.24	)	$	(0.24	)	$	(0.24	)	$	(0.24	)	$	(0.24	)
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

2015 – Collar contracts with short puts
Volume		30,000		30,000		30,000		30,000		30,000
NYMEX price:
Ceiling	$	7.11	$	7.11	$	7.11	$	7.11	$	7.11
Floor	$	5.00	$	5.00	$	5.00	$	5.00	$	5.00
Short put	$	4.00	$	4.00	$	4.00	$	4.00	$	4.00

Diesel prices. As of September 30, 2011, the Company has diesel derivative swap contracts for 250 notional Bbls per day for the period from October 2011 through December 2011 at an average per Bbl fixed price of $123.90 and for all of 2012 at an average per Bbl fixed price of $119.28. The diesel derivative swap contracts are priced at an index that is highly correlated to the prices that the Company incurs to fuel its drilling rigs and fracture stimulation fleet equipment. The Company purchases diesel derivative swap contracts to mitigate fuel price risk.

Interest rates. As of September 30, 2011, the Company is a party to interest rate derivative contracts that lock in, through July 2012, a fixed forward 10-year annual interest rate of 3.06 percent on $200 million notional amount of debt.

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

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

Fair Value of Derivative Instruments as of September 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	$	247,036	Derivatives - current	$	24,607
Commodity price derivatives	Derivatives - noncurrent		230,875	Derivatives - noncurrent		10,403
Interest rate derivatives	Derivatives - noncurrent		—	Derivatives - noncurrent		12,664
		$	477,911		$	47,674

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.

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 September 30,						Nine Months  Ended September 30,
		2011			2010			2011			2010
		(in thousands)
Commodity price derivatives	Oil and gas revenue	$	8,295		$	21,976		$	24,627		$	67,634
Interest rate derivatives	Interest expense		(71	)		(63	)		(209	)		(1,633	)
Interest rate derivatives	Derivative gains, net		—			—			—			(2,465	)
Total		$	8,224		$	21,913		$	24,418		$	63,536

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 September 30,					Nine Months Ended September 30,
			2011			2010		2011		2010
			(in thousands)
Commodity price derivatives		Derivative gains, net	$	407,407		$	112,733	$	380,030	$	520,486
Interest rate derivatives		Derivative gains, net		(6,335	)		14,848		6,088		52,564
Total			$	401,072		$	127,581	$	386,118	$	573,050

AOCI - Hedging. As of September 30, 2011 AOCI – Hedging represented net deferred losses of $58 thousand compared to net deferred gains of $7.4 million as of December 31, 2010. The AOCI – Hedging balance as of September 30, 2011 was comprised of $5.1 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 $0.1 million of associated net deferred tax benefits, reduced by $3.5 million of AOCI – Hedging net deferred gains attributable to and classified as noncontrolling interests in consolidated subsidiaries.

During the twelve months ending September 30, 2012, the Company expects to reclassify $5.9 million of AOCI – Hedging net deferred gains to oil revenues (including $3.5 million related to noncontrolling interests) and $308 thousand of AOCI – Hedging net deferred losses to interest expense. The Company also expects to reclassify $777 thousand of net deferred income tax provisions associated with hedge derivatives during the twelve months ending September 30, 2012 from AOCI – Hedging to income tax expense.

XML

Derivative Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2011

Derivative Financial Instruments [Abstract]

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
NYMEX price							$	77.25	$	77.25
2011 – Collar contracts
Volume								2,000		2,000
NYMEX price:
Ceiling							$	170.00	$	170.00
Floor							$	115.00	$	115.00
2011 – Collar contracts with short puts
Volume								32,000		32,000
NYMEX price:
Ceiling							$	99.33	$	99.33
Floor							$	73.75	$	73.75
Short put							$	59.31	$	59.31
2012 – Swap contracts
Volume		3,000		3,000		3,000		3,000		3,000
NYMEX price (a)	$	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		28,000		28,000		28,000		28,000		28,000
NYMEX price:
Ceiling	$	120.62	$	120.62	$	120.62	$	120.62	$	120.62
Floor	$	83.68	$	83.68	$	83.68	$	83.68	$	83.68
Short put	$	65.82	$	65.82	$	65.82	$	65.82	$	65.82
2014 – Collar contracts with short puts (a)
Volume		16,500		16,500		16,500		16,500		16,500
NYMEX price:
Ceiling	$	129.69	$	129.69	$	129.69	$	129.69	$	129.69
Floor	$	88.48	$	88.48	$	88.48	$	88.48	$	88.48
Short put	$	71.97	$	71.97	$	71.97	$	71.97	$	71.97

(a) Subsequent to September 30, 2011, the Company entered into (i) NYMEX swap contracts on 3,000 Bbls per day of March 2012 through May 2012 forecasted production, whereby the Company receives $0.28 per Bbl and pays the difference between (a) each day's price per Bbl of WTI for the first nearby month less (b) the price per Bbl of WTI for the second nearby NYMEX month, multiplied by .6667; plus (c) each day's price per Bbl of WTI for the first nearby month less (d) the price per Bbl of WTI for the third nearby NYMEX month, multiplied by .3333 and (ii) additional collar contracts with short puts for 3,000 Bbls per day of the Company's 2013 production with a ceiling price of $111.95 per Bbl, a floor price of $85.00 per Bbl and a short put price of $70.00 per Bbl and (iii) terminated collar contracts with short puts for 6,500 Bbls per day of the Company's 2014 production with an average ceiling price of $133.12 per Bbl, an average floor price of $90.00 per Bbl and an average short put price of $65.00 per Bbl.

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
Blended index price										$	51.50		$	51.50
2011 – Collar contracts
Volume											2,650			2,650
Blended index price:
Ceiling										$	64.23		$	64.23
Floor										$	53.29		$	53.29
2012 – Swap contracts
Volume		750			750			750			750			750
Blended index price	$	35.03		$	35.03		$	35.03		$	35.03		$	35.03
2012 – NGL Percentage of WTI Oil Prices contracts (a)
Volume		2,000			2,000			2,000			2,000			2,000
Percent of WTI oil price		85	%		85	%		85	%		85	%		85	%

(a) Subsequent to September 30, 2011, the Company (i) entered into additional NGL Percentage of WTI Oil Prices contracts for 1,000 Bbls per day of the Company's 2012 production priced at 68 percent of WTI and (ii) converted 3,000 Bbls per day of the Company's 2012 production from NGL Percentage of WTI Oil Prices contracts to NGL collar contracts with short puts with an average ceiling price of $79.99 per Bbl, an average floor price of $67.70 per Bbl and an average short put price of $55.76 per Bbl.

Gas Volume And Weighted Average Price

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		136,000			136,000			136,000			136,000			136,000
Price differential	$	(0.34	)	$	(0.34	)	$	(0.34	)	$	(0.34	)	$	(0.34	)
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		72,500			72,500			72,500			72,500			72,500
Price differential	$	(0.26	)	$	(0.26	)	$	(0.26	)	$	(0.26	)	$	(0.26	)
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		60,000			60,000			60,000			60,000			60,000
NYMEX price:
Ceiling	$	7.80		$	7.80		$	7.80		$	7.80		$	7.80
Floor	$	5.83		$	5.83		$	5.83		$	5.83		$	5.83
Short put	$	4.42		$	4.42		$	4.42		$	4.42		$	4.42
2014 – Basis swap contracts
Volume		55,000			55,000			55,000			55,000			55,000
Price differential	$	(0.24	)	$	(0.24	)	$	(0.24	)	$	(0.24	)	$	(0.24	)
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

Derivative Instruments

Fair Value of Derivative Instruments as of September 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	$	247,036	Derivatives - current	$	24,607
Commodity price derivatives	Derivatives - noncurrent		230,875	Derivatives - noncurrent		10,403
Interest rate derivatives	Derivatives - noncurrent		—	Derivatives - noncurrent		12,664
		$	477,911		$	47,674

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.

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 September 30,						Nine Months  Ended September 30,
		2011			2010			2011			2010
		(in thousands)
Commodity price derivatives	Oil and gas revenue	$	8,295		$	21,976		$	24,627		$	67,634
Interest rate derivatives	Interest expense		(71	)		(63	)		(209	)		(1,633	)
Interest rate derivatives	Derivative gains, net		—			—			—			(2,465	)
Total		$	8,224		$	21,913		$	24,418		$	63,536

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 September 30,					Nine Months Ended September 30,
			2011			2010		2011		2010
			(in thousands)
Commodity price derivatives		Derivative gains, net	$	407,407		$	112,733	$	380,030	$	520,486
Interest rate derivatives		Derivative gains, net		(6,335	)		14,848		6,088		52,564
Total			$	401,072		$	127,581	$	386,118	$	573,050

XML

Income Taxes

9 Months Ended

Sep. 30, 2011

Income Taxes [Abstract]

Income Taxes

NOTE E.    Income Taxes

The Company accounts for income taxes in accordance with the provisions of ASC 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 deferred tax attributes in the U.S., state, local and foreign tax jurisdictions will be utilized prior to their expiration. As of September 30, 2011 and December 31, 2010, the Company's valuation allowances were $5.3 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 September 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 September 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 nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands)
Current:
U.S. federal	$	—		$	(1,550	)	$	—		$	(4,850	)
U.S. state		(2,978	)		(1,520	)		(7,915	)		(4,644	)
Foreign		(8,960	)		(10,211	)		(26,061	)		(10,661	)
		(11,938	)		(13,281	)		(33,976	)		(20,155	)
Deferred:
U.S. federal		(174,758	)		(66,198	)		(274,918	)		(269,256	)
U.S. state		(5,138	)		(6,854	)		5,591			(23,354	)
Foreign		6,363			10,122			20,287			9,327
		(173,533	)		(62,930	)		(249,040	)		(283,283	)
Income tax provision	$	(185,471	)	$	(76,211	)	$	(283,016	)	$	(303,438	)

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands)
Current:
U.S. federal	$	—		$	(4,700	)	$	—		$	(4,700	)
U.S. state		(99	)	$	(400	)	$	(4,034	)	$	(400	)
Foreign		(336	)		(6,142	)		(5,937	)		(11,436	)
		(435	)		(11,242	)		(9,971	)		(16,536	)
Deferred:
U.S. federal		802			4,167			(221,686	)		(8,672	)
U.S. state		(76	)		—			(2,144	)		—
Foreign		(429	)		5,606			(8,083	)		(17,354	)
		297			9,773			(231,913	)		(26,026	)
Income tax provision	$	(138	)	$	(1,469	)	$	(241,884	)	$	(42,562	)

XML

Long-Term Debt (Narrative) (Details) (USD $)	9 Months Ended	3 Months Ended	9 Months Ended	3 Months Ended				9 Months Ended
	Sep. 30, 2011	Sep. 30, 2011 Cash [Member] 2.875% Convertible Senior Notes [Member]	Sep. 30, 2011 Noncash [Member] If Converted [Member] 2.875% Convertible Senior Notes [Member]	Sep. 30, 2011 If Converted [Member] 2.875% Convertible Senior Notes [Member]	Sep. 30, 2011 2.875% Convertible Senior Notes [Member]	Jun. 30, 2011 2.875% Convertible Senior Notes [Member]	Dec. 31, 2010 2.875% Convertible Senior Notes [Member]	Sep. 30, 2011 Swing Line Loans [Member]
Debt Instrument [Line Items]
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
Prime Rate Plus	0.50%
LIBOR Plus A Margin Rate	two
Applicable Margin Plus Rate	0.125%
Credit facility Rate	0.375%
Loss on extinguishment of debt to write off the unamortized issuance costs	2,400,000
Senior notes, interest rate					2.875%		2.875%
Senior convertible notes, outstanding					479,900,000		479,900,000
Senior convertible notes, principal amount						70,000
Shares received for conversion of debt				185,000	340
Value of shares received for conversion of debt		$ 71,000	$ 12,100,000

XML

Consolidated Statement Of Stockholders' Equity (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Consolidated Statement Of Stockholders' Equity [Abstract]
Dividends declared, per share	$ 0.04	$ 0.04	$ 0.08	$ 0.08

XML

Organization And Nature Of Operations

9 Months Ended

Sep. 30, 2011

Organization And Nature Of Operations [Abstract]

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.

XML

Basis Of Presentation (Narrative) (Details) (USD $)	1 Months Ended	3 Months Ended		9 Months Ended		12 Months Ended
	Dec. 31, 2010	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010	Jun. 30, 2011
Other Ownership Interests [Line Items]
Percentage of divest of subsidiaries capital stock	0.00%
Allowance for doubtful accounts, premiums and other receivables	$ 3,674,000	$ 1,103,000		$ 1,103,000		$ 3,674,000	$ 1,414,000
Materials and supplies inventories	183,400,000	283,300,000		283,300,000		183,400,000
Commodities	3,900,000	4,200,000		4,200,000		3,900,000
Net materials and supplies inventories reserves	3,600,000	1,000,000		1,000,000		3,600,000
Inventory value classified as other noncurrent assets	13,700,000	27,200,000		27,200,000		13,700,000
Basis points added to variable interest rate				250
Noncontrolling interests in consolidating subsidiaries	105,442,000	125,432,000		125,432,000		105,442,000
Net income attributable to the noncontrolling interests		34,134,000	2,538,000	49,467,000	39,003,000
Allocated stock-based compensation expense		11,700,000	11,000,000	38,100,000	31,600,000
Share-based compensation arrangement by share-based payment award, award vesting period				three
Restricted stock awards unvested shares at balance sheet date				533,125		825,796
Restricted stock awards liability				16,900,000
Unrecognized compensation expense		78,000,000		78,000,000
Restricted Stock Equity Awards [Member]
Other Ownership Interests [Line Items]
Amount of liabilities attributable to liability awards included in accounts payable				4,500,000		4,900,000
Limited Partner Interest [Member] | Pioneer Southwest [Member]
Other Ownership Interests [Line Items]
Partnerships interest of oil and gas		61.90%		61.90%
General Partner Interest [Member] | Subsidiaries [Member]
Other Ownership Interests [Line Items]
Partnerships interest of oil and gas		0.10%		0.10%
EFS Midstream [Member]
Other Ownership Interests [Line Items]
Percent of interest owned				50.10%
Pioneer Southwest [Member]
Other Ownership Interests [Line Items]
Net income attributable to the noncontrolling interests		34,100,000	2,500,000	49,500,000	39,000,000
Tunisian Subsidiaries [Member]
Other Ownership Interests [Line Items]
Inventories classified as discontinued operations held for sale	13,600,000					13,600,000
BOEMRE [Member]
Other Ownership Interests [Line Items]
Interest and other				$ 2,000,000	$ 35,300,000

XML

Income Taxes (Tables)

9 Months Ended

Sep. 30, 2011

Income Taxes [Abstract]

Income Tax (Provisions) Benefits

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands)
Current:
U.S. federal	$	—		$	(1,550	)	$	—		$	(4,850	)
U.S. state		(2,978	)		(1,520	)		(7,915	)		(4,644	)
Foreign		(8,960	)		(10,211	)		(26,061	)		(10,661	)
		(11,938	)		(13,281	)		(33,976	)		(20,155	)
Deferred:
U.S. federal		(174,758	)		(66,198	)		(274,918	)		(269,256	)
U.S. state		(5,138	)		(6,854	)		5,591			(23,354	)
Foreign		6,363			10,122			20,287			9,327
		(173,533	)		(62,930	)		(249,040	)		(283,283	)
Income tax provision	$	(185,471	)	$	(76,211	)	$	(283,016	)	$	(303,438	)

Discontinued Operations

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands)
Current:
U.S. federal	$	—		$	(4,700	)	$	—		$	(4,700	)
U.S. state		(99	)	$	(400	)	$	(4,034	)	$	(400	)
Foreign		(336	)		(6,142	)		(5,937	)		(11,436	)
		(435	)		(11,242	)		(9,971	)		(16,536	)
Deferred:
U.S. federal		802			4,167			(221,686	)		(8,672	)
U.S. state		(76	)		—			(2,144	)		—
Foreign		(429	)		5,606			(8,083	)		(17,354	)
		297			9,773			(231,913	)		(26,026	)
Income tax provision	$	(138	)	$	(1,469	)	$	(241,884	)	$	(42,562	)

XML

Derivative Financial Instruments (Derivative Obligations Under Terminated Hedge Arrangements) (Details) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Derivative [Line Items]
Amount of Gain/(Loss) Reclassified from AOCI into Earnings	$ 8,224	$ 21,913	$ 24,418	$ 63,536
Amount of Gain (Loss) Recognized in Earnings on Derivatives	401,072	127,581	386,118	573,050
Interest Rate Derivatives [Member] | Interest Expense [Member]
Derivative [Line Items]
Amount of Gain/(Loss) Reclassified from AOCI into Earnings	(71)	(63)	(209)	(1,633)
Interest Rate Derivatives [Member] | Derivative Gains (Losses), Net [Member]
Derivative [Line Items]
Amount of Gain/(Loss) Reclassified from AOCI into Earnings				(2,465)
Amount of Gain (Loss) Recognized in Earnings on Derivatives	(6,335)	14,848	6,088	52,564
Commodity Price Derivatives [Member] | Derivative Gains (Losses), Net [Member]
Derivative [Line Items]
Amount of Gain (Loss) Recognized in Earnings on Derivatives	407,407	112,733	380,030	520,486
Commodity Price Derivatives [Member] | Oil And Gas revenue [Member]
Derivative [Line Items]
Amount of Gain/(Loss) Reclassified from AOCI into Earnings	$ 8,295	$ 21,976	$ 24,627	$ 67,634

XML

Postretirement Benefit Obligations (Accumulated Postretirement Benefit Obligations) (Details) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Postretirement Benefit Obligations [Abstract]
Beginning accumulated postretirement benefit obligations	$ 6,996	$ 8,968	$ 7,408	$ 9,075
Net benefit payments	(271)	(543)	(962)	(1,127)
Service costs	61	80	183	241
Net actuarial losses		100		200
Accretion of interest	79	108	236	324
Ending accumulated postretirement benefit obligations	$ 6,865	$ 8,713	$ 6,865	$ 8,713

XML

Income Taxes (Discontinued Operations) (Details) (USD $) In Thousands	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Income Taxes [Abstract]
U.S. federal			$ (4,700)				$ (4,700)
U.S. state	(99)		(400)		(4,034)		(400)
Foreign	(336)		(6,142)		(5,937)		(11,436)
Total current tax (provision) benefit	(435)		(11,242)		(9,971)		(16,536)
U.S. federal	802		4,167		(221,686)		(8,672)
U.S. state	(76)				(2,144)
Foreign	(429)		5,606		(8,083)		(17,354)
Total deferred tax (provision) benefit	297	[1]	9,773	[1]	(231,913)	[1]	(26,026)	[1]
Income tax provision	$ (138)		$ (1,469)		$ (241,884)		$ (42,562)

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

XML

Geographic Operating Segment Information (Reconciliation Of Assets From Segment To Consolidated) (Details) (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Geographic Operating Segment Information [Abstract]
Total consolidated assets	$ 10,985,043	$ 9,679,102

XML

Basis Of Presentation

9 Months Ended

Sep. 30, 2011

Basis Of Presentation [Abstract]

Basis Of Presentation

NOTE B.    Basis of Presentation

Presentation. In the opinion of management, the consolidated financial statements of the Company as of September 30, 2011 and for the three and nine months ended September 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.

Certain reclassifications have been made to the 2010 financial statement and footnote amounts in order to conform to the 2011 presentations.

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 nine months ended September 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 nine months ended September 30, 2010, which were originally classified as continuing operations). See Note Q for more information regarding the sale of Pioneer Tunisia.

During the nine months ended September 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 September 30, 2011 and December 31, 2010, the Company's allowances for doubtful accounts totaled $1.1 million and $3.7 million, respectively. Changes in the Company's allowance for doubtful accounts during the three and nine months ended September 30, 2011 are summarized in the following table:

	Three Months  Ended September 30, 2011			Nine Months  Ended September 30, 2011
	(in thousands)
Beginning allowance for doubtful accounts balance	$	1,414		$	3,674
Amount recorded in other expense for bad debt expense (recoveries)		51			(1,746	)
Other net decreases		(362	)		(825	)
Ending allowance for doubtful accounts balance	$	1,103		$	1,103

 Inventories. Inventories used in continuing operations consisted of $283.3 million and $183.4 million of materials and supplies and $4.2 million and $3.9 million of commodities as of September 30, 2011 and December 31, 2010, respectively. As of September 30, 2011 and December 31, 2010, the Company's materials and supplies inventory was net of $1.0 million and $3.6 million, respectively, of valuation reserve allowances. As of September 30, 2011 and December 31, 2010, the Company estimated that $27.2 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 (loss) – net deferred hedge gains (losses), 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.

.Impairment of long-lived assets. 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.

During the third quarter of 2011, events and circumstances provided indications of possible impairment of certain of the Company's dry gas assets, including assets in the Company's South Texas (excluding the Eagle Ford Shale), Raton Basin and Barnett Shale areas. The events and circumstances indicating a possible impairment in these areas are primarily related to a reduction in management's price outlooks that led to a decrease in estimated future undiscounted net cash flows attributable to the properties' proved reserves. However, the Company's estimate of undiscounted future net cash flows still indicated that such carrying amounts were expected to be recovered.

The Company's primary assumptions of the estimated future net cash flows attributable to oil and gas properties include (i) utilizing proved reserves (including development of proved undeveloped reserves) and appropriate risk-adjusted probable and possible reserves and (ii) management's commodity price outlook. Nonetheless, it is reasonably possible that the estimate of undiscounted future net cash flows attributable to these or other properties may change in the near or distant future resulting in the need to impair the assets' carrying values. The primary factors that may affect future cash flows are (i) future reserve adjustments, both positive and negative, (ii) results of future drilling activities, (iii) management's outlook on commodity prices and (iv) increases or decreases in production and capital costs associated with these assets.

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 2011, 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 $125.4 million and $105.4 million as of September 30, 2011 and December 31, 2010, respectively. The Company recorded net income attributable to the noncontrolling interests of $34.1 million and $49.5 million for the three and nine months ended September 30, 2011, respectively (principally related to Pioneer Southwest), compared to net income attributable to the noncontrolling interests of $2.5 million and $39.0 million for the three and nine months ended September 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.

Revenue recognition. The Company does not recognize revenues until they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.

The Company uses the entitlements method of accounting for oil, natural gas liquids ("NGL") and gas revenues. Sales proceeds in excess of the Company's entitlement are included in other liabilities and the Company's share of sales taken by others is included in other assets in the accompanying consolidated balance sheets.

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 September 30, 2011 and December 31, 2010, accounts payable – due to affiliates includes $4.5 million and $4.9 million, respectively, of liabilities attributable to Liability Awards.

For the three and nine months ended September 30, 2011, the Company recorded $11.7 million and $38.1 million, respectively, of stock-based compensation costs for all plans, as compared to $11.0 million and $31.6 million for the same respective periods of 2010. As of September 30, 2011, there was $78.0 million of unrecognized compensation expense related to unvested share- and unit-based compensation plan awards, including $16.9 million attributable to Liability Awards. This compensation will be recognized over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis.

The Company's issued shares, as reflected in the consolidated balance sheets at September 30, 2011 and December 31, 2010, do not include 533,125 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 nine months ended September 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		443,060			202,436			43,495			86,903			6,812			30,039
Awards vested		(1,075,993	)		(69,805	)		(14,807	)		—			(11,532	)		—
Options exercised		—			—			—			(30,398	)		—			—
Awards forfeited		(51,204	)		(20,491	)		—			—			—			—
Outstanding at September 30, 2011		1,875,642			327,274			292,417			564,044			7,492			65,157

 New accounting pronouncements. In May 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2011-04, "Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in U.S. GAAP and IFRSs." ASU 2011-04 amended Accounting Standards Codification ("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 future financial position, results of operation or liquidity.

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 impact the Company's future financial position, results of operations or liquidity.

In September 2011, the FASB issued ASU No. 2011-08 "Intangibles—Goodwill and Other (Topic 350)." ASU 2011-08 amends ASC 350 to permit an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. ASU 2011-08 is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The adoption of ASU 2011-08 is not expected to have a material impact on the future carrying value of the Company's goodwill. See "Goodwill" above for more information about the Company's policy for assessing goodwill for impairment.

XML

Basis Of Presentation (Stock-Based Awards, Lapses, Exercises And Forfeitures) (Details)	9 Months Ended
	Sep. 30, 2011
Restricted Stock Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at December 31, 2010	2,559,779
Awards granted	443,060
Awards vested	(1,075,993)
Awards forfeited	(51,204)
Outstanding at September 30, 2011	1,875,642
Restricted Stock Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at December 31, 2010	215,134
Awards granted	202,436
Awards vested	(69,805)
Awards forfeited	(20,491)
Outstanding at September 30, 2011	327,274
Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at December 31, 2010	263,729
Awards granted	43,495
Awards vested	(14,807)
Outstanding at September 30, 2011	292,417
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at December 31, 2010	507,539
Awards granted	86,903
Options exercised	(30,398)
Outstanding at September 30, 2011	564,044
Pioneer Southwest LTIP Restricted Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at December 31, 2010	12,212
Awards granted	6,812
Awards vested	(11,532)
Outstanding at September 30, 2011	7,492
Pioneer Southwest LTIP Phantom Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at December 31, 2010	35,118
Awards granted	30,039
Outstanding at September 30, 2011	65,157

XML

Basis Of Presentation (Tables)

9 Months Ended

Sep. 30, 2011

Basis Of Presentation [Abstract]

Allowance For Doubtful Accounts

	Three Months  Ended September 30, 2011			Nine Months  Ended September 30, 2011
	(in thousands)
Beginning allowance for doubtful accounts balance	$	1,414		$	3,674
Amount recorded in other expense for bad debt expense (recoveries)		51			(1,746	)
Other net decreases		(362	)		(825	)
Ending allowance for doubtful accounts balance	$	1,103		$	1,103

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		443,060			202,436			43,495			86,903			6,812			30,039
Awards vested		(1,075,993	)		(69,805	)		(14,807	)		—			(11,532	)		—
Options exercised		—			—			—			(30,398	)		—			—
Awards forfeited		(51,204	)		(20,491	)		—			—			—			—
Outstanding at September 30, 2011		1,875,642			327,274			292,417			564,044			7,492			65,157

XML

Deferred Revenue (Deferred Revenue Carrying Values) (Details) (Volumetric Production Payment [Member], USD $) In Thousands	9 Months Ended
	Sep. 30, 2011
Volumetric Production Payment [Member]
Deferred Revenue Arrangement [Line Items]
VPP Deferred revenue at December 31, 2010	$ 87,020
Less: 2011 VPP amortization	(33,620)
VPP Deferred revenue at September 30, 2011	$ 53,400

XML

Net Income (Loss) Per Share (Reconciliation Of Weighted-Average Common Shares Outstanding, Basic And Diluted) (Details) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Net Income (Loss) Per Share [Abstract]
Basic	116,281	115,191	116,122	114,985
Dilutive common stock options	166	168	181	218
Convertible senior notes dilution	185		1,618
Contingently issuable performance unit shares	443	662	429	629
Diluted	117,075	116,021	118,350	115,832

XML

Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2011

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands)
Beginning asset retirement obligations	$	151,970		$	137,181		$	152,291		$	166,434
Liabilities assumed in acquisitions		—			—			6			6
New wells placed on production		1,132			2,356			3,206			7,000
Changes in estimates (a)		(5,453	)		—			(5,331	)		—
Disposition of wells		—			(131	)		(448	)		(29,671	)
Liabilities settled		(2,808	)		(6,141	)		(10,277	)		(16,096	)
Accretion of discount from continuing operations		2,806			2,521			8,119			7,909
Accretion of discount from discontinued operations		—			105			81			309
Ending asset retirement obligations	$	147,647		$	135,891		$	147,647		$	135,891

(a) Changes in estimates during 2011 are primarily associated with the deferral of the future abandonment of the Company's South Africa oil and gas properties to allow Petroleum Oil and Gas Corporation of South Africa, Ltd ("PetroSA") to recover take-or-pay make up gas (see Note M) and a $1.5 million reduction in East Cameron 322 reclamation costs.

XML

Basis Of Presentation (Allowances For Doubtful Accounts) (Details) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Basis Of Presentation [Abstract]
Beginning allowance for doubtful accounts balance	$ 1,414		$ 3,674
Amount recorded in other expense for bad debt expense (recoveries)	51	(547)	(1,746)	(577)
Other net decreases	(362)		(825)
Ending allowance for doubtful accounts balance	$ 1,103		$ 1,103

XML

Disclosures About Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2011

Disclosures About Fair Value Measurements [Abstract]

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 September 30, 2011
	(in thousands)
Assets:
Trading securities	$	283	$	146	$	—	$	429
Commodity derivatives		—		459,560		—		459,560
Deferred compensation plan assets		35,786		—		—		35,786
Total assets	$	36,069	$	459,706	$	—	$	495,775
Liabilities:
Commodity derivatives	$	—	$	16,659	$	—	$	16,659
Interest rate derivatives		—		12,664		—		12,664
Pioneer Southwest credit facility		—		94,917		—		94,917
5.875% senior notes due 2016		475,878		—		—		475,878
6.65% senior notes due 2017		522,695		—		—		522,695
6.875% senior notes due 2018		480,965		—		—		480,965
7.50% senior notes due 2020		506,250		—		—		506,250
7.20% senior notes due 2028		259,875		—		—		259,875
2.875% senior convertible notes due 2038 (a)		578,589		—		—		578,589
Total liabilities	$	2,824,252	$	124,240	$	—	$	2,948,492

(a) 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 September 30, 2011			Nine Months  Ended September 30, 2011
	(in thousands)
Beginning liability balance	$	(13,351	)	$	(9,556	)
Fair value changes (a):
Net unrealized gains included in earnings		3,983			188
Net realized losses included in earnings		(4,478	)		(11,803	)
Settlement payments		4,478			11,803
Transfers out of Level 3		9,368			9,368
Ending liability balance	$	—		$	—

(a) Changes in fair value are included in net derivative gains in the accompanying consolidated statements of operations.

Fair Values Of The Company Financial Instruments

	September 30, 2011				December 31, 2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in thousands)
Assets:
Commodity price derivatives	$	459,560	$	459,560	$	304,434	$	304,434
Interest rate derivatives	$	—	$	—	$	18,256	$	18,256
Trading securities	$	429	$	429	$	467	$	467
Deferred compensation plan assets	$	35,786	$	35,786	$	36,162	$	36,162
Liabilities:
Commodity price derivatives	$	16,659	$	16,659	$	136,867	$	136,867
Interest rate derivatives	$	12,664	$	12,664	$	704	$	704
Pioneer credit facility	$	—	$	—	$	49,000	$	58,382
Pioneer Southwest credit facility	$	97,000	$	94,917	$	81,200	$	77,241
5.875 % senior notes due 2016	$	403,188	$	475,878	$	396,880	$	475,194
6.65 % senior notes due 2017	$	484,149	$	522,695	$	484,046	$	516,632
6.875 % senior notes due 2018	$	449,217	$	480,965	$	449,192	$	480,969
7.50 % senior notes due 2020	$	446,643	$	506,250	$	446,433	$	494,145
7.20 % senior notes due 2028	$	249,928	$	259,875	$	249,925	$	259,350
2.875% senior convertible notes due 2038 (a)	$	457,246	$	578,589	$	444,994	$	728,400

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

XML

Commitments And Contingencies

9 Months Ended

Sep. 30, 2011

Commitments And Contingencies [Abstract]

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.

XML

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]
Derivative [Line Items]
Volume	117,500				117,500
NYMEX price	6.13				6.13
2011 - Collar Contracts With Short Puts [Member]
Derivative [Line Items]
Volume	200,000				200,000
2011 - Collar Contracts With Short Puts [Member] | Ceiling [Member]
Derivative [Line Items]
NYMEX price	8.55				8.55
2011 - Collar Contracts With Short Puts [Member] | Floor [Member]
Derivative [Line Items]
NYMEX price	6.32				6.32
2011 - Collar Contracts With Short Puts [Member] | Short Put [Member]
Derivative [Line Items]
NYMEX price	4.88				4.88
2011 - Basis Swap Contracts [Member]
Derivative [Line Items]
Volume	143,500				143,500
NYMEX price	(0.56)				(0.56)
2012 - Collar Contracts [Member]
Derivative [Line Items]
Volume	65,000	65,000	65,000	65,000	65,000
2012 - Collar Contracts [Member] | Ceiling [Member]
Derivative [Line Items]
NYMEX price	6.60	6.60	6.60	6.60	6.60
2012 - Collar Contracts [Member] | Floor [Member]
Derivative [Line Items]
NYMEX price	5.00	5.00	5.00	5.00	5.00
2012 - Collar Contracts With Short Puts [Member]
Derivative [Line Items]
Volume	190,000	190,000	190,000	190,000	190,000
2012 - Collar Contracts With Short Puts [Member] | Ceiling [Member]
Derivative [Line Items]
NYMEX price	7.96	7.96	7.96	7.96	7.96
2012 - Collar Contracts With Short Puts [Member] | Floor [Member]
Derivative [Line Items]
NYMEX price	6.12	6.12	6.12	6.12	6.12
2012 - Collar Contracts With Short Puts [Member] | Short Put [Member]
Derivative [Line Items]
NYMEX price	4.55	4.55	4.55	4.55	4.55
2012 - Basis Swap Contracts [Member]
Derivative [Line Items]
Volume	136,000	136,000	136,000	136,000	136,000
NYMEX price	(0.34)	(0.34)	(0.34)	(0.34)	(0.34)
2012 - Swap Contracts [Member]
Derivative [Line Items]
Volume	105,000	105,000	105,000	105,000	105,000
NYMEX price	5.82	5.82	5.82	5.82	5.82
2013 - Swap Contracts [Member]
Derivative [Line Items]
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]
Derivative [Line Items]
Volume	150,000	150,000	150,000	150,000	150,000
2013 - Collar Contracts [Member] | Ceiling [Member]
Derivative [Line Items]
NYMEX price	6.25	6.25	6.25	6.25	6.25
2013 - Collar Contracts [Member] | Floor [Member]
Derivative [Line Items]
NYMEX price	5.00	5.00	5.00	5.00	5.00
2013 - Collar Contracts With Short Puts [Member]
Derivative [Line Items]
Volume	45,000	45,000	45,000	45,000	45,000
2013 - Collar Contracts With Short Puts [Member] | Ceiling [Member]
Derivative [Line Items]
NYMEX price	7.49	7.49	7.49	7.49	7.49
2013 - Collar Contracts With Short Puts [Member] | Floor [Member]
Derivative [Line Items]
NYMEX price	6.00	6.00	6.00	6.00	6.00
2013 - Collar Contracts With Short Puts [Member] | Short Put [Member]
Derivative [Line Items]
NYMEX price	4.50	4.50	4.50	4.50	4.50
2013 - Basis Swap Contracts [Member]
Derivative [Line Items]
Volume	72,500	72,500	72,500	72,500	72,500
NYMEX price	(0.26)	(0.26)	(0.26)	(0.26)	(0.26)
2014 - Swap Contracts [Member]
Derivative [Line Items]
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]
Derivative [Line Items]
Volume	140,000	140,000	140,000	140,000	140,000
2014 - Collar Contracts [Member] | Ceiling [Member]
Derivative [Line Items]
NYMEX price	6.44	6.44	6.44	6.44	6.44
2014 - Collar Contracts [Member] | Floor [Member]
Derivative [Line Items]
NYMEX price	5.00	5.00	5.00	5.00	5.00
2014 - Collar Contracts With Short Puts [Member]
Derivative [Line Items]
Volume	60,000	60,000	60,000	60,000	60,000
2014 - Collar Contracts With Short Puts [Member] | Ceiling [Member]
Derivative [Line Items]
NYMEX price	7.80	7.80	7.80	7.80	7.80
2014 - Collar Contracts With Short Puts [Member] | Floor [Member]
Derivative [Line Items]
NYMEX price	5.83	5.83	5.83	5.83	5.83
2014 - Collar Contracts With Short Puts [Member] | Short Put [Member]
Derivative [Line Items]
NYMEX price	4.42	4.42	4.42	4.42	4.42
2014 - Basis Swap Contracts [Member]
Derivative [Line Items]
Volume	55,000	55,000	55,000	55,000	55,000
NYMEX price	(0.24)	(0.24)	(0.24)	(0.24)	(0.24)
2015 - Collar contracts [Member]
Derivative [Line Items]
Volume	50,000	50,000	50,000	50,000	50,000
2015 - Collar contracts [Member] | Ceiling [Member]
Derivative [Line Items]
NYMEX price	7.92	7.92	7.92	7.92	7.92
2015 - Collar contracts [Member] | Floor [Member]
Derivative [Line Items]
NYMEX price	5.00	5.00	5.00	5.00	5.00
2015 - Collar contracts with short puts [Member]
Derivative [Line Items]
Volume	30,000	30,000	30,000	30,000	30,000
2015 - Collar contracts with short puts [Member] | Ceiling [Member]
Derivative [Line Items]
NYMEX price	7.11	7.11	7.11	7.11	7.11
2015 - Collar contracts with short puts [Member] | Floor [Member]
Derivative [Line Items]
NYMEX price	5.00	5.00	5.00	5.00	5.00
2015 - Collar contracts with short puts [Member] | Short Put [Member]
Derivative [Line Items]
NYMEX price	4.00	4.00	4.00	4.00	4.00

XML

Net Income (Loss) Per Share (Reconciliation Of Earnings, Basic And Diluted) (Details) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Statement Operating Activities Segment [Line Items]
Income (loss) as reported, Continuing Operations	$ 386,145	$ 96,490	$ 582,591	$ 500,123
Income (loss) as reported, Discontinued Operations	(547)	18,083	412,511	63,745
Profit Loss	385,598	114,573	995,102	563,868
Net income attributable to the noncontrolling interests	(34,134)	(2,538)	(49,467)	(39,003)
Participating basic distributed earnings	(6,797)	(2,689)	(17,186)	(12,020)
Basic income (loss) attributable to common stockholders	344,667	109,346	928,449	512,845
Reallocation of participating earnings	189	19	458	127
Diluted income (loss) attributable to common stockholders	344,856	109,365	928,907	512,972
Segment, Continuing Operations [Member]
Statement Operating Activities Segment [Line Items]
Income (loss) as reported, Continuing Operations	386,145	96,490	582,591	500,123
Net income attributable to the noncontrolling interests	(34,134)	(2,538)	(49,467)	(39,003)
Participating basic distributed earnings	(6,797)	(2,265)	(10,062)	(10,661)
Basic income (loss) attributable to common stockholders	345,214	91,687	523,062	450,459
Reallocation of participating earnings	189	16	268	112
Diluted income (loss) attributable to common stockholders	345,403	91,703	523,330	450,571
Segment, Discontinued Operations [Member]
Statement Operating Activities Segment [Line Items]
Income (loss) as reported, Discontinued Operations	(547)	18,083	412,511	63,745
Participating basic distributed earnings		(424)	(7,124)	(1,359)
Basic income (loss) attributable to common stockholders	(547)	17,659	405,387	62,386
Reallocation of participating earnings		3	190	15
Diluted income (loss) attributable to common stockholders	$ (547)	$ 17,662	$ 405,577	$ 62,401

XML

Exploratory Costs

9 Months Ended

Sep. 30, 2011

Exploratory Costs [Abstract]

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 accompanying consolidated balance sheets. If the exploratory well or project is determined to be impaired, the impaired costs are charged to exploration and abandonments expense.

The following table reflects the Company's capitalized exploratory well and project activity during the three and nine months ended September 30, 2011:

	Three Months  Ended September 30, 2011			Nine Months  Ended September 30, 2011
	(in thousands)
Beginning capitalized exploratory costs	$	85,111		$	96,193
Additions to exploratory costs pending the determination of proved reserves		158,448			372,793
Reclassification due to determination of proved reserves		(139,624	)		(335,306	)
Disposition of assets sold		—			(28,938	)
Exploratory well costs charged to exploration expense		(126	)		(933	)
Ending capitalized exploratory costs	$	103,809		$	103,809

The following table provides an aging, as of September 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:

	September 30, 2011		December 31, 2010
	(in thousands, except project counts)
Capitalized exploratory costs that have been suspended:
One year or less	$	95,790	$	70,635
More than one year		8,019		25,558
	$	103,809	$	96,193
Number of projects with exploratory costs that have been suspended for a period greater than one year		1		3

As of September 30, 2011, the Company had one project with exploratory costs that had 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 September 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 fourth quarter 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.

NOTE D.    Disclosures About Fair Value Measurements

XML

Deferred Revenue

9 Months Ended

Sep. 30, 2011

Deferred Revenue [Abstract]

Deferred Revenue

NOTE M.    Deferred Revenue

The Company's deferred revenue is associated with a United States volumetric production payment obligation ("VPP") and take-or-pay gas receipts under the Company's South Africa gas sales agreement that are each expected to be recovered volumetrically by the purchasers.

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) transferred title of the reserves to the purchaser and (v) allows 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 nine months ended September 30, 2011 (in thousands):

VPP Deferred revenue at December 31, 2010	$	87,020
Less: 2011 VPP amortization		(33,620	)
VPP Deferred revenue at September 30, 2011	$	53,400

The remaining VPP 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	$	11,329
2012	$	42,071

During July 2011, the Company received $36.1 million of cash take-or-pay proceeds from PetroSA in accordance with the terms of its South Coast Gas Project gas sales agreement (the "GSA"). The terms of the GSA obligate PetroSA to purchase certain minimum volumes of gas per year as a source for its gas-to-liquids plant in South Africa. Under certain circumstances, if PetroSA fails to take such minimum volumes, then PetroSA is contractually obligated to make take-or-pay payments to the Company. The GSA allows PetroSA to take delivery of available take-or-pay make up volumes during certain stipulated periods, including a period of one year beyond the date the GSA would otherwise expire.

The Company recorded the take-or-pay receipt as noncurrent deferred revenue in the accompanying consolidated balance sheet as of September 30, 2011. The deferred revenue associated with take-or-pay volumes will be recognized in gas revenues in the consolidated statements of operations as PetroSA takes delivery of the take-or-pay make up volumes or in the earnings of any period during which the future make up of the take-or-pay volumes were to become unlikely beyond a reasonable doubt.

XML

Deferred Revenue (Narrative) (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2011 Volumetric Production Payment [Member]	Dec. 31, 2010 Volumetric Production Payment [Member]	Jul. 31, 2011 Take-Or-Pay [Member]
Deferred Revenue Arrangement [Line Items]
Production/capital costs responsibility, in percentage	100.00%
Deferred revenue	$ 53,400	$ 87,020	$ 36,100

XML

Geographic Operating Segment Information (Schedule Of Income Statement By Geographic Operating Segment) (Details) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Segment Reporting Information [Line Items]
Oil and gas	$ 610,509	$ 437,411	$ 1,691,570	$ 1,331,498
Interest and other	17,573	14,969	68,714	49,929
Derivative gains, net	401,072	127,581	386,118	570,585
Gain (loss) on disposition of assets, net	1,048	2,383	(1,439)	26,971
Hurricane activity, net	1,487	3,452	1,418	5,678
Revenues and other income	1,031,689	585,796	2,146,381	1,984,661
Oil and gas production	119,609	100,717	321,995	280,829
Production and ad valorem taxes	38,542	33,045	107,702	85,444
Depletion, depreciation and amortization	166,536	147,096	460,807	435,833
Exploration and abandonments	20,026	21,610	57,583	61,201
General and administrative	49,812	43,417	138,562	122,165
Accretion of discount on asset retirement obligations	2,806	2,521	8,119	7,909
Interest	45,559	45,002	136,554	137,893
Other	17,183	19,687	49,452	49,826
Costs and expenses, Total	460,073	413,095	1,280,774	1,181,100
Income from continuing operations before income taxes	571,616	172,701	865,607	803,561
Income tax provision	(185,471)	(76,211)	(283,016)	(303,438)
Income from continuing operations	386,145	96,490	582,591	500,123
United States [Member]
Segment Reporting Information [Line Items]
Oil and gas	591,147	416,112	1,629,287	1,264,316
Interest and other	13,691	268	30,294	1,776
Gain (loss) on disposition of assets, net	1,523	2,429	1,523	27,408
Hurricane activity, net	1,487	3,452	1,418	5,678
Revenues and other income	607,848	422,261	1,662,522	1,299,178
Oil and gas production	118,989	99,717	319,564	278,157
Production and ad valorem taxes	38,542	33,045	107,702	85,444
Depletion, depreciation and amortization	142,632	119,726	387,035	353,090
Exploration and abandonments	20,026	21,308	57,242	60,773
General and administrative
Accretion of discount on asset retirement obligations	2,072	1,899	6,164	6,043
Interest
Other	9,773	9,682	31,302	30,233
Costs and expenses, Total	332,034	285,377	909,009	813,740
Income from continuing operations before income taxes	275,814	136,884	753,513	485,438
Income tax provision	(102,051)	(50,647)	(278,800)	(179,612)
Income from continuing operations	173,763	86,237	474,713	305,826
South Africa [Member]
Segment Reporting Information [Line Items]
Oil and gas	19,362	21,299	62,283	67,182
Interest and other			0
Gain (loss) on disposition of assets, net			0
Revenues and other income	19,362	21,299	62,283	67,182
Oil and gas production	620	1,000	2,431	2,672
Depletion, depreciation and amortization	8,449	18,338	35,671	58,677
Exploration and abandonments		302	341	428
General and administrative
Accretion of discount on asset retirement obligations	734	622	1,955	1,866
Interest
Other			0
Costs and expenses, Total	9,803	20,262	40,398	63,643
Income from continuing operations before income taxes	9,559	1,037	21,885	3,539
Income tax provision	(2,677)	(290)	(6,128)	(991)
Income from continuing operations	6,882	747	15,757	2,548
Headquarters [Member]
Segment Reporting Information [Line Items]
Interest and other	3,882	14,701	38,420	48,153
Derivative gains, net	401,072	127,581	386,118	570,585
Gain (loss) on disposition of assets, net	(475)	(46)	(2,962)	(437)
Revenues and other income	404,479	142,236	421,576	618,301
Depletion, depreciation and amortization	15,455	9,032	38,101	24,066
General and administrative	49,812	43,417	138,562	122,165
Interest	45,559	45,002	136,554	137,893
Other	7,410	10,005	18,150	19,593
Costs and expenses, Total	118,236	107,456	331,367	303,717
Income from continuing operations before income taxes	286,243	34,780	90,209	314,584
Income tax provision	(80,743)	(25,274)	1,912	(122,835)
Income from continuing operations	$ 205,500	$ 9,506	$ 92,121	$ 191,749

XML

Discontinued Operations (Tables)

9 Months Ended

Sep. 30, 2011

Discontinued Operations [Abstract]

Schedule Of Discontinued Operations

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands)
Revenues and other income:
Oil and gas	$	—		$	33,965		$	22,130		$	109,813
Interest and other		43			229			4,629			44,643
Gain (loss) on disposition of assets, net (a)		(57	)		—			645,241			—
		(14	)		34,194			672,000			154,456
Costs and expenses:
Oil and gas production		—			3,628			2,126			10,522
Depletion, depreciation and amortization (a)		—			5,740			—			18,086
Exploration and abandonments		—			2,853			4,246			11,182
General and administrative		275			1,343			9,173			5,916
Accretion of discount on asset retirement obligations (a)		—			105			81			309
Other		120			973			1,979			2,134
		395			14,642			17,605			48,149
Income (loss) from discontinued operations before income taxes		(409	)		19,552			654,395			106,307
Current tax provision		(435	)		(11,242	)		(9,971	)		(16,536	)
Deferred tax (provision) benefit (a)		297			9,773			(231,913	)		(26,026	)
Income (loss) from discontinued operations	$	(547	)	$	18,083		$	412,511		$	63,745

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

XML

Other Expense (Schedule Of Components Of Other Expense) (Details) (USD $) In Thousands	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Other Expense [Abstract]
Transportation commitment charges	$ 5,141	[1]		[1]	$ 16,101	[1]		[1]
Above market drilling rig related costs	4,632	[2]	9,682	[2]	15,201	[2]	30,233	[2]
Other	1,150		2,102		4,176		4,028
Contingency and environmental accrual adjustments	588		260		3,470		507
Tax penalties (recoveries)	190		(18)		2,478		668
Loss on extinguishment of debt					2,367
Inventory impairments	1,745	[3]	5,660	[3]	2,332	[3]	7,230	[3]
Legal settlements	1,573		224		2,201		716
Cancelled well costs	2,113		19		2,872		56
Bad debt expense (recoveries)	51		(547)		(1,746)		(577)
Well servicing operations			2,305	[4]			6,965	[4]
Total other expense	$ 17,183		$ 19,687		$ 49,452		$ 49,826

[1] Primarily represents contract deficiency payments on excess pipeline capacity.

[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.

XML

Exploratory Costs (Tables)

9 Months Ended

Sep. 30, 2011

Exploratory Costs [Abstract]

Capitalized Exploratory Well And Project Activity

	Three Months  Ended September 30, 2011			Nine Months  Ended September 30, 2011
	(in thousands)
Beginning capitalized exploratory costs	$	85,111		$	96,193
Additions to exploratory costs pending the determination of proved reserves		158,448			372,793
Reclassification due to determination of proved reserves		(139,624	)		(335,306	)
Disposition of assets sold		—			(28,938	)
Exploratory well costs charged to exploration expense		(126	)		(933	)
Ending capitalized exploratory costs	$	103,809		$	103,809

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

	September 30, 2011		December 31, 2010
	(in thousands, except project counts)
Capitalized exploratory costs that have been suspended:
One year or less	$	95,790	$	70,635
More than one year		8,019		25,558
	$	103,809	$	96,193
Number of projects with exploratory costs that have been suspended for a period greater than one year		1		3

XML

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 (Loss) [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 ($0.08 per share)				(9,493)			(9,493)
Exercise of long-term incentive plan stock options and employee stock purchases	79,000
Exercise of long-term incentive plan stock options		951	3,091	(352)			3,690
Treasury stock purchases (in shares)	(439,000)
Treasury stock purchases			(40,128)			(198)	(40,326)
Conversion of 2.875% senior convertible notes		(20)	14				(6)
Tax benefit related to stock-based compensation		28,123					28,123
Disposition of subsidiary		(510)					(510)
Compensation costs:
Vested compensation awards, net (in shares)	1,401,000
Vested compensation awards, net	14	(14)
Compensation costs included in net income		30,760				940	31,700
Cash distributions to noncontrolling interests						(19,944)	(19,944)
Net income				945,635		49,467	995,102
Deferred hedging activity, net of tax:
Net hedge gains included in continuing operations					(7,419)	(10,275)	(17,694)
Ending Balance at Sep. 30, 2011	$ 1,276	$ 3,082,058	$ (458,258)	$ 2,446,217	$ (58)	$ 125,432	$ 5,196,667
Ending Balance (in shares) at Sep. 30, 2011	116,350,000

XML

Gain (Loss) On Disposition Of Assets, Net

9 Months Ended

Sep. 30, 2011

Gain (Loss) On Disposition Of Assets, Net [Abstract]

Gain (Loss) On Disposition Of Assets, Net

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

For the three and nine months ended September 30, 2011, the Company recorded $1.0 million of net gains and $1.4 million of net losses on disposition of assets from continuing operations, respectively, as compared to $2.4 million and $27.0 million, respectively, of net gains from continuing operations for the three and nine months ended September 30, 2010.

The Company's net gains for the three months ended September 30, 2011 are primarily associated with the sale of unproved oil and gas properties while the net losses during the nine months ended September 30, 2011 are primarily associated with the sale of excess materials and supplies inventory, partially offset by gains on the aforementioned unproved property sale. During the nine months ended September 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 nine months ended September 30, 2011 from the sale of its Tunisia subsidiaries that are included in discontinued operations.

XML

Exploratory Costs (Capitalized Exploratory Costs And The Number Of Projects For Which Exploratory Costs Have Been Capitalized) (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2011	Jun. 30, 2011	Dec. 31, 2010
Exploratory Costs [Abstract]
One year or less	$ 95,790		$ 70,635
More than one year	8,019		25,558
Capitalized exploratory costs, total	$ 103,809	$ 85,111	$ 96,193
Number of projects with exploratory costs that have been suspended for a period greater than one year	1		3

XML

Other Expense

9 Months Ended

Sep. 30, 2011

Other Expense [Abstract]

Other Expense

NOTE P.    Other Expense

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011		2010			2011			2010
	(in thousands)
Transportation commitment charges (a)	$	5,141	$	—		$	16,101		$	—
Above market drilling rig related costs (b)		4,632		9,682			15,201			30,233
Other		1,150		2,102			4,176			4,028
Contingency and environmental accrual adjustments		588		260			3,470			507
Tax penalties (recoveries)		190		(18	)		2,478			668
Loss on extinguishment of debt		—		—			2,367			—
Inventory impairments (c)		1,745		5,660			2,332			7,230
Legal settlements		1,573		224			2,201			716
Cancelled well costs		2,113		19			2,872			56
Bad debt expense (recoveries)		51		(547	)		(1,746	)		(577	)
Well servicing operations (d)		—		2,305			—			6,965
Total other expense	$	17,183	$	19,687		$	49,452		$	49,826

(a) Primarily represents contract deficiency payments on excess pipeline capacity.

(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.

XML

Gain (Loss) On Disposition Of Assets, Net (Details) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Gain (Loss) On Disposition Of Assets, Net [Abstract]
Gain (loss) on disposition of assets, net	$ 1,048	$ 2,383	$ (1,439)	$ 26,971

XML

Consolidated Statements Of Cash Flows (USD $) In Thousands	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Cash flows from operating activities:
Net income	$ 995,102	$ 563,868
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	460,807	435,833
Exploration expenses, including dry holes	6,008	16,655
Hurricane activity, net		3,500
Deferred income taxes	249,040	283,283
(Gain) loss on disposition of assets, net	1,439	(26,971)
Accretion of discount on asset retirement obligations	8,119	7,909
Discontinued operations	(407,353)	43,339
Interest expense	23,412	22,567
Derivative related activity	(269,746)	(549,387)
Amortization of stock-based compensation	31,525	28,631
Amortization of deferred revenue	(33,620)	(67,739)
Other noncash items	(15,773)	10,440
Change in operating assets and liabilities
Accounts receivable, net	(35,252)	97,873
Income taxes receivable	28,588	16,689
Inventories	(115,961)	(6,459)
Prepaid expenses	(7,558)	(8,975)
Other current assets	8,520	2,162
Accounts payable	83,632	62,349
Interest payable	(25,053)	(13,211)
Income taxes payable	(1,807)	1,307
Other current liabilities	45,969	(21,941)
Net cash provided by operating activities	1,030,038	901,722
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold	819,638	297,742
Investment in unconsolidated subsidiary	(89,620)	(15,651)
Additions to oil and gas properties	(1,319,131)	(714,014)
Additions to other assets and other property and equipment, net	(265,740)	(132,279)
Net cash used in investing activities	(854,853)	(564,202)
Cash flows from financing activities:
Borrowings under long-term debt	102,616	199,784
Principal payments on long-term debt	(135,883)	(438,894)
Contributions from noncontrolling interests		1,151
Distributions to noncontrolling interests	(19,944)	(20,160)
Payments of other liabilities	(503)	(20,668)
Exercise of long-term incentive plan stock options	3,690	6,736
Purchases of treasury stock	(40,326)	(13,776)
Excess tax benefits from share-based payment arrangements	28,123	4,032
Payment of financing fees	(8,741)	(145)
Dividends paid	(4,812)	(4,783)
Net cash used in financing activities	(75,780)	(286,723)
Net increase in cash and cash equivalents	99,405	50,797
Cash and cash equivalents, beginning of period	111,160	27,368
Cash and cash equivalents, end of period	$ 210,565	$ 78,165

XML

Asset Retirement Obligations

9 Months Ended

Sep. 30, 2011

Asset Retirement Obligations [Abstract]

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 nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands)
Beginning asset retirement obligations	$	151,970		$	137,181		$	152,291		$	166,434
Liabilities assumed in acquisitions		—			—			6			6
New wells placed on production		1,132			2,356			3,206			7,000
Changes in estimates (a)		(5,453	)		—			(5,331	)		—
Disposition of wells		—			(131	)		(448	)		(29,671	)
Liabilities settled		(2,808	)		(6,141	)		(10,277	)		(16,096	)
Accretion of discount from continuing operations		2,806			2,521			8,119			7,909
Accretion of discount from discontinued operations		—			105			81			309
Ending asset retirement obligations	$	147,647		$	135,891		$	147,647		$	135,891

(a) Changes in estimates during 2011 are primarily associated with the deferral of the future abandonment of the Company's South Africa oil and gas properties to allow Petroleum Oil and Gas Corporation of South Africa, Ltd ("PetroSA") to recover take-or-pay make up gas (see Note M) and a $1.5 million reduction in East Cameron 322 reclamation costs.

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 September 30, 2011 and December 31, 2010, the current portions of the Company's asset retirement obligations were $13.6 million and $19.9 million, respectively.

XML

Derivative Financial Instruments (Natural Gas Liquids Volume And Weighted Average Price) (Details)	3 Months Ended								9 Months Ended	12 Months Ended
	Dec. 31, 2011 bbl		Sep. 30, 2011 bbl		Jun. 30, 2011 bbl		Mar. 31, 2011 bbl		Sep. 30, 2011 MMbls	Dec. 31, 2011 bbl
2011 - Swap Contracts [Member]
Derivative [Line Items]
Volume	1,150									1,150
Blended index price	51.50									51.50
NGL NYMEX price	77.25									77.25
2011 - Collar Contracts [Member]
Derivative [Line Items]
Volume	2,650									2,650
2011 - Collar Contracts [Member] | Ceiling [Member]
Derivative [Line Items]
Blended index price	64.23									64.23
2011 - Collar Contracts [Member] | Floor [Member]
Derivative [Line Items]
Blended index price	53.29									53.29
2012 - Swap Contracts [Member]
Derivative [Line Items]
Volume	750		750		750		750			750
Blended index price	35.03		35.03		35.03		35.03			35.03
2012 - NGL Percentage of WTI Oil Prices contracts [Member]
Derivative [Line Items]
Volume	2,000	[1]	2,000	[1]	2,000	[1]	2,000	[1]	1,000	2,000	[1]
Percent of WTI oil price	85.00%	[1]	85.00%	[1]	85.00%	[1]	85.00%	[1]	68.00%	85.00%	[1]
2012 - NGL Collar Contracts With Short Puts [Member]
Derivative [Line Items]
Volume									3,000
2012 - NGL Collar Contracts With Short Puts [Member] | Ceiling [Member]
Derivative [Line Items]
NGL NYMEX price									79.99
2012 - NGL Collar Contracts With Short Puts [Member] | Floor [Member]
Derivative [Line Items]
NGL NYMEX price									67.70
2012 - NGL Collar Contracts With Short Puts [Member] | Short Put [Member]
Derivative [Line Items]
NGL NYMEX price									55.76

[1] Subsequent to September 30, 2011, the Company (i) entered into additional NGL Percentage of WTI Oil Prices contracts for 1,000 Bbls per day of the Company's 2012 production priced at 68 percent of WTI and (ii) converted 3,000 Bbls per day of the Company's 2012 production from NGL Percentage of WTI Oil Prices contracts to NGL collar contracts with short puts with an average ceiling price of $79.99 per Bbl, an average floor price of $67.70 per Bbl and an average short put price of $55.76 per Bbl.

XML

Asset Retirement Obligations (Asset Retirement Obligations) (Details) (USD $)	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010		Dec. 31, 2010
Asset Retirement Obligations [Abstract]
Beginning asset retirement obligations	$ 151,970,000		$ 137,181,000		$ 152,291,000		$ 166,434,000
Liabilities assumed in acquisitions					6,000		6,000
New wells placed on production	1,132,000		2,356,000		3,206,000		7,000,000
Changes in estimates	(5,453,000)	[1]			(5,331,000)	[1]
Disposition of wells			(131,000)		(448,000)		(29,671,000)
Liabilities settled	(2,808,000)		(6,141,000)		(10,277,000)		(16,096,000)
Accretion of discount from continuing operations	2,806,000		2,521,000		8,119,000		7,909,000
Accretion of discount from discontinued operations			105,000	[2]	81,000	[2]	309,000	[2]
Ending asset retirement obligations	147,647,000		135,891,000		147,647,000		135,891,000
Asset retirement obligations, current portion	13,600,000				13,600,000				19,900,000
Reclamation and abandonment costs					$ 1,500,000

[1] Changes in estimates during 2011 are primarily associated with the deferral of the future abandonment of the Company's South Africa oil and gas properties to allow Petroleum Oil and Gas Corporation of South Africa, Ltd ("PetroSA") to recover take-or-pay make up gas (see Note M) and a $1.5 million reduction in East Cameron 322 reclamation costs.

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

XML

Interest And Other Income (Interest And Other Income) (Details) (USD $) In Thousands	3 Months Ended				9 Months Ended
	Sep. 30, 2011		Sep. 30, 2010		Sep. 30, 2011		Sep. 30, 2010
Interest And Other Income [Abstract]
Alaskan Petroleum Production Tax credits	$ 95	[1]	$ 12,129	[1]	$ 27,547	[1]	$ 39,990	[1]
Third-party income from vertical integration services	13,691	[2]	268	[2]	30,294	[2]	1,776	[2]
Other income (loss)	222		(478)		3,135		1,304
Eagle Ford Shale land fees	1,001				2,803
Equity interest in income (loss) of unconsolidated affiliate	1,641		(269)		2,442		(269)
Deferred compensation plan income	288		206		1,454		890
Change in asset retirement estimates	556				556
Interest income	79		3,113		483		3,589
Sales and other tax refunds							984
Insurance claim recovery							1,665
Total interest and other income	$ 17,573		$ 14,969		$ 68,714		$ 49,929

[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 gross margins from vertical integration services primarily represents third party revenues less operating costs associated with Company-provided fracture stimulation, drilling and related services.

XML

Net Income (Loss) Per Share (Tables)

9 Months Ended

Sep. 30, 2011

Net Income (Loss) Per Share [Abstract]

Reconciliation Of Earnings Attributable To Common Stockholders, Basic And Diluted

	Three Months Ended September 30, 2011									Nine Months Ended September 30, 2011
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Income (loss) as reported	$	386,145		$	(547	)	$	385,598		$	582,591		$	412,511		$	995,102
Net income attributable to the noncontrolling interests		(34,134	)		—			(34,134	)		(49,467	)		—			(49,467	)
Participating basic earnings		(6,797	)		—			(6,797	)		(10,062	)		(7,124	)		(17,186	)
Basic net income (loss) attributable to common stockholders		345,214			(547	)		344,667			523,062			405,387			928,449
Reallocation of participating earnings		189			—			189			268			190			458
Diluted income (loss) attributable to common stockholders	$	345,403		$	(547	)	$	344,856		$	523,330		$	405,577		$	928,907
	Three Months Ended September 30, 2010									Nine Months Ended September 30, 2010
	Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total
	(in thousands)
Income as reported	$	96,490		$	18,083		$	114,573		$	500,123		$	63,745		$	563,868
Net income attributable to the noncontrolling interests		(2,538	)		—			(2,538	)		(39,003	)		—			(39,003	)
Participating basic earnings		(2,265	)		(424	)		(2,689	)		(10,661	)		(1,359	)		(12,020	)
Basic income attributable to common stockholders		91,687			17,659			109,346			450,459			62,386			512,845
Reallocation of participating earnings		16			3			19			112			15			127
Diluted income attributable to common stockholders	$	91,703		$	17,662		$	109,365		$	450,571		$	62,401		$	512,972

Reconciliation Of Basic Weighted Average Common Shares

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(in thousands)
Weighted average common shares outstanding:
Basic		116,281		115,191		116,122		114,985
Dilutive common stock options		166		168		181		218
Convertible senior notes dilution		185		—		1,618		—
Contingently issuable performance unit shares		443		662		429		629
Diluted		117,075		116,021		118,350		115,832

XML

Geographic Operating Segment Information

9 Months Ended

Sep. 30, 2011

Geographic Operating Segment Information [Abstract]

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 nine months ended September 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 September 30, 2011
Revenues and other income:
Oil and gas	$	591,147		$	19,362		$	—		$	610,509
Interest and other		13,691			—			3,882			17,573
Derivative gains, net		—			—			401,072			401,072
Gain (loss) on disposition of assets, net		1,523			—			(475	)		1,048
Hurricane activity, net		1,487			—			—			1,487
		607,848			19,362			404,479			1,031,689
Costs and expenses:
Oil and gas production		118,989			620			—			119,609
Production and ad valorem taxes		38,542			—			—			38,542
Depletion, depreciation and amortization		142,632			8,449			15,455			166,536
Exploration and abandonments		20,026			—			—			20,026
General and administrative		—			—			49,812			49,812
Accretion of discount on asset retirement obligations		2,072			734			—			2,806
Interest		—			—			45,559			45,559
Other		9,773			—			7,410			17,183
		332,034			9,803			118,236			460,073
Income from continuing operations before income taxes		275,814			9,559			286,243			571,616
Income tax provision		(102,051	)		(2,677	)		(80,743	)		(185,471	)
Income from continuing operations	$	173,763		$	6,882		$	205,500		$	386,145

	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Three Months Ended September 30, 2010
Revenues and other income:
Oil and gas	$	416,112		$	21,299		$	—		$	437,411
Interest and other		268			—			14,701			14,969
Derivative gains, net		—			—			127,581			127,581
Gain (loss) on disposition of assets, net		2,429			—			(46	)		2,383
Hurricane activity, net		3,452			—			—			3,452
		422,261			21,299			142,236			585,796
Costs and expenses:
Oil and gas production		99,717			1,000			—			100,717
Production and ad valorem taxes		33,045			—			—			33,045
Depletion, depreciation and amortization		119,726			18,338			9,032			147,096
Exploration and abandonments		21,308			302			—			21,610
General and administrative		—			—			43,417			43,417
Accretion of discount on asset retirement obligations		1,899			622			—			2,521
Interest		—			—			45,002			45,002
Other		9,682			—			10,005			19,687
		285,377			20,262			107,456			413,095
Income from continuing operations before income taxes		136,884			1,037			34,780			172,701
Income tax provision		(50,647	)		(290	)		(25,274	)		(76,211	)
Income from continuing operations	$	86,237		$	747		$	9,506		$	96,490
	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Nine Months Ended September 30, 2011
Revenues and other income:
Oil and gas	$	1,629,287		$	62,283		$	—		$	1,691,570
Interest and other		30,294			—			38,420			68,714
Derivative gains, net		—			—			386,118			386,118
Gain (loss) on disposition of assets, net		1,523			—			(2,962	)		(1,439	)
Hurricane activity, net		1,418			—			—			1,418
		1,662,522			62,283			421,576			2,146,381
Costs and expenses:
Oil and gas production		319,564			2,431			—			321,995
Production and ad valorem taxes		107,702			—			—			107,702
Depletion, depreciation and amortization		387,035			35,671			38,101			460,807
Exploration and abandonments		57,242			341			—			57,583
General and administrative		—			—			138,562			138,562
Accretion of discount on asset retirement obligations		6,164			1,955			—			8,119
Interest		—			—			136,554			136,554
Other		31,302			—			18,150			49,452
		909,009			40,398			331,367			1,280,774
Income from continuing operations before income taxes		753,513			21,885			90,209			865,607
Income tax benefit (provision)		(278,800	)		(6,128	)		1,912			(283,016	)
Income from continuing operations	$	474,713		$	15,757		$	92,121		$	582,591

	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Nine Months Ended September 30, 2010
Revenues and other income:
Oil and gas	$	1,264,316		$	67,182		$	—		$	1,331,498
Interest and other		1,776			—			48,153			49,929
Derivative gains, net		—			—			570,585			570,585
Gain (loss) on disposition of assets, net		27,408			—			(437	)		26,971
Hurricane activity, net		5,678			—			—			5,678
		1,299,178			67,182			618,301			1,984,661
Costs and expenses:
Oil and gas production		278,157			2,672			—			280,829
Production and ad valorem taxes		85,444			—			—			85,444
Depletion, depreciation and amortization		353,090			58,677			24,066			435,833
Exploration and abandonments		60,773			428			—			61,201
General and administrative		—			—			122,165			122,165
Accretion of discount on asset retirement obligations		6,043			1,866			—			7,909
Interest		—			—			137,893			137,893
Other		30,233			—			19,593			49,826
		813,740			63,643			303,717			1,181,100
Income from continuing operations before income taxes		485,438			3,539			314,584			803,561
Income tax provision		(179,612	)		(991	)		(122,835	)		(303,438	)
Income from continuing operations	$	305,826		$	2,548		$	191,749		$	500,123

	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Nine Months Ended September 30, 2010
Revenues and other income:
Oil and gas	$	1,264,316		$	67,182		$	—		$	1,331,498
Interest and other		1,776			—			48,153			49,929
Derivative gains, net		—			—			570,585			570,585
Gain (loss) on disposition of assets, net		27,408			—			(437	)		26,971
Hurricane activity, net		5,678			—			—			5,678
		1,299,178			67,182			618,301			1,984,661
Costs and expenses:
Oil and gas production		278,157			2,672			—			280,829
Production and ad valorem taxes		85,444			—			—			85,444
Depletion, depreciation and amortization		353,090			58,677			24,066			435,833
Exploration and abandonments		60,773			428			—			61,201
General and administrative		—			—			122,165			122,165
Accretion of discount on asset retirement obligations		6,043			1,866			—			7,909
Interest		—			—			137,893			137,893
Other		30,233			—			19,593			49,826
		813,740			63,643			303,717			1,181,100
Income from continuing operations before income taxes		485,438			3,539			314,584			803,561
Income tax provision		(179,612	)		(991	)		(122,835	)		(303,438	)
Income from continuing operations	$	305,826		$	2,548		$	191,749		$	500,123

	United States			South Africa			Headquarters			Consolidated Total
	(in thousands)
Nine Months Ended September 30, 2010
Revenues and other income:
Oil and gas	$	1,264,316		$	67,182		$	—		$	1,331,498
Interest and other		1,776			—			48,153			49,929
Derivative gains, net		—			—			570,585			570,585
Gain (loss) on disposition of assets, net		27,408			—			(437	)		26,971
Hurricane activity, net		5,678			—			—			5,678
		1,299,178			67,182			618,301			1,984,661
Costs and expenses:
Oil and gas production		278,157			2,672			—			280,829
Production and ad valorem taxes		85,444			—			—			85,444
Depletion, depreciation and amortization		353,090			58,677			24,066			435,833
Exploration and abandonments		60,773			428			—			61,201
General and administrative		—			—			122,165			122,165
Accretion of discount on asset retirement obligations		6,043			1,866			—			7,909
Interest		—			—			137,893			137,893
Other		30,233			—			19,593			49,826
		813,740			63,643			303,717			1,181,100
Income from continuing operations before income taxes		485,438			3,539			314,584			803,561
Income tax provision		(179,612	)		(991	)		(122,835	)		(303,438	)
Income from continuing operations	$	305,826		$	2,548		$	191,749		$	500,123

	September 30, 2011		December 31, 2010
	(in thousands)
Consolidating Assets by Geographic Area:
United States	$	10,775,975	$	8,987,141
South Africa		86,710		134,901
Tunisia		—		325,942
Headquarters		122,358		231,118
Total consolidated assets	$	10,985,043	$	9,679,102

XML

Consolidated Balance Sheets (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 210,565	$ 111,160
Accounts receivable:
Trade, net of allowance for doubtful accounts of $755 and $1,155 as of September 30, 2011 and December 31, 2010, respectively	272,154	237,511
Due from affiliates	6,034	7,792
Income taxes receivable	2,312	30,901
Inventories	260,356	173,615
Prepaid expenses	18,910	11,441
Deferred income taxes	92,140	156,650
Discontinued operations held for sale		281,741
Other current assets:
Derivatives	234,806	171,679
Other	6,366	14,693
Total current assets	1,103,643	1,197,183
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	12,092,300	10,739,114
Unproved properties	249,537	191,112
Accumulated depletion, depreciation and amortization	(3,788,686)	(3,366,440)
Total property, plant and equipment	8,553,151	7,563,786
Deferred income taxes	7,358
Goodwill	298,154	298,182
Other property and equipment, net	500,709	283,542
Other assets:
Investment in unconsolidated affiliate	164,107	72,045
Derivatives	224,754	151,011
Other, net of allowance for doubtful accounts of $348 and $2,519 as of September 30, 2011 and December 31, 2010, respectively	133,167	113,353
Assets, Total	10,985,043	9,679,102
Accounts payable:
Trade	583,383	354,890
Due to affiliates	48,421	64,260
Interest payable	33,955	59,008
Income taxes payable	15,604	19,168
Deferred income taxes		1,144
Discontinued operations held for sale		108,592
Other current liabilities:
Derivatives	12,377	80,997
Deferred revenue	42,825	44,951
Other	39,552	36,210
Total current liabilities	776,117	769,220
Long-term debt	2,587,371	2,601,670
Derivatives	16,946	56,574
Deferred income taxes	2,133,147	1,751,310
Deferred revenue	46,701	42,069
Other liabilities	228,094	232,234
Stockholders' equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 127,614,963 and 126,212,256 shares issued at September 30, 2011 and December 31, 2010, respectively	1,276	1,262
Additional paid-in capital	3,082,058	3,022,768
Treasury stock, at cost: 11,264,660 and 10,903,743 at September 30, 2011 and December 31, 2010, respectively	(458,258)	(421,235)
Retained earnings	2,446,217	1,510,427
Accumulated other comprehensive income (loss)-net deferred hedge gains (losses), net of tax	(58)	7,361
Total stockholders' equity attributable to common stockholders	5,071,235	4,120,583
Noncontrolling interests in consolidating subsidiaries	125,432	105,442
Total stockholders' equity	5,196,667	4,226,025
Commitments and contingencies
Liabilities and Stockholders' Equity, Total	$ 10,985,043	$ 9,679,102

XML

Deferred Revenue (Tables)

9 Months Ended

Sep. 30, 2011

Deferred Revenue [Abstract]

Deferred Revenue Carrying Values

VPP Deferred revenue at December 31, 2010	$	87,020
Less: 2011 VPP amortization		(33,620	)
VPP Deferred revenue at September 30, 2011	$	53,400

Revenue Recognition In Future Periods

Remaining 2011	$	11,329
2012	$	42,071

XML

Income Taxes (Narrative) (Details) (USD $)	Sep. 30, 2011	Dec. 31, 2010
Income Tax Examination [Line Items]
Valuation allowances	$ 5,300,000	$ 6,600,000
Unrecognized tax benefits	0
Tunisia [Member]
Income Tax Examination [Line Items]
Valuation allowances		$ 26,500,000

XML

Derivative Financial Instruments (Derivative Instruments) (Details) (USD $) In Thousands	Sep. 30, 2011		Dec. 31, 2010
Derivative [Line Items]
Total derivatives, Asset			$ 347,802	[1]
Total derivatives, Liability			162,683	[1]
Interest Rate Derivatives [Member] | Not Designated As Hedging Instruments [Member] | Derivatives - Current [Member]
Derivative [Line Items]
Total derivatives, Asset			11,903	[1]
Total derivatives, Liability			886	[1]
Interest Rate Derivatives [Member] | Not Designated As Hedging Instruments [Member] | Derivatives - Noncurrent [Member]
Derivative [Line Items]
Total derivatives, Asset			15,762	[1]
Total derivatives, Liability	12,664	[1]	9,227	[1]
Not Designated As Hedging Instruments [Member]
Derivative [Line Items]
Total derivatives, Asset	477,911	[1]
Total derivatives, Liability	47,674	[1]
Not Designated As Hedging Instruments [Member] | Commodity Price Derivatives [Member] | Derivatives - Current [Member]
Derivative [Line Items]
Total derivatives, Asset	247,036	[1]	167,406	[1]
Total derivatives, Liability	24,607	[1]	87,741	[1]
Not Designated As Hedging Instruments [Member] | Commodity Price Derivatives [Member] | Derivatives - Noncurrent [Member]
Derivative [Line Items]
Total derivatives, Asset	230,875	[1]	152,731	[1]
Total derivatives, Liability	$ 10,403	[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.

XML

Deferred Revenue (Revenue Recognition In Future Periods) (Details) (USD $) In Thousands	Sep. 30, 2011
Deferred Revenue [Abstract]
Remaining 2011	$ 11,329
2012	$ 42,071

XML

Disclosures About Fair Value Measurements (Narrative) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2011
Disclosures About Fair Value Measurements [Abstract]
Derivative fixed interest rate	3.06%
Swap contract notional amount fixed rate of interest and variable LIBOR	$ 200

XML

Disclosures About Fair Value Measurements (Assets And Liabilities That Are Measured At Fair Value On A Recurring Basis) (Details) (USD $)	9 Months Ended
	Sep. 30, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	$ 495,775,000
Liabilities, (Fair Value, Total)	2,948,492,000
Proceeds from termination of interest rate derivatives	26,100,000
Interest Rate Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)	12,664,000
Interest Rate Derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)	12,664,000
Interest Rate Derivatives [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)
Pioneer Southwest Credit Facility [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)	94,917,000
Pioneer Southwest Credit Facility [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)	94,917,000
Pioneer Southwest Credit Facility [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	36,069,000
Liabilities, (Fair Value, Total)	2,824,252,000
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | Trading Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	283,000
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | Deferred Compensation Plan Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	35,786,000
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | 5.875% Senior Notes Due 2016 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)	475,878,000
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | 6.65% Senior Notes Due 2017 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)	522,695,000
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | 6.875% Senior Notes Due 2018 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)	480,965,000
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | 7.50% Senior Notes Due 2020 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)	506,250,000
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | 7.20% Senior Notes Due 2028 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)	259,875,000
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | 2.875% Convertible Senior Notes Due 2038 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)	578,589,000	[1]
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	459,706,000
Liabilities, (Fair Value, Total)	124,240,000
Significant Other Observable Inputs (Level 2) [Member] | Trading Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	146,000
Significant Other Observable Inputs (Level 2) [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	459,560,000
Liabilities, (Fair Value, Total)	16,659,000
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)
Liabilities, (Fair Value, Total)
Significant Unobservable Inputs (Level 3) [Member] | Trading Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)
Significant Unobservable Inputs (Level 3) [Member] | Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)
Liabilities, (Fair Value, Total)
Significant Unobservable Inputs (Level 3) [Member] | Deferred Compensation Plan Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)
Significant Unobservable Inputs (Level 3) [Member] | 5.875% Senior Notes Due 2016 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)
Significant Unobservable Inputs (Level 3) [Member] | 6.65% Senior Notes Due 2017 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)
Significant Unobservable Inputs (Level 3) [Member] | 6.875% Senior Notes Due 2018 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)
Significant Unobservable Inputs (Level 3) [Member] | 7.50% Senior Notes Due 2020 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)
Significant Unobservable Inputs (Level 3) [Member] | 7.20% Senior Notes Due 2028 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)
Significant Unobservable Inputs (Level 3) [Member] | 2.875% Convertible Senior Notes Due 2038 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)		[1]
Trading Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	429,000
Commodity Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	459,560,000
Liabilities, (Fair Value, Total)	16,659,000
Deferred Compensation Plan Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, (Fair Value, Total)	35,786,000
5.875% Senior Notes Due 2016 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)	475,878,000
Senior notes, interest rate	5.875%
Debt instrument expiration date	2016
6.65% Senior Notes Due 2017 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)	522,695,000
Senior notes, interest rate	6.65%
Debt instrument expiration date	2017
6.875% Senior Notes Due 2018 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)	480,965,000
Senior notes, interest rate	6.875%
Debt instrument expiration date	2018
7.50% Senior Notes Due 2020 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)	506,250,000
Senior notes, interest rate	7.50%
Debt instrument expiration date	2020
7.20% Senior Notes Due 2028 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)	259,875,000
Senior notes, interest rate	7.20%
Debt instrument expiration date	2028
2.875% Convertible Senior Notes Due 2038 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, (Fair Value, Total)	$ 578,589,000	[1]
Senior notes, interest rate	2.875%
Debt instrument expiration date	2038

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

XML

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 bbl Mmbtu
Trading Activity, Gains and Losses, Net [Line Items]
Price per barrel received on contracts			0.28
2011 - Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Volume	750,000,000,000								750,000,000,000
2011 - Collar Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Volume	2,000,000,000,000								2,000,000,000,000
2011 - Collar Contracts [Member] | Ceiling [Member]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price	170.00								170.00
2011 - Collar Contracts [Member] | Floor [Member]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price	115.00								115.00
2011 - Collar Contracts With Short Puts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Volume	32,000,000,000,000								32,000,000,000,000
2011 - Collar Contracts With Short Puts [Member] | Ceiling [Member]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price	99.33								99.33
2011 - Collar Contracts With Short Puts [Member] | Floor [Member]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price	73.75								73.75
2011 - Collar Contracts With Short Puts [Member] | Short Put [Member]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price	59.31								59.31
2012 - Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
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	[1]	79.32	[1]	79.32	[1]	79.32	[1]	79.32	[1]
2012 - Collar Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
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]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price	127.00		127.00		127.00		127.00		127.00
2012 - Collar Contracts [Member] | Floor [Member]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price	90.00		90.00		90.00		90.00		90.00
2012 - Collar Contracts With Short Puts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
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]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price	117.99		117.99		117.99		117.99		117.99
2012 - Collar Contracts With Short Puts [Member] | Floor [Member]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price	80.42		80.42		80.42		80.42		80.42
2012 - Collar Contracts With Short Puts [Member] | Short Put [Member]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price	65.00		65.00		65.00		65.00		65.00
2013 - Swap Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
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]
Trading Activity, Gains and Losses, Net [Line Items]
Volume	28,000,000,000,000	[1]	28,000,000,000,000	[1]	28,000,000,000,000	[1]	28,000,000,000,000	[1]	28,000,000,000,000	[1]
2013 - Collar Contracts With Short Puts [Member] | Ceiling [Member]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price	120.62	[1]	120.62	[1]	120.62	[1]	120.62	[1]	120.62	[1]
2013 - Collar Contracts With Short Puts [Member] | Ceiling [Member] | Additional Collar Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price			111.95
2013 - Collar Contracts With Short Puts [Member] | Floor [Member]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price	83.68	[1]	83.68	[1]	83.68	[1]	83.68	[1]	83.68	[1]
2013 - Collar Contracts With Short Puts [Member] | Floor [Member] | Additional Collar Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price			85.00
2013 - Collar Contracts With Short Puts [Member] | Short Put [Member]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price	65.82	[1]	65.82	[1]	65.82	[1]	65.82	[1]	65.82	[1]
2013 - Collar Contracts With Short Puts [Member] | Short Put [Member] | Additional Collar Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price			70.00
2013 - Collar Contracts With Short Puts [Member] | Additional Collar Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Volume			3,000,000,000,000
2014 - Collar Contracts With Short Puts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Volume	16,500,000,000,000	[1]	16,500,000,000,000	[1]	16,500,000,000,000	[1]	16,500,000,000,000	[1]	16,500,000,000,000	[1]
2014 - Collar Contracts With Short Puts [Member] | Ceiling [Member]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price	129.69	[1]	129.69	[1]	129.69	[1]	129.69	[1]	129.69	[1]
2014 - Collar Contracts With Short Puts [Member] | Ceiling [Member] | Terminated Collar Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price			133.12
2014 - Collar Contracts With Short Puts [Member] | Floor [Member]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price	88.48	[1]	88.48	[1]	88.48	[1]	88.48	[1]	88.48	[1]
2014 - Collar Contracts With Short Puts [Member] | Floor [Member] | Terminated Collar Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price			90.00
2014 - Collar Contracts With Short Puts [Member] | Short Put [Member]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price	71.97	[1]	71.97	[1]	71.97	[1]	71.97	[1]	71.97	[1]
2014 - Collar Contracts With Short Puts [Member] | Short Put [Member] | Terminated Collar Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
NYMEX price			65.00
2014 - Collar Contracts With Short Puts [Member] | Terminated Collar Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Volume			6,500,000,000,000

[1] Subsequent to September 30, 2011, the Company entered into (i) NYMEX swap contracts on 3,000 Bbls per day of March 2012 through May 2012 forecasted production, whereby the Company receives $0.28 per Bbl and pays the difference between (a) each day's price per Bbl of WTI for the first nearby month less (b) the price per Bbl of WTI for the second nearby NYMEX month, multiplied by .6667; plus (c) each day's price per Bbl of WTI for the first nearby month less (d) the price per Bbl of WTI for the third nearby NYMEX month, multiplied by .3333 and (ii) additional collar contracts with short puts for 3,000 Bbls per day of the Company's 2013 production with a ceiling price of $111.95 per Bbl, a floor price of $85.00 per Bbl and a short put price of $70.00 per Bbl and (iii) terminated collar contracts with short puts for 6,500 Bbls per day of the Company's 2014 production with an average ceiling price of $133.12 per Bbl, an average floor price of $90.00 per Bbl and an average short put price of $65.00 per Bbl.

XML

Interest And Other Income (Tables)

9 Months Ended

Sep. 30, 2011

Interest And Other Income [Abstract]

Interest And Other Income

	Three Months Ended September 30,					Nine Months Ended September 30,
	2011		2010			2011		2010
	(in thousands)
Alaskan Petroleum Production Tax credits (a)	$	95	$	12,129		$	27,547	$	39,990
Third-party income from vertical integration services (b)		13,691		268			30,294		1,776
Other income (loss)		222		(478	)		3,135		1,304
Eagle Ford Shale land fees		1,001		—			2,803		—
Equity interest in income (loss) of unconsolidated affiliate		1,641		(269	)		2,442		(269	)
Deferred compensation plan income		288		206			1,454		890
Change in asset retirement estimates		556		—			556		—
Interest income		79		3,113			483		3,589
Insurance claim recovery		—		—			—		1,665
Sales and other tax refunds		—		—			—		984
Total interest and other income	$	17,573	$	14,969		$	68,714	$	49,929

(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 gross margins from vertical integration services primarily represents third party revenues less operating costs associated with Company-provided fracture stimulation, drilling and related services.